89
78
Monday, April 22, 2024
Contents
Agriculture

Agriculture Department

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
29282
2024-08544
AIRFORCE

Air Force Department

NOTICES
Environmental Impact Statements; Availability, etc.:
Construction and Operation of the Air Force Maui Optical and Supercomputing Site Small Telescope Advanced Research Facility on the Island of Maui, HI,
29311-29312
2024-08540
Antitrust Division

Antitrust Division

NOTICES
Changes under the National Cooperative Research and Production Act:
Countering Weapons of Mass Destruction,
29362-29363
2024-08460
Centers Disease

Centers for Disease Control and Prevention

NOTICES
Hearings, Meetings, Proceedings, etc.:
Board of Scientific Counselors, Office of Readiness and Response,
29336-29337
2024-08448
Requests for Nominations:
Advisory Committee on HIV, Viral Hepatitis and STD Prevention and Treatment,
29335-29336
2024-08447
Centers Medicare

Centers for Medicare & Medicaid Services

NOTICES
Hearings, Meetings, Proceedings, etc.:
Medicare Program; New Revisions to the Healthcare Common Procedure Coding System Coding,
29337-29338
2024-08551
Children

Children and Families Administration

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Community Services Block Grant Annual Progress Report,
29339-29340
2024-08549
Refugee Support Services and Refugee Support Services Set Aside Sub-Agency List,
29340-29341
2024-08538
Civil Rights

Civil Rights Commission

NOTICES
Hearings, Meetings, Proceedings, etc.:
Colorado Advisory Committee,
29284-29285
2024-08554
Commonwealth of the Northern Mariana Islands Advisory Committee,
29284
2024-08533
Guam Advisory Committee,
29282-29283
2024-08556
Nebraska Advisory Committee,
29283-29285
2024-08558
2024-08559
Tennessee Advisory Committee,
29283
2024-08532
Commerce

Commerce Department

See
Industry and Security Bureau

See
International Trade Administration

See
National Oceanic and Atmospheric Administration
Defense Department

Defense Department

See
Air Force Department

RULES
Federal Acquisition Regulation:
Federal Acquisition Circular 2024-05; Introduction,
30210
2024-07930
Federal Acquisition Circular 2024-05; Small Entity Compliance Guide,
30256
2024-07933
Sustainable Procurement,
30212-30250
2024-07931
Technical Amendments,
30252-30254
2024-07932

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
29312-29315
2024-08474
2024-08475
2024-08476
2024-08477
2024-08478
Energy Department

Energy Department

See
Federal Energy Regulatory Commission

RULES
Energy Conservation Program:
Standards for Distribution Transformers,
29834-30043
2024-07480

NOTICES
Hearings, Meetings, Proceedings, etc.:
Environmental Management Site-Specific Advisory Board, Northern New Mexico,
29315-29316
2024-08467
Environmental Protection

Environmental Protection Agency

RULES
Air Quality State Implementation Plans; Approvals and Promulgations:
California; Antelope Valley Air Quality Management District and Mojave Desert Air Quality Management District; Determination to Defer Sanctions,
29259-29260
2024-08441
California; Feather River Air Quality Management District; Nonattainment New Source Review; 2015 Ozone Standard,
29257-29259
2024-08511
Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3,
29439-29831
2024-06809

PROPOSED RULES
Air Quality State Implementation Plans; Approvals and Promulgations:
California; Antelope Valley Air Quality Management District and Mojave Desert Air Quality Management District,
29277-29281
2024-08442

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Standards for Pesticide Containers and Containment,
29323-29325
2024-08555
Federal Agency Hazardous Waste Compliance Docket,
29325-29328
2024-07518
Information Regarding Allowances Used in Cross-State Air Pollution Rule Trading Programs,
29328-29329
2024-08493
Federal Aviation

Federal Aviation Administration

RULES
Airman Certification Standards and Practical Test Standards for Airmen; Incorporation by Reference:
Correction,
29252
2024-08631
Airspace Designations and Reporting Points:
Vicinity of Kodiak, AK,
29253-29254
2024-08432
Airworthiness Directives:
Diamond Aircraft Industries GmbH Airplanes,
29247-29252
2024-08539

PROPOSED RULES
Airworthiness Directives:
The Boeing Company Airplanes,
29274-29277
2024-08392
Federal Emergency

Federal Emergency Management Agency

NOTICES
Flood Hazard Determinations,
29347-29358
2024-08521
2024-08522
2024-08523
2024-08524
2024-08525
Federal Energy

Federal Energy Regulatory Commission

NOTICES
Application:
Brookfield White Pine Hydro, LLC,
29317-29318
2024-08535
Combined Filings,
29316-29317, 29319-29323
2024-08461
2024-08462
2024-08495
2024-08496
2024-08536
2024-08537
Environmental Assessments; Availability, etc.:
Great Lakes Hydro America, LLC, Proposed Project Relicenses,
29320
2024-08497
Initial Market-Based Rate Filings Including Requests for Blanket Section 204 Authorizations:
Hickory Solar LLC,
29318-29319
2024-08465
Ragsdale Solar, LLC,
29319
2024-08464
Wolf Run Solar LLC,
29321-29322
2024-08463
Water Quality Certification:
Kaukauna Utilities,
29320
2024-08534
Federal Housing Finance Agency

Federal Housing Finance Agency

NOTICES
Freddie Mac Proposed Purchase of Single-Family Closed-End Second Mortgages,
29329-29333
2024-08479
Federal Motor

Federal Motor Carrier Safety Administration

NOTICES
Exemption Application:
Qualification of Drivers; Epilepsy and Seizure Disorders,
29426-29427
2024-08519
2024-08520
Federal Reserve

Federal Reserve System

NOTICES
Change in Bank Control:
Acquisitions of Shares of a Bank or Bank Holding Company,
29333
2024-08560
Financial Crimes

Financial Crimes Enforcement Network

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Anti-Money Laundering Programs for Certain Financial Institutions,
29427-29432
2024-08529
Fish

Fish and Wildlife Service

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
National Double-Crested Cormorant Survey,
29361-29362
2024-08516
Service Agreements with Friends Organizations,
29358-29361
2024-08517
General Services

General Services Administration

RULES
Federal Acquisition Regulation:
Federal Acquisition Circular 2024-05; Introduction,
30210
2024-07930
Federal Acquisition Circular 2024-05; Small Entity Compliance Guide,
30256
2024-07933
Sustainable Procurement,
30212-30250
2024-07931
Technical Amendments,
30252-30254
2024-07932
Federal Management Regulation:
Designation of Authority and Sustainable Siting,
29261-29273
2024-08452

NOTICES
Adoption of the Department of Energy's Electric Vehicle Charging Stations Categorical Exclusion Pursuant to the National Environmental Policy Act,
29334-29335
2024-08505
Health and Human

Health and Human Services Department

See
Centers for Disease Control and Prevention

See
Centers for Medicare & Medicaid Services

See
Children and Families Administration

See
Health Resources and Services Administration

See
National Institutes of Health

See
Substance Abuse and Mental Health Services Administration
Health Resources

Health Resources and Services Administration

NOTICES
Income Levels Used for Various Health Professions and Nursing Programs Authorized in the Public Health Service Act,
29341-29342
2024-08504
Homeland

Homeland Security Department

See
Federal Emergency Management Agency
Industry

Industry and Security Bureau

RULES
Export Control Measures to Address Iranian Aggression against Israel and Military Support for Russia,
29254-29257
2024-08622
Interior

Interior Department

See
Fish and Wildlife Service
Internal Revenue

Internal Revenue Service

RULES
Elective Payment of Advanced Manufacturing Investment Credit; Correction,
29257
2024-08494

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Digital Asset Proceeds from Broker Transactions,
29433
2024-08528
Requests for Nominations:
Internal Revenue Service Advisory Council,
29433-29434
2024-08510
International Trade Adm

International Trade Administration

NOTICES
Antidumping or Countervailing Duty Investigations, Orders, or Reviews:
Brass Rod from the Republic of Korea,
29290-29292
2024-08457
Certain Non-Refillable Steel Cylinders from India,
29296-29298
2024-08451
Multilayered Wood Flooring from the People's Republic of China; Withdrawal,
29303
2024-08506
Sales at Less Than Fair Value; Determinations, Investigations, etc.:
Brass Rod from Brazil,
29303-29305
2024-08454
Brass Rod from India,
29300-29302
2024-08455
Brass Rod from Mexico,
29305-29306
2024-08458
Brass Rod from South Africa,
29292-29294
2024-08459
Brass Rod from the Republic of Korea,
29298-29300
2024-08456
Certain Non-Refillable Steel Cylinders from India,
29294-29296
2024-08450
Dioctyl Terephthalate from Malaysia, Poland, Taiwan, and the Republic of Turkiye,
29285-29290
2024-08449
Justice Department

Justice Department

See
Antitrust Division

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Capital Punishment Report of Inmates under Sentence of Death,
29363-29364
2024-08470
The Arson and Explosives Training Registration for Non-ATF Employees,
29364-29365
2024-08471
Proposed Consent Decree:
CERCLA,
29365
2024-08531
Labor Department

Labor Department

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Demographic Information Collection for Mine Safety and Health Administration Grants,
29366-29367
2024-08469
Management

Management and Budget Office

RULES
Guidance:
Federal Financial Assistance,
30046-30208
2024-07496
NASA

National Aeronautics and Space Administration

RULES
Federal Acquisition Regulation:
Federal Acquisition Circular 2024-05; Introduction,
30210
2024-07930
Federal Acquisition Circular 2024-05; Small Entity Compliance Guide,
30256
2024-07933
Sustainable Procurement,
30212-30250
2024-07931
Technical Amendments,
30252-30254
2024-07932
National Endowment for the Arts

National Endowment for the Arts

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Panelist Profile Data,
29367
2024-08498
National Foundation

National Foundation on the Arts and the Humanities

See
National Endowment for the Arts
National Institute

National Institutes of Health

NOTICES
Hearings, Meetings, Proceedings, etc.:
Fogarty International Center,
29344
2024-08501
National Cancer Institute,
29343-29344
2024-08483
National Institute of Dental and Craniofacial Research,
29343
2024-08502
National Institute of Mental Health,
29342
2024-08482
National Institute on Aging,
29342, 29344-29345
2024-08484
2024-08485
National Institute on Drug Abuse,
29344
2024-08500
Office of the Director,
29342-29343
2024-08499
National Oceanic

National Oceanic and Atmospheric Administration

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Highly Migratory Species Scientific Research Permits, Exempted Fishing Permits, Letters of Acknowledgement, Display Permits, and Shark Research Fishery Permits,
29306-29307
2024-08507
Taking or Importing of Marine Mammals:
Geophysical Surveys Related to Oil and Gas Activities in the Gulf of Mexico,
29307-29310
2024-08542
National Science

National Science Foundation

NOTICES
Meetings; Sunshine Act,
29367-29368
2024-08590
2024-08696
Nuclear Regulatory

Nuclear Regulatory Commission

NOTICES
Completion of Operational Readiness Reviews:
American Centrifuge Operating, LLC,
29368-29369
2024-08480
Environmental Assessments; Availability, etc.:
Susquehanna Nuclear, LLC, Susquehanna Steam Electric Station, Units 1 and 2, Independent Spent Fuel Storage Installation; Finding of No Significant Impact,
29369-29371
2024-08468
Meetings; Sunshine Act,
29368
2024-08600
Postal Regulatory

Postal Regulatory Commission

NOTICES
New Postal Products,
29371-29372
2024-08466
2024-08553
Presidio

Presidio Trust

NOTICES
Privacy Act; Systems of Records,
29372-29375
2024-08473
Railroad Retirement

Railroad Retirement Board

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
29375-29379
2024-08557
Securities

Securities and Exchange Commission

NOTICES
Meetings; Sunshine Act,
29423-29424
2024-08673
Order:
Fiscal Year 2024 Annual Adjustments to Transaction Fee Rates,
29402-29408
2024-08512
Self-Regulatory Organizations; Proposed Rule Changes:
Cboe BYX Exchange, Inc.,
29389-29402
2024-08487
Cboe Exchange, Inc.,
29389
2024-08486
New York Stock Exchange LLC,
29409-29413
2024-08489
NYSE American LLC,
29379-29384
2024-08488
NYSE Arca, Inc.,
29413-29418
2024-08490
NYSE Chicago, Inc.,
29384-29389
2024-08491
NYSE National, Inc.,
29418-29423
2024-08492
Substance

Substance Abuse and Mental Health Services Administration

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
29345-29347
2024-08548
Trade Representative

Trade Representative, Office of United States

NOTICES
Initiation of Section 301 Investigation:
China's Acts, Policies, and Practices Targeting the Maritime, Logistics, and Shipbuilding Sectors for Dominance,
29424-29426
2024-08515
Transportation Department

Transportation Department

See
Federal Aviation Administration

See
Federal Motor Carrier Safety Administration
Treasury

Treasury Department

See
Financial Crimes Enforcement Network

See
Internal Revenue Service

NOTICES
Privacy Act; Systems of Records,
29434-29436
2024-08513
Veteran Affairs

Veterans Affairs Department

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Servicer's Staff Appraisal Reviewer Application,
29436-29437
2024-08526

Separate Parts In This Issue

Part II
Environmental Protection Agency,
29439-29831
2024-06809

Part III
Energy Department,
29834-30043
2024-07480

Part IV
Management and Budget Office,
30046-30208
2024-07496

Part V
Defense Department,
30210
2024-07930
General Services Administration,
30210
2024-07930
National Aeronautics and Space Administration,
30210
2024-07930

Part VI
Defense Department,
30212-30250
2024-07931
General Services Administration,
30212-30250
2024-07931
National Aeronautics and Space Administration,
30212-30250
2024-07931

Part VII
Defense Department,
30252-30254
2024-07932
General Services Administration,
30252-30254
2024-07932
National Aeronautics and Space Administration,
30252-30254
2024-07932

Part VIII
Defense Department,
30256
2024-07933
General Services Administration,
30256
2024-07933
National Aeronautics and Space Administration,
30256
2024-07933

Reader Aids
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.
To subscribe to the Federal Register Table of Contents electronic mailing list, go to https://public.govdelivery.com/accounts/USGPOOFR/subscriber/new, enter your e-mail address, then follow the instructions to join, leave, or manage your subscription.
89
78
Monday, April 22, 2024
Rules and Regulations
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 39
[Docket No. FAA-2023-2143; Project Identifier MCAI-2023-00088-A; Amendment 39-22718; AD 2024-06-13]
RIN 2120-AA64
Airworthiness Directives; Diamond Aircraft Industries GmbH Airplanes

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Final rule.

SUMMARY:
The FAA is superseding Airworthiness Directive (AD) 2022-21-15 for certain Diamond Aircraft Industries GmbH (DAI) Model DA 42, DA 42 NG, and DA 42 M-NG airplanes. AD 2022-21-15 required replacing the rudder T-yoke axle with an improved rudder T-yoke axle. Since the FAA issued AD 2022-21-15, the European Union Aviation Safety Agency (EASA) superseded its mandatory continuing airworthiness information (MCAI) to correct an unsafe condition on these products. This AD requires, for certain airplanes, inspecting the rudder steering bracket edge distance and depending on the inspection results, inspecting the T-yoke bolt hole for wear and play, and corrective action if necessary. For certain airplanes this AD requires replacing the rudder T-yoke bolt (axle) with a serviceable part, installing a new self-locking nut, and applying torque seal marks on the rudder T-yoke bolt head and self-locking nut. For all airplanes this AD requires repetitively inspecting the torque seal marks on the rudder T-yoke bolt head for proper alignment and the self-locking nut for proper installation and corrective action if necessary. This AD also prohibits the installation of affected parts. The FAA is issuing this AD to address the unsafe condition on these products.

DATES:
This AD is effective May 28, 2024.
The Director of the Federal Register approved the incorporation by reference of certain publications listed in this AD as of May 28, 2024.

ADDRESSES:
AD Docket: You may examine the AD docket at regulations.gov under Docket No. FAA-2023-2143; or in person at Docket Operations between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this final rule, the MCAI, any comments received, and other information. The address for Docket Operations is U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590.
Material Incorporated by Reference:
• For service information contact Diamond Aircraft Industries GmbH, N.A. Otto-Straße 5, A-2700 Wiener Neustadt, Austria; phone: +43 2622 26700; email: airworthiness-austria@diamondaircraft.com; website: diamondaircraft.com.
• You may view this service information at the FAA, Airworthiness Products Section, Operational Safety Branch, 901 Locust, Kansas City, MO 64106. For information on the availability of this material at the FAA, call (817) 222-5110. It is also available at regulations.gov under Docket No. FAA-2023-2143.

FOR FURTHER INFORMATION CONTACT:
Penelope Trease, Aviation Safety Engineer, FAA, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590; phone: (303) 342-1094; email: penelope.trease@faa.gov.

SUPPLEMENTARY INFORMATION:

Background
The FAA issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 to supersede AD 2022-21-15, Amendment 39-22214 (87 FR 67541, November 9, 2022) (AD 2022-21-15). AD 2022-21-15 applied to certain DAI Model DA 42, DA 42 NG, and DA 42 M-NG airplanes. AD 2022-21-15 was prompted by MCAI originated by EASA, which is the Technical Agent for the Member States of the European Union. EASA issued EASA AD 2019-0302, dated December 13, 2019 (EASA AD 2019-0302) to correct an unsafe condition on DAI Model DA 42, DA 42 NG, and DA 42 M-NG airplanes. EASA AD 2019-0302 described the unsafe condition as reports of a loose rudder T-yoke axle nut on DAI Model DA 42 airplanes and the need for new inspections for correct installation of the self-locking nut to the rudder T-yoke standard bolt LN 9037 (dimensions M6x90), and depending on findings, accomplishment of applicable corrective action(s) and replacement of the self-locking nut. EASA AD 2019-0302 also provided an optional terminating action for the repetitive inspections. This condition, if not detected and corrected, could lead to vertical movement of the bolt, possibly resulting in reduced rudder control of the airplane.
AD 2022-21-15 required replacing the rudder T-yoke axle with an improved rudder T-yoke bolt. The FAA issued AD 2022-21-15 to prevent movement of the T-yoke bolt.
The NPRM published in the Federal Register on November 8, 2023 (88 FR 77060). The NPRM was prompted by EASA AD 2023-0013, dated January 18, 2023 (EASA AD 2023-0013) (also referred to as the MCAI) for all Model DA 42, DA 42 M, DA 42 NG, and DA 42 M-NG airplanes. EASA AD 2023-0013 superseded EASA AD 2019-0302.
The MCAI states that since EASA AD 2019-0302 was issued, DAI published revised service information to provide additional inspection and modification instructions. The MCAI requires a one-time inspection of the rudder steering bracket for insufficient edge distance or wear, replacement of rudder T-yoke standard bolt LN 9037 (dimensions M6x90) with rudder T-yoke bolt part number (P/N) D60-5320-00-32, repetitive inspections of rudder T-yoke bolt P/N D60-5320-00-32 for correct installation, corrective actions if necessary, and prohibits installation of rudder T-yoke standard bolt LN 9037 (dimensions M6x90). The affected and serviceable parts, identified as “bolt” in EASA AD 2023-0013, were referred to as “axle” in EASA AD 2019-0302.
This condition, if not detected and corrected, could lead to blockage or loss of rudder control. You may examine the MCAI in the AD docket at regulations.gov under Docket No. FAA-2023-2143.
In the NPRM the FAA proposed to require, for certain airplanes, inspecting the rudder steering bracket edge distance and depending on the inspection results, inspecting the T-yoke bolt hole for wear and play, and corrective action if necessary. For certain airplanes, the NPRM proposed to require replacing the rudder T-yoke bolt (axle) with a serviceable part and applying torque seal marks on the rudder T-yoke bolt head, and self-locking nut. For all airplanes, the NPRM proposed to require repetitively inspecting the torque seal marks on the rudder T-yoke bolt head for proper alignment and the self-locking nut for proper installation and corrective action if necessary. The NPRM also proposed to prohibit the installation of affected parts.

Discussion of Final Airworthiness Directive

Comments
The FAA received comments from three commenters. The commenters were two individuals and DAI. The individuals supported the NPRM without any changes. The following presents the comments received on the NPRM and the FAA's response to each comment.

Request To Extend the Compliance Time
DAI requested that the compliance time in the proposed AD be changed from “Within 200 hours time-in-service (TIS) or 9 months after the effective date of this AD, whichever occurs first” to “Within 200 flight hours or 12 months after the effective date of this AD, whichever occurs first.” DAI explained that the pilot and passenger seats need to be removed prior to the inspection of the rudder steering bracket and the installation of the improved T-yoke bolt and that the removal of these seats is already part of an airplane's annual inspection. DAI noted that extending the compliance time from 9 months to 12 months would allow operators to align the requirements specified in the proposed AD with an airplane's scheduled annual inspection. DAI mentioned that this would avoid unnecessary financial burden for operators. DAI also noted that the formation of wear in the hole in the rudder steering bracket is related to flight time and not a specific period of time. In addition, DAI emphasized that an unnecessary maintenance action that can be avoided also avoids possible maintenance errors.
The FAA agrees with the commenter's request to extend the compliance time from 9 months to 12 months and revised paragraph (h)(1) of this AD to specify “Within 200 hours time-in-service (TIS) or 12 months after the effective date of this AD, whichever occurs first . . . .” Extending the compliance time by 3 months will not adversely affect safety and will allow the inspection of the rudder steering bracket and the installation of the improved T-yoke bolt to be performed during the annual inspection. The FAA does not agree to change “Within 200 hours time-in-service (TIS) . . . .” to “Within 200 flight hours . . . .” Although the MCAI compliance time specifies “flight hours” this AD requires using “hours TIS” because “TIS” is defined in FAA regulations and is used with respect to maintenance records and “flight hours” is not defined in FAA regulations.

Request To Require Entire Work Instruction Instead of Specific Steps
DAI requested that instead of referring to specific steps in the work instructions identified in paragraphs (h)(1) and (2) and paragraph (i) of the proposed AD that the entire work instruction be referred to. DAI stated that it is important to reference the entire document and include all of the steps instead of specific steps because there are additional steps that were not identified in paragraphs (h)(1) and (2) and paragraph (i) of the proposed AD that operators need to do in order to complete the required actions specified in the proposed AD. DAI provided the example that operators must do step 9, release rudder cable turnbuckles, of Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document) because it is important that the T-yoke bolt and self-locking nut are tightened with released rudder cable tension.
The FAA agrees to require additional steps from the applicable work instructions in paragraphs (h)(2) and (i) of this AD but does not agree to require compliance with the entire work instruction document. The requirements of this AD correspond with the requirements in EASA AD 2023-0013. EASA AD 2023-0013 only requires the following specific steps from the work instructions: inspecting the edge distance and repair if required, inspecting the hole and repair if required, replacing an affected part with a serviceable part, and marking the head of the T-yoke bolt and the self-locking nut.
The FAA acknowledges that doing additional steps in the work instructions is necessary to complete the actions required by this AD, for example, removing the pilot and passenger seats prior to the inspection of the rudder steering bracket and the installation of the improved T-yoke bolt; however, to provide operators flexibility regarding how the required steps are accomplished, the FAA does not require that operators follow all of the steps in the work instructions. For example, 14 CFR part 135 operators could have their own maintenance program which includes instructions regarding pilot and passenger seat removal. Requiring seat removal in accordance with the work instructions would create an unnecessary burden on operators because they would have to submit an alternative method of compliance (AMOC) request to the FAA if they did not follow the process specified in the work instructions to remove the seats.
Paragraph (h)(2) of this AD was revised to add steps 9 and 10 of Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document), with the exception that instead of discarding a self-locking nut an operator is required to remove that part from service. Steps 9 and 10 of that work instruction specify releasing the rudder cable turnbuckles and removing and discarding the self-locking nut of the T-yoke bolt.
Paragraph (i) of this AD was revised to add steps 6 through 9 of the Instructions, Section III, in Diamond Aircraft Work Instruction WI-RSB 42-139 and WI-RSB 42NG-081, Revision 2, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Recommended Service Bulletin DAI RSB 42-139 and DAI RSB 42NG-081, dated October 21, 2019 (issued as one document), with the exception that instead of discarding a self-locking nut an operator is required to remove that part from service. Steps 6 through 9 of that work instruction are included in the “Replacement of rudder T-yoke bolt” instructions and specify procedures for accessing the rudder T-yoke bolt, which include disconnecting the nose landing gear (NLG) steering linkage at the steering cardan in the wheel well, releasing the rudder cable turnbuckles, removing the self-locking nut of the T-yoke bolt, discarding the nut, and removing the T-yoke bolt from the rudder steering bracket.

Request To Require Application of Torque Seal Marks for Group 1 Minus Group 2 Airplanes
DAI requested that the requirement to apply torque seal marks be added in paragraph (h) of the proposed AD because that action should also be done on Group 1 minus Group 2 airplanes. DAI noted that the requirement to apply torque seal marks was only included in paragraph (i) of the proposed AD and was only applicable to Group 2 airplanes.
The FAA agrees with the commenter's request but instead of revising paragraph (h) of this AD, the FAA revised paragraph (i) of this AD to change the header from “Replacement” to “Replacement and Application of Torque Seal Marks,” added paragraph (i)(1) that is applicable to Group 1 airplanes that are not also Group 2 airplanes, and moved the content of paragraph (i) of the proposed AD to paragraph (i)(2) of this AD.

Request To Have Operator Contact Only DAI for Post-Inspection Instructions
DAI requested that paragraphs (h)(3) and (4) of the proposed AD be revised to require operators to contact only DAI for post-inspection instructions instead of contacting “. . . the Manager, International Validation Branch, FAA; the European Union Aviation Safety Agency (EASA); or Diamond's EASA Design Organization Approval (DOA) . . . .” DAI noted that depending on the extent of the inspection findings, in the case of a too large edge distance or a worn or enlarged hole on the rudder steering bracket, the rudder steering bracket could be repaired instead of being replaced. The commenter stated that the intention is to avoid the replacement of the rudder steering bracket if possible, but this has to be determined for each airplane by DAI experts.
The FAA does not agree with the commenter's request. The FAA acknowledges that not all discrepancies will result in a rudder steering bracket having to be replaced and that some rudder steering brackets can be repaired. The FAA cannot delegate repair approval authority to a single outside entity; however, the current language in paragraphs (h)(3) and (4) of this AD provides operators the option to contact DAI's EASA DOA with the inspection findings for a determination regarding if the affected rudder steering bracket can be repaired or must be replaced. The FAA has not changed this AD regarding this issue.

Request To Clarify “Proposed AD Requirements in This NPRM” Section
DAI requested clarification of the proposed requirement regarding repetitive inspections of the torque seal marks in the “Proposed AD Requirements in this NPRM” section of the NPRM. DAI stated that existing wording could be misinterpreted to mean the inspections would only apply to the torque seal marks on the T-yoke bolt head and clarification was needed to specify that the repetitive inspections are visual inspections of the torque seal marks for proper alignment on the T-yoke bolt head and the self-locking nut.
The FAA acknowledges the commenter's request and agrees that the proposed wording clarifies the requirement in this AD regarding the repetitive inspections of the torque seal marks; however, the “Proposed AD Requirements in this NPRM” section is not carried over to the final rule. The FAA has not changed this AD regarding this issue.

Conclusion
These products have been approved by the aviation authority of another country and are approved for operation in the United States. Pursuant to the FAA's bilateral agreement with this State of Design Authority, it has notified the FAA of the unsafe condition described in the MCAI referenced above. The FAA reviewed the relevant data, considered the comments received, and determined that air safety requires adopting this AD as proposed. Accordingly, the FAA is issuing this AD to address the unsafe condition on these products. Except for any changes described previously, this AD is adopted as proposed in the NPRM. None of the changes will increase the economic burden on any operator.

Related Service Information Under 1 CFR Part 51
The FAA reviewed Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document), published with DAI Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached. The service bulletin specifies compliance with the work instruction, which contains procedures for inspecting the hole position and condition in the rudder steering bracket.
The FAA also reviewed Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-146 and DAI MSB 42NG-087, dated November 15, 2022 (issued as one document). The service bulletin specifies the serial numbers for affected airplanes defined as Group 2 airplanes in paragraph (g)(2) of this AD.
In addition, the FAA reviewed Diamond Aircraft Recommended Service Bulletin DAI RSB 42-139 and DAI RSB 42NG-081, dated October 21, 2019 (issued as one document), published with DAI Work Instruction WI-RSB 42-139 and WI-RSB 42NG-081, Revision 2, dated November 15, 2022 (issued as one document) attached. The service bulletin specifies compliance with the work instruction, which contains procedures for replacement of the rudder T-yoke axle with an improved (additional retaining pin) rudder T-yoke axle.
This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in ADDRESSES .

Differences Between This AD and the MCAI
The MCAI applies to DAI Model DA 42 M airplanes and this AD does not because those airplanes do not have an FAA type certificate.
Paragraph (1) of the MCAI specifies a compliance time of within 200 flight hours or 9 months after the effective date of the MCAI, whichever occurs first, for measuring the distance between the edge of the rudder steering bracket hole and rear edge of the rudder steering bracket but this AD requires doing that action within 200 hours TIS or 12 months after the effective date of this AD, whichever occurs first. Extending the compliance time by three months will not adversely affect safety and will allow this action to be done during regularly scheduled maintenance. Although the MCAI compliance time specifies “flight hours” this AD requires using “hours TIS.”
Paragraph (3) of the MCAI specifies to contact the manufacturer for repair instructions and paragraph (7) of the MCAI specifies to contact the manufacturer for corrective actions if any discrepancy is found, but for both of those corrective actions, this AD requires contacting either the Manager, International Validation Branch, FAA; EASA; or Diamond's EASA DOA instead. If approved by the DOA, the approval must include the DOA-authorized signature.

Costs of Compliance
The FAA estimates that this AD affects 205 airplanes of U.S. registry. The FAA estimates the following costs to comply with this AD:
Estimated Costs
Action | Labor cost | Parts cost | Cost per product | Cost on U.S. operators
Inspection of rudder steering bracket edge distance | 0.25 work-hour × $85 per hour = $21.25 | $0 | $21.25 | $4,356.25.
Replacement of rudder t-yoke bolt P/N LN 9037 with P/N D60-5320-0032 | 0.50 work-hour × $85 per hour = $42.50 | 82 | $124.50 | $25,522.50.
Application of torque seal marks to rudder T-yoke bolt and self-locking nut | 0.75 work-hour × $85 per hour = $63.75 | 15 | $78.75 | $16,143.75.
Repetitive inspection of torque seal marks | 0.25 work-hour × $85 per hour | 0 | $21.25, per inspection | $4,356.25, per inspection.
The FAA estimates the following costs to do any necessary on-condition action that would be required based on the results of any required actions. The FAA has no way of determining the number of aircraft that might need this on-condition action:
On-Condition Costs
Action | Labor cost | Parts cost | Cost per product
Inspection of rudder steering bracket hole for wear and play, if edge distance is equal to or greater than 11 millimeters | 0.50 work-hour × $85 per hour = $42.50 | $0 | $42.50
Since the replacement or repair instructions could vary significantly from airplane to airplane if discrepancies are found during the inspections, the FAA has no data to determine the number of airplanes that would need follow-on actions or what the cost per airplane would be.

Authority for This Rulemaking
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.
The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

Regulatory Findings
The FAA has determined that this AD will not have federalism implications under Executive Order 13132. This AD will not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify that this AD:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Will not affect intrastate aviation in Alaska, and
(3) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

List of Subjects in 14 CFR Part 39
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.

The Amendment
Accordingly, under the authority delegated to me by the Administrator, the FAA amends 14 CFR part 39 as follows:

PART 39—AIRWORTHINESS DIRECTIVES
1. The authority citation for part 39 continues to read as follows:

Authority:
49 U.S.C. 106(g), 40113, 44701.
§ 39.13
[Amended]
2. The FAA amends § 39.13 by:
a. Removing Airworthiness Directive 2022-21-15, Amendment 39-22214 (87 FR 67541, November 9, 2022); and
b. Adding the following new airworthiness directive:
2024-06-13 Diamond Aircraft Industries GmbH: Amendment 39-22718; Docket No. FAA-2023-2143; Project Identifier MCAI-2023-00088-A.

(a) Effective Date
This airworthiness directive (AD) is effective May 28, 2024.

(b) Affected ADs
This AD replaces AD 2022-21-15, Amendment 39-22214 (87 FR 67541, November 9, 2022).

(c) Applicability
This AD applies to Diamond Aircraft Industries GmbH (DAI) Model DA 42, DA 42 NG, and DA 42 M-NG airplanes, all serial numbers, certificated in any category.

(d) Subject
Joint Aircraft System Component (JASC) Code 2700, Flight Control System.

(e) Unsafe Condition
This AD was prompted by reports of a loose rudder T-yoke bolt nut, excessive wear of the hole, and insufficient hole edge margin at the rudder steering bracket. The FAA is issuing this AD to detect and correct vertical movement of the T-yoke bolt (axle). The unsafe condition, if not addressed, could lead to blockage or loss of rudder control and result in reduced control of the airplane.

(f) Compliance
Comply with this AD within the compliance times specified, unless already done.

(g) Definitions
For the purposes of this AD, the following definitions apply.
(1) Group 1 airplanes: Airplanes with serial numbers specified in Technical Details, section I.2, of Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document), published with DAI Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached.
(2) Group 2 airplanes: Airplanes with serial numbers specified in Technical Details, section I.2, of Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-146 and DAI MSB 42NG-087, dated November 15, 2022 (issued as one document).
(3) Group 3 airplanes: Airplanes that are not in Group 1 or Group 2.
(4) Depending on the serial number, a Group 1 airplane can also be a Group 2 airplane.

(h) Inspections and Corrective Actions
For Group 1 and Group 2 airplanes: Do the inspection required by paragraph (h)(1) of this AD at the compliance time specified in paragraph (h)(1) of this AD and the applicable corrective actions specified in paragraphs (h)(2) through (4) of this AD at the applicable compliance times specified in paragraphs (h)(2) through (4) of this AD.
(1) Within 200 hours time-in-service (TIS) or 12 months after the effective date of this AD, whichever occurs first, inspect the rudder steering bracket edge distance by measuring in accordance with step 6 of the Instructions, Section III, in Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document).
(2) If, during the inspection required by paragraph (h)(1) of this AD, the measured distance is equal to or greater than 11 millimeters (mm), before further flight, inspect the hole in the rudder steering bracket for wear and play in accordance with steps 9 through 11 of the Instructions, Section III, in Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document). Where Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document) specifies to discard the self-locking nut this AD requires removing that part from service.
(3) If, during the inspection required by paragraph (h)(1) of this AD, the measured distance is less than 11 mm, before further flight, contact the Manager, International Validation Branch, FAA; the European Union Aviation Safety Agency (EASA); or Diamond's EASA Design Organization Approval (DOA) for repair instructions, and within the compliance time specified therein, complete the repair. If approved by the DOA, the approval must include the DOA-authorized signature.
(4) If, during the inspection required by paragraph (h)(2) of this AD, a worn or enlarged hole is found on the rudder steering bracket, or if the T-yoke bolt is found to have play, before further flight, contact the Manager, International Validation Branch, FAA; EASA; or Diamond's EASA DOA for instructions (repair or replacement of the rudder steering bracket), and within the compliance time specified therein, do the instructions. If approved by the DOA, the approval must include the DOA-authorized signature.

(i) Replacement and Application of Torque Seal Marks
(1) For Group 1 airplanes that are not also Group 2 airplanes: Concurrently with the inspection required by paragraph (h)(1) of this AD, replace the rudder T-yoke bolt part number (P/N) LN 9037-M6x90 with rudder T-yoke bolt P/N D60-5320-00-32, and apply torque seal marks on the rudder T-yoke bolt head and self-locking nut, in accordance with steps 13 through 15 of the Instructions, Section III, in Diamond Aircraft Work Instruction WI-MSB 42-143 and WI- MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document).
(2) For Group 2 airplanes: Concurrently with the inspection required by paragraph (h)(1) of this AD, replace the rudder T-yoke bolt part number (P/N) LN 9037-M6x90 with rudder T-yoke bolt P/N D60-5320-00-32, and apply torque seal marks on the rudder T-yoke bolt head and self-locking nut, in accordance with steps 6 through 9, 14, 15, and 18 of the Instructions, Section III, in Diamond Aircraft Work Instruction WI-RSB 42-139 and WI-RSB 42NG-081, Revision 2, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Recommended Service Bulletin DAI RSB 42-139 and DAI RSB 42NG-081, dated October 21, 2019 (issued as one document). Where Diamond Aircraft Work Instruction WI-RSB 42-139 and WI-RSB 42NG-081, Revision 2, dated November 15, 2022 (issued as one document) attached to Diamond Aircraft Recommended Service Bulletin DAI RSB 42-139 and DAI RSB 42NG-081, dated October 21, 2019 (issued as one document) specifies to discard the self-locking nut this AD requires removing that part from service.

(j) Repetitive Inspections
(1) For Group 1 and Group 2 airplanes: Within 200 hours TIS after the inspection required by paragraph (h)(1) of this AD and, thereafter, at intervals not to exceed 200 hours TIS, inspect the torque seal marks on the T-yoke bolt head and self-locking nut for proper alignment.
Note 1 to paragraph (j)(1): This can be accomplished using DAI Maintenance Manual (AMM) Temporary Revision (TR) AMM-TR-MÄM-42-1213/a, dated June 7, 2022 (DAI AMM TR AMM-TR-MÄM-42-1213/a).
(2) For Group 3 airplanes: Within 200 hours TIS after the effective date of this AD, and thereafter at intervals not to exceed 200 hours TIS, inspect the torque seal marks on the T-yoke bolt head and self-locking nut for proper alignment.
Note 2 to paragraph (j)(2): This can be accomplished using DAI AMM TR AMM-TR-MÄM-42-1213/a.
(3) For all airplanes: If, during any inspection required by paragraph (j)(1) or (j)(2) of this AD, it is found that the torque seal marks are not properly aligned, before further flight, contact the Manager, International Validation Branch, FAA; EASA; or Diamond's EASA DOA for approved repair instructions, and within the compliance time specified therein, accomplish those instructions accordingly. If approved by the DOA, the approval must include the DOA-authorized signature.

(k) Parts Installation Prohibition
For all airplanes: As of the effective date of this AD, do not install on any airplane a rudder T-yoke bolt P/N LN 9037-M6x90.

(l) Credit for Previous Actions
(1) You may take credit for the actions required by paragraphs (h)(1) and (2) of this AD if the actions were done before the effective date of this AD using any of the work instructions specified in paragraphs (l)(1)(i), (ii), or (iii) of this AD.
(i) Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 0, dated December 23, 2021 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143 and DAI MSB 42NG-086, dated December 23, 2021 (issued as one document).
(ii) Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 1, dated January 25, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document).
(iii) Diamond Aircraft Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 2, dated March 10, 2022 (issued as one document) attached to Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document).
(2) You may take credit for the rudder T-yoke bolt replacement required by paragraph (i) of this AD if that action was done before the effective date of this AD using the Diamond Aircraft Work Instruction WI-RSB 42-139 and WI-RSB 42NG-081, Revision 1, dated October 24, 2019 (issued as one document) attached to Diamond Aircraft Recommended Service Bulletin DAI RSB 42-139 and DAI RSB 42NG-081, dated October 21, 2019 (issued as one document).

(m) Alternative Methods of Compliance (AMOCs)
The Manager, International Validation Branch, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly to the International Validation Branch, send it to the attention of the person identified in paragraph (n)(2) of this AD or email to: 9- AVS-AIR-730-AMOC@faa.gov. If mailing information, also submit information by email. Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the responsible Flight Standards Office.

(n) Additional Information
(1) Refer to EASA AD 2023-0013, dated January 18, 2023, for related information. This EASA AD may be found in the AD docket at regulations.gov under Docket No. FAA-2023-2143.
(2) For more information about this AD, contact Penelope Trease, Aviation Safety Engineer, FAA, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590; phone: (303) 342-1094; email: penelope.trease@faa.gov.
(3) Service information identified in this AD that is not incorporated by reference is available at the address specified in paragraph (o)(3) of this AD.

(o) Material Incorporated by Reference
(1) The Director of the Federal Register approved the incorporation by reference (IBR) of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
(2) You must use this service information as applicable to do the actions required by this AD, unless the AD specifies otherwise.
(i) Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-143/1 and DAI MSB 42NG-086/1, dated January 25, 2022 (issued as one document), published with DAI Work Instruction WI-MSB 42-143 and WI-MSB 42NG-086, Revision 3, dated November 15, 2022 (issued as one document) attached.
(ii) Diamond Aircraft Mandatory Service Bulletin DAI MSB 42-146 and DAI MSB 42NG-087, dated November 15, 2022 (issued as one document).
(iii) Diamond Aircraft Recommended Service Bulletin DAI RSB 42-139 and DAI RSB 42NG-081, dated October 21, 2019 (issued as one document), published with DAI Work Instruction WI-RSB 42-139 and WI-RSB 42NG-081, Revision 2, dated November 15, 2022 (issued as one document) attached.
(3) For service information contact Diamond Aircraft Industries GmbH, N.A. Otto-Straße 5, A-2700 Wiener Neustadt, Austria; phone: +43 2622 26700; email: airworthiness-austria@diamondaircraft.com; website: diamondaircraft.com .
(4) You may view this service information at the FAA, Airworthiness Products Section, Operational Safety Branch, 901 Locust, Kansas City, MO 64106. For information on the availability of this material at the FAA, call (817) 222-5110. It is also available at regulations.gov under Docket No. FAA-2023-2143.
(5) You may view this material at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email fr.inspection@nara.gov.
Issued on March 22, 2024.
Victor Wicklund,

Deputy Director, Compliance & Airworthiness Division, Aircraft Certification Service.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Parts 61, 63, and 65
[Docket No. FAA-2022-1463; Amdt. No. 65-64A]
RIN 2120-AL74
Airman Certification Standards and Practical Test Standards for Airmen; Incorporation by Reference

AGENCY:
Federal Aviation Administration (FAA), Department of Transportation (DOT).

ACTION:
Final rule; correction.

SUMMARY:
On April 1, 2024, the Federal Aviation Administration (FAA) published a final rule in the Federal Register to incorporate certain Airman Certification Standards and Practical Test Standards by reference into the certification requirements for pilots, flight instructors, flight engineers, aircraft dispatchers, and parachute riggers. In that final rule, the FAA incorrectly set forth certain regulatory text which, if not corrected, would remove certain content from the Code of Federal Regulations the FAA did not intend to remove. This correction remedies the error.

DATES:
Effective on May 31, 2024.

ADDRESSES:
For information on where to obtain copies of rulemaking documents and other information related to this final rule, see “How to Obtain Additional Information” in the SUPPLEMENTARY INFORMATION section of this document.

FOR FURTHER INFORMATION CONTACT:
James Ciccone, Training and Certification Group, AFS-810, Federal Aviation Administration, 800 Independence Avenue SW, Washington, DC 20591; telephone (202) 267-1100; email ACSPTSinquiries@faa.gov.

SUPPLEMENTARY INFORMATION:
On April 1, 2024, the Federal Aviation Administration (FAA) published the final rule, Airman Certification Standards and Practical Test Standards for Airmen; Incorporation by Reference. ^1 That final rule adopted several amendments to parts 61, 63, and 65 of Title 14 of the Code of Federal Regulations (14 CFR) by incorporating by reference (IBR) the Airman Certification Standards (ACS) and Practical Test Standards (PTS). The ACS and PTS ^2 serve as the testing standards for airman certificates and rating practical tests. Among other things, the final rule revised § 65.119(a) to require compliance with the respective PTS for parachute riggers. However, the FAA inadvertently set forth only the revisions to the introductory text of paragraph (a) and did not address the undesignated paragraph at the end of paragraph (a). The FAA is correcting this error by setting forth the entirety of paragraph (a) and designating the currently-undesignated paragraph at the end of paragraph (a) as paragraph (a)(3).
^1 89 FR 22482 FR Doc 2024-06644.
^2 ACS and PTS refers to both the singular Standard and the plural Standards throughout the document.

Correction
Effective May 31, 2024, in rule document 2024-06644 at 89 FR 22482 in the issue of April 1, 2024, on page 22520, in the third column, in amendatory instruction 16, paragraph a is corrected to read as follows:
§ 65.119
[Corrected]
* * * * *
(a) Present evidence satisfactory to the Administrator that the applicant has had at least 3 years of experience as a parachute rigger and has satisfactorily packed at least 100 parachutes of each of two types in common use, in accordance with the manufacturer's instructions—
(1) While a certificated and appropriately rated senior parachute rigger; or
(2) While under the supervision of a certificated and appropriately rated parachute rigger or a person holding appropriate military ratings.
(3) An applicant may combine experience specified in paragraphs (a)(1) and (2) of this section to meet the requirements of this paragraph (a).
* * * * *
Issued under authority provided by 49 U.S.C. 106(f), 40113, 44701, 44702, and 44703 in Washington, DC.
Brandon Roberts,

Executive Director, Office of Rulemaking.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 71
[Docket No. FAA-2023-2105; Airspace Docket No. 22-AAL-61]
RIN 2120-AA66
Amendment of Alaskan Very High Frequency Omnidirectional Range Federal Airway V-506 in the Vicinity of Kodiak, AK

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Final rule.

SUMMARY:
This action amends Alaskan Very High Frequency Omnidirectional Range Federal airway (VOR) V-506 in the vicinity of Kodiak, AK. The FAA is taking this action due to the loss of signal from the Kodiak, AK, VOR and due to the pending decommissioning of the Hotham, AK, Nondirectional Radio Beacon (NDB).

DATES:
Effective date 0901 UTC, July 11, 2024. The Director of the Federal Register approves this incorporation by reference action under 1 CFR part 51, subject to the annual revision of FAA Order JO 7400.11 and publication of conforming amendments.

ADDRESSES:
A copy of the Notice of Proposed Rulemaking (NPRM), all comments received, this final rule, and all background material may be viewed online at www.regulations.gov using the FAA Docket number. Electronic retrieval help and guidelines are available on the website. It is available 24 hours each day, 365 days each year.
FAA Order JO 7400.11H, Airspace Designations and Reporting Points, and subsequent amendments can be viewed online at www.faa.gov/air_traffic/publications/. You may also contact the Rules and Regulations Group, Office of Policy, Federal Aviation Administration, 800 Independence Avenue SW, Washington DC 20591; telephone: (202) 267-8783.

FOR FURTHER INFORMATION CONTACT:
Steven Roff, Rules and Regulations Group, Office of Policy, Federal Aviation Administration, 800 Independence Avenue SW, Washington, DC 20591; telephone: (202) 267-8783.

SUPPLEMENTARY INFORMATION:

Authority for This Rulemaking
The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of the airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority as it modifies the Air Traffic Service (ATS) route structure as necessary to preserve the safe and efficient flow of air traffic within the National Airspace System.

History
The FAA published a NPRM for Docket No. FAA 2023-2105 in the Federal Register (88 FR 71781; October 18, 2023), proposing to amend V-506 in the vicinity of Kodiak, AK. Interested parties were invited to participate in this rulemaking effort by submitting written comments on the proposal to the FAA. No comments were received.

Differences From the NPRM
The NPRM published for Docket No. FAA-2023-2105 in the Federal Register (88 FR 71781; October 18, 2023) contained a typographical error in the regulatory text. The NPRM listed V-508 as the airway to be amended. The NPRM should have listed V-506 as the airway to be amended by Docket No. FAA-2023-2105. This rule corrects this error.

Incorporation by Reference
Alaskan VOR Federal airways are published in paragraph 6010(b) of FAA Order JO 7400.11, Airspace Designations and Reporting Points, which is incorporated by reference in 14 CFR 71.1 on an annual basis. This document amends the current version of that order, FAA Order JO 7400.11H, dated August 11, 2023, and effective September 15, 2023. FAA Order JO 7400.11H is publicly available as listed in the ADDRESSES section of this document. These amendments will be published in the next update to FAA Order JO 7400.11.
FAA Order JO 7400.11H lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The Rule
This action amends 14 CFR part 71 by amending Alaskan Federal Airway V-506 in the vicinity of Kodiak, AK. The FAA is taking this action due to the loss of signal from the Kodiak, AK, VOR and due to the pending decommissioning of the Hotham, AK, NDB. The airspace action is described below.
V-506: Alaskan Federal Airway V-506 extends between the Kotzebue Very High Frequency Omnidirectional Range/Distance Measuring Equipment (VOR/DME) and the King Salmon VORTAC.

Regulatory Notices and Analyses
The FAA has determined that this regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore: (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a regulatory evaluation as the anticipated impact is so minimal. Since this is a routine matter that only affects air traffic procedures and air navigation, it is certified that this rule, when promulgated, does not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Environmental Review
The FAA has determined that this airspace action of amending Alaskan VOR Federal Airway V-506 in the vicinity of Kodiak, AK qualifies for categorical exclusion under the National Environmental Policy Act (42 U.S.C. 4321 et seq. ) and its implementing regulations at 40 CFR part 1500, and in accordance with FAA Order 1050.1F, Environmental Impacts: Policies and Procedures, paragraph 5-6.5a, which categorically excludes from further environmental impact review rulemaking actions that designate or modify classes of airspace areas, airways, routes, and reporting points (see 14 CFR part 71, Designation of Class A, B, C, D, and E Airspace Areas; Air Traffic Service Routes; and Reporting Points), and paragraph 5-6.5k, which categorically excludes from further environmental review the publication of existing air traffic control procedures that do not essentially change existing tracks, create new tracks, change altitude, or change concentration of aircraft on these tracks. As such, this action is not expected to result in any potentially significant environmental impacts. In accordance with FAA Order 1050.1F, paragraph 5-2 regarding Extraordinary Circumstances, the FAA has reviewed this action for factors and circumstances in which a normally categorically excluded action may have a significant environmental impact requiring further analysis. Accordingly, the FAA has determined that no extraordinary circumstances exist that warrant preparation of an environmental assessment or environmental impact study.

List of Subjects in 14 CFR Part 71
Airspace, Incorporation by reference, Navigation (air).

The Amendment
In consideration of the foregoing, the Federal Aviation Administration amends 14 CFR part 71 as follows:

PART 71—DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR TRAFFIC SERVICE ROUTES; AND REPORTING POINTS
1. The authority citation for 14 CFR part 71 continues to read as follows:

Authority:
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
§ 71.1
[Amended]
2. The incorporation by reference in 14 CFR 71.1 of FAA Order JO 7400.11H, Airspace Designations and Reporting Points, dated August 11, 2023, and effective September 15, 2023, is amended as follows:

Paragraph 6010(b) Alaskan VOR Federal Airways.
* * * * *

V-506 [Amended]
From Kotzebue, AK; 53 miles 12 AGL, 71 miles 55 MSL, 35 miles 12 AGL; Nome, AK; Bethel, AK; 63 miles 12 AGL, 84 miles 70 MSL, 51 miles 12 AGL; to King Salmon, AK.
* * * * *
Issued in Washington, DC, on April 16, 2024.
Frank Lias,

Manager, Rules and Regulations Group.
DEPARTMENT OF COMMERCE
Bureau of Industry and Security
15 CFR Part 746
[Docket No. 240417-0112]
RIN 0694-AJ61
Export Control Measures Under the Export Administration Regulations (EAR) To Address Iranian Aggression Against Israel and Military Support for Russia

AGENCY:
Bureau of Industry and Security, Department of Commerce.

ACTION:
Final rule.

SUMMARY:
In this final rule, the Bureau of Industry and Security (BIS) makes changes to the Export Administration Regulations (EAR) to expand the scope of items that require a license for export and reexport to Iran; this rule also expands the scope of the Russia/Belarus/Temporarily occupied Crimea region of Ukraine Foreign Direct Product (FDP) rule and the Iran FDP rule. Certain foreign-made items located outside of the United States are subject to the EAR because they meet criteria specified under one of the FDP rules under the EAR. This final rule expands the product scope of two of the FDP rules to make additional items subject to the EAR and imposes a license requirement when they are reexported or exported from abroad to Iran, Russia, Belarus, or the Temporarily occupied Crimea region of Ukraine. Prior to this rule, BIS had not controlled all foreign transactions involving items covered by this rule, but in light of recent events and the need to fully leverage EAR controls to address U.S. national security and foreign policy interests, these additional controls are now warranted under the EAR.

DATES:
This rule is effective on April 18, 2024.

FOR FURTHER INFORMATION CONTACT:
For questions on this final rule, contact Tracy Patts, Supervisory Export Policy Analyst, Office of Nonproliferation and Foreign Policy Controls, Bureau of Industry and Security, Department of Commerce, Phone: 202-482-4252, Email: Foreign.Policy@bis.doc.gov
For emails, include “supplement no. 7” in the subject line.

SUPPLEMENTARY INFORMATION:

I. Background
On April 13, 2024, the Islamic Republic of Iran and its proxies conducted an unprecedented air attack on Israel. Iran's destabilizing actions endanger the region and all its people. In addition, Iran's military cooperation with Russia has increased Russia's capacity to wage war against Ukraine while enabling advancements in Iran's and Russia's military capabilities. Consistent with the U.S. Government's commitment to restrict Iran from obtaining any item that might contribute to its manufacture of missiles, including those used against Israel and Ukraine, this rule amends the EAR to impose new controls restricting Iran's access to additional low-level technology, including items manufactured outside the United States that are produced using U.S. technology, i.e., through the Iran FDP Rule in § 734.9(j) of the EAR.
Iran is already subject to comprehensive export restrictions under U.S. law, including licensing requirements described in § 746.7 of the EAR. This rule builds on BIS's February 2023 action that targeted Iran's involvement in supplying Unmanned Aerial Vehicles (UAVs) in support of Russia's war in Ukraine (see 88 FR 12150, February 24, 2023) In that rule, BIS imposed export and reexport license requirements on a subset of EAR99 items, i.e., items not specified on the Commerce Control List (CCL, supplement no. 1 to part 774 of the EAR) if destined to Iran, regardless of whether a U.S. person is involved in the transaction. BIS also added a new Iran Foreign Direct Product rule for items in certain categories of the CCL and for certain other items identified by Harmonized Tariff System Codes at the six-digit level (HTS-6 Codes) in supplement no. 7 to part 746 of the EAR in the February 24, 2023 rule. On January 23, 2024, BIS expanded the list of items included in supplement no. 7 to part 746 of the EAR (see 89 FR 4804, January 23, 2024).
Russia, Belarus, and certain temporarily occupied regions of Ukraine have been subjected to increasing export controls since Russia's full-scale invasion of Ukraine on February 24, 2022. There are now thousands of categories of items controlled to these destinations, including those controlled together with substantially aligned allies and partners in the Global Export Control Coalition (GECC). Export controls in the EAR extend to foreign produced items caught by the Russia/Belarus/Temporarily occupied Crimea region of Ukraine FDP rule in § 734.9(f) of the EAR (Russia FDPR), ensuring that foreign items produced with controlled software and technology are also caught by U.S. restrictions. The continued expansion of controls on Russia, Belarus, and the temporarily occupied regions of Ukraine meets U.S. national security and foreign policy objectives to continue the degradation of Russia's ability to execute its war against Ukraine.
This action is consistent with U.S. policy objectives to continue to strengthen the impact of export control measures in response to Iran's attack on Israel and Iran's support for Russia's war in Ukraine by limiting Iran's and Russia's access to certain EAR99 items critical to their weapons programs.

II. Overview of New Controls
This rule revises the EAR to enhance and strengthen existing measures against Iran, Russia, and Belarus. Specifically, this rule further expands the list of items included in supplement no. 7 to part 746 to include additional items that are critical to Iran and Russia's weapons programs. The export control measures in this final rule build upon the national security and foreign policy objectives of the United States. The expansion of items included in supplement no. 7 to part 746 will enhance the effectiveness of export controls on Iran and Russia by further limiting access to items that enable their military capabilities.
While BIS's controls cover a vast array of items necessary to the defense industries of Iran and Russia, certain items are more significant to their weaponry than others. The items in supplement no. 7 to part 746 will now include the entirety of the `Common High Priority List' (CHPL). ( See https://www.bis.doc.gov/index.php/all-articles/13-policy-guidance/country-guidance/2172-russia-export-controls-list-of-common-high-priority-items ) BIS, in coordination with its partners in the European Union, Japan, and the United Kingdom, developed the CHPL to jointly identify items used in Russian weapons development by HTS-6 Codes. The 50 CHPL HTS-6 Codes include electronic components such as integrated circuits and radio frequency (RF) transceiver modules, items essential for the manufacturing and testing of electronic components, and computer numerically controlled (CNC) machine tools. Iran's drone program is also dependent on foreign sources for these items. In adding 39 additional items to supplement no. 7 to part 746, the supplement will now include all 50 Common High Priority items.

III. Amendments to the EAR
This rule expands the list of items in supplement no. 7 to part 746 (Items That Require a License Under § 746.6 When Destined to the Temporarily Occupied Crimea region of Ukraine, Under § 746.7 When Destined to Iran, and Under § 746.8 When Destined to Russia or Belarus) by adding 39 additional HTS-6 Code entries (845710, 845811, 845891, 845961, 846693, 847180, 848210, 848220, 848230, 848250, 848610, 848620, 848640, 850440, 851769, 852589, 852990, 853400, 853669, 853690, 854110, 854121, 854129, 854130, 854149, 854151, 854159, 854160, 854320, 880730, 901310, 901380, 901420, 901480, 902750, 903020, 903032, 903039, and 903082).
All items subject to the EAR that are classified under these HTS-6 entries already require a license for export, reexport, or transfer (in-country) to Russia and Belarus under § 746.5 of the EAR. In addition, CCL and U.S.-origin EAR99 items classified under these HTS-6 entries are prohibited for export or reexport to Iran under § 746.7(e) of the EAR. By adding these items to supplement no. 7 to part 746, BIS jurisdiction over foreign produced items in these categories will be expanded, which will in turn expand license requirements for Russia and Belarus under § 746.8(a)(2). The addition of these codes to supplement no. 7 to part 746 will also expand EAR restrictions over foreign transactions with Iran under § 746.7(a). The restrictions on these items are intended to further undermine the ability of Iran and Russia to support the production of missiles, drones, and other military items for use against Israel and Ukraine.

Savings Clause
Shipments of items removed from eligibility for a License Exception or export, reexport, or transfer (in-country) without a license (NLR) as a result of this regulatory action that were en route aboard a carrier to a port of export, reexport, or transfer (in-country), on April 18, 2024, pursuant to actual orders for export, reexport, or transfer (in-country) to or within a foreign destination, may proceed to that destination under the previous eligibility for a License Exception or export, reexport, or transfer (in-country) without a license (NLR), provided the export, reexport, or transfer (in-country) is completed no later than on May 20, 2024.

Export Control Reform Act of 2018
On August 13, 2018, the President signed into law the John S. McCain National Defense Authorization Act for Fiscal Year 2019, which included the Export Control Reform Act of 2018 (ECRA) (codified, as amended, at 50 U.S.C. 4801-4852). ECRA provides the legal basis for BIS's principal authorities and serves as the authority under which BIS issues this rule.

Rulemaking Requirements
1. BIS has examined the impact of this rule as required by Executive Orders 12866, 13563, and 14094, which direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits ( e.g., potential economic, environmental, public, health, and safety effects, distributive impacts, and equity). Pursuant to E.O. 12866, as amended, this final rule is not a “significant regulatory action.”
2. Notwithstanding any other provision of law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ) (PRA), unless that collection of information displays a currently valid Office of Management and Budget (OMB) Control Number. This rule involves the following OMB-approved collections of information subject to the PRA:
• 0694-0088, “Simple Network Application Process and Multipurpose Application Form,” which carries a burden hour estimate of 29.4 minutes for a manual or electronic submission;
• 0694-0096 “Five Year Records Retention Period,” which carries a burden hour estimate of less than 1 minute; and
• 0607-0152 “Automated Export System (AES) Program,” which carries a burden hour estimate of 3 minutes per electronic submission.
BIS estimates that these new controls on Iran under the EAR will result in an increase of five license applications submitted annually to BIS. However, the additional burden falls within the existing estimates currently associated with these control numbers. Additional information regarding these collections of information—including all background materials—can be found at https://www.reginfo.gov/public/do/PRAMain by using the search function to enter either the title of the collection or the OMB Control Number.
3. This rule does not contain policies with federalism implications as that term is defined in E.O. 13132.
4. Pursuant to section 1762 of ECRA (50 U.S.C. 4821), this action is exempt from the Administrative Procedure Act (APA) (5 U.S.C. 553) requirements for notice of proposed rulemaking, opportunity for public participation, and delay in effective date. While section 1762 of ECRA provides sufficient authority for such an exemption, this action is also independently exempt from these APA requirements because it involves a military or foreign affairs function of the United States (5 U.S.C. 553(a)(1)).
5. Because neither the Administrative Procedure Act nor any other law requires that notice of proposed rulemaking and an opportunity for public comment be given for this rule, the analytical requirements of the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) are not applicable. Accordingly, no Final Regulatory Flexibility Analysis is required and none has been prepared.

List of Subjects in 15 CFR Part 746
Exports, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, part 746 of the Export Administration Regulations (15 CFR parts 730 through 774) is amended as follows:

PART 746—EMBARGOES AND OTHER SPECIAL CONTROLS
1. The authority citation for 15 CFR part 746 is revised to read as follows:

Authority:
50 U.S.C. 4801-4852; 50 U.S.C. 4601 et seq.; 50 U.S.C. 1701 et seq.; 22 U.S.C. 3201 et seq.; 42 U.S.C. 2139a; 22 U.S.C. 7201 et seq.; 22 U.S.C. 7210; E.O. 12058, 43 FR 20947, 3 CFR, 1978 Comp., p. 179; E.O. 12851, 58 FR 33181, 3 CFR, 1993 Comp., p. 608; E.O. 12938, 59 FR 59099, 3 CFR, 1994 Comp., p. 950; E.O. 13026, 61 FR 58767, 3 CFR, 1996 Comp., p. 228; E.O. 13099, 63 FR 45167, 3 CFR, 1998 Comp., p. 208; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; E.O. 13224, 66 FR 49079, 3 CFR, 2001 Comp., p. 786; Notice of September 19, 2022, 87 FR 57569 (September 21, 202); Notice of November 8, 2022, 87 FR 68015, 3 CFR, 2022 Comp., p. 563; Notice of September 7, 2023, 88 FR 62439 (September 11, 2023).
2. Supplement no. 7 to part 746 is amended by adding in numerical order the following entries to the table: 845710, 845811, 845891, 845961, 846693, 847180, 848210, 848220, 848230, 848250, 848610, 848620, 848640, 850440, 851769, 852589, 852990, 853400, 853669, 853690, 854110, 854121, 854129, 854130, 854149, 854151, 854159, 854160, 854320, 880730, 901310, 901380, 901420, 901480, 902750, 903020, 903032, 903039, and 903082.

Supplement No. 7 to Part 746—Items That Require a License Under § 746.6 When Destined to the Temporarily Occupied Crimea Region of Ukraine, Under § 746.7 When Destined to Iran, and Under § 746.8 When Destined to Russia or Belarus
* * * * *
HTS-6 codes | HTS description
* * * * * * *
845710 | Machining centers for working metal.
845811 | Horizontal lathes for removing metal, numerically controlled.
845891 | Lathes, excluding horizontal, for removing metal, numerically controlled.
845961 | Milling machines, not knee type, for removing metal, numerically controlled.
846693 | Parts and accessories for machine tools, for laser operation, metalworking machining centers, lathes and drilling machines, etc., NESOI.
* * * * * * *
847180 | Automatic data processing units, NESOI.
848210 | Ball bearings.
848220 | Tapered roller bearings, including cone and tapered roller assemblies.
848230 | Spherical roller bearings.
848250 | Cylindrical roller bearings NESOI.
848610 | Machines and apparatus for the manufacture of boules or wafers.
848620 | Machines and apparatus for the manufacture of semiconductor devices or of electronic integrated circuits.
848640 | Machines and apparatus for the manufacture or repair of masks and reticles; for assembling semiconductors devices; for lifting, handling, loading or unloading of semi-conductor devices.
850440 | Electrical static converters; power supplies for ADP machines or units of 8471.
* * * * * * *
851769 | Apparatus for the transmission or reception of voice, images or other data, including switching and routing apparatus, NESOI.
852589 | Television cameras, digital cameras and video camera recorders.
* * * * * * *
852990 | Parts (except antennas and reflectors) sfor use with radio transmission, radar, radio navigational aid, reception and television apparatus, NESOI.
* * * * * * *
853400 | Printed circuits.
853669 | Electric plugs and sockets for a voltage not exceeding 1,000 V.
853690 | Electrical apparatus for switching, protecting or making connections to or in electrical circuits, for a voltage not exceeding 1,000 V, NESOI.
854110 | Diodes, other than photosensitive or light-emitting diodes.
854121 | Transistors, other than photosensitive, with a dissipation rate of less than 1W.
854129 | Transistors, other than photosensitive, NESOI.
854130 | Thyristors, diacs and triacs, other than photosensitive devices.
854149 | Photosensitive semiconductor devices, excluding photovoltaic generators and cells.
854151 | Semiconductor-based transducers, NESOI.
854159 | Semiconductor devices NESOI.
854160 | Mounted piezoelectric crystals.
* * * * * * *
854320 | Electrical signal generators.
* * * * * * *
880730 | Other parts of airplanes, helicopters or unmanned aircraft.
901310 | Telescopic sights for fitting to arms; periscopes; telescopes designed to form parts of machines, appliances, instruments or apparatus of this chapter or Section XVI.
901380 | Other optical devices, appliances and instruments not elsewhere specified.
901420 | Instruments and appliances for aeronautical or space navigation (other than compasses).
901480 | Other navigational instruments and appliances.
902750 | Other instruments and apparatus using optical radiations (ultraviolet, visible, infrared).
903020 | Oscilloscopes and oscillographs.
903032 | Multimeters with recording device.
| 903039 | Instruments and apparatus for measuring or checking voltage, current, resistance or electrical power, with recording device.
903082 | Oscilloscopes, spectrum analyzers and other instruments and apparatus for measuring or checking electrical quantities, for measuring or checking semiconductor wafers or devices.
Thea D. Rozman Kendler,

Assistant Secretary for Export Administration.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
26 CFR Part 1
[TD 9989]
RIN 1545-BQ75
Elective Payment of Advanced Manufacturing Investment Credit; Correction

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Final rule; correction.

SUMMARY:
This document contains corrections to Treasury Decision 9989, which was published in the Federal Register for Monday, March 11, 2024. Treasury Decision 9989 issued final regulations concerning the elective payment election of the advanced manufacturing investment credit under the Creating Helpful Incentives to Produce Semiconductors (CHIPS) Act of 2022.

DATES:
These corrections are effective on April 22, 2024 and for dates of applicability see § 1.48D-6(h).

FOR FURTHER INFORMATION CONTACT:
Concerning these final regulations, Lani M. Sinfield of the Office of Associate Chief Counsel (Passthroughs and Special Industries) at (202) 317-4137 (not a toll-free number).

SUPPLEMENTARY INFORMATION:

Background
The final regulations (TD 9989) that are the subject of this correction are under section 48D of the Internal Revenue Code.

Corrections to Publication
Accordingly, the final regulations (TD 9989) that are the subject of FR Doc. 2024-04605, published on March 11, 2024, are corrected to read:
1. On page 17597, in the third column, the ninth line of the first full paragraph is corrected to read “§ 1.48D-6(b)(7)(iv) is revised in the ”.
2. On page 17600, in the first column, fourth line from the bottom of the column is corrected to read, “completed Form 3800 which may be”.
3. On page 17605, in the third column, the second line from the bottom of the column is corrected to read, “credit. A partnership or S corporation”.
§ 1.48D-6
[Corrected]
4. On page 17608, in the third column, paragraph (c)(1)(iv)(A) is corrected to read “The taxpayer claiming to be an eligible taxpayer is not a foreign entity of concern within the meaning of regulations under section 48D and has not made an applicable transaction as defined under regulations under section 50 during the taxable year that the qualified property is placed in service; and”.
5. On page 17612, in the first column, the third line from the bottom of paragraph (f)(3)(i) is corrected to read “48D(d)(2)(A)(i)(I) and paragraph (d) of”.
6. On page 17612, in the second column, lines twenty-two through twenty-nine of paragraph (f)(4) are corrected to read, “$100,000. In 2025, the IRS determines that the amount of the section 48D credit properly allowable to A Corp in 2023 with respect to Facility A (as determined under regulations under section 48D that apply for purposes of determining the amount of the section 48D credit and without regard to the limitation based on tax in section 38(c)) was $60,000. A Corp is not able to show”.
7. On page 17612, in the third column, the second line of paragraph (h)(2) is corrected to read, “years ending before March 11, 2024,”.
Aron L. Cosby,

Federal Register Liaison, Publications & Regulations Branch, Legal Processing Division, Associate Chief Counsel, (Procedure and Administration).
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R09-OAR-2022-0090; FRL-9528-02-R9]
Air Plan Approval; California; Feather River Air Quality Management District; Nonattainment New Source Review; 2015 Ozone Standard

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
The Environmental Protection Agency (EPA) is taking final action to approve a state implementation plan (SIP) revision submitted by the State of California addressing the nonattainment new source review (NNSR) requirements for the 2015 ozone National Ambient Air Quality Standards (NAAQS). This SIP revision addresses the Feather River Air Quality Management District (District) portion of the California SIP. This action is being taken pursuant to the Clean Air Act (CAA or Act) and its implementing regulations.

DATES:
This rule is effective on May 22, 2024.

ADDRESSES:
The EPA has established a docket for this action under Docket ID No. EPA-R09-OAR-2022-0090. All documents in the docket are listed on the https://www.regulations.gov website. Although listed in the index, some information is not publicly available, e.g., Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available through https://www.regulations.gov, or please contact the person identified in the FOR FURTHER INFORMATION CONTACT section for additional availability information. If you need assistance in a language other than English or if you are a person with disabilities who needs a reasonable accommodation at no cost to you, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section.

FOR FURTHER INFORMATION CONTACT:
Amita Muralidharan, EPA Region IX, 75 Hawthorne St., San Francisco, CA 94105. By phone: (415) 947-4140 or by email at muralidharan.amita@epa.gov.

SUPPLEMENTARY INFORMATION:
Throughout this document, “we,” “us,” and “our” refer to the EPA.

Table of Contents
I. Proposed Action
II. Public Comments and EPA Responses
III. EPA Action
IV. Statutory and Executive Order Reviews

I. Proposed Action
On January 24, 2024 (89 FR 4586), the EPA proposed to approve the SIP revision listed in Table 1 of this document, addressing the NNSR requirements for the 2015 ozone NAAQS for the District.
Table 1—Submitted Certification Letter
District | Adoption date | Submittal date
Feather River Air Quality Management District | 6/7/2021 | 8/3/2021
We proposed approval of the submitted SIP revision because we determined that the 2015 ozone certification submitted by the District fulfills the 40 CFR 51.1314 revision requirement and meets the requirements of CAA sections 110, 172(c)(5), 173, 182(a)(2)(c), 193, and 40 CFR 51.165. Our proposed action contains more information on the SIP revision and our evaluation.

II. Public Comments and EPA Responses
The EPA's proposed action provided a 30-day public comment period. During this period, we received no comments.

III. EPA Action
No comments were submitted during the 30-day public comment period. Therefore, as authorized in section 110(k)(3) of the Act, the EPA is approving this certification into the California SIP as proposed.

IV. Statutory and Executive Order Reviews
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this action merely approves state law as meeting federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:
• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 14094 (88 FR 21879, April 11, 2023);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq. );
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. );
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• Does not have federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it approves a state program;
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001); and
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act.
In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
Executive Order 12898 (Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations, 59 FR 7629, Feb. 16, 1994) directs Federal agencies to identify and address “disproportionately high and adverse human health or environmental effects” of their actions on minority populations and low-income populations to the greatest extent practicable and permitted by law. The EPA defines environmental justice (EJ) as “the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” The EPA further defines the term fair treatment to mean that “no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies.”
The State did not evaluate environmental justice considerations as part of its SIP submittal; the CAA and applicable implementing regulations neither prohibit nor require such an evaluation. The EPA did not perform an EJ analysis and did not consider EJ in this action. Due to the nature of the action being taken here, this action is expected to have a neutral to positive impact on the air quality of the affected area. Consideration of EJ is not required as part of this action, and there is no information in the record inconsistent with the stated goal of Executive Order 12898 of achieving environmental justice for people of color, low-income populations, and Indigenous peoples.
This action is subject to the Congressional Review Act, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a “major rule” as defined by 5 U.S.C. 804(2).
Under section 307(b)(1) of the Clean Air Act, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by June 21, 2024. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)

List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by Reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
Dated: April 16, 2024.
Martha Guzman Aceves,

Regional Administrator, Region IX.
For the reasons stated in the preamble, the Environmental Protection Agency amends part 52, chapter I, title 40 of the Code of Federal Regulations as follows:

PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
1. The authority citation for part 52 continues to read as follows:

Authority:
42 U.S.C. 7401 et seq.

Subpart F—California
2. Section 52.220 is amended by adding paragraph (c)(591)(ii)(E) to read as follows:
§ 52.220
Identification of plan-in part.
* * * * *
(c) * * *
(591) * * *
(ii) * * *
(E) Feather River Air Quality Management District.
( 1 ) “Nonattainment New Source Review Certification for the 2015 8-hour Ozone National Ambient Air Quality Standard (Adoption),” adopted June 7, 2021.
( 2 ) [Reserved]
* * * * *
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R09-OAR-2024-0142; FRL-11848-02-R9]
Determination To Defer Sanctions; California; Antelope Valley Air Quality Management District and Mojave Desert Air Quality Management District

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Interim final determination.

SUMMARY:
The Environmental Protection Agency (EPA) is making an interim final determination that the California Air Resources Board (CARB) has submitted a revised rule on behalf of the Antelope Valley Air Quality Management District (AVAQMD) and Mojave Desert Air Quality Management District (MDAQMD) that corrects deficiencies identified in its Clean Air Act (CAA or Act) state implementation plan (SIP) provisions concerning rules submitted to address section 185 of the Clean Air Act (CAA or the Act) with respect to the 1-hour ozone standard. This determination is based on a proposed approval, published elsewhere in this Federal Register , of AVAQMD Rule 315 and MDAQMD Rule 315, which establish a section 185 fee program in the AVAQMD and MDAQMD portions of the Southeast Desert Modified Air Quality Management Area. The effect of this interim final determination is that the imposition of sanctions that were triggered by a previous disapproval by the EPA in 2022 is now deferred. If the EPA finalizes its approval of AVAQMD Rule 315 and MDAQMD Rule 315 submission, relief from these sanctions will become permanent.

DATES:
This interim final determination is effective on April 22, 2024. However, comments will be accepted on or before May 22, 2024.

ADDRESSES:
Submit your comments, identified by Docket ID No. EPA-R09-OAR-2024-0142 at https://www.regulations.gov. For comments submitted at Regulations.gov , follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from Regulations.gov . The EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission ( i.e., on the web, cloud, or other file sharing system). For additional submission methods, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section. For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets. If you need assistance in a language other than English or if you are a person with disabilities who needs a reasonable accommodation at no cost to you, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section.

FOR FURTHER INFORMATION CONTACT:
Donnique Sherman, EPA Region IX, 75 Hawthorne St., San Francisco, CA 94105. By phone: (415) 947-4129 or by email at sherman.donnique@epa.gov.

SUPPLEMENTARY INFORMATION:
Throughout this document, “we,” “us,” and “our” refer to the EPA.

Table of Contents
I. Background
II. The EPA's Evaluation and Action
III. Statutory and Executive Order Reviews

I. Background
On September 29, 2022 (87 FR 59021), the EPA issued a disapproval of AVAQMD Rule 315 and MDAQMD Rule 315 that had been submitted by CARB to the EPA on December 14, 2011. In our 2022 action, we determined that the rules were largely consistent with general CAA requirements regarding SIP submissions. However, the rules were found to have the following summarized deficiencies: no justification for the method chosen to calculate alternate baseline emissions for facilities with emissions that are irregular, cyclical, or otherwise vary significantly; the rules establish an area-wide equivalency “Tracking Account” across AVAQMD, MDAQMD, and South Coast Air Quality Management District (SCAQMD) but SCAQMD did not have a rule that contained the same provisions rendering the area-wide tracking system unenforceable; the formula for calculation for the penalty fee did not properly reflect the inflation adjustment based on the Consumer Price index; and AVAQMD Rule 315 defined the term “Major Facility” as defined in “District Rule 1301” but the current SIP-approved Rule 1301 for AVAQMD did not contain a definition of “Major Facility.” Therefore, we disapproved the rules because they contained provisions that did not meet our evaluation criteria and affected rule enforceability and stringency.
Pursuant to section 179 of the CAA and our regulations at 40 CFR 52.31, the full disapproval action under title I, part D started a sanctions clock for imposition of offset sanctions 18 months after the action's effective date of October 31, 2022, and highway sanctions 6 months later.
On May 11, 2023, CARB submitted MDAQMD Rule 315 (amended February 27, 2023) and on February 14, 2024, CARB submitted AVAQMD Rule 315 (amended November 21, 2023) to correct the deficiencies of the full disapproval and to satisfy the requirements of CAA sections 182(d)(3) and 185 by utilizing a fee equivalency approach consistent with the principles of CAA section 172(e). In the Proposed Rules section of this Federal Register , we have proposed approval of AVAQMD's 2024 submittal of Rule 315 and MDAQMD's 2023 submittal of Rule 315. Based on this proposed approval action, we are also making this interim final determination, effective on publication, to defer imposition of the offset sanctions and highway sanctions that were triggered by our 2022 full disapproval of AVAQMD Rule 315 and MDAQMD Rule 315, because we believe that the new rule submissions correct the deficiencies that triggered such sanctions.
The EPA is providing the public with an opportunity to comment on this deferral of sanctions. If comments are submitted that change our assessment described in this interim final determination and the proposed full approval of AVAQMD Rule 315 and MDAQMD Rule 315, we would take final action to lift this deferral of sanctions under 40 CFR 52.31. If no comments are submitted that change our assessment, then all sanctions and any sanction clocks triggered by our 2022 action would be permanently terminated on the effective date of our final approval of AVAQMD Rule 315 and MDAQMD Rule 315.

II. The EPA's Evaluation and Action
We are making an interim final determination to defer CAA section 179 sanctions associated with our September 29, 2022 (87 FR 59021) disapproval of the 2011 submittal of AVAQMD Rule 315 and MDAQMD Rule 315. This determination is based on our concurrent proposal to approve the 2023 submittal of MDAQMD Rule 315 and the 2024 submittal of AVAQMD Rule 315, which resolves the deficiency that triggered sanctions under section 179 of the CAA.
Because the EPA has preliminarily determined that the 2023 submittal of MDAQMD Rule 315 and the 2024 submittal of AVAQMD Rule 315 is fully approvable, relief from sanctions should be provided as quickly as possible. Therefore, the EPA is invoking the good cause exception under the Administrative Procedure Act (APA) in not providing an opportunity for comment before this action takes effect (5 U.S.C. 553(b)(3)). However, by this action, the EPA is providing the public with a chance to comment on the EPA's determination after the effective date, and the EPA will consider any comments received in determining whether to reverse such action.
The EPA believes that notice-and-comment rulemaking before the effective date of this action is impracticable and contrary to the public interest. The EPA has reviewed the State's submittals and, through its proposed action, is indicating that it is more likely than not that the State has submitted a revision to the SIP that corrects deficiencies under part D of the Act that were the basis for the action that started the sanctions clocks. Therefore, it is not in the public interest to impose sanctions. The EPA believes that it is necessary to use the interim final rulemaking process to defer sanctions while the EPA completes its rulemaking process on the approvability of the State's submittal. Moreover, with respect to the effective date of this action, the EPA is invoking the good cause exception to the 30-day notice requirement of the APA because the purpose of this notice is to relieve a restriction (5 U.S.C. 553(d)(1)).

III. Statutory and Executive Order Reviews
This action defers sanctions and imposes no additional requirements. For that reason, this action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq. );
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. );
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• Does not have federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act; and
• Does not provide the EPA with the discretionary authority to address disproportionate human health or environmental effects with practical, appropriate, and legally permissible methods under Executive Order 12898 (59 FR 7629, February 16, 1994).
• Is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
• Is subject to the Congressional Review Act (CRA), 5 U.S.C. 801 et seq., and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. The CRA allows the issuing agency to make a rule effective sooner than otherwise provided by the CRA if the agency makes a good cause finding that notice and comment rulemaking procedures are impracticable, unnecessary or contrary to the public interest (5 U.S.C. 808(2)). The EPA has made a good cause finding for this rule as discussed in section II of this preamble, including the basis for that finding.
Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by June 21, 2024. Filing a petition for reconsideration by the EPA Administrator of this final rule does not affect the finality of this rule for the purpose of judicial review nor does it extend the time within which petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements (see CAA section 307(b)(2)).

List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Oxides of nitrogen, Ozone, Volatile Organic Compounds, Reporting and recordkeeping requirements.

Authority:
42 U.S.C. 7401 et seq.
Dated: April 16, 2024.
Martha Guzman Aceves,

Regional Administrator, Region IX.
GENERAL SERVICES ADMINISTRATION
41 CFR Part 102-83
[FMR Case 2023-102-1; Docket No. GSA-FMR-2023-0012; Sequence No. 2]
RIN: 3090-AK69
Federal Management Regulation; Designation of Authority and Sustainable Siting

AGENCY:
Office of Government-wide Policy (OGP), U.S. General Services Administration (GSA).

ACTION:
Final rule.

SUMMARY:
GSA, in furtherance of its authority to furnish space to federal agencies, hereby amends the Federal Management Regulation (FMR) to elaborate on the factors that are advantageous to the Government when planning for location decisions. In addition, the proposed revisions are necessary to bring the current regulation into compliance with updated terminology in statute and Office of Management and Budget (OMB) bulletins. The objective of these changes is to direct agencies to better integrate strategic, holistic analysis into planning for agency location decisions and to provide consistency in the application of these regulations across Federal agencies and regions.

DATES:
May 22, 2024.

FOR FURTHER INFORMATION CONTACT:
For clarification of content, contact Mr. Chris Coneeney, Office of Government-wide Policy, at 202-208-2956. For information pertaining to status or publication schedules, contact the Regulatory Secretariat Division (MVCB), 1800 F Street NW, Washington, DC 20405, 202-501-4755. Please cite FMR Case 2023-102-1.

SUPPLEMENTARY INFORMATION:

I. Background
This final rule amends the Federal Management Regulation (FMR) to elaborate on the factors that are advantageous to the Government when planning for location decisions. The U.S. General Services Administration (GSA) published a proposed rule in the Federal Register on October 24, 2023 (88 FR 72974).
The Administrator of General Services (Administrator) is authorized to acquire real estate and interests in real estate to accommodate the space needs of federal agencies. In particular, these authorities are codified at 40 U.S.C. 301 note (specifically, the 1950 Reorganization Plan No. 18), 113(d), 581(c)(1), 585, and 3304, and 28 U.S.C. 462(f). In addition, 40 U.S.C. 584 requires the Administrator to assign space to executive agencies in accordance with policies and directives the President prescribes under 40 U.S.C. 121(a), after consultation with the affected agency, and based on a determination by the Administrator that the assignment or reassignment is advantageous to the Government in terms of economy, efficiency, or national security.
There are several other statutory authorities that underlie federal site location policy. The Rural Development Act of 1972, as amended (7 U.S.C. 2204b-1) (RDA), requires executive agencies to give first priority to locating in rural areas.
The Federal Urban Land Use Act of 1949, as amended (40 U.S.C. 901-905), requires GSA and other Federal agencies to consult and engage with the unit of general local government exercising zoning and land use jurisdiction so that Federal urban land acquisitions and uses are developed in accordance with local zoning, land use practices and planning and development objectives to the greatest extent practicable. The National Historic Preservation Act of 1966, as amended (54 U.S.C. 300101 et seq. ) (NHPA), encourages the preservation and utilization of all usable elements of the Nation's historic built environment. The Competition in Contracting Act of 1984, as amended (41 U.S.C. 3301 et seq. ) (CICA), requires executive agencies to consider whether the location decision or delineated area will provide for adequate competition when acquiring leased space. Finally, 40 U.S.C. 121(c) authorizes the Administrator to issue regulations that the Administrator considers necessary to carry out the Administrator's functions under, as relevant here, subtitle I of chapter 40 of the United States Code. Thus, this rule implements the requirements of the statutes described above and establishes factors to be considered in the pre-procurement or acquisition process for federal agency location decisions.
This rule updates the existing part 102-83 by incorporating new terminology but continues to implement the underlying principles for planning for location decisions that have been in existence for almost 50 years. These principles were first incorporated in 41 CFR part 101-17, Assignment and Utilization of Space (45 FR 37200-37206, June 2, 1980), and continue to be the foundation for the factors elaborated on today. The procedures for location decisions were eventually given a separate part in the FMR in 2002, when 41 CFR part 102-83, Location of Space, was issued. This part was last revised and published in the Federal Register on November 8, 2005 (70 FR 67857-67860).
The rule continues to be guided by the longstanding Executive Order (E.O.) 12072, “Federal Space Management,” which prescribes policies and directives for the planning, acquisition, utilization, and management of federal space facilities in accordance with 40 U.S.C. 121(a) (43 FR 36869, August 18, 1978). E.O. 12072 requires that “serious consideration” be given “to the impact a site selection will have on improving the social, economic, environmental, and cultural conditions of the communities in the urban area.”
In addition, in accordance with the NHPA and consistent with E.O. 12072, E.O. 13006, “Locating Federal Facilities on Historic Properties in Our Nation's Central Cities” (61 FR 26071, May 24, 1996), requires Federal agencies to give first consideration to historic properties within historic districts. If no such property is suitable, then Federal agencies must consider other developed or undeveloped sites within historic districts. If no suitable site exists within historic districts, Federal agencies must then consider historic properties outside of historic districts.
On May 15, 2023, GSA published a bulletin to the FMR (88 FR 30975, May 15, 2023) to bring the regulation into alignment with current terminology and concepts, and to attempt to provide consistency when applying the existing regulation across Federal agencies. As these concepts and associated terminology are incorporated into this final rule, GSA will cancel the bulletin once this rule takes effect.
Other E.O.s and more recent administration policies further inform this rule by providing new terminology to help understand and address what it means to consider the impact of social, economic, environmental, and cultural conditions. For example, E.O 11988,”Floodplain Management” (42 FR 26951, May 25, 1977), as amended by E.O 13690, “Establishing a Flood Risk Management Standard and a Process for Further Soliciting and Considering Stakeholder Input” (80 FR 6425, Feb. 4, 2015), and E.O. 11990, “Wetlands Protection” (42 FR 26961, May 24, 1977), direct agencies to avoid locating in a floodplain and disturbing wetlands. E.O. 14057, “Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability” (86 FR 70935, December 13, 2021), its accompanying Implementing Instructions, dated August 31, 2022, and the associated Office of Management and Budget (OMB), White House Council on Environmental Quality and National Climate Policy Office memorandum (M-22-06, 12/8/2021), direct Federal agencies to promote sustainable locations for Federal facilities and strengthen the vitality and livability of the communities in which Federal facilities are located. These directives charge agencies with advancing sustainable land use that promotes the conservation of natural resources, reduces greenhouse gas (GHG) emissions and increases resilience to the impacts of climate change; efficient use of local infrastructure; expanded public transportation use and access; equitable development that promotes environmental justice and economic opportunity for disadvantaged communities; and coordination and alignment with the development plans of Tribal, State, and local or regional governments that advance these and related goals. Note that while E.O. 12072 and E.O. 13006 only address urban areas, E.O. 14057 applies many of the same goals to both urban and rural areas.
E.O. 14008, “Tackling the Climate Crisis at Home and Abroad” (86 FR 7619, February 1, 2021), directs Federal agencies to employ a Government-wide approach across a wide range of activities and goals related to tackling the climate change crisis. Most relevant to this part, it directs agencies to reduce climate pollution, increase resilience to the impacts of climate change, and deliver environmental justice, spur economic opportunity for disadvantaged communities that have been historically marginalized, and overburdened by pollution and underinvestment in housing, transportation, water and wastewater infrastructure, and health care.
E.O. 14091, “Further Advancing Racial Equity and Support for Underserved Communities Through the Federal Government” (88 FR 10825, February 22, 2023), directs Federal agencies to advance equity for all communities, especially those populations that historically have suffered from underinvestment and inequality, discrimination and persistent poverty, and to give equitable treatment to all individuals in a consistent and systematic manner. The order further promotes efficiency by directing Federal agencies, when planning for Federally owned and leased facilities, to consider locations near existing employment centers and public transit so that a broad range of the region's workforce and population may access the jobs and services at those facilities. This enables the agencies for which GSA provides space to more readily carry out their missions. Where the Federal development may spur displacement of current community populations, the E.O. instructs Federal agencies to engage further with those communities and the relevant regional and local officials to address displacement risks.
E.O. 14096, “Revitalizing Our Nation's Commitment to Environmental Justice for All” (88 FR 25251, April 26, 2023), builds on the E.O.s described above to reinforce agency use of data analysis in identifying communities suffering environmental injustice, including related to climate change and cumulative impacts, and targeting mitigation or harm avoidance through Federal actions. GSA and other Federal agencies can use various data sets and tools to identify if proposed locations for Federally owned and leased facilities are in communities with environmental justice concerns. For example, the Climate and Economic Justice Screening Tool ^1 (CEJST) identifies geographically defined disadvantaged communities, includes an interactive map, and uses datasets that are indicators of burdens in eight categories: climate change, energy, health, housing, legacy pollution, transportation, water and wastewater, and workforce development. The tool uses this information to identify disadvantaged communities that are experiencing these burdens. These are the communities that are disadvantaged because they are overburdened by pollution and marginalized by underinvestment. The order also re-emphasizes consultation and engagement with members of affected communities that allow meaningful participation for those communities in agency decision-making, including individuals with limited English proficiency and individuals with disabilities. This is in keeping with the requirements of the Federal Urban Land Use Act. As mentioned above, the principles that underlie this rule have been in existence for decades and it is well established that GSA has broad discretion regarding the substance of this regulation because it involves managerial and economic choices that are dependent on GSA's special expertise in this area. Moreover, when a project subject to 40 U.S.C. 3307 is contemplated, as part of the appropriations process, GSA provides the Committee on Environment and Public Works of the Senate and the Committee on Transportation and Infrastructure of the House of Representatives notice of the delineated area for locating the project and a comprehensive plan that demonstrates that the project will enhance the architectural, historical, social, cultural, and economic environment of the locality. Thus, by adopting resolutions approving the appropriation of the funds for the proposed project, there is a presumption of congressional approval of the delineated area and the process completed by which either GSA or the agencies operating under GSA's authority, or both, establish the location decision. The congressional approval of the future location decision is further evidenced by a provision that Congress routinely includes in GSA's annual appropriations act (See, for example, section 525 of title V of division E of section 2 of the Consolidated Appropriations Act, 2023, Pub. L. 117-328, 136 Stat. 4459, 4687). That provision requires the Administrator to ensure that the delineated area of a prospectus-level lease procurement is identical to the delineated area included in the approved prospectus and, if the Administrator determines that the delineated area of the procurement should not be identical to the delineated area included in the prospectus, the Administrator must provide an explanatory statement to GSA's authorizing and appropriations committees.
^1 The CEJST tool is available at https://screeningtool.geoplatform.gov/en/.
For non-prospectus projects, GSA exercises its discretion in accordance with the principles that underlie this rule.
It is important to note that these final rule changes work in concert with, and not in lieu of, agency mission and physical security needs, CICA, cost considerations, consolidation and reductions in square footage, prioritizing Federally owned space, and other procurement policies. In accordance with the statutes and policies described above, the optimal Federal location decision is the one that meets Federal agency mission needs, at an appropriate cost to taxpayers, while achieving the necessary level of security and leveraging Federal development in support of other Federal and local goals.
This final rule will revise in its entirety 41 CFR part 102-83, Location of Space. Federal agencies operating under or subject to the real property authorities of the Administrator of General Services must comply with the provisions of the FMR that cover real property (41 CFR parts 102-71 through 102-85).

II. Discussion of the Final Rule

A. Summary of Major Changes
The following updates and clarification changes are incorporated into the amended part 102-83:
• Social, Economic, Environmental, and Cultural factors in Location Decisions
The rule now more explicitly explains the factors associated with social, economic, environmental, and cultural conditions to be considered in location decisions.
• Central Cities to Principal Cities
The term “central cities” has, for many years, been retired in favor of the term “principal cities,” as published in the OMB “2010 Standards for Delineating Metropolitan and Micropolitan Statistical Areas” (75 FR 37246, June 28, 2010) (the 2010 Standards). This term reflects new consideration for how single or multiple urban centers function as commuting destinations and population centers within a single core-based statistical area (CBSA). This final rule updates the terminology throughout the part accordingly.
• Metropolitan Areas to Core-Based Statistical Areas
The shift from metropolitan areas (MA) to CBSAs reflects the change that first appeared in the OMB “2000 Standards for Delineating Metropolitan and Micropolitan Statistical Areas” (65 FR 82228, December 27, 2000) (the 2000 Standards) to recognize both MAs and micropolitan statistical areas as having an urbanized core and surrounding areas with a high degree of integration to that core. The 2000 Standards were replaced and superseded by the 2010 Standards, and the most recent delineations for CBSA boundaries appeared in OMB Bulletin No. 18-04 on September 14, 2018. This final rule updates the term throughout the part accordingly.
• Urban/Rural Definitions
The definitions for “urban area” and “rural area” in the existing regulations are difficult to interpret because they draw on two different sources, and these definitions are not necessarily mutually exclusive from one another. The current part 102-83 has a definition for urban that relies on the boundaries of MAs defined by OMB.
The current definition for rural area comes not from the RDA, but rather from the Consolidated Farmers Home Administration Act of 1961 (CFHA), as amended by the Farm Security and Rural Investment Act of 2002, which identifies a rural area for general purposes of CFHA as any area except a city or town with a population greater than 50,000 people or adjacent urbanized areas. The original definition of rural area applicable to the RDA was stricken from the statute and, subsequently, GSA adopted the CFHA definition. The circularity of these current definitions, however, makes the boundaries of urban and rural difficult to interpret. Among the difficulties are the fact that the boundaries established by the definitions do not relate to jurisdictional boundaries and are measured at the fine grain of census blocks, meaning that adjacent parcels within the same jurisdiction may be designated one as rural and the other as urban. With urban and rural areas immediately across the street from each other, making the case that an agency can only meet its need in the parcel designated as urban rather than the adjacent parcel designated rural, or vice versa, needlessly opens the Federal space action to protest.
Given that subsequent revisions of the RDA have actually eliminated the original definition of rural area, GSA has chosen a definition that better meets the needs of the Federal location decision process, and this final rule simplifies the definition to the boundaries of CBSAs, which follow county lines. Those areas contained within the boundaries are considered urban, and those outside the boundaries are considered rural. As with the current definitions, agency mission need remains the primary determinant of whether a Federal agency will seek space in an urban or rural area.
• Considering Real Estate Cost and Efficiency Factors
Federal location policy has long advocated that Federal agencies balance cost, mission and real estate efficiencies, as well as local development goals, when making location decisions. This derives from statute and related policies. This revised part enumerates these factors to encourage agencies to reach balanced, holistic decisions, and to clarify agency latitude to consider cost and other business factors.
• Local Consultation and Engagement Requirements
The various governing authorities and directives for this part require that Federal agencies consult and engage with local officials when making real estate decisions and that they seek opportunities for Federal action to support local development objectives. These authorities and policies include the Federal Urban Land Use Act of 1949 (40 U.S.C. 901-905); the RDA; and E.O. 12072. For the Federal Government to consider locating Federal facilities in a specific area or jurisdiction in keeping with the goals of this part, the existing or planned development composition for that area needs to be appropriate both to meeting Federal agency mission and space needs and local development goals.
Determining whether a specific area is appropriate for Federal facilities calls for consultation and engagement with State and local officials, Tribal governments, Alaska Native corporations, and Native Hawaiian Organizations, and meaningful engagement with communities in applicable geographies, to better understand local conditions and development goals, including those related to sustainability, climate change mitigation and resilience, and environmental justice. Further, where Federal agencies determine through data analysis, including through use of CEJST or other applicable Federal tools, and local consultation and other engagement that displacement risks or other environmental justice concerns exist for current populations in the vicinity of a planned facility, Federal agencies are directed to engage with the affected communities and relevant regional and local officials to address mitigating those risks.
To encourage both effective long-term consultation and engagement and efficient processes that are not overly burdensome to Federal agencies, this revised part outlines the latitude that agencies have to develop efficient internal policy and procedure.

B. Analysis of Public Comments
In response to the notice of public rulemaking, five commenters submitted comments on the provisions of the proposed rule, including three environmental advocacy groups, one individual and one anonymous commenter.
GSA appreciates the thorough public response to the proposed rule, and carefully considered all comments received. Commenters provided feedback on several provisions of the proposed rule, but primarily focused on the following topics: referencing the numerous statutory and executive authorities governing the process by which the agency plans for location decisions; providing an explanation on how to apply the changes in the regulation; explaining the hard to quantify benefits of the rule; and protection of floodplains and wetlands to avoid harming these critical native ecosystems.

Citing Additional Authorities for This Rule
Some of the commenters requested GSA include additional authorities that pertain to the selection of a specific site. GSA has based the rule on the existing authorities pertaining to the factors that are advantageous to the Government when planning for location decisions. This rule establishes the process for determining the delineated area and, once the delineated area is determined, helps to inform the specific site selection decision. The references cited by commenters are better addressed at the point in the process when specific sites are under consideration.

Explain How To Apply Changes in the Rule
The FMR outlines, at a high level, what must be considered when planning for location decisions to meet Federal space needs. The comments regarding specific procedures to implement the changes in the regulation will be addressed in subsequent implementation policies and guidance to be published after the rule takes effect.

Explain the Non-Quantifiable Benefits of the Rule
GSA notes that when selecting a site to accommodate Federal space needs, there are considerations, such as equity, environmental justice and sustainability, whose benefits to society are difficult to quantify. This rule outlines those factors that Federal agencies must consider in location decisions, but it does not dictate outcomes. Even if the specific location decision and the associated outcomes were addressed in this rule, that decision would be very difficult to anticipate, given that the Federal real estate inventory is highly diverse in terms of geography, scale, and function. The scope of the analysis is, therefore, limited to the processes of governments and stakeholders rather than the outcomes of those processes.

Floodplain and Wetlands Protection
GSA made an edit to the rule to acknowledge the protection of the natural environment by preserving ecosystems, including native ecosystems, avoiding development of green space, and promoting climate change adaptation planning. GSA reiterates, though, that mitigating the impact to wetlands and floodplains largely occurs during the site planning and design steps in the process, after the location decision itself. Those steps are not the subject of this rule.

III. Executive Orders 12866, 13563 and 14094
Executive Order (E.O.) 12866 ( Regulatory Planning and Review ) directs agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). E.O. 13563 ( Improving Regulation and Regulatory Review ) emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. E.O. 14094 ( Modernizing Regulatory Review ) amends subsection 3(f) of Executive Order 12866 and supplements and reaffirms the principles, structures, and definitions governing contemporary regulatory review established in E.O. 12866 and E.O. 13563. OMB's Office of Information and Regulatory Affairs has determined that this rule is a significant regulatory action and, therefore, it is subject to review under subsection 6(b) of E.O. 12866.

IV. Regulatory Flexibility Act
GSA does not expect this final rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601 et seq.

V. Regulatory Impact Analysis
During the first and subsequent years after publication of the rule, Federally owned new construction members and leasing acquisition members (which include a combination of Planning Managers, Site Acquisition Staff, Program Managers, Lease Contracting Officers, and Lease Project Managers) will need to learn about GSA's government-wide plan and compliance requirements. GSA estimates this cost by multiplying the time required to review the regulations and guidance implementing the rule by the estimated hourly compensation. GSA calculates the estimated hourly compensation using the U.S. Office of Personnel Management's 2023 General Schedule (GS) Rest of United States Locality Pay Table, a full fringe benefit cost factor of 36.25% and an overhead cost factor of 12%. 2 3 4 5
^2 General Schedule ( opm.gov ).
^3 OMB Memo M-08-13, dated March 11, 2008.
^4 OMB Circular-76.
^5 Computing Hourly Rates of Pay Using the 2,087-Hour Divisor ( opm.gov ).
GSA assumes the Federally owned new construction members and leasing acquisition members will, on average, stay consistent in the subsequent years. GSA also delegates leasing authority to several agencies, which are required to follow GSA's policies. As of July 2023, GSA has nine agencies actively using delegated leasing authority. The numbers and assumptions also apply to agencies using delegated leasing authority.

1. Government Costs

a. Federally Owned New Construction
The Government must educate its Federally owned new construction members via a government-wide plan to heighten their familiarity with the rule. GSA makes these assumptions based on historical familiarization and subject matter expert judgment. Below is a list of training and communication activities related to regulatory familiarization and compliance that GSA anticipates will occur.
GSA estimates it will take 5 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 20 hours each in year 1 to develop new content for planning managers and site acquisition staff training. Therefore, GSA estimates the total estimated cost for this part of the rule to be $9,370 (= 5 × $93.70 GS-14 step 5 rate × 20 hours).
GSA estimates it will take 5 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 1 hour each in years 3, 5, 7, and 9 to update new content for planning managers and site acquisition staff training. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $469 (= 5 × $93.70 GS-14 step 5 rate × 1 hour).
GSA estimates it will take 5 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 1.5 hours each in years 1, 3, 5, 7, and 9 to deliver new training content to planning managers and site acquisition staff. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $703 (= 5 × $93.70 GS-14 step 5 rate × 1.5 hours).
GSA estimates it will take 103 GSA planning managers and site acquisition staff on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1.5 hours each in years 1, 3, 5, 7, and 9 to receive new training content. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $12,251 (= 103 × $79.29 GS-13 step 5 rate × 1.5 hours).
GSA estimates it will take 5 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 4 hours each in year 1 to develop new content for training for client agencies. Therefore, GSA estimates the total estimated cost for this part of the rule to be $1,874 (= 5 × $93.70 GS-14 step 5 rate × 4 hours).
GSA estimates it will take 5 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 1 hour each in years 3, 5, 7, and 9 to develop new content for training for client agencies. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $469 (= 5 × $93.70 GS-14 step 5 rate × 1 hour).
GSA estimates it will take 5 GSA Central Office program managers on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 1.5 hours each in years 1, 3, 5, 7, and 9 to provide training to client agencies. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $703 (= 5 × $93.70 GS-14 step 5 rate × 1.5 hours).
GSA estimates it will take 400 client agency employees on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1.5 hours each in years 1, 3, 5, 7, and 9 to receive training. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $47,577 (= 400 × $79.29 GS-13 step 5 rate × 1.5 hours).
GSA estimates it will take 11 GSA regional office employees on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1 hour each in years 1, 3, 5, 7, and 9 to provide additional communications from GSA regional offices to client agency regional offices on the new training content. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $872 (= 11 × $79.29 GS-13 step 5 rate × 1 hour).
GSA estimates it will take 400 client agency regional office employees on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 0.5 hours each in years 1, 3, 5, 7, and 9 to review the GSA regional office communications on the new training content. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $15,859 (= 400 × $79.29 GS-13 step 5 rate × 0.5 hours).
GSA estimates it will take 2 GSA project managers on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 2 hours each in years 1, 3, 5, 7, and 9 to share GSA location decision information with community organizations. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $317 (= 2 × $79.29 GS-13 step 5 rate × 2 hours).
Beyond the direct costs of educating users and stakeholders about the policy changes associated with the rule, the location decisions resulting from incorporating sustainability factors and engaging with local stakeholders could be different from what they otherwise might have been without this revised rule. GSA anticipates that changes in outcomes will come with changes in costs and benefits. Inclusion of those costs and benefits in the regulatory impact analysis are not easily quantifiable. This rule guides processes in location decisions but does not mandate outcomes. Outcomes, moreover, would be very difficult to anticipate across the breadth of the Federal location decisions, which are highly diverse in geography, scale, and function and highly variable in quantity across a given time period. By incorporating sustainability factors and local planning goals into agency location decision making, GSA seeks to maximize benefits to the Federal Government, the environment and local communities and minimize negative externalities. Direct costs and indirect impacts associated with location decisions will depend on the specific characteristics of each decision and will more appropriately be addressed at the time an agency makes such a decision. Lastly, while impossible to predict for future projects, in GSA's experience the community engagement and collaboration envisioned by the rule are more likely to lead to outcomes that reduce rather than increase project costs for two reasons:
(1) effective collaboration with local stakeholders and coordination with local officials tends toward reducing risk of opposition to a project along with attendant costs associated with delay; and
(2) site selections that align with local goals are often supported by local government through donation or discount to the Federal Government or assistance with land assembly.

b. Leased Buildings
The Government must educate its leasing acquisition members via a government-wide plan to heighten their familiarity with the rule. Below is a list of training and communication activities related to regulatory familiarization and compliance that GSA anticipates will occur.
GSA estimates it will take 3 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 5 hours each in year 1 to develop new contract language relating to location and preferences. Therefore, GSA estimates the total estimated cost for this part of the rule to be $1,406 (= 3 × $93.70 GS-14 step 5 rate × 5 hours).
GSA estimates it will take 3 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 1 hour each in years 2 and 3 to develop new contract language relating to location and preferences. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $281 (= 3 × $93.70 GS-14 step 5 rate × 1 hour).
GSA estimates it will take 1 GSA employee on average, with an SES Level 3 with an average hourly rate of $138.52/hour, 2 hours in year 1 to develop new contract language relating to location and preferences. Therefore, GSA estimates the total estimated cost for this part of the rule to be $277 (= 1 × $138.52 SES Level 3 rate × 2 hours).
GSA estimates it will take 1 GSA employee on average, with an SES Level 3 with an average hourly rate of $138.52/hour, 1 hour in years 2 and 3 to develop new contract language relating to location and preferences. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $139 (= 1 × $138.52 SES Level 3 rate × 1 hour).
GSA estimates it will take 3 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 5 hours each in year 1 to update existing locational policy guidance. Therefore, GSA estimates the total estimated cost for this part of the rule to be $1,406 (= 3 × $93.70 GS-14 step 5 rate × 5 hours).
GSA estimates it will take 3 GSA employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 1 hour each in years 2 and 3 to update existing locational policy guidance. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $281 (= 3 × $93.70 GS-14 step 5 rate × 1 hour).
GSA estimates it will take 1 GSA employee on average, with an SES Level 3 with an average hourly rate of $138.52/hour, 2 hours in year 1 to update existing locational policy guidance. Therefore, GSA estimates the total estimated cost for this part of the rule to be $277 (= 1 × $138.52 SES Level 3 rate × 2 hours).
GSA estimates it will take 1 GSA employee on average, with an SES Level 3 with an average hourly rate of $138.52/hour, 1 hour in years 2 and 3 to update existing locational policy guidance. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $139 (= 1 × $138.52 SES Level 3 rate × 1 hour).
GSA estimates it will take 1 GSA employee on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1 hour in year 1 to update training for Lease Contracting Officers and Lease Project Managers. Therefore, GSA estimates the total estimated cost for this part of the rule to be $79 (= 1 × $79.29 GS-13 step 5 rate × 1 hour).
GSA estimates it will take 1 GSA employee on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1 hour in year 1 to deliver training to Lease Contracting Officers and Lease Project Managers. Therefore, GSA estimates the total estimated cost for this part of the rule to be $79 (= 1 × $79.29 GS-15 step 5 rate × 1 hour).
GSA estimates it will take 650 GSA Lease Contracting Officers and Lease Project Managers on average, with a GS-12 step 5 with an average hourly rate of $66.68/hour, 1 hour each in year 1 to receive training. Therefore, GSA estimates the total estimated cost for this part of the rule to be $43,345 (= 650 × $66.68 GS-12 step 5 rate × 1 hour).
GSA estimates it will take 650 GSA Lease Contracting Officers and Lease Project Managers on average, with a GS-12 step 5 with an average hourly rate of $66.68/hour, 0.5 hours each in years 3, 5, 7, and 9 to receive training. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $21,672 (= 650 × $66.68 GS-12 step 5 rate × 0.5 hours).
GSA estimates it will take 500 Lease Contracting Officers and Lease Project Managers from delegated leasing agencies ^6 on average, with a GS-12 step 5 with an average hourly rate of $66.68/hour, 1 hour each in year 1 to receive GSA training. Therefore, GSA estimates the total estimated cost for this part of the rule to be $33,342 (= 500 × $66.68 GS-12 step 5 rate × 1 hour).
^6 The GSA Office of Leasing provided this number as an averaged total across delegated leasing agencies by surveying their internal database.
GSA estimates it will take 500 Lease Contracting Officers and Lease Project Managers from delegated leasing agencies on average, with a GS-12 step 5 with an average hourly rate of $66.68/hour, 0.5 hours each in years 3, 5, 7, and 9 to receive GSA training. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $16,671 (= 500 × $66.68 GS-12 step 5 rate × 0.5 hours).
GSA estimates it will take 9 employees from delegated leasing agencies on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1 hour each in year 1 to update delegated leasing agency training for Lease Contracting Officers and Lease Project Managers. Therefore, GSA estimates the total estimated cost for this part of the rule to be $714 (= 9 × $79.29 GS-13 step 5 rate × 1 hour).
GSA estimates it will take 9 employees from delegated leasing agencies on average, with a GS-13 step 5 with an average hourly rate of $79.29/hour, 1 hour each in year 1 to deliver training to Lease Contracting Officers and Lease Project Managers. Therefore, GSA estimates the total estimated cost for this part of the rule to be $714 (= 9 × $79.29 GS-13 step 5 rate × 1 hour).
GSA estimates it will take 500 Lease Contracting Officers and Lease Project Managers from delegated leasing agencies on average, with a GS-12 step 5 with an average hourly rate of $66.68/hour, 1 hour each in year 1 to receive delegated leasing agency training. Therefore, GSA estimates the total estimated cost for this part of the rule to be $33,342 (= 500 × $66.68 GS-12 step 5 rate × 1 hour).
GSA estimates it will take 500 Lease Contracting Officers and Lease Project Managers from delegated leasing agencies on average, with a GS-12 step 5 with an average hourly rate of $66.68/hour, 0.5 hours each in years 3, 5, 7, and 9 to receive delegated leasing agency training. Therefore, GSA estimates the total estimated cost for this part of the rule to be $16,671 (= 500 × $66.68 GS-12 step 5 rate × 0.5 hours).

Total Government Costs
GSA estimates the total estimated Government costs to be $743,118 for years 1 through 10. A breakdown of total estimated Government costs by year is provided in the table below. ^7
^7 Costs are rounded to the nearest thousand.

2. Public Costs
Public costs associated with this rule include small entities of community organizations in areas GSA is considering for Federally owned new construction. GSA assumes, for each location decision, the agency will engage with one small entity, which, on average, will have two employees. Those employees would receive, review, and share GSA location decision information. GSA estimates the average hourly rate of $93.70 for the small entity employees as the private sector pay equivalent of a GS-14 step 5. GSA estimates it will engage with 1 small entity on average with 2 small entity employees on average, with a GS-14 step 5 with an average hourly rate of $93.70/hour, 4 hours each in years 1, 3, 5, 7, and 9 to receive, review and share GSA location decision information. Therefore, GSA estimates the total annual estimated cost for this part of the rule to be $750 (= 2 × $93.70 GS-14 step 5 rate × 4 hours).

Total Public Costs
GSA estimates the total estimated public costs to be $3,748 for years 1 through 10. A breakdown of total estimated public costs by year is provided in the table below. ^8
^8 Costs are rounded to the nearest thousand.

3. Overall Total Additional Costs
The overall total additional undiscounted cost of this rule is estimated to be $746,866 over a 10-year period. GSA did not identify any cost savings based on the impact of the rule. A breakdown of overall total additional costs by year is provided in the table below. ^9
^9 Costs are rounded to the nearest thousand.
The following is a summary of the estimated costs calculated for a 10-year time horizon at a 3- and 7-percent discount rate:

VI. Paperwork Reduction Act
The Paperwork Reduction Act does not apply because the changes to the FMR do not impose recordkeeping or information collection requirements, or the collection of information from offerors, contractors, or members of the public that require the approval of OMB under 44 U.S.C. 3501 et seq.

VII. Small Business Regulatory Enforcement Fairness Act
This final rule is also exempt from congressional review prescribed under 5 U.S.C. 801 since it relates solely to agency management and personnel.

VIII. Severability
GSA is adding a new provision on severability at 41 CFR 102-83.150, which states that all provisions included in part 102-83 are separate and severable from one another.
Regulations concerning location policy do a number of things—from identifying and elaborating upon the factors that are advantageous to the Government when planning for location decisions, to outlining the consultation and engagement requirements with local officials and the communities potentially impacted by Federal location decisions, to explaining the role of agencies when planning for such decisions.
Accordingly, if any particular term or provision in part 102-83, or the application thereof to any agency or circumstance, is determined by a court of competent jurisdiction to be invalid or unenforceable, the remaining terms or provisions, or the application of such term or provision to agencies or circumstances other than those to which it is invalid or unenforceable, will not be affected thereby, and each term and provision of this rule will be valid and enforced to the fullest extent permitted by law. For example, if any location factor is determined to be invalid, the other factors would remain in full force and effect.
Further, any cross-references that appear throughout part 102-83 are duplicative and are intended only to make the regulations more user-friendly. Invalidation of a particular provision that is cross-referenced elsewhere will not materially alter the provision that contains the cross-reference.
In summary, removal of any particular provision from part 102-83 would not render the entire regulatory scheme unworkable. Thus, GSA considers each of the provisions in part 102-83 to be separate and severable from one another. In the event of a stay or invalidation of any particular provision, it is GSA's intention that the remaining provisions will continue in effect.

List of Subjects in 41 CFR Part 102-83
Federal buildings and facilities, Government property management, Rates and fares.
Robin Carnahan,

Administrator of General Services.
For the reasons stated in the preamble, GSA revises 41 CFR part 102-83 to read as follows:

PART 102-83—LOCATION OF SPACE

Authority:
40 U.S.C. 113(d), 121(c), 581(c)(1), 584, 585, and 901-905; section 1 of Reorganization Plan No. 18 of 1950, 15 FR 3177, 64 Stat. 1270 (40 U.S.C. 301 note); 28 U.S.C. 462(f); 7 U.S.C. 2204b; 41 U.S.C. 3301 et seq.; 54 U.S.C. 300101 et seq.; E.O. 12072, 43 FR 36869, 3 CFR, 1978., p. 213; and E.O. 13006, 61 FR 26071, 3 CFR, 1996 Comp., p. 195.

Subpart A—General Provisions
Sec.
102-83.05
What does this part cover?
102-83.10
What are the governing authorities for this part?
102-83.15
Which Federal agencies must comply with these provisions?
102-83.20
How does an agency request a deviation from the provisions of this part?
102-83.25
Intentionally Omitted

Subpart A—General Provisions
§ 102-83.05
What does this part cover?
This part covers GSA's considerations when making location decisions for Federal agencies in both Federally owned and leased space and the considerations of those Federal agencies operating under or subject to the real property authorities of the Administrator of General Services (Administrator), including those using delegated real property authority, when making their own location decisions. It directs practices that foster the policies and programs of the Federal Government and improve the management, efficiency, and effectiveness of Government activities.
§ 102-83.10
What are the governing authorities for this part?
The authorities for this regulation are as follows:
(a) Rural Development Act of 1972, as amended (7 U.S.C. 2204b-1), requires executive agencies to give first priority to locating in rural areas.
(b) Federal Urban Land Use Act of 1949, as amended (40 U.S.C. 901-905), requires GSA and other Federal agencies to consult and engage with the unit of general local government exercising zoning and land use jurisdiction. To the greatest extent possible, GSA must coordinate Federal projects with local planning agencies to be in accordance with zoning, land use practices and planning and development objectives.
(c) Competition in Contracting Act of 1984, as amended, (41 U.S.C. 3301 et seq. ) (CICA), requires executive agencies to consider whether the delineated area will provide for adequate competition when acquiring leased space.
(d) 40 U.S.C. 113(d) authorizes the Administrator to provide space to the Senate, the House of Representatives, and the Architect of the Capitol upon their request.
(e) 40 U.S.C. 121(c) authorizes the Administrator to issue regulations that the Administrator considers necessary to carry out the Administrator's functions under subtitle I of title 40 of the United States Code.
(f) National Historic Preservation Act of 1966, as amended, 54 U.S.C. 300101 et seq., encourages, among other things, the public and private preservation and utilization of all usable elements of the Nation's historic built environment.
(g) 40 U.S.C. 584 authorizes the Administrator to assign and reassign space for an executive agency in any Federal Government-owned or leased building.
(h) 40 U.S.C. 581(c)(1) authorizes the Administrator to acquire, by purchase, condemnation or otherwise, real estate and interests in real estate.
(i) 40 U.S.C. 585 authorizes the Administrator to enter into a lease agreement for the accommodation of a federal agency in a building or improvement that is in existence or being erected by the lessor to accommodate the federal agency, and to assign and reassign the leased space to a federal agency.
(j) Section 1 of Reorganization Plan No. 18 of 1950, 15 FR 3177, 64 Stat. 1270 (40 U.S.C. 301 note), which, with certain exceptions, transferred all function with respect to acquiring space in buildings by lease, and all functions with respect to assigning and reassigning space in buildings for use by agencies (including both space acquired by lease and space in Government-owned buildings) to the Administrator.
(k) 28 U.S.C. 462(f) authorizes the Administrator to provide space to the judicial branch upon request from the Director of the Administrative Office of the United States Court.
(l) E.O. 12072 encourages Federal agencies to locate and use real estate in ways that serve to strengthen the Nation's cities and make them attractive places to live and work, conserve existing urban resources, and encourage the development and redevelopment of cities. Toward this end, the E.O. requires executive agencies to give first consideration to centralized community business areas and other areas recommended by local officials as possible locations for Federal facilities when locating in urban areas.
(m) E.O. 13006 requires that, when operationally appropriate and economically prudent, and subject to the RDA and E.O. 12072, when locating Federal facilities, Federal agencies must give first consideration to historic properties within historic districts. If no such property is suitable, then Federal agencies must consider other developed or undeveloped sites within historic districts. Federal agencies must then consider historic properties outside of historic districts, if no suitable site within a district exists.
§ 102-83.15
Which Federal agencies must comply with these provisions?
All Federal agencies operating under or subject to the real property authorities of the Administrator, including those using delegated real property authority, must comply with these provisions. Refer to 41 CFR 102-71.20 for the definition of Federal agency. Federal agencies using independent authority must still comply with statutory requirements and E.O.s (consistent with such authority), but this part does not apply to these agencies. Agencies with independent authority may use these provisions at agency discretion.
§ 102-83.20
How does an agency request a deviation from the provisions of this part?
Refer to §§ 102-2.60 through 102-2.110 of this chapter for information on how to obtain a deviation from this part.
§ 102-83.25
Intentionally Omitted.

Subpart B—Location of Space
Sec.
102-83.30
What basic location of space policy governs a Federal agency?
102-83.35
Is there a general hierarchy of consideration that agencies must follow in their utilization of space?
102-83.40
What is a delineated area?
102-83.45
What is a Core-Based Statistical Area?
102-83.50
How is a Core-Based Statistical Area defined?
102-83.55
What is a rural area?
102-83.60
What is an urban area?
102-83.65
What is a principal city?
102-83.70
What are centralized community business areas and centralized business districts?
102-83.75
What is environmental justice?
102-83.80
What is equitable development?
102-83.85
In addition to Federal agency mission, security and program requirements, what other factors and principles must agencies consider when establishing a potential delineated area?
102-83.90
What hierarchy of geographic consideration must agencies apply to location decisions for new Federal facilities or leased locations?
102-83.95
How must agencies consult and engage with local officials to comply with the consultation and engagement elements of part 102-83?
102-83.100
What flexibility do Federal agencies have to implement part 102-83 in high cost areas?
102-83.105
Are Federal agencies required to give preference to historic properties when acquiring leased space?
102-83.110
Does GSA provide assistance to Federal agencies by consulting and engaging with local officials to establish recommended delineated areas?
102-83.115
Are Federal agencies required to consider whether the CBA or other areas recommended by local officials will provide for adequate competition when acquiring leased space?
102-83.120
What information and data must agencies provide to the Administrator of General Services, or other acquiring agency head, to comply with the provisions of this part?
102-83.125
Who must approve the final delineated area?
102-83.130
When is written justification for a delineated area in urban areas required?
102-83.135
How will GSA negotiate changes to the final delineated area with requesting agencies?
102-83.140
Where may Federal agencies appeal GSA decisions and recommendations concerning the delineated area?
102-83.145
Do these regulations apply in GSA's National Capital Region?

Subpart B—Location of Space
§ 102-83.30
What basic location of space policy governs a Federal agency?
(a) All Federal agencies when planning for location decisions under the authorities of the Administrator, including those using delegated real property authority, are required to apply the applicable laws, regulations, and E.O.s outlined in this part to their activities. This applies to agencies using the space and to agencies acquiring a leasehold interest or a new site to accommodate a space requirement.
(b) Federal agencies intending to use space under this part are responsible for identifying the geographic area within which to locate their activities ( i.e., the delineated area) to support their mission and program requirements. Agencies must define delineated areas that support the applicable laws, regulations, and E.O.s outlined in this part. In addition to these responsibilities, agencies conducting a space acquisition have certain additional specific responsibilities as outlined in this part.
§ 102-83.35
Is there a general hierarchy of consideration that agencies must follow in their utilization of space?
Yes. In accordance with part 79, Assignment and Utilization of Space, Federal agencies must follow the hierarchy of consideration, giving first priority to Government-owned and Government-leased buildings. When no existing Government-owned or Government-leased space meets the space need, Federal agencies must follow the hierarchy of geographic consideration in § 102-83.95 when obtaining new space as identified in this subpart.
§ 102-83.40
What is a delineated area?
The delineated area is the specific geographic boundary within which space will be obtained to satisfy a Federal agency space requirement.
§ 102-83.45
What is a Core-Based Statistical Area?
A Core-Based Statistical Area (CBSA) is a geographic area established by the Office of Management and Budget (OMB). Current CBSAs are listed in OMB Bulletin No. 20-01, “Revised Delineations of Metropolitan Statistical Areas, Micropolitan Statistical Areas, and Combined Statistical Areas, and Guidance on Uses of the Delineations of These Areas,” dated March 6, 2020, or succeeding OMB Bulletin. In this part, the CBSA designation is used to distinguish between urban and rural areas, which have different directives associated with them.
§ 102-83.50
How is a CBSA defined?
A CBSA is defined by OMB using U.S. Census data as an area that has at its core an urban center and includes the adjacent areas that are socioeconomically tied to the urban center by commuting patterns pursuant to the Standards for Delineating Metropolitan and Micropolitan Statistical Areas, as updated periodically and published in the Federal Register , pursuant to 31 U.S.C. 1104(d) and 44 U.S.C. 3504.
§ 102-83.55
What is a rural area?
A rural area is any area that is not contained within the geographic boundaries of a CBSA.
§ 102-83.60
What is an urban area?
An urban area is any area contained within the geographic boundaries of a CBSA.
§ 102-83.65
What is a principal city?
(a) A principal city is an incorporated place or census designated place within a CBSA that meets certain employment and population-based criteria. Major metropolitan areas typically have several principal cities.
(b) The principal city designation is established by OMB pursuant to the Standards for Delineating Metropolitan and Micropolitan Statistical Areas, as updated periodically and published in the Federal Register , pursuant to 31 U.S.C. 1104(d) and 44 U.S.C. 3504(e). OMB regularly publishes an updated list of Principal Cities (OMB Bulletin No. 20-01, and succeeding). In this part, the principal city designation is used to help the Federal agency focus local consultation and engagement.
§ 102-83.70
What are centralized community business areas and centralized business districts?
A centralized community business area (CBA) or centralized business district, also commonly referred to as a central business district, is an area of concentration of commercial real estate and activity within a principal city, including other specific areas of similar character that may be recommended by local officials. The CBA may be part of a traditional downtown area or part of another area that local government officials have identified as supportive of their long-term economic development objectives. CBAs are designated by local governments and not by Federal agencies, so Federal agencies must consult and engage with local officials to understand the current boundaries of these areas. As described in E.O. 12072, these areas may include other specific areas that are recommended by local officials.
§ 102-83.75
What is environmental justice?
Environmental justice is the just treatment and meaningful involvement of all people, regardless of income, race, color, national origin, Tribal affiliation, or disability, in agency decision-making and other Federal activities that affect human health and the environment so that people are fully protected from disproportionate and adverse human health and environmental effects including risks and hazards, such as those related to climate change and cumulative impacts of environmental and other burdens on communities with environmental justice concerns; and have equitable access to a healthy, sustainable, and resilient environment. Advancing environmental justice further requires Federal agencies to provide opportunities for meaningful engagement of the public, including communities with environmental justice concerns who are potentially affected by Federal activities. When planning for location decisions, which is the federal activity for purposes of this rule, Federal agencies must be especially mindful of how proposed locations would impact communities with environmental justice concerns. As appropriate and consistent with applicable law, Federal agencies should seek to minimize negative and maximize positive impacts in these areas, using available data and meaningful engagement with local stakeholders to identify such communities, and identify, analyze, and address adverse human health and environmental effects (including risks) and hazards of the Federal activity.
§ 102-83.80
What is equitable development?
Equitable development is a positive development approach that employs processes, policies, and programs that aim to meet the needs of all communities and community members, with a particular focus on underserved communities and populations. When seeking Federal locations, agencies should, to the extent consistent with applicable law, consider the needs of communities, including those communities that are underserved, through policies and actions that reduce disparities while fostering communities that are healthy and vibrant.
§ 102-83.85
In addition to Federal agency mission, security and program requirements, what other factors and principles must agencies consider when establishing a potential delineated area and planning for location decisions?
(a) In addition to agency mission, security and program requirements, Federal agencies also must give serious consideration to the impact a location decision will have on improving the social, economic, environmental, and cultural conditions of communities, including those that have been historically harmed by environmental injustice and inequality, as well as avoiding harm to such communities, while at the same time promoting efficient and cost-effective Government real estate management. These factors and principles derive from the relevant authorities in this part and include the following:
(1) Cost to the Government, including both upfront real estate acquisition as well as long-term operating costs;
(2) Opportunities to reduce the Federal real estate footprint and optimize agency space usage;
(3) Ability to manage the local Federal real estate portfolio strategically to optimize effective operations over the long term; and
(4) Consideration of the competition requirements under CICA, if applicable to the site location decision.
(b) In addition to agency mission, security and program requirements, Federal agencies also must consider a series of factors meant to promote Federal investment that supports larger Federal program goals and local development objectives. These factors include the following:
(1) Compatibility with State and local economic development objectives, such as local and regional comprehensive plans, housing and transportation plans, neighborhood scale plans and local plans covering sustainability and resilience goals. When planning for location decisions, agencies should align, where possible, with local and regional planning goals. Agencies should meaningfully engage with local officials and community members potentially impacted by a location decision and consider their recommendations in light of Federal mission needs and equitability and sustainability goals, including where affected populations have experienced historic and ongoing harms due to environmental injustice and inequality;
(2) Promoting environmentally sustainable development, reduced greenhouse gas emissions, increased resilience to the impacts of climate change, and stewardship of regional natural resources;
(3) Maximizing the use of existing resources by leveraging investment in existing infrastructure;
(4) Prioritizing development of brownfields (properties, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant), greyfields (previously developed land that is underutilized) and infill development;
(5) Locating facilities along transportation corridors to encourage the use of alternate modes of transportation, and seeking efficient locations that provide a variety of transportation options for employees and the public, especially walking, biking and public transit options, while maximizing use of existing infrastructure and minimizing employee and visitor travel by car;
(6) Prioritizing central business districts, existing employment centers and rural town centers, and locating in areas that are accessible by public transit, where it exists, to a broad range of the workforce and population, such as those seeking services or needing to visit Federal space locations;
(7) Avoiding development in floodplains or impacts to wetlands to the extent practicable;
(8) Fostering protection of the natural environment by preserving ecosystems, including native ecosystems, avoiding development of green space, and promoting climate change adaptation planning;
(9) Advancing environmental justice and equitable development; and
(10) Advancing Federal and local historic preservation objectives and promoting the preservation of historic resources and other existing buildings.
(c) The factors listed in paragraphs (a) and (b) of this section must be considered when applying the hierarchy of geographic consideration in § 102-83.90. The optimal Federal location decision is the choice that meets Federal agency mission, security and program requirements and is cost effective, while leveraging Federal development in support of these other Federal programs policies and goals, as well as local development objectives.
§ 102-83.90
What hierarchy of geographic consideration must agencies apply to location decisions?
(a) Agencies must develop policies and procedures for applying the goals of this part in their business practices. These policies and procedures must include methods for applying the hierarchy outlined in paragraph (b) of this section.
(b) When making new location decisions, agencies must give preference to geographic areas in the following order:
(1) Agencies must give first priority to locating in a rural area in accordance with the Rural Development Act of 1972 (RDA). As with other elements of this part, acquiring agencies must develop their own policies and procedures for implementing the goals of the RDA. Agencies must consider the objectives outlined in § 102-83.85 and use these principles and factors to differentiate among potential locations. Agencies are encouraged to seek a location that best meets these factors or meet multiple factors. If an agency's mission cannot be accomplished in a rural area, the agency may locate in an urban area.
(2) When an agency's mission requires location in an urban area, the agency must give priority to the CBA within a principal city of a CBSA or other areas as recommended by local officials. Agencies must consider the objectives outlined in § 102-83.85 and use these principles and factors to differentiate among potential locations. Agencies are encouraged to seek a location that best meets these factors or meets multiple factors.
(3) If an agency mission cannot be met within a principal city, or where areas, such as existing employment centers, outside the principal city offer better opportunities to advance the objectives outlined in § 102-83.85, in accordance with their established policies and procedures, agencies may proceed to seek space in those areas.
(4) Once an agency has set a delineated area in a rural or urban area, agencies must comply with the requirements for consideration of historic properties and districts set forth in § 102-78.60.
§ 102-83.95
How must agencies consult and engage with local officials and communities to comply with the consultation and engagement elements of part 102-83?
Agencies have wide latitude to develop their own internal policies for consulting and engaging in ways that are both effective and efficient based upon the intent of this part, the relevant development context and the agency's core business practices. Agencies must develop internal policies and procedures that guide consultation and engagement using different methods for actions of varying scale or scope. Location decisions to support fee simple acquisition and Federal construction in most cases will require direct consultation and engagement with local officials during the location evaluation process to meet the intent of this part. Conversely, for acquisition of existing space through a lease contract, agencies may develop internal procedures that apply the hierarchy outlined in this part such that no transaction-specific consultation or engagement with local officials would be required if the delineated area is within a recognized CBA or other area recommended by local officials. To expedite effective and efficient implementation of this part, where appropriate, agencies are encouraged to pursue consultation and engagement actively with local officials and communities, as appropriate, to discuss development goals well ahead of specific space actions.
(a) Under multiple guiding authorities, acquiring agencies must consult and engage with local officials to apply the principles outlined in this part properly. Consultation and engagement and consideration of local input must occur in urban areas, and agencies are encouraged to perform similar consultation and engagement in rural areas, as appropriate.
(b) Federal agencies should refer to their agency Tribal consultation policies and applicable legal requirements, and confer if needed with agency counsel, to determine whether consultation with Tribal governments, Alaska Native corporations, Native Hawaiian Organizations, or other entities is required, such as if the Federal location decision may include or affect Tribal trust or reserved lands, and natural resources, and if so conduct such consultation.
(c) Where communities are likely to face displacement risks associated with a Federal location decision, based on agency analysis of existing data and consultation and engagement with local officials, or where communities have been harmed historically by inequity, such as persistent poverty or underinvestment, or environmental injustice, agency engagement should occur not only with relevant regional and local officials but also with members of the affected communities.
(d) Meaningful engagement with local stakeholders outside of government or those who have been historically left out of community and economic development planning requires agencies to identify and include community members in federal location planning activities early enough in the process for them to have insight into and for their input to be reflected in the decision making process. This includes opportunities for significant participation through modes that reduce known barriers to participation, such as plain language use, translation, transportation, digital and non-digital access, culture, time of day, and availability of childcare and other supportive services.
§ 102-83.100
What flexibility do Federal agencies have to implement part 102-83 in high cost areas?
Agencies have flexibility in considering the differing costs among principal cities within a single CBSA and in setting delineated areas to incorporate lower-cost markets.
There may be some instances where the head of the responsible acquiring agency or the head of the agency's designee determines that cost and security issues take precedence over the hierarchy of consideration in this part. Federal agencies may deviate from the hierarchy only where doing so would represent significant cost savings or security advantages to the Government. In such cases, agencies must consult and engage with and consider the recommendations of local officials, review and affirm this determination, and document the file accordingly.
In every instance, agencies must seek to meet the intent of the governing authorities described in § 102-83.10, and they must incorporate their applicable process into their internal policies and procedures.
§ 102-83.105
Are Federal agencies required to give preference to historic properties when acquiring leased space?
Yes. Federal agencies must give a price preference to historic properties when acquiring leased space. See § 102-73.30 of this chapter for additional guidance.
§ 102-83.110
Does GSA provide assistance to Federal agencies by consulting and engaging with local officials to establish recommended delineated areas?
Yes. GSA may, at its discretion, assist agencies by consulting and engaging with local officials to establish recommended delineated areas for use in Federal location decisions. These GSA-recommended delineated areas may be proactively developed independent of a specific space requirement. These recommended delineated areas will take into consideration the factors discussed in this part. The final delineated area used in the space acquisition may differ from these recommended areas, depending on the agency mission requirements, CICA and other factors relevant to a specific space action.
§ 102-83.115
Are Federal agencies required to consider whether the CBA or other areas recommended by local officials will provide for adequate competition when acquiring leased space?
Yes. In accordance with CICA, Federal agencies must consider whether restricting the delineated area for obtaining leased space to CBAs or other areas recommended by local officials will provide for adequate competition when acquiring space. If a Federal agency determines that the delineated area must be expanded beyond the preferred areas to provide adequate competition, the agency may expand the delineated area in consultation and engagement with local officials. Federal agencies must continue to include the preferred area in such expanded areas.
§ 102-83.120
What information and data must agencies provide to the Administrator of General Services, or other acquiring agency head, to comply with the provisions of this part?
Efficient and effective space management of Federally owned and leased facilities through the activities described in this part requires that Federal agencies cooperate with acquiring agencies and furnish any related data and information requested by the acquiring agencies, to the extent not prohibited by law. This includes information or data that allows for:
(a) Selecting, acquiring, managing, and disposing of Federal space in a manner that will foster the policies and programs of the Federal Government and improve the management and administration of Government activities;
(b) Issuing regulations, standards and criteria for the selection, acquisition and management of Federally owned and leased space;
(c) Surveying space requirements, space utilization and daily occupancy data of executive agencies;
(d) Meeting essential space requirements in a manner that is economically feasible and prudent; and
(e) Making maximum use of existing Federally controlled facilities that, in the acquiring agency head's judgment, are adequate or economically adaptable to meeting the space needs of executive agencies.
§ 102-83.125
Who must approve the final delineated area?
The Federal agency conducting the space acquisition must approve the final delineated area for the site acquisition or action. The acquiring agency must confirm that the final delineated area complies with all applicable laws, regulations and E.O.s.
§ 102-83.130
When is written justification for a delineated area in urban areas required?
If the delineated area identified is outside the CBA in a principal city, or differs from a GSA-recommended delineated area that has been developed in accordance with the guiding authorities in this part, an agency must demonstrate, in writing, that preference has been given to the CBA of a principal city or GSA's recommended delineated area, and that the agency considered the environmental and socioeconomic factors in subpart B, Location of Space, of this part. The agency justification also must address, at a minimum, the efficient performance of the mission(s) and program(s) of the agency, the nature and function of the facility or facilities involved, and the convenience of the public being served.
§ 102-83.135
How will GSA negotiate changes to the final delineated area with requesting agencies?
For space acquisitions conducted by GSA, if, based on its review of a requesting agency's identified delineated area, GSA concludes that the requesting agency's identified delineated area should be modified, GSA will discuss its recommended changes with the requesting agency. If, after discussions, the requesting agency does not agree with GSA's delineated area recommendation, the requesting agency may appeal GSA's determination in accordance with § 102-83.140. If a requesting agency elects to ask for a review of GSA's delineated area recommendation, GSA will continue to work on the requirements development and other activities related to the requesting agency's space request. GSA will not issue a solicitation to satisfy an agency's space request until a final delineated area is determined through the appeal process.
§ 102-83.140
Where may Federal agencies appeal GSA decisions and recommendations concerning the delineated area?
Agencies may appeal decisions and recommendations, in writing, to the GSA Regional Commissioner of Public Buildings in the region where the space acquisition is to take place or to the GSA Regional Commissioner's designee. The written request for review must include all relevant facts and other considerations and must justify the alternative delineated area identified by the requesting agency with regard to the location requirements set forth in all applicable statutes, E.O.s and regulations. Once submitted to the Regional Commissioner or the Regional Commissioner's designee, the requesting agency's appeal will proceed according to the process established internally by GSA.
§ 102-83.145
Do these regulations apply in GSA's National Capital Region?
The presence of the Federal Government in the National Capital Region is such that the distribution of Federal facilities has been, and will continue to be, a major influence on the character and extent of development in the National Capital Region. In view of the special nature of the National Capital Region and the preponderance of Federal space contained therein, these regulations will be applied in the National Capital Region in conjunction with regional plans and will guide the development of strategic plans for the housing of Federal agencies within the National Capital Region.

Subpart C—Severability
§ 102-83.150
What portions of this part are severable?
All provisions of this part are separate and severable from one another. If any provision is stayed or determined to be invalid, it is GSA's intention that the remaining provisions will continue in effect.
89
78
Monday, April 22, 2024
Proposed Rules
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 39
[Docket No. FAA-2023-1053; Project Identifier AD-2023-00164-T]
RIN 2120-AA64
Airworthiness Directives; The Boeing Company Airplanes

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Supplemental notice of proposed rulemaking (SNPRM).

SUMMARY:
The FAA is revising a notice of proposed rulemaking NPRM that would have applied to certain The Boeing Company Model 757-200, -200CB, and -200PF series airplanes. This action revises the NPRM by revising the compliance times for certain airplanes. The FAA is proposing this airworthiness directive (AD) to address the unsafe condition on these products. Since these actions would impose an additional burden over that in the NPRM, the FAA is requesting comments on this SNPRM.

DATES:
The FAA must receive comments on this SNPRM by June 6, 2024.

ADDRESSES:
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
• Federal eRulemaking Portal: Go to regulations.gov . Follow the instructions for submitting comments.
• Fax: 202-493-2251.
• Mail: U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590.
• Hand Delivery: Deliver to Mail address above between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
AD Docket: You may examine the AD docket at regulations.gov under Docket No. FAA-2023-1053; or in person at Docket Operations between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this SNPRM, any comments received, and other information. The street address for Docket Operations is listed above.
Material Incorporated by Reference:
• For Boeing material, contact Boeing Commercial Airplanes, Attention: Contractual & Data Services (C&DS), 2600 Westminster Blvd., MC 110-SK57, Seal Beach, CA 90740-5600; telephone 562-797-1717; website myboeingfleet.com .
• You may view this material at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206-231-3195. It is also available at regulations.gov by searching for and locating Docket No. FAA-2023-1053.

FOR FURTHER INFORMATION CONTACT:
Wayne Ha, Aviation Safety Engineer, FAA, 2200 South 216th Street, Des Moines, WA 98198; phone: 562-627-5238; email: wayne.ha@faa.gov.

SUPPLEMENTARY INFORMATION:

Comments Invited
The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under ADDRESSES . Include “Docket No. FAA-2023-1053; Project Identifier AD-2023-00164-T” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may again revise this proposal because of those comments.
Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to regulations.gov , including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this proposed AD.

Confidential Business Information
CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this SNPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this SNPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this SNPRM. Submissions containing CBI should be sent Wayne Ha, Aviation Safety Engineer, FAA, 2200 South 216th Street, Des Moines, WA 98198; phone: 562-627-5238; email: wayne.ha@faa.gov. Any commentary that the FAA receives that is not specifically designated as CBI will be placed in the public docket for this rulemaking.

Background
The FAA issued an NPRM to amend 14 CFR part 39 by adding an AD that would apply to certain The Boeing Company Model 757-200, -200CB, and -200PF series airplanes. The NPRM published in the Federal Register on July 24, 2023 (88 FR 47402). The NPRM was prompted by a crack growth analysis, which indicated that current inspections are not adequate to detect cracks in certain sections of the upper frame at the frame splice between certain stringers before a single frame fails. In the NPRM, the FAA proposed to require an inspection or records review for existing repairs; repetitive inspections for cracks of the upper frame at the frame splices between certain stringers in certain sections, and applicable on-condition actions.

Actions Since the NPRM Was Issued
Since the FAA issued the NPRM, it was determined that the repetitive inspection intervals for airplanes that were modified by Aviation Partners Boeing (APB) supplemental type certificate (STC) ST01518SE need to be revised.

Comments
The FAA received comments from United Airlines who supported the NPRM without change.
The FAA received additional comments from APB, Federal Express (FedEx), Boeing, and United Parcel Service (UPS). The following presents the comments received on the NPRM and the FAA's response to each comment.

Limited Organization Designation Authorization (ODA) Approvals
APB stated that Boeing does not have a delegation to approve repairs in areas affected by the scimitar blended winglet configuration of STC ST01518SE. APB also commented that approval by The Boeing Company ODA, as specified in paragraph (i)(3) of the proposed AD, may not be given for an alternative method of compliance (AMOC) for alternative inspections and corrective actions in those areas, but such approval must be obtained as specified in paragraph (i)(1) of the proposed AD.
The FAA acknowledges and concurs with APB's assertions. However, no change to this proposed AD is necessary. Paragraph (h)(2) of this proposed AD states that AMOC approval be obtained using a method approved in accordance with the procedures specified in “paragraph (i)” of this proposed AD, and does not limit approvals to the provisions of paragraph (i)(1) or (3) of this proposed AD. Therefore, AMOC approval in accordance with paragraph (i)(1) or (3) of this proposed AD would be provided based on whether the actions needing an AMOC apply to the APB design or the Boeing design.

Request for Changing an Exception
APB requested changing the wording in paragraph (h)(3) of the proposed AD to clarify that it applies to airplanes with winglet structural provisions (original equipment manufacturer (OEM) wingtips installed) or APB winglets installed in accordance with STC ST01518SE. APB stated the compliance time exception in paragraph (h)(3) of the proposed AD are identical to the exceptions proposed by APB in a service bulletin submitted to the FAA for approval. APB noted that if the compliance time exceptions are adopted as proposed, paragraph (h)(3) of the proposed AD would eliminate the need for APB to publish supplemental service information.
The FAA agrees the compliance times should be the same for all airplanes that have been modified using STC ST01518SE. However, there is no FAA-approved APB service bulletin to address the unsafe condition, nor does the FAA have adequate justification to allow the repetitive inspection interval specified in the NPRM. Therefore, the FAA has revised paragraph (h)(3) of this proposed AD to specify that, for all airplanes modified using STC ST01518SE the compliance times must be divided by a factor of two. Under the provisions of paragraph (i) of this proposed AD, the FAA will consider requests for approval of alternative actions and compliance times if sufficient data are submitted to substantiate that the change would provide an acceptable level of safety.

Request To Change Requirements for Certain Airplanes
FedEx requested the proposed AD be revised to allow using alternative compliance methods and times for its airplanes. FedEx noted that its 757 fleet has been modified using VT MAE STC ST03562AT, which adds a main deck cargo door to the aircraft. FedEx requested modifications to the requirements for Groups 1, 2, and 3 airplanes, allowing it to use alternative figures, repetitive intervals, and compliance methods.
The FAA disagrees with the request because the commenter did not provide adequate substantiation that using the proposed alternative compliance methods and times adequately addresses the identified unsafe condition. However, under the provisions of paragraph (i) of this proposed AD, the FAA will consider requests for approval of alternative compliance methods or times if sufficient data are submitted to substantiate that the new compliance methods and times would provide an acceptable level of safety. The FAA has not changed this proposed AD in this regard.

Request for Change to Related Service Information Under 1 CFR Part 51
Boeing requested the FAA revise a sentence in the Related Service Information under 1 CFR part 51 to read as follows: “. . . for repetitive high frequency eddy current (HFEC) and low frequency eddy current (LFEC) inspections for cracking of the upper frames and splice doublers at the frame splices.” Boeing noted that, for airplanes in Group 4, 5, and 6, it is a requirement to inspect both the frame and splice doublers. Boeing stated the proposed change will clarify that inspection of the splice doublers is required for some airplanes.
The FAA agrees with the commenter for the reasons provided and has revised the proposed AD accordingly.

Request To Clarify Repairs Requiring Additional Action
UPS requested that the FAA clarify the proposed AD regarding the repairs found during the required general visual inspection (GVI) or maintenance records review. UPS stated Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022, does not fully define “any repair.” UPS stated that Boeing 757-200PF Structural Repair Manual (SRM) 53-00-01-1A-1 allows for smooth dents, edge and surface blends, and plugging of removed damage areas in the frame web within the affected inspection area. UPS added that the repairs within the SRM allowable limits have no supplemental inspections, so such repairs do not appreciably affect damage tolerance of the fuselage frames. UPS stated that it believes the intent of the GVI or maintenance records review is to identify and report existing reinforcing repairs that may affect damage tolerance of the frame. UPS therefore requested the addition of paragraph (h)(4) of the proposed AD, stating “Where Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022, uses the phrase “any repair,” this AD requires using “any reinforcing repair.”
The FAA disagrees with the commenter's request. The FAA has no way of knowing the type or extent of repairs that might be on a given airplane or how those repairs would impact the actions required by this AD. Therefore, any existing repair, including any non-reinforced repair, needs to be evaluated for any potential effect on the inspection requirements. The FAA has not changed this proposed AD in this regard.

FAA's Determination
The FAA is proposing this AD after determining the unsafe condition described previously is likely to exist or develop in other products of the same type design. Certain changes described above expand the scope of the NPRM. As a result, it is necessary to reopen the comment period to provide additional opportunity for the public to comment on this SNPRM.

Related Service Information Under 1 CFR Part 51
The FAA reviewed Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022. This service information specifies procedures for a GVI or records review between stringers S-13 and S-14 in Sections 43 and 46 for existing repairs. This service information also describes procedures, depending on the configuration, for repetitive HFEC and LFEC inspections for cracking of the upper frames and splice doublers at the frame splices between stringers S-13 and S-14, left- and right-hand sides, in Sections 43 and 46; and applicable on-condition actions. On-condition actions include repair.
This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in ADDRESSES .

Proposed AD Requirements in This SNPRM
This proposed AD would require accomplishing the actions specified in the service information already described, except for any differences identified as exceptions in the regulatory text of this proposed AD. For information on the procedures and compliance times, see this service information at regulations.gov by searching for and locating Docket No. FAA-2023-1053.

Costs of Compliance
The FAA estimates that this AD, if adopted as proposed, would affect 456 airplanes of U.S. registry. The FAA estimates the following costs to comply with this proposed AD:
Estimated Costs
Action | Labor cost | Parts cost | Cost per product | Cost on U.S. operators
GVI | 2 work-hours × $85 per hour = $170 per inspection cycle | $0 | $170 per inspection cycle | $77,520 per inspection cycle.
Repetitive Inspections | Up to 267 work-hour × $85 per hour = Up to $22,695 per inspection cycle | 0 | Up to $22,695 per inspection cycle | Up to $10,348,920 per inspection cycle.
The FAA has received no definitive data on which to base the cost estimates for the on-condition repairs specified in this proposed AD.

Authority for This Rulemaking
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs” describes in more detail the scope of the Agency's authority.
The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

Regulatory Findings
The FAA determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government.
For the reasons discussed above, I certify this proposed regulation:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Would not affect intrastate aviation in Alaska, and
(3) Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

List of Subjects in 14 CFR Part 39
Air transportation, Aircraft, Aviation safety, Incorporation by reference, Safety.

The Proposed Amendment
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

PART 39—AIRWORTHINESS DIRECTIVES
1. The authority citation for part 39 continues to read as follows:

Authority:
49 U.S.C. 106(g), 40113, 44701.
§ 39.13
[Amended]
2. The FAA amends § 39.13 by adding the following new airworthiness directive:
The Boeing Company: Docket No. FAA-2023-1053; Project Identifier AD-2023-00164-T.

(a) Comments Due Date
The FAA must receive comments on this airworthiness directive (AD) by June 6, 2024.

(b) Affected ADs
None.

(c) Applicability
This AD applies to The Boeing Company Model 757-200, -200CB, and -200PF series airplanes, certificated in any category, as identified in Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022.

(d) Subject
Air Transport Association (ATA) of America Code 53, Fuselage.

(e) Unsafe Condition
This AD was prompted by a crack growth analysis, which indicated that current inspections are not adequate to detect cracks in the Sections 43 and 46 upper frame at the frame splice between stringers S-13 and S-14 before a single frame fails. The FAA is issuing this AD to address cracking at the upper frames common to the splice at stringers S-13 to S-14, which could interact with fuselage skin cracking at the stringer S-14 lap splice. The unsafe condition, if not addressed, could result in the inability of a principal structural element to sustain limit loads, and could adversely affect the structural integrity of the airplane.

(f) Compliance
Comply with this AD within the compliance times specified, unless already done.

(g) Required Actions
Except as specified by paragraph (h) of this AD: At the applicable times specified in the “Compliance” paragraph of Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022, do all applicable actions identified in, and in accordance with, the Accomplishment Instructions of Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022.
Note 1 to paragraph (g): Guidance for accomplishing the actions required by this AD can be found in Boeing Alert Service Bulletin 757-53A0115, dated January 25, 2022, which is referred to in Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022.

(h) Exceptions to Service Information Specifications
(1) Where the Compliance Time columns of the tables in the “Compliance” paragraph of Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022, use the phrase “the original issue date of Requirements Bulletin 757-53A0115 RB,” this AD requires using the effective date of this AD.
(2) Where Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022, specifies contacting Boeing for repair instructions or for alternative inspections: This AD requires doing the repair and doing the alternative inspections and applicable on-condition actions using a method approved in accordance with the procedures specified in paragraph (i) of this AD.
(3) For airplanes on which winglet structural provisions (original equipment manufacturer (OEM) wingtips) or Aviation Partners Boeing (APB) winglets have been installed in accordance with APB Supplemental Type Certificate (STC) ST01518SE: This AD requires dividing the applicable compliance times and repeat intervals specified in the “Compliance” paragraph of Boeing Requirements Bulletin 757-53A0115 RB, dated January 25, 2022, by a factor of two.

(i) Alternative Methods of Compliance (AMOCs)
(1) The Manager, AIR-520, Continued Operational Safety Branch, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or responsible Flight Standards Office, as appropriate. If sending information directly to the manager of the certification office, send it to the attention of the person identified in paragraph (j)(1) of this AD. Information may be emailed to: AMOC@faa.gov.
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the responsible Flight Standards Office.
(3) An AMOC that provides an acceptable level of safety may be used for any repair, modification, or alteration required by this AD if it is approved by The Boeing Company Organization Designation Authorization (ODA) that has been authorized by the Manager, AIR-520, Continued Operational Safety Branch, to make those findings. To be approved, the repair method, modification deviation, or alteration deviation must meet the certification basis of the airplane, and the approval must specifically refer to this AD.

(j) Related Information
(1) For more information about this AD, contact Wayne Ha, Aviation Safety Engineer, Continued Operational Safety Branch, FAA, 2200 South 216th Street, Des Moines, WA 98198; phone: 562-627-5238; email: wayne.ha@faa.gov.
(2) Service information identified in this AD that is not incorporated by reference is available at the address specified in paragraph (k)(3) of this AD.

(k) Material Incorporated by Reference
(1) The Director of the Federal Register approved the incorporation by reference (IBR) of the service information listed in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
(2) You must use this service information as applicable to do the actions required by this AD, unless the AD specifies otherwise.
(i) Boeing Alert Requirements Bulletin 757-53A0115 RB, dated January 25, 2022.
(ii) [Reserved]
(3) For Boeing service information, contact Boeing Commercial Airplanes, Attention: Contractual & Data Services (C&DS), 2600 Westminster Blvd., MC 110-SK57, Seal Beach, CA 90740-5600; telephone 562-797-1717; website myboeingfleet.com .
(4) You may view this material at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206-231-3195.
(5) You may view this material at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email fr.inspection@nara.gov .
Issued on April 16, 2024.
Victor Wicklund,

Deputy Director, Compliance & Airworthiness Division, Aircraft Certification Service.
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R09-OAR-2024-0142; FRL-11848-01-R9]
Air Plan Approval; California; Antelope Valley Air Quality Management District and Mojave Desert Air Quality Management District

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Proposed rule.

SUMMARY:
The Environmental Protection Agency (EPA) is proposing to approve revisions to the Antelope Valley Air Quality Management District (AVAQMD) and the Mojave Desert Air Quality Management District (MDAQMD) portions of the California State Implementation Plan (SIP) concerning rules submitted to address section 185 of the Clean Air Act (CAA or the Act) with respect to the 1979 1-hour ozone National Ambient Air Quality Standards (NAAQS or standard). We are proposing action on these local rules that were submitted as equivalent alternatives to a statutory section 185 program. We are taking comments on this proposal and plan to follow with a final action.

DATES:
Comments must be received on or before May 22, 2024.

ADDRESSES:
Submit your comments, identified by Docket ID No. EPA-R09-OAR-2024-0142 at http://www.regulations.gov. For comments submitted at Regulations.gov , follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from Regulations.gov . The EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission ( i.e., on the web, cloud, or other file sharing system). For additional submission methods, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section. For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit http://www.epa.gov/dockets/commenting-epa-dockets. If you need assistance in a language other than English or if you are a person with disabilities who needs a reasonable accommodation at no cost to you, please contact the person identified in the FOR FURTHER INFORMATION CONTACT section.

FOR FURTHER INFORMATION CONTACT:
Donnique Sherman, EPA Region IX, 75 Hawthorne St., San Francisco, CA 94105. By phone: (415) 947-4129 or by email at sherman.donnique@epa.gov.

SUPPLEMENTARY INFORMATION:
Throughout this document, “we,” “us,” and “our” refer to the EPA.

Table of Contents
I. Background
A. Section 185 Fees
B. Mojave Desert AQMD and Antelope Valley AQMD
II. The State's Submittal
A. What rules did the State submit?
B. Are there other versions of these rules?
C. What is the purpose of the submitted rules?
III. EPA's Evaluation and Action
A. How is the EPA evaluating these rules?
B. Do these rules meet the evaluation criteria?
i. Addressing September 29, 2022 Action (87 FR 59021) Deficiencies
ii. Evaluation of MDAQMD Rule 315 and AVAQMD Rule 315 Alternative Section 185 Fee Equivalent Programs
C. Proposed Action and Public Comment
IV. Incorporation by Reference
V. Statutory and Executive Order Reviews

I. Background

A. Section 185 Fees
Under sections 182(d)(3), (e), (f) and 185 of the Act, states with ozone nonattainment areas classified as Severe or Extreme are required to submit a revision to the SIP that would require major stationary sources of VOC or NO X to pay a fee for each ton of VOC or NO X emitted in excess of 80% of baseline emissions. ^1 Under section 185(a) of the Act, the SIP revision must provide that the fees be paid if the area to which the SIP revision applies has failed to attain the primary NAAQS by the applicable attainment date. A source's baseline emissions are its actual emissions during the applicable attainment year. The fee rate is $5,000 per ton in 1990 dollars, which must be adjusted for inflation based on the Consumer Price Index (CPI). More information on CAA section 185 is provided in our technical support document (TSD).
^1 VOC help produce ground-level ozone and smog, which harm human health and the environment. NO X helps produce ground-level ozone, smog and particulate matter, which harm human health and the environment.

B. Mojave Desert AQMD and Antelope Valley AQMD
The Southeast Desert Modified Air Quality Management Area (AQMA) is classified as a “Severe-17” nonattainment area for the 1979 1-hour ozone standard. ^2 Therefore, the AQMA is subject to the CAA section 182(d)(3) requirement to submit a plan revision which includes the provisions required under section 185 of the Act. The MDAQMD and AVAQMD regulate portions of the Southeast Desert Modified AQMA and must therefore include a section 185 program for this NAAQS in their respective portions of the California SIP.
^2 40 CFR 81.305.

II. The State's Submittal

A. What rules did the State submit?
Table 1 lists the rules proposed for approval with the dates that they were adopted by the local agencies and submitted by the California Air Resources Board (CARB).
Table 1—Submitted Rules
Local agency | Rule No. | Rule title | Amended | Submitted
AVAQMD | 315 | Federal Clean Air Act Section 185 Penalty | 11/21/23 | 02/14/24
MDAQMD | 315 | Federal Clean Air Act Section 185 Penalty | 02/27/23 | 05/11/23
On March 13, 2024, the EPA determined that the submittal for AVAQMD Rule 315 met the completeness criteria in 40 CFR part 51 Appendix V, which must be met before formal EPA review.
On October 11, 2023, the submittal for MDAQMD Rule 315 was deemed by operation of law to meet the completeness criteria in 40 CFR part 51 Appendix V.

B. Are there other versions of these rules?
There are no previous versions of AVAQMD Rule 315 and MDAQMD Rule 315 in the SIP. However, on September 29, 2022, EPA disapproved previous submitted versions of these rules due to deficiencies that are discussed in section III. B.

C. What is the purpose of the submitted rules?
Under sections 182(d)(3), (e), (f) and 185 of the Act, states with ozone nonattainment areas classified as Severe or Extreme are required to submit a SIP revision that requires major stationary sources of volatile organic compounds (VOC) or oxides of nitrogen (NO X ) emissions in the area to pay a fee if the area fails to attain the standard by the attainment date. The required SIP revision must provide for annual payment of the fees, computed in accordance with section 185(b).
The purpose of AVAQMD Rule 315 and MDAQMD Rule 315 is to satisfy the requirements of sections 182(d)(3) and 185 of the Act by utilizing an equivalency approach consistent with the principles of section 172(e) of the Act. Under these rules, the AVAQMD and the MDAQMD will track, calculate, analyze, and report on expenditures designed to result in VOC or NO X reductions within the Districts to implement an alternative program that is not less stringent than a statutory CAA section 185 fee program. The rules include calculation of the CAA section 185 fee obligation, establishment of a CAA section 185 equivalency “Tracking Account,” an annual demonstration of equivalency, reporting to the CARB and the EPA, and a provision requiring major sources to pay fees directly in the event the area fails to establish equivalency. The “Tracking Account” would include funds from qualified programs that are surplus to the SIP and designed to result in direct reductions or facilitate future reductions of VOC or NO X emissions, as approved by the EPA.

III. EPA's Evaluation and Action

A. How is the EPA evaluating these rules?
SIP rules must be enforceable (see CAA section 110(a)(2)) and must not interfere with applicable requirements concerning attainment and reasonable further progress or other CAA requirements (see CAA section 110(l)). The EPA is also evaluating these rules for consistency with the statutory requirements of CAA section 185. Since the rules allow for equivalent alternative programs to meet the CAA section 185 obligation for the 1-hour ozone NAAQS, they must be consistent with the principles of CAA section 172(e) and must be “not less stringent” than the statutory section 185 program.
Guidance and policy documents that we use to evaluate enforceability, revision/relaxation and rule stringency requirements for the applicable criteria pollutants include the following:
1. “State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990,” 57 FR 13498 (April 16, 1992); 57 FR 18070 (April 28, 1992).
2. “Issues Relating to VOC Regulation Cutpoints, Deficiencies, and Deviations,” EPA, May 25, 1988 (the Bluebook, revised January 11, 1990).
3. “Guidance Document for Correcting Common VOC & Other Rule Deficiencies,” EPA Region 9, August 21, 2001 (the Little Bluebook).

B. Do these rules meet the evaluation criteria?
AVAQMD Rule 315 and MDAQMD Rule 315 meet CAA requirements and are consistent with relevant guidance regarding enforceability, SIP revisions, and section 185. Because we previously disapproved an earlier version of these rules, we address the deficiencies identified in that action, and the ways that the Districts rectified them, and then examine the alternative equivalent program as a whole in the context of the section 172(e) requirement that the program be “not less stringent” than a statutory program. The TSD has more information on our evaluation. ^3
^3 See TSD subsection “a. Summary of Evaluation Criteria”.

i. Addressing September 29, 2022 Action (87 FR 59021) Deficiencies
On December 14, 2011, the CARB submitted AVAQMD Rule 315 and MDAQMD Rule 315 to satisfy the requirements of sections 182(d)(3) and 185 of the Act by utilizing an equivalency approach consistent with the principles of section 172(e) of the Act. In our September 29, 2022 action (87 FR 59021), we found that these rules were largely consistent with general CAA requirements regarding SIP submissions. However, we could not approve the rules because we found that they contained the following summarized deficiencies:
1. There was no justification for the method chosen to calculate alternate baseline emissions for facilities with emissions that are irregular, cyclical, or otherwise vary significantly.
2. The rules establish an area-wide equivalency “Tracking Account” across AVAQMD, MDAQMD, and South Coast Air Quality Management District (SCAQMD) but SCAQMD did not have a rule that contained the same provisions, rendering the rule unenforceable.
3. The formula for calculation for the penalty fee did not properly reflect the inflation adjustment based on the Consumer Price index.
4. AVAQMD Rule 315 defined the term “Major Facility” as defined in “District Rule 1301” but the current SIP-approved Rule 1301 for AVAQMD did not contain a definition of “Major Facility.”
On May 11, 2023, the CARB submitted MDAQMD Rule 315 (amended February 27, 2023) and on February 14, 2024, the CARB submitted AVAQMD Rule 315 (amended November 21, 2023), to correct the deficiencies of the 2022 disapproval and to satisfy the requirements of CAA sections 182(d)(3) and 185 by utilizing a fee equivalency approach consistent with the principles of CAA section 172(e). Summarized below is how each deficiency was addressed by MDAQMD and AVAQMD:
1. MDAQMD and AVAQMD removed section (D)(1)(d), the section that provided for alternate baseline emissions for facilities with emissions that are irregular, cyclical, or otherwise vary significantly.
2. AVAQMD and MDAQMD removed SCAQMD from the accounting system. Accordingly, the two rules only rely on each other, and are enforceable without action from the SCAQMD to ensure that all applicable sources in the AVAQMD and MDAQMD are accounted for. In addition, Section (E)(2) now requires the Air Pollution Control Officer (APCO) for each district to provide the accounting to the other district, rather than to request it from the other district.
3. The formula in section (D)(2)(a) was corrected to add (1+C), to properly reflect the inflation adjustment based on the Consumer Price index.
4. AVAQMD removed references to AVAQMD Rule 1301 in Rule 315, and updated the definition to include that a Major Facility is a Facility that emits or has the Potential to Emit NO X or VOC in an amount greater than or equal to 25 tons per year. This is consistent with the threshold for major stationary sources for Severe ozone nonattainment areas, as provided in CAA section 182(d).

ii. Evaluation of MDAQMD Rule 315 and AVAQMD Rule 315 Alternative Section 185 Fee Equivalent Programs
The CAA section 185 fee program requirements apply to ozone nonattainment areas classified as Severe or Extreme that fail to attain by the required attainment date. It requires each major stationary source of VOC located in an area that fails to attain by its attainment date to pay a fee to the state for each ton of VOC the source emits in excess of 80 percent of a baseline amount. CAA section 182(f) extends the application of this provision to major stationary sources of NO X . In 1990, the CAA set the fee as $5,000 per ton of VOC and NO X emitted, which is adjusted for inflation, based on the Consumer Price Index, on an annual basis. More information on CAA section 185 is provided in our TSD.
On January 5, 2010, the EPA issued the memo “Guidance on Developing Fee Programs Required by Clean Air Act Section 185 for the 1-hour Ozone NAAQS.” ^4 The guidance discussed options for the EPA approval of SIPs that included an equivalent alternative program to the section 185 fee program specified in the CAA when addressing anti-backsliding for a revoked ozone NAAQS under the principles of section 172(e). Section 172(e) requires the EPA to develop regulations to ensure that controls in a nonattainment area are “not less stringent” than those that applied to the area before the EPA revised a NAAQS to make it less stringent. Although section 172(e) does not directly apply where the EPA has strengthened the NAAQS, as it did in 1997, 2008, and 2015, the EPA has applied the principles in section 172(e) when revoking less stringent ozone standards. The EPA allows a state to adopt an alternative to CAA section 185 if the state demonstrates that the proposed alternative program is “not less stringent” than the direct application of CAA section 185. The EPA has previously stated that one way to demonstrate this is to show that the alternative program provides equivalent or greater fees and/or emissions reductions directly attributable to the application of CAA section 185. Although the 2010 guidance was vacated and remanded by the D.C. Circuit on procedural grounds, the court did not prohibit alternative programs, stating “neither the statute nor our case law obviously precludes that alternative” ( NRDC v. EPA, 643 F.3d 311 (D.C. Cir. 2011)). The EPA has approved alternative equivalent section 185 fee programs in California for the San Joaquin Valley (77 FR, 50021, August 20, 2012) and the SCAQMD covering both the Los Angeles-South Coast Air Basin Area and the portion of the Southeast Desert Modified Air Quality Management Area that is regulated by SCAQMD (77 FR 74372, December 14, 2012) (upheld in Natural Res. Def. Council v. EPA , 779 F.3d 1119 (9th Cir. 2015)). More recently we approved an alternative 185 fee equivalent program for the New York portion of the New York-Northern New Jersey-Long Island 1-hour ozone nonattainment area (84 FR 12511, April 2, 2019), and the Houston-Galveston-Brazoria area (85 FR 8411, February 14, 2020).
^4 See https://www.epa.gov/sites/production/files/2015-09/documents/1hour_ozone_nonattainment_guidance.pdf.
The MDAQMD and the AVAQMD rules which allow for the equivalent program: (1) calculate the amount of fees that major sources would pay each year; (2) allow for offsetting the major source fees with fees collected in the area for programs designed to result in emission reductions within the District portion of the nonattainment area (NAA); and (3) allow for major sources' fee obligations to be offset fully or partially with surplus expenditures that are collected from these programs. In order for expenditures to be creditable to the equivalency tracking account, they must: be surplus to the SIP, have been certified in writing by the APCO, the Executive Officer of CARB, and the USEPA as being surplus to the SIP, and be designed to result in direct, or to facilitate future, reductions in NO X or VOC emissions within the district portions of the NAA. In the staff reports submitted along with the rules, the MDAQMD and the AVAQMD stated that they intend to credit expenditures from (1) the Carl Moyer Memorial Air Quality Standards Attainment Program, (2) Assembly Bill 2766, (3) the Lawn & Garden Replacement Program, and (4) Assembly Bill 923 (only in the AVAQMD). In a letter dated February 22, 2024, the MDAQMD elaborated on the qualified programs for Section 172(e) and demonstrated how the programs would be evaluated using the 2020 fiscal year as an example, and the AVAQMD provided a similar demonstration in its Rule 315 district staff report. The Carl Moyer Memorial Air Quality Standards Attainment Program provides money to help fund the replacement of engines and other equipment with cleaner versions. Assembly Bill 2766 provides money to assist in public transit and provides monetary incentives to vehicle owners to retire their older polluting vehicles. The Lawn & Garden Replacement Program provides money for replacing lawn and garden equipment with zero emissions alternatives. Assembly Bill 923 collects additional revenue to remediate the air pollution harms caused by motor vehicles under the Carl Moyer program, the new purchase, retrofit, repower, or add-on of equipment for previously unregulated agricultural sources, the new purchase of school buses pursuant to the Lower-Emission School Bus Program, and an accelerated vehicle retirement or repair program. These programs all lead to the replacement of older dirtier equipment with newer, lower-emitting equipment, providing emission reductions in the MDAQMD and the AVAQMD portions of the nonattainment area. We evaluated these programs in the TSD for this action and propose to find that they are surplus to the SIP. ^5
^5 See section “Criteria for Expenditures from Qualified Programs” in the TSD for this action.
Based on our evaluation we are proposing to find that the alternative equivalent program established by the MDAQMD and AVAQMD rules are equivalent section 185 fee programs under section 172(e), as they collect greater or equivalent fees than would be collected under a statutory section 185 fee program for each area. It also requires that expenditures from qualified programs result in direct reductions or facilitate future reductions of VOC or NO X emissions. In contrast, section 185 of the Act requires states to assess fees on stationary sources but does not require that the fees be used for activities beneficial in reducing ozone formation. We believe this requirement in Rule 315 to use the surplus funds for reducing ozone formation will result in further progress toward attainment. A detailed evaluation of the MDAQMD and AVAQMD section 185 alternative fee programs is included in the TSD for this action.

C. Proposed Action and Public Comment
As authorized in section 110(k)(3) of the Act, the EPA proposes to approve the submitted rules because they fulfill all relevant requirements. We will accept comments from the public on this proposal until May 22, 2024. If we take final action to approve the submitted rules, our final action will incorporate these rules into the federally enforceable SIP and stop all sanction clocks associated with our September 29, 2022 disapproval (87 FR 59021). It will also address the EPA's obligation to promulgate a FIP arising from our previous finding that the State of California has failed to submit the required CAA section 185 SIP revisions for the 1-hour ozone NAAQS for the Southeast Desert Modified Air Quality Management Area (75 FR 232).

IV. Incorporation by Reference
In this rule, the EPA is proposing to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is proposing to incorporate by reference MDAQMD Rule 315, Federal Clean Air Act Section 185 Penalty, amended on February 27, 2023, and AVAQMD Rule 315, Federal Clean Air Act Section 185 Penalty, amended on November 21, 2023, described in section II.C. The EPA has made, and will continue to make, these materials available through https://www.regulations.gov and at the EPA Region IX Office (please contact the person identified in the FOR FURTHER INFORMATION CONTACT section of this preamble for more information).

V. Statutory and Executive Order Reviews
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this proposed action merely proposes to approve state law as meeting federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this proposed action:
• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 14094 (88 FR 21879, April 11, 2023);
• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq. );
• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. );
• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• Does not have federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• Is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it proposes to approve a state program;
• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001); and
• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the Clean Air Act.
In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
Executive Order 12898 (Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations, 59 FR 7629, February 16, 1994) directs Federal agencies to identify and address “disproportionately high and adverse human health or environmental effects” of their actions on minority populations and low-income populations to the greatest extent practicable and permitted by law. The EPA defines environmental justice (EJ) as “the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” The EPA further defines the term fair treatment to mean that “no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies.”
The air agencies evaluated environmental justice considerations as part of its SIP submittal even though the CAA and applicable implementing regulations neither prohibit nor require an evaluation. The analysis was done for the purpose of providing additional context and information about this rulemaking to the public, not as a basis of the action. The EPA has also included an environmental justice analysis in the TSD for this action, utilizing the EPA's environmental justice screening and mapping tool (“EJSCREEN”) to identify environmental burdens and susceptible populations in the Southeast Desert Modified AQMA. The results of this analysis are being provided for informational and transparency purposes. EPA is taking action under the CAA on bases independent of the air agencies' and the EPA's evaluation of environmental justice. Due to the nature of the action being taken here, this action is expected to have a positive impact on the air quality of the affected area. In addition, there is no information in the record upon which this decision is based that is inconsistent with the stated goal of E.O. 12898 of achieving environmental justice for people of color, low-income populations, and Indigenous peoples.

List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen oxides, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.

Authority:
42 U.S.C. 7401 et seq.
Dated: April 16, 2024.
Martha Guzman Aceves,

Regional Administrator, Region IX.
89
78
Monday, April 22, 2024
Notices
DEPARTMENT OF AGRICULTURE
Submission for OMB Review; Comment Request
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and approval under the Paperwork Reduction Act of 1995, Public Law 104-13. Comments are requested regarding: whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; the accuracy of the agency's estimate of burden including the validity of the methodology and assumptions used; ways to enhance the quality, utility and clarity of the information to be collected; and ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology Comments regarding these information collections are best assured of having their full effect if received by May 22, 2024. Written comments and recommendations for the proposed information collection should be submitted within 30 days of the publication of this notice on the following website www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.

Agricultural Marketing Service
Title: Marketing Order No. 984 for Walnuts Grown in California.
OMB Control Number: 0581-NEW.
Summary of Collection: Marketing Order No. 984 (7 CFR part 984) regulates the handling of walnuts grown in California and emanates from enabling legislation (the Agricultural Marketing Agreement Act of 1937, secs. 1-19, 48 Stat. 31, as amended; 7 U.S.C. 601-674). This legislation, hereinafter referred to as the Act, was designed to permit regulation of certain agricultural commodities for the purpose of providing orderly marketing conditions in interstate commerce and to improve returns to growers. Section 608 (d)(1) of the Act provides the Department of Agriculture (USDA) with the authority to request from the regulated handlers such information as is deemed necessary to determine the extent to which a marketing order has effectuated the declared policy of the Act.
Marketing Order No. 984 became effective in 1948, following public hearings in accordance with formal rulemaking procedures specified under the Act, and is locally administered by the California Walnut Board (Board). Growers approved the marketing order in referendum, as specified by the Act. The marketing order authorizes quality regulations and research and promotion programs for walnuts grown in California.
Need and Use of the Information: Under the program, handler assessment obligations are incurred at the time of certification, and provisions under § 984.67 exempt certain walnut sales from assessments and quality regulations. Therefore, walnuts considered exempt are not inspected, certified, and assessed. Under the new mechanism of determining and collecting assessments, handler assessments would be based on walnuts received rather than walnuts certified. Accordingly, effective September 20, 2023, walnut receipts for deliveries that previously would have been exempt, as those walnuts would not be inspected and certified, may now be subject to assessment. To ensure that those walnuts continue to be exempt from assessment and/or that handlers can receive a refund against their current year assessments for walnut deliveries exempt under § 984.67, the Board recommended the establishment of the new information collection form described below. The form designated as OMB No. 0581-NEW is voluntary and is titled (CWB Form No. 2) Report of Walnuts Exempt from Assessments. Depending on when handlers submit the form, submission would either ensure that walnuts that are exempt from assessment are not assessed or if they are assessed, handlers would be able to receive a refund.
Description of Respondents: Business or other for-profit; Farms.
Number of Respondents: 14.
Frequency of Responses: Reporting: Annually.
Total Burden Hours: 1.
Levi S. Harrell,

Departmental Information Collection Clearance Officer.
COMMISSION ON CIVIL RIGHTS
Notice of Public Meeting of the Guam Advisory Committee to the U.S. Commission on Civil Rights

AGENCY:
U.S. Commission on Civil Rights.

ACTION:
Announcement of public meeting.

SUMMARY:
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act, that the Guam Advisory Committee (Committee) to the U.S. Commission on Civil Rights will hold a virtual business meeting via Zoom at 9:00 a.m. ChST on Tuesday, April 30, 2024 (7:00 p.m. ET on Monday, April 29, 2024). The purpose of this meeting is to discuss the Committee's project, Overrepresentation of FAS Members in the Criminal Justice System on Guam.

DATES:
Tuesday, April 30, 2024, from 9:00 a.m.-10:00 a.m. ChST (Monday, April 29, 2024, from 7:00 p.m.-8:00 p.m. ET).

ADDRESSES:
The meeting will be held via Zoom Webinar.
Registration Link (Audio/Visual): https://www.zoomgov.com/webinar/register/WN_CKHmVYevQkmxeZ3p4uCGPQ.
Join by Phone (Audio Only): (833) 435-1820 USA Toll Free; Meeting ID: 160 139 1205.

FOR FURTHER INFORMATION CONTACT:
Kayla Fajota, DFO, at kfajota@usccr.gov or (434) 515-2395.

SUPPLEMENTARY INFORMATION:
This committee meeting is available to the public through the registration link above. Any interested member of the public may listen to the meeting. An open comment period will be provided to allow members of the public to make a statement as time allows. Per the Federal Advisory Committee Act, public minutes of the meeting will include a list of persons who are present at the meeting. If joining via phone, callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan. The Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Closed captioning will be available for individuals who are deaf, hard of hearing, or who have certain cognitive or learning impairments. To request additional accommodations, please email lschiller@usccr.gov at least 10 business days prior to the meeting.
Members of the public are entitled to submit written comments; the comments must be received in the regional office within 30 days following the meeting. Written comments may be emailed to David Mussatt at dmussatt@usccr.gov. Persons who desire additional information may contact the Regional Programs Coordination Unit at (312) 353-8311.
Records generated from this meeting may be inspected and reproduced at the Regional Programs Coordination Unit, as they become available, both before and after the meeting. Records of the meeting will be available via www.facadatabase.gov under the Commission on Civil Rights, Guam Advisory Committee link. Persons interested in the work of this Committee are directed to the Commission's website, http://www.usccr.gov, or may contact the Regional Programs Coordination Unit at the above phone number.

Agenda
I. Welcome & Roll Call
II. Announcements & Updates
III. Approval of Meeting Minutes
IV. Committee Discussion
V. Next Steps
VI. Public Comment
VII. Adjournment
Dated: April 17, 2024.
David Mussatt,

Supervisory Chief, Regional Programs Unit.
COMMISSION ON CIVIL RIGHTS
Notice of Public Meeting of the Tennessee Advisory Committee

AGENCY:
Commission on Civil Rights.

ACTION:
Announcement of meeting.

SUMMARY:
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission), and the Federal Advisory Committee Act (FACA) that a meeting of the Tennessee Advisory Committee to the Commission will convene by Zoom on Thursday, May 9, 2024, at 3:30 p.m. (CT). The purpose of the meeting is to discuss their draft report on Voting Rights.

DATES:
The meeting will take place on Thursday, May 9, 2024, at 3:30 p.m. (CST).

ADDRESSES:
Registration Link (Audio/Visual): https://www.zoomgov.com/webinar/register/WN_GQGcMN2PSfyxFz6r5hXWPQ .
Telephone (Audio Only): Dial (833) 568-8864 USA Toll Free; Access Code: 161 338 3123.

FOR FURTHER INFORMATION CONTACT:
Victoria Moreno at vmoreno@usccr.gov or by phone at 434-515-0204.

SUPPLEMENTARY INFORMATION:
This meeting is available to the public through the Zoom link above. If joining only via phone, callers can expect to incur charges for calls they initiate over wireless lines, and the Commission will not refund any incurred charges. Individuals who are deaf, deafblind and hard of hearing may also follow the proceedings by first calling the Federal Relay Service at 1-800-877-8339 and providing the Service with the call-in number found through registering at the web link provided above for the meeting.
Members of the public are entitled to make comments during the open period at the end of the meeting. Members of the public may also submit written comments; the comments must be received in the Regional Programs Unit within 30 days following the respective meeting. Written comments may be emailed to Victoria Moreno at vmoreno@usccr.gov. All written comments received will be available to the public.
Persons who desire additional information may contact the Regional Programs Unit at (202) 809-9618. Records and documents discussed during the meeting will be available for public viewing as they become available at the www.facadatabase.gov. Persons interested in the work of this advisory committee are advised to go to the Commission's website, www.usccr.gov, or to contact the Regional Programs Unit at the above phone number or email address.

Agenda

Thursday, May 9, 2024, at 3:30 p.m. (CST)
1. Welcome & Roll Call
2. Chair's Comments
3. Discussion on Report
4. Next Steps
5. Public Comment
6. Adjourn
Dated: April 17, 2024.
David Mussatt,

Supervisory Chief, Regional Programs Unit.
COMMISSION ON CIVIL RIGHTS
Notice of Public Meeting of the Nebraska Advisory Committee to the U.S. Commission on Civil Rights

AGENCY:
U.S. Commission on Civil Rights.

ACTION:
Announcement of meeting.

SUMMARY:
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Nebraska Advisory Committee (Committee) to the U.S. Commission on Civil Rights will hold a business meeting via web conference. The purpose of the meeting will be to discuss their project on to the Effects of the Covid-19 Pandemic on K-12 Education in the State.

DATES:
Monday, June 10, 2024 at 4:00 p.m. Central Time.

ADDRESSES:
The meeting will be held via Zoom.

June 10th Business Meeting
Registration Link (Audio/Visual): https://www.zoomgov.com/webinar/register/WN_TJn2NBdJSjOGeexq8PBjBQ
Join by Phone (Audio Only): 1-833-435-1820 USA Toll Free; Meeting ID: 161 744 9367

FOR FURTHER INFORMATION CONTACT:
Victoria Moreno, DFO, at vmoreno@usccr.gov or by phone at 434-515-0204.

SUPPLEMENTARY INFORMATION:
Members of the public may listen to the discussions through the above call-in numbers (audio only) or online registration links (audio/visual). An open comment period at each meeting will be provided to allow members of the public to make a statement as time allows. Callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan. The Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Individuals who are deaf, deafblind, and/or hard of hearing may also follow the proceedings by first calling the Federal Relay Service at 1-800-877-8339 and providing the Service with the conference call number and meeting ID number.
Members of the public are entitled to submit written comments; the comments must be received in the regional office within 30 days following the meetings. Written comments may be emailed to Victoria at vmoreno@usccr.gov.
Records generated from this meeting may be inspected and reproduced at the Regional Programs Unit Office, as they become available, both before and after the meetings. Records of the meetings will be available via www.facadatabase.gov under the Commission on Civil Rights, Nebraska Advisory Committee link. Persons interested in the work of this Committee are directed to the Commission's website, http://www.usccr.gov, or may contact the Regional Programs Unit at the above email or street address.

Agenda
I. Welcome and Roll Call
II. Chair's Comments
III. Committee Business
IV. Public Comment
V. Adjournment
Dated: April 17, 2024.
David Mussatt,

Supervisory Chief, Regional Programs Unit.
COMMISSION ON CIVIL RIGHTS
Notice of Public Meeting of the Commonwealth of the Northern Mariana Islands Advisory Committee to the U.S. Commission on Civil Rights

AGENCY:
U.S. Commission on Civil Rights.

ACTION:
Notice of public meeting.

SUMMARY:
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act, that the Commonwealth of the Northern Mariana Islands Advisory Committee (Committee) to the U.S. Commission on Civil Rights will hold a public meeting via Zoom at 9:00 a.m. ChST on Wednesday, May 8, 2024 (7:00 p.m. ET on Tuesday, May 7, 2024). The purpose of this meeting is to discuss the Committee's project, Access to Adequate Health Care for Incarcerated Individuals in the CNMI Judicial System.

DATES:
Wednesday, May 8, 2024, 9:00 a.m.-10:30 a.m. Chamorro Standard Time (Tuesday, May 7, 2024, 7:00 p.m.-8:30 p.m. Eastern Time).

ADDRESSES:
The meeting will be held via Zoom Webinar.
Registration Link (Audio/Visual): https://www.zoomgov.com/webinar/register/WN_RLEXp4PzRMyaXZfCsagKSw .
Join by Phone (Audio Only): (833) 435-1820 USA Toll-Free; Meeting ID: 161 993 0226.

FOR FURTHER INFORMATION CONTACT:
Kayla Fajota, Designated Federal Officer, at kfajota@usccr.gov or (434) 515-2395.

SUPPLEMENTARY INFORMATION:
This committee meeting is available to the public through the registration link above. Any interested member of the public may listen to the meeting. An open comment period will be provided to allow members of the public to make a statement as time allows. Per the Federal Advisory Committee Act, public minutes of the meeting will include a list of persons who are present at the meeting. If joining via phone, callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan. The Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Closed captioning will be available for individuals who are deaf, hard of hearing, or who have certain cognitive or learning impairments. To request additional accommodations, please email Liliana Schiller, Support Services Specialist, at lschiller@usccr.gov at least 10 business days prior to the meeting.
Members of the public are entitled to submit written comments; the comments must be received in the regional office within 30 days following the meeting. Written comments may be emailed to Kayla Fajota at kfajota@usccr.gov. Persons who desire additional information may contact the Regional Programs Coordination Unit at (312) 353-8311.
Records generated from this meeting may be inspected and reproduced at the Regional Programs Coordination Unit Office, as they become available, both before and after the meeting. Records of the meetings will be available via www.facadatabase.gov under the Commission on Civil Rights, Commonwealth of the Northern Mariana Islands Advisory Committee link. Persons interested in the work of this Committee are directed to the Commission's website, http://www.usccr.gov, or may contact the Regional Programs Coordination Unit at lschiller@usccr.gov.

Agenda
I. Welcome & Roll Call
II. Approval of Minutes
III. Discussion and Project Planning: Access to Health Care for incarcerated individuals within the CNMI Judicial System
IV. Public Comment
V. Next Steps
VI. Adjournment
Dated: April 17, 2024.
David Mussatt,

Supervisory Chief, Regional Programs Unit.
COMMISSION ON CIVIL RIGHTS
Notice of Public Meetings of the Colorado Advisory Committee to the U.S. Commission on Civil Rights

AGENCY:
U.S. Commission on Civil Rights.

ACTION:
Notice of public meetings.

SUMMARY:
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Colorado Advisory Committee (Committee) to the U.S. Commission on Civil Rights will convene monthly virtual business meetings on Wednesday, May 15, 2024, and Wednesday, June 19, 2024, both at 3:00 p.m. Mountain Time. The purpose of the meetings is to continue working on its project on public school attendance zones in Colorado.

DATES:
Wednesday, May 15 2024, and Wednesday, June 19, 2024, at 3:00 p.m. Mountain Time.

ADDRESSES:
The meetings will be held via Zoom.
Meeting Link for Both Meetings (Audio/Visual): https://tinyurl.com/279fjudv; password: USCCR-CO.
Join by Phone (Audio Only): 1-833 435 1820; Meeting ID: 160 614 2807#.

FOR FURTHER INFORMATION CONTACT:
Barbara Delaviez, Designated Federal Official at bdelaviez@usccr.gov or (312) 353-8311.

SUPPLEMENTARY INFORMATION:
These committee meetings are available to the public through the meeting link above. Any interested member of the public may listen to the meetings. At the meetings, an open comment period will be provided to allow members of the public to make a statement as time allows. Per the Federal Advisory Committee Act, public minutes of the meetings will include a list of persons who are present at the meetings. If joining via phone, callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan. The Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Closed captioning will be available for individuals who are deaf, hard of hearing, or who have certain cognitive or learning impairments. To request additional accommodations, please email ebohor@usccr.gov at least 10 business days prior to the meetings.
Members of the public are entitled to submit written comments; the comments must be received in the regional office within 30 days following the meetings. Written comments may be emailed to Barbara Delaviez at bdelaviez@usccr.gov. Persons who desire additional information may contact the Regional Programs Coordination Unit at 1-312-353-8311.
Records generated from these meetings may be inspected and reproduced at the Regional Programs Coordination Unit Office, as they become available, both before and after the meetings. Records of meetings will be available via www.facadatabase.gov under the Commission on Civil Rights, Colorado Advisory Committee link. Persons interested in the work of this Committee are directed to the Commission's website, http://www.usccr.gov, or may contact the Regional Programs Coordination Unit at ebohor@usccr.gov.

Agenda for Both Meeting Dates
I. Welcome and Roll Call
II. Report Stage: Public School Attendance Zones
III. Discuss Next Steps
IV. Public Comment
V. Adjournment
Dated: April 17, 2024.
David Mussatt,

Supervisory Chief, Regional Programs Unit.
COMMISSION ON CIVIL RIGHTS
Notice of Public Meeting of the Nebraska Advisory Committee to the U.S. Commission on Civil Rights

AGENCY:
U.S. Commission on Civil Rights.

ACTION:
Announcement of meeting.

SUMMARY:
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Nebraska Advisory Committee (Committee) to the U.S. Commission on Civil Rights will hold a briefing meeting via web conference. The purpose of the meeting will be to hear testimony on their project related to the Effects of the Covid-19 Pandemic on K-12 Education in the state.

DATES:
Wednesday, May 15, 2024, at 11:00 a.m. Central Time.

ADDRESSES:
The meeting will be held via Zoom.

May 15th Briefing Meeting
Registration Link (Audio/Visual): https://www.zoomgov.com/webinar/register/WN_V_AmuTH7SkezLFvVqnqt2w
Join by Phone (Audio Only): 1-833-435-1820 USA Toll Free; Meeting ID: 161 771 4603

FOR FURTHER INFORMATION CONTACT:
Victoria Moreno, DFO, at vmoreno@usccr.gov or by phone at 434-515-0204.

SUPPLEMENTARY INFORMATION:
Members of the public may listen to the discussions through the above call-in numbers (audio only) or online registration links (audio/visual). An open comment period at each meeting will be provided to allow members of the public to make a statement as time allows. Callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan. The Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Individuals who are deaf, deafblind, and/or hard of hearing may also follow the proceedings by first calling the Federal Relay Service at 1-800-877-8339 and providing the Service with the conference call number and meeting ID number.
Members of the public are entitled to submit written comments; the comments must be received in the regional office within 30 days following the meetings. Written comments may be emailed to Victoria at vmoreno@usccr.gov.
Records generated from this meeting may be inspected and reproduced at the Regional Programs Unit Office, as they become available, both before and after the meetings. Records of the meetings will be available via www.facadatabase.gov under the Commission on Civil Rights, Nebraska Advisory Committee link. Persons interested in the work of this Committee are directed to the Commission's website, http://www.usccr.gov, or may contact the Regional Programs Unit at the above email or street address.

Agenda:
I. Welcome and Roll Call
II. Chair's Comments
III. Panel Presentations
IV. Committee Q & A
V. Public Comment
VI. Adjournment
Dated: April 17, 2024.
David Mussatt,

Supervisory Chief, Regional Programs Unit.
DEPARTMENT OF COMMERCE
International Trade Administration
[A-557-827, A-455-808, A-583-875, A-489-852]
Dioctyl Terephthalate From Malaysia, Poland, Taiwan, and the Republic of Türkiye: Initiation of Less-Than-Fair-Value Investigations

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

DATES:
Applicable April 15, 2024.

FOR FURTHER INFORMATION CONTACT:
Nathan Araya (Malaysia) at (202) 482-3401; Cameron Cheatham (Poland) at (678) 756-8362; Brian Smith (Taiwan) at (202) 482-1766; and Craig Matney (the Republic of Türkiye (Türkiye)) at (202) 482-2429, AD/CVD Operations, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230.

SUPPLEMENTARY INFORMATION:

The Petitions
On March 26, 2024, the U.S. Department of Commerce (Commerce) received antidumping duty (AD) petitions concerning imports of dioctyl terephthalate (DOTP) filed in proper form on behalf of Eastman Chemical Company (the petitioner). ^1
^1 See Petitioner's Letter, “Petitions for the Imposition of Antidumping Duties,” dated March 26, 2024 (the Petitions).
Between March 28 and April 4, 2024, Commerce requested supplemental information pertaining to certain aspects of the Petitions in separate supplemental questionnaires. ^2 The petitioner filed responses to the supplemental questionnaires between April 1 and 8, 2024. ^3
^2 See Commerce's Letter, “Supplemental Questions,” dated March 28, 2024 (General Issues Questionnaire); see also Country-Specific AD Supplemental Questionnaires: Malaysia Supplemental, Poland Supplemental, Taiwan Supplemental, and Türkiye Supplemental, dated March 28, 2024 and March 29, 2024; and Memorandum, “Phone Call with Petitioner,” dated April 4, 2024.
^3 See Petitioner's Letter, “Response to Request for Clarification,” dated April 1, 2024 (General Issues Supplement); see also Country-Specific AD Supplemental Responses, dated April 1, 2024 and April 3, 2024; and Petitioner's Letter, “Response to Request for Clarification (Turkey),” dated April 8, 2024.
In accordance with section 732(b) of the Tariff Act of 1930, as amended (the Act), the petitioner alleges that imports of DOTP from Malaysia, Poland, Taiwan, and Türkiye are being, or are likely to be, sold in the United States at less than fair value (LTFV) within the meaning of section 731 of the Act, and that imports of such products are materially injuring, or threatening material injury to, the DOTP industry in the United States. Consistent with section 732(b)(1) of the Act, the Petitions were accompanied by information reasonably available to the petitioner supporting its allegations.
Commerce finds that the petitioner filed the Petitions on behalf of the domestic industry, because the petitioner is an interested party, as defined in section 771(9)(C) of the Act. Commerce also finds that the petitioner demonstrated sufficient industry support for the initiation of the requested LTFV investigations. ^4
^4 See section on “Determination of Industry Support for the Petitions,” infra.

Periods of Investigation
Because the Petitions were filed on March 26, 2024, pursuant to 19 CFR 351.204(b)(1), the period of investigation (POI) for each of these LTFV investigations is January 1, 2023, through December 31, 2023.

Scope of the Investigations
The product covered by these investigations is DOTP from Malaysia, Poland, Taiwan, and Türkiye. For a full description of the scope of these investigations, see the appendix to this notice.

Comments on the Scope of the Investigations
On March 28, 2024, Commerce requested information and clarification from the petitioner regarding the proposed scope to ensure that the scope language in the Petitions is an accurate reflection of the products for which the domestic industry is seeking relief. ^5 On April 1, 2024, the petitioner provided clarifications regarding the scope. ^6 The description of merchandise covered by these investigations, as described in the appendix to this notice, reflects the products for which the domestic industry is seeking relief.
^5 See General Issues Questionnaire.
^6 See General Issues Supplement at 1-2.
As discussed in the Preamble to Commerce's regulations, we are setting aside a period for interested parties to raise issues regarding product coverage ( i.e., scope). ^7 Commerce will consider all scope comments received from interested parties and, if necessary, will consult with interested parties prior to the issuance of the preliminary determinations. If scope comments include factual information, ^8 all such factual information should be limited to public information. To facilitate preparation of its questionnaires, Commerce requests that scope comments be submitted by 5:00 p.m. Eastern Time (ET) on May 6, 2024, which is the next business day after 20 calendar days from the signature date of this notice. ^9 Any rebuttal comments, which may include factual information, must be filed by 5:00 p.m. ET on May 16, 2024, which is 10 calendar days from the initial comment deadline.
^7 See Antidumping Duties; Countervailing Duties, Final Rule, 62 FR 27296, 27323 (May 19, 1997) ( Preamble ); see also 19 CFR 351.312.
^8 See 19 CFR 351.102(b)(21) (defining “factual information”).
^9 The deadline for scope comments falls on May 5, 2024, which is a Sunday. In accordance with 19 CFR 351.303(b)(1), Commerce will accept comments filed by 5:00 p.m. ET on May 6, 2024 (“For both electronically filed and manually filed documents, if the applicable due date falls on a non-business day, the Secretary will accept documents that are filed on the next business day.”).
Commerce requests that any factual information that parties consider relevant to the scope of these investigations be submitted during that period. However, if a party subsequently finds that additional factual information pertaining to the scope of the investigations may be relevant, the party must contact Commerce and request permission to submit the additional information. All scope comments must be filed simultaneously on the records of the concurrent LTFV investigations.

Filing Requirements
All submissions to Commerce must be filed electronically via Enforcement and Compliance's Antidumping Duty and Countervailing Duty Centralized Electronic Service System (ACCESS), unless an exception applies. ^{10} An electronically filed document must be received successfully in its entirety by the time and date it is due.
^{10} See Antidumping and Countervailing Duty Proceedings: Electronic Filing Procedures; Administrative Protective Order Procedures, 76 FR 39263 (July 6, 2011); see also Enforcement and Compliance: Change of Electronic Filing System Name, 79 FR 69046 (November 20, 2014) for details of Commerce's electronic filing requirements, effective August 5, 2011. Information on using ACCESS can be found at https://access.trade.gov/help.aspx and a handbook can be found at https://access.trade.gov/help/Handbook_on_Electronic_Filing_Procedures.pdf.

Comments on Product Characteristics
Commerce is providing interested parties an opportunity to comment on the appropriate physical characteristics of DOTP to be reported in response to Commerce's AD questionnaires. This information will be used to identify the key physical characteristics of the subject merchandise in order to report the relevant cost of production (COP) accurately, as well as to develop appropriate product comparison criteria.
Interested parties may provide any information or comments that they feel are relevant to the development of an accurate list of physical characteristics. Specifically, they may provide comments as to which characteristics are appropriate to use as: (1) general product characteristics; and (2) product comparison criteria. We note that it is not always appropriate to use all product characteristics as product comparison criteria. We base product comparison criteria on meaningful commercial differences among products. In other words, although there may be some physical product characteristics utilized by manufacturers to describe DOTP, it may be that only a select few product characteristics take into account commercially meaningful physical characteristics. In addition, interested parties may comment on the order in which the physical characteristics should be used in matching products. Generally, Commerce attempts to list the most important physical characteristics first and the least important characteristics last.
In order to consider the suggestions of interested parties in developing and issuing the AD questionnaires, all product characteristics comments must be filed by 5:00 p.m. ET on May 6, 2024, which is the next business day after 20 calendar days from the signature date of this notice. ^{11} Any rebuttal comments must be filed by 5:00 p.m. ET on May 16, 2024, which is 10 calendar days from the initial comment deadline. All comments and submissions to Commerce must be filed electronically using ACCESS, as explained above, on the record of each of the LTFV investigations.
^{11} See 19 CFR 351.303(b)(1). The deadline for product characteristics comments falls on May 5, 2024, which is a Sunday. In accordance with 19 CFR 351.303(b)(1), Commerce will accept comments filed by 5:00 p.m. ET on May 6, 2024 (“For both electronically filed and manually filed documents, if the applicable due date falls on a non-business day, the Secretary will accept documents that are filed on the next business day.”).

Determination of Industry Support for the Petitions
Section 732(b)(1) of the Act requires that a petition be filed on behalf of the domestic industry. Section 732(c)(4)(A) of the Act provides that a petition meets this requirement if the domestic producers or workers who support the petition account for: (i) at least 25 percent of the total production of the domestic like product; and (ii) more than 50 percent of the production of the domestic like product produced by that portion of the industry expressing support for, or opposition to, the petition. Moreover, section 732(c)(4)(D) of the Act provides that, if the petition does not establish support of domestic producers or workers accounting for more than 50 percent of the total production of the domestic like product, Commerce shall: (i) poll the industry or rely on other information in order to determine if there is support for the petition, as required by subparagraph (A); or (ii) determine industry support using a statistically valid sampling method to poll the “industry.”
Section 771(4)(A) of the Act defines the “industry” as the producers as a whole of a domestic like product. Thus, to determine whether a petition has the requisite industry support, the statute directs Commerce to look to producers and workers who produce the domestic like product. The U.S. International Trade Commission (ITC), which is responsible for determining whether “the domestic industry” has been injured, must also determine what constitutes a domestic like product in order to define the industry. While both Commerce and the ITC apply the same statutory definition regarding the domestic like product, ^{12} they do so for different purposes and pursuant to a separate and distinct authority. In addition, Commerce's determination is subject to limitations of time and information. Although this may result in different definitions of the like product, such differences do not render the decision of either agency contrary to law. ^{13}
^{12} See section 771(10) of the Act.
^{13} See USEC, Inc. v. United States, 132 F. Supp. 2d 1, 8 (CIT 2001) (citing Algoma Steel Corp., Ltd. v. United States, 688 F. Supp. 639, 644 (CIT 1988), aff'd Algoma Steel Corp., Ltd. v. United States, 865 F.2d 240 (Fed. Cir. 1989)).
Section 771(10) of the Act defines the domestic like product as “a product which is like, or in the absence of like, most similar in characteristics and uses with, the article subject to an investigation under this title.” Thus, the reference point from which the domestic-like product analysis begins is “the article subject to an investigation” ( i.e., the class or kind of merchandise to be investigated, which normally will be the scope as defined in the petition).
With regard to the domestic like product, the petitioner does not offer a definition of the domestic like product distinct from the scope of the investigations. ^{14} Based on our analysis of the information submitted on the record, we have determined that DOTP, as defined in the scope, constitutes a single domestic like product, and we have analyzed industry support in terms of that domestic like product. ^{15}
^{14} See Petitions at Volume I (pages 10-13 and Exhibits Gen-4 through Gen-6, Gen-12, and Gen-14).
^{15} For a discussion of the domestic like product analysis as applied to these cases and information regarding industry support, see Antidumping Duty Investigation Initiation Checklists: Dioctyl Terephthalate from Malaysia, Poland, Taiwan, and the Republic of Türkiye, dated concurrently with, and hereby adopted by, this notice (Country-Specific AD Initiation Checklists) at Attachment II, Analysis of Industry Support for the Antidumping Duty Petitions Covering Dioctyl Terephthalate from Malaysia, Poland, Taiwan, and the Republic of Türkiye (Attachment II). These checklists are on file electronically via ACCESS.
In determining whether the petitioner has standing under section 732(c)(4)(A) of the Act, we considered the industry support data contained in the Petitions with reference to the domestic like product as defined in the “Scope of the Investigations,” in the appendix to this notice. To establish industry support, the petitioner provided its own production of the domestic like product in 2023. ^{16} In addition, the petitioner estimated the 2023 production of BASF Corporation, the other U.S. producer of the domestic like product in 2023. ^{17} The petitioner then compared its production to the total volume of DOTP produced by the U.S. industry. ^{18} We relied on the data provided by the petitioner for purposes of measuring industry support. ^{19}
^{16} See Petitions at Volume I (page 4).
^{17} Id. at 4 and Exhibit Gen-15.
^{18} Id. at 4.
^{19} Id.; see also General Issues Supplement at 2 and Exhibit Supp-Gen1. For further discussion, see Attachment II of the Country-Specific AD Initiation Checklists.
Our review of the data provided in the Petitions, the General Issues Supplement, and other information readily available to Commerce indicates that the petitioner has established industry support for the Petitions. ^{20} First, the Petitions established support from domestic producers (or workers) accounting for more than 50 percent of the total production of the domestic like product and, as such, Commerce is not required to take further action in order to evaluate industry support ( e.g., polling). ^{21} Second, the domestic producers (or workers) have met the statutory criteria for industry support under section 732(c)(4)(A)(i) of the Act because the domestic producers (or workers) who support the Petitions account for at least 25 percent of the total production of the domestic like product. ^{22} Finally, the domestic producers (or workers) have met the statutory criteria for industry support under section 732(c)(4)(A)(ii) of the Act because the domestic producers (or workers) who support the Petitions account for more than 50 percent of the production of the domestic like product produced by that portion of the industry expressing support for, or opposition to, the Petitions. ^{23} Accordingly, Commerce determines that the Petitions were filed on behalf of the domestic industry within the meaning of section 732(b)(1) of the Act. ^{24}
^{20} See Petitions at Volume I (page 4 and Exhibit Gen-15); see also General Issues Supplement at 2. For further discussion, see Attachment II of the Country-Specific AD Initiation Checklists.
^{21} See Attachment II of the Country-Specific AD Initiation Checklists; see also section 732(c)(4)(D) of the Act.
^{22} See Attachment II of the Country-Specific AD Initiation Checklists.
^{23} Id.
^{24} Id.

Allegations and Evidence of Material Injury and Causation
The petitioner alleges that the U.S. industry producing the domestic like product is being materially injured, or is threatened with material injury, by reason of the imports of the subject merchandise sold at LTFV. In addition, the petitioner states that subject imports from Malaysia, Poland, Taiwan, and Türkiye individually exceed the negligibility threshold provided for under section 771(24)(A) of the Act. ^{25}
^{25} See Petitions at Volume I (page 19 and Exhibits Gen-1 and Gen-15); see also General Issues Supplement at 2 and Exhibit Supp-Gen-2.
The petitioner contends that the industry's injured condition is illustrated by the significant volume of subject imports; lost market share; underselling and price depression and/or suppression; declines in volume of production, sales, productivity and profitability; and lost sales and revenue. ^{26} We assessed the allegations and supporting evidence regarding material injury, threat of material injury, causation, as well as negligibility, and we have determined that these allegations are properly supported by adequate evidence and meet the statutory requirements for initiation. ^{27}
^{26} See Petitions at Volume I (pages 1-2, 14-37, and Exhibits Gen-1, Gen-4 through Gen-8, and Gen-13 through Gen-17); see also General Issues Supplement at 2 and Exhibit Supp-Gen-2.
^{27} See Country-Specific AD Initiation Checklists at Attachment III, Analysis of Allegations and Evidence of Material Injury and Causation for the Antidumping Duty Petitions Covering Dioctyl Terephthalate from Malaysia, Poland, Taiwan, and the Republic of Türkiye.

Allegations of Sales at LTFV
The following is a description of the allegations of sales at LTFV upon which Commerce based its decision to initiate LTFV investigations of imports of DOTP from Malaysia, Poland, Taiwan, and Türkiye. The sources of data for the deductions and adjustments relating to U.S. price and normal value (NV) are discussed in greater detail in the Country-Specific AD Initiation Checklists.

U.S. Price
For Malaysia, Poland, Taiwan, and Türkiye, the petitioner based export price (EP) on pricing information for sales, or offers for sale, of DOTP produced in and exported from each country. ^{28} For each country, the petitioner made certain adjustments to U.S. price to calculate net ex-factory U.S. prices, where applicable. ^{29}
^{28} See Country-Specific AD Initiation Checklists.
^{29} Id.

Normal Value
^{30} In accordance with section 773(b)(2) of the Act, for each of these LTFV investigations, Commerce will request information necessary to calculate the constructed value (CV) and COP to determine whether there are reasonable grounds to believe or suspect that sales of the foreign like product have been made at prices that represent less than the COP of the product.
For Malaysia, Taiwan, and Türkiye, the petitioner based NV on home market prices it obtained for DOTP produced in and sold, or offered for sale, in the respective countries during the POI. ^{31} For Taiwan and Türkiye, the petitioner provided information indicating that the prices for DOTP sold or offered for sale in the respective countries were below the COP. ^{32} Therefore, for Taiwan and Türkiye, the petitioner calculated NV based on CV. ^{33} For further discussion of CV for Taiwan and Türkiye, see the section “Normal Value Based on Constructed Value” below.
^{31} See Malaysia AD Initiation Checklist; Taiwan AD Initiation Checklist; and Türkiye AD Initiation Checklist.
^{32} See Taiwan AD Initiation Checklist; and Türkiye AD Initiation Checklist.
^{33} Id.
For Poland, the petitioner states that there are believed to be insignificant commercial sales of DOTP in Poland and, therefore, it based NV on pricing information for DOTP produced in Poland and sold, or offered for sale, in a third country. ^{34}
^{34} See Poland AD Initiation Checklist.

Normal Value Based on Constructed Value
As noted above, for Taiwan and Türkiye, the petitioner provided information that indicated that the prices for DOTP sold or offered for sale in the respective home markets were below the COP. ^{35} Therefore, for Taiwan and Türkiye, the petitioner calculated NV based on CV. ^{36}
^{35} See Taiwan AD Initiation Checklist; and Türkiye AD Initiation Checklist.
^{36} Id.
Pursuant to section 773(e) of the Act, the petitioner calculated CV as the sum of the cost of manufacturing, selling, general, and administrative (SG&A) expenses, financial expenses, and profit. ^{37} For each of these countries, in calculating the cost of manufacturing, the petitioner relied on its own production experience and input consumption rates, valued using publicly available information applicable to the respective countries. ^{38} In calculating SG&A expenses, financial expenses, and profit ratios, the petitioner relied on the 2022 or 2023 financial statements of a producer of identical merchandise domiciled in the respective countries, where applicable. ^{39}
^{37} Id.
^{38} Id.
^{39} Id.

Fair Value Comparisons
Based on the data provided by the petitioner, there is reason to believe that imports of DOTP from Malaysia, Poland, Taiwan, and Türkiye are being, or are likely to be, sold in the United States at LTFV. Based on comparisons of EP to NV in accordance with sections 772 and 773 of the Act, the estimated dumping margins for DOTP for each of the countries covered by this initiation are as follows: (1) Malaysia—48.70 percent; (2) Poland—57.88 percent; (3) Taiwan—93.04 to 148.22 percent; and (4) Türkiye—42.50 and 80.71 percent. ^{40}
^{40} See Country-Specific AD Initiation Checklists.

Initiation of LTFV Investigations
Based upon the examination of the Petitions and supplemental responses, we find that they meet the requirements of section 732 of the Act. Therefore, we are initiating LTFV investigations to determine whether imports of DOTP from Malaysia, Poland, Taiwan, and Türkiye are being, or are likely to be, sold in the United States at LTFV. In accordance with section 733(b)(1)(A) of the Act and 19 CFR 351.205(b)(1), unless postponed, we will make our preliminary determinations no later than 140 days after the date of these initiations.

Respondent Selection

Malaysia and Poland
In the Petitions, the petitioner identified one company in Malaysia (Upc Chemicals (Malaysia) Sdn Bhd.) as a producer/exporter of DOTP and one company in Poland (Grupa Azoty Zaklady Azotowy) as a producer/exporter of DOTP and provided independent, third-party information as support. ^{41} We currently know of no additional producers/exporters of DOTP from Malaysia and Poland.
^{41} See Petitions at Volume I (page 5 and Exhibits Gen-9 and Gen-16); see also General Issues Supplement at 1 and Exhibit Gen-9.
Accordingly, Commerce intends to individually examine all known producers/exporters in the investigations from these countries ( i.e., the companies cited above). We invite interested parties to comment on this issue. Such comments may include factual information within the meaning of 19 CFR 351.102(b)(21). Parties wishing to comment must do so within three business days of the publication of this notice in the Federal Register . Comments must be filed electronically using ACCESS. An electronically filed document must be received successfully in its entirety via ACCESS by 5:00 p.m. ET on the specified deadline. Because we intend to examine all known producers/exporters in Malaysia and Poland, if no comments are received or if comments received further support the existence of these sole producers/exporters in Malaysia and Poland, respectively, we do not intend to conduct respondent selection and will proceed to issuing the initial AD questionnaires to the companies identified. However, if comments are received which create a need for a respondent selection process, we intend to finalize our decisions regarding respondent selection within 20 days of publication of this notice.

Taiwan and Türkiye
In the Petitions, the petitioner identified four companies in Taiwan as producers/exporters of DOTP and 10 companies in Türkiye as producers/exporters of DOTP. ^{42} Following standard practice in LTFV investigations involving market economy countries, in the event Commerce determines that the number of companies is large, and it cannot individually examine each company based upon Commerce's resources, where appropriate, Commerce intends to select mandatory respondents based on U.S. Customs and Border Protection (CBP) data for imports under the appropriate Harmonized Tariff Schedule of the United States (HTSUS) subheading(s) listed in the “Scope of the Investigations,” in the appendix.
^{42} See Petitions at Volume I (page 5 and Exhibit Gen-9); see also General Issues Supplement at 1 and Exhibit Gen-9.
On April 9, 2024, Commerce released CBP data on imports of DOTP from Taiwan and Türkiye under administrative protective order (APO) to all parties with access to information protected by APO and indicated that interested parties wishing to comment on CBP data and/or respondent selection must do so within three business days of the publication date of this notice of initiation of these investigations. ^{43} Comments must be filed electronically using ACCESS. An electronically filed document must be received successfully in its entirety via ACCESS by 5:00 p.m. ET on the specified deadline. Commerce will not accept rebuttal comments regarding the CBP data or respondent selection.
^{43} See Memoranda, “Release of U.S. Customs and Border Protection Data,” dated April 9, 2024.
Interested parties must submit applications for disclosure under APO in accordance with 19 CFR 351.305(b). Instructions for filing such applications may be found on Commerce's website at https://www.trade.gov/administrative-protective-orders.

Distribution of Copies of the Petitions
In accordance with section 732(b)(3)(A) of the Act and 19 CFR 351.202(f), copies of the public version of the Petitions have been provided to the governments of Malaysia, Poland, Taiwan, and Türkiye via ACCESS. To the extent practicable, we will attempt to provide a copy of the public version of the Petitions to each exporter named in the Petitions, as provided under 19 CFR 351.203(c)(2).

ITC Notification
Commerce will notify the ITC of our initiation, as required by section 732(d) of the Act.

Preliminary Determinations by the ITC
The ITC will preliminarily determine, within 45 days after the date on which the Petitions were filed, whether there is a reasonable indication that imports of DOTP from Malaysia, Poland, Taiwan, and/or Türkiye are materially injuring, or threatening material injury to, a U.S. industry. ^{44} A negative ITC determination for any country will result in the investigation being terminated with respect to that country. ^{45} Otherwise, these LTFV investigations will proceed according to statutory and regulatory time limits.
^{44} See section 733(a) of the Act.
^{45} Id.

Submission of Factual Information
Factual information is defined in 19 CFR 351.102(b)(21) as: (i) evidence submitted in response to questionnaires; (ii) evidence submitted in support of allegations; (iii) publicly available information to value factors under 19 CFR 351.408(c) or to measure the adequacy of remuneration under 19 CFR 351.511(a)(2); (iv) evidence placed on the record by Commerce; and (v) evidence other than factual information described in (i)-(iv). Section 351.301(b) of Commerce's regulations requires any party, when submitting factual information, to specify under which subsection of 19 CFR 351.102(b)(21) the information is being submitted ^{46} and, if the information is submitted to rebut, clarify, or correct factual information already on the record, to provide an explanation identifying the information already on the record that the factual information seeks to rebut, clarify, or correct. ^{47} Time limits for the submission of factual information are addressed in 19 CFR 351.301, which provides specific time limits based on the type of factual information being submitted. Interested parties should review the regulations prior to submitting factual information in these investigations.
^{46} See 19 CFR 351.301(b).
^{47} See 19 CFR 351.301(b)(2).

Particular Market Situation Allegation
Section 773(e) of the Act addresses the concept of particular market situation (PMS) for purposes of CV, stating that “if a particular market situation exists such that the cost of materials and fabrication or other processing of any kind does not accurately reflect the COP in the ordinary course of trade, the administering authority may use another calculation methodology under this subtitle or any other calculation methodology.” When an interested party submits a PMS allegation pursuant to section 773(e) of the Act ( i.e., a cost-based PMS allegation), Commerce will respond to such a submission consistent with 19 CFR 351.301(c)(2)(v). If Commerce finds that a cost-based PMS exists under section 773(e) of the Act, then it will modify its dumping calculations appropriately.
Neither section 773(e) of the Act, nor 19 CFR 351.301(c)(2)(v), set a deadline for the submission of cost-based PMS allegations and supporting factual information. However, in order to administer section 773(e) of the Act, Commerce must receive PMS allegations and supporting factual information with enough time to consider the submission. Thus, should an interested party wish to submit a cost-based PMS allegation and supporting new factual information pursuant to section 773(e) of the Act, it must do so no later than 20 days after submission of a respondent's initial section D questionnaire response.
We note that a PMS allegation filed pursuant to sections 773(a)(1)(B)(ii)(III) or 773(a)(1)(C)(iii) of the Act ( i.e., a sales-based PMS allegation) must be filed within 10 days of submission of a respondent's initial section B questionnaire response, in accordance with 19 CFR 301(c)(2)(i) and 19 CFR 351.404(c)(2).

Extensions of Time Limits
Parties may request an extension of time limits before the expiration of a time limit established under 19 CFR 351.301, or as otherwise specified by Commerce. In general, an extension request will be considered untimely if it is filed after the expiration of the time limit established under 19 CFR 351.301, or as otherwise specified by Commerce. ^{48} For submissions that are due from multiple parties simultaneously, an extension request will be considered untimely if it is filed after 10:00 a.m. ET on the due date. Under certain circumstances, Commerce may elect to specify a different time limit by which extension requests will be considered untimely for submissions which are due from multiple parties simultaneously. In such a case, we will inform parties in a letter or memorandum of the deadline (including a specified time) by which extension requests must be filed to be considered timely. An extension request must be made in a separate, standalone submission; under limited circumstances we will grant untimely filed requests for the extension of time limits, where we determine, based on 19 CFR 351.302, that extraordinary circumstances exist. Parties should review Commerce's regulations concerning the extension of time limits and the Time Limits Final Rule prior to submitting factual information in these investigations. ^{49}
^{48} See 19 CFR 351.301; see also Extension of Time Limits; Final Rule, 78 FR 57790 (September 20, 2013) ( Time Limits Final Rule ), available at https://www.gpo.gov/fdsys/pkg/FR-2013-09-20/html/2013-22853.htm.
^{49} See 19 CFR 351.302; see also, e.g., Time Limits Final Rule.

Certification Requirements
Any party submitting factual information in an AD proceeding must certify to the accuracy and completeness of that information. ^{50} Parties must use the certification formats provided in 19 CFR 351.303(g). ^{51} Commerce intends to reject factual submissions if the submitting party does not comply with the applicable certification requirements.
^{50} See section 782(b) of the Act.
^{51} See Certification of Factual Information to Import Administration During Antidumping and Countervailing Duty Proceedings, 78 FR 42678 (July 17, 2013) ( Final Rule ). Additional information regarding the Final Rule is available at https://access.trade.gov/Resources/filing/index.html.

Notification to Interested Parties
Interested parties must submit applications for disclosure under APO in accordance with 19 CFR 351.305. Parties wishing to participate in these investigations should ensure that they meet the requirements of 19 CFR 351.103(d) ( e.g., by filing the required letter of appearance). Note that Commerce has modified certain of its requirements for serving documents containing business proprietary information and has made additional clarifications and corrections to its AD/CVD regulations. ^{52}
^{52} See Administrative Protective Order, Service, and Other Procedures in Antidumping and Countervailing Duty Proceedings, 88 FR 67069 (September 29, 2023).
This notice is issued and published pursuant to sections 732(c)(2) and 777(i) of the Act, and 19 CFR 351.203(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix

Scope of the Investigations
The merchandise covered by these investigations is dioctyl terephthalate (DOTP), regardless of form. DOTP that has been blended with other products is included within this scope when such blends include constituent parts that have not been chemically reacted with each other to produce a different product. For such blends, only the DOTP component of the mixture is covered by the scope of the investigations.
DOTP that is otherwise subject to these investigations is not excluded when commingled with DOTP from sources not subject to these investigations. Commingled refers to the mixing of subject and non-subject DOTP. Only the subject component of such commingled products is covered by the scope of these investigations.
DOTP has the general chemical formulation of C 6 H 4 (C 8 H 17 COO) 2 and a chemical name of “bis (2-ethylhexyl) terephthalate” and has a Chemical Abstract Service (CAS) registry number of 6422-86-2. Regardless of the label, all DOTP is covered by these investigations.
Subject merchandise is currently classified under subheading 2917.39.2000 of the Harmonized Tariff Schedule of the United States (HTSUS). Subject merchandise may also enter under subheadings 2917.39.7000 or 3812.20.1000 of the HTSUS. While the CAS registry number and HTSUS classifications are provided for convenience and customs purposes, the written description of the scope of these investigations is dispositive.
DEPARTMENT OF COMMERCE
International Trade Administration
[C-580-917]
Brass Rod From the Republic of Korea: Final Affirmative Countervailing Duty Determination

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that countervailable subsidies are being provided to producers and exporters of brass rod from the Republic of Korea (Korea). The period of investigation is January 1, 2022, through December 31, 2022.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Toni Page or Lingjun Wang, AD/CVD Operations, Office OVII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-1398 or (202) 482-2316, respectively.

SUPPLEMENTARY INFORMATION:

Background
On September 29, 2023, Commerce published the Preliminary Determination in the Federal Register and invited interested parties to comment on it. ^1 For a complete description of the events that followed the Preliminary Determination, see the Issues and Decision Memorandum. ^2 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at http://access.trade.gov . In addition, a complete version of the Preliminary Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx .
^1 See Brass Rod from the Republic of Korea: Preliminary Affirmative Countervailing Duty Determination and Alignment of Final Determination with Final Antidumping Duty Determination , 88 FR 67233 (September 29, 2023), and accompanying Preliminary Decision Memorandum (PDM).
^2 See Memorandum, “Issues and Decision Memorandum for the Final Affirmative Determination in the Countervailing Duty Investigation of Brass Rod from the Republic of Korea,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The product covered by this investigation is brass rod from Korea. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
During this investigation, Commerce received scope comments from parties. Commerce issued a Preliminary Scope Decision Memorandum to address these comments and set aside a period for parties to address scope issues in scope-specific case and rebuttal briefs. ^3 We did not receive timely comments from any interested parties on the Preliminary Scope Decision Memorandum. Thus, we did not make any changes to the scope of the investigation from the scope published in the Preliminary Determination , as noted in Appendix I.
^3 See Memorandum, “Preliminary Scope Decision Memorandum,” dated September 25, 2023 (Preliminary Scope Decision Memorandum).

Analysis of Subsidy Programs and Comments Received
The subsidy programs under investigation and the issues raised in the case and rebuttal briefs by parties are discussed in the Issues and Decision Memorandum. For a list of topics discussed, and the issues raised by parties to which we responded in the Issues and Decision Memorandum, see Appendix II.

Verification
As provided in section 782(i) of the Tariff Act of 1930, as amended (the Act), between January 15 and February 2, 2024, Commerce conducted verification of the subsidy information reported by the Government of the Republic of Korea (GOK), Booyoung Industry (BYI), and Daechang Co. Ltd. (Daechang). ^4 We used standard verification procedures, including an examination of relevant accounting records and original source documents provided by the respondents.
^4 See Memoranda, “Verification of the Questionnaire Response of the Government of Korea,” dated February 29, 2024; “Verification of Questionnaire Responses of Booyoung Industry,” dated February 27, 2024; and “Verification of Questionnaire Responses of Daechang Co., Ltd.,” dated March 1, 2024.

Methodology
Commerce conducted this investigation in accordance with section 701 of the Act. For each of the subsidy programs found to be countervailable, Commerce preliminarily determines that there is a subsidy, i.e. , a financial contribution by an “authority” that gives rise to a benefit to the recipient, and that the subsidy is specific. ^5 For a full description of the methodology underlying our final determination, see the Issues and Decision Memorandum.
^3 See sections 771(5)(B) and (D) of the Act regarding financial contribution; section 771(5)(E) of the Act regarding benefit; and section 771(5A) of the Act regarding specificity.
In making this final determination, Commerce relied, in part, on facts otherwise available, including adverse facts available (AFA), pursuant to sections 776(a) and (b) of the Act. For a full discussion of our application of AFA, see the section “Use of Facts Available and Adverse Inferences” in the accompanying Issues and Decision Memorandum.

Changes Since the Preliminary Determination
Based on our review and analysis of the information received during verification and comments received from parties, for this final determination, we made certain changes to the countervailable subsidy rate calculations for BYI, Daechang, and for all other producers/exporters. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Pursuant to section 705(c)(5)(A)(i) of the Act, Commerce will determine an all-others rate equal to the weighted average countervailable subsidy rates established for those exporters and/or producers individually investigated, excluding any zero and de minimis countervailable subsidy rates and any rates based entirely under section 776 of the Act.
In this investigation, Commerce calculated rates for BYI and Daechang that are above de minimis and are not based entirely on facts available. For the all-others rate we are using the simple average of the subsidy rates calculated for BYI and Daechang. This is consistent with the methodology that we use in an investigation to establish the all-others rate, pursuant to section 705(c)(5)(A) of the Act.

Final Determination
Commerce determines that the following estimated countervailable subsidy rates exist for the period of January 1, 2022, through December 31, 2022:
^6 Commerce has found the following companies to be cross-owned with Daechang Co. Ltd.: Essentech Co., Ltd., IN Steel Industry Co., Ltd., Seowon Co., Ltd., Taewoo Co., Ltd., and IMI Co., Ltd.
Company | Subsidy rate (percent ad valorem )
Booyoung Industry | 2.04
Daechang Co. Ltd ^6 | 3.70
All Others | 2.87

Continuation of Suspension of Liquidation
As a result of our Preliminary Determination , and pursuant to sections 703(d)(1)(B) and (d)(2) of the Act, Commerce instructed U.S. Customs and Border Protection (CBP) to collect cash deposits and suspend liquidation of entries of subject merchandise as described in the scope of the investigation section entered, or withdrawn from warehouse, for consumption on or after September 29, 2023, the date of publication of the Preliminary Determination in the Federal Register .
Additionally, pursuant to section 705(c)(1)(B)(ii) of the Act and 19 CFR 351.210(d), where appropriate, Commerce will instruct CBP to require a cash deposit equal to the estimated individual countervailable subsidy rate or the estimated all-others rate, as indicated in the chart above, effective on the date of publication of this final determination.
If the U.S. International Trade Commission (ITC) issues a final affirmative injury determination, we will issue a countervailing duty order and require a cash deposit of estimated countervailing duties for such entries of subject merchandise in the amounts indicated above, in accordance with section 706(a) of the Act. If the ITC determines that material injury, or threat of material injury, does not exist, this proceeding will be terminated, and all estimated duties deposited or securities posted as a result of the suspension of liquidation will be refunded or canceled.

Disclosure
Commerce intends to disclose its calculations and analysis performed to interested parties in this final determination within five days of its public announcement, or if there is no public announcement, within five days of the date of this notice in accordance with 19 CFR 351.224(b).

ITC Notification
In accordance with section 705(d) of the Act, Commerce will notify the ITC of its final affirmative determination that countervailable subsidies are being provided to producers and exporters of brass rod from Korea. As Commerce's final determination is affirmative, in accordance with section 705(b) of the Act, the ITC will determine, within 45 days, whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports of brass rod from Korea. In addition, we are making available to the ITC all non-privileged and non-proprietary information related to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order (APO), without the written consent of the Assistant Secretary for Enforcement and Compliance.

Administrative Protective Order
In the event that the ITC issues a final negative injury determination, this notice will serve as the only reminder to parties subject to the APO of their responsibility concerning the destruction of proprietary information disclosed under APO, in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.

Notification to Interested Parties
This final determination is issued and published pursuant to sections 705(d) and 777(i) of the Act, and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I—Scope of the Investigation
The products covered by this investigation are brass rod and bar (brass rod), which is defined as leaded, low-lead, and no-lead solid brass made from alloys such as, but not limited to the following alloys classified under the Unified Numbering System (UNS) as C27450, C27451, C27460, C34500, C35000, C35300, C35330, C36000, C36300, C37000, C37700, C48500, C67300, C67600, and C69300, and their international equivalents.
The brass rod subject to this investigation has an actual cross-section or outside diameter greater than 0.25 inches but less than or equal to 12 inches. Brass rod cross-sections may be round, hexagonal, square, or octagonal shapes as well as special profiles ( e.g. , angles, shapes), including hollow profiles.
Standard leaded brass rod covered by the scope contains, by weight, 57.0-65.0 percent copper; 0.5-3.0 percent lead; no more than 1.3 percent iron; and at least 15 percent zinc. No-lead or low-lead brass rod covered by the scope contains by weight 59.0-76.0 percent copper; 0-1.5 percent lead; no more than 0.35 percent iron; and at least 15 percent zinc. Brass rod may also include other chemical elements ( e.g. , nickel, phosphorous, silicon, tin, etc .).
Brass rod may be in straight lengths or coils. Brass rod covered by this investigation may be finished or unfinished, and may or may not be heated, extruded, pickled, or cold-drawn. Brass rod may be produced in accordance with ASTM B16, ASTM B124, ASTM B981, ASTM B371, ASTM B453, ASTM B21, ASTM B138, and ASTM B927, but such conformity to an ASTM standard is not required for the merchandise to be included within the scope.
Excluded from the scope of this investigation is brass ingot, which is a casting of unwrought metal unsuitable for conversion into brass rod without remelting, that contains, by weight, at least 57.0 percent copper and 15.0 percent zinc.
The merchandise covered by this investigation is currently classifiable under subheadings 7407.21.9000, 7407.21.7000, and 7407.21.1500 of the Harmonized Tariff Schedule of the United States (HTSUS). Products subject to the scope may also enter under HTSUS subheadings 7403.21.0000, 7407.21.3000, and 7407.21.5000. The HTSUS subheadings and UNS alloy designations are provided for convenience and customs purposes. The written description of the scope of the investigation is dispositive.

Appendix II—List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Scope of the Investigation
IV. Subsidies Valuation
V. Use of Facts Otherwise Available and Adverse Inferences
VI. Analysis of Programs
VII. Discussion of the Issues
Comment 1: Whether to Revise Preliminary Determination on Provision of Electricity for Less Than Adequate Remuneration (LTAR)
Comment 2: Whether to Apply Adverse Facts Available (AFA) to BYI's Reported Loan
Comment 3: Whether to Apply AFA to Essentech's Loans
Comment 4: Whether Daechang Received Benefits from the Provision of Carbon Emission Permits by the GOK-Korea Emission Trading System (K-ETS)
Comment 5: Whether to Treat Seowon as a Cross-Owned Producer of Subject Merchandise for Purposes of Attribution
Comment 6: Whether to Allocate the Benefit Received Over Total Sales for the Energy Efficiency Utilizing Artificial Intelligence Program
Comment 7: Whether to Revise Daechang's Benefit Calculation for the Facility Improvement Fund to Reduce Air Pollutants in Sihwa Banwol Industrial Complex Program
Comment 8: Whether the Hwaseong City Export Logistics Support Program is Countervailable
VIII. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[A-791-828]
Brass Rod From South Africa: Final Affirmative Determination of Sales at Less Than Fair Value

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that imports of brass rod from South Africa are being, or are likely to be, sold in the United States at less than fair value (LTFV) for the period of investigation (POI) April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Dmitry Vladimirov, AD/CVD Operations, Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-0665.

SUPPLEMENTARY INFORMATION:

Background
On December 1, 2023, Commerce published in the Federal Register its preliminary affirmative determination in the LTFV investigation of brass rod from South Africa, in which it also postponed the final determination until April 15, 2024. ^1 We invited interested parties to comment on the Preliminary Determination.
^1 See Brass Rod from South Africa: Preliminary Affirmative Determination of Sales at Less Than Fair Value, Postponement of Final Determination, and Extension of Provisional Measures, 88 FR 83904 (December 1, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum.
A summary of the events that occurred since Commerce published the Preliminary Determination, as well as a full discussion of the issues raised by parties for this final determination, may be found in the Issues and Decision Memorandum. ^2 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov. In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx.
^2 See Memorandum, “Issues and Decision Memorandum for the Final Affirmative Determination of Sales at Less Than Fair Value in the Investigation of Brass Rod from South Africa,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The product covered by this investigation is brass rod from South Africa. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
During this investigation, Commerce received scope comments from parties. Commerce issued a Preliminary Scope Decision Memorandum to address these comments and set aside a period for parties to address scope issues in scope-specific case and rebuttal briefs. ^3 We did not receive timely comments from any interested parties on the Preliminary Scope Decision Memorandum. Thus, we did not make any changes to the scope of the investigation from the scope published in the Preliminary Determination, as noted in Appendix I. ^4
^3 See Memorandum, “Preliminary Scope Decision Memorandum,” dated September 25, 2023 (Preliminary Scope Decision Memorandum).
^4 See Brass Rod from India: Final Affirmative Countervailing Duty Determination, 88 FR 87407 (December 18, 2023).

Verification
Commerce verified the sales and cost information submitted by Non-Ferrous Metal Works (SA) (PTY) Ltd. (NFMW) ^5 for use in our final determination, consistent with section 782(i) of the Tariff Act of 1930, as amended (the Act). We used standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by NFMW.
^5 See Memorandum, “Sales Verification Report,” dated January 23, 2024; Memorandum, “CEP Sales Verification Report,” dated January 29, 2024, and Memorandum, “Verification of the Cost Response of Non-Ferrous Metal Works (SA) (PTY) Ltd.,” dated February 20, 2024.

Analysis of Comments Received
All issues raised in the case and rebuttal briefs submitted by interested parties in this investigation are addressed in the Issues and Decision Memorandum. A list of the issues addressed in the Issues and Decision Memorandum is attached to this notice as Appendix II.

Changes Since the Preliminary Determination
We made certain changes to the margin calculation for NFMW since the Preliminary Determination. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Section 735(c)(5)(A) of the Act provides that the estimated weighted-average dumping margin for all other producers and exporters not individually investigated shall be equal to the weighted average of the estimated weighted-average dumping margins established for individually investigated exporters and producers, excluding rates that are zero, de minimis, or determined entirely under section 776 of the Act, i.e., facts otherwise available.
In this investigation, Commerce calculated an individual estimated weighted-average dumping margin for the sole mandatory respondent, NFMW, that is not zero, de minimis, or based entirely on facts otherwise available. Consequently, Commerce assigned the estimated weighted-average dumping margin calculated for NFMW to all other producers and exporters of the merchandise under consideration, pursuant to section 735(c)(5)(A) of the Act.

Final Determination
Commerce determines that the following estimated weighted-average dumping margins exist:
Exporter/producer | Weighted-average dumping margin (percent)
Non-Ferrous Metal Works (SA) (PTY) Ltd. | 10.67
All Others | 10.67

Disclosure
Commerce intends to disclose the calculations performed in connection with this final determination to interested parties within five days of any public announcement or, if there is no public announcement, within five days of the date of publication of this notice in the Federal Register , in accordance with 19 CFR 351.224(b).

Continuation of Suspension of Liquidation
In accordance with section 735(c)(1)(B) of the Act, Commerce will instruct U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all entries of subject merchandise, as described in Appendix I of this notice, which were entered, or withdrawn from warehouse, for consumption on or after December 1, 2023, the date of publication of the Preliminary Determination in the Federal Register . These suspension of liquidation instructions will remain in effect until further notice.
Pursuant to section 735(c)(1)(B)(ii) of the Act and 19 CFR 351.210(d), upon the publication of this notice, we will instruct CBP to require a cash deposit for estimated antidumping duties for such entries as follows: (1) the cash deposit rate for the respondent listed in the table above is the company-specific estimated weighted-average dumping margin listed for the respondent in the table; (2) if the exporter is not the respondent listed in the table above, but the producer is, then the cash deposit rate is the company-specific estimated weighted-average dumping margin listed for the producer of the subject merchandise in the table above; and (3) the cash deposit rate for all other producers and exporters is the all-others estimated weighted-average dumping margin listed in the table above.

U.S. International Trade Commission Notification
In accordance with section 735(d) of the Act, Commerce will notify the U.S. International Trade Commission (ITC) of its final affirmative determination of sales at LTFV. Because Commerce's final determination is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports or sales (or the likelihood of sales) for importation of brass rod no later than 45 days after this final determination. If the ITC determines that such injury does not exist, this proceeding will be terminated, all cash deposits posted will be refunded, and suspension of liquidation will be lifted. If the ITC determines that such injury does exist, Commerce will issue an antidumping duty order directing CBP to assess, upon further instruction by Commerce, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation, as discussed in the “Continuation of Suspension of Liquidation” section above.

Administrative Protective Order
This notice serves as the only reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a sanctionable violation.

Notification to Interested Parties
This final determination and notice are issued and published in accordance with sections 735(d) and 777(i) of the Act and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I

Scope of the Investigation
The products covered by this investigation are brass rod and bar (brass rod), which is defined as leaded, low-lead, and no-lead solid brass made from alloys such as, but not limited to the following alloys classified under the Unified Numbering System (UNS) as C27450, C27451, C27460, C34500, C35000, C35300, C35330, C36000, C36300, C37000, C37700, C48500, C67300, C67600, and C69300, and their international equivalents.
The brass rod subject to this investigation has an actual cross-section or outside diameter greater than 0.25 inches but less than or equal to 12 inches. Brass rod cross-sections may be round, hexagonal, square, or octagonal shapes as well as special profiles ( e.g., angles, shapes), including hollow profiles.
Standard leaded brass rod covered by the scope contains, by weight, 57.0-65.0 percent copper; 0.5-3.0 percent lead; no more than 1.3 percent iron; and at least 15 percent zinc. No-lead or low-lead brass rod covered by the scope contains by weight 59.0-76.0 percent copper; 0-1.5 percent lead; no more than 0.35 percent iron; and at least 15 percent zinc. Brass rod may also include other chemical elements ( e.g., nickel, phosphorous, silicon, tin, etc. ).
Brass rod may be in straight lengths or coils. Brass rod covered by this investigation may be finished or unfinished, and may or may not be heated, extruded, pickled, or cold-drawn. Brass rod may be produced in accordance with ASTM B16, ASTM B124, ASTM B981, ASTM B371, ASTM B453, ASTM B21, ASTM B138, and ASTM B927, but such conformity to an ASTM standard is not required for the merchandise to be included within the scope.
Excluded from the scope of this investigation is brass ingot, which is a casting of unwrought metal unsuitable for conversion into brass rod without remelting, that contains, by weight, at least 57.0 percent copper and 15.0 percent zinc.
The merchandise covered by this investigation is currently classifiable under subheadings 7407.21.9000, 7407.21.7000, and 7407.21.1500 of the Harmonized Tariff Schedule of the United States (HTSUS). Products subject to the scope may also enter under HTSUS subheadings 7403.21.0000, 7407.21.3000, and 7407.21.5000. The HTSUS subheadings and UNS alloy designations are provided for convenience and customs purposes. The written description of the scope of the investigation is dispositive.

Appendix II

List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Period of Investigation
IV. Scope of the Investigation
V. Changes Since the Preliminary Determination
VI. Discussion of the Issues
Comment 1: Constructed Export Price (CEP) Offset
Comment 2: Flood-Related Expenses and Insurance Reimbursement Offset
VII. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[A-533-912]
Final Affirmative Determination in the Less-Than-Fair-Value Investigation of Certain Non-Refillable Steel Cylinders From India

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that certain non-refillable steel cylinders (cylinders) from the India are being, or are likely to be, sold in the United States at less than fair value (LTFV). The period of investigation (POI) is April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Benito Ballesteros or Samuel Evans, AD/CVD Operations, Office IX, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-7425 or (202) 482-2420, respectively.

SUPPLEMENTARY INFORMATION:

Background
Commerce selected two companies, Bhiwadi Cylinders Pvt. Ltd./Sapphire (India) Pvt. Ltd. (collectively Bhiwadi/Sapphire) ^1 and Inox India Limited (Inox) as the mandatory respondents, in this investigation. On December 1, 2023, Commerce published in the Federal Register the Preliminary Determination, in which it also postponed the final determination until not later than 135 days after the date of publication of the Preliminary Determination ( i.e., April 15, 2024). ^2 We invited parties to comment on the Preliminary Determination.
^1 Commerce determined that it was appropriate to collapse Bhiwadi and Sapphire and treat these companies as a single entity. See Memorandum, “Preliminary Determination Affiliation and Single Entity Memorandum,” dated November 24, 2023.
^2 See Certain Non-Refillable Steel Cylinders from India: Preliminary Affirmative Determination of Sales at Less Than Fair Value, Postponement of Final Determination, and Extension of Provisional Measures, 88 FR 83906 (December 1, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum (PDM).
In March 2024, we received case briefs from Worthington Industries (the petitioner) and Bhiwadi/Sapphire, ^3 and rebuttal briefs from the petitioner, Bhiwadi/Sapphire, and Inox. ^4 For a complete description of the events that occurred since the Preliminary Determination, see the Issues and Decision Memorandum. ^5 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov. In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx.
^3 See Petitioner's Letter, “Petitioner's Case Brief for Inox India, Ltd,” dated March 20, 2024; Petitioner's Letter, “Petitioner's Case Brief for Bhiwadi Cylinders Private Limited,” dated March 20, 2024; and Bhiwadi/Sapphire's Letter, “Bhiwadi's Revised Case Brief,” dated March 26, 2024.
^4 See Petitioner's Letter, “Petitioner's Rebuttal Brief for Bhiwadi Cylinders Private Limited,” dated March 26, 2024; Bhiwadi/Sapphire's Letter, “Bhiwadi's Rebuttal Case Brief,” dated March 26, 2024; and Inox's Letter, “Rebuttal Brief,” dated March 26, 2024.
^5 See Memorandum, “Decision Memorandum for the Final Affirmative Determination in the Less-Than-Fair-Value Investigation of Certain Non-Refillable Steel Cylinders from India,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The merchandise covered by the scope of this investigation is cylinders from India. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
No interested party commented on the scope of the investigation as it appeared in the Preliminary Determination. Therefore, no changes were made to the scope of the investigation.

Verification
Commerce conducted verification of the information relied upon in making its final determination in this investigation, in accordance with section 782(i) of the Tariff Act of 1930, as amended (the Act). Specifically, we conducted on-site verifications of Bhiwadi/Sapphire and Inox in December 2023 and January 2024 using standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by the respondents. ^6
^6 See Memorandum, “Verification of the Cost Response of Bhiwadi Cylinders Private Limited and Sapphire (India) Private Limited,” dated February 8, 2024; Memorandum, “Verification of the Cost Response of Inox India Ltd.,” dated February 29, 2024; Memorandum, “Verification of the Sales Response of Inox India Limited,” dated March 11, 2024; and Memorandum, “Verification of the Sales Response of Bhiwadi Cylinders Private Limited and Sapphire (India) Private Limited,” dated March 12, 2024.

Analysis of Comments Received
All issues raised in the case and rebuttal briefs are addressed in the Issues and Decision Memorandum. A list of the issues that parties raised, and to which we responded in the Issues and Decision Memorandum, is attached to this notice in Appendix II.

Changes Since the Preliminary Determination
We made certain changes to the margin calculations for Bhiwadi/Sapphire and Inox since the Preliminary Determination. See the Issues and Decision Memorandum for a discussion of these changes.

All-Others Rate
Section 735(c)(5)(A) of the Act provides that the estimated weighted-average dumping margin for all other producers and exporters not individually investigated shall be equal to the weighted average of the estimated weighted-average dumping margins established for individually investigated exporters and producers, excluding rates that are zero, de minimis, or determined entirely under section 776 of the Act.
In this investigation, Commerce calculated a zero rate for Inox. Therefore, the only rate that is not zero, de minimis, or based entirely on facts otherwise available is the rate calculated for Bhiwadi/Sapphire. Consequently, the rate calculated for Bhiwadi/Sapphire is also assigned as the rate for all other producers and exporters.

Final Determination
The final estimated weighted-average dumping margins are listed below for the period October 1, 2021, through September 30, 2022:
Exporter/producer | Weighted-average dumping margin (percent) | Cash deposit rate (adjusted for subsidy offset(s)) (percent)
Bhiwadi Cylinders Private Limited; Sapphire (India) Private Limited | 6.27 | 4.13
Inox India Limited | 0.00 | 0.00
All Others | 6.27 | 4.13

Disclosure
Commerce intends to disclose the calculations performed in connection with this final determination to interested parties within five days of any public announcement or, if there is no public announcement, within five days of the date of publication of this final determination in the Federal Register , in accordance with 19 CFR 351.224(b).

Continuation of Suspension of Liquidation
In accordance with section 735(c)(1)(B) of the Act, Commerce will instruct U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all entries of cylinders from India, as described in Appendix I of this notice, which were entered or withdrawn from warehouse for consumption on or after December 1, 2023, the date of publication of the Preliminary Determination of this investigation in the Federal Register , with the exception of entries of subject merchandise that were produced and exported by Inox. Because the estimated weighted-average dumping margin for Inox is zero, entries of shipments of subject merchandise produced and exported by Inox will not be subject to suspension of liquidation or cash deposit requirements. In such situations, Commerce applies the exclusion to the provisional measures to the producer/exporter combination that was examined in the investigation. Accordingly, Commerce is directing CBP not to suspend liquidation of entries of merchandise produced and exported by Inox. However, entries of subject merchandise in any other producer/exporter combination, e.g., merchandise produced by a third party and exported by Inox or produced by Inox and exported by a third party, are subject to the cash deposit requirements at the all-others rate.
Furthermore, other than for entries produced and exported by Inox, pursuant to section 735(c)(1)(B)(ii) of the Act and 19 CFR 351.210(d), upon the publication of this notice, we will instruct CBP to require a cash deposit for estimated antidumping duties for such entries of merchandise as follows: (1) the cash deposit rate for the respondents listed in the table above will be equal to the company-specific estimated weighted-average dumping margin determined in this final determination; (2) if the exporter is not a respondent identified above, but the producer is, then the cash deposit rate will be equal to the company-specific estimated weighted-average dumping margin established for that producer of the subject merchandise; and (3) the cash deposit rate for all other producers and exporters will be equal to the all-others estimated weighted-average dumping margin listed in the table above.
Commerce normally adjusts cash deposits for estimated antidumping duties by the amount of export subsidies countervailed in a companion countervailing duty (CVD) proceeding, when CVD provisional measures are in effect. Accordingly, where Commerce made an affirmative determination for countervailable export subsidies, Commerce has offset the estimated weighted-average dumping margin by the appropriate CVD rate. Any such adjusted cash deposit rate may be found in the “Final Determination” section above.
Should provisional measures in the companion CVD investigation expire prior to the expiration of provisional measures in this LTFV investigation, Commerce will direct CBP to begin collecting estimated antidumping duty cash deposits unadjusted for countervailed export subsidies at the time that the provisional CVD measures expire.
These suspension of liquidation instructions will remain in effect until further notice.

U.S. International Trade Commission Notification
In accordance with section 735(d) of the Act, Commerce will notify the U.S. International Trade Commission (ITC) of its final affirmative determination of sales at LTFV. Because the final determination in this investigation is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured or threatened with material injury by reason of imports of cylinders from India no later than 45 days after our final determination. If the ITC determines that such injury does not exist, this proceeding will be terminated, all cash deposits posted will be refunded, and suspension of liquidation will be lifted. If the ITC determines that such injury does exist, Commerce will issue an antidumping duty order directing CBP to assess, upon further instruction by Commerce, antidumping duties on all imports of the subject merchandise entered or withdrawn from warehouse for consumption on or after the effective date of the suspension of liquidation, as discussed in the “Continuation of Suspension of Liquidation” section.

Administrative Protective Order
This notice also serves as a reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the return or destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.

Notification to Interested Parties
This determination is issued and published in accordance with sections 735(d) and 777(i)(1) of the Act and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I—Scope of the Investigation
The merchandise covered by this investigation is certain seamed (welded or brazed), non-refillable steel cylinders meeting the requirements of, or produced to meet the requirements of, U.S. Department of Transportation specification 39, TransportCanada specification 39M, or United Nations pressure receptacle standard ISO 11118 and otherwise meeting the description provided below (non-refillable steel cylinders). The subject non-refillable steel cylinders are portable and range from 100-cubic inch (1.6 liter) water capacity to 1,526-cubic inch (25 liter) water capacity. Subject non-refillable steel cylinders may be imported with or without a valve and/or pressure release device and are unfilled at the time of importation. Non-refillable steel cylinders filled with pressurized air otherwise meeting the physical description above are covered by this investigation.
Specifically excluded are seamless non-refillable steel cylinders.
The merchandise subject to this investigation is properly classified under statistical reporting numbers 7311.00.0060 and 7311.00.0090 of the Harmonized Tariff Schedule of the United States (HTSUS). The merchandise may also enter under HTSUS statistical reporting numbers 7310.29.0030 and 7310.29.0065. Although the HTSUS statistical reporting numbers are provided for convenience and customs purposes, the written description of the merchandise is dispositive.

Appendix II—List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Scope of the Investigation
IV. Changes Since the Preliminary Determination
V. Discussion of the Issues
Comment 1: Whether to Apply Adverse Facts Available to Bhiwadi/Sapphire
Comment 2: Whether to Adjust Bhiwadi/Sapphire's Export Prices for Average Annual Warranty Expenses
Comment 3: Whether to Adjust Bhiwadi/Sapphire's Financial Expense Ratio
Comment 4: Whether Certain of Bhiwadi/Sapphire's Cost Reallocations Should be Reversed
Comment 5: Whether to Include the Purchase Cost of Semi-Finished Cylinders in Bhiwadi/Sapphire's Cost of Manufacturing (COM)
Comment 6: Whether to Adjust Bhiwadi/Sapphire's Reported Costs for Freight Inward and Loading and Unloading Expenses
Comment 7: Whether to Make Certain Revisions to SIPL's Reported COM
Comment 8: Whether to Remove Raw Material Offsets Related to Profit Earned on Sales of Raw Materials Between BCPL and SIPL
Comment 9: Whether Inox's Cost Reconciliation is Misstated for both the Merchandise Under Consideration (MUC) and Non-MUC
Comment 10: Whether Inox's Direct Material Costs Are Unreconciled and Unsupported by Record Evidence
Comment 11: Whether Inox Understated its Reported Direct Material Costs
Comment 12: Whether Commerce Should Revise Inox's Scrap Offset
Comment 13: Whether Commerce Should Revise Inox's General and Administrative Expense Ratio
VI. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[C-533-913]
Certain Non-Refillable Steel Cylinders From India: Final Affirmative Countervailing Duty Determination

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that countervailable subsidies are being provided to producers and exporters of certain non-refillable steel cylinders (steel cylinders) from India. The period of investigation (POI) is April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Shane Subler or Rachel Accorsi, AD/CVD Operations, Office VIII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-6241 or (202) 482-3149, respectively.

SUPPLEMENTARY INFORMATION:

Background
On September 29, 2023, Commerce published the Preliminary Determination in the Federal Register. ^1 Subsequently, on February 8, 2024, Commerce released its Post-Preliminary Analysis. ^2 For a complete description of the events that followed the Preliminary Determination, see the Issues and Decision Memorandum. ^3 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov . In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx .
^1 See Certain Non-Refillable Steel Cylinders from India: Preliminary Affirmative Countervailing Duty Determination and Alignment of Final Determination With Final Antidumping Duty Determination , 88 FR 67231 (September 29, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum.
^2 See Memorandum, “Decision Memorandum for the Post-Preliminary Analysis in the Countervailing Duty Investigation of Certain Non-Refillable Steel Cylinders from India,” dated February 8, 2024 (Post-Preliminary Analysis).
^3 See Memorandum, “Issues and Decision Memorandum for the Final Affirmative Determination of the Countervailing Duty Investigation of Certain Non-Refillable Steel Cylinders from India,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The products covered by this investigation are steel cylinders. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
No interested party commented on the scope of the investigation as it appeared in the Preliminary Determination . Therefore, no changes were made to the scope of the investigation.

Verification
Commerce conducted verification of the information relied upon in making its final determination in this investigation, in accordance with section 782(i) of the Tariff Act of 1930, as amended (the Act). Specifically, we conducted on-site verifications of the Government of India, Inox India Ltd. (Inox), and Bhiwadi Cylinders Private Limited (Bhiwadi) in February 2024 using standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by the respondents. ^4
^4 See Memoranda, “Verification of the Questionnaire Responses of INOX India Ltd.,” dated March 1, 2024; “Verification of the Questionnaire Responses of the Government of India,” dated March 1, 2024; and “Verification of the Questionnaire Responses of Bhiwadi Cylinders Private Limited,” dated March 7, 2024.

Analysis of Comments Received
The subsidy programs under investigation, and the issues raised in the case and rebuttal briefs by parties in this investigation, are discussed in the Issues and Decision Memorandum. For a list of the issues raised by parties, and to which we responded in the Issues and Decision Memorandum, see Appendix II.

Methodology
Commerce conducted this investigation in accordance with section 701 of the Act. For each of the subsidy programs found to be countervailable, Commerce determines that there is a subsidy, i.e. , a financial contribution by an “authority” that gives rise to a benefit to the recipient, and that the subsidy is specific. ^5 For a full description of the methodology underlying our final determination, see the Issues and Decision Memorandum.
^5 See sections 771(5)(B) and (D) of the Act regarding financial contribution; section 771(5)(E) of the Act regarding benefit; and section 771(5A) of the Act regarding specificity.
In making this final determination, Commerce relied, in part, on facts available and, because it finds that the Government of India did not act to the best of its ability to respond to Commerce's requests for information, Commerce has drawn an adverse inference where appropriate in selecting from among the facts otherwise available. For a full discussion of our application of adverse facts available, see the “Use of Facts Otherwise Available and Application of Adverse Inferences” section in the Issues and Decision Memorandum.

Changes Since the Preliminary Determination and Post-Preliminary Analysis
Based on our findings at verification and our review and analysis of the comments received from parties, for this final determination, we made certain changes to the countervailable subsidy rate calculations for Inox, Bhiwadi, and for all other producers/exporters. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Pursuant to section 705(c)(5)(A)(i) of the Act, Commerce will determine an all-others rate equal to the weighted-average countervailable subsidy rates established for exporters and/or producers individually investigated, excluding any zero and de minimis countervailable subsidy rates, and any rates based entirely under section 776 of the Act. We continue to calculate individual estimated countervailable subsidy rates for Bhiwadi and Inox that are not zero, de minimis , or based entirely on facts otherwise available. We, therefore, continue to calculate the all-others rate using a weighted average of the individual estimated subsidy rates calculated for Bhiwadi and Inox, the individually examined exporters/producers in this investigation, pursuant to section 705(c)(5)(A)(i) of the Act.

Final Determination
Commerce determines that the following estimated countervailable subsidy rates exist for the period April 1, 2022, through March 31, 2023:
^6 Commerce finds the following company to be cross-owned with Bhiwadi Cylinders Private Limited: Sapphire (India) Private Limited.
Company | Subsidy rate ad valorem (percent)
Bhiwadi Cylinders Private Limited ^6 | 2.48
Inox India Ltd | 2.26
All Others | 2.38

Disclosure
Commerce intends to disclose its calculations and analysis performed to interested parties in this final determination within five days of any public announcement, or if there is no public announcement, within five days of the date of the publication of this notice in the Federal Register , in accordance with 19 CFR 351.224(b).

Continuation of Suspension of Liquidation
As a result of our Preliminary Determination , and pursuant to sections 703(d)(1)(B) and (d)(2) of the Act, Commerce instructed U.S. Customs and Border Protection (CBP) to collect cash deposits and suspend liquidation of entries of subject merchandise as described in the scope of the investigation section entered, or withdrawn from warehouse, for consumption on or after September 29, 2023, the date of publication of the Preliminary Determination in the Federal Register . In accordance with section 703(d) of the Act, on January 29, 2024, we instructed CBP to discontinue the suspension of liquidation of all entries of subject merchandise entered or withdrawn from warehouse on or after January 27, 2024, but to continue the suspension of liquidation of all entries of subject merchandise on or after September 29, 2023, to on or before January 26, 2024.
If the U.S. International Trade Commission (ITC) issues a final affirmative injury determination, we will issue a countervailing duty order, reinstate the suspension of liquidation under section 706(a) of the Act, and require a cash deposit of estimated countervailing duties for such entries of subject merchandise in the amounts indicated above, in accordance with section 706(a) of the Act. If the ITC determines that material injury, or threat of material injury, does not exist, this proceeding will be terminated, and all estimated duties deposited or securities posted as a result of the suspension of liquidation will be refunded or canceled.

ITC Notification
In accordance with section 705(d) of the Act, Commerce will notify the ITC of its final affirmative determination that countervailable subsidies are being provided to producers and exporters of steel cylinders from India. As Commerce's final determination is affirmative, in accordance with section 705(b) of the Act, the ITC will determine, within 45 days, whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports of steel cylinders from India. In addition, we are making available to the ITC all non-privileged and non-proprietary information related to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order (APO), without the written consent of the Assistant Secretary for Enforcement and Compliance.

Administrative Protective Order
In the event that the ITC issues a final negative injury determination, this notice will serve as the only reminder to parties subject to an APO of their responsibility concerning the destruction of proprietary information disclosed under APO, in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.

Notification to Interested Parties
This determination is issued and published pursuant to sections 705(d) and 777(i) of the Act, and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I

Scope of the Investigation
The merchandise covered by this investigation is certain seamed (welded or brazed), non-refillable steel cylinders meeting the requirements of, or produced to meet the requirements of, U.S. Department of Transportation specification 39, TransportCanada specification 39M, or United Nations pressure receptacle standard ISO 11118 and otherwise meeting the description provided below (non-refillable steel cylinders). The subject non-refillable steel cylinders are portable and range from 100-cubic inch (1.6 liter) water capacity to 1,526-cubic inch (25 liter) water capacity. Subject non-refillable steel cylinders may be imported with or without a valve and/or pressure release device and are unfilled at the time of importation. Non-refillable steel cylinders filled with pressurized air otherwise meeting the physical description above are covered by this investigation.
Specifically excluded are seamless non-refillable steel cylinders.
The merchandise subject to this investigation is properly classified under statistical reporting numbers 7311.00.0060 and 7311.00.0090 of the Harmonized Tariff Schedule of the United States (HTSUS). The merchandise may also enter under HTSUS statistical reporting numbers 7310.29.0030 and 7310.29.0065. Although the HTSUS statistical reporting numbers are provided for convenience and customs purposes, the written description of the merchandise is dispositive.

Appendix II

List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Scope of the Investigation
IV. Subsidies Valuation Information
V. Use of Facts Otherwise Available and Application of Adverse Inferences
VI. Analysis of Programs
VII. Discussion of the Issues
Comment 1: Whether Commerce Incorrectly Found the Duty Drawback (DDB) Program to Be Countervailable
Comment 2: Whether Commerce Incorrectly Determined that the Mandatory Respondents Benefited from the Merchandise Export from India Scheme (MEIS) and Target Plus Scheme (TPS) After the Programs Were Discontinued
Comment 3a: Whether Commerce Should Revise the Calculation of the Export Promotion of Capital Goods Scheme (EPCGS) Benefit for Inox
Comment 3b: Whether Commerce Incorrectly Found the EPCGS to Be Countervailable
Comment 4a: Whether Commerce Incorrectly Found the Remission of Duties and Taxes on Export Products (RODTEP) Scheme to Be Countervailable
Comment 4b: Whether Commerce Should Amend Its Benefit Calculation Methodology for the RODTEP Program
Comment 5a: Whether Commerce Erred by Applying Adverse Facts Available (AFA) in Its Specificity Determinations for the Provision of Cold-Rolled (CR) Steel by the Steel Authority of India Limited (SAIL) for Less Than Adequate Remuneration (LTAR) and the Provision of Hot-Rolled (HR) Steel by SAIL for LTAR Programs
Comment 5b: Whether SAIL Is a Government “Authority”
Comment 5c: Whether Commerce Should Find the Indian CR Steel and HR Steel Markets to Be Distorted by the Government of India's (GOI) Involvement
Comment 5d: Whether Commerce Properly Countervailed Bhiwadi's HR Coil Purchases
Comment 6: Whether Commerce Should Correct Its Status Holders Incentive Scheme (SHIS) Benefit Calculation Methodology
Comment 7: Whether Inox Received a Stamp Duty Exemption Within the Kandla Special Economic Zone (SEZ) to Produce Subject Merchandise
Comment 8: Whether the Mukhyamantri Apprentice Training Scheme (MATS) Confers a Countervailable Subsidy
VIII. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[A-580-916]
Brass Rod From the Republic of Korea: Final Affirmative Determination of Sales at Less Than Fair Value

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that brass rod from the Republic of Korea (Korea) is being, or is likely to be, sold in the United States at less than fair value (LTFV) for the period of investigation (POI) April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Krisha Hill or Drew Jackson, AD/CVD Operations, Office IV, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-4037 or (202) 482-4406, respectively.

SUPPLEMENTARY INFORMATION:

Background
On December 1, 2023, Commerce published in the Federal Register its preliminary affirmative determination in the LTFV investigation of brass rod from Korea, in which it also postponed the final determination until April 15, 2023. ^1 We invited interested parties to comment on the Preliminary Determination.
^1 See Brass Rod from the Republic of Korea: Preliminary Affirmative Determination of Sales at Less Than Fair Value, Postponement of Final Determination, and Extension of Provisional Measures, 88 FR 83915 (December 1, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum (PDM) (Postponing the final determination to 135 days after the publication of the Preliminary Determination would place the deadline on Sunday April 14, 2024. Pursuant to the “Next Business Day” rule, where a deadline falls on a weekend or federal holiday, the appropriate deadline is the next business day. See Notice of Clarification: Application of “Next Business Day” Rule for Administrative Determination Deadlines Pursuant to the Tariff Act of 1930, As Amended, 70 FR 24533 (May 10, 2005)).
A summary of the events that occurred since Commerce published the Preliminary Determination, as well as a full discussion of the issues raised by parties for this final determination may be found in the Issues and Decision Memorandum. ^2 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov. In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx.
^2 See Memorandum, “Decision Memorandum for the Final Affirmative Determination of Sales at Less-Than-Fair-Value in the Investigation of Brass Rod from the Republic of Korea,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The product covered by this investigation is brass rod from Korea. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
During this investigation, Commerce received scope comments from parties. Commerce issued a Preliminary Scope Decision Memorandum to address these comments and set aside a period of time for parties to address scope issues in scope-specific case and rebuttal briefs. ^3 We did not receive timely comments from any interested parties on the Preliminary Scope Memorandum. Thus, we did not make any changes to the scope of the investigation from the scope published in the Preliminary Determination, as noted in Appendix I.
^3 See Memorandum, “Preliminary Scope Decision Memorandum,” dated September 25, 2023 (Preliminary Scope Decision Memorandum).

Verification
Commerce verified the sales and cost information submitted by Booyoung Industry (BYI) and Daechang Co., Ltd. (Daechang) ^4 for use in our final determination, consistent with section 782(i) of the Tariff Act of 1930, as amended (the Act). We used standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by BYI and Daechang. ^5
^4 Commerce has treated Daechang Co., Ltd., Seowon Co. Ltd., and IMI Co. Ltd. as single entity in this investigation.
^5 See Memorandum, “Verification of the Sales Response of Booyoung Industry in the Antidumping Duty Investigation of Brass Rod from the Republic of Korea,” dated February 27, 2024; Memorandum, “Verification of the Cost Response of Booyoung Industry (BYI) in the Less-Than-Fair-Value Investigation of Brass Rod from Korea,” dated February 28, 2024; Memorandum, “Verification of the Cost Response of Daechang Co., Ltd. in the Less-Than-Fair-Value Investigation of Certain Brass Rod from the Republic of Korea,” dated February 8, 2024; Memorandum, “Verification of the Sales Response of Daechang Co., Ltd.'s U.S. Affiliate, Daechang Lloyds Inc., in the Antidumping Investigation of Brass Rod from the Republic of Korea,” dated February 27, 2024; and Memorandum, “Verification of the Sales Response of Daechang Co. Ltd. in the Antidumping Investigation of Brass Rod from the Republic of Korea,” dated February 27, 2024.

Analysis of Comments Received
All issues raised in the case and rebuttal briefs by interested parties in this investigation are addressed in the Issues and Decision Memorandum. A list of the issues raised is attached to this notice as Appendix II.

Changes Since the Preliminary Determination
We made certain changes to the margin calculation for BYI and Daechang since the Preliminary Determination. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Section 735(c)(5)(A) of the Act provides that the estimated weighted-average dumping margin for all other producers and exporters not individually investigated shall be equal to the weighted average of the estimated weighted-average dumping margins established for individually investigated exporters and producers, excluding rates that are zero, de minimis, or determined entirely under section 776 of the Act, i.e., facts otherwise available.
In this investigation, Commerce calculated estimated weighted-average dumping margins that are above de minimis for the mandatory respondents, BYI and Daechang. Commerce calculated the all-others rate by weight-averaging the estimated weighted-average dumping margins that it calculated for the individually examined respondents. Commerce weight-averaged these dumping margins using the publicly ranged total quantities of each respondent's sales of subject merchandise to the United States during the POI. ^6
^6 With two respondents under examination, Commerce normally calculates: (A) a weighted-average of the estimated weighted-average dumping margins calculated for the examined respondents; (B) a simple average of the estimated weighted-average dumping margins calculated for the examined respondents; and (C) a weighted-average of the estimated weighted-average dumping margins calculated for the examined respondents using each company's publicly ranged U.S. sale quantities for the merchandise under consideration. Commerce then compares (B) and (C) to (A) and selects the rate closer to (A) as the most appropriate rate for all other producers and exporters. See Ball Bearings and Parts Thereof from France, Germany, Italy, Japan, and the United Kingdom: Final Results of Antidumping Duty Administrative Reviews, Final Results of Changed-Circumstances Review, and Revocation of an Order in Part, 75 FR 53661, 53663 (September 1, 2010), and accompanying Issues and Decision Memorandum at Comment 1; see also Memorandum, “All-Others Rate Calculation,” dated concurrently with this notice.

Final Determination
Commerce determines that the following estimated weighted-average dumping margins exist:
^7 IMI Co. Ltd. is referred to as “Affiliate A” in Daechang's response and the Preliminary Determination. Daechang has consented to the public disclosure of IMI Co. Ltd.'s identity. See Daechang's Letter, “Response to the Department's December 12th Letter Concerning Business Proprietary Treatment of Certain Information,” dated December 15, 2023 (“Nevertheless, in order to avoid the potential adverse consequences associated with the Department's treatment of certain factual submissions as “non-conforming”— notwithstanding the safeguards afforded to Daechang under 19 CFR 351.105(c)—Daechang, under protest, consents to treat Affiliate A's { i.e., IMI Co. Ltd.} identity as public information.”).
Exporter/producer | Weighted-average dumping margin (percent) | Cash deposit rate (adjusted for subsidy offset(s) (percent)
Booyoung Industry | 9.18 | 7.45
Daechang Co., Ltd./Seowon Co. Ltd./IMI Co. Ltd. ^7 | 8.26 | 8.04
All Others | 8.48 | 7.90

Disclosure
Commerce intends to disclose the calculations performed in connection with this final determination within five days of any public announcement or, if there is no public announcement, within five days of the date of publication of this notice, in accordance with 19 CFR 351.224(b).

Suspension of Liquidation
In accordance with section 733(d)(2) of the Act, Commerce will direct U.S. Customs and Border Protection (CBP) to suspend liquidation of all entries of brass rod from Korea as described in the appendix, entered, or withdrawn from warehouse, for consumption on or after the date of publication of this notice in the Federal Register .
Further, pursuant to section 733(d)(1)(B) of the Act and 19 CFR 351.205(d), Commerce will instruct CBP to require a cash deposit equal to the estimated weighted-average dumping margin or the estimated all-others rate, as follows: (1) the cash deposit rate for the respondents listed in the table above is the company-specific cash deposit rate listed for the respondent in the table; (2) if the exporter is not a respondent identified in the table above, but the producer is, then the cash deposit rate will be equal to the company-specific estimated weighted-average dumping margin established for that producer of the subject merchandise; and (3) the cash deposit rate for all other producers and exporters will be equal to the all-others estimated weighted-average dumping margin.

U.S. International Trade Commission Notification
In accordance with section 735(d) of the Act, we will notify the U.S. International Trade Commission (ITC) of this final affirmative determination of sales at LTFV. Because Commerce's final determination is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports or sales (or the likelihood of sales) for importation of brass rod no later than 45 days after this final determination. If the ITC determines that such injury does not exist, this proceeding will be terminated, all cash deposits posted will be refunded, and suspension of liquidation will be lifted. If the ITC determines that such injury does exist, Commerce will issue an antidumping duty order directing CBP to assess, upon further instruction by Commerce, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation, as discussed in the “Continuation of Suspension of Liquidation” section above.

Administrative Protective Order
This notice serves as the only reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.

Notification to Interested Parties
This final determination and this notice are issued and published pursuant to sections 735(d) and 777(i) of the Act, and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I

Scope of the Investigation
The products covered by this investigation are brass rod and bar (brass rod), which is defined as leaded, low-lead, and no-lead solid brass made from alloys such as, but not limited to the following alloys classified under the Unified Numbering System (UNS) as C27450, C27451, C27460, C34500, C35000, C35300, C35330, C36000, C36300, C37000, C37700, C48500, C67300, C67600, and C69300, and their international equivalents.
The brass rod subject to this investigation has an actual cross-section or outside diameter greater than 0.25 inches but less than or equal to 12 inches. Brass rod cross-sections may be round, hexagonal, square, or octagonal shapes as well as special profiles ( e.g., angles, shapes), including hollow profiles.
Standard leaded brass rod covered by the scope contains, by weight, 57.0-65.0 percent copper; 0.5-3.0 percent lead; no more than 1.3 percent iron; and at least 15 percent zinc. No-lead or low-lead brass rod covered by the scope contains by weight 59.0-76.0 percent copper; 0-1.5 percent lead; no more than 0.35 percent iron; and at least 15 percent zinc. Brass rod may also include other chemical elements ( e.g., nickel, phosphorous, silicon, tin, etc.).
Brass rod may be in straight lengths or coils. Brass rod covered by these investigations may be finished or unfinished, and may or may not be heated, extruded, pickled, or cold-drawn. Brass rod may be produced in accordance with ASTM B16, ASTM B124, ASTM B981, ASTM B371, ASTM B453, ASTM B21, ASTM B138, and ASTM B927, but such conformity to an ASTM standard is not required for the merchandise to be included within the scope.
Excluded from the scope of this investigation is brass ingot, which is a casting of unwrought metal unsuitable for conversion into brass rod without remelting, that contains, by weight, at least 57.0 percent copper and 15.0 percent zinc.
The merchandise covered by this investigation is currently classifiable under subheadings 7407.21.9000, 7407.21.7000, and 7407.21.1500 of the Harmonized Tariff Schedule of the United States (HTSUS). Products subject to the scope may also enter under HTSUS subheadings 7403.21.0000, 7407.21.3000, and 7407.21.5000. The HTSUS subheadings and UNS alloy designations are provided for convenience and customs purposes. The written description of the scope of the investigations is dispositive.

Appendix II

List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Period of Investigation
IV. Scope of the Investigation
V. Changes Since the Preliminary Determination
VI. Affiliation/Single Entity
VII. Discussion of the Issues
Booyoung Industry (BYI) Issues
Comment 1: Whether to Adjust BYI's Reported Costs for the Value of Brass Scrap Obtained as Partial Payment for Brass Rod Sales to Domestic Customers
Comment 2: Whether to Apply the Cost Verification Adjustments to BYI's Reported Costs
Comment 3: Whether BYI Failed to Report Accurate Home Market Gross Unit Prices
Comment 4: Whether Commerce Should Apply Partial Adverse Facts Available to BYI's Sales Purchases of Drawn Brass Rod Products Purchased from an Unaffiliated Supplier
Daechang Co., Ltd. (Daechang) Issues
Comment 5: Whether to Exclude Selling Expenses from Daechang's General and Administrative Expense Ratio
Comment 6: Whether to Limit Daechang's Freight Revenue Cap to Revenue Earned for Ocean Freight
Comment 7: Whether to Revise Certain Per-Unit Packing Expenses
Comment 8: Whether to Use the Revised Sales Databases That Reflect the Sales Verification Minor Corrections
VIII. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[A-533-915]
Brass Rod From India: Final Affirmative Determination of Sales at Less Than Fair Value

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that imports of brass rod from India are being, or are likely to be, sold in the United States at less than fair value (LTFV) for the period of investigation (POI) April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Allison Hollander or Christopher Williams, AD/CVD Operations, Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-2805 or (202) 482-5166, respectively.

SUPPLEMENTARY INFORMATION:

Background
On December 1, 2023, Commerce published in the Federal Register its preliminary affirmative determination in the LTFV investigation of brass rod from India, in which it also postponed the final determination until April 15, 2024. ^1 We invited interested parties to comment on the Preliminary Determination.
^1 See Brass Rod from India: Preliminary Affirmative Determination of Sales at Less Than Fair Value, Postponement of Final Determination, and Extension of Provisional Measures, 88 FR 83900 (December 1, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum.
A summary of the events that occurred since Commerce published the Preliminary Determination, as well as a full discussion of the issues raised by parties for this final determination, may be found in the Issues and Decision Memorandum. ^2 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov. In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx.
^2 See Memorandum, “Issues and Decision Memorandum for the Final Affirmative Determination of Sales at Less Than Fair Value in the Investigation of Brass Rod from India,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The product covered by this investigation is brass rod from India. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
During this investigation, Commerce received scope comments from parties. Commerce issued a Preliminary Scope Decision Memorandum to address these comments and set aside a period for parties to address scope issues in scope-specific case and rebuttal briefs. ^3 We did not receive timely comments from any interested parties on the Preliminary Scope Decision Memorandum. Thus, we did not make any changes to the scope of the investigation from the scope published in the Preliminary Determination, as noted in Appendix I. ^4
^3 See Memorandum, “Preliminary Scope Decision Memorandum,” dated September 25, 2023 (Preliminary Scope Decision Memorandum).
^4 See Brass Rod from India: Final Affirmative Countervailing Duty Determination, 88 FR 87407 (December 18, 2023) ( Brass Rod from India Countervailing Duty Final ).

Verification
Commerce verified the sales and cost information submitted by Rajhans Metals Pvt Ltd (Rajhans) and Shree Extrusions Limited (Shree) ^5 for use in our final determination, consistent with section 782(i) of the Tariff Act of 1930, as amended (the Act). We used standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by Rajhans and Shree.
^5 See Memoranda, “Sales Verification Report for Rajhans Metals Private Limited,” dated January 23, 2024; “Sales Verification report for Shree Extrusions Limited,” dated January 23, 2024; “Verification of the Cost Response of Rajhans Metals Private Limited,” dated February 12, 2024; and “Verification of the Cost Response of Shree Extrusions Limited,” dated February 26, 2024.

Analysis of Comments Received
All issues raised in the case and rebuttal briefs submitted by interested parties in this investigation are addressed in the Issues and Decision Memorandum. A list of the issues addressed in the Issues and Decision Memorandum is attached to this notice as Appendix II.

Changes Since the Preliminary Determination
We made certain changes to the margin calculations for Rajhans and Shree since the Preliminary Determination. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Section 735(c)(5)(A) of the Act provides that the estimated weighted-average dumping margin for all other producers and exporters not individually investigated shall be equal to the weighted average of the estimated weighted-average dumping margins established for individually investigated exporters and producers, excluding rates that are zero, de minimis, or determined entirely under section 776 of the Act, i.e., facts otherwise available.
In this investigation, Commerce calculated individual estimated weighted-average dumping margins for Rajhans and Shree that are not zero, de minimis, or based entirely on facts otherwise available. Because the individually calculated margins are not zero, de minimis, or based entirely on facts otherwise available, Commerce calculated an all-others rate using a weighted averages of the weighted-average dumping margins calculated for Rajhans and Shree using each company's publicly ranged U.S. sales values for the merchandise under consideration, pursuant to section 735(c)(5)(A) of the Act.

Final Determination
Commerce determines that the following estimated weighted-average dumping margins exist:
Exporter/producer | Weighted-average dumping margin (percent) | Adjusted cash deposit rate (percent)
Rajhans Metals Pvt Ltd | 2.19 | 0.00
Shree Extrusions Limited | 5.42 | 3.22
All Others | 2.41 | 0.00

Disclosure
Commerce intends to disclose the calculations performed in connection with this final determination to interested parties within five days of any public announcement or, if there is no public announcement, within five days of the date of publication of this notice in the Federal Register , in accordance with 19 CFR 351.224(b).

Continuation of Suspension of Liquidation
In accordance with section 735(c)(1)(B) of the Act, Commerce will instruct U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all entries of subject merchandise, as described in Appendix I of this notice, which were entered, or withdrawn from warehouse, for consumption on or after December 1, 2023, the date of publication of the Preliminary Determination in the Federal Register . These suspension of liquidation instructions will remain in effect until further notice.
Pursuant to section 735(c)(1)(B)(ii) of the Act and 19 CFR 351.210(d), upon the publication of this notice, we will instruct CBP to require a cash deposit for estimated antidumping duties for such entries as follows: (1) the cash deposit rates for the respondents listed in the table above are the company-specific estimated weighted-average dumping margins listed for the respondents in the table; (2) if the exporter is not a respondent listed in the table above, but the producer is, then the cash deposit rate is the company-specific estimated weighted-average dumping margin listed for the producer of the subject merchandise in the table above; and (3) the cash deposit rate for all other producers and exporters is the all-others estimated weighted-average dumping margin listed in the table above.
Commerce normally adjusts cash deposits for estimated antidumping duties by the amount of export subsidies countervailed in a companion countervailing duty investigation. Accordingly, because Commerce made an affirmative final determination for countervailable export subsidies, ^6 Commerce has offset the estimated weighted-average dumping margin by the appropriate export subsidy rate. Any such adjusted cash deposit rate may be found in the “Final Determination” section above.
^6 See Brass Rod from India Countervailing Duty Final and accompanying Issues and Decision Memorandum at 3-4 for export subsidies we found to be specific under sections 771(5A)(A) and (B) of the Act.

U.S. International Trade Commission Notification
In accordance with section 735(d) of the Act, Commerce will notify the U.S. International Trade Commission (ITC) of its final affirmative determination of sales at LTFV. Because Commerce's final determination is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports or sales (or the likelihood of sales) for importation of brass rod no later than 45 days after this final determination. If the ITC determines that such injury does not exist, this proceeding will be terminated, all cash deposits posted will be refunded, and suspension of liquidation will be lifted. If the ITC determines that such injury does exist, Commerce will issue an antidumping duty order directing CBP to assess, upon further instruction by Commerce, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation, as discussed in the “Continuation of Suspension of Liquidation” section above.

Administrative Protective Order
This notice serves as the only reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a sanctionable violation.

Notification to Interested Parties
This final determination and notice are issued and published in accordance with sections 735(d) and 777(i) of the Act and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I

Scope of the Investigation
The products covered by this investigation are brass rod and bar (brass rod), which is defined as leaded, low-lead, and no-lead solid brass made from alloys such as, but not limited to the following alloys classified under the Unified Numbering System (UNS) as C27450, C27451, C27460, C34500, C35000, C35300, C35330, C36000, C36300, C37000, C37700, C48500, C67300, C67600, and C69300, and their international equivalents.
The brass rod subject to this investigation has an actual cross-section or outside diameter greater than 0.25 inches but less than or equal to 12 inches. Brass rod cross-sections may be round, hexagonal, square, or octagonal shapes as well as special profiles ( e.g., angles, shapes), including hollow profiles.
Standard leaded brass rod covered by the scope contains, by weight, 57.0-65.0 percent copper; 0.5-3.0 percent lead; no more than 1.3 percent iron; and at least 15 percent zinc. No-lead or low-lead brass rod covered by the scope contains by weight 59.0-76.0 percent copper; 0-1.5 percent lead; no more than 0.35 percent iron; and at least 15 percent zinc. Brass rod may also include other chemical elements ( e.g., nickel, phosphorous, silicon, tin, etc. ).
Brass rod may be in straight lengths or coils. Brass rod covered by this investigation may be finished or unfinished, and may or may not be heated, extruded, pickled, or cold-drawn. Brass rod may be produced in accordance with ASTM B16, ASTM B124, ASTM B981, ASTM B371, ASTM B453, ASTM B21, ASTM B138, and ASTM B927, but such conformity to an ASTM standard is not required for the merchandise to be included within the scope.
Excluded from the scope of this investigation is brass ingot, which is a casting of unwrought metal unsuitable for conversion into brass rod without remelting, that contains, by weight, at least 57.0 percent copper and 15.0 percent zinc.
The merchandise covered by this investigation is currently classifiable under subheadings 7407.21.9000, 7407.21.7000, and 7407.21.1500 of the Harmonized Tariff Schedule of the United States (HTSUS). Products subject to the scope may also enter under HTSUS subheadings 7403.21.0000, 7407.21.3000, and 7407.21.5000. The HTSUS subheadings and UNS alloy designations are provided for convenience and customs purposes. The written description of the scope of the investigation is dispositive.

Appendix II

List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Period of Investigation
IV. Scope of the Investigation
V. Changes Since the Preliminary Determination
VI. Adjustments to Cash Deposit Rates for Export Subsidies
VII. Discussion of the Issues
Comment 1: Rajhans' Scrap Recovery Methodology
Comment 2: Rajhans' Work-in-Process (WIP) Adjustment
Comment 3: Rajhans' Billet Material
Comment 4: Rajhans' on Notice
Comment 5: Shree's U.S. International Movement Expenses
Comment 6: Quarterly Cost Methodology
VIII. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[A-570-970]
Multilayered Wood Flooring From the People's Republic of China: Preliminary Results of the Antidumping Duty Administrative Review, Preliminary Determination of No Shipments, and Rescission of Review, in Part; 2021-2022; Withdrawal

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

DATES:
Applicable April 22, 2024, FR Doc. 2023-28782, published at 88 FR 90164 on December 29, 2023, is withdrawn.

FOR FURTHER INFORMATION CONTACT:
Davyd Williams, AD/CVD Operations, Office VIII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-4338.

SUPPLEMENTARY INFORMATION:

Background
On December 29, 2023, the U.S. Department of Commerce (Commerce) erroneously published a duplicate Federal Register notice titled Multilayered Wood Flooring from the People's Republic of China: Preliminary Results of the Antidumping Duty Administrative Review, Preliminary Determination of No Shipments, and Rescission of Review, in Part; 2021-2022. Commerce is withdrawing the above-mentioned notice, Federal Register Doc. 2023-28782.

Notification to Interested Parties
This notice is issued and published pursuant to sections 751(a)(l) and 777(i)(l) of the Tariff Act of 1930, as amended, and 19 CFR 351.221(b)(4).
Dated: April 16, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.
DEPARTMENT OF COMMERCE
International Trade Administration
[A-351-859]
Brass Rod From Brazil: Final Affirmative Determination of Sales at Less Than Fair Value

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that imports of brass rod from Brazil are being, or are likely to be, sold in the United States at less than fair value (LTFV) for the period of investigation (POI) April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Claudia Cott or Thomas Schauer, AD/CVD Operations, Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-4270 or (202) 482-0410, respectively.

SUPPLEMENTARY INFORMATION:

Background
On December 1, 2023, Commerce published in the Federal Register its preliminary affirmative determination in the LTFV investigation of brass rod from Brazil, in which it also postponed the final determination until April 15, 2024. ^1 We invited interested parties to comment on the Preliminary Determination.
^1 See Brass Rod from Brazil: Preliminary Affirmative Determination of Sales at Less Than Fair Value, Postponement of Final Determination, and Extension of Provisional Measures, 88 FR 83910 (December 1, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum.
A summary of the events that occurred since Commerce published the Preliminary Determination, as well as a full discussion of the issues raised by parties for this final determination, may be found in the Issues and Decision Memorandum. ^2 The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov. In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx.
^2 See Memorandum, “Issues and Decision Memorandum for the Final Affirmative Determination of Sales at Less Than Fair Value in the Investigation of Brass Rod from Brazil,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The product covered by this investigation is brass rod from Brazil. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
During this investigation, Commerce received scope comments from parties. Commerce issued a Preliminary Scope Decision Memorandum to address these comments and set aside a period for parties to address scope issues in scope-specific case and rebuttal briefs. ^3 We did not receive timely comments from any interested parties on the Preliminary Scope Decision Memorandum. Thus, we did not make any changes to the scope of the investigation from the scope published in the Preliminary Determination, as noted in Appendix I. ^4
^3 See Memorandum, “Preliminary Scope Decision Memorandum,” dated September 25, 2023 (Preliminary Scope Decision Memorandum).
^4 See Brass Rod from India: Final Affirmative Countervailing Duty Determination, 88 FR 87407 (December 18, 2023).

Verification
Commerce verified the sales and cost information submitted by Termomecanica Sao Paulo S.A. (Termomecanica) ^5 for use in our final determination, consistent with section 782(i) of the Tariff Act of 1930, as amended (the Act). We used standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by Termomecanica.
^5 See Memorandum, “Sales Verification Report,” dated January 23, 2024; and Memorandum, “Verification of the Cost Response of Termomecanica Sao Paulo S.A.,” dated February 28, 2024.

Analysis of Comments Received
All issues raised in the case and rebuttal briefs submitted by interested parties in this investigation are addressed in the Issues and Decision Memorandum. A list of the issues addressed in the Issues and Decision Memorandum is attached to this notice as Appendix II.

Changes Since the Preliminary Determination
We made certain changes to the margin calculation for Termomecanica since the Preliminary Determination. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Section 735(c)(5)(A) of the Act provides that the estimated weighted-average dumping margin for all other producers and exporters not individually investigated shall be equal to the weighted average of the estimated weighted-average dumping margins established for individually investigated exporters and producers, excluding rates that are zero, de minimis, or determined entirely under section 776 of the Act, i.e., facts otherwise available.
In this investigation, Commerce calculated an individual estimated weighted-average dumping margin for the only individually examined respondent, Termomecanica, that is not zero, de minimis, or based entirely on facts otherwise available. Consequently, Commerce assigned the estimated weighted-average dumping margin calculated for Termomecanica to all other producers and exporters of the merchandise under consideration, pursuant to section 735(c)(5)(A) of the Act.

Final Determination
Commerce determines that the following estimated weighted-average dumping margins exist:
Exporter/producer | Weighted-average dumping margin (percent)
Termomecanica Sao Paulo S.A | 22.78
Megabras Industria Eletronica Ltda | 77.14
All Others | 22.78

Disclosure
Commerce intends to disclose the calculations performed in connection with this final determination to interested parties within five days of any public announcement or, if there is no public announcement, within five days of the date of publication of this notice in the Federal Register , in accordance with 19 CFR 351.224(b).

Continuation of Suspension of Liquidation
In accordance with section 735(c)(1)(B) of the Act, Commerce will instruct U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all entries of subject merchandise, as described in Appendix I of this notice, which were entered, or withdrawn from warehouse, for consumption on or after December 1, 2023, the date of publication of the Preliminary Determination in the Federal Register . These suspension of liquidation instructions will remain in effect until further notice.
Pursuant to section 735(c)(1)(B)(ii) of the Act and 19 CFR 351.210(d), upon the publication of this notice, we will instruct CBP to require a cash deposit for estimated antidumping duties for such entries as follows: (1) the cash deposit rate for the respondents listed in the table above is the company-specific estimated weighted-average dumping margins listed for the respondents in the table; (2) if the exporter is not a respondent listed in the table above, but the producer is, then the cash deposit rate is the company-specific estimated weighted-average dumping margins listed for the producer of the subject merchandise in the table above; and (3) the cash deposit rate for all other producers and exporters is the all-others estimated weighted-average dumping margins listed in the table above.

U.S. International Trade Commission Notification
In accordance with section 735(d) of the Act, Commerce will notify the U.S. International Trade Commission (ITC) of its final affirmative determination of sales at LTFV. Because Commerce's final determination is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports or sales (or the likelihood of sales) for importation of brass rod no later than 45 days after this final determination. If the ITC determines that such injury does not exist, this proceeding will be terminated, all cash deposits posted will be refunded, and suspension of liquidation will be lifted. If the ITC determines that such injury does exist, Commerce will issue an antidumping duty order directing CBP to assess, upon further instruction by Commerce, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation, as discussed in the “Continuation of Suspension of Liquidation” section above.

Administrative Protective Order
This notice serves as the only reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a sanctionable violation.

Notification to Interested Parties
This final determination and notice are issued and published in accordance with sections 735(d) and 777(i) of the Act and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I

Scope of the Investigation
The products covered by this investigation are brass rod and bar (brass rod), which is defined as leaded, low-lead, and no-lead solid brass made from alloys such as, but not limited to the following alloys classified under the Unified Numbering System (UNS) as C27450, C27451, C27460, C34500, C35000, C35300, C35330, C36000, C36300, C37000, C37700, C48500, C67300, C67600, and C69300, and their international equivalents.
The brass rod subject to this investigation has an actual cross-section or outside diameter greater than 0.25 inches but less than or equal to 12 inches. Brass rod cross-sections may be round, hexagonal, square, or octagonal shapes as well as special profiles ( e.g., angles, shapes), including hollow profiles.
Standard leaded brass rod covered by the scope contains, by weight, 57.0-65.0 percent copper; 0.5-3.0 percent lead; no more than 1.3 percent iron; and at least 15 percent zinc. No-lead or low-lead brass rod covered by the scope contains by weight 59.0-76.0 percent copper; 0-1.5 percent lead; no more than 0.35 percent iron; and at least 15 percent zinc. Brass rod may also include other chemical elements ( e.g., nickel, phosphorous, silicon, tin, etc. ).
Brass rod may be in straight lengths or coils. Brass rod covered by this investigation may be finished or unfinished, and may or may not be heated, extruded, pickled, or cold-drawn. Brass rod may be produced in accordance with ASTM B16, ASTM B124, ASTM B981, ASTM B371, ASTM B453, ASTM B21, ASTM B138, and ASTM B927, but such conformity to an ASTM standard is not required for the merchandise to be included within the scope.
Excluded from the scope of this investigation is brass ingot, which is a casting of unwrought metal unsuitable for conversion into brass rod without remelting, that contains, by weight, at least 57.0 percent copper and 15.0 percent zinc.
The merchandise covered by this investigation is currently classifiable under subheadings 7407.21.9000, 7407.21.7000, and 7407.21.1500 of the Harmonized Tariff Schedule of the United States (HTSUS). Products subject to the scope may also enter under HTSUS subheadings 7403.21.0000, 7407.21.3000, and 7407.21.5000. The HTSUS subheadings and UNS alloy designations are provided for convenience and customs purposes. The written description of the scope of the investigation is dispositive.

Appendix II

List of Topics Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Period of Investigation
IV. Scope of the Investigation
V. Changes Since the Preliminary Determination
VI. Discussion of the Issues
Comment 1: Imputed U.S. Expenses
Comment 2: General, Administrative, and Financial Expense Ratios
Comment 3: Financial Expense Offset
VII. Recommendation
DEPARTMENT OF COMMERCE
International Trade Administration
[A-201-858]
Brass Rod From Mexico: Final Affirmative Determination of Sales at Less Than Fair Value

AGENCY:
Enforcement and Compliance, International Trade Administration, Department of Commerce.

SUMMARY:
The U.S. Department of Commerce (Commerce) determines that imports of brass rod from Mexico are being, or are likely to be, sold in the United States at less than fair value (LTFV) for the period of investigation (POI) April 1, 2022, through March 31, 2023.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Frank Schmitt or Jacob Waddell, AD/CVD Operations, Office VI, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW, Washington, DC 20230; telephone: (202) 482-4880 or (202) 482-1369, respectively.

SUPPLEMENTARY INFORMATION:

Background
On December 1, 2023, Commerce published in the Federal Register its Preliminary Determination in the LTFV investigation of brass rod from Mexico, in which it also postponed the final determination until April 15, 2024. ^1 We invited interested parties to comment on the Preliminary Determination. ^2
^1 See Brass Rod from Mexico: Preliminary Affirmative Determination of Sales at Less Than Fair Value, Postponement of Final Determination, and Extension of Provisional Measures, 88 FR 83913 (December 1, 2023) ( Preliminary Determination ), and accompanying Preliminary Decision Memorandum.
^2 See Preliminary Determination, 88 FR at 83913.
A summary of the events that occurred since Commerce published the Preliminary Determination, as well as a full discussion of the issues raised by parties for this final determination, may be found in the Issues and Decision Memorandum. ^3 The Issues and Decisions Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at https://access.trade.gov. In addition, a complete version of the Issues and Decision Memorandum can be accessed directly at https://access.trade.gov/public/FRNoticesListLayout.aspx.
^3 See Memorandum, “Decision Memorandum for the Final Affirmative Determination of Sales at Less Than Fair Value in the Investigation of Brass Rod from Mexico,” dated concurrently with, and hereby adopted by, this notice (Issues and Decision Memorandum).

Scope of the Investigation
The product covered by this investigation is brass rod from Mexico. For a complete description of the scope of this investigation, see Appendix I.

Scope Comments
During this investigation, Commerce received scope comments from parties. Commerce issued a Preliminary Scope Decision Memorandum to address these comments and set aside a period for parties to address scope issues in scope-specific case and rebuttal briefs. ^4 We did not receive timely comments from any interested parties on the Preliminary Scope Decision Memorandum. Thus, we did not make any changes to the scope of the investigation from the scope published in the Preliminary Determination, as noted in Appendix I. ^5
^4 See Memorandum, “Preliminary Scope Decision Memorandum,” dated September 25, 2023 (Preliminary Scope Decision Memorandum).
^5 See Brass Rod from India: Final Affirmative Countervailing Duty Determination, 88 FR 87407 (December 18, 2023).

Verification
Commerce verified the sales and cost information submitted by Industrias Unidas S.A. de C.V. (IUSA) for use in our final determination, consistent with section 782(i) of the Tariff Act of 1930, as amended (the Act). We used standard verification procedures, including an examination of relevant sales and accounting records, and original source documents provided by IUSA. ^6 `
^6 See Memoranda, “Verification of Sales Response of Industrias Unidas S.A. de C.V.,” dated February 15, 2024; “Verification of the Constructed Export Price Sales Response of Industrias Unidas S.A. de C.V.,” dated February 15, 2024; and “Verification of the Cost Response of Industrias S.A. de C.V.,” dated February 16, 2024.

Analysis of Comments Received
All issues raised in the case and rebuttal briefs submitted by interested parties in this investigation are addressed in the Issues and Decision Memorandum. A list of the issues addressed in the Issues and Decision Memorandum is attached to this notice as Appendix II.

Changes Since the Preliminary Determination
We made certain changes to the margin calculations for IUSA since the Preliminary Determination. For a discussion of these changes, see the Issues and Decision Memorandum.

All-Others Rate
Section 735(c)(5)(A) of the Act provides that the estimated weighted-average dumping margin for all other producers and exporters not individually investigated shall be equal to the weighted average of the estimated weighted-average dumping margins established for individually investigated exporters and producers, excluding rates that are zero, de minimis, or determined entirely under section 776 of the Act, i.e., facts otherwise available.
In this investigation, Commerce assigned a rate to ALEAMEX S.A. de C.V. based entirely on facts available. Therefore, the only rate that is not zero, de minimis, or based entirely on facts otherwise available is the rate calculated for IUSA. Consequently, Commerce assigned the estimated weighted-average dumping margin calculated for IUSA to all other producers and exporters of the merchandise under consideration, pursuant to section 735(c)(5)(A) of the Act.

Final Determination
Commerce determines that the following estimated weighted-average dumping margins exist:
Exporter/producer | Weighted-average dumping margin (percent)
Industrias Unidas S.A. de C.V | 6.51
ALEAMEX S.A. de C.V | 29.43
All Others | 6.51

Disclosure
Commerce intends to disclose the calculations performed in connection with this final determination to interested parties within five days of any public announcement or, if there is no public announcement, within five days of the date of publication of this notice in the Federal Register , in accordance with 19 CFR 351.224(b).

Continuation Suspension of Liquidation
In accordance with section 735(c)(1)(B) of the Act, Commerce will instruct U.S. Customs and Border Protection (CBP) to suspend liquidation of all entries of subject merchandise, as described in Appendix I of this notice, which were entered, or withdrawn from warehouse, for consumption on or after December 1, 2023, the date of publication of the Preliminary Determination in the Federal Register . These suspension of liquidation instructions will remain in effect until further notice.
Pursuant to section 735(c)(1)(B)(ii) of the Act and 19 CFR 351.210(d), upon publication of this notice, we will instruct CBP to require a cash deposit equal for estimated antidumping duties for such entities as follows: (1) the cash deposit rate for the respondents listed in the table above is the company-specific estimated weighted-average dumping margin listed for the respondent in the table; (2) if the exporter is not a respondent identified in the table above, but the producer is, then the cash deposit rate is the company-specific estimated weighted-average dumping margin listed for the producer of the subject merchandise in the table above; and (3) the cash deposit rate for all other producers and exporters is the all-others estimated weighted-average dumping margin listed in the table above.

U.S. International Trade Commission Notification
In accordance with section 735(d) of the Act, Commerce will notify the U.S. International Trade Commission (ITC) of this final affirmative determination of sales at LTFV. Because Commerce's final determination is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports or sales (or the likelihood of sales) for importation of brass rod no later than 45 days after this final determination. If the ITC determines that such injury does not exist, this proceeding will be terminated, all cash deposits posted will be refunded, and suspension of liquidation will be lifted. If the ITC determines that such injury does exist, Commerce will issue an antidumping duty order directing CBP to assess, upon further instruction by Commerce, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation, as discussed in the “Continuation of Suspension of Liquidation” section above.

Administrative Protective Order
This notice serves as the only reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.

Notification to Interested Parties
This final determination and this notice are issued and published pursuant to sections 735(d) and 777(i) of the Act and 19 CFR 351.210(c).
Dated: April 15, 2024.
Ryan Majerus,

Deputy Assistant Secretary for Policy and Negotiations, performing the non-exclusive functions and duties of the Assistant Secretary for Enforcement and Compliance.

Appendix I

Scope of the Investigation
The products covered by this investigation are brass rod and bar (brass rod), which is defined as leaded, low-lead, and no-lead solid brass made from alloys such as, but not limited to the following alloys classified under the Unified Numbering System (UNS) as C27450, C27451, C27460, C34500, C35000, C35300, C35330, C36000, C36300, C37000, C37700, C48500, C67300, C67600, and C69300, and their international equivalents.
The brass rod subject to this investigation has an actual cross-section or outside diameter greater than 0.25 inches but less than or equal to 12 inches. Brass rod cross-sections may be round, hexagonal, square, or octagonal shapes as well as special profiles ( e.g., angles, shapes), including hollow profiles.
Standard leaded brass rod covered by the scope contains, by weight, 57.0-65.0 percent copper; 0.5-3.0 percent lead; no more than 1.3 percent iron; and at least 15 percent zinc. No-lead or low-lead brass rod covered by the scope contains by weight 59.0-76.0 percent copper; 0-1.5 percent lead; no more than 0.35 percent iron; and at least 15 percent zinc. Brass rod may also include other chemical elements ( e.g., nickel, phosphorous, silicon, tin, etc.).
Brass rod may be in straight lengths or coils. Brass rod covered by this investigation may be finished or unfinished, and may or may not be heated, extruded, pickled, or cold-drawn. Brass rod may be produced in accordance with ASTM B16, ASTM B124, ASTM B981, ASTM B371, ASTM B453, ASTM B21, ASTM B138, and ASTM B927, but such conformity to an ASTM standard is not required for the merchandise to be included within the scope.
Excluded from the scope of this investigation is brass ingot, which is a casting of unwrought metal unsuitable for conversion into brass rod without remelting, that contains, by weight, at least 57.0 percent copper and 15.0 percent zinc.
The merchandise covered by this investigation is currently classifiable under subheadings 7407.21.9000, 7407.21.7000, and 7407.21.1500 of the Harmonized Tariff Schedule of the United States (HTSUS). Products subject to the scope may also enter under HTSUS subheadings 7403.21.0000, 7407.21.3000, and 7407.21.5000. The HTSUS subheadings and UNS alloy designations are provided for convenience and customs purposes. The written description of the scope of the investigation is dispositive.

Appendix II

Topic Discussed in the Issues and Decision Memorandum
I. Summary
II. Background
III. Period of Investigation
IV. Scope of the Investigation
V. Changes Since the Preliminary Determination
VI. Application of Facts Available and AFA
VII. Discussion of the Issues
Comment 1: Date of Sale in the Comparison Market
Comment 2: Freight Expenses in the U.S. Market
VIII. Recommendation
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
Agency Information Collection Activities; Submission to the Office of Management and Budget (OMB) for Review and Approval; Comment Request; Highly Migratory Species (HMS) Scientific Research Permits, Exempted Fishing Permits, Letters of Acknowledgement, Display Permits, and Shark Research Fishery Permits
The Department of Commerce will submit the following information collection request to the Office of Management and Budget (OMB) for review and clearance in accordance with the Paperwork Reduction Act of 1995, on or after the date of publication of this notice. We invite the general public and other Federal agencies to comment on proposed, and continuing information collections, which helps us assess the impact of our information collection requirements and minimize the public's reporting burden. Public comments were previously requested via the Federal Register on December 12, 2023, during a 60-day comment period. This notice allows for an additional 30 days for public comments.
Agency: National Oceanic and Atmospheric Administration (NOAA), Commerce.
Title: Highly Migratory Species (HMS) Scientific Research Permits, Exempted Fishing Permits, Letters of Acknowledgement, Display Permits, and Shark Research Fishery Permits.
OMB Control Number: 0648-0471.
Form Number(s): None.
Type of Request: Renewal [request for extension of a currently approved information collection].
Number of Respondents: 57 unique respondents.
Average Hours per Response: 2 hours for a scientific research plan; 40 minutes for an application for an EFP, display permit, SRP, LOA, or shark research fishery permit; 1 hour for an interim report; 12 minutes for an annual fishing report; 15 minutes for an application for an amendment; 5 minutes for notification of departure phone calls to NMFS Enforcement; 10 minutes for calls to request and observer; and 2 minutes for “no-catch” reports.
Burden Hours: 226.
Needs and Uses: Exempted fishing permits (EFPs), scientific research permits (SRPs), display permits, letters of acknowledgment (LOAs), and shark research fishery permits are issued under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (Magnuson-Stevens Act) (16 U.S.C. 1801 et seq. ) and/or the Atlantic Tunas Convention Act (ATCA) (16 U.S.C. 971 et seq. ). Issuance of EFPs and related permits is necessary for the collection of Atlantic Highly Migratory Species (HMS) for public display and scientific research that requires exemption from regulations ( e.g., seasons, prohibited species, authorized gear, minimum sizes) that otherwise may prohibit such collection. Display permits are issued for the collection of HMS for the purpose of public display, and a limited number of shark research fishery permits are issued for the collection of fishery-dependent data for future stock assessments and cooperative research with commercial fishermen to meet the shark research objectives of the Agency.
Regulations at 50 CFR 600.745 and 635.32 govern scientific research activity, exempted fishing, and exempted educational activities with respect to Atlantic HMS. Since the Magnuson-Stevens Act does not include scientific research within the definition of “fishing,” scientific research is exempt from this statute, and NMFS does not issue EFPs for bona fide research activities ( e.g., research conducted from a research vessel and not a commercial or recreational fishing vessel) involving species that are only regulated under the Magnuson-Stevens Act ( e.g., most species of sharks) and not under ATCA. NMFS requests copies of scientific research plans for these activities and indicates concurrence by issuing a LOA to researchers to indicate that the proposed activity meets the definition of scientific research and is therefore exempt from regulation.
Scientific research is not exempt from regulation under ATCA. NMFS issues SRPs for collection of species managed under this statute ( i.e., tunas, swordfish, billfish, and some shark species), which authorize researchers to collect Atlantic HMS from bona fide research vessels ( e.g., NMFS or university research vessel). NMFS will issue an EFP when research/collection involving such species occurs from commercial or recreational fishing platforms.
To regulate these fishing activities, NMFS needs information to determine the justification for granting an EFP, LOA, SRP, display, or shark research fishery permit. The application requirements are detailed at 50 CFR 600.745(b)(2). Interim, annual, and no-catch/fishing reports must also be submitted to the Atlantic HMS Management Division within NMFS new EFP online portal or emailed. The authority for NMFS requiring this information is found at 50 CFR 635.32.
Affected Public: Businesses or other for-profit organizations (vessel owners or aquariums); Not-for-profit institutions (academic researchers); State, Local, or Tribal governments (state agency researchers); Federal government (federal agency researchers).
Frequency: Permit applications, scientific research plans, and annual reports are submitted annually; interim and no catch reports are submitted monthly; departure notifications are submitted for each trip; permit amendment applications are submitted as needed. Interim reports are submitted via our new EFP online portal or emailed, while annual reports are created in our new EFP online portal or emailed.
Respondent's Obligation: Mandatory.
Legal Authority: Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. 1801 et seq. ), and the Atlantic Tunas Convention Act of 1975 (16 U.S.C. 971 et seq. ).
This information collection request may be viewed at reginfo.gov. Follow the instructions to view Department of Commerce collections currently under review by OMB.
Written comments and recommendations for the proposed information collection should be submitted within 30 days of the publication of this notice on the following website www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function and entering either the title of the collection or the OMB Control Number 0648-0471.
Sheleen Dumas,

Department PRA Clearance Officer, Office of the Under Secretary for Economic Affairs, Commerce Department.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
[RTID 0648-XD797]
Taking and Importing Marine Mammals; Taking Marine Mammals Incidental to Geophysical Surveys Related to Oil and Gas Activities in the Gulf of Mexico

AGENCY:
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.

ACTION:
Notice; issuance of Letter of Authorization.

SUMMARY:
In accordance with the Marine Mammal Protection Act (MMPA), as amended, its implementing regulations, and NMFS' MMPA Regulations for Taking Marine Mammals Incidental to Geophysical Surveys Related to Oil and Gas Activities in the Gulf of Mexico, notification is hereby given that a Letter of Authorization (LOA) has been issued to bp Exploration and Production Inc. (bp) for the take of marine mammals incidental to geophysical survey activity in the Gulf of Mexico.

DATES:
The LOA is effective from April 27, 2024 through September 15, 2024.

ADDRESSES:
The LOA, LOA request, and supporting documentation are available online at: https://www.fisheries.noaa.gov/action/incidental-take-authorization-oil-and-gas-industry-geophysical-survey-activity-gulf-mexico. In case of problems accessing these documents, please call the contact listed below (see FOR FURTHER INFORMATION CONTACT ).

FOR FURTHER INFORMATION CONTACT:
Jenna Harlacher, Office of Protected Resources, NMFS, (301) 427-8401.

SUPPLEMENTARY INFORMATION:

Background
Sections 101(a)(5)(A) and (D) of the MMPA (16 U.S.C. 1361 et seq. ) direct the Secretary of Commerce to allow, upon request, the incidental, but not intentional, taking of small numbers of marine mammals by U.S. citizens who engage in a specified activity (other than commercial fishing) within a specified geographical region if certain findings are made and either regulations are issued or, if the taking is limited to harassment, a notice of a proposed authorization is provided to the public for review.
An authorization for incidental takings shall be granted if NMFS finds that the taking will have a negligible impact on the species or stock(s), will not have an unmitigable adverse impact on the availability of the species or stock(s) for subsistence uses (where relevant), and if the permissible methods of taking and requirements pertaining to the mitigation, monitoring and reporting of such takings are set forth. NMFS has defined “negligible impact” in 50 CFR 216.103 as an impact resulting from the specified activity that cannot be reasonably expected to, and is not reasonably likely to, adversely affect the species or stock through effects on annual rates of recruitment or survival.
Except with respect to certain activities not pertinent here, the MMPA defines “harassment” as: any act of pursuit, torment, or annoyance which: (i) has the potential to injure a marine mammal or marine mammal stock in the wild (Level A harassment); or (ii) has the potential to disturb a marine mammal or marine mammal stock in the wild by causing disruption of behavioral patterns, including, but not limited to, migration, breathing, nursing, breeding, feeding, or sheltering (Level B harassment).
On January 19, 2021, we issued a final rule with regulations to govern the unintentional taking of marine mammals incidental to geophysical survey activities conducted by oil and gas industry operators, and those persons authorized to conduct activities on their behalf (collectively “industry operators”), in U.S. waters of the Gulf of Mexico (GOM) over the course of 5 years (86 FR 5322). The rule was based on our findings that the total taking from the specified activities over the 5-year period will have a negligible impact on the affected species or stock(s) of marine mammals and will not have an unmitigable adverse impact on the availability of those species or stocks for subsistence uses. The rule became effective on April 19, 2021.
Our regulations at 50 CFR 217.180 et seq. allow for the issuance of LOAs to industry operators for the incidental take of marine mammals during geophysical survey activities and prescribe the permissible methods of taking and other means of effecting the least practicable adverse impact on marine mammal species or stocks and their habitat (often referred to as mitigation), as well as requirements pertaining to the monitoring and reporting of such taking. Under 50 CFR 217.186(e), issuance of an LOA shall be based on a determination that the level of taking will be consistent with the findings made for the total taking allowable under these regulations and a determination that the amount of take authorized under the LOA is of no more than small numbers.

Summary of Request and Analysis
Bp plans to conduct a three-dimensional (3D) ocean bottom node (OBN) and distributed acoustic sensing (DAS) survey in the Atlantis protraction area. Approximate water depths of the survey area range from 1,295-2,346 meters (m). See section 1.1 of the LOA application for a map of the area.
Consistent with the preamble to the final rule, the survey effort proposed by bp in its LOA request was used to develop LOA-specific take estimates based on the acoustic exposure modeling results described in the preamble (86 FR 5398, January 19, 2021). In order to generate the appropriate take numbers for authorization, the following information was considered: (1) survey type; (2) location (by modeling zone ^1 ); (3) number of days; and (4) season. ^2 The acoustic exposure modeling performed in support of the rule provides 24-hour exposure estimates for each species, specific to each modeled survey type in each zone and season.
^1 For purposes of acoustic exposure modeling, the GOM was divided into seven zones. Zone 1 is not included in the geographic scope of the rule.
^2 For purposes of acoustic exposure modeling, seasons include winter (December-March) and summer (April-November).
No 3D OBN or DAS surveys were included in the modeled survey types, and use of existing proxies ( i.e., two-dimensional (2D), 3D narrow-azimuth (NAZ), 3D wide-azimuth (WAZ), Coil) is generally conservative for use in evaluation of 3D OBN and DAS survey effort, largely due to the greater area covered by the modeled proxies. Summary descriptions of these modeled survey geometries are available in the preamble to the proposed rule (83 FR 29220, June 22, 2018). Coil was selected as the best available proxy survey type in this case because the spatial coverage of the planned survey is most similar to the coil survey pattern.
The planned 3D OBN and DAS surveys will use the same seismic source and are thus conducted at the same time. This will involve two source vessels. The coil survey pattern was assumed to cover approximately 144 kilometers squared (km ^2 ) per day (compared with approximately 795 km ^2 , 199 km ^2 , and 845 km ^2 per day for the 2D, 3D NAZ, and 3D WAZ survey patterns, respectively).Among the different parameters of the modeled survey patterns ( e.g., area covered, line spacing, number of sources, shot interval, total simulated pulses), NMFS considers area covered to be influential on daily modeled exposures exceeding Level B harassment criteria. Although bp is not proposing to perform a survey using the coil geometry, its planned 3D OBN and DAS survey is expected to cover approximately 15 km ^2 per day, meaning that the coil proxy is most representative of the total survey effort planned by bp in terms of predicted Level B harassment exposures. In addition, all available acoustic exposure modeling results assume use of a 72-element, 8,000 cubic inches (in ^3 ) array. Thus, estimated take numbers for this LOA are considered conservative due to differences in both the airgun array (32 elements, 5,110 in ^3 ) and daily survey area planned by bp, as compared to those modeled for the rule.
The survey will include 60 days of sound source operation. The survey plan includes 30 days within Zone 5 and 30 days within Zone 7. The survey would occur in summer months only. Therefore, the take estimates for each species are based on summer take estimates.
For some species, take estimates based solely on the modeling yielded results that are not realistically likely to occur when considered in light of other relevant information available during the rulemaking process regarding marine mammal occurrence in the GOM. The approach used in the acoustic exposure modeling, in which seven modeling zones were defined over the U.S. GOM, necessarily averages fine-scale information about marine mammal distribution over the large area of each modeling zone. This can result in unrealistic projections regarding the likelihood of encountering particularly rare species and/or species not expected to occur outside particular habitats. Thus, although the modeling conducted for the rule is a natural starting point for estimating take, our rule acknowledged that other information could be considered ( e.g., 86 FR 5322, January 19, 2021), discussing the need to provide flexibility and make efficient use of previous public and agency review of other information and identifying that additional public review is not necessary unless the model or inputs used differ substantively from those that were previously reviewed by NMFS and the public). For this survey, NMFS has other relevant information reviewed during the rulemaking that indicates use of the acoustic exposure modeling to generate a take estimate for Rice's whales (formerly known as GOM Bryde's whales) ^3 and killer whales produces results inconsistent with what is known regarding their occurrence in the GOM. Accordingly, we have adjusted the calculated take estimates for those species as described below.
^3 The final rule refers to the GOM Bryde's whale ( Balaenoptera edeni ). These whales were subsequently described as a new species, Rice's whale ( Balaenoptera ricei ) (Rosel et al., 2021).
NMFS' final rule described a “core habitat area” for Rice's whales located in the northeastern GOM in waters between 100 and 400 m depth along the continental shelf break (Rosel et al., 2016). However, whaling records suggest that Rice's whales historically had a broader distribution within similar habitat parameters throughout the GOM (Reeves et al., 2011; Rosel and Wilcox, 2014). In addition, habitat-based density modeling has identified similar habitat ( i.e., approximately 100-400 m water depths along the continental shelf break) (Roberts et al., 2016; Garrison et al., 2023), and Rice's whales have been detected within this depth band throughout the GOM (Soldevilla et al., 2022, 2024). See discussion provided at, e.g., 83 FR 29228, June 22, 2018; 83 FR 29280, June 22, 2018; 86 FR 5418, January 19, 2021.
Although Rice's whales may occur outside of the core habitat area, we expect that any such occurrence would be limited to the narrow band of suitable habitat described above ( i.e., 100-400 m) and that, based on the few available records, these occurrences would be rare. Bp's planned activities will occur in water depths of approximately 1,295- 2,347 m in the central GOM. Thus, NMFS does not expect there to be the reasonable potential for take of Rice's whale in association with this survey and, accordingly, does not authorize take of Rice's whale through this LOA.
Killer whales are the most rarely encountered species in the GOM, typically in deep waters of the central GOM (Roberts et al., 2015; Maze-Foley and Mullin, 2006). As discussed in the final rule, the density models produced by Roberts et al. (2016) represent the output of models derived from multi-year observations and associated environmental parameters that incorporate corrections for detection bias. However, in the case of killer whales, the model is informed by few data, as indicated by the coefficient of variation associated with the abundance predicted by the model (0.41, the second-highest of any GOM species model; Roberts et al., 2016). The model's authors noted the expected non-uniform distribution of this rarely-encountered species (as discussed above) and expressed that, due to the limited data available to inform the model, it “should be viewed cautiously” (Roberts et al., 2015).
NOAA surveys in the GOM from 1992 to 2009 reported only 16 sightings of killer whales, with an additional 3 encounters during more recent survey effort from 2017 to 2018 (Waring et al., 2013; https://www.boem.gov/gommapps ). Two other species were also observed on fewer than 20 occasions during the 1992-2009 NOAA surveys (Fraser's dolphin and false killer whale). ^4 However, observational data collected by protected species observers (PSO) on industry geophysical survey vessels from 2002 to 2015 distinguish the killer whale in terms of rarity. During this period, killer whales were encountered on only 10 occasions, whereas the next most rarely encountered species (Fraser's dolphin) was recorded on 69 occasions (Barkaszi and Kelly, 2019). The false killer whale and pygmy killer whale were the next most rarely encountered species, with 110 records each. The killer whale was the species with the lowest detection frequency during each period over which PSO data were synthesized (2002-2008 and 2009-2015). This information qualitatively informed our rulemaking process, as discussed at 86 FR 5322 and 86 FR 5334 (January 19, 2021), and similarly informs our analysis here.
^4 However, note that these species have been observed over a greater range of water depths in the GOM than have killer whales.
The rarity of encounter during seismic surveys is not likely to be the product of high bias on the probability of detection. Unlike certain cryptic species with high detection bias, such as Kogia spp. or beaked whales, or deep-diving species with high availability bias, such as beaked whales or sperm whales, killer whales are typically available for detection when present and are easily observed. Roberts et al. (2015) stated that availability is not a major factor affecting detectability of killer whales from shipboard surveys, as they are not a particularly long-diving species. Baird et al. (2005) reported that mean dive durations for 41 fish-eating killer whales for dives greater than or equal to 1 minute in duration was 2.3-2.4 minutes, and Hooker et al. (2012) reported that killer whales spent 78 percent of their time at depths between 0 and 10 m. Similarly, Kvadsheim et al. (2012) reported data from a study of 4 killer whales, noting that the whales performed 20 times as many dives 1-30 m in depth than to deeper waters, with an average depth during those most common dives of approximately 3 m.
In summary, killer whales are the most rarely encountered species in the GOM and typically occur only in particularly deep water. This survey would take place in deep waters that would overlap with depths in which killer whales typically occur. While this information is reflected through the density model informing the acoustic exposure modeling results, there is relatively high uncertainty associated with the model for this species, and the acoustic exposure modeling applies mean distribution data over areas where the species is in fact less likely to occur. In addition, as noted above in relation to the general take estimation methodology, the assumed proxy source (72-element, 8,000-in ^3 array) results in a significant overestimate of the actual potential for take to occur. NMFS' determination in reflection of the information discussed above, which informed the final rule, is that use of the generic acoustic exposure modeling results for killer whales will generally result in estimated take numbers that are inconsistent with the assumptions made in the rule regarding expected killer whale take (86 FR 5322, January 19, 2021; 86 FR 5403, January 19, 2021).
In past authorizations, NMFS has often addressed situations involving the low likelihood of encountering a rare species such as killer whales in the GOM through authorization of take of a single group of average size ( i.e., representing a single potential encounter). See 83 FR 63268, December 7, 2018; 86 FR 29090, May 28, 2021; 85 FR 55645, September 9, 2020. For the reasons expressed above, NMFS determined that a single encounter of killer whales is more likely than the model-generated estimates and has authorized take associated with a single group encounter ( i.e., up to 7 animals).
Based on the results of our analysis, NMFS has determined that the level of taking authorized through the LOA is consistent with the findings made for the total taking allowable under the regulations for the affected species or stocks of marine mammals. See Table 1 in this notice and Table 9 of the rule (86 FR 5322, January 19, 2021).

Small Numbers Determination
Under the GOM rule, NMFS may not authorize incidental take of marine mammals in an LOA if it will exceed “small numbers.” In short, when an acceptable estimate of the individual marine mammals taken is available, if the estimated number of individual animals taken is up to, but not greater than, one-third of the best available abundance estimate, NMFS will determine that the numbers of marine mammals taken of a species or stock are small. For more information please see NMFS' discussion of the MMPA's small numbers requirement provided in the final rule (86 FR 5438, January 19, 2021).
The take numbers for authorization are determined as described above in the Summary of Request and Analysis section. Subsequently, the total incidents of harassment for each species are multiplied by scalar ratios to produce a derived product that better reflects the number of individuals likely to be taken within a survey (as compared to the total number of instances of take), accounting for the likelihood that some individual marine mammals may be taken on more than 1 day (see 86 FR 5404, January 19, 2021). The output of this scaling, where appropriate, is incorporated into adjusted total take estimates that are the basis for NMFS' small numbers determinations, as depicted in table 1.
This product is used by NMFS in making the necessary small numbers determinations through comparison with the best available abundance estimates (see discussion at 86 FR 5322, January 19, 2021; 86 FR 5391, January 19, 2021). For this comparison, NMFS' approach is to use the maximum theoretical population, determined through review of current stock assessment reports (SAR; https://www.fisheries.noaa.gov/national/marine-mammal-protection/marine-mammal-stock-assessment-reports-species-stock ) and model-predicted abundance information ( https://seamap.env.duke.edu/models/Duke/GOM/ ). For the latter, for taxa where a density surface model could be produced, we use the maximum mean seasonal ( i.e., 3-month) abundance prediction for purposes of comparison as a precautionary smoothing of month-to-month fluctuations and in consideration of a corresponding lack of data in the literature regarding seasonal distribution of marine mammals in the GOM. Information supporting the small numbers determinations is provided in table 1.
Table 1—Take Analysis
Species | Authorized take | Scaled take ^1 | Abundance ^2 | Percent abundance
Rice's whale | 0 | n/a | 51 | 0
Sperm whale | 932 | 394 | 2,207 | 17.9
Kogia spp. | ^3 363 | 109 | 4,373 | 3.0
Beaked whales | 4,684 | 473 | 3,768 | 12.6
Rough-toothed dolphin | 804 | 231 | 4,853 | 4.8
Bottlenose dolphin | 2,673 | 767 | 176,108 | 0.4
Clymene dolphin | 2,175 | 624 | 11,895 | 5.2
Atlantic spotted dolphin | 1,098 | 315 | 74,785 | 0.4
Pantropical spotted dolphin | 12,974 | 3,724 | 102,361 | 3.6
Spinner dolphin | 2,080 | 597 | 25,114 | 2.4
Striped dolphin | 924 | 265 | 5,229 | 5.1
Fraser's dolphin | 285 | 82 | 1,665 | 4.9
Risso's dolphin | 565 | 167 | 3,764 | 4.4
Melon-headed whale | 1,478 | 436 | 7,003 | 6.2
Pygmy killer whale | 438 | 129 | 2,126 | 4.4
False killer whale | 612 | 180 | 3,204 | 5.6
Killer whale | 7 | n/a | 267 | 2.6
Short-finned pilot whale | 346 | 102 | 1,981 | 5.2
^1 Scalar ratios were applied to “Authorized Take” values as described at 86 FR 5322 and 86 FR 5404 (January 19, 2021) to derive scaled take numbers shown here.
^2 Best abundance estimate. For most taxa, the best abundance estimate for purposes of comparison with take estimates is considered here to be the model-predicted abundance (Roberts et al., 2016). For those taxa where a density surface model predicting abundance by month was produced, the maximum mean seasonal abundance was used. For those taxa where abundance is not predicted by month, only mean annual abundance is available. For Rice's whale and the killer whale, the larger estimated SAR abundance estimate is used.
^3 Includes 23 takes by Level A harassment and 340 takes by Level B harassment. Scalar ratio is applied to takes by Level B harassment only; small numbers determination made on basis of scaled Level B harassment take plus authorized Level A harassment take.
Based on the analysis contained herein of bp's proposed survey activity described in its LOA application and the anticipated take of marine mammals, NMFS finds that small numbers of marine mammals will be taken relative to the affected species or stock sizes ( i.e., less than one-third of the best available abundance estimate) and therefore the taking is of no more than small numbers.

Authorization
NMFS has determined that the level of taking for this LOA request is consistent with the findings made for the total taking allowable under the incidental take regulations and that the amount of take authorized under the LOA is of no more than small numbers. Accordingly, we have issued an LOA to bp authorizing the take of marine mammals incidental to its geophysical survey activity, as described above.
Dated: April 17, 2024.
Kimberly Damon-Randall,

Director, Office of Protected Resources, National Marine Fisheries Service.
DEPARTMENT OF DEFENSE
Department of the Air Force
Notice of Intent To Prepare an Environmental Impact Statement for the Construction and Operation of the Air Force Maui Optical and Supercomputing Site Small Telescope Advanced Research Facility on the Island of Maui, Hawaíi

AGENCY:
Department of Defense, Department of the Air Force.

ACTION:
Notice of intent.

SUMMARY:
The Department of the Air Force (DAF) is issuing this notice of intent (NOI) to prepare an Environmental Impact Statement (EIS) to assess the potential environmental and socioeconomic impacts associated with the proposed construction and operation of the Air Force Maui Optical and Supercomputing Site Small Telescope Advanced Research (AMOS STAR) facility on the island of Maui, Hawaíi (the Proposed Action). DAF is the Lead Agency and has invited the Federal Aviation Administration (FAA) and the National Park Service (NPS) to participate as Cooperating Agencies in the NEPA process. The project proponent is the 15th Space Surveillance Squadron (15 SPSS), a blended asset unit with assigned personnel from the U.S. Space Force Space Operations Command and the Air Force Research Laboratory (AFRL).

DATES:
A public scoping period of 45 days will start on the date of publication of this NOI in the Federal Register . Through the scoping process, the DAF is inviting input regarding potential alternatives, information, and analysis relevant to the Proposed Action. The DAF will be conducting analysis and consultation to comply with Section 106 of the National Historic Preservation Act (NHPA) and is soliciting comments and concerns regarding the effect of the project on historic properties. Comments will be accepted at any time during the environmental impact analysis process; however, to ensure the DAF has sufficient time to consider public scoping comments during preparation of the Draft EIS, please submit comments within the 45-day scoping period.
The Notice of Availability (NOA) of the Draft EIS is anticipated to be published in early 2025; and the NOA of the Final EIS is anticipated in early 2026. A decision could be made no earlier than 30 days after the Final EIS.
The DAF invites the public, stakeholders, and other interested parties to attend one or more of three scoping meetings to be held at community centers in Kahului, Pukalani, and Kīhei on Maui on the evenings of May 13, 14 and 15, 2024, from 6:00 p.m. to 9:00 p.m. The meeting on May 13 will be held at Kahului Community Center, 275 Uhu St., Kahului, Maui, HI, 96732, the meeting on May 14 will be held at Mayor H. Tavares Community Center, 91 Pukalani St., Pukalani, Maui, HI 96768, and the meeting on May 15 will be held at Kīhei Community Center, 303 E. Lipoa St., Kīhei, Maui, HI 96753. The meetings will provide an opportunity for attendees to learn more about the proposed AMOS STAR facility and the scope of the EIS. Project team members will be available to answer questions, and exhibits will be on view starting at 6:00 p.m. A presentation about the proposed AMOS STAR facility will be shown at 6:30 p.m. Attendees will have an opportunity to provide oral comments from approximately 7:00 p.m. to 9:00 p.m. Written comments are encouraged and can be submitted at any time during the 45-day scoping period.

ADDRESSES:
The AMOS STAR EIS website at www.amosstareis.com can be used to submit comments on the scope of the EIS and comments regarding the effect of the project on historic properties. Alternatively, comments can be submitted by email to amosstareis@tetratech.com or by U.S. Mail to AMOS STAR EIS c/o Tetra Tech, 1230 Columbia Street, Suite 1000, San Diego, CA 92101. For other AMOS STAR facility inquiries, or for assistance under the Americans with Disabilities Act, please call Ms. Emily Peacock, USSF Public Affairs, Space Base Delta 1 at (774) 545-0152 or email emily.peacock@spaceforce.mil.

SUPPLEMENTARY INFORMATION:
The purpose of the Proposed Action is to provide dedicated satellite tracking and communication capability to allow the characterization, cataloging, and tracking of objects in space and to enable advanced research to expand the DAF's understanding of objects in the Pacific Theater. The DAF needs to expand the capabilities of AMOS STAR regarding space domain awareness. To expand this capability, additional telescopes need to be located at a site where there are favorable viewing conditions for observing objects in space in the Pacific Theater. Additionally, the 15 SPSS must be able to readily provide operational control and support to the additional telescopes.
The EIS will analyze the potential impacts of constructing and operating the AMOS STAR facility on 0.87 acres of a developed site adjacent to the Haleakalā Observatory and the 15 SPSS Maui Space Surveillance Complex (MSSC). The proposed facility of telescopes and an optics lab would be connected to and largely operated by existing high-speed fiber optic links and microwave transmissions from the AFRL and 15 SPSS facilities from the MSSC AEOS control room, and would require installation of utilities, additional fiber optic links, paved access and parking facilities, surface water management measures, and other site improvements. Electricity would be supplied from the island-wide grid; during power grid interruptions, power would be supplied by the diesel generator located on the south side of MSSC approximately 200 feet northeast of the AMOS STAR facility site.
The Proposed Action (Alternative 1) would consist of six telescopes enclosed in ground-mounted domes, one rooftop-mounted domed telescope, and use of an existing building for communication equipment and an optics laboratory for the rooftop telescope. Two of the telescopes under the Proposed Action would have laser communication capabilities. The EIS will also evaluate Alternative 2, a reduced build out alternative as a reasonable action alternative. Alternative 2 is similar to the Proposed Action (Alternative 1); under Alternative 2, only the 6 ground-mounted telescopes would be installed, and the existing building on the site would only be used for communication equipment storage. Alternative 2 would result in less intrusion on the viewshed of the site from points downslope, and less intensive use of the overall facility. The EIS will also analyze the effects of the No Action Alternative as prescribed by the Council on Environmental Quality regulations.
To implement the proposed action, the DAF would require an Outgrant Permit from the Federal Aviation Administration (FAA) and a Special Use Permit from the National Park Service (NPS) for roadway use. A federal Coastal Zone Management Act determination will be conducted and coordinated to determine consistency of the action with the Hawaíi Coastal Management Program. Additionally, a Conservation District Use Permit would be required from the Department of Land and Natural Resources, Office of Conservation and Coastal Lands.
Key resources of concern, for which adverse impacts could occur, include cultural and historical resources, visual resources, and biological resources. Those resource areas and others will be analyzed in the EIS to determine if impacts would be significant.
Scoping and Agency Coordination: Consultation will include, but not necessarily be limited to, consultation under Section 7 of the Endangered Species Act and consultation under Section 106 of the NHPA, to include consultation with federally recognized Native Hawaiian organizations. The DAF and Cooperating Agencies will determine the scope of the analysis by soliciting comments from interested local, State, and federally elected officials and agencies, federally recognized Native Hawaiian organizations, as well as interested members of the public.
Tommy W. Lee,

Acting Air Force Federal Register Liaison Officer.
DEPARTMENT OF DEFENSE
Office of the Secretary
[Docket ID: DoD-2024-OS-0038]
Proposed Collection; Comment Request

AGENCY:
Office of the Under Secretary of Defense (Comptroller)/Chief Financial Officer, Department of Defense (DoD).

ACTION:
60-Day information collection notice.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995, the Defense Finance and Accounting Service (DFAS) announces a proposed public information collection and seeks public comment on the provisions thereof. Comments are invited on: whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the agency's estimate of the burden of the proposed information collection; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the information collection on respondents, including through the use of automated collection techniques or other forms of information technology.

DATES:
Consideration will be given to all comments received by June 21, 2024.

ADDRESSES:
You may submit comments, identified by docket number and title, by any of the following methods:
Federal eRulemaking Portal:
http://www.regulations.gov. Follow the instructions for submitting comments.
Mail: Department of Defense, Office of the Assistant to the Secretary of Defense for Privacy, Civil Liberties, and Transparency, 4800 Mark Center Drive, Mailbox #24, Suite 08D09, Alexandria, VA 22350-1700.
Instructions: All submissions received must include the agency name, docket number and title for this Federal Register document. The general policy for comments and other submissions from members of the public is to make these submissions available for public viewing on the internet at http://www.regulations.gov as they are received without change, including any personal identifiers or contact information.

FOR FURTHER INFORMATION CONTACT:
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Finance and Accounting Service, 8899 E 56th St., Indianapolis, IN 46249, ATTN: Ms. Kellen Stout, (317) 212-1801.

SUPPLEMENTARY INFORMATION:
Title; Associated Form; and OMB Number: Personal Check Cashing Agreement; DD Form 2761; OMB Control Number 0730-0005.
Needs and Uzses: The information collection requirement is necessary to meet the Department of Defense's (DoD) requirement for cashing personal checks overseas and afloat by DoD disbursing activities, as provided in 31 U.S.C. 3342. The DoD Financial Management Regulation, volume 5, provides guidance to DoD disbursing officers in the performance of this information collection. This allows the DoD disbursing officer or authorized agent the authority to offset the pay without prior notification in cases where this form has been signed subject to conditions specified within the approved procedures.
Affected Public: Individuals or households.
Annual Burden Hours: 1187.
Number of Respondents: 4748.
Responses per Respondent: 1.
Annual Responses: 4748.
Average Burden per Response: 15 minutes.
Frequency: On occasion.
The Personal Check Cashing Agreement form is designed exclusively to help the DoD disbursing offices expedite the collection process of dishonored checks. The front of the form will be completed and signed by the authorized individual requesting check cashing privileges. By signing the form, the individual is freely and voluntarily consenting to the immediate collection from their current pay, without prior notice, for the face value of any check cashed, plus any charges assessed against the government by a financial institution, in the event the check is dishonored. In the event the check is dishonored, the disbursing office will complete and certify the reverse side of the form and forward the form to the applicable payroll office for collection from the individual's current pay.
Dated: April 16, 2024.
Aaron T. Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF DEFENSE
Office of the Secretary
[Docket ID: DoD-2024-HA-0037]
Proposed Collection; Comment Request

AGENCY:
Office of the Assistant Secretary of Defense for Health Affairs (OASD(HA)), Department of Defense (DoD).

ACTION:
60-Day information collection notice.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995, the Defense Health Agency (DHA) announces a proposed public information collection and seeks public comment on the provisions thereof. Comments are invited on: whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the agency's estimate of the burden of the proposed information collection; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the information collection on respondents, including through the use of automated collection techniques or other forms of information technology.

DATES:
Consideration will be given to all comments received by June 21, 2024.

ADDRESSES:
You may submit comments, identified by docket number and title, by any of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.
Mail: Department of Defense, Office of the Assistant to the Secretary of Defense for Privacy, Civil Liberties, and Transparency, 4800 Mark Center Drive, Mailbox #24, Suite 08D09, Alexandria, VA 22350-1700.
Instructions: All submissions received must include the agency name, docket number and title for this Federal Register document. The general policy for comments and other submissions from members of the public is to make these submissions available for public viewing on the internet at http://www.regulations.gov as they are received without change, including any personal identifiers or contact information.

FOR FURTHER INFORMATION CONTACT:
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to Defense Health Agency, 7700 Arlington Blvd., Falls Church, VA 22042, Amanda Grifka, 703-681-1771.

SUPPLEMENTARY INFORMATION:
Title; Associated Form; and OMB Number: TRICARE Select Enrollment, Disenrollment, and Change Form; DD Form 3043; OMB Control Number 0720-0061.
Needs and Uses: The information collection requirement is necessary to obtain each non-active duty TRICARE beneficiary's personal information needed to: (1) Complete his/her enrollment into the TRICARE Select health plan option, (2) dis-enroll a beneficiary, or (3) change a beneficiary's enrollment information ( e.g., address, add a dependent, report other health insurance). This information is required to ensure the beneficiary's TRICARE benefits and claims are administered based on their TRICARE plan of choice. Without this new enrollment form, each non-active duty TRICARE beneficiary is automatically defaulted into direct care, limiting their health care options to beneficiaries would have no TRICARE coverage when using the TRICARE network of providers for services not available at their local military hospital or clinic.
Affected Public: Individuals or households.
Annual Burden Hours: 24,825.
Number of Respondents: 99,300.
Responses per Respondent: 1.
Annual Responses: 99,300.
Average Burden per Response: 15 minutes.
Frequency: On occasion.
Dated: April 16, 2024.
Aaron T. Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF DEFENSE
Office of the Secretary
[Docket ID: DoD-2024-OS-0035]
Proposed Collection; Comment Request

AGENCY:
Office of the Under Secretary of Defense for Intelligence and Security (OUSD(I&S)), Department of Defense (DoD).

ACTION:
60-day information collection notice.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995, the Defense Counterintelligence and Security Agency (DCSA) announces a proposed public information collection and seeks public comment on the provisions thereof. Comments are invited on: whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the agency's estimate of the burden of the proposed information collection; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the information collection on respondents, including through the use of automated collection techniques or other forms of information technology.

DATES:
Consideration will be given to all comments received by June 21, 2024.

ADDRESSES:
You may submit comments, identified by docket number and title, by any of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.
Mail: Department of Defense, Office of the Assistant to the Secretary of Defense for Privacy, Civil Liberties, and Transparency, 4800 Mark Center Drive, Mailbox #24, Suite 08D09, Alexandria, VA 22350-1700.
Instructions: All submissions received must include the agency name, docket number and title for this Federal Register document. The general policy for comments and other submissions from members of the public is to make these submissions available for public viewing on the internet at http://www.regulations.gov as they are received without change, including any personal identifiers or contact information.

FOR FURTHER INFORMATION CONTACT:
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Counterintelligence and Security Agency, 27130 Telegraph Rd., Quantico, VA, 22134, ATTN: Ms. Stepheny Fanning, (571) 305-6243.

SUPPLEMENTARY INFORMATION:
Title; Associated Form; and OMB Number: Certificate Pertaining to Foreign Interests; SF-328; OMB Control Number 0704-0579.
Needs and Uses: This information collection requirement is necessary to support the execution of 32 CFR part 117, “National Industrial Security Program (NISPOM),” dated December 21, 2020 or equivalent. Executive Order (E.O.) 12829, as amended, “National Industrial Security Program (NISP)”, section 202 (a) stipulates that the Secretary of Defense serves as the Executive Agent for inspecting and monitoring the contractors, licensees, and grantees who require or will require access to, or who store or will store classified information; and for determining eligibility for access to classified information of contractors, licensees, and grantees and their respective employees. Section 202 (e) also authorizes the Executive Agent to issue, after consultation with affected agencies, standard forms that will promote the implementation of the NISP.
Executive Order 12829 was amended by Executive Order 13691, adding the Secretary of Homeland Security as the fifth Cognizant Security Agency. Section 202 (d) of E.O. 12829 stipulates that the Secretary of Homeland security may determine the eligibility for access to Classified National Security Information of contractors, licensees and grantees and their respective employees under a designated critical infrastructure protection program, including parties to agreements with such programs. The Secretary of Homeland Security also may inspect and monitor the contractors, grantees or licensees and facilities or may enter into written agreements with the Secretary of Defense, as Executive Agent or with the office of the Director of Intelligence/Director of Central Intelligence Agency to inspect and monitor these programs in whole or in part on behalf of the Secretary of Homeland Security. The specific requirements necessary to protect classified information released to private industry are found in 32 CFR part 117, “National Industrial Security Program (NISPOM),” (Part 117) dated December 21, 2020 or equivalent; DoD Industrial Security Regulation, DoD 5220. 22-R, as amend by DoD 5220.22- NISP Volume 3, “National Industrial Security Program: Procedures for Government Activities Relating to Foreign Ownership, Control or Influence (FOCI), dated April 17, 2014. The SF 328 incorporates its usage for the NISP portion of the Classified Critical Infrastructure Protection Program as stipulated under E.O. 12829, as amended by Executive Order 13691. Revisions to the SF 328 will also incorporate its usage under the DoD's Innovation initiative through the DoD Enhanced Security Program (DESP), pursuant to section 951 of Public Law 114-328 (10 U.S.C. 1564 note). The DESP is a DoD only initiative and is not part of the NISP. Companies participating under the DESP do not require a DoD contract but are required to enter into a Memorandum of Agreement. Completion of the SF 328 and submission of supporting documentation ( e.g., company or entity charter documents, board meeting minutes, stock or securities information, descriptions of organizational structures, contracts, sales, leases and/or loan agreements and revenue documents, annual reports and income statements, etc.) is part of the eligibility determination for access to classified information and/or issuance of an Entity Eligibility Determination (also known as a Facility Security Clearance).
The National Defense Authorization Act for Fiscal Year 2020, Public Law 116-92, section 847, “Mitigating Risks Related to Foreign Ownership, Control, or Influence of Department of Defense Contractors or Subcontractors” (sec. 847), requires the Secretary for Defense to improve the process and procedures for the assessment and mitigation of risks related to FOCI of contractors and subcontractors doing business with the DoD, in conjunction with the Departments efforts to develop and implement an improved analytical framework for mitigating risk relating to ownership structure, as required by 10 U.S.C. 2509 and section 847 of Public Law 116-92. To fulfill the requirements of sec. 847, contractors and subcontractors must disclose to DCSA their beneficial ownership and whether they are under FOCI, and to update those disclosures when changes occur to information previously provided consistent with the requirements of the NISPOM. In addition, sec. 847 provides for the creation of other measures as necessary to be consistent with other relevant authorities, including the NISP.
The Small Business Innovation Research and Small Business Technology Transfer (SBIR/STTR) Extension Act of 2022, Public Law 117-183, section 4, “Foreign Risk Management” (DoD SBIR/STTR programs), requires the head of each Federal agency required to establish a SBIR or STTR program to implement a due diligence program to assess security risks presented by small business concerns seeking Federal awards. These security risks includes, among other things, foreign interested-related risks. The DoD intends to utilize the SF 328 as the basis for information collection for DoD SBIR/STTR program participants to disclose their foreign interests, and to report any future changes, as appropriate. For DoD SBIR/STTR, the DoD will use this form to collect information to conduct a risk-based due diligence review and assess security risks presented by small business concerns seeking a federally funded award through the DoD SBIR/STTR programs. The submission will be required to be submitted as part of the SBIR/STTR solicitation package, and details concerning its submission will be included in the solicitation published to perspective submitters.
The use of the SF 328 will also be required by the forthcoming Cybersecurity Maturity Model Certification (CMMC) program, which is currently in the Rulemaking process under 32 CFR part 170. The CMMC program will require CMMC Level 2 Certification Assessments be conducted by a CMMC Third Party Assessment Organization (C3PAO), accredited by the DoD approved CMMC Accreditation Body (AB). To be accredited, the CMMC AB and all C3PAOs must receive a favorable adjudication and not be subject to a level of risk from Foreign Ownership, Control, or Influence (FOCI) as determined by the CMMC Program Management Office (PMO). DCSA will conduct the FOCI assessments for the CMMC AB and C3PAOs after they are nominated by the CMMC PMO.
The multiple authorized uses of this form will create uniformity among numerous authorities responsible for the vetting or review of companies or entities for foreign interest-related risks. In addition, it will establish more consistency among industry concerning their basic information submission requirements regarding foreign interest information.
The submission of the SF-328, and supporting documentation, may be done electronically through a government approved system of record.
Affected Public: Business or other for profit; Not-for-profit institutions.
Annual Burden Hours: 104,917.
Number of Respondents: 62,950.
Responses per Respondent: 1.
Annual Responses: 62,950.
Average Burden per Response: 100 minutes.
Frequency: On occasion.
Dated: April 16, 2024.
Aaron T. Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF DEFENSE
Office of the Secretary
[Docket ID: DoD-2024-OS-0039]
Proposed Collection; Comment Request

AGENCY:
Office of the Under Secretary of Defense (Comptroller)/Chief Financial Officer, Department of Defense (DoD).

ACTION:
60-Day information collection notice.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995, the Defense Finance and Accounting Service (DFAS) announces a proposed public information collection and seeks public comment on the provisions thereof. Comments are invited on: whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the agency's estimate of the burden of the proposed information collection; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the information collection on respondents, including through the use of automated collection techniques or other forms of information technology.

DATES:
Consideration will be given to all comments received by June 21, 2024.

ADDRESSES:
You may submit comments, identified by docket number and title, by any of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.
Mail: Department of Defense, Office of the Assistant to the Secretary of Defense for Privacy, Civil Liberties, and Transparency, 4800 Mark Center Drive, Mailbox #24, Suite 08D09, Alexandria, VA 22350-1700.
Instructions: All submissions received must include the agency name, docket number and title for this Federal Register document. The general policy for comments and other submissions from members of the public is to make these submissions available for public viewing on the internet at http://www.regulations.gov as they are received without change, including any personal identifiers or contact information.

FOR FURTHER INFORMATION CONTACT:
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Finance and Accounting Service, 8899 E 56th St., Indianapolis, IN 46249, ATTN: Ms. Kellen Stout, (317) 212-1801.

SUPPLEMENTARY INFORMATION:
Title; Associated Form; and OMB Number: Request for Information Regarding Deceased Debtor, DD Form 2840; OMB Control Number 0730-0015.
Needs and Uses: The information collection requirement is necessary to obtain information on deceased debtors from probate courts. Probate courts review their records to see if an estate was established. They provide the name and address of the executor or lawyer handling the estate. From the information obtained, DFAS submits a claim against the estate for the amount due to the United States.
Affected Public: State, local, or tribal government.
Annual Burden Hours: 100.
Number of Respondents: 300.
Responses per Respondent: 1.
Annual Respondent: 300.
Average Burden per Response: 20 minutes.
Frequency: On occasion.
Dated: April 16, 2024.
Aaron T. Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF DEFENSE
Office of the Secretary
[Docket ID: DoD-2024-HA-0036]
Proposed Collection; Comment Request

AGENCY:
Office of the Assistant Secretary of Defense for Health Affairs (OASD(HA)), Department of Defense (DoD).

ACTION:
60-Day information collection notice.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995, the Defense Health Agency (DHA) announces a proposed public information collection and seeks public comment on the provisions thereof. Comments are invited on: whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; the accuracy of the agency's estimate of the burden of the proposed information collection; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the information collection on respondents, including through the use of automated collection techniques or other forms of information technology.

DATES:
Consideration will be given to all comments received by June 21, 2024.

ADDRESSES:
You may submit comments, identified by docket number and title, by any of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.
Mail: Department of Defense, Office of the Assistant to the Secretary of Defense for Privacy, Civil Liberties, and Transparency, 4800 Mark Center Drive, Mailbox #24, Suite 08D09, Alexandria, VA 22350-1700.
Instructions: All submissions received must include the agency name, docket number and title for this Federal Register document. The general policy for comments and other submissions from members of the public is to make these submissions available for public viewing on the internet at http://www.regulations.gov as they are received without change, including any personal identifiers or contact information.

FOR FURTHER INFORMATION CONTACT:
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Health Agency, 7700 Arlington Blvd., Falls Church, VA 22042, ATTN: Ms. Amanda Grifka, 703-681-1771.

SUPPLEMENTARY INFORMATION:
Title; Associated Form; and OMB Number: TRICARE Plus Enrollment and Disenrollment Forms; DD Forms 2853 and 2854; OMB Control Number 0720-0028.
Needs and Uses: These collected instruments serve as an application for enrollment and disenrollment in the Department of Defense's TRICARE Plus Health Plan established in accordance with Title 10 U.S.C. 1099. The information hereby provides the TRICARE contractors with the necessary data to determine beneficiary eligibility and to identify the selection of a health care option.
Affected Public: Individuals or households.
Annual Burder Hours: 386.
Number of Respondents: 3,305.
Responses per Respondent: 1.
Annual Responses: 3,305.
Average Burden per Response: 7 minutes.
Frequency: On occasion.
Dated: April 16, 2024.
Aaron T. Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF ENERGY
Environmental Management Site-Specific Advisory Board, Northern New Mexico

AGENCY:
Office of Environmental Management, Department of Energy.

ACTION:
Notice of open meeting.

SUMMARY:
This notice announces an in-person/virtual hybrid meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Northern New Mexico. The Federal Advisory Committee Act requires that public notice of this meeting be announced in the Federal Register .

DATES:
Wednesday, May 15, 2024; 1 to 5 p.m. MDT

ADDRESSES:
This hybrid meeting will be open to the public in person and via WebEx. To attend virtually, please contact the Northern New Mexico Citizens Advisory Board (NNMCAB) Executive Director (below) no later than 5 p.m. MDT on Friday, May 10, 2024. Fuller Lodge, 2132 Central Avenue, Los Alamos, New Mexico 87544.

FOR FURTHER INFORMATION CONTACT:
Bridget Maestas, NNMCAB Executive Director, by Phone: 505-709-7466 or Email: bridget.maestas@em.doe.gov.

SUPPLEMENTARY INFORMATION:
Purpose of the Board: The purpose of the Board is to provide advice and recommendations concerning the following EM site-specific issues: clean-up activities and environmental restoration; waste and nuclear materials management and disposition; excess facilities; future land use and long-term stewardship. The Board may also be asked to provide advice and recommendations on any EM program components.

Tentative Agenda
• Presentations
• Agency Updates
Public Participation: The in-person/online virtual hybrid meeting is open to the public in person or virtually, via WebEx. Written statements may be filed with the Board no later than 5 p.m. MDT on Friday, May 10, 2024, or within seven days after the meeting by sending them to the NNMCAB Executive Director at the aforementioned email address. Written public comments received prior to the meeting will be read into the record. The Deputy Designated Federal Officer is empowered to conduct the meeting in a fashion that will facilitate the orderly conduct of business. Individuals wishing to submit public comments should follow as directed above.
Minutes: Minutes will be available by emailing or calling Bridget Maestas, NNMCAB Executive Director, at bridget.maestas@em.doe.gov or at (505) 709-7466.
Signing Authority: This document of the Department of Energy was signed on April 16, 2024, by David Borak, Deputy Committee Management Officer, pursuant to delegated authority from the Secretary of Energy. That document with the original signature and date is maintained by DOE. For administrative purposes only, and in compliance with requirements of the Office of the Federal Register, the undersigned DOE Federal Register Liaison Officer has been authorized to sign and submit the document in electronic format for publication, as an official document of the Department of Energy. This administrative process in no way alters the legal effect of this document upon publication in the Federal Register.
Signed in Washington, DC, on April 16, 2024.
Treena V. Garrett,

Federal Register Liaison Officer, U.S. Department of Energy.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings #1
Take notice that the Commission received the following electric corporate filings:
Docket Numbers: EC24-49-000.
Applicants: RiverCrest Power-SOUTH, LLC, Six One Commodities LLC.
Description: Notice to Withdraw February 8, 2024, Application of RiverCrest Power-South, LLC.
Filed Date: 4/9/24.
Accession Number: 20240409-5242.
Comment Date: 5 pm ET 4/19/24.
Take notice that the Commission received the following exempt wholesale generator filings:
Docket Numbers: EG24-162-000.
Applicants: Three Rivers Solar Power, LLC.
Description: Three Rivers Solar Power, LLC submits Notice of Self-Certification of Exempt Wholesale Generator Status.
Filed Date: 4/10/24.
Accession Number: 20240410-5124.
Comment Date: 5 pm ET 5/1/24.
Take notice that the Commission received the following electric rate filings:
Docket Numbers: ER24-851-001.
Applicants: PacifiCorp.
Description: Tariff Amendment: Response to Deficiency Letter to be effective 3/12/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5165.
Comment Date: 5 p.m. ET 5/1/24.
Docket Numbers: ER24-856-001.
Applicants: Nevada Power Company.
Description: Tariff Amendment: Response to Deficiency Letter to be effective 3/12/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5156.
Comment Date: 5 p.m. ET 5/1/24.
Docket Numbers: ER24-857-001.
Applicants: Sierra Pacific Power Company.
Description: Tariff Amendment: Response to Deficiency Letter to be effective 3/12/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5159.
Comment Date: 5 p.m. ET 5/1/24.
Docket Numbers: ER24-1231-002.
Applicants: Wythe County Solar Project, LLC.
Description: Tariff Amendment: Deficiency Filing to be effective 4/12/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5048.
Comment Date: 5 p.m. ET 5/1/24.
Docket Numbers: ER24-1724-000.
Applicants: PJM Interconnection, L.L.C.
Description: Tariff Amendment: Cancellation of WMPA SA No. 5816, Queue Position No. AF2-271 to be effective 6/10/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5069.
Comment Date: 5 p.m. ET 5/1/24.
Docket Numbers: ER24-1725-000.
Applicants: Alabama Power Company, Georgia Power Company, Mississippi Power Company.
Description: § 205(d) Rate Filing: Alabama Power Company submits tariff filing per 35.13(a)(2)(iii: Tatum Pines LGIA Filing to be effective 3/28/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5088.
Comment Date: 5 p.m. ET 5/1/24.
The filings are accessible in the Commission's eLibrary system ( https://elibrary.ferc.gov/idmws/search/fercgensearch.asp ) by querying the docket number.
Any person desiring to intervene, to protest, or to answer a complaint in any of the above proceedings must file in accordance with Rules 211, 214, or 206 of the Commission's Regulations (18 CFR 385.211, 385.214, or 385.206) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 10, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:

Filings Instituting Proceedings
Docket Numbers: RP24-658-000.
Applicants: Jay-Bee Production Company v. Texas Gas Transmission, LLC.
Description: Complaint of Jay-Bee Production Company v. Texas Gas Transmission, LLC.
Filed Date: 4/9/24.
Accession Number: 20240409-5227.
Comment Date: 5 p.m. ET 5/9/24.
Docket Numbers: RP24-659-000.
Applicants: Cove Point LNG, LP.
Description: § 4(d) Rate Filing: Cove Point—April 10, 2024 Negotiated Rate Agreement to be effective 5/10/2024.
Filed Date: 4/10/24.
Accession Number: 20240410-5018.
Comment Date: 5 p.m. ET 4/22/24.
Docket Numbers: RP24-660-000.
Applicants: Alliance Pipeline L.P.
Description: Compliance filing: Request for Waiver of Tariff Provisions to be effective N/A.
Filed Date: 4/10/24.
Accession Number: 20240410-5080.
Comment Date: 5 p.m. ET 4/22/24.
Any person desiring to intervene, to protest, or to answer a complaint in any of the above proceedings must file in accordance with Rules 211, 214, or 206 of the Commission's Regulations (18 CFR 385.211, 385.214, or 385.206) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
The filings are accessible in the Commission's eLibrary system ( https://elibrary.ferc.gov/idmws/search/fercgensearch.asp ) by querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 10, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Project No. 2284-052]
Brookfield White Pine Hydro, LLC; Notice of Intent to File License Application, Filing of Pre-Application Document, Commencement of Pre-Filing Process, and Scoping; Request for Comments on the PAD and Scoping Document, and Identification of Issues and Associated Study Requests
a. Type of Filing: Notice of Intent To File License Application for New License and Commencing Pre-filing Process.
b. Submitted By: Brookfield White Pine Hydro, LLC.
c. Name of Project: Brunswick Hydroelectric Project.
d. Location: On the Androscoggin River, in the towns of Brunswick and Topsham, Maine.
e. Filed Pursuant to: 18 CFR part 5 of the Commission's Regulations.
f. Licensee Contact: Michael Scarzello, Brookfield White Pine Hydro, LLC, Brookfield Renewable Group, 150 Main St., Lewiston, Maine, 04240, (315) 566-0157, michael.scarzello@brookfieldrenewable.com.
g. FERC Contact: Ryan Hansen at (202) 502-8074 or email at ryan.hansen@ferc.gov.
h. Cooperating agencies : Federal, State, local, and Tribal agencies with jurisdiction and/or special expertise with respect to environmental issues that wish to cooperate in the preparation of the environmental document should follow the instructions for filing such requests described in item m below. Cooperating agencies should note the Commission's policy that agencies that cooperate in the preparation of the environmental document cannot also intervene. See 94 FERC ¶ 61,076 (2001).
i. With this notice, we are initiating informal consultation with: (a) the U.S. Fish and Wildlife Service and/or NOAA Fisheries under section 7 of the Endangered Species Act and the joint agency regulations thereunder at 50 CFR part 402 and (b) the State Historic Preservation Officer, as required by section 106, National Historic Preservation Act, and the implementing regulations of the Advisory Council on Historic Preservation at 36 CFR 800.2.
j. With this notice, we are designating Brookfield White Pine Hydro, LLC as the Commission's non-Federal representatives for carrying out informal consultation, pursuant to section 7 of the Endangered Species Act and section 106 of the National Historic Preservation Act.
k. Brookfield White Pine Hydro, LLC filed with the Commission a Pre-Application Document (PAD; including a proposed process plan and schedule), pursuant to 18 CFR 5.6 of the Commission's regulations.
l. Copies of the PAD are available for review at the Commission in the Public Reference Room or may be viewed on the Commission's website ( http://www.ferc.gov ), using the “eLibrary” link. Enter the docket number, excluding the last three digits in the docket number field to access the document. For assistance, contact FERC Online Support at FERCONlineSupport@ferc.gov, (866) 208-3676 (toll free), or (202) 502-8659 (TTY). Copies are also available for inspection and reproduction at the address in paragraph f.
Register online at http://www.ferc.gov/docs-filing/esubscription.asp to be notified via email of new filing and issuances related to this or other pending projects. For assistance, contact FERC Online Support.
m. With this notice, we are soliciting comments on the PAD and Commission's staff Scoping Document 1 (SD1), as well as study requests. All comments on the PAD and SD1, and study requests should be sent to the address above in paragraph f. In addition, all comments on the PAD and SD1, study requests, requests for cooperating agency status, and all communications to and from Commission staff related to the merits of the potential application must be filed with the Commission.
The Commission strongly encourages electronic filing. Please file all documents using the Commission's eFiling system at http://www.ferc.gov/docs-filing/efiling.asp. Commenters can submit brief comments up to 6,000 characters, without prior registration, using the eComment system at http://www.ferc.gov/docs-filing/ecomment.asp. You must include your name and contact information at the end of your comments. For assistance, please contact FERC Online Support at FERCOnlineSupport@ferc.gov. In lieu of electronic filing, you may submit a paper request. Submissions sent via the U.S. Postal Service must be addressed to: Debbie-Anne A. Reese, Acting Secretary, Federal Energy Regulatory Commission, 888 First Street, NE, Room 1A, Washington, DC 20426. Submissions sent via any other carrier must be addressed to: Debbie-Anne A. Reese, Acting Secretary, Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, Maryland 20852. All written or emailed requests must specify your wish to be added to, or removed from, the mailing list, and must clearly identify the following on the first page: Brunswick Hydroelectric Project (P-2284-052).
All filings with the Commission must bear the appropriate heading: “Comments on Pre-Application Document,” “Study Requests,” “Comments on Scoping Document 1,” “Request for Cooperating Agency Status,” or “Communications to and from Commission Staff.” Any individual or entity interested in submitting study requests, commenting on the PAD or SD1, and any agency requesting cooperating status must do so by June 20, 2024.
n. Although our current intent is to prepare an environmental assessment (EA), there is the possibility that an Environmental Impact Statement (EIS) will be required. Nevertheless, this meeting will satisfy the NEPA scoping requirements, irrespective of whether an EA or EIS is issued by the Commission.

Scoping Meetings
Commission staff will hold two scoping meetings in the vicinity of the project at the time and place noted below. The daytime meeting will focus on resource agency, Native-American Tribes, and non-governmental organization concerns, while the evening meeting is primarily for receiving input from the public. We invite all interested individuals, organizations, and agencies to attend one or both of the meetings, and to assist staff in identifying particular study needs, as well as the scope of environmental issues to be addressed in the environmental document. The times and locations of these meetings are as follows:

Daytime Scoping Meeting
Date: Tuesday, May 7, 2024.
Time: 9 a.m.
Location: The Brunswick Hotel, 4 Noble St, Brunswick, ME 04011.
Phone: (207) 837-6565.

Evening Scoping Meeting
Date: Tuesday, May 7, 2024.
Time: 6 p.m.
Location: The Brunswick Hotel, 4 Noble St, Brunswick, ME 04011.
Phone: (207) 837-6565.
SD1, which outlines the subject areas to be addressed in the environmental document, was mailed to the individuals and entities on the Commission's mailing list. Copies of SD1 may be viewed on the web at http://www.ferc.gov, using the “eLibrary” link. Follow the directions for accessing information in paragraph l. Based on all oral and written comments, a Scoping Document 2 (SD2) may be issued. SD2 may include a revised process plan and schedule, as well as a list of issues, identified through the scoping process.

Environmental Site Review
The licensee and Commission staff conducted an Environmental Site Review of the project on May 7, 2024.
Date: May 7, 2024.
Time: 1:00 p.m.
Location: Brunswick Hydroelectric Project, Maine St., Brunswick, Maine 04011.

Meeting Objectives
At the scoping meetings, staff will: (1) initiate scoping of the issues; (2) review and discuss existing conditions and resource management objectives; (3) review and discuss existing information and identify preliminary information and study needs; (4) review and discuss the process plan and schedule for pre-filing activity that incorporates the time frames provided for in part 5 of the Commission's regulations and, to the extent possible, maximizes coordination of Federal, State, and Tribal permitting and certification processes; and (5) discuss the appropriateness of any Federal or State agency or Native-American Tribe acting as a cooperating agency for development of an environmental document. Meeting participants should come prepared to discuss their issues and/or concerns. Please review the PAD in preparation for the scoping meetings. Directions on how to obtain a copy of the PAD and SD1 are included in item l of this document.

Meeting Procedures
The meetings will be recorded by a stenographer and will be placed in the public records of the project.
Dated: April 16, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. ER24-1737-000]
Hickory Solar LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization
This is a supplemental notice in the above-referenced proceeding of Hickory Solar LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is May 6, 2024.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with internet access who will eFile a document and/or be listed as a contact for an intervenor must create and validate an eRegistration account using the eRegistration link. Select the eFiling link to log on and submit the intervention or protests.
Persons unable to file electronically may mail similar pleadings to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426. Hand delivered submissions in docketed proceedings should be delivered to Health and Human Services, 12225 Wilkins Avenue, Rockville, Maryland 20852.
In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page ( http://www.ferc.gov ) using the “eLibrary” link. Enter the docket number excluding the last three digits in the docket number field to access the document. At this time, the Commission has suspended access to the Commission's Public Reference Room, due to the proclamation declaring a National Emergency concerning the Novel Coronavirus Disease (COVID-19), issued by the President on March 13, 2020. For assistance, contact the Federal Energy Regulatory Commission at FERCOnlineSupport@ferc.gov or call toll-free, (886) 208-3676 or TYY, (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 15, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. ER24-1738-000]
Ragsdale Solar, LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization
This is a supplemental notice in the above-referenced proceeding of Ragsdale Solar, LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is May 6, 2024.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with internet access who will eFile a document and/or be listed as a contact for an intervenor must create and validate an eRegistration account using the eRegistration link. Select the eFiling link to log on and submit the intervention or protests.
Persons unable to file electronically may mail similar pleadings to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426. Hand delivered submissions in docketed proceedings should be delivered to Health and Human Services, 12225 Wilkins Avenue, Rockville, Maryland 20852.
In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page ( http://www.ferc.gov ) using the “eLibrary” link. Enter the docket number excluding the last three digits in the docket number field to access the document. At this time, the Commission has suspended access to the Commission's Public Reference Room, due to the proclamation declaring a National Emergency concerning the Novel Coronavirus Disease (COVID-19), issued by the President on March 13, 2020. For assistance, contact the Federal Energy Regulatory Commission at FERCOnlineSupport@ferc.gov or call toll-free, (886) 208-3676 or TYY, (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202)502-6595 or OPP@ferc.gov.
Dated: April 15, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:

Filings Instituting Proceedings
Docket Numbers: RP24-670-000.
Applicants: Southern Star Central Gas Pipeline, Inc.
Description: 4(d) Rate Filing: GT&C 13.5—Zero Fuel on Certain Backhaul Transactions to be effective 6/1/2024.
Filed Date: 4/12/24.
Accession Number: 20240412-5226.
Comment Date: 5 p.m. ET 4/24/24.
Any person desiring to intervene, to protest, or to answer a complaint in any of the above proceedings must file in accordance with Rules 211, 214, or 206 of the Commission's Regulations (18 CFR 385.211, 385.214, or 385.206) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
The filings are accessible in the Commission's eLibrary system ( https://elibrary.ferc.gov/idmws/search/fercgensearch.asp ) by querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 15, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:

Filings in Existing Proceedings
Docket Numbers: RP24-163-001.
Applicants: Tallgrass Interstate Gas Transmission, LLC.
Description: Compliance filing: TIGT RP24-163 Stipulation and Agreement Compliance Filing to be effective 6/1/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5175.
Comment Date: 5 p.m. ET 4/29/24.
Any person desiring to protest in any the above proceedings must file in accordance with Rule 211 of the Commission's Regulations (18 CFR 385.211) on or before 5:00 p.m. Eastern time on the specified comment date.
The filings are accessible in the Commission's eLibrary system ( https://elibrary.ferc.gov/idmws/search/fercgensearch.asp ) by querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 16, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Project No. 2715-026]
Kaukauna Utilities; Notice of Reasonable Period of Time for Water Quality Certification Application
On April 12, 2024, the Wisconsin Department of Natural Resources (DNR) submitted to the Federal Energy Regulatory Commission (Commission) notice that it received a complete request for a Clean Water Act section 401(a)(1) water quality certification from Kaukauna Utilities, in conjunction with the above captioned project, on March 12, 2024. Pursuant to section 4.34(b)(5) of the Commission's regulations, ^1 we hereby notify the Wisconsin DNR of the following:
^1 18 CFR 4.34(b)(5).
Date of Receipt of the Certification Request: March 12, 2024.
Reasonable Period of Time to Act on the Certification Request: One year, March 12, 2025.
If the Wisconsin DNR fails or refuses to act on the water quality certification request on or before the above date, then the certifying authority is deemed waived pursuant to section 401(a)(1) of the Clean Water Act, 33 U.S.C. 1341(a)(1).
Dated: April 16, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Project No. 2300-052; 2300-052; 2311-067; 2326-054; 2327-047; 2422-058; 2423-031]
Great Lakes Hydro America, LLC; Notice of Revised Procedural Schedule for Environmental Assessments for the Proposed Project Relicenses
On August 1, 2022, Great Lakes Hydro America, LLC filed applications for new major licenses for the 3.7-MW Shelburne Hydroelectric Project, the 4.8-MW Upper Gorham Hydroelectric Project, the 3.2-MW Cross Power Hydroelectric Project, the 7.9-MW Cascade Hydroelectric Project, the 3.2-MW Sawmill Hydroelectric Project, and the 7.9-MW Riverside Hydroelectric Project. On October 12, 2023, Commission staff issued a notice of intent to prepare an environmental assessment (EA) to evaluate the effects of relicensing these projects. The notice identified an anticipated schedule for issuance of draft and final EAs.
By this notice, Commission staff is updating the procedural schedule for completing the draft and final EAs. The revised schedule is shown below. Further revisions to the schedule may be made as appropriate.
Milestone | Target date
Commission issues draft EAs | May 2024.
Commission issues final EAs | September 2024. ^1
Any questions regarding this notice may be directed to Ryan Hansen at (202) 502-8074, or by email at ryan.hansen@ferc.gov.
^1 The Council on Environmental Quality's (CEQ) regulations under 40 CFR 1501.10(b)(1) (2022) require that EAs be completed within 1 year of the Federal action agency's decision to prepare an EA. See National Environmental Policy Act, 42 U.S.C. 4321 et seq., as amended by section 107(g)(1)(B)(iii) of the Fiscal Responsibility Act of 2023, Public Law 118-5, sec. 4336a, 137 Stat. 42.
Dated: April 11, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings #1
Take notice that the Commission received the following electric rate filings:
Docket Numbers: ER19-2259-003.
Applicants: Turquoise Nevada LLC.
Description: Compliance filing: Turquoise Nevada LLC Change in Status to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5253.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER19-2276-006.
Applicants: New York Independent System Operator, Inc.
Description: Compliance filing: NYISO Compliance: DER program effective date to be effective 4/16/2024.
Filed Date: 4/16/24.
Accession Number: 20240416-5121.
Comment Date: 5 p.m. ET 5/7/24.
Docket Numbers: ER21-280-001.
Applicants: CO Buffalo Flats, LLC.
Description: Compliance filing: CO Buffalo Flats, LLC Change in Status to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5244.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER22-2646-002.
Applicants: Graphite Solar 1, LLC.
Description: Compliance filing: Graphite Solar I, LLC submits tariff filing per 35: Graphite Solar I, LLC Change in Status to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5248.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER22-2689-002.
Applicants: MTSun LLC.
Description: Compliance filing: MTSun LLC Change in Status to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5250.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER22-2850-002.
Applicants: Fall River Solar, LLC.
Description: Compliance filing: Fall River Solar, LLC Change in Status to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5246.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER23-1928-002.
Applicants: Appaloosa Solar I, LLC.
Description: Compliance filing: Appaloosa Solar I, LLC Change in Status to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5242.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1761-000.
Applicants: Harmony Florida Solar II, LLC.
Description: Baseline eTariff Filing: Harmony Florida Solar II, LLC Cost-Based PPA with Orlando Utilities Commission to be effective 8/15/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5255.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1762-000.
Applicants: Storey Bend Solar, LLC.
Description: Baseline eTariff Filing: Storey Bend Solar, LLC Cost-Based PPA with Orlando Utilities Commission to be effective 8/15/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5265.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1763-000.
Applicants: FRP Tupelo Solar, LLC.
Description: Baseline eTariff Filing: FRP Tupelo Solar, LLC Cost-Based PPA with Orlando Utilities Commission to be effective 8/15/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5277.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1764-000.
Applicants: FirstEnergy Service Company, PJM Interconnection, L.L.C.
Description: § 205(d) Rate Filing: FirstEnergy Service Company submits tariff filing per 35.13(a)(2)(iii: ATSI submits Revised Interconnection Agreement (IA) SA No. 3994 to be effective 6/16/2024.
Filed Date: 4/16/24.
Accession Number: 20240416-5010.
Comment Date: 5 p.m. ET 5/7/24.
Docket Numbers: ER24-1765-000.
Applicants: Southwest Power Pool, Inc.
Description: § 205(d) Rate Filing: 4247 Minco II Energy Storage Surplus Interconnection GIA to be effective 6/15/2024.
Filed Date: 4/16/24.
Accession Number: 20240416-5066.
Comment Date: 5 p.m. ET 5/7/24.
Docket Numbers: ER24-1767-000.
Applicants: PJM Interconnection, L.L.C.
Description: § 205(d) Rate Filing: Original NSA No. 7232, Queue No. AD2-031 & AF1-159 to be effective 6/16/2024.
Filed Date: 4/16/24.
Accession Number: 20240416-5073.
Comment Date: 5 p.m. ET 5/7/24.
Docket Numbers: ER24-1768-000.
Applicants: Arizona Public Service Company.
Description: Tariff Amendment: Rate Schedule 198—Notice of Cancellation to be effective 6/16/2014.
Filed Date: 4/16/24.
Accession Number: 20240416-5173.
Comment Date: 5 p.m. ET 5/7/24.
Take notice that the Commission received the following electric securities filings:
Docket Numbers: ES24-34-000.
Applicants: Orange and Rockland Utilities, Inc.
Description: Application Under Section 204 of the Federal Power Act for Authorization to Issue Securities of Orange and Rockland Utilities, Inc.
Filed Date: 4/15/24.
Accession Number: 20240415-5337.
Comment Date: 5 p.m. ET 5/6/24.
The filings are accessible in the Commission's eLibrary system ( https://elibrary.ferc.gov/idmws/search/fercgensearch.asp ) by querying the docket number.
Any person desiring to intervene, to protest, or to answer a complaint in any of the above proceedings must file in accordance with Rules 211, 214, or 206 of the Commission's Regulations (18 CFR 385.211, 385.214, or 385.206) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 16, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. ER24-1739-000]
Wolf Run Solar LLC; Supplemental Notice That Initial Market-Based Rate Filing Includes Request for Blanket Section 204 Authorization
This is a supplemental notice in the above-referenced proceeding of Wolf Run Solar LLC's application for market-based rate authority, with an accompanying rate tariff, noting that such application includes a request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability.
Any person desiring to intervene or to protest should file with the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Anyone filing a motion to intervene or protest must serve a copy of that document on the Applicant.
Notice is hereby given that the deadline for filing protests with regard to the applicant's request for blanket authorization, under 18 CFR part 34, of future issuances of securities and assumptions of liability, is May 6, 2024.
The Commission encourages electronic submission of protests and interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with internet access who will eFile a document and/or be listed as a contact for an intervenor must create and validate an eRegistration account using the eRegistration link. Select the eFiling link to log on and submit the intervention or protests.
Persons unable to file electronically may mail similar pleadings to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426. Hand delivered submissions in docketed proceedings should be delivered to Health and Human Services, 12225 Wilkins Avenue, Rockville, Maryland 20852.
In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page ( http://www.ferc.gov ) using the “eLibrary” link. Enter the docket number excluding the last three digits in the docket number field to access the document. At this time, the Commission has suspended access to the Commission's Public Reference Room, due to the proclamation declaring a National Emergency concerning the Novel Coronavirus Disease (COVID-19), issued by the President on March 13, 2020. For assistance, contact the Federal Energy Regulatory Commission at FERCOnlineSupport@ferc.gov or call toll-free, (886) 208-3676 or TYY, (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 15, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings #1
Take notice that the Commission received the following electric corporate filings:
Docket Numbers: EC24-69-000.
Applicants: ECP ControlCo, LLC.
Description: Application for Authorization Under Section 203 of the Federal Power Act of ECP ControlCo, LLC.
Filed Date: 4/11/24.
Accession Number: 20240411-5194.
Comment Date: 5 p.m. ET 5/2/24.
Take notice that the Commission received the following Complaints and Compliance filings in EL Dockets:
Docket Numbers: EL24-98-000.
Applicants: California Independent System Operator Corporation, PacifiCorp.
Description: Petition for Approval of Uncontested Settlement Agreement of California Independent System Operator Corporation, et. al.
Filed Date: 4/3/24.
Accession Number: 20240403-5202.
Comment Date: 5 p.m. ET 4/24/24.
Take notice that the Commission received the following electric rate filings:
Docket Numbers: ER21-2818-004.
Applicants: Tri-State Generation and Transmission Association, Inc.
Description: Compliance filing: Revisions on Compliance to Rate Schedule No. 281 to be effective 11/1/2021.
Filed Date: 4/12/24.
Accession Number: 20240412-5260.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER23-628-004.
Applicants: Bellflower Solar 1, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection, to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5257.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-19-003.
Applicants: Cottontail Solar 1, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5262.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-20-004.
Applicants: Cottontail Solar 2, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection, to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5265.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-21-003.
Applicants: Cottontail Solar 8, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5280.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-942-001.
Applicants: Cottontail Solar 4, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5268.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-943-002.
Applicants: Cottontail Solar 5, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection, to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5272.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-945-001.
Applicants: Cottontail Solar 6, LLC.
Description: Compliance filing: Informational Filing Pursuant to Schedule 2 of the PJM Interconnection to be effective N/A.
Filed Date: 4/12/24.
Accession Number: 20240412-5275.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-1145-001.
Applicants: Tri-State Generation and Transmission Association, Inc.
Description: Compliance filing: Revisions on Compliance to United Power Withdrawal Agreement to be effective 4/1/2024.
Filed Date: 4/12/24.
Accession Number: 20240412-5238.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-1749-000.
Applicants: Public Service Company of New Mexico.
Description: 205(d) Rate Filing: Certificates of Concurrence to be effective 3/21/2012.
Filed Date: 4/12/24.
Accession Number: 20240412-5282.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ER24-1750-000.
Applicants: PacifiCorp.
Description: 205(d) Rate Filing: Surplus Large Gen Interconnect Agrmt (Granite East—SA No. 1110) to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5065.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1751-000.
Applicants: PacifiCorp.
Description: 205(d) Rate Filing: Surplus Large Gen Interconnect Agrmt (Granite West—SA No. 1111) to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5069.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1752-000.
Applicants: PacifiCorp.
Description: 205(d) Rate Filing: Surplus Large Gen Interconnect Agrmt (Iron Springs—SA No. 1112) to be effective 4/16/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5072.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1753-000.
Applicants: Duke Energy Florida, LLC.
Description: 205(d) Rate Filing: DEF-FMPA FMPP Northern Star Rate Schedule No. 436—Reimbursement Agmt to be effective 7/1/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5091.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1754-000.
Applicants: Southwest Power Pool, Inc.
Description: 205(d) Rate Filing: Revisions to Modify the Uninstructed Resource Deviation Charge to be effective 12/31/9998.
Filed Date: 4/15/24.
Accession Number: 20240415-5117.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1755-000.
Applicants: Alabama Power Company, Georgia Power Company, Mississippi Power Company.
Description: 205(d) Rate Filing: Alabama Power Company submits tariff filing per 35.13(a)(2)(iii: Shelby Solar Park LGIA Amendment Filing to be effective 4/2/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5138.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1756-000.
Applicants: Alabama Power Company, Georgia Power Company, Mississippi Power Company.
Description: 205(d) Rate Filing: Alabama Power Company submits tariff filing per 35.13(a)(2)(iii: Sawmill Junction Solar Park A&R LGIA Amendment Filing to be effective 4/4/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5139.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1757-000.
Applicants: Tri-State Generation and Transmission Association, Inc.
Description: 205(d) Rate Filing: Certificate of Concurrence for PNM Subentity Reserve Sharing Agreement to be effective 4/1/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5173.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1758-000.
Applicants: AEP Texas Inc.
Description: 205(d) Rate Filing: AEPTX-Oncor Regency Facilities Development Agreement to be effective 3/22/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5188.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1759-000.
Applicants: AEP Texas Inc.
Description: 205(d) Rate Filing: AEPTX-CGRP 10 (Copano & Port Bay Solar) Interconnection Agreement to be effective 3/26/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5210.
Comment Date: 5 p.m. ET 5/6/24.
Docket Numbers: ER24-1760-000.
Applicants: PJM Interconnection, L.L.C.
Description: 205(d) Rate Filing: Amended ISA, Service Agreement No. 6876; AC2-141 to be effective 6/17/2024.
Filed Date: 4/15/24.
Accession Number: 20240415-5217.
Comment Date: 5 p.m. ET 5/6/24.
Take notice that the Commission received the following electric securities filings:
Docket Numbers: ES24-32-000.
Applicants: Louisville Gas and Electric Company.
Description: Application Under Section 204 of the Federal Power Act for Authorization to Issue Securities of Louisville Gas and Electric Company.
Filed Date: 4/12/24.
Accession Number: 20240412-5353.
Comment Date: 5 p.m. ET 5/3/24.
Docket Numbers: ES24-33-000.
Applicants: Kentucky Utilities Company.
Description: Application Under Section 204 of the Federal Power Act for Authorization to Issue Securities of Kentucky Utilities Company.
Filed Date: 4/12/24.
Accession Number: 20240412-5354.
Comment Date: 5 p.m. ET 5/3/24.
The filings are accessible in the Commission's eLibrary system ( https://elibrary.ferc.gov/idmws/search/fercgensearch.asp ) by querying the docket number.
Any person desiring to intervene, to protest, or to answer a complaint in any of the above proceedings must file in accordance with Rules 211, 214, or 206 of the Commission's Regulations (18 CFR 385.211, 385.214, or 385.206) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
The Commission's Office of Public Participation (OPP) supports meaningful public engagement and participation in Commission proceedings. OPP can help members of the public, including landowners, environmental justice communities, Tribal members and others, access publicly available information and navigate Commission processes. For public inquiries and assistance with making filings such as interventions, comments, or requests for rehearing, the public is encouraged to contact OPP at (202) 502-6595 or OPP@ferc.gov.
Dated: April 15, 2024.
Debbie-Anne A. Reese,

Acting Secretary.
ENVIRONMENTAL PROTECTION AGENCY
[EPA-HQ-OPP-2024-0023; FRL-11670-01-OCSPP]
Agency Information Collection Activities; Proposed Renewal of an Existing ICR Collection and Request for Comment; Standards for Pesticide Containers and Containment

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice.

SUMMARY:
In compliance with the Paperwork Reduction Act (PRA), this document announces the availability of and solicits public comment on the following Information Collection Request (ICR) that EPA is planning to submit to the Office of Management and Budget (OMB): “Standards for Pesticide Container and Containment,” identified by EPA ICR No. 1632.07 and OMB Control No. 2070-0133. This ICR represents a renewal of an existing ICR that is currently approved through January 31, 2025. Before submitting the ICR to OMB for review and approval under the PRA, EPA is soliciting comments on specific aspects of the information collection that is summarized in this document. The ICR and accompanying material are available in the docket for public review and comment.

DATES:
Comments must be received on or before June 21, 2024.

ADDRESSES:
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPP-2024-0023, through https://www.regulations.gov. Follow the online instructions for submitting comments. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at https://www.epa.gov/dockets.

FOR FURTHER INFORMATION CONTACT:
Carolyn Siu, Mission Support Division (7602M), Office of Program Support, Office of Chemical Safety and Pollution Prevention, Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460-0001; telephone number: (703) 719-1649; email address: siu.carolyn@epa.gov.

SUPPLEMENTARY INFORMATION:

I. What information is EPA particularly interested in?
Pursuant to PRA section 3506(c)(2)(A) (44 U.S.C. 3506(c)(2)(A)), EPA specifically solicits comments and information to enable it to:
1. Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility.
2. Evaluate the accuracy of the Agency's estimates of the burden of the proposed collection of information, including the validity of the methodology and assumptions used.
3. Enhance the quality, utility, and clarity of the information to be collected.
4. Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses. In particular, EPA is requesting comments from very small businesses (those that employ less than 25) on examples of specific additional efforts that EPA could make to reduce the paperwork burden for very small businesses affected by this collection.

II. What information collection activity or ICR does this action apply to?
Title: Standards for Pesticide Containers and Containment.
EPA ICR No.: 1632.07.
OMB Control No.: 2070-0133.
ICR status: This ICR is currently approved through January 31, 2025. Under the PRA, an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information, unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in title 40 of the Code of Federal Regulations (CFR), after appearing in the Federal Register when approved, are displayed either by publication in the Federal Register or by other appropriate means, such as on the related collection instrument or form, if applicable. The display of OMB control numbers for certain EPA regulations is consolidated in 40 CFR part 9.
Abstract: This ICR covers the information collection activities associated with the pesticide container design and residue removal requirements and containment structure requirements. With respect to the container design and residue removal requirements, the information collection activities are associated with the requirement that businesses subject to the container regulations (pesticide registrants) and repackaging regulations (pesticide registrants and refillers) maintain records of test data, cleaning procedures, certain data when a container is refilled, and other supporting information. These records are subject to both call-in by EPA and on-site inspection by EPA and its representatives. EPA has not established a regular schedule for the collection of these records, and there is no reporting. With respect to the containment structure requirements, the information collection activities are associated with the requirement that businesses subject to the containment structure regulations maintain records of the: (1) Monthly inspection and maintenance of each containment structure and all stationary bulk containers; (2) Duration over which non-stationary bulk containers holding pesticide and not protected by a secondary containment unit remain at the same location; and (3) Construction date of the containment structure. The businesses subject to the containment structure regulations include agrichemical retailers and refilling establishments, custom blenders and commercial applicators of agricultural pesticides. The records have to be maintained by the owners and operators of such businesses and made available to inspectors to ensure that businesses are in compliance with containment requirements. These inspections are generally conducted by the states, which enforce FIFRA regulations through cooperative agreements with EPA.
Burden statement: The annual public reporting and recordkeeping burden for this collection of information is estimated to average 7.5 hours per response for container regulations and 4 hours per response for containment regulations. Burden is defined in 5 CFR 1320.3(b).
The ICR, which is available in the docket along with other related materials, provides a detailed explanation of the collection activities and the burden estimate that is only briefly summarized here:
Respondents/affected entities: Entities potentially affected are those that are part of the regulated community affected by the container design and residue removal regulations which includes businesses that formulate pesticide products or repackage pesticide products into refillable containers. The ICR includes a list of potentially affected entities with North American Industrial Classification System (NAICS) codes provided to assist in determining potential applicability.
Respondent's obligation to respond: Mandatory under sections 3, 8, 19 and 25 of the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA)(7 U.S.C. 136f, 136q, and 136w).
Forms: None.
Frequency of response: Occasional.
Total estimated number of potential respondents: 23,586.
Total estimated average number of responses for each respondent: 1.
Total estimated annual burden hours: 180,763 hours.
Total estimated annual costs: $10,864,043. This includes total burden costs of $10,444,168 and $419,875 of capital investment or maintenance and operational costs.

III. Are there changes in the estimates from the last approval?
There is no change in the number of burden hours as there are no programmatic updates to changes identified in the ICR currently approved by OMB. The change in costs for the regulated community are $1,410,512. The change is costs are based on BLS wage rate adjustments. There is also an increase in capital costs of $83,975 due to an increase in costs for agricultural pesticide refiller. These changes qualify as adjustments.
In addition, OMB requested that EPA replace the format the Agency has historically used for ICR Supporting Statements with the 18-question format that is used by other federal agencies and departments. The 18-question format is based on the submission instructions to agencies that appear on the OMB submission form. Although this supporting statement has been modified to reflect the 18-question format, the change in format did not change the information collection activities or related estimated burden and costs. EPA welcomes your feedback on whether this improves the presentation of the information collection activities and related burden and costs estimates.

IV. What is the next step in the process for this ICR?
EPA will consider the comments received and amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval pursuant to 5 CFR 1320.12. EPA will issue another Federal Register document pursuant to 5 CFR 1320.5(a)(1)(iv) to announce the submission of the ICR to OMB and the opportunity to submit additional comments to OMB. If you have any questions about this ICR or the approval process, please contact the person listed under FOR FURTHER INFORMATION CONTACT .
Authority: 44 U.S.C. 3501 et seq.
Dated: April 17, 2024.
Michal Freedhoff,

Assistant Administrator, Office of Chemical Safety and Pollution Prevention.
ENVIRONMENTAL PROTECTION AGENCY
[FRL-11851-01-OLEM]
Forty-Fifth Update of the Federal Agency Hazardous Waste Compliance Docket

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice.

SUMMARY:
Since 1988, the Environmental Protection Agency (EPA) has maintained a Federal Agency Hazardous Waste Compliance Docket (“Docket”) under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA). CERCLA requires EPA to establish a Docket that contains certain information reported to EPA by Federal facilities that manage hazardous waste or from which a reportable quantity of hazardous substances has been released. This notice identifies the Federal facilities not previously listed on the Docket and identifies Federal facilities reported to EPA since the last update on October 26, 2023. In addition to the list of additions to the Docket, this notice includes a section with revisions of the previous Docket list and a section of Federal facilities that are to be deleted from the Docket. Thus, the revisions in this update include one addition, zero deletions, and zero corrections to the Docket since the previous update.

DATES:
This list is current as of March 28, 2024.

FOR FURTHER INFORMATION CONTACT:
Electronic versions of the Docket and more information on its implementation can be obtained at http://www.epa.gov/fedfac/federal-agency-hazardous-waste-compliance-docket by clicking on the link for Cleanups at Federal Facilities or by contacting Jonathan Tso ( Tso.Jonathan@epa.gov ), Federal Agency Hazardous Waste Compliance Docket Coordinator, Federal Facilities Restoration and Reuse Office. Additional information on the Docket and a complete list of Docket sites can be obtained at: https://www.epa.gov/fedfac/federal-agency-hazardous-waste-compliance-docket-1.

SUPPLEMENTARY INFORMATION:

Table of Contents
1.0 Introduction
2.0 Regional Docket Coordinators
3.0 Revisions of the Previous Docket
4.0 Process for Compiling the Updated Docket
5.0 Facilities Not Included
6.0 Facility NPL Status Reporting, Including NFRAP Status
7.0 Information Contained on Docket Listing

1.0 Introduction
Section 120(c) of CERCLA, 42 U.S.C. 9620(c), as amended by the Superfund Amendments and Reauthorization Act of 1986 (SARA), requires EPA to establish the Federal Agency Hazardous Waste Compliance Docket. The Docket contains information on Federal facilities that manage hazardous waste and such information is submitted by Federal agencies to EPA under sections 3005, 3010, and 3016 of the Resource Conservation and Recovery Act (RCRA), 42 U.S.C. 6925, 6930, and 6937. Additionally, the Docket contains information on Federal facilities with a reportable quantity of hazardous substances that has been released and such information is submitted by Federal agencies to EPA under section 103 of CERCLA, 42 U.S.C. 9603. Specifically, RCRA section 3005 establishes a permitting system for certain hazardous waste treatment, storage, and disposal (TSD) facilities; RCRA section 3010 requires waste generators, transporters and TSD facilities to notify EPA of their hazardous waste activities; and RCRA section 3016 requires Federal agencies to submit biennially to EPA an inventory of their Federal hazardous waste facilities. CERCLA section 103(a) requires the owner or operator of a vessel or onshore or offshore facility to notify the National Response Center (NRC) of any spill or other release of a hazardous substance that equals or exceeds a reportable quantity (RQ), as defined by CERCLA section 101. Additionally, CERCLA section 103(c) requires facilities that have “stored, treated, or disposed of” hazardous wastes and where there is “known, suspected, or likely releases” of hazardous substances to report their activities to EPA.
CERCLA section 120(d) requires EPA to take steps to assure that a Preliminary Assessment (PA) be completed for those sites identified in the Docket and that the evaluation and listing of sites with a PA be completed within a reasonable time frame. The PA is designed to provide information for EPA to consider when evaluating the site for potential response action or inclusion on the National Priorities List (NPL).
The Docket serves three major purposes: (1) To identify all Federal facilities that must be evaluated to determine whether they pose a threat to human health and the environment sufficient to warrant inclusion on the National Priorities List (NPL); (2) to compile and maintain the information submitted to EPA on such facilities under the provisions listed in section 120(c) of CERCLA; and (3) to provide a mechanism to make the information available to the public. Previous Docket updates are available at https://www.epa.gov/fedfac/previous-federal-agency-hazardous-waste-compliance-docket-updates.
This notice provides some background information on the Docket. Additional information on the Docket requirements and implementation are found in the Docket Reference Manual, Federal Agency Hazardous Waste Compliance Docket found at http://www.epa.gov/fedfac/docket-reference-manual-federal-agency-hazardous-waste-compliance-docket-interim-final or obtained by calling the Regional Docket Coordinators listed below. This notice also provides changes to the list of sites included on the Docket in three areas: (1) Additions, (2) Deletions, and (3) Corrections. Specifically, additions are newly identified Federal facilities that have been reported to EPA since the last update and now are included on the Docket; the deletions section lists Federal facilities that EPA is deleting from the Docket. ^1 The information submitted to EPA on each Federal facility is maintained in the Docket repository located in the EPA Regional office of the Region in which the Federal facility is located; for a description of the information required under those provisions, see 53 FR 4280 (February 12, 1988). Each repository contains the documents submitted to EPA under the reporting provisions and correspondence relevant to the reporting provisions for each Federal facility.
^1 See section 3.2 for the criteria for being deleted from the Docket.
In prior updates, information was also provided regarding No Further Remedial Action Planned (NFRAP) status changes. However, information on NFRAP and NPL status is no longer being provided separately in the Docket update as it is now available at: http://www.epa.gov/fedfacts/federal-facility-cleanup-sites-searchable-list or by contacting the EPA HQ Docket Coordinator at the address provided in the FOR FURTHER INFORMATION CONTACT section of this notice.

2.0 Regional Docket Coordinators
Contact the following Docket Coordinators for information on Regional Docket repositories:
• US EPA Region 1. Alyssa Villalpando (HBS), 5 Post Office Square, Suite 100, Mail Code: 01-5, Boston MA 02109-3912, (617) 918-1603.
• US EPA Region 2. James Desir, 290 Broadway, New York, NY 10007-1866, (212) 637-4342.
• US EPA Region 3. Joseph Vitello (3HS12), 1650 Arch Street, Philadelphia, PA 19107, (215) 814-3354.
• US EPA Region 3. Dawn Fulsher (3HS12), 1650 Arch Street, Philadelphia, PA 19107, (215) 814-3270.
• US EPA Region 4. Emily Jones (9T25), 61 Forsyth St., SW, Atlanta, GA 30303, (404) 562-8334.
• US EPA Region 5. David Brauner (SR-6J), 77 W. Jackson Blvd., Chicago, IL 60604, (312) 886-1526.
• US EPA Region 6. Philip Ofosu (6SF-RA), 1445 Ross Avenue, Dallas, TX 75202-2733, (214) 665-3178.
• US EPA Region 7. Matthew Smith (SUPRERSB), 11201 Renner Blvd., Lenexa, KS 66219, (913) 551-7527.
• US EPA Region 8. Ryan Dunham (EPR-F), 1595 Wynkoop Street, Denver, CO 80202, (303) 312-6627.
• US EPA Region 9. Ashley Mrzljak (SFD-6-1), 600 Wilshire Boulevard, Suite 940, Los Angeles, CA 90017, (213) 244-1839.
• US EPA Region 10. Stephen Nguyen, 1200 Sixth Avenue, Seattle, WA 98101, (206) 553-1073.

3.0 Revisions of the Previous Docket
This section includes a discussion of the additions, deletions and corrections to the list of Docket facilities since the previous Docket update.

3.1 Additions
These Federal facilities are being added primarily because of new information obtained by EPA (for example, recent reporting of a facility pursuant to RCRA sections 3005, 3010, or 3016 or CERCLA section 103). CERCLA section 120, as amended by the Defense Authorization Act of 1997, specifies that EPA take steps to assure that a Preliminary Assessment (PA) be completed within a reasonable time frame for those Federal facilities that are included on the Docket. Among other things, the PA is designed to provide information for EPA to consider when evaluating the site for potential response action or listing on the NPL. This notice includes one addition.

3.2&Deletions
There are no statutory or regulatory provisions that address deletion of a facility from the Docket. However, if a facility is incorrectly included on the Docket, it may be deleted from the Docket. The criteria EPA uses in deleting sites from the Docket include: a facility for which there was an incorrect report submitted for hazardous waste activity under RCRA ( e.g., 40 CFR 262.44); a facility that was not federally-owned or operated at the time of the listing; a facility included more than once ( i.e., redundant listings); or when multiple facilities are combined under one listing. ( See Docket Codes ( Reasons for Deletion of Facilities ) for a more refined list of the criteria EPA uses for deleting sites from the Docket.) Facilities being deleted no longer will be subject to the requirements of CERCLA section 120(d). This notice includes zero deletions.

3.3 Corrections
Changes necessary to correct the previous Docket are identified by both EPA and Federal agencies. The corrections section may include changes in addresses or spelling, and corrections of the recorded name and ownership of a Federal facility. In addition, changes in the names of Federal facilities may be made to establish consistency in the Docket or between the Superfund Enterprise Management System (SEMS) and the Docket. For the Federal facility for which a correction is entered, the original entry is as it appeared in previous Docket updates. The corrected update is shown directly below, for easy comparison. This notice includes zero corrections.

4.0 Process for Compiling the Updated Docket
In compiling the newly reported Federal facilities for the update being published in this notice, EPA extracted the names, addresses, and identification numbers of facilities from four EPA databases—the WebEOC, the Biennial Inventory of Federal Agency Hazardous Waste Activities, the Resource Conservation and Recovery Act Information System (RCRAInfo), and SEMS— that contain information about Federal facilities submitted under the four provisions listed in CERCLA section 120(c).
EPA assures the quality of the information on the Docket by conducting extensive evaluation of the current Docket list and contacts the other Federal Agency (OFA) with the information obtained from the databases identified above to determine which Federal facilities were, in fact, newly reported and qualified for inclusion on the update. EPA is also striving to correct errors for Federal facilities that were previously reported. For example, state-owned or privately-owned facilities that are not operated by the Federal government may have been included. Such problems are sometimes caused by procedures historically used to report and track Federal facilities data. Representatives of Federal agencies are asked to contact the EPA HQ Docket Coordinator at the address provided in the FOR FURTHER INFORMATION CONTACT section of this notice if revisions of this update information are necessary.

5.0 Facilities Not Included
Certain categories of facilities may not be included on the Docket, such as: (1) Federal facilities formerly owned by a Federal agency that at the time of consideration was not federally-owned or operated; (2) Federal facilities that are small quantity generators (SQGs) that have not, more than once per calendar year, generated more than 1,000 kg of hazardous waste in any single month; (3) Federal facilities that are very small quantity generators (VSQGs) that have never generated more than 100 kg of hazardous waste in any month; (4) Federal facilities that are solely hazardous waste transportation facilities, as reported under RCRA section 3010; and (5) Federal facilities that have mixed mine or mill site ownership.
An EPA policy issued in June 2003 provided guidance for a site-by-site evaluation as to whether “mixed ownership” mine or mill sites, typically created as a result of activities conducted pursuant to the General Mining Law of 1872 and never reported under section 103(a) of CERCLA, should be included on the Docket. For purposes of that policy, mixed ownership mine or mill sites are those located partially on private land and partially on public land. This policy is found at http://www.epa.gov/fedfac/policy-listing-mixed-ownership-mine-or-mill-sites-created-result-general-mining-law-1872. The policy of not including these facilities may change; facilities now omitted may be added at some point if EPA determines that they should be included.

6.0 Facility NPL Status Reporting, Including NFRAP Status
EPA tracks the NPL status of Federal facilities listed on the Docket. An updated list of the NPL status of all Docket facilities, as well as their NFRAP status, is available at https://www.epa.gov/fedfacts/federal-facility-cleanup-sites-searchable-list or by contacting the EPA HQ Docket Coordinator at the address provided in the FOR FURTHER INFORMATION CONTACT section of this notice. In prior updates, information regarding NFRAP status changes was provided separately.

7.0 Information Contained on Docket Listing
The information is provided in three tables. The first table is a list of additional Federal facilities that are being added to the Docket. The second table is a list of Federal facilities that are being deleted from the Docket. The third table is for corrections.
The Federal facilities listed in each table are organized by the date reported. Under each heading is listed the name and address of the facility, the Federal agency responsible for the facility, the statutory provision(s) under which the facility was reported to EPA, and a code. ^2
^2 Each Federal facility listed in the update has been assigned a code that indicates a specific reason for the addition or deletion. The code precedes this list.
The statutory provisions under which a Federal facility is reported are listed in a column titled “Reporting Mechanism.” Applicable mechanisms are listed for each Federal facility: for example, Sections 3005, 3010, 3016, 103(c), or Other. “Other” has been added as a reporting mechanism to indicate those Federal facilities that otherwise have been identified to have releases or threat of releases of hazardous substances. The National Contingency Plan at 40 CFR 300.405 addresses discovery or notification, outlines what constitutes discovery of a hazardous substance release, and States that a release may be discovered in several ways, including: (1) A report submitted in accordance with section 103(a) of CERCLA, i.e., reportable quantities codified at 40 CFR 302; (2) a report submitted to EPA in accordance with section 103(c) of CERCLA; (3) investigation by government authorities conducted in accordance with section 104(e) of CERCLA or other statutory authority; (4) notification of a release by a Federal or State permit holder when required by its permit; (5) inventory or survey efforts or random or incidental observation reported by government agencies or the public; (6) submission of a citizen petition to EPA or the appropriate Federal facility requesting a preliminary assessment, in accordance with section 105(d) of CERCLA; (7) a report submitted in accordance with section 311(b)(5) of the Clean Water Act; and (8) other sources. As a policy matter, EPA generally believes it is appropriate for Federal facilities identified through the CERCLA discovery and notification process to be included on the Docket.
The complete list of Federal facilities that now make up the Docket and the NPL and NFRAP status are available to interested parties and can be obtained at https://www.epa.gov/fedfacts/federal-facility-cleanup-sites-searchable-list or by contacting the EPA HQ Docket Coordinator at the address provided in the FOR FURTHER INFORMATION CONTACT section of this notice. As of the date of this notice, the total number of Federal facilities that appear on the Docket is 2,394.
Gregory Gervais,

Director, Federal Facilities Restoration and Reuse Office, Office of Land and Emergency Management.

7.1 Docket Codes/Reasons for Deletion of Facilities
• Code 1. Small-Quantity Generator and Very Small Quantity Generator. Show citation box
• Code 2. Never Federally Owned and/or Operated.
• Code 3. Formerly Federally Owned and/or Operated but not at time of listing.
• Code 4. No Hazardous Waste Generated.
• Code 5. (This code is no longer used.)
• Code 6. Redundant Listing/Site on Facility.
• Code 7. Combining Sites Into One Facility/Entries Combined.
• Code 8. Does Not Fit Facility Definition.

7.2 Docket Codes/Reasons for Addition of Facilities
• Code 15. Small-Quantity Generator with either a RCRA 3016 or CERCLA 103 Reporting Mechanism.
• Code 16. One Entry Being Split Into Two (or more)/Federal Agency Responsibility Being Split. • Code 16A. NPL site that is part of a Facility already listed on the Docket.
• Code 17. New Information Obtained Showing That Facility Should Be Included.
• Code 18. Facility Was a Site on a Facility That Was Disbanded; Now a Separate Facility.
• Code 19. Sites Were Combined Into One Facility.
• Code 19A. New Currently Federally Owned and/or Operated Facility Site.

7.3 Docket Codes/Types of Corrections of Information About Facilities
• Code 20. Reporting Provisions Change.
• Code 20A. Typo Correction/Name Change/Address Change.
• Code 21. Changing Responsible Federal Agency. (If applicable, new responsible Federal agency submits proof of previously performed PA, which is subject to approval by EPA.)
• Code 22. Changing Responsible Federal Agency and Facility Name. (If applicable, new responsible Federal Agency submits proof of previously performed PA, which is subject to approval by EPA.)
• Code 24. Reporting Mechanism Determined To Be Not Applicable After Review of Regional Files.
Federal Agency Hazardous Waste Compliance Docket Update #45—Additions
Facility name | Address | City | State | Zip Code | Agency | Reporting mechanism | Code | Date
CT AVCRAD 1109TH TASMG | 139 TOWER AVE | GROTON | CT | 06340 | ARMY | RCRA 3010 | 17 | UPDATE #45
Federal Agency Hazardous Waste Compliance Docket Update #45—Deletions
Facility name | Address | City | State | Zip Code | Agency | Reporting mechanism | Code | Date
Federal Agency Hazardous Waste Compliance Docket Update #45—Corrections
Facility name | Address | City | State | Zip Code | Agency | Reporting mechanism | Code | Date
ENVIRONMENTAL PROTECTION AGENCY
[FRL-9542-06-OAR]
Information Regarding Allowances Used in Cross-State Air Pollution Rule (CSAPR) Trading Programs

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice of data availability.

SUMMARY:
The Environmental Protection Agency (EPA) is providing notice of the availability of data on emission allowance allocations to certain units under the Cross-State Air Pollution Rule (CSAPR) trading programs. EPA has completed final calculations for the allocations of allowances from the new unit set-asides (NUSAs) for the 2023 control periods and has posted spreadsheets containing the calculations on EPA's website. EPA has also completed calculations for allocations of the remaining 2023 NUSA allowances to existing units and has posted spreadsheets containing those calculations on EPA's website as well. Additionally, EPA is making available an estimate of the data and calculations to be used in the allowance bank recalibration process for the 2024 control period under the CSAPR NO X Ozone Season Group 3 Trading Program.

DATES:
April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Questions concerning this action should be addressed to Garrett Powers at (202) 564-2300 or powers.jamesg@epa.gov or Morgan Riedel at (202) 564-1144 or riedel.morgan@epa.gov.

SUPPLEMENTARY INFORMATION:

I. Allocations From New Unit Set-Asides
Under each CSAPR trading program where EPA is responsible for determining emission allowance allocations, a portion of each state's emissions budget for the program for each control period is reserved in a NUSA (and, under most of the trading programs, in an additional Indian country NUSA in the case of states with Indian country within their borders) for allocation to certain units that would not otherwise receive allowance allocations. The procedures for identifying the eligible units for each control period and for allocating allowances from the NUSAs and Indian country NUSAs to these units are set forth in the CSAPR trading program regulations at 40 CFR 97.411(b) and 97.412 (NO X Annual), 97.511(b) and 97.512 (NO X Ozone Season Group 1), 97.611(b) and 97.612 (SO 2 Group 1), 97.711(b) and 97.712 (SO 2 Group 2), 97.811(b) and 97.812 (NO X Ozone Season Group 2), and 97.1012 (NO X Ozone Season Group 3). Each NUSA allowance allocation process involves allocations to eligible units, termed “new” units, followed by the allocation to “existing” units of any allowances not allocated to new units. ^1
^1 The CSAPR NO X Ozone Season Group 3 Trading Program serves as the compliance mechanism for electricity generating units under the Good Neighbor Plan (88 FR 36654, June 5, 2023). As of the date of signature of this notice, applications for a stay of the Good Neighbor Plan are pending before the Supreme Court of the United States. If a stay order is issued and depending on its nature, it could affect EPA's ability to implement the regulatory provisions of the CSAPR NO X Ozone Season Group 3 Trading Program that are described in this notice.
In a notice of data availability (NODA) published in the Federal Register on March 1, 2024 (89 FR 15199), EPA provided notice of the preliminary calculations of NUSA allowance allocations for the 2023 control periods and described the process for submitting any objections. This NODA concerns the final NUSA allowance allocations.
In response to the March 1, 2024, NODA, EPA received a written objection from Shell Chemical Appalachia LLC (ORIS 58933) stating that the preliminary allocation of one CSAPR SO 2 Group 1 allowance to unit 101 from the NUSA for West Virginia was incorrect and that unit 101 should receive two allowances instead. EPA agrees and accordingly has corrected the final NUSA allowance allocations for the CSAPR SO 2 Group 1 Trading Program to reflect a 1-ton increase in the amount of NUSA allowances allocated to Shell Chemical Appalachia LLC unit 101 and a corresponding 1-ton decrease in the collective amount of NUSA allowances allocated to West Virginia's “existing” units. EPA received no other written objections, and all other final allocations are unchanged from the preliminary allocations.
The detailed unit-by-unit data and final allowance allocation calculations are set forth in Excel spreadsheets titled “CSAPR_NUSA_2023_NO x _Annual_Final_Data_New_Units,” “CSAPR_NUSA_2023_NO x _OS_Final_Data_New_Units,” “CSAPR_NUSA_2023_SO 2 _Final_Data_New_Units,” “CSAPR_NUSA_2023_NO x _Annual_Final_Data_Existing_Units,” “CSAPR_NUSA_2023_NO x _OS_Final_Data_Existing_Units,” and “CSAPR_NUSA_2032_SO 2 _Final_Data_Existing_Units”, available on EPA's website at www.epa.gov/Cross-State-Air-Pollution/csapr-compliance-year-2023-nusa-nodas.
EPA notes that an allocation or lack of allocation of allowances to a given unit under a given CSAPR trading program does not constitute a determination that the trading program does or does not apply to the unit. EPA also notes that, under 40 CFR 97.411(c), 97.511(c), 97.611(c), 97.711(c), 97.811(c), 97.1011(c), and 97.1012(c), allocations are subject to potential correction if a unit to which allowances have been allocated for a given control period is not actually an affected unit as of the start of that control period.

II. Information for the Allowance Bank Recalibration Procedures
The CSAPR NO X Ozone Season Group 3 Trading Program includes provisions calling for EPA to annually recalibrate the bank of CSAPR NO X Ozone Season Group 3 allowances if the total quantity of banked allowances from previous control periods held in all facility and general accounts after compliance deductions for those control periods exceeds an allowance bank ceiling target for the current control period. The allowance bank recalibration procedures are set forth in the trading program regulations at 40 CFR 97.1026(d). Generally, if recalibration takes place for a given control period, the amount of banked CSAPR NO X Ozone Season Group 3 allowances from previous control periods held in each facility or general account will be adjusted so that the amount of such banked allowances held in the account after recalibration will equal the amount held in the account immediately before recalibration multiplied by the allowance bank ceiling target, divided by the total amount of such banked allowances held in all facility and general accounts immediately before recalibration, and rounded up to the nearest allowance. Allowance bank recalibration for a given control period applies only to holdings of banked allowances issued for previous control periods; it does not affect any holdings of allowances issued for that control period. The regulations call for EPA to carry out the allowance bank recalibration procedures for the 2024 control period as soon as practicable on or after August 1, 2024. ^2
^2 See note 1, supra.
For the 2024 control period, the allowance bank ceiling target is expected to be 12,605 tons, computed as 21% the sum of the 2024 state emission budgets for the ten states currently covered by the trading program. Based on the emissions and allowance data available at campd.epa.gov as of the date of signature of this notice, EPA estimates that after allowance deductions for 2023 compliance are completed in June 2024, approximately 38,545 banked vintage 2021-2023 allowances will be held in facility or general accounts (84,378 current allowance holdings + 3,365 upcoming NUSA allocations−49,198 reported 2023 ozone season emissions = 38,545 estimated remaining allowances). Based on these figures, EPA expects that allowance bank recalibration will take place for the 2024 control period and estimates that the amount of banked vintage 2021-2023 allowances that will be held in each facility or general account after recalibration will be the amount of such banked allowances held in the account immediately before recalibration multiplied by 12,605 and divided by 38,545 (or, equivalently, the amount of such banked allowances held in the account immediately before recalibration multiplied by approximately 33%). In the actual allowance bank recalibration process, instead of using the estimated figures described in this notice, EPA will use the most current information available as of the recalibration date.
(Authority: 40 CFR 97.411(b), 97.511(b), 97.611(b), 97.711(b), 97.811(b), and 97.1012(a).)
Rona Birnbaum,

Director, Clean Air and Power Division, Office of Atmospheric Protection, Office of Air and Radiation.
FEDERAL HOUSING FINANCE AGENCY
[No. 2024-N-5]
Freddie Mac Proposed Purchase of Single-Family Closed-End Second Mortgages; Comment Request

AGENCY:
Federal Housing Finance Agency.

ACTION:
Notice of proposed Enterprise new product; request for comment.

SUMMARY:
The Federal Housing Finance Agency (FHFA) invites comments on a proposal by the Federal Home Loan Mortgage Corporation (Freddie Mac) to purchase certain single-family closed-end second mortgages as a new product (proposed new product).

DATES:
FHFA will accept written comments on the proposed new product on or before May 22, 2024.

ADDRESSES:
You may submit your comments by electronic mail (Email) only on the proposed new product, identified by “Proposed Enterprise New Product; Comment Request `Freddie Mac Single-Family Closed-End Second Mortgages,' (No. 2024-N-5),” by either of the following methods:
• Agency website: www.fhfa.gov/open-for-comment-or-input.
• Email: RegComments@fhfa.gov.
FHFA will post all public comments received without change, including any personal information you provide, such as your name, address, email address, and telephone number, on the FHFA website at http://www.fhfa.gov. In addition, all comments received will be available for examination by the public through the electronic comment docket for this notice also located on the FHFA website.

FOR FURTHER INFORMATION CONTACT:
Eric Bryant, Policy Analyst, Division of Housing Mission and Goals, (202) 253-4505, eric.bryant@fhfa.gov; William Merrill, Associate Director, Division of Housing Mission and Goals, (202) 649-3428, william.merrill@fhfa.gov; Lyn Abrams, Associate General Counsel, Office of General Counsel, (202) 649-3059, lyn.abrams@fhfa.gov; or Dinah Knight, Assistant General Counsel, Office of General Counsel, (202) 748-7801, dinah.knight@fhfa.gov, Federal Housing Finance Agency, 400 Seventh Street, SW, Washington, DC 20219. These are not toll-free numbers. For TTY/TRS users with hearing and speech disabilities, dial 711 and ask to be connected to any of the contact numbers above.

SUPPLEMENTARY INFORMATION:

I. Background

A. FHFA's Statutory and Regulatory Authority
FHFA oversees the government sponsored enterprises, the Federal National Mortgage Association (Fannie Mae) and the Federal Home Loan Mortgage Corporation (Freddie Mac and, together with Fannie Mae, the Enterprises), to ensure that they operate in a safe and sound manner, achieve the purposes of the Federal Housing Enterprises Financial Safety and Soundness Act of 1992, as amended ^1 (the Safety and Soundness Act), fulfill their statutory charters, ^2 and comply with other applicable laws. ^3
^1 12 U.S.C. 4501 et seq.
^2 12 U.S.C. 1716 et seq. and 12 U.S.C. 1451 et seq.
^3 Since 2008, FHFA has also acted as conservator for each Enterprise.
In recognition of the significant impact that the activities of the Enterprises have on the U.S. housing finance system, market participants, and the broader economy, section 1321 of the Safety and Soundness Act requires the FHFA Director to review new Enterprise activities and to approve new Enterprise products before these activities and products are offered to the market. ^4 Under the Safety and Soundness Act, for any new activity, an Enterprise must seek a determination from the Director as to whether the new activity is a new product that is subject to FHFA prior approval. ^5 Before taking a decision on a new product proposal, the Safety and Soundness Act requires the Director to provide the public with notice and an opportunity to comment on the proposal and prescribes a 30-day public notice period. ^6 The Safety and Soundness Act also specifies the standards that must be considered by the Director in acting on a new product proposal. ^7 Those standards specifically require the Director to make a determination that the proposed new product is in the public interest.
^4 See generally, 12 U.S.C. 4541.
^5 12 U.S.C. 4541(e)(2).
^6 12 U.S.C. 4541(c).
^7 12 U.S.C. 4541(b).
FHFA implements these statutory requirements through its regulation on Prior Approval for Enterprise Products. ^8 The regulation establishes a framework for identifying new activities and new products and a process for an Enterprise to provide FHFA with advance notice of a new activity and to request prior approval of a new product. ^9 The regulation also describes the factors that the Director may consider when determining whether a proposed new product is in the public interest. Those factors fall into three broad categories: (1) the impact of the new product on the Enterprise's public mission; (2) the impact of the new product on the stability of mortgage finance or financial system; and (3) the impact of the new product on the competitiveness of the housing finance market. ^{10} In addition to the enumerated public interest factors, the Director retains the discretion to seek public comment on any other appropriate factor.
^8 12 CFR part 1253.
^9 12 CFR 1253.3 and 1253.4.
^{10} 12 CFR 1253.4(b) and 1253.6(e).
FHFA has determined that Freddie Mac's proposed purchase of closed-end second mortgage loans is a new product for Freddie Mac that merits public notice and comment about whether it is in the public interest. ^{11} In turn, Freddie Mac has requested FHFA's approval to proceed with the proposed new product. Consistent with statutory and regulatory requirements, FHFA is seeking public comment on the proposed new product, including on the public interest factors set forth in the regulation and additional factors which the Director has determined to be appropriate. The Director will consider all public comments received by the closing date of the comment period to inform the determination as to whether the proposed new product is in the public interest. ^{12}
^{11} See, 12 CFR 1253.3(a)(1).
^{12} 12 CFR 1253.6(b)(3).

B. Freddie Mac's Charter Act
One element of assessing the public interest is examining the degree to which the new product might advance any of the purposes of the Federal Home Loan Mortgage Corporation Act (charter act). ^{13} Congress created Freddie Mac to serve four public purposes: “(1) provide stability in the secondary market for residential mortgages; (2) respond appropriately to the private capital market; (3) provide ongoing assistance to the secondary market for residential mortgages (including activities relating to mortgages on housing for low- and moderate-income families involving a reasonable economic return that may be less than the return earned on other activities) by increasing the liquidity of mortgage investments and improving the distribution of investment capital available for residential mortgage financing; and (4) promote access to mortgage credit throughout the Nation (including central cities, rural areas, and underserved areas) by increasing the liquidity of mortgage investments and improving the distribution of investment capital available for residential mortgage financing.” ^{14}
^{13} 12 U.S.C. 1451 et seq.
^{14} 12 U.S.C. 1451 note.
Freddie Mac must operate within the confines of the powers expressly granted to it by Congress under its charter act, and the exercise of those powers must fulfill one or more of the statutory purposes that Congress articulated in the charter act. Section 305(a)(4) of the charter act specifically authorizes Freddie Mac to purchase, service, sell, lend on the security of and deal with subordinate mortgages secured by a single-family or multifamily property, provided certain conditions are met. ^{15}
^{15} 12 U.S.C. 1454(a)(4).

II. The Proposed New Product

A. Objective
In the current housing market, marked by higher mortgage rates, low housing supply, and continued year-over-year house price appreciation, existing borrowers face limited options to access the equity in their primary residences. For the many homeowners who purchased or refinanced their homes during a period of lower mortgage rates, a traditional cash-out refinance today may pose a significant financial burden, as it requires a refinancing of the entire outstanding loan balance at a new, and likely much higher, interest rate. Homeowners may also use second mortgages to access the equity in their homes. For a second mortgage, only the smaller, second mortgage would be subject to the current market rate, as the original terms of the first mortgage would remain intact. Moreover, second mortgages are typically offered at a lower interest rate than some financing alternatives such as consumer or personal loans.
Freddie Mac proposes to purchase certain closed-end second mortgage loans from primary market lenders who are approved to sell mortgage loans to Freddie Mac (Sellers). In a closed-end second mortgage loan, the borrower's funds are fully disbursed when the loan closes, the borrower repays over a set time schedule, and the mortgage is recorded in a junior lien position in the land records. Freddie Mac has indicated that the primary goal of this proposed new product is to provide borrowers a lower cost alternative to a cash-out refinance in higher interest rate environments. Purchase parameters would seek to minimize credit risk to Freddie Mac while balancing with potential cost saving to existing homeowners.

B. Key Offering Parameters
The following tables contain Freddie Mac's proposed parameters which help describe the proposed new product. There are two tables indicating the various parameters; one table focuses on general eligibility while the other table focuses on servicing and underwriting. The requirement field in the tables below represents the important criteria and features of the proposed new product. The observation field indicates how the specific requirements would assist Freddie Mac in managing the proposed new product to have a positive effect in the relevant marketplace. These items are potential considerations to minimize risk and assist with an efficient operational process.
Table 1—General Eligibility
Terms | Requirement | Observation
Seller Participation | Seller must be an approved and active Seller/Servicer to Freddie Mac. | Ability to meet the financial and counterparty standards to sell loans to Freddie Mac.
Second Mortgage | Freddie Mac will only purchase a second mortgage if it currently owns the first mortgage. | Assist with servicing and risk oversight.
Restricted Products | Certain second mortgages would be ineligible such as land trusts and co-operative share mortgages. | Minimize additional layers of risk due to complexity and terms.
Evaluation Period | Limitations on the number and aggregate unpaid principal balance of second mortgage purchases for an initial period. | Provide an opportunity to manage risk and create the infrastructure to support possible future growth.
Loan Terms | Fixed-rate fully amortizing loan up to a 20-year term on borrower's primary residence. | Fixed and stable payment for the borrower.
Loan Acquisition: Commitments & Delivery | Second mortgages would initially be delivered through the Cash Window. | Help manage the market risk in the pipeline.
Pricing | Freddie Mac would initially provide “spot bids” rather than forward prices to its Sellers. | Help achieve appropriate risk vs. return ratios.
Securitization | Loans would remain in portfolio for approximately six to nine months until the creation of second mortgage non-TBA guaranteed securities and for systems implementation. | Allow for Credit Risk Transfer opportunities that would be evaluated in subsequent phases.
Table 2—Servicing & Underwriting Eligibility
Terms | Requirement | Observation
Loan Servicing | Overall servicing for second mortgages would be similar to servicing requirements for current first mortgages. | Consistency with servicing and risk oversight.
Loss Mitigation | Overall loss mitigation servicing for second mortgages would be comparable to current servicing requirements for delinquent first mortgages. Specific loss mitigation solutions for all foreclosure activities on the closed-end second mortgage would require Freddie Mac approval. | Freddie Mac could holistically review the performance of both loans.
Manual Underwriting | Initially, the Seller would manually underwrite the mortgage. | Interim approach until automated underwriting is available.
Maximum Total Loan-to- Value (TLTV) ratio | <= 80%, Manufactured Home <= 65%, Not to exceed the maximum LTV/TLTV for cash-out refinance mortgage. | Helps maintain acceptable risk levels.
Payoffs | If the first mortgage is refinanced the second mortgage must be paid in full with the first mortgage unless prohibited by law. | Avoids Freddie Mac master servicing only second mortgages.
Representation and Warranty (R&W) Framework | R&W framework for the second mortgage and the first mortgage, if applicable, would be applied independently. | Encourages independent and holistic quality control measures.

A. Potential Impact
Freddie Mac's proposed new product may impact various stakeholders such as borrowers, Freddie Mac, and the relevant market participants.

Potential Borrower Benefit
In the current mortgage interest rate environment, a closed-end second mortgage may provide a more affordable option to homeowners than obtaining a new cash-out refinance or leveraging other consumer debt products. A significant portion of borrowers have low interest rate first mortgages, and the proposal would allow those homeowners to retain this beneficial interest rate on the first mortgage and avoid resetting to a higher rate through a cash-out refinance. ^{16}
^{16} U.S. Economic, Housing and Mortgage Market Outlook, Freddie Mac (December 2023), p. 4, available at https://www.freddiemac.com/research/pdf/Freddie_Mac_Outlook_December_2023.pdf.
The following table is an illustrative example of a borrower having two distinct choices to access the $30,000 equity available in their current home. In Option A, the closed-end second mortgage, the borrower retains their existing three percent fixed rate mortgage, which has an initial unpaid principal balance (UPB) of $150,000 and current UPB of $120,000. The borrower obtains a second mortgage for $30,000 at a fixed interest rate of 9.5 percent for a 20-year term.
In Option B, the cash-out refinance, the borrower obtains a cash-out refinance at a hypothetical mortgage interest rate of 7.5 percent. The borrower refinances into a new first mortgage with a new principal balance of $150,000 and pays off the original first mortgage with an outstanding UPB of $120,000, retaining $30,000 to use for their personal benefit.
^{17} Refinance Rates Slide Down Again: Mortgage Refinance Rates for March 18, 2024—CNET Money, available at https://www.cnet.com/personal-finance/mortgages/mortgage-interest-rates-today/. “Refinance rates are currently between 6.5% and 7.5%, but your personal interest rate will depend on your credit history, financial profile and application.”
^{18} Current Home Equity Interest Rates | Bankrate, the home equity loan average rate range is 8.41%—9.49%, available at https://www.bankrate.com/home-equity/current-interest-rates/?zipCode=20024.
^{19} This amount reflects life of loan interest costs on both mortgages.
^{20} This amount does not include mortgage interest already paid on the prior mortgage.
Table 3—Illustrative Comparison of Cash-Out Refinance to a Second Mortgage Using Freddie Mac Provided Information
| Option A | Option B
Scenario | • Maintain First Mortgage • Origination UPB $150,000 • Current First Mortgage UPB $120,000 • Obtain a Second Mortgage for $30,000 | • Cash-out refinance for $150,000. • Payoff Existing First Mortgage for $120,000. • Borrower Receives $30,000 cash.
First Mortgage Initial terms | 3% fixed rate 360-month term Originated ~ 8.5 years ago | 7.5% fixed rate ^{17} . 360-month term. Originated in 2024.
Current First Mortgage UPB and terms | $120,000 258 remaining months | $150,00.0 360 remaining months.
First Mortgage Monthly Payment | $632.41 | $1,048.82.
Second Mortgage UPB and terms | $30,000 9.5% fixed rate ^{18} 240 payments | N/A.
Second Mortgage Monthly Payment | $279.64 | N/A.
Total First and Second Mortgage Monthly Payment (if any) Amounts | $912.05 | $1,048.82.
Total First and Second Mortgage Interest Paid (if any) by Borrower | ^{19} $114,779 | $227,576 ^{20} .
Table 3 above illustrates the potential borrower's savings between the two options for the total monthly loan payment amounts, Option A (closed-end second mortgage) [$632.41 + $279.64 = $912.05]; Option B (cash-out refinance) [$1048.82]. In this scenario the borrower will save $136.77 per month by choosing Option A, the closed-end second mortgage. Table 3 also illustrates the total interest savings from a closed-end second mortgage. It specifically highlights the lower costs of the closed-end second mortgage (Option A) [$77,666 first mortgage + $37,113 second mortgage = $114,779 total interest paid] versus the cash-out refinance (Option B) [$227,576 total interest paid]. Thus, the closed-end second mortgage saves the borrower $112,797 in total interest paid compared to the cash-out refinance. The savings to the borrower could vary by the interest rates and the loan terms.
Borrowers may possibly benefit from lower costs if more lenders offer closed-end second mortgages. If there is more competition among second mortgage lenders, this may provide borrowers with more lender choices and better pricing to further reduce their costs.

Potential Enterprise Impact
Freddie Mac believes the proposed new product may advance its charter act purposes by providing liquidity and stability in the secondary mortgage market. Freddie Mac also believes it could provide a foundation for more consistent liquidity in the secondary mortgage market because of its credit guarantee and experience securitizing mortgage loans. Freddie Mac believes that the shorter duration of the second mortgage term as described in table 1, relative to a typical 30-year cash-out refinance, would lower Freddie Mac's credit risk relative to a cash-out refinance while providing borrowers with significant cost savings due to the interest savings on a shorter repayment schedule. Finally, Freddie Mac would specifically review and develop compliance and technology risk mitigation strategies for this proposed new product.
Since Freddie Mac would only purchase a closed-end second mortgage if it has purchased the first mortgage, Freddie Mac would have insight into the performance of both loans, enabling better risk management by providing consistent servicing support for both mortgages. Moreover, loss mitigation activities for closed-end second mortgages would be similar to Freddie Mac's current solutions available for first mortgages. Certain loss mitigation solutions or proceeding with foreclosure on second mortgages would be decided by Freddie Mac, not the servicer. The borrower's lower cost of credit and the servicer's holistic approach should provide more sustainability and thus the potential for lower credit losses for Freddie Mac.

Potential Market and Seller Impacts
Financial institutions who choose to originate and/or buy closed-end second mortgages could securitize the loans or hold them on their balance sheet. Freddie Mac's involvement could provide participating Sellers with additional liquidity which could be beneficial in creating lending opportunities for more borrowers. Sellers would have an additional secondary market option to consider for obtaining their most favorable execution terms.
Sellers targeted for this proposed new product would be all lenders that are currently offering closed-end second mortgages or plan to offer such mortgages in the near term. Freddie Mac expects to be able to provide Sellers with pricing that would enable them to offer rates competitive with current market rates for closed-end second mortgages.
Current mortgage-backed securities (MBS) investors may experience slower pre-payment speeds if borrowers decided against a cash-out refinance. The retention of the existing mortgage avoids a payoff transaction to the MBS. This could be beneficial to investors by enabling them to realize a more predictable and consistent rate of return.
The proposed new product may provide data and process standardization to drive operational efficiency and assist with servicing the loans. Increasing secondary market transactions across many lenders may improve operational processes and data standards. Freddie Mac's ownership of both loans reduces the challenges of obtaining concurrence for loss mitigation solutions on the closed-end second mortgage and may assist with holistic borrower retention activities including loan modifications.

III. Request for Comments
FHFA requests comments on the questions below. Commenters do not need to answer each question. Please identify the question answered by the number assigned below.
1. To what degree might the proposed new product advance any of the purposes set forth in Freddie Mac's charter act ( see section I.B above)?
2. To what degree might the proposed new product advance Freddie Mac's Duty to Serve Underserved Markets activities ^{21} and support Freddie Mac in meeting its housing goals? ^{22}
^{21} Under the Safety and Soundness Act, the Enterprises have a statutory duty to serve three specified underserved markets—manufactured housing, affordable housing preservation, and rural housing—by increasing the liquidity for mortgage investments and improving the distribution of investment capital available for residential financing for very low-, low-, and moderate-income families in those markets. 12 U.S.C. 4565; 12 CFR part 1282.
^{22} As required by the Safety and Soundness Act, the Director establishes annual housing goals with respect to mortgage purchases by the Enterprises. 12 U.S.C. 4561, 12 CFR part 1282. Purchases of subordinate lien mortgages, including the proposed new product, would not be treated as mortgage purchases for purposes of Freddie Mac's housing goals. 12 CFR 1282.16(b)(10).
3. To what degree might the proposed new product already be supplied by other market participants?
4. To what degree might the proposed new product promote or lessen competition in the marketplace?
5. To what degree might the proposed new product overcome natural market barriers or inefficiencies?
6. To what degree might the proposed new product raise or mitigate risks to the mortgage finance or financial system?
7. To what degree might the proposed new product further fair housing and fair lending?
8. To what degree might borrowers benefit from or be adversely affected by the proposed new product?
9. Are there any other factors that the Director should take into consideration concerning the proposed new product?
Sandra L. Thompson,

Director, Federal Housing Finance Agency.
FEDERAL RESERVE SYSTEM
Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company
The notificants listed below have applied under the Change in Bank Control Act (Act) (12 U.S.C. 1817(j)) and 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the applications are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The public portions of the applications listed below, as well as other related filings required by the Board, if any, are available for immediate inspection at the Federal Reserve Bank(s) indicated below and at the offices of the Board of Governors. This information may also be obtained on an expedited basis, upon request, by contacting the appropriate Federal Reserve Bank and from the Board's Freedom of Information Office at https://www.federalreserve.gov/foia/request.htm. Interested persons may express their views in writing on the standards enumerated in paragraph 7 of the Act.
Comments received are subject to public disclosure. In general, comments received will be made available without change and will not be modified to remove personal or business information including confidential, contact, or other identifying information. Comments should not include any information such as confidential information that would not be appropriate for public disclosure.
Comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors, Ann E. Misback, Secretary of the Board, 20th Street and Constitution Avenue, NW, Washington DC 20551-0001, not later than May 7, 2024.
A. Federal Reserve Bank of Dallas (Karen Smith, Director, Mergers & Acquisitions) 2200 North Pearl Street, Dallas, Texas 75201-2272. Comments can also be sent electronically to Comments.applications@dal.frb.org:
1. Sandra Davis Maddox, Dallas, Texas; to retain voting shares of First West Texas Bankshares, Inc., and thereby indirectly retain voting shares of West Texas National Bank, both of Midland, Texas.
In addition, David Lynn Davis, as executor of the Estate of Michael Keith Davis and as trustee of the Michael K. Davis Family Trust and the Michael K. Davis Marital Trust, Nicholas Andrew Davis, as trustee of the Nicholas Andrew Davis Exempt GST Trust and the Nicholas Andrew Davis Non-Exempt GST Trust, Eric Ryan Davis, individually and as trustee of the Eric R. Davis Exempt GST Trust and the Eric R. Davis Non-Exempt GST Trust, and Richard Dell Hatchett, all of Midland, Texas; Jeffrey Lyle Maddox, as trustee of the Jeffrey L. Maddox Exempt GST Trust and the Jeffrey L. Maddox Non-Exempt GST Trust, and Amber Lynette Klimczak, as trustee of the Amber L. Maddox Exempt GST Trust and the Amber L. Maddox Non-Exempt GST Trust, all of Dallas, Texas; Brian Lee Maddox, as executor of the Estate of Lori Davis Winter, and as trustee of the Brian L. Maddox Exempt GST Trust and the Brian L. Maddox Non-Exempt GST Trust, Alexander Nolan Davis, and Christopher Lane Maddox, as trustee of the Christopher L. Maddox Exempt GST Trust and the Christopher L. Maddox Non-Exempt GST Trust, all of Houston, Texas; Amy Louise Patyk, as trustee of the Amy L. Maddox Exempt GST Trust and the Amy L. Maddox Non-Exempt GST Trust, all of Fort Worth, Texas; Dawn Marie Belizaire, as trustee of the Dawn M. Davis Exempt GST Trust and the Dawn M. Davis Non-Exempt GST Trust, all of Jamaica Plain, Massachusetts; Matthew Lynn Davis, as trustee of the Matthew L. Davis Exempt GST Trust and the Matthew L. Davis Non-Exempt GST Trust, all of Coppell, Texas; and Randall Keith Moore of Slaton, Texas; to join the Davis/Maddox family group, a group acting in concert, to acquire voting shares of First West Texas Bankshares, Inc., and thereby indirectly acquire voting shares of West Texas National Bank, both of Midland, Texas. David Lynn Davis and Nicholas Andrew Davis are members of the Davis/Maddox family group and were both previously permitted by the Federal Reserve System to acquire control of voting shares of First West Texas Bankshares, Inc.
Board of Governors of the Federal Reserve System.
Michele Taylor Fennell,

Deputy Associate Secretary of the Board.
GENERAL SERVICES ADMINISTRATION
[Notice-PBS-2024-04; Docket No. 2024-0002; Sequence No. 12]
Notice of Adoption of the U.S. Department of Energy's Electric Vehicle Charging Stations Categorical Exclusion Pursuant to Section 109 of the National Environmental Policy Act

AGENCY:
Public Buildings Service, U.S. General Services Administration (GSA).

ACTION:
Notice.

SUMMARY:
GSA is adopting the U.S. Department of Energy's (DOE) electric vehicle charging stations categorical exclusion (CATEX) pursuant to section 109 of the National Environmental Policy Act (NEPA) to use for proposed GSA actions. This notice describes the categories of proposed actions for which GSA intends to use DOE's electric vehicle charging stations CATEX and details the consultation between the agencies.

DATES:
Applicable April 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Greg Graybadger, Director, Real Property Valuation Division, GSA Public Buildings Service, Office of Portfolio Management & Customer Engagement, by phone at 208-863-5969 or by email at gregory.graybadger@gsa.gov.

SUPPLEMENTARY INFORMATION:

• Background
NEPA, as amended at 42 U.S.C. 4321-4347, requires all Federal agencies to assess the environmental impact of their actions. Congress enacted NEPA in order to encourage productive and enjoyable harmony between humans and the environment, recognizing the profound impact of human activity and the critical importance of restoring and maintaining environmental quality to the overall welfare of humankind. 42 U.S.C. 4321. NEPA's twin aims are to ensure that agencies consider the environmental effects of their proposed actions in their decision-making processes and inform and involve the public in that process. 42 U.S.C. 4331. NEPA created the Council on Environmental Quality (CEQ), which promulgated NEPA implementing regulations, 40 CFR parts 1500 through 1508 (CEQ regulations).
To comply with NEPA, agencies determine the appropriate level of review—an environmental impact statement (EIS), an environmental assessment (EA), or a CATEX. 42 U.S.C. 4336. If a proposed action is likely to have significant environmental effects, the agency must prepare an EIS and document its decision in a record of decision. 42 U.S.C. 4336. If the proposed action is not likely to have significant environmental effects or the effects are unknown, the agency may instead prepare an EA, which involves a more concise analysis and process than an EIS. 42 U.S.C. 4336. Following the EA, the agency may conclude the process with a finding of no significant impact if the analysis shows that the action will have no significant effects. If the analysis in the EA finds that the action is likely to have significant effects, however, then an EIS is required.
Under NEPA and the CEQ regulations, a federal agency also can establish in its NEPA implementing procedures CATEXs, which are categories of actions that the agency has determined normally do not significantly affect the quality of the human environment. 42 U.S.C. 4336(e)(1), 1507.3(e)(2)(ii), 1508.1(d). If an agency determines that a CATEX covers a proposed action, it then evaluates the proposed action for extraordinary circumstances in which a normally excluded action may have a significant effect. 40 CFR 1501.4(b). If no extraordinary circumstances are present or if further analysis determines that the extraordinary circumstances do not involve the potential for significant environmental impacts, the agency may apply the CATEX to the proposed action without preparing an EA or EIS. 42 U.S.C. 4336(a)(2), 40 CFR 1501.4. If the extraordinary circumstances have the potential to result in significant effects, the agency is required to prepare an EA or EIS.
Section 109 of NEPA, enacted as part of the Fiscal Responsibility Act of 2023, allows a Federal agency to adopt a CATEX listed in another agency's NEPA procedures for a category of proposed agency actions. 42 U.S.C. 4336. To use another agency's CATEXs under Section 109, an agency must identify the relevant CATEXs listed in that agency's (the “establishing agency”) NEPA procedures that cover its category of proposed actions or related actions; consult with the establishing agency to ensure that the proposed adoption of the CATEX to a category of actions is appropriate; identify to the public the CATEX that the agency plans to use for its proposed actions; and document adoption of the CATEX. 40 CFR 1506.3.
This notice documents GSA's adoption of DOE's electric vehicle charging stations CATEX under section 109 of NEPA.

• Identification of the Categorical Exclusion

DOE's Electric Vehicle Charging Stations CATEX
DOE's electric vehicle charging stations CATEX is codified in DOE's NEPA procedures as CATEX B5.23 of 10 CFR part 1021, subpart D, appendix B, as follows:
B5.23 Electric Vehicle Charging Stations: The installation, modification, operation, and removal of electric vehicle charging stations, using commercially available technology, within a previously disturbed or developed area. Covered actions are limited to areas where access and parking are in accordance with applicable requirements (such as local land use and zoning requirements) in the proposed project area and would incorporate appropriate control technologies and best management practices.
“Previously disturbed or developed” refers to land that has been changed such that its functioning ecological processes have been and remain altered by human activity. The phrase encompasses areas that have been transformed from natural cover to non-native species or a managed State, including, but not limited to, utility and electric power transmission corridors and rights-of-way, and other areas where active utilities and currently used roads are readily available. 10 CFR 1021.410(g)(1).
The DOE electric vehicle charging stations CATEX also includes additional conditions referred to as integral elements. (10 CFR part 1021) In order to apply this CATEX, the proposal must be one that would not:
(1) Threaten a violation of applicable statutory, regulatory, or permit requirements for environment, safety, and health, or similar requirements of GSA or executive orders;
(2) Require siting and construction or major expansion of waste storage, disposal, recovery, or treatment facilities (including incinerators), but the proposal may include categorically excluded waste storage, disposal, recovery, or treatment actions or facilities;
(3) Disturb hazardous substances, pollutants, contaminants, or CERCLA-excluded petroleum and natural gas products that preexist in the environment such that there would be uncontrolled or unpermitted releases;
(4) Have the potential to cause significant impacts on environmentally sensitive resources. An environmentally sensitive resource is typically a resource that has been identified as needing protection through Executive Order, statute, or regulation by Federal, State, or local government, or a federally recognized Indian Tribe. An action may be categorically excluded if, although sensitive resources are present, the action would not have the potential to cause significant impacts on those resources (such as construction of a building with its foundation well above a sole-source aquifer or upland surface soil removal on a site that has wetlands). Environmentally sensitive resources include, but are not limited to:
(i) Property (such as sites, buildings, structures, and objects) of historic, archeological, or architectural significance designated by a Federal, State, or local government, federally recognized Indian Tribe, or Native Hawaiian organization, or property determined to be eligible for listing on the National Register of Historic Places;
(ii) Federally listed threatened or endangered species or their habitat (including critical habitat) or federally proposed or candidate species or their habitat (Endangered Species Act); State-listed or State-proposed endangered or threatened species or their habitat; federally protected marine mammals and Essential Fish Habitat (Marine Mammal Protection Act; Magnuson-Stevens Fishery Conservation and Management Act); and otherwise federally protected species (such as the Bald and Golden Eagle Protection Act or the Migratory Bird Treaty Act);
(iii) Floodplains and wetlands;
(iv) Areas having a special designation such as federally and State-designated wilderness areas, national parks, national monuments, national natural landmarks, wild and scenic rivers, State and Federal wildlife refuges, scenic areas (such as National Scenic and Historic Trails or National Scenic Areas), and marine sanctuaries;
(v) Prime or unique farmland, or other farmland of Statewide or local importance, as defined at 7 CFR 658.2(a), “Farmland Protection Policy Act: Definitions,” or its successor;
(vi) Special sources of water (such as sole-source aquifers, wellhead protection areas, and other water sources that are vital in a region); and
(vii) Tundra, coral reefs, or rain forests; or
(5) Involve genetically engineered organisms, synthetic biology, governmentally designated noxious weeds, or invasive species, unless the proposed activity would be contained or confined in a manner designed and operated to prevent unauthorized release into the environment and conducted in accordance with applicable requirements, such as those of the Department of Agriculture, the Environmental Protection Agency, and the National Institutes of Health.

Proposed GSA Category of Actions
DOE's electric vehicle charging stations CATEX allows for the installation, modification, operation, and removal of electric vehicle charging stations. GSA intends to apply this CATEX to electric vehicle charging station projects undertaken directly by GSA, to electric vehicle charging station actions requiring an approval by GSA, or to electric vehicle charging station projects financed in whole or in part through Federal funds made available by GSA.
GSA will consider each proposal for electric vehicle charging stations to ensure that the proposal is within the scope of the CATEX. GSA intends to apply this CATEX in a manner consistent with DOE's application to the same types of proposals.

• Consideration of Extraordinary Circumstances
When applying this CATEX, GSA will evaluate the proposed action to ensure evaluation of integral elements listed above. In addition, in considering extraordinary circumstances, GSA will consider whether the proposed action has the potential to result in significant effects as described in DOE's extraordinary circumstances listed at 10 CFR 1021.410(b)(2). DOE defines extraordinary circumstances as unique situations presented by specific proposals, including, but not limited to, scientific controversy about the environmental effects of the proposal; uncertain effects or effects involving unique or unknown risks; and unresolved conflicts concerning alternative uses of available resources.

• Consultation With DOE and Determination of Appropriateness
GSA and DOE consulted on the appropriateness of GSA's adoption of the CATEX in January 2024. This consultation included a review of DOE's experience developing and applying the CATEX, as well as the types of actions for which GSA plans to utilize the CATEX. Based on this consultation and review, GSA has determined that the types of projects it intends to undertake to install, operate, modify, or remove electric vehicle charging stations are substantially similar to such projects for which DOE has applied the CATEX. Accordingly, the impacts of GSA projects will be very similar to the impacts of DOE projects, which are not significant, absent the existence of extraordinary circumstances that could involve potentially significant impacts. Therefore, GSA has determined that its proposed use of the electric vehicle charging stations CATEX as described in this notice would be appropriate.

• Notice to the Public and Documentation of Adoption
This notice serves to identify to the public and document GSA's adoption of DOE's CATEX for electric vehicle charging stations. The notice also identifies the types of actions to which GSA will apply the CATEX, as well as the considerations that GSA will use in determining whether an action is within the scope of the CATEX. Upon issuance of this notice, the adopted electric vehicle charging stations CATEX will be available to GSA.
Elliot Doomes,

Commissioner, Public Buildings Service, U.S. General Services Administration.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Centers for Disease Control and Prevention
Solicitation of Nominations for Appointment to the CDC/HRSA Advisory Committee on HIV, Viral Hepatitis and STD Prevention and Treatment

AGENCY:
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).

ACTION:
Notice.

SUMMARY:
In accordance with the Federal Advisory Committee Act, the Centers for Disease Control and Prevention (CDC), within the Department of Health and Human Services (HHS), is seeking nominations for membership on the CDC/HRSA Advisory Committee on HIV, Viral Hepatitis and STD Prevention and Treatment (CHAC). CHAC consists of 18 experts in fields associated with public health; epidemiology; laboratory practice; immunology; infectious diseases; substance use disorder; behavioral science; health education; healthcare delivery; state health programs; clinical care; preventive health; medical education; health services and clinical research; health equity; and healthcare financing, who are selected by the Secretary, HHS.

DATES:
Nominations for membership on CHAC must be received no later than October 1, 2024. Packages received after this time will not be considered for the current membership cycle.

ADDRESSES:
All nominations should be emailed to nchhstppolicy@cdc.gov with the subject line “CHAC 2025 Nomination.”

FOR FURTHER INFORMATION CONTACT:
Marah Condit, M.S., Committee Management Lead, Office of Policy, Planning, and Partnerships, National Center for HIV, Viral Hepatitis, STD, and TB Prevention, Centers for Disease Control and Prevention, 1600 Clifton Road NE, Mailstop US8-6, Atlanta, Georgia 30329-4027. Telephone: (404) 639-3423; Email: nchhstppolicy@cdc.gov.

SUPPLEMENTARY INFORMATION:
The Secretary, Department of Health and Human Services (HHS), and by delegation, the Director, Centers for Disease Control and Prevention (CDC), and the Administrator, Health Resources and Services Administration (HRSA), are authorized by the Public Health Service Act to: (1) conduct, encourage, cooperate with, and assist other appropriate public health authorities, scientific institutions, and scientists in the conduct of research, investigations, experiments, demonstrations, and studies relating to the causes, diagnosis, treatment, control, and prevention of physical and mental diseases and other impairments; (2) assist states and their political subdivisions in preventing, suppressing, and treating communicable diseases and other preventable conditions and in promoting health and well-being; (3) assist public and non-profit private entities in preventing, controlling and treating sexually transmitted diseases (STDs), including the human immunodeficiency virus (HIV); (4) improve health and achieve health equity through access to quality services and a skilled health workforce and innovative programs; (5) support healthcare services to persons with or who experience risk for HIV, viral hepatitis, and other STDs; (6) advance the education of health professionals and the public about HIV, viral hepatitis, and other STDs; and (7) improve adolescent and school health as it pertains to HIV, viral hepatitis, and STDs.
The CDC/HRSA Advisory Committee on HIV, Viral Hepatitis and STD Prevention and Treatment (CHAC) meets at least two times each calendar year, or at the discretion of the Designated Federal Officers in consultation with the CHAC co-chairs.
HHS policy stipulates that committee membership be balanced in terms of points of view represented and the committee's function. Appointments shall be made without discrimination on the basis of age, race, ethnicity, gender, sexual orientation, gender identity, HIV status, disability, and cultural, religious, or socioeconomic status. Nominees must be U.S. citizens and cannot be full-time employees of the U.S. Government. Current participation on Federal workgroups or prior experience serving on a Federal advisory committee does not disqualify a candidate; however, HHS policy is to avoid excessive individual service on advisory committees and multiple committee memberships. The CHAC charter stipulates that the Committee must include at least four members who are persons with HIV. The Committee may also include representation from persons with lived experience, such as those who have experienced viral hepatitis, STDs, and drug use; state and local health and education agencies; HIV/viral hepatitis/STD community-based organizations; and the ethics or faith-based community.
Committee members are Special Government Employees, requiring the filing of financial disclosure reports at the beginning of and annually during their terms. Individuals who are selected for appointment will be required to provide detailed information regarding their financial interests and, for example, any work they do for the federal government through research grants or contracts. Disclosure of this information is required in order for CDC ethics officials to determine whether there is a conflict between the SGE's public duties as a member of CHAC and the SGE's private interests, including an appearance of a loss of impartiality as defined by Federal laws and regulations, and to identify any required remedial action needed to address the potential conflict.
CDC and HRSA review potential candidates for CHAC membership when a vacancy arises and provide a slate of nominees for consideration to the Secretary of HHS for final selection. CDC and HRSA each publish a Federal Register notice and will be using a joint process to nominate nominees on a rolling basis; thus, applications received by CDC will be shared with HRSA for consideration. Therefore, potential candidates need only apply in response to one of the Federal Register notices. HHS notifies selected candidates of their appointment near the start of the term in December 2025, or as soon as the HHS selection process is completed. Note that the need for different expertise varies from year to year and a candidate who is not selected in one year may be reconsidered in a subsequent year.
Candidates should submit the following items:
A letter of interest or personal statement from the nominee stating how the nominee's expertise would inform the work of CHAC
A biographical sketch of the nominee (500 words or fewer)
Current curriculum vitae or resume, including complete contact information (telephone numbers, mailing address, and email address)
At least one letter of recommendation from person(s) not employed by HHS. Candidates may submit letter(s) from current HHS employees if they wish, but at least one letter must be submitted by a person not employed by an HHS agency ( e.g., CDC, National Institutes of Health, Food and Drug Administration).
Nominations may be submitted by the candidate or by the person/organization recommending the candidate. CDC and HRSA will collect and retain nominations received for up to two years to create a pool of potential CHAC nominees. When a vacancy occurs, CDC and HRSA will review nominations and may contact nominees at that time.
The Director, Office of Strategic Business Initiatives, Office of the Chief Operating Officer, Centers for Disease Control and Prevention, has been delegated the authority to sign Federal Register notices pertaining to announcements of meetings and other committee management activities, for both the Centers for Disease Control and Prevention and the Agency for Toxic Substances and Disease Registry.
Kalwant Smagh,

Director, Office of Strategic Business Initiatives, Office of the Chief Operating Officer, Centers for Disease Control and Prevention.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Centers for Disease Control and Prevention
Meeting of the Board of Scientific Counselors, Office of Readiness and Response

AGENCY:
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).

ACTION:
Notice of meeting.

SUMMARY:
In accordance with the Federal Advisory Committee Act, the Centers for Disease Control and Prevention (CDC) announces the following meeting for the Board of Scientific Counselors, Office of Readiness and Response, (BSC, ORR). This virtual meeting is open to the public. Time will be available for public comment.

DATES:
The meeting will be held on May 23, 2024, from 10 a.m. to 4:30 p.m., EDT.

ADDRESSES:
Zoom virtual meeting. If you wish to attend the meeting, please register in advance by accessing the link at https://cdc.zoomgov.com/webinar/register/WN_kNZWpr8KRVGTGN0ERE_1Cg#/registration. Instructions to access the meeting will be provided following registration.

FOR FURTHER INFORMATION CONTACT:
Dometa Ouisley, Public Health Analyst, Office of Science and Laboratory Readiness, Office of Readiness and Response, Centers for Disease Control and Prevention, 1600 Clifton Road NE, Mailstop H21-6, Atlanta, Georgia 30329-4027. Telephone: (404) 639-7450; Email: DOuisley@cdc.gov.

SUPPLEMENTARY INFORMATION:
Purpose: The Board of Scientific Counselors, Office of Readiness and Response provides advice and guidance to the Secretary, Department of Health and Human Services (HHS); the Assistant Secretary for Health, HHS; the Director, Centers for Disease Control and Prevention (CDC); and the Director, Office of Readiness and Response (ORR), CDC. The Board recommends strategies and goals for readiness and response activities pertaining to programs and research within the agency and the ORR divisions and monitors the overall strategic direction and focus of the ORR divisions and offices. The Board may also perform second-level peer review of applications for grants-in-aid for research and research training activities, cooperative agreements, and research contract proposals relating to the broad areas within the center. For additional information about the Board, please visit https://www.cdc.gov/orr/bsc/index.htm.
Matters to be Considered: Agenda topics for the meeting include: (1) ORR Updates, (2) ORR Division Directors Follow-up Discussion, (3) Polio Containment Working Group Updates, (4) Health Equity Working Group Updates, and (5) ORR Science Agenda Presentation and Discussion. Agenda items are subject to change as priorities dictate.
The Director, Office of Strategic Business Initiatives, Office of the Chief Operating Officer, Centers for Disease Control and Prevention, has been delegated the authority to sign Federal Register notices pertaining to announcements of meetings and other committee management activities, for both the Centers for Disease Control and Prevention and the Agency for Toxic Substances and Disease Registry.
Kalwant Smagh,

Director, Office of Strategic Business Initiatives, Office of the Chief Operating Officer, Centers for Disease Control and Prevention.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Centers for Medicare & Medicaid Services
[CMS-1821-N]
Medicare Program Public Meeting for New Revisions to the Healthcare Common Procedure Coding System (HCPCS) Coding—May 28-30, 2024

AGENCY:
Centers for Medicare & Medicaid Services (CMS), Department of Health and Human Services (HHS).

ACTION:
Notice.

SUMMARY:
This notice announces the dates and times of the virtual Healthcare Common Procedure Coding System (HCPCS) public meeting to be held from May 28, 2024, through May 30, 2024, to discuss CMS' preliminary coding, Medicare benefit category, and payment determinations, if applicable, for new revisions to the HCPCS Level II code set for non-drug and non-biological items and services, as well as how to register for those meetings.

DATES:
Virtual Meeting Dates: Tuesday, May 28, 2024, 9 a.m. to 5 p.m. Eastern Time (ET); Wednesday, May 29, 2024, 9 a.m. to 5 p.m. ET; and Thursday, May 30, 2024, 9 a.m. to 5 p.m. ET.

ADDRESSES:
Virtual Meeting Location: The HCPCS public meetings will be held virtually via Zoom only.

FOR FURTHER INFORMATION CONTACT:
Sundus Ashar, (410) 786-0750, Sundus.ashar1@cms.hhs.gov, or HCPCS@cms.hhs.gov.

SUPPLEMENTARY INFORMATION:

I. Background
On December 21, 2000, Congress enacted the Medicare, Medicaid, and the Children's Health Insurance Program (CHIP) Benefits Improvement and Protection Act of 2000 (BIPA) (Pub. L. 106-554). Section 531(b) of BIPA mandated that the Secretary establish procedures that permit public consultation for coding and payment determinations for new durable medical equipment (DME) under Medicare Part B of title XVIII of the Social Security Act (the Act). In the November 23, 2001, Federal Register (66 FR 58743), we published a notice providing information regarding the establishment of the annual public meeting process for DME.
In 2020, we implemented changes to our HCPCS Level II coding procedures, including the establishment of quarterly coding cycles for drugs and biological products and biannual coding cycles for non-drug and non-biological items and services.
In the December 28, 2021, Federal Register (86 FR 73860), we published a final rule that established procedures for making Medicare benefit category and payment determinations for new items and services that are DME, prosthetic devices, orthotics and prosthetics, therapeutic shoes and inserts, surgical dressings, or splints, casts, and other devices used for reductions of fractures and dislocations under Medicare Part B.

II. Public Meeting Agendas
Prior to registering to attend a virtual public meeting, all potential participants and other attendees are advised to review the public meeting agendas at https://www.cms.gov/Medicare/Coding/MedHCPCSGenInfo/HCPCSPublicMeetings, which identify CMS' preliminary coding, Medicare benefit category, and payment determinations, if applicable, and the date each item will be discussed. In establishing the public meeting agendas, CMS may group multiple, related code applications under the same agenda item.

III. Virtual Meeting Registration
The May 28, 2024, through May 30, 2024, HCPCS public meetings will be virtual and available for remote audio attendance and participation only via Zoom. The Zoom link and registration instructions will be posted in the Guidelines for Participation in HCPCS Public Meetings document on the CMS website at https://www.cms.gov/Medicare/Coding/MedHCPCSGenInfo/HCPCSPublicMeetings and in an announcement on the HCPCS General Information page at https://www.cms.gov/medicare/coding-billing/healthcare-common-procedure-system. The same website also contains detailed information on how attendees can join the virtual public meetings using Zoom, including dial-in information. All individuals who plan to speak (15 or 5 minutes) at the virtual public meetings must register by 5 p.m. ET on Friday, May 17, 2024. All participants and other attendees can access the virtual public meeting through the Zoom link, which will be posted on the HCPCS website. Attendees can attend more than 1 day of the public meeting.

A. Required Information for Registration
The following information must be provided when registering to be a speaker:
• Name;
• Company name (if applicable);
• Email address;
• Any special assistance requests (will be considered if the registration is submitted by 5 p.m. ET, Friday, May 17, 2024);
• Whether the registrant is a primary speaker or a 5-minute speaker for an agenda item;
• Agenda item and application number;
• Whether the primary speaker will use a PowerPoint presentation; and
• Whether the registrant will participate in a practice Zoom session, to be held on Thursday, May 23, 2024.

B. Speakers and Attendees

1. Primary Speakers
Each applicant that submitted a HCPCS Level II code application that will be discussed at the virtual public meetings is permitted to designate a primary speaker. Fifteen minutes is the total time interval for a primary speaker per agenda item. Any unused time from the primary speaker will be forfeited and cannot be delegated to another speaker. The deadline for primary speakers to register and submit any supporting PowerPoint presentation is 5 p.m. ET, Friday, May 17, 2024. CMS will accept PowerPoint presentations if those materials are emailed to HCPCS@cms.hhs.gov by the stated deadline. Due to the timeframe needed for the planning and coordination of the HCPCS virtual public meetings, materials that are not submitted in accordance with this deadline cannot be accommodated.
All PowerPoint presentation materials must not exceed 10 slides and should be in PowerPoint presentation format, not PDF. We will not play videos or animations during the public meeting sessions and request the speakers exclude these materials from their PowerPoint presentation and instead submit any relevant video or animation materials along with the written comments. We request that speakers ensure the presentation does not include any inappropriate content before submission.
Every primary speaker must declare at the beginning of their presentation at the meeting, as well as in their written summary, whether they have any financial involvement with the manufacturer of the item that is the subject of the HCPCS Level II application that the primary speaker presented, or any competitors of that manufacturer with respect to the item. This includes any payment, salary, remuneration, or benefit provided to that speaker by the applicant.

2. 5-Minute Speakers
Any individual related to the public meeting agenda item, including but not limited to, an employee, interested parties, competitor, insurer, public consumer, etc., may register and speak as a 5-minute speaker. The deadline for registering to be a 5-minute speaker is 5 p.m. ET, Friday, May 17, 2024.
Every 5-minute speaker must declare at the beginning of their presentation at the meeting, as well as in their written summary, whether they have any financial involvement with the manufacturer of the item that is the subject of the HCPCS Level II code application or agenda item that the 5-minute speaker presented, or any competitors of that manufacturer with respect to the item. This includes any payment, salary, remuneration, or benefit provided to that speaker by the applicant. We will not accept any other written materials, outside of the written comments, from a 5-minute speaker.

3. All Other Attendees
All individuals who plan to attend the virtual public meetings to listen and do not plan to speak, may access the virtual public meeting using the Zoom link posted on the HCPCS website at https://www.cms.gov/medicare/coding-billing/healthcare-common-procedure-system.
Individuals who require special assistance must register and request special assistance services by 5 p.m. ET, Friday, May 17, 2024.

IV. Written Comments
The primary and 5-minute speaker(s) must email a brief, written summary (one paragraph) of their comments and conclusions. Written comments from anyone, including the primary and 5-minute speaker(s), will only be accepted when emailed to: HCPCS@cms.hhs.gov before 5 p.m. ET on the date of the virtual public meeting at which the HCPCS Level II code application that is the subject of the comments is discussed.

V. Additional Information
The HCPCS section of the CMS website also includes details regarding the public meeting process for new revisions to the HCPCS Level II code set, including information on how to join the meeting remotely, and guidelines for an effective presentation. The HCPCS section of the CMS website also contains a document titled “Healthcare Common Procedure Coding System (HCPCS) Level II Coding Procedures,” which is a description of the HCPCS Level II coding process, including a detailed explanation of the procedures CMS uses to make HCPCS Level II coding determinations.
When CMS refers to a HCPCS code or HCPCS Level II coding application above, CMS may also be referring to circumstances when a HCPCS code has already been issued, but a Medicare benefit category and/or payment has not been determined. CMS is working diligently to address Medicare benefit category and payment determinations for new items and services that may be DME, prosthetic devices, orthotics and prosthetics, therapeutic shoes and inserts, surgical dressings, or splints, casts, and other devices used for reductions of fractures and dislocations under Medicare Part B. Please check the CMS website listed above for the final agenda.

VI. Collection of Information Requirements
This document does not impose information collection requirements, that is, reporting, recordkeeping, or third-party disclosure requirements. Consequently, there is no need for review by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ).
The Administrator of CMS, Chiquita Brooks-LaSure, having reviewed and approved this document, authorizes Trenesha Fultz-Mimms, who is the Federal Register Liaison, to electronically sign this document for purposes of publication in the Federal Register.
Trenesha Fultz-Mimms,

Federal Register Liaison, Centers for Medicare & Medicaid Services.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Administration for Children and Families
Proposed Information Collection Activity; Community Services Block Grant (CSBG) Annual Progress Report (Office of Management and Budget No. 0970-0492)

AGENCY:
Office of Community Services, Administration for Children and Families, U.S. Department of Health and Human Services.

ACTION:
Request for public comments.

SUMMARY:
The Office of Community Services (OCS), Administration for Children and Families (ACF) requests approval of revisions of the Community Services Block Grant (CSBG) Annual Progress Report, (OMB #0970-0492, expiration 6/30/2024). This includes an extension with minor changes to the currently approved Annual Report, a proposed revised version of the Annual Report for use in future fiscal years, the submission of the Tribal Annual Report and Tribal Short Form, and the removal of supplemental funding reports that are no longer in use.

DATES:
Comments due within 60 days of publication. In compliance with the requirements of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, ACF is soliciting public comment on the specific aspects of the information collection described in this notice.

ADDRESSES:
Copies of the proposed collection of information can be obtained and comments may be forwarded by emailing infocollection@acf.hhs.gov. Identify all requests by the title of the information collection.

SUPPLEMENTARY INFORMATION:
Description: Section 678E of the CSBG Act requires States, including the District of Columbia and the Commonwealth of Puerto Rico, and U.S. territories, to annually prepare and submit a report on the measured performance of the State and the eligible entities in the State. Prior to the participation of the State in the performance measurement system, the State shall include in the report any information collected by the State relating to such performance. Each State shall also include in the report an accounting of the expenditure of funds received by the State through the CSBG program, including an accounting of funds spent on administrative costs by the State and the eligible entities, and funds spent by the eligible entities on the direct delivery of local services, and shall include information on the number of and characteristics of clients served under the subtitle in the State, based on data collected from the eligible entities. The State shall also include in the report a summary describing the training and technical assistance offered by the State.
Section 3(b) of the Government Performance and Results (GPRA) Modernization Act of 2010 (GPRAMA) requires OCS, as an office under the U.S. Department of Health and Human Services, to collect performance information for the CSBG. The CSBG Tribal Annual Report enables OCS to collect performance information from Tribal grant recipients. Tribal grant recipients would submit the report annually. This request will support:
1. CSBG Annual Report 2.1—an extension of the current Annual Report form with clarification revisions to be used in Federal fiscal year (FY) 2024 as a requirement to satisfy section 678E of the CSBG Act and then as an optional collection instrument in FY 2025 to support an incremental implementation. An updated version (see next bullet) would become required in FY 2026;
2. CSBG Annual Report 3.0—a substantial revision of the current Annual Report form. This updated version continues to streamline State administrative information, as well as National Performance Indicators for individuals and families as reported by eligible entities. The proposed revisions seek to lessen the burden of the previous iteration of the report by decreasing the amount of data points collected, clarifying data points by using clearer language, removing items not pertinent to annual report data collection, and improving data points to reflect industry standards in measuring the reduction of poverty. This revision would be an optional collection instrument in FY 2025 to support incremental implementation and minimize burden to the public and would become the required sole collection instrument in FY 2026;
3 CSBG Annual Report 3.0 Tribal Annual Report—a modified annual report, derived from the above described CSBG Annual Report 3.0, for CSBG directly funded Tribal grantees receiving more than $50,000. Tribes would be required to report using the Tribal Annual Report to fulfill FY 2024- FY 2026 reporting requirements due each year on March 31; and
4. CSBG Annual Report 3.0 Tribal Short Form—a Tribal short form also derived from Annual Report 3.0. This would be required for use by Tribes directly funded by CSBG below the $50,000 funding threshold beginning in FY 2025. Both the Tribal Annual Report and Tribal Short Form were developed using the revisions of the CSBG Annual Report to provide a comparable reporting schema for directly funded CSBG Tribes commiserate with their funding levels to minimize burden while collecting performance data. Tribes receiving less than $50,000 annual would be required to report using the Tribal Short Form to fulfill FY 2024-FY 2026 reporting requirements due each year on March 31.
5. Supplemental Funding Reports—the discontinuation of the Annual Report Form for the Coronavirus Aid, Relief, and Economic Security (CARES) Act and CSBG Disaster Supplemental Funding. These supplemental funding requests are no longer in use.
Copies of the proposed collections of information can be obtained by visiting: http://www.acf.hhs.gov/programs/ocs/programs/csbg.
Respondents: State governments, including the District of Columbia, the Commonwealth of Puerto Rico, U.S. territories, directly funded federally and State-recognized Tribes and CSBG eligible entities.

Annual Burden Estimates

Estimated Burden—FY24
In FY24, States and Tribal grant recipients would be required to complete the current versions of the Annual Reports.
Instrument | Total number of respondents | Total number of responses per respondent | Average burden hours per response | Annual burden hours
CSBG Annual Report 2.1 (States) | 56 | 1 | 198 | 11,088
CSBG Annual Report 2.1(Eligible Entities) | 1000 | 1 | 493 | 493,000
CSBG Tribal Annual Report | 24 | 1 | 111 | 2,664
CSBG Tribal Annual Report Short Form | 30 | 1 | 40 | 1,200
| FY24 Total Annual Burden Estimates: | | | | 507,952

Estimated Burden—FY25
In FY25, States would have the option to complete the current versions of the Annual Report or the revised version (CSBG Annual Report 3.0). Burden estimates for States and eligible entities assume the greatest number based on the option provided to utilize either reporting schema. Tribal grant recipients would continue to use the current versions.
Instrument | Total number of respondents | Total number of responses per respondent | Average burden hours per response | Annual burden hours
CSBG Annual Report 2.1 (States) | 56 | 1 | 198 | 11,088
CSBG Annual Report 2.1(Eligible Entities) | 1000 | 1 | 493 | 493,000
CSBG Annual Report 3.0 (States) | 56 | 1 | 80 | 4,480
CSBG Annual Report 3.0(Eligible Entities) | 1000 | 1 | 260 | 260,000
CSBG Tribal Annual Report | 24 | 1 | 111 | 2,664
CSBG Tribal Annual Report Short Form | 30 | 1 | 40 | 1,200
FY25 Total Annual Burden Estimates: | | | | 772,432

Estimated Burden—FY26
In FY26, States would be required to complete the revised version of the Annual Report (CSBG Annual Report 3.0). Tribal grant recipients would continue to use the current versions.
Instrument | Total number of respondents | Total number of responses per respondent | Average burden hours per response | Annual burden hours
CSBG Annual Report 3.0 (States) | 56 | 1 | 80 | 4,480
CSBG Annual Report 3.0(Eligible Entities) | 1000 | 1 | 260 | 260,000
CSBG Tribal Annual Report | 24 | 1 | 111 | 2,664
CSBG Tribal Annual Report Short Form | 30 | 1 | 40 | 1,200
FY26 Total Annual Burden Estimates: | | | | 268,344

Total Estimated Burden Over Three Years
Fiscal year | Estimated annual burden
2024 | 507,952
2025 | 772,432
2026 | 268,344
Total: | 1,548,728
Comments: The Department specifically requests comments on the following:
1. Whether the proposed collection of information is necessary for the proper performance measurement of Federal, State, or local agencies.
2. The quality of the information to be collected.
3. The clarity of the information to be collected.
4. Does the information to be collected produce significant burden? If so, how could the burden be minimized on respondents, including through the use of automated collection techniques or other forms of technology?
5. The accuracy of the agency's estimate of the burden of the proposed collection of information.
6. What, if any, additions, revisions, or modifications to the information collection would you suggest?
Consideration will be given to comments and suggestions submitted within 60 days of this publication.
Authority: 112 Stat. 2729; 42 U.S.C. 9902(2)
Mary C. Jones,

ACF/OPRE Certifying Officer.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Administration for Children and Families
Proposed Information Collection Activity; Refugee Support Services (RSS) and RSS Set Aside Sub-Agency List (Office of Management and Budget # 0970—0556)

AGENCY:
Office of Refugee Resettlement, Administration for Children and Families, U.S. Department of Health and Human Services.

ACTION:
Request for public comments.

SUMMARY:
The Administration for Children and Families (ACF) Office of Refugee Resettlement (ORR) is requesting a 3-year extension of the Refugee Support Services (RSS) and RSS Set Aside Sub-Agency List (Office of Management and Budget # 0970-0556). ORR is not proposing any changes to the form.

DATES:
Comments due within 60 days of publication. In compliance with the requirements of the Paperwork Reduction Act of 1995, ACF is soliciting public comment on the specific aspects of the information collection described above.

ADDRESSES:
Copies of the proposed collection of information can be obtained and comments may be forwarded by emailing infocollection@acf.hhs.gov. Identify all requests by the title of the information collection.

SUPPLEMENTARY INFORMATION:
Description: The RSS and RSS Set Aside Sub-Agency List requests grantees to provide the agency name, city, state, website, and funding amount for each contracted sub-grantee.
The information will be used for national resource mapping pertaining to ORR RSS funding at the local level. Improved communication and the knowledge of all local providers is important to ORR's overall oversight of the program. In addition to RSS formula funding to states and state replacement agencies who then issue sub-awards to local providers, ORR also awards discretionary grants that directly fund local refugee service providers. This report will continue to provide ORR a complete picture of the availability all ORR resources to assist newly arrived refugees at the local level increasing our ability to identify gaps or target areas of need.
Respondents: State agencies and replacement designees under 45 CFR 400.301(c) administering or supervising the administration of programs.
Annual Burden Estimates
Instrument | Total number of respondents | Annual number of responses per respondent | Average burden hours rer response | Annual burden hours
RSS and RSS Set Aside Sub-grantee List | 59 | 1 | 2 | 118
Comments: The Department specifically requests comments on (a) whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology. Consideration will be given to comments and suggestions submitted within 60 days of this publication.
Authority: Refugee Act of 1980 [Immigration and Nationality Act, title IV, chapter 2 section 412(e)] and 45 CFR 400.28.
Mary C. Jones,

ACF/OPRE Certifying Officer.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Health Resources and Services Administration
Income Levels Used for Various Health Professions and Nursing Programs Authorized in Titles III, VII, and VIII of the Public Health Service Act

AGENCY:
Health Resources and Services Administration (HRSA), Department of Health and Human Services (HHS).

ACTION:
Notice.

SUMMARY:
HRSA is updating income levels used to identify a “low-income family” for the purpose of determining eligibility for programs that provide health professions and nursing training to individuals from disadvantaged backgrounds. These various programs are authorized in titles III, VII, and VIII of the Public Health Service Act. HHS periodically publishes in the Federal Register low-income levels to be used by institutions receiving grants or cooperative agreement awards to determine eligibility for programs providing training for disadvantaged individuals, individuals from disadvantaged backgrounds, or individuals from low-income families.

SUPPLEMENTARY INFORMATION:
Many health professions and nursing grant and cooperative agreement awardees use the low-income levels to determine whether potential program participants are from economically disadvantaged backgrounds and would be eligible to participate in the program, as well as to determine the amount of funding the individual receives. Awards are generally made to accredited schools of medicine, osteopathic medicine, public health, dentistry, pharmacy, nursing, and allied health; public or private nonprofit schools which offer graduate programs in behavioral health and mental health practice; and, other public or private nonprofit health or educational entities to assist individuals from disadvantaged backgrounds and disadvantaged students to enter and graduate from health professions and nursing schools. Some programs provide for the repayment of health professions or nursing education loans for students from disadvantaged backgrounds and disadvantaged students.
A low-income family/household for programs included in titles III, VII, and VIII of the Public Health Service Act is defined as having an annual income that does not exceed 200 percent of HHS's poverty guidelines. A family is a group of two or more individuals related by birth, marriage, or adoption who live together.
Most HRSA programs use the income of a student's parent(s) to compute low-income status. However, a household may potentially be only one person. Other HRSA programs, depending upon the legislative intent of the program, the programmatic purpose related to income level, as well as the age and circumstances of the participant, apply these low-income standards to the individual student to determine eligibility, if the student is not listed as a dependent on the tax form of his or her parent(s). Each program announces the rationale and methodology for determining low-income levels in program funding opportunities or applications.
Low-income levels are adjusted annually based on HHS's poverty guidelines. HHS's poverty guidelines are based on poverty thresholds published by the U.S. Census Bureau, adjusted annually for changes in the Consumer Price Index. The income figures below have been updated to reflect HHS's 2024 poverty guidelines as published in the Federal Register at 89 FR 2961 (Jan. 11, 2024).
Low-Income Levels Based on the 2024 Poverty Guidelines for the 48 Contiguous States and the District of Columbia
Persons in family/household * | Income level **
1 | $30,120
2 | 40,880
3 | 51,640
4 | 62,400
5 | 73,160
6 | 83,920
7 | 94,680
8 | 105,440
For families with more than 8 persons, add $10,760 for each additional person.
* Includes only dependents listed on Federal income tax forms.
** Adjusted gross income for calendar year 2023.
Low-Income Levels Based on the 2024 Poverty Guidelines for Alaska
Persons in family/household * | Income level **
1 | $37,620
2 | 51,080
3 | 64,540
4 | 78,000
5 | 91,460
6 | 104,920
7 | 118,380
8 | 131,840
For families with more than 8 persons, add $13,460 for each additional person.
* Includes only dependents listed on Federal income tax forms.
** Adjusted gross income for calendar year 2023.
Low-Income Levels Based on the 2024 Poverty Guidelines for Hawaii
Persons in family/household * | Income level **
1 | $34,620
2 | 47,000
3 | 59,380
4 | 71,760
5 | 84,140
6 | 96,520
7 | 108,900
8 | 121,280
For families with more than 8 persons, add $12,380 for each additional person.
* Includes only dependents listed on Federal income tax forms.
** Adjusted gross income for calendar year 2023.
Separate poverty guidelines figures for Alaska and Hawaii reflect Office of Economic Opportunity administrative practice beginning in the 1966-1970 period since the U.S. Census Bureau poverty thresholds do not have separate figures for Alaska and Hawaii. The poverty guidelines are not defined for Puerto Rico or other outlying jurisdictions. Puerto Rico and other outlying jurisdictions shall use income guidelines for the 48 Contiguous States and the District of Columbia.
Carole Johnson,

Administrator.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
National Institute on Aging; Notice of Closed Meeting
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: National Institute on Aging Special Emphasis Panel; Alzheimer's Disease Sequencing Project.
Date: June 18, 2024.
Time: 12:00 p.m. to 3:30 p.m.
Agenda: To review and evaluate grant applications.
Place: National Institute on Aging, Gateway Building, 7201 Wisconsin Avenue, Bethesda, MD 20892, (Virtual Meeting).
Contact Person: Mariel Jais, Ph.D., M.D., Scientific Review Officer, Scientific Review Branch, National Institute on Aging, 7201 Wisconsin Avenue, Gateway Bldg. Suite E400, Bethesda, MD 20814, (301) 594-2614, mariel.jais@nih.gov.
(Catalogue of Federal Domestic Assistance Program Nos. 93.866, Aging Research, National Institutes of Health, HHS)
Dated: April 16, 2024.
Miguelina Perez,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
National Institute of Mental Health; Notice of Closed Meeting
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: National Institute of Mental Health Special Emphasis Panel; BRAIN Initiative: Brain Behavior Quantification and Synchronization (R61/R33).
Date: May 21, 2024.
Time: 10:00 a.m. to 5:00 p.m.
Agenda: To review and evaluate grant applications.
Place: National Institutes of Health, Neuroscience Center, 6001 Executive Boulevard, Rockville, MD 20852 (Virtual Meeting).
Contact Person: Evon Abisaid, Ph.D., Scientific Review Officer, Division of Extramural Activities, National Institute of Mental Health, National Institutes of Health, Rockville, MD 20852, (301) 827-0399, ereifejes@mail.nih.gov
(Catalogue of Federal Domestic Assistance Program No. 93.242, Mental Health Research Grants, National Institutes of Health, HHS)
Dated: April 16, 2024.
Melanie J. Pantoja,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
Office of the Director, National Institutes of Health; Notice of Meeting
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of a meeting of the Council of Councils.
The meeting will be held as a virtual meeting and will be partially open to the public as indicated below. Individuals who plan to view the virtual meeting and need special assistance or other reasonable accommodations, to view the meeting should notify the Contact Person listed below in advance of the meeting. The open session will be videocast and can be accessed from the NIH Videocasting website ( http://videocast.nih.gov/ ).
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: Council of Councils.
Date: May 30, 2024.
Closed: May 30, 2024, 10:00 a.m. to 11:00 a.m.
Agenda: Review of Grant Applications.
Place: National Institutes of Health Building 1, 1 Center Drive, Bethesda, MD 20892 (Virtual Meeting).
Open: May 30, 2024, 11:15 a.m. to 3:40 p.m.
Agenda: Welcome and Opening Remarks; Announcements; NIH Program Updates; Presentations; Strategic Plans; and Other Business of the Committee.
Place: National Institutes of Health Building 1, 1 Center Drive, Bethesda, MD 20892 (Virtual Meeting).
Contact Person: Franziska Grieder, D.V.M., Ph.D., Executive Secretary, Council of Councils, Director, Office of Research Infrastructure Programs, Division of Program Coordination, Planning, and Strategic Initiatives, Office of the Director, NIH, 6701 Democracy Boulevard, Room 948, Bethesda, MD 20892, GriederF@mail.nih.gov, 301-435-0744.
Any interested person may file written comments with the committee by forwarding the statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
Information is also available on the Council of Council's home page at http://dpcpsi.nih.gov/council/ where an agenda and any additional information for the meeting will be posted when available.
(Catalogue of Federal Domestic Assistance Program Nos. 93.14, Intramural Research Training Award; 93.22, Clinical Research Loan Repayment Program for Individuals from Disadvantaged Backgrounds; 93.232, Loan Repayment Program for Research Generally; 93.39, Academic Research Enhancement Award; 93.936, NIH Acquired Immunodeficiency Syndrome Research Loan Repayment Program; 93.187, Undergraduate Scholarship Program for Individuals from Disadvantaged Backgrounds, National Institutes of Health, HHS)
Dated: April 16, 2024.
David W. Freeman,

Supervisory Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
National Institute of Dental and Craniofacial Research; Notice of Meeting
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of a meeting of the National Advisory Dental and Craniofacial Research Council.
This will be a hybrid meeting held in-person and virtually and will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend in-person or view the virtual meeting and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting. The open session will be videocast and can be accessed from the NIH Videocasting website ( http://videocast.nih.gov/ ).
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: National Advisory Dental and Craniofacial Research Council.
Date: May 21-22, 2024.
Closed: May 21, 2024, 2:30 p.m. to 4:00 p.m.
Agenda: To review and evaluate grant applications.
Place: National Institutes of Health, 31 Center Drive, C Wing, 6th Floor, Rooms A & B, Bethesda, MD 20892 (Hybrid Meeting).
Closed: May 21, 2024, 4:00 p.m. to 4:30 p.m.
Agenda: To review and evaluate the Board of Scientific Counselors Report to Council.
Place: National Institutes of Health, 31 Center Drive, C Wing, 6th Floor, Rooms A & B, Bethesda, MD 20892 (Hybrid Meeting).
Open: May 22, 2024, 8:30 a.m. to 2:45 p.m.
Agenda: Report of the Director, NIDCR and concept clearances.
Place: National Institutes of Health, 31 Center Drive, C Wing, 6th Floor, Rooms A & B, Bethesda, MD 20892 (Hybrid Meeting).
Contact Person: Lynn M. King, Ph.D., Executive Secretary, Division of Extramural Activities, National Institute of Dental & Craniofacial Research, 6701 Democracy Blvd., Bethesda, MD 20892-4878, (301) 594-5006, Lynn.King@nih.gov.
Any interested person may file written comments with the committee by forwarding the statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
In the interest of security, NIH has procedures at https://www.nih.gov/about-nih/visitor-information/campus-access-security for entrance into on-campus and off-campus facilities. All visitor vehicles, including taxicabs, hotel, and airport shuttles will be inspected before being allowed on campus. Visitors attending a meeting on campus or at an off-campus federal facility will be asked to show one form of identification (for example, a government-issued photo ID, driver's license, or passport) and to state the purpose of their visit.
Information is also available on the Institute's/Center's home page: https://www.nidcr.nih.gov/about-us/advisory-committees/advisory-council, where an agenda and any additional information for the meeting will be posted when available.
(Catalogue of Federal Domestic Assistance Program No. 93.121, Oral Diseases and Disorders Research, National Institutes of Health, HHS)
Dated: April 16, 2024.
Melanie J. Pantoja,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
National Cancer Institute; Amended Notice of Meeting
Notice is hereby given of a change in the meeting of the National Cancer Institute Special Emphasis Panel; NCI Program Project (P01) Review SEP-C, June 20, 2024, 9:00 a.m. to June 21, 2024, 6:00 p.m., NCI Shady Grove, 9609 Medical Center Drive, Rockville, Maryland, 20850 which was published in the Federal Register on March 18, 2024, FR Doc. 2024-05654, 89 FR 19330.
This notice is being amended to change the meeting title from NCI Program Project (P01) Review SEP-C to NCI Program Project (P01) Review SEP-D. The meeting date, time, and location will stay the same. The meeting is closed to the public.
Dated: April 16, 2024.
Melanie J. Pantoja,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
National Institute on Drug Abuse; Notice of Closed Meetings
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: National Institute on Drug Abuse Special Emphasis Panel; Developing Regulated Therapeutic and Diagnostic Solutions for Patients Affected by Opioid and/or Stimulants Use Disorders (OUD/StUD).
Date: May 28-29, 2024.
Time: 10:00 a.m. to 4:00 p.m.
Agenda: To review and evaluate grant applications.
Place: National Institute of Health, National Institute on Drug Abuse, 301 North Stonestreet Avenue, Bethesda, MD 20892 (Virtual Meeting).
Contact Person: Sudhirkumar U. Yanpallewar, M.D., Scientific Review Officer, Scientific Review Branch, National Institute on Drug Abuse, NIH, 301 North Stonestreet Avenue, MSC 6021, Bethesda, MD 20892, (301) 443-4577, sudhirkumar.yanpallewar@nih.gov.
Name of Committee: National Institute on Drug Abuse Special Emphasis Panel; Mechanistic Studies of the Effects of Psychosocial Stress on Complex Morbidity Involving SUD, Psychiatric Disorders, and HIV.
Date: June 5, 2024.
Time: 12:00 p.m. to 2:15 p.m.
Agenda: To review and evaluate grant applications.
Place: National Institute of Health, National Institute on Drug Abuse, 301 North Stonestreet Avenue, Bethesda, MD 20892 (Virtual Meeting).
Contact Person: Marisa Srivareerat, Ph.D., Scientific Review Officer, Scientific Review Branch, Office of Extramural Policy, National Institute on Drug Abuse, NIH, 301 North Stonestreet Avenue, MSC 6021, Bethesda, MD 20892, (301) 435-1258, marisa.srivareerat@nih.gov.
(Catalogue of Federal Domestic Assistance Program Nos. 93.277, Drug Abuse Scientist Development Award for Clinicians, Scientist Development Awards, and Research Scientist Awards; 93.278, Drug Abuse National Research Service Awards for Research Training; 93.279, Drug Abuse and Addiction Research Programs, National Institutes of Health, HHS)
Dated: April 16, 2024.
Lauren A. Fleck,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
Fogarty International Center; Notice of Meeting
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of a meeting of the Fogarty International Center Advisory Board.
This will be a hybrid meeting held in-person and virtually and will be open to the public as indicated below. Individuals who plan to attend in-person or view the virtual meeting and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting. The open session can be accessed from the Fogarty International Center website: ( https://www.fic.nih.gov/About/Advisory/Pages/default.aspx ).
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: Fogarty International Center Advisory Board.
Date: June 3-4, 2024.
Closed: June 3, 2024, 1:00 p.m. to 4:00 p.m.
Agenda: To review and evaluate to review and evaluate the second level of grant applications.
Place: Fogarty International Center, National Institutes of Health, Lawton Chiles International House (Stone House), 16 Center Drive, Conference Room, Bethesda, MD 20892.
Open: June 4, 2024, 9:00 a.m. to 3:00 p.m.
Agenda: Update and discussion of current and planned Fogarty International Center activities.
Place: Fogarty International Center, National Institutes of Health, Lawton Chiles International House (Stone House), 16 Center Drive, Conference Room, Bethesda, MD 20892 (Virtual Meeting).
Meeting Access: https://www.fic.nih.gov/About/Advisory/Pages/default.aspx.
Contact Person: Kristen Weymouth, Executive Secretary, Fogarty International Center, 31 Center Drive, Room B2C02, Bethesda, MD 20892, 301-495-1415, kristen.weymouth@nih.gov.
Any interested person may file written comments with the committee by forwarding the statement to the Contact Persons listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
Information is also available on the Institute's/Center's home page: http://www.fic.nih.gov/About/Advisory/Pages/default.aspx, where an agenda and any additional information for the meeting will be posted when available.
(Catalogue of Federal Domestic Assistance Program Nos. 93.106, Minority International Research Training Grant in the Biomedical and Behavioral Sciences; 93.154, Special International Postdoctoral Research Program in Acquired Immunodeficiency Syndrome; 93.168, International Cooperative Biodiversity Groups Program; 93.934, Fogarty International Research Collaboration Award; 93.989, Senior International Fellowship Awards Program, National Institutes of Health, HHS)
Dated: April 16, 2024.
Lauren A. Fleck,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
National Institute on Aging; Notice of Closed Meeting
Pursuant to section 1009 of the Federal Advisory Committee Act, as amended, notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Name of Committee: National Institute on Aging Special Emphasis Panel; Alzheimer's Disease Drug Development.
Date: May 28, 2024.
Time: 12:00 p.m. to 4:00 p.m.
Agenda: To review and evaluate grant applications.
Place: National Institute on Aging, Gateway Building, 7201 Wisconsin Avenue, Bethesda, MD 20892 (Virtual Meeting).
Contact Person: Mariel Jais, Ph.D., M.D., Scientific Review Officer, Scientific Review Branch, National Institute on Aging, 7201 Wisconsin Avenue, Gateway Bldg. Suite E400, Bethesda, MD 20814, (301) 594-2614, mariel.jais@nih.gov.
(Catalogue of Federal Domestic Assistance Program Nos. 93.866, Aging Research, National Institutes of Health, HHS)
Dated: April 16, 2024.
Miguelina Perez,

Program Analyst, Office of Federal Advisory Committee Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Substance Abuse and Mental Health Services Administration
Agency Information Collection Activities: Proposed Collection; Comment Request
In compliance with section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 concerning opportunity for public comment on proposed collections of information, the Substance Abuse and Mental Health Services Administration (SAMHSA) will publish periodic summaries of proposed projects. To request more information on the proposed projects or to obtain a copy of the information collection plans, call the SAMHSA Reports Clearance Officer at (240) 276-0361 or carlos.graham@samhsa.hhs.gov.
Comments are invited on: (a) whether the proposed collections of information are necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on respondents, including the use of automated collection techniques or other forms of information technology.

Proposed Project: Programs to Reduce Underage Drinking—(OMB No. 0930-0316)—Revision
The Sober Truth on Preventing Underage Drinking Act (the “STOP Act”) was passed by Congress in 2006, reauthorized in December 2016 as part of the 21st Century Cures Act (Pub. L. 114-255) and the Consolidated Appropriations Act, 2023 (Pub. L. 117-328), and codified into law in 42 U.S.C. 290bb-25b: Programs to reduce underage drinking. The STOP Act contains four primary elements:
1. The award of community-based coalition enhancement grants for underage drinking prevention activities to eligible entities currently receiving funds under the Drug-Free Communities Act of 1997.
2. A national adult-oriented media public service campaign to prevent underage drinking (“Talk. They Hear You.” (TTHY), and an annual report to Congress evaluating the campaign.
3. An annual report to Congress summarizing federal prevention activities and the extent of progress in reducing underage drinking nationally, including data from national surveys conducted by federal agencies.
4. An annual report to Congress “on each State's performance in enacting, enforcing, and creating laws, regulations, and programs to prevent or reduce underage drinking.” The State Survey that is the subject of this request gathers data used to develop the state-by-state report on prevention and enforcement activities related to underage drinking
Driven by the legislation and coordinated by Interagency Coordinating Committee on the Prevention of Underage Drinking (ICCPUD), each of these activities work together to prevent and reduce underage drinking. The Interagency Coordinating Committee on the Prevention of Underage Drinking (ICCPUD) provides national leadership in federal policy and programming to support state and community activities that prevent and reduce underage drinking. The data collection activities described in this package serve to assess the outputs and outcomes of public health messaging and interventions. The three data collection activities outlined in this package are:
1. The STOP Act State Survey: An annual survey mandated by the STOP Act legislation sent to an individual designated by the governor of all 50 states and the mayor of the District of Columbia;
2. The ICCPUD Alcohol Policy Academy Evaluation: An assessment of coalition capacity and workforce development throughout a 12 month Alcohol Policy Academy; and
3. The Parents Night Out Evaluation; An assessment of changes in knowledge, skills, and confidence of parents and caregivers after receiving the training and materials for Parents Night Out and TTHY products.

The STOP Act State Survey
The STOP Act states that the “Secretary [of Health and Human Services] shall . . . annually issue a report on each state's performance in enacting, enforcing, and creating laws, regulations, and programs to prevent or reduce underage drinking.” The Secretary has delegated responsibility for this report to SAMHSA. Therefore, SAMHSA has developed a Survey of State Underage Drinking Prevention Policies, Programs, and Practices (the “ State Survey ”) to provide input for the state-by-state report on prevention and enforcement activities related to the underage drinking component of the Annual Report to Congress on the Prevention and Reduction of Underage Drinking (“ Report to Congress ”).
Congress' purpose in mandating the collection of data on state policies, programs, and practices through the State Survey is to provide policymakers and the public with otherwise unavailable but much needed information regarding state underage drinking prevention policies and programs. SAMHSA and other federal agencies that have underage drinking prevention as part of their mandate use the results of the State Survey to inform federal programmatic priorities, as do other stakeholders, including community organizations. The information gathered by the State Survey has established a resource for state agencies and the public for assessing policies and programs in their own state and for becoming familiar with the policies, programs, practices, and funding priorities of other states.
SAMHSA has determined that data on Categories #2 and #3 mandated in the STOP Act (as listed on page 2) (enforcement and educational programs; programs targeting youth, parents, and caregivers) as well as states' collaborations with tribal governments, use of social marketing or counter-advertising campaigns, state-level interagency collaborations, and prevention workforce development activities are not available from secondary sources and therefore must be collected from the states themselves. The State Survey is therefore necessary to fulfill the Congressional mandate found in the STOP Act. Furthermore, the uniform collection of these data from the states over the last fifteen years has created a valuable longitudinal dataset, and the State Survey's renewal is vital to maintaining this resource.
The State Survey is a single document that is divided into three sections: (1) Enforcement of underage drinking laws; (2A) Underage drinking prevention programs targeted to youth, parents, and caregivers, including data on the approximate number of persons served by these programs; (2B) State collaborations and best practices; (2C) Interagency collaborations and state participation in social marketing media campaigns intended to reduce underage drinking; and (3) Workforce development activities, including strategies and funds expended on recruiting and retaining a behavioral health workforce.
SAMHSA collects the required data using an online survey data collection platform. Links to the survey are distributed to states via email. The State Survey is sent to each state governor's office and the Office of the Mayor of the District of Columbia. SAMHSA provides both telephone and electronic technical support to state agency staff and emphasizes that the states are expected to provide data from existing state databases and other data sources available to them. The burden estimate below considers these assumptions.
The estimated annual response burden to collect this information is as follows:
Instrument | # of respondents | Responses/ respondent | Total responses | Hrs. per response | Total hour burden | Wage rate | Total hour cost
State Survey | 51 | 1 | 51 | 18.5 | 943.50 | $28.07 | $26,484.05

The ICCPUD Alcohol Policy Academy Evaluation
The Policy Academy strives to reduce and prevent underage and excessive drinking by increasing the capacity of community coalitions to modify the community context through the policy process. The Policy Academy includes 14 coalitions from across the U.S., with two individuals from each coalition serving as the Academy participants. The Policy Academy evaluation is designed to measure the effectiveness of increasing coalition capacity through the training and coaching of the policy process. Additionally, the evaluation will measure the increase in the policy training workforce through a coaches and mentee development pipeline. The scope of the evaluation is limited to measuring the impact of the Policy Academy curriculum on participants and coaches.
The evaluation is comprised of seven surveys and one focus group. Surveys are conducted after each monthly training and coaching call. The participant surveys seek feedback on changes in knowledge, skills, and confidence after each training or coaches call, as well as feedback on the training content and training/coaching provider. The coach surveys track the progress of the coalitions. These surveys take the participants and coaches approximately 5-10 minutes each. The participants will also complete a baseline survey, a 12-month survey, and an 18-month survey. These surveys assess whether participants reach their own goals during the Policy Academy, how they share their knowledge and skills gained, and how they continue to progress in the policy process. All surveys will be fielded using a web-based survey tool. The focus group with the cohort will collect qualitative data from the participants on their experience and efforts to incorporate health equity into their policy campaign.
Table 2 indicates the estimated total annual burden on the participants and coaches of the Policy Academy. The survey estimates include reading the instructions and questions and responding to each question. The focus group is scheduled for one hour, and includes introductions, instructions, posing of questions, and open discussion.
The estimated annual response burden to collect this information is as follows:
Instrument | # of respondents | Responses/ respondent | Total responses | Hrs. per response | Total hour burden | Wage rate | Total hour cost
Focus Group | 28 | 1 | 28 | 1 | 28 | $27.10 | $758.80
Participant Post-Coaching Call Survey | 28 | 11 | 308 | 0.125 | 38.5 | 27.10 | 1043.35
Participant Post-Training Call Survey | 28 | 10 | 280 | 0.125 | 35 | 27.10 | 948.50
Coach Post-Coaching Call Survey | 3 | 77 | 231 | 0.17 | 39.27 | 50.00 | 1,963.50
Baseline | 28 | 1 | 28 | 0.67 | 18.76 | 27.10 | 508.40
Follow-Up | 28 | 1 | 28 | 1 | 28 | 27.10 | 758.80
Six-Month Follow-Up | 28 | 1 | 28 | 0.67 | 18.76 | 27.10 | 508.40

“Talk. They Hear You.” Parents Night Out Evaluation
The “Talk They Hear You” campaign is comprised of a variety of tools and resources designed to decrease underage drinking by encouraging parents and caregivers, educators, and community members/organizations to proactively engage youth in conversations about alcohol another other drugs. Research has demonstrated that active and engaged adults can reduce underage drinking. ^1 One TTHY mechanism to engage parents and caregivers is through Parents' Night Out (PNO).
^1 Glenn, S.D., Turrisi, R., Mallett, K.A., Waldron, M.S., Lenker, L.K. (2024). Examination of Brief Parent-Based Interventions to Reduce Drinking Outcomes on a Nationally Representative Sample of Teenagers. Journal of Adolescent Health, 74 (3) 449-457. https://doi.org/10.1016/j.jadohealth.2023.09.010
The PNO Evaluation will assess changes in knowledge, skills, and confidence of parents and caregivers after receiving the training and materials for PNO and TTHY products. This evaluation will be delivered in partnership with community partners, who will be exposed to varying combinations of PNO and materials to determine change before and after exposure. The information gleaned in a survey of parents and caregivers will allow the evaluation team to assess whether PNO is being implemented as intended, and which products are most useful in increasing parents' and caregivers' capacity and intentions. The results will be shared with the implementation team for PNO curriculum modifications and for updating TTHY materials.
PNO data will be collected from participants through a survey delivered via email using Qualtrics. Completing the survey is not a requirement of the event, but an option to provide feedback to the campaign team. Collecting data through Qualtrics will improve the participant experience and allow them to quickly provide feedback. The distribution of the PNO Evaluation survey will be facilitated by local organizations who host a PNO event. They will be provided with the link to the survey and will be asked to spend a few moments of the presentation to share the link. The TTHY campaign team will develop, distribute, and support the survey.
Table 4 indicates the estimated total annual burden on the participants of PNO. The survey estimates include reading the instructions and questions and responding to each question, and totals 7 minutes. The wage rate was determined based on the highest state minimum wage, as site locations have not yet been identified.
The estimated annual response burden to collect this information is as follows:
Instrument | # of respondents | Responses/ respondent | Total responses | Hrs. per response | Total hour burden | Wage rate | Total hour cost
PNO Evaluation Survey | 150 | 1 | 150 | 0.12 | 18 | $16.28 * | $293.04
* https://www.dol.gov/agencies/whd/minimum-wage/state
Send comments to SAMHSA Reports Clearance Office at samhsapra@samhsa.hhs.gov. Written comments should be received by June 21, 2024.
Alicia Broadus,

Public Health Advisor.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Docket ID FEMA-2024-0002]
Final Flood Hazard Determinations

AGENCY:
Federal Emergency Management Agency, Department of Homeland Security.

ACTION:
Notice.

SUMMARY:
Flood hazard determinations, which may include additions or modifications of Base Flood Elevations (BFEs), base flood depths, Special Flood Hazard Area (SFHA) boundaries or zone designations, or regulatory floodways on the Flood Insurance Rate Maps (FIRMs) and where applicable, in the supporting Flood Insurance Study (FIS) reports have been made final for the communities listed in the table below. The FIRM and FIS report are the basis of the floodplain management measures that a community is required either to adopt or to show evidence of having in effect in order to qualify or remain qualified for participation in the Federal Emergency Management Agency's (FEMA's) National Flood Insurance Program (NFIP).

DATES:
The date of August 28, 2024 has been established for the FIRM and, where applicable, the supporting FIS report showing the new or modified flood hazard information for each community.

ADDRESSES:
The FIRM, and if applicable, the FIS report containing the final flood hazard information for each community is available for inspection at the respective Community Map Repository address listed in the tables below and will be available online through the FEMA Map Service Center at https://msc.fema.gov by the date indicated above.

FOR FURTHER INFORMATION CONTACT:
Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance and Mitigation Administration, FEMA, 400 C Street SW, Washington, DC 20472, (202) 646-7659, or (email) patrick.sacbibit@fema.dhs.gov; or visit the FEMA Mapping and Insurance eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html.

SUPPLEMENTARY INFORMATION:
The Federal Emergency Management Agency (FEMA) makes the final determinations listed below for the new or modified flood hazard information for each community listed. Notification of these changes has been published in newspapers of local circulation and 90 days have elapsed since that publication. The Deputy Associate Administrator for Insurance and Mitigation has resolved any appeals resulting from this notification.
This final notice is issued in accordance with section 110 of the Flood Disaster Protection Act of 1973, 42 U.S.C. 4104, and 44 CFR part 67. FEMA has developed criteria for floodplain management in floodprone areas in accordance with 44 CFR part 60.
Interested lessees and owners of real property are encouraged to review the new or revised FIRM and FIS report available at the address cited below for each community or online through the FEMA Map Service Center at https://msc.fema.gov.
The flood hazard determinations are made final in the watersheds and/or communities listed in the table below.
(Catalog of Federal Domestic Assistance No. 97.022, “Flood Insurance.”)
Nicholas A. Shufro,

Assistant Administrator (Acting) for Risk Management, Federal Emergency Management Agency, Department of Homeland Security.
Community | Community map repository address
Washington County, Mississippi and Incorporated Areas
Docket No.: FEMA-B-2252
City of Greenville | City Hall, 340 Main Street, Greenville, MS 38701.
Unincorporated Areas of Washington County | Washington County Planning Department, 900 Washington Avenue, Greenville, MS 38701.
Stone County, Missouri and Incorporated Areas
Docket No.: FEMA-B-2031, FEMA-B-2179, FEMA-B-2340
City of Branson West | City Hall, 110 Silver Lady Lane, Branson West, MO 65737.
City of Crane | City Hall, 120 North Commerce Street, Crane, MO 65633.
City of Galena | City Hall, 113 East 4th Street, Galena, MO 65656.
City of Hurley | City Hall, 202 South Walnut Street, Hurley, MO 65675.
City of Kimberling City | City Hall, 34 Kimberling Boulevard, Kimberling City, MO 65686.
City of Reeds Spring | City Hall, 22597 Main Street, Reeds Spring, MO 65737.
Unincorporated Areas of Stone County | Stone County Courthouse, 108 East 4th Street, Galena, MO 65656.
Village of Blue Eye | Stone County Courthouse, 108 East 4th Street, Galena, MO 65656.
Village of Coney Island | Stone County Courthouse, 108 East 4th Street, Galena, MO 65656.
Village of Indian Point | Indian Point Government Office, 957 Indian Point Road, Branson, MO 65616.
Village of McCord Bend | Stone County Courthouse, 108 East 4th Street, Galena, MO 65656.
Stark County, North Dakota and Incorporated Areas
Docket No.: FEMA-B-2037 and FEMA-B-2273
City of Dickinson | City Hall, 38 1st Street W, Dickinson, ND 58601.
City of Gladstone | City Hall, 183 5th Avenue, Gladstone, ND 58630.
City of Richardton | City Hall, 111 North Avenue W, Richardton, ND 58652.
City of South Heart | City Hall, 209 4th Street NW, South Heart, ND 58655.
City of Taylor | City Hall, 30 Ertel Avenue, Taylor, ND 58656.
Unincorporated Areas of Stark County | Stark County Courthouse, 51 3rd Street E, Dickinson, ND 58601.
Sanborn County, South Dakota and Incorporated Areas
Docket No.: FEMA-B-2322
City of Woonsocket | Sanborn County Courthouse, 604 West 6th Street, Woonsocket, SD 57385.
Town of Artesian | Community Center, 209 South 2nd Street, Artesian, SD 57314.
Unincorporated Areas of Sanborn County | Sanborn County Courthouse, 604 West 6th Street, Woonsocket, SD 57385.
Kewaunee County, Wisconsin and Incorporated Areas
Docket No.: FEMA-B-2318
City of Algoma | City Hall, 416 Fremont Street, Algoma, WI 54201.
City of Kewaunee | City Hall, 401 5th Street, Kewaunee, WI 54216.
Unincorporated Areas of Kewaunee County | Kewaunee County Emergency Management Department, 625 3rd Street, Luxemburg, WI 54217.
Village of Casco | Village Hall, 211 1st Street, Casco, WI 54205.
Village of Luxemburg | Village Office, 206 Maple Street, Luxemburg, WI 54217.
Sheboygan County, Wisconsin and Incorporated Areas
Docket No.: FEMA-B-2305
City of Sheboygan | City Hall, 828 Center Avenue, Sheboygan, WI 53081.
Unincorporated Areas of Sheboygan County | Administration Building, 508 New York Avenue, Sheboygan, WI 53081.
Village of Cascade | Village Hall, 301 1st Street, Cascade, WI 53011.
Village of Random Lake | Village Hall, 96 Russell Drive, Random Lake, WI 53075.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Docket ID FEMA-2024-0002; Internal Agency Docket No. FEMA-B-2431]
Changes in Flood Hazard Determinations

AGENCY:
Federal Emergency Management Agency, Department of Homeland Security.

ACTION:
Notice.

SUMMARY:
This notice lists communities where the addition or modification of Base Flood Elevations (BFEs), base flood depths, Special Flood Hazard Area (SFHA) boundaries or zone designations, or the regulatory floodway (hereinafter referred to as flood hazard determinations), as shown on the Flood Insurance Rate Maps (FIRMs), and where applicable, in the supporting Flood Insurance Study (FIS) reports, prepared by the Federal Emergency Management Agency (FEMA) for each community, is appropriate because of new scientific or technical data. The FIRM, and where applicable, portions of the FIS report, have been revised to reflect these flood hazard determinations through issuance of a Letter of Map Revision (LOMR), in accordance with Federal Regulations. The currently effective community number is shown in the table below and must be used for all new policies and renewals.

DATES:
These flood hazard determinations will be finalized on the dates listed in the table below and revise the FIRM panels and FIS report in effect prior to this determination for the listed communities.
From the date of the second publication of notification of these changes in a newspaper of local circulation, any person has 90 days in which to request through the community that the Deputy Associate Administrator for Insurance and Mitigation reconsider the changes. The flood hazard determination information may be changed during the 90-day period.

ADDRESSES:
The affected communities are listed in the table below. Revised flood hazard information for each community is available for inspection at both the online location and the respective community map repository address listed in the table below. Additionally, the current effective FIRM and FIS report for each community are accessible online through the FEMA Map Service Center at https://msc.fema.gov for comparison.
Submit comments and/or appeals to the Chief Executive Officer of the community as listed in the table below.

FOR FURTHER INFORMATION CONTACT:
Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance and Mitigation Administration, FEMA, 400 C Street SW, Washington, DC 20472, (202) 646-7659, or (email) patrick.sacbibit@fema.dhs.gov; or visit the FEMA Mapping and Insurance eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html.

SUPPLEMENTARY INFORMATION:
The specific flood hazard determinations are not described for each community in this notice. However, the online location and local community map repository address where the flood hazard determination information is available for inspection is provided.
Any request for reconsideration of flood hazard determinations must be submitted to the Chief Executive Officer of the community as listed in the table below.
The modifications are made pursuant to section 201 of the Flood Disaster Protection Act of 1973, 42 U.S.C. 4105, and are in accordance with the National Flood Insurance Act of 1968, 42 U.S.C. 4001 et seq., and with 44 CFR part 65.
The FIRM and FIS report are the basis of the floodplain management measures that the community is required either to adopt or to show evidence of having in effect in order to qualify or remain qualified for participation in the National Flood Insurance Program (NFIP).
These flood hazard determinations, together with the floodplain management criteria required by 44 CFR 60.3, are the minimum that are required. They should not be construed to mean that the community must change any existing ordinances that are more stringent in their floodplain management requirements. The community may at any time enact stricter requirements of its own or pursuant to policies established by other Federal, State, or regional entities. The flood hazard determinations are in accordance with 44 CFR 65.4.
The affected communities are listed in the following table. Flood hazard determination information for each community is available for inspection at both the online location and the respective community map repository address listed in the table below. Additionally, the current effective FIRM and FIS report for each community are accessible online through the FEMA Map Service Center at https://msc.fema.gov for comparison.
(Catalog of Federal Domestic Assistance No. 97.022, “Flood Insurance.”)
Nicholas A. Shufro,

Assistant Administrator (Acting) for Risk Management, Federal Emergency Management Agency, Department of Homeland Security.
State and county | Location and case No. | Chief executive officer of community | Community map repository | Online location of letter of map revision | Date of modification | Community No.
Arkansas: Benton | City of Bentonville (23-06-1761P). | The Honorable Stephanie Orman, Mayor, City of Bentonville, 305 Southwest A Street, Bentonville, AR 72712. | Engineering Department, 3200 Southwest Municipal Drive, Bentonville, AR 72712. | https://msc.fema.gov/portal/advanceSearch. | Jul. 8, 2024 | 080182
Colorado:
Weld | City of Evans (22-08-0399P). | The Honorable Mark Clark, Mayor, City of Evans, 1100 37th Street, Evans, CO 80620. | City Hall, 1100 37th Street, Evans, CO 80620. | https://msc.fema.gov/portal/advanceSearch. | Jul. 22, 2024 | 080182
Weld | Unincorporated areas of Weld County (22-08-0399P). | Kevin Ross, Chair, Weld County Board of Commissioners, P.O. Box 758, Greeley, CO 80632. | Weld County Administrative Building, 1150 O Street, Greeley, CO 80631. | https://msc.fema.gov/portal/advanceSearch. | Jul. 22, 2024 | 080266
Florida:
| Lee | Village of Estero (23-04-0983P). | The Honorable Jon McLain, Mayor, Village of Estero, 9401 Corkscrew Palms Circle, Estero, FL 33928. | Village Hall, 9401 Corkscrew Palms Circle, Estero, FL 33928. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 120260
Lee | Unincorporated areas of Lee County (23-04-0983P). | David Harner, Lee County Manager, 2115 2nd Street, Fort Myers, FL 33901. | Lee County Building Department, 1500 Monroe Street, Fort Myers, FL 33901. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 125124
Lee | Unincorporated areas of Lee County (24-04-0733P). | David Harner, Lee County Manager, 2115 2nd Street, Fort Myers, FL 33901. | Lee County Building Department, 1500 Monroe Street, Fort Myers, FL 33901. | https://msc.fema.gov/portal/advanceSearch. | Jun. 24, 2024 | 125124
Pasco | Unincorporated areas of Pasco County (23-04-4336P). | Ron Oakley, Chair, Pasco County Board of Commissioners, 37918 Meridian Avenue, New Port Richey, FL 34654. | Pasco County Building, Construction Services Department, 8661 Citizens Drive, Suite 100, New Port Richey, FL 34654. | https://msc.fema.gov/portal/advanceSearch. | Jul. 11, 2024 | 120230
Sumter | Unincorporated areas of Sumter County (24-04-1005X). | Craig A. Estep, Chair, Sumter County Board of Commissioners, 7375 Powell Road, Wildwood, FL 34785. | Sumter County Administration Building, 7375 Powell Road, Wildwood, FL 34785. | https://msc.fema.gov/portal/advanceSearch. | Jul. 19, 2024 | 120296
Volusia | City of Ormond Beach (23-04-6364P). | The Honorable Bill Partington Mayor, City of Ormond Beach, 22 South Beach Street, Ormond Beach, FL 32174. | City Hall, 22 South Beach Street, Ormond Beach, FL 32174. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 125136
Georgia:
Fulton | City of Alpharetta (23-04-5816P). | The Honorable Jim Gilvin, Mayor, City of Alpharetta, 2 Park Plaza, Alpharetta, GA 30009. | City Hall, 2 Park Plaza, Alpharetta, GA 30009. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 130084
Gwinnett | Unincorporated areas of Gwinnett County (23-04-2557P). | Nicole Love Hendrickson, Chair, Gwinnett County Board of Commissioners, 75 Langley Drive, Lawrenceville, GA 30046. | Gwinnett County Department of Planning and Development, 446 West Crogan Street, Suite 300, Lawrenceville, GA 30046. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 130322
Maryland:
Anne Arundel | Unincorporated areas of Anne Arundel County (23-03-0580P). | Steuart Pittman, Anne Arundel County Executive, 44 Calvert Street, Annapolis, MD 21401. | Anne Arundel County Heritage Office Complex, 2664 Riva Road, Annapolis, MD 21401. | https://msc.fema.gov/portal/advanceSearch. | Jun. 24, 2024 | 240008
Prince Georges | City of Laurel (23-03-0580P). | The Honorable Keith R. Sydnor, Mayor, City of Laurel, 8103 Sandy Spring Road, Laurel, MD 20707. | City Hall, 8103 Sandy Spring Road, Laurel, MD 20707. | https://msc.fema.gov/portal/advanceSearch. | Jun. 24, 2024 | 240053
Maine:
Cumberland | Town of Harpswell (24-01-0301X). | Kevin E. Johnson Chair, Town of Harpswell Board of Selectmen,P.O. Box 39, Harpswell, ME 04079. | Code Office, 263 Mountain Road, Harpswell, ME 04079. | https://msc.fema.gov/portal/advanceSearch. | Jun. 24, 2024 | 230169
York | Town of Kittery (24-01-0142P). | Kendra Amaral, Manager, Town of Kittery, 200 Rogers Road, Kittery, ME 03904. | Planning and Development Department, 200 Rogers Road, Kittery, ME 03904. | https://msc.fema.gov/portal/advanceSearch. | Jul. 18, 2024 | 230171
North Carolina:
Henderson | City of Hendersonville (22-04-5682P). | The Honorable Barbara Volk, Mayor, City of Hendersonville, 160 6th Avenue East, Hendersonville, NC 28792. | City Hall, 305 Williams Street, Hendersonville, NC 28792. | https://msc.fema.gov/portal/advanceSearch. | Jun. 28, 2024 | 370128
Randolph | Unincorporated areas of Randolph County (23-04-2820P). | Darrell L. Frye, Chair, Randolph County Board of Commissioners, 725 McDowell Road, Asheboro, NC 27205. | Central Permitting Building, 204 East Academy Street, Asheboro, NC 27205. | https://msc.fema.gov/portal/advanceSearch. | Jul. 17, 2024. | 370195
Robeson | Unincorporated areas of Robeson County (23-04-4166P). | John Cummings, Chair, Robeson County Board of Commissioners, 550 North Chestnut Street, Lumberton, NC 28358. | Robeson County Planning and Zoning Department, 701 North Elm Street, Lumberton, NC 28358. | https://msc.fema.gov/portal/advanceSearch. | Jun. 10, 2024 | 370202
| Union | Unincorporated areas of Union County (23-04-3292P). | J.R. Rowell, Chair, Union County Board of Commissioners, 500 North Main Street, Suite 914, Monroe, NC 28112. | Union County Planning Department, 500 North Main Street, Suite 70, Monroe, NC 28112. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 370234
Wake | City of Raleigh (22-04-5283P). | The Honorable Mary-Ann Baldwin, Mayor, City of Raleigh, P.O. Box 590, Raleigh, NC 27601. | Engineering Services Department, 1 Exchange Plaza, Suite 706, Raleigh, NC 27601. | https://msc.fema.gov/portal/advanceSearch. | Jul. 29, 2024 | 370243
Tennessee:
Davidson and Sumner | City of Goodlettsville (23-04-1929P). | The Honorable Rusty Tinnin, Mayor, City of Goodlettsville, 105 South Main Street, Goodlettsville, TN 37072. | City Hall, 318 North Main Street, Goodlettsville, TN 37072. | https://msc.fema.gov/portal/advanceSearch. | Jul. 8, 2024 | 470287
Davidson | Metropolitan Government of Nashville-Davidson County (23-04-1929P). | The Honorable John Cooper, Mayor, Metropolitan Government of Nashville-Davidson County, 1 Public Square, Suite 100, Nashville, TN 37201. | Metro Water Services Administration Building, 1600 2nd Avenue North, Nashville, TN 37208. | https://msc.fema.gov/portal/advanceSearch. | Jul. 8, 2024 | 470040
Sumner | City of Gallatin (23-04-4807P). | The Honorable Paige Brown, Mayor, City of Gallatin, 132 West Main Street, Gallatin, TN 37066. | City Hall, 132 West Main Street, Gallatin, TN 37066. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 470185
Sumner | City of Hendersonville (23-04-4807P). | The Honorable Jamie Clary, Mayor, City of Hendersonville, 101 Maple Drive North, Hendersonville, TN 37075. | City Hall, 101 Maple Drive North, Hendersonville, TN 37075. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 470186
Sumner | Unincorporated areas of Sumner County (23-04-4807P). | The Honorable John C. Isbell, Mayor, Sumner County, 355 North Belvedere Drive, Room 102, Gallatin, TN 37066. | Sumner County Administration Building, 355 North Belvedere Drive, Gallatin, TN 37066. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 470349
Texas:
Bell | City of Copperas Cove (23-06-1940P). | Ryan Haverlah, Manager, City of Copperas Cove, 914 South Main Street, Suite D, Copperas Cove, TX 76522. | Development Services Department, 914 South Main Street, Suite G, Copperas Cove, TX 76522. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 480155
Bell | City of Killeen (24-06-0682P). | The Honorable Debbie Nash-King, Mayor, City of Killeen, P.O. Box 1329 Killeen, TX 76541. | City Hall, 101 North College Street, Killeen, TX 76541. | https://msc.fema.gov/portal/advanceSearch. | Jul. 11, 2024 | 480031
Brazos | City of Bryan (24-06-0422P). | The Honorable Bobby Gutierrez, Mayor, City of Bryan, P.O. Box 1000, Bryan, TX 77805. | City Hall, 300 South Texas Avenue, Bryan, TX 77803. | https://msc.fema.gov/portal/advanceSearch. | Jul. 17, 2024 | 480082
Caldwell | City of Lockhart (24-06-0378P). | The Honorable Lew White, Mayor, City of Lockhart, P.O. Box 239, Lockhart, TX 78644. | City Hall, 308 West San Antonio Street, Lockhart, TX 78644. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 480095
Caldwell | Unincorporated areas of Caldwell County (24-06-0378P). | The Honorable Hoppy Haden, Caldwell County Judge, 110 South Main Street, Room 101, Lockhart, TX 78644. | Caldwell County Justice Center, 1703 South Colorado Street, Lockhart, TX 78644. | https://msc.fema.gov/portal/advanceSearch. | Jul. 12, 2024 | 480094
Collin | City of Plano (23-06-2014P). | The Honorable John B. Muns, Mayor, City of Plano, 1520 K Avenue, Plano, TX 75074. | Engineering Department, 1520 K Avenue, Plano, TX 75074. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 480140
Harris | Unincorporated areas of Harris County (22-06-2364P). | The Honorable Lina Hidalgo, Harris County Judge, 1001 Preston Street, Suite 911, Houston, TX 77002. | Harris County Permit Office, 1111 Fannin Street, 8th Floor, Houston, TX 77002. | https://msc.fema.gov/portal/advanceSearch. | Jul. 8, 2024 | 480287
Montgomery | City of Conroe (23-06-1878P). | The Honorable Jody Czajkoski, Mayor, City of Conroe, 300 West Davis Street, Conroe, TX 77301. | City Hall, 700 Metcalf Street, Conroe, TX 77301. | https://msc.fema.gov/portal/advanceSearch. | Jun. 27, 2024 | 480484
| Montgomery | Unincorporated areas of Montgomery County (23-06-1878P). | The Honorable Mark J. Keough, Montgomery County Judge, 501 North Thompson Street, Suite 401, Conroe, TX 77301. | Alan B. Sadler, Commissioners' Court Building, 501 North Thompson Street, Suite 401, Conroe, TX 77301. | https://msc.fema.gov/portal/advanceSearch. | Jun. 27, 2024 | 480483
Tarrant | City of Fort Worth (23-06-0416P). | The Honorable Mattie Parker, Mayor, City of Fort Worth, 200 Texas Street, Fort Worth, TX 76102. | Department of Transportation and Public Works, Engineering Vault and Map Repository, 200 Texas Street, Fort Worth, TX 76102. | https://msc.fema.gov/portal/advanceSearch. | Jul. 1, 2024 | 480596
Tarrant | City of Fort Worth (23-06-1364P). | The Honorable Mattie Parker, Mayor, City of Fort Worth, 200 Texas Street, Fort Worth, TX 76102. | Department of Transportation and Public Works, Engineering Vault and Map Repository, 200 Texas Street, Fort Worth, TX 76102. | https://msc.fema.gov/portal/advanceSearch. | Jul. 22, 2024 | 480596
Tarrant | City of Fort Worth (23-06-1452P). | The Honorable Mattie Parker, Mayor, City of Fort Worth, 200 Texas Street, Fort Worth, TX 76102. | Department of Transportation and Public Works, Engineering Vault and Map Repository, 200 Texas Street, Fort Worth, TX 76102. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 480596
Tarrant | City of Grand Prairie (23-06-2070P). | The Honorable Ron Jensen, Mayor, City of Grand Prairie, 300 West Main Street, Grand Prairie, TX 75050. | Stormwater Department, 300 West Main Street, Grand Prairie, TX 75050. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 485472
Tarrant | City of Haltom City (23-06-1452P). | The Honorable An Truong, Mayor, City of Haltom City, 5024 Broadway Avenue, Haltom City, TX 76117. | Public Works Department, 4200 Hollis Street, Haltom City, TX 76111. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 480599
Tarrant | City of Keller (23-06-1786P). | The Honorable Armin Mizani, Mayor, City of Keller, P.O. Box 770 Keller, TX 76244. | Public Works Department, 1100 Bear Creek Parkway, Keller, TX 76248. | https://msc.fema.gov/portal/advanceSearch. | Jul. 15, 2024 | 480602
Williamson | City of Cedar Park (23-06-1438P). | The Honorable Jim Penniman-Morin, Mayor, City of Cedar Park, 450 Cypress Creek Road, Building 1, Cedar Park, TX 78613. | City Hall, 450 Cypress Creek Road, Building 1, Cedar Park, TX 78613. | https://msc.fema.gov/portal/advanceSearch. | Jul. 22, 2024 | 481282
Virginia: Prince William | Unincorporated areas of Prince William County (23-03-0600P). | Christopher Shorter, Prince William County Executive, 1 County Complex Court, Prince William, VA 22192. | Prince William County Environmental Management Division, 5 County Complex Court, Suite 170, Prince William, VA 22192. | https://msc.fema.gov/portal/advanceSearch. | Jul. 5, 2024 | 510119
West Virginia:
Jefferson | City of Charles Town (23-03-0716P). | The Honorable Bob Trainor, Mayor, City of Charles Town, 101 East Washington Street, Charles Town, WV 25414. | Planning and Zoning Division, 101 East Washington Street, Charles Town, WV 25414. | https://msc.fema.gov/portal/advanceSearch. | Jul. 18, 2024 | 540066
Jefferson | Unincorporated areas of Jefferson County (23-03-0716P). | Steve Stolipher, President, Jefferson County Commission, P.O. Box 250, Charles Town, WV 25414. | Jefferson County Department of Engineering, 116 East Washington Street, Suite 200, Charles Town, WV 25414. | https://msc.fema.gov/portal/advanceSearch. | Jul. 18, 2024 | 540065
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Docket ID FEMA-2024-0002]
Final Flood Hazard Determinations

AGENCY:
Federal Emergency Management Agency, Department of Homeland Security.

ACTION:
Notice.

SUMMARY:
Flood hazard determinations, which may include additions or modifications of Base Flood Elevations (BFEs), base flood depths, Special Flood Hazard Area (SFHA) boundaries or zone designations, or regulatory floodways on the Flood Insurance Rate Maps (FIRMs) and where applicable, in the supporting Flood Insurance Study (FIS) reports have been made final for the communities listed in the table below. The FIRM and FIS report are the basis of the floodplain management measures that a community is required either to adopt or to show evidence of having in effect in order to qualify or remain qualified for participation in the Federal Emergency Management Agency's (FEMA's) National Flood Insurance Program (NFIP).

DATES:
The date of August 14, 2024 has been established for the FIRM and, where applicable, the supporting FIS report showing the new or modified flood hazard information for each community.

ADDRESSES:
The FIRM, and if applicable, the FIS report containing the final flood hazard information for each community is available for inspection at the respective Community Map Repository address listed in the tables below and will be available online through the FEMA Map Service Center at https://msc.fema.gov by the date indicated above.

FOR FURTHER INFORMATION CONTACT:
Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance and Mitigation Administration, FEMA, 400 C Street SW, Washington, DC 20472, (202) 646-7659, or (email) patrick.sacbibit@fema.dhs.gov ; or visit the FEMA Mapping and Insurance eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html .

SUPPLEMENTARY INFORMATION:
The Federal Emergency Management Agency (FEMA) makes the final determinations listed below for the new or modified flood hazard information for each community listed. Notification of these changes has been published in newspapers of local circulation and 90 days have elapsed since that publication. The Deputy Associate Administrator for Insurance and Mitigation has resolved any appeals resulting from this notification.
This final notice is issued in accordance with section 110 of the Flood Disaster Protection Act of 1973, 42 U.S.C. 4104, and 44 CFR part 67. FEMA has developed criteria for floodplain management in floodprone areas in accordance with 44 CFR part 60.
Interested lessees and owners of real property are encouraged to review the new or revised FIRM and FIS report available at the address cited below for each community or online through the FEMA Map Service Center at https://msc.fema.gov .
The flood hazard determinations are made final in the watersheds and/or communities listed in the table below.
(Catalog of Federal Domestic Assistance No. 97.022, “Flood Insurance.”)
Nicholas A. Shufro,

Assistant Administrator (Acting) for Risk Management, Federal Emergency Management Agency, Department of Homeland Security.
Community | Community map repository address
Thomas County, Georgia and Incorporated Areas
Docket No.: FEMA-B-2207 and B-2337
City of Barwick | City Hall, 2090 Cedar Street, Barwick, GA 31720.
City of Pavo | City Hall, 1010 West Harris Street, Pavo, GA 31778.
Unincorporated Areas of Thomas County | Thomas County, Elijah Hill Jr. Services Center, 227 West Jefferson Street, Thomasville, GA 31799.
Marion County, Indiana (All Jurisdictions)
Docket No.: FEMA-B-2301
City of Indianapolis | City County Building, 200 E. Washington Street, Suite W122, Indianapolis, IN 46204.
Town of Speedway | Municipal Center, 5300 Crawfordsville Road, Speedway, IN 46224.
Breathitt County, Kentucky and Incorporated Areas
Docket No.: FEMA-B-2337
City of Jackson | City Hall, 333 Broadway Street, Jackson, Kentucky 41339.
Unincorporated Areas of Breathitt County | Breathitt County Courthouse, 1137 Main Street, Suite 205, Jackson, Kentucky 41339.
Knott County, Kentucky and Incorporated Areas
Docket No.: FEMA-B-2337
City of Hindman | City Hall, 10 Professor Clarke Circle, Hindman, Kentucky 41822.
Unincorporated Areas of Knott County | Knott County Courthouse, 54 West Main Street, Hindman, Kentucky 41822.
Lee County, Kentucky and Incorporated Areas
Docket No.: FEMA-B-2337
City of Beattyville | Lee County Courthouse, 256 Main Street, Beattyville, Kentucky 41311.
Unincorporated Areas of Lee County | Lee County Courthouse, 256 Main Street, Beattyville, Kentucky 41311.
Letcher County, Kentucky and Incorporated Areas
Docket No.: FEMA-B-2337
City of Fleming-Neon | City Hall, 1081 Highway 317, Fleming-Neon, Kentucky 41840.
City of Whitesburg | City Hall, 38 East Main Street, Whitesburg, Kentucky 41858.
Unincorporated Areas of Letcher County | Letcher County Courthouse, 156 Main Street, Suite 107, Whitesburg, Kentucky 41858.
| Perry County, Kentucky and Incorporated
AreasDocket No.: FEMA-B-2337
City of Hazard | City Hall, 700 Main Street, Hazard, Kentucky 41701.
Unincorporated Areas of Perry County | Perry County Courthouse, 481 Main Street, 1st Floor, Hazard, Kentucky 41701.
Wolfe County, Kentucky and Incorporated Areas
Docket No.: FEMA-B-2337
Unincorporated Areas of Wolfe County | Wolfe County Courthouse, 16 Court Street, Campton, Kentucky 41301.
Sharkey County, Mississippi and Incorporated Areas
Docket No.: FEMA-B-2252
Town of Anguilla | Town Hall, 22 Rolling Fork Road, Anguilla, MS 38721
Unincorporated Areas of Sharkey County | Sharkey County Courthouse, 120 Locust Street, #5, Rolling Fork, MS 39159.
Cass County, Nebraska and Incorporated Areas
Docket No.: FEMA-B-2254
City of Plattsmouth | City Hall, 136 North 5th Street, Plattsmouth, NE 68048.
Unincorporated Areas of Cass County | Cass County Courthouse, 346 Main Street, Plattsmouth, NE 68048.
Coal County, Oklahoma and Incorporated Areas
Docket No.: FEMA-B-2243
Choctaw Nation of Oklahoma | Choctaw Nation of Oklahoma Headquarters, 1802 Chukka Hina, Durant, OK 74701.
City of Colgate | City Hall, 3 South Main Street, Coalgate, OK 74538.
City of Lehigh | Coal County Courthouse, 4 North Main Street, Coalgate, OK 74538.
City of Tupelo | Coal County Courthouse, 4 North Main Street, Coalgate, OK 74538.
Town of Phillips | Coal County Courthouse, 4 North Main Street, Coalgate, OK 74538.
Unincorporated Areas of Coal County | Coal County Courthouse,4 North Main Street, Coalgate, OK 74538.
Hanson County, South Dakota and Incorporated Areas
Docket No.: FEMA-B-2264
City of Alexandria | City Hall, 421 Main Street, Alexandria, SD 57311.
City of Emery | City Hall, 560 South Dakota Highway 262, Emery, SD 57332.
Town of Fulton | City Hall, 126 West 6th Street, Fulton, SD 57340.
Unincorporated Areas of Hanson County | Hanson County Courthouse, 720 5th Street, Alexandria, SD 57311.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Docket ID FEMA-2024-0002; Internal Agency Docket No. FEMA-B-2428]
Proposed Flood Hazard Determinations

AGENCY:
Federal Emergency Management Agency, Department of Homeland Security.

ACTION:
Notice.

SUMMARY:
Comments are requested on proposed flood hazard determinations, which may include additions or modifications of any Base Flood Elevation (BFE), base flood depth, Special Flood Hazard Area (SFHA) boundary or zone designation, or regulatory floodway on the Flood Insurance Rate Maps (FIRMs), and where applicable, in the supporting Flood Insurance Study (FIS) reports for the communities listed in the table below. The purpose of this notice is to seek general information and comment regarding the preliminary FIRM, and where applicable, the FIS report that the Federal Emergency Management Agency (FEMA) has provided to the affected communities. The FIRM and FIS report are the basis of the floodplain management measures that the community is required either to adopt or to show evidence of having in effect in order to qualify or remain qualified for participation in the National Flood Insurance Program (NFIP).

DATES:
Comments are to be submitted on or before July 22, 2024.

ADDRESSES:
The Preliminary FIRM, and where applicable, the FIS report for each community are available for inspection at both the online location https://hazards.fema.gov/femaportal/prelimdownload and the respective Community Map Repository address listed in the tables below. Additionally, the current effective FIRM and FIS report for each community are accessible online through the FEMA Map Service Center at https://msc.fema.gov for comparison.
You may submit comments, identified by Docket No. FEMA-B-2428, to Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance and Mitigation Administration, FEMA, 400 C Street SW, Washington, DC 20472, (202) 646-7659, or (email) patrick.sacbibit@fema.dhs.gov .

FOR FURTHER INFORMATION CONTACT:
Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance and Mitigation Administration, FEMA, 400 C Street SW, Washington, DC 20472, (202) 646-7659, or (email) patrick.sacbibit@fema.dhs.gov ; or visit the FEMA Mapping and Insurance eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html .

SUPPLEMENTARY INFORMATION:
FEMA proposes to make flood hazard determinations for each community listed below, in accordance with section 110 of the Flood Disaster Protection Act of 1973, 42 U.S.C. 4104, and 44 CFR 67.4(a).
These proposed flood hazard determinations, together with the floodplain management criteria required by 44 CFR 60.3, are the minimum that are required. They should not be construed to mean that the community must change any existing ordinances that are more stringent in their floodplain management requirements. The community may at any time enact stricter requirements of its own or pursuant to policies established by other Federal, State, or regional entities. These flood hazard determinations are used to meet the floodplain management requirements of the NFIP.
The communities affected by the flood hazard determinations are provided in the tables below. Any request for reconsideration of the revised flood hazard information shown on the Preliminary FIRM and FIS report that satisfies the data requirements outlined in 44 CFR 67.6(b) is considered an appeal. Comments unrelated to the flood hazard determinations also will be considered before the FIRM and FIS report become effective.
Use of a Scientific Resolution Panel (SRP) is available to communities in support of the appeal resolution process. SRPs are independent panels of experts in hydrology, hydraulics, and other pertinent sciences established to review conflicting scientific and technical data and provide recommendations for resolution. Use of the SRP only may be exercised after FEMA and local communities have been engaged in a collaborative consultation process for at least 60 days without a mutually acceptable resolution of an appeal. Additional information regarding the SRP process can be found online at https://www.floodsrp.org/pdfs/srp_overview.pdf .
The watersheds and/or communities affected are listed in the tables below. The Preliminary FIRM, and where applicable, FIS report for each community are available for inspection at both the online location https://hazards.fema.gov/femaportal/prelimdownload and the respective Community Map Repository address listed in the tables. For communities with multiple ongoing Preliminary studies, the studies can be identified by the unique project number and Preliminary FIRM date listed in the tables. Additionally, the current effective FIRM and FIS report for each community are accessible online through the FEMA Map Service Center at https://msc.fema.gov for comparison.
(Catalog of Federal Domestic Assistance No. 97.022, “Flood Insurance.”)
Nicholas A. Shufro,

Assistant Administrator (Acting) for Risk Management, Federal Emergency Management Agency, Department of Homeland Security.
Community | Community map repository address
Granite County, Montana and Incorporated Areas
Project: 22-08-0035S Preliminary Date: May 24, 2023
Town of Drummond | Town Hall, 114 A Street, Dummond, MT 59832.
Unincorporated Areas of Granite County | Granite County Courthouse, 220 North Sansome Street, Philipsburg, MT 59858.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Docket ID FEMA-2024-0002; Internal Agency Docket No. FEMA-B-2429]
Changes in Flood Hazard Determinations

AGENCY:
Federal Emergency Management Agency, Department of Homeland Security.

ACTION:
Notice.

SUMMARY:
This notice lists communities where the addition or modification of Base Flood Elevations (BFEs), base flood depths, Special Flood Hazard Area (SFHA) boundaries or zone designations, or the regulatory floodway (hereinafter referred to as flood hazard determinations), as shown on the Flood Insurance Rate Maps (FIRMs), and where applicable, in the supporting Flood Insurance Study (FIS) reports, prepared by the Federal Emergency Management Agency (FEMA) for each community, is appropriate because of new scientific or technical data. The FIRM, and where applicable, portions of the FIS report, have been revised to reflect these flood hazard determinations through issuance of a Letter of Map Revision (LOMR), in accordance with Federal Regulations. The currently effective community number is shown in the table below and must be used for all new policies and renewals.

DATES:
These flood hazard determinations will be finalized on the dates listed in the table below and revise the FIRM panels and FIS report in effect prior to this determination for the listed communities.
From the date of the second publication of notification of these changes in a newspaper of local circulation, any person has 90 days in which to request through the community that the Deputy Associate Administrator for Insurance and Mitigation reconsider the changes. The flood hazard determination information may be changed during the 90-day period.

ADDRESSES:
The affected communities are listed in the table below. Revised flood hazard information for each community is available for inspection at both the online location and the respective community map repository address listed in the table below. Additionally, the current effective FIRM and FIS report for each community are accessible online through the FEMA Map Service Center at https://msc.fema.gov for comparison.
Submit comments and/or appeals to the Chief Executive Officer of the community as listed in the table below.

FOR FURTHER INFORMATION CONTACT:
Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance and Mitigation Administration, FEMA, 400 C Street SW, Washington, DC 20472, (202) 646-7659, or (email) patrick.sacbibit@fema.dhs.gov ; or visit the FEMA Mapping and Insurance eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html .

SUPPLEMENTARY INFORMATION:
The specific flood hazard determinations are not described for each community in this notice. However, the online location and local community map repository address where the flood hazard determination information is available for inspection is provided.
Any request for reconsideration of flood hazard determinations must be submitted to the Chief Executive Officer of the community as listed in the table below.
The modifications are made pursuant to section 201 of the Flood Disaster Protection Act of 1973, 42 U.S.C. 4105, and are in accordance with the National Flood Insurance Act of 1968, 42 U.S.C. 4001 et seq., and with 44 CFR part 65.
The FIRM and FIS report are the basis of the floodplain management measures that the community is required either to adopt or to show evidence of having in effect in order to qualify or remain qualified for participation in the National Flood Insurance Program (NFIP).
These flood hazard determinations, together with the floodplain management criteria required by 44 CFR 60.3, are the minimum that are required. They should not be construed to mean that the community must change any existing ordinances that are more stringent in their floodplain management requirements. The community may at any time enact stricter requirements of its own or pursuant to policies established by other Federal, State, or regional entities. The flood hazard determinations are in accordance with 44 CFR 65.4.
The affected communities are listed in the following table. Flood hazard determination information for each community is available for inspection at both the online location and the respective community map repository address listed in the table below. Additionally, the current effective FIRM and FIS report for each community are accessible online through the FEMA Map Service Center at https://msc.fema.gov for comparison.
(Catalog of Federal Domestic Assistance No. 97.022, “Flood Insurance.”)
Nicholas A. Shufro,

Assistant Administrator (Acting) for Risk Management, Federal Emergency Management Agency, Department of Homeland Security.
State and county | Location and case No. | Chief executive officer of community | Community map repository | Online location of letter of map revision | Date of modification | Community No.
Arizona:
Maricopa | City of Glendale (23-09-1262P). | The Honorable Jerry Weiers, Mayor, City of Glendale, 9494 West Maryland Avenue, Glendale, AZ 85305. | City Hall, 5850 West Glendale Avenue, Glendale, AZ 85301. | https://msc.fema.gov/portal/advanceSearch . | Jul. 12, 2024 | 040045
Maricopa | City of Goodyear (23-09-1262P). | The Honorable Joe Pizzillo, Mayor, City of Goodyear, 1900 North Civic Square, Goodyear, AZ 85395. | Engineering and Development Services, 14455 West Van Buren Street, Suite D101, Goodyear, AZ 85338. | https://msc.fema.gov/portal/advanceSearch . | Jul. 12, 2024 | 040046
Maricopa | City of Surprise (23-09-0697P). | The Honorable Skip Hall, Mayor, City of Surprise, 16000 North Civic Center Plaza, Surprise, AZ 85374. | Public Works Department, Engineering Development Services, 16000 North Civic Center Plaza, Surprise, AZ 85374. | https://msc.fema.gov/portal/advanceSearch . | Jun. 28, 2024 | 040053
Maricopa | Unincorporated Areas of Maricopa County (23-09-1262P). | The Honorable Jack Sellers, Chair, Board of Supervisors, Maricopa County, 301 West Jefferson Street, 10th Floor, Phoenix, AZ 85003. | Flood Control District of Maricopa County, 2801 West Durango Street, Phoenix, AZ 85009. | https://msc.fema.gov/portal/advanceSearch . | Jul. 12, 2024 | 040037
Pima | Unincorporated Areas of Pima County (23-09-1217P). | The Honorable Adelita Grijalva, Chair, Board of Supervisors, Pima County, 33 North Stone Avenue 11th Floor, Tucson, AZ 85701. | Pima County Flood Control District, 201 North Stone Avenue, 9th Floor, Tucson, AZ 85701. | https://msc.fema.gov/portal/advanceSearch . | Jul. 11, 2024 | 040073
Pinal | Town of Superior (23-09-0243P). | The Honorable Mila Besich, Mayor, Town of Superior, P.O. Box 218, Superior, AZ 85173. | Town Hall, 199 North Lobb Avenue, Superior, AZ 85173. | https://msc.fema.gov/portal/advanceSearch . | Jun. 27, 2024 | 040119
California:
Contra Costa | City of Oakley (23-09-1104P). | The Honorable Anissa Williams, Mayor, City of Oakley, 3231 Main Street, Oakley, CA 94561. | Public Works and Engineering Department, 3231 Main Street, Oakley, CA 94561. | https://msc.fema.gov/portal/advanceSearch . | Jul. 24, 2024 | 060766
Napa | Unincorporated Areas of Napa County (22-09-0692P). | The Honorable Belia Ramos, Chair, Board of Supervisors, Napa County, 1195 3rd Street, Suite 310, Napa, CA 94559. | Napa County, Public Works Department, 1195 3rd Street, Suite 101, Napa, CA 94559. | https://msc.fema.gov/portal/advanceSearch . | Jun. 26, 2024 | 060205
Riverside | Unincorporated Areas of Riverside County (22-09-1288P). | The Honorable Chuck Washington, Chair, Board of Supervisors, Riverside County, 4080 Lemon Street, 5th Floor, Riverside, CA 92501. | Riverside County, Flood Control and Water Conservation District, 1995 Market Street, Riverside, CA 92501. | https://msc.fema.gov/portal/advanceSearch . | Jul. 10, 2024 | 060245
| San Diego | Unincorporated Areas of San Diego County (23-09-0964P). | The Honorable Nora Vargas, Chair, Board of Supervisors, San Diego County, 1600 Pacific Highway, Room 335, San Diego, CA 92101. | San Diego County Flood Control District, Department of Public Works, 5510 Overland Avenue, Suite 410, San Diego, CA 92123. | https://msc.fema.gov/portal/advanceSearch . | Jun. 28, 2024 | 060284
Ventura | Unincorporated Areas of Ventura County (23-09-1390P). | The Honorable Kelly Long, Chair, Board of Supervisors, Ventura County, 1203 Flynn Road, Suite 220, Camarillo, CA 93012. | Ventura County, Public Works Agency, 800 South Victoria Avenue, Ventura, CA 93009. | https://msc.fema.gov/portal/advanceSearch . | Jun. 26, 2024 | 060413
Florida: Duval | City of Jacksonville (23-04-4924P). | The Honorable Donna Deegan, Mayor, City of Jacksonville, 117 West Duval Street, Suite 400, Jacksonville, FL 32202. | Edward Ball Building Development Services, 214 North Hogan Street, Room 2100, Jacksonville, FL 32202. | https://msc.fema.gov/portal/advanceSearch . | Jul. 31, 2024 | 120077
Hawaii: Maui | Maui County (22-09-1030P). | The Honorable Richard T. Bissen, Jr., Mayor, County of Maui, 200 South High Street, Kalana O Maui Building, 9th Floor, Wailuku, HI 96793. | County of Maui Planning Department, One Main Plaza, 2200 Main Street, Suite 315, Wailuku, HI 96793. | https://msc.fema.gov/portal/advanceSearch . | Jun. 17, 2024 | 150003
Illinois:
Cook | Village of Buffalo Grove (24-05-0045P). | Eric Smith, Village President, Village of Buffalo Grove, 50 Raupp Boulevard, Buffalo Grove, IL 60089. | Public Service Center, 51 Raupp Boulevard, Buffalo Grove, IL 60089. | https://msc.fema.gov/portal/advanceSearch . | Jun. 26, 2024 | 170068
Will | Unincorporated Areas of Will County (23-05-2762P). | Jennifer Bertino-Tarrant, Will County Executive, Will County Office Building, 302 North Chicago Street, Joliet, IL 60432. | Will County Land Use Department, 58 East Clinton Street, Suite 100, Joliet, IL 60432. | https://msc.fema.gov/portal/advanceSearch . | Jun. 26, 2024 | 170695
Indiana: Marion | City of Indianapolis (23-05-1479P). | The Honorable Joe Hogsett, Mayor, City of Indianapolis, City-County Building, 200 East Washington Street, Suite 2501, Indianapolis, IN 46204. | City Hall, 1200 Madison Avenue, Suite 100, Indianapolis, IN 46225. | https://msc.fema.gov/portal/advanceSearch . | Jul. 10, 2024 | 180159
Nevada: Washoe | City of Reno (23-09-0241P). | The Honorable Hillary L. Schieve, Mayor, City of Reno, P.O. Box 1900, Reno, NV 89505. | City Hall, 1 East 1st Street, Reno, NV 89501. | https://msc.fema.gov/portal/advanceSearch . | Jul. 18, 2024 | 320020
New York: Westchester | Village of Mamaroneck (22-02-0906P). | The Honorable Sharon Torres, Mayor, Village of Mamaroneck, 123 Mamaroneck Avenue, Mamaroneck, NY 10543. | Building Inspector, The Regatta Building, 123 Mamaroneck Avenue, Mamaroneck, NY 10543. | https://msc.fema.gov/portal/advanceSearch . | Sep. 12, 2024 | 360916
Ohio:
Lorain | City of North Ridgeville (23-05-0136P). | The Honorable Kevin Corcoran, Mayor, City of North Ridgeville, City Hall, 7307 Avon Belden Road, North Ridgeville, OH 44039. | City Hall, 7307 Avon Belden Road, North Ridgeville, OH 44039. | https://msc.fema.gov/portal/advanceSearch . | Jul. 5, 2024 | 390352
Lucas | City of Toledo (23-05-2723P). | The Honorable Wade Kapszukiewicz, Mayor, City of Toledo, 1 Government Center, 640 Jackson Street, Toledo, OH 43604. | Department of Inspection, 1 Government Center, Suite 1600, Toledo, OH 43604. | https://msc.fema.gov/portal/advanceSearch . | Jul. 8, 2024 | 395373
Lucas | Unincorporated Areas of Lucas County (23-05-2723P). | Jessica Ford, Administrator, Lucas County, 1 Government Center, Suite 800, Toledo, OH 43604. | Lucas County Engineer's Office, 1049 South McCord Road, Holland, OH 43528. | https://msc.fema.gov/portal/advanceSearch . | Jul. 8, 2024 | 390359
South Carolina:
Richland | City of Columbia (23-04-4451P). | The Honorable Daniel J. Rickenmann, Mayor, City of Columbia, 1737 Main Street, Columbia, SC 29201. | Department of Utilities and Engineering, 1136 Washington Street, Columbia, SC 29201. | https://msc.fema.gov/portal/advanceSearch . | Jul. 1, 2024 | 450172
| Richland | City of Forest Acres (23-04-4451P). | The Honorable Thomas Andrews, Mayor, City of Forest Acres, City Hall, 5209 North Trenholm Road, Forest Acres, SC 29206. | City Hall, 5209 North Trenholm Road, Forest Acres, SC 29206. | https://msc.fema.gov/portal/advanceSearch . | Jul. 1, 2024 | 450174
Richland | Unincorporated Areas of Richland County (23-04-4451P). | Jesica Mackey, Chair, Richland County, P.O. Box 192, Columbia, SC 29201. | Richland County, Department of Public Works, 400 Powell Road, Columbia, SC 29203. | https://msc.fema.gov/portal/advanceSearch . | Jul. 1, 2024 | 450170
Washington: Pierce | Unincorporated Areas of Pierce County (23-10-0850P). | Shannon Reynolds, Chair, Pierce County, 2401 South 35th Street, Suite 2, Tacoma, WA 98409. | Pierce County Public Works and Utilities Department, 2401 South 35th Street, Tacoma, WA 98409. | https://msc.fema.gov/portal/advanceSearch . | Jul. 30, 2024 | 530138
DEPARTMENT OF THE INTERIOR
Fish and Wildlife Service
[FWS-HQ-NWRS-2024-N013; FF09M21200-245-FXMB1231099BPP0; OMB Control Number 1018-0193]
Agency Information Collection Activities; Submission to the Office of Management and Budget; U.S. Fish and Wildlife Service Agreements With Friends Organizations

AGENCY:
Fish and Wildlife Service, Interior.

ACTION:
Notice of information collection; request for comment.

SUMMARY:
In accordance with the Paperwork Reduction Act of 1995, we, the U.S. Fish and Wildlife Service (Service), are proposing to renew an information collection with revisions.

DATES:
Interested persons are invited to submit comments on or before May 22, 2024.

ADDRESSES:
Written comments and recommendations for the proposed information collection should be submitted within 30 days of publication of this notice at https://www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under Review—Open for Public Comments” or by using the search function. Please provide a copy of your comments to the Service Information Collection Clearance Officer, U.S. Fish and Wildlife Service, MS: PRB (JAO/3W), 5275 Leesburg Pike, Falls Church, VA 22041-3803 (mail); or by email to Info_Coll@fws.gov. Please reference “1018-0193” in the subject line of your comments.

FOR FURTHER INFORMATION CONTACT:
To request additional information about this ICR, contact Madonna L. Baucum, Service Information Collection Clearance Officer, by email at Info_Coll@fws.gov, or by telephone at (703) 358-2503. Individuals in the United States who are deaf, deafblind, hard of hearing, or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to access telecommunications relay services. Individuals outside the United States should use the relay services offered within their country to make international calls to the point-of-contact in the United States. You may also view the ICR at http://www.reginfo.gov/public/do/PRAMain.

SUPPLEMENTARY INFORMATION:
In accordance with the Paperwork Reduction Act (PRA, 44 U.S.C. 3501 et seq. ) and its implementing regulations at 5 CFR 1320.8(d)(1), all information collections require approval under the PRA. We may not conduct or sponsor and you are not required to respond to a collection of information unless it displays a currently valid OMB control number.
On September 25, 2023, we published in the Federal Register (88 FR 65741) a notice of our intent to request that OMB approve this information collection. In that notice, we solicited comments for 60 days, ending on November 24, 2023. In an effort to increase public awareness of, and participation in, our public commenting processes associated with information collection requests, the Service also published the Federal Register notice on Regulations.gov (Docket No. FWS-HQ-NWRS-2023-0135). We received the following five comments in response to that notice:
Comment 1: Electronic comment submitted via Regulations.gov (FWS-HQ-NWRS-2023-0135-0002) by Jean Publie on 09/25/2023. The commenter requests that the Friends program be shut down and is inherently biased toward insider groups.
Agency Response to Comment 1: The commenter did not address the information collection requirements; therefore, no response is required.
Comment 2: Anonymous electronic comment submitted via Regulations.gov (FWS-HQ-NWRS-2023-0135-0006) received 11/19/2023. The commenter asked us not to kill any wildlife.
Agency Response to Comment 2: The commenter did not address the information collection requirements; therefore, no response is required.
Comment 3: Electronic comment submitted via Regulations.gov (FWS-HQ-NWRS-2023-0135-0007) by A. Hill on 11/23/2023. The commenter states:
“The proposed USFWS collection of information from Friends groups is supposedly being done to “reduce paperwork” of citizens under the Paperwork Reduction Act. At least our Friends group is already working very closely with our local USFWS manager, providing all relevant information. We provide all required information to the Internal Revenue Service (IRS), and that information is provided to members and our local USFWS manager. We provide all financial information to our membership, and any and all of that information is available to the public upon request. We are a small, all volunteer organization—absolutely no paid staff. All but a minimum portion of our raised money goes directly to refuge support, education programs, and other mission relevant expenses. It is already hard enough to recruit executive officers, particularly to positions overseeing record keeping. Any additional reporting requirements would further discourage participation. If your goal is to cripple smaller friends groups, your proposal is right on point. Otherwise, unless there is reason for concern, let the refuge manager and friends group work out reporting requirements.”
Agency Response to Comment 3: We must collect Friends information per the September 2020 audit by the Department of the Interior (DOI) Office of the Inspector General (OIG), who was concerned that the information was not available for the program as a whole. No information will be requested that isn't already being collected by the Friends and that should already be regularly reported to the refuge manager. We will allow the refuge manager and Friends to determine who reports the information to the Service. This standard reporting form will allow the Service to tell a fuller story of the contributions of all Friends across the country.
Comment 4: Electronic comment submitted via Regulations.gov (FWS-HQ-NWRS-2023-0135-0008) by Charles Paxton on 11/23/2023. The commenter states:
“I am a board member at large for the friends of Black Bayou Lake NWR group, I'm writing on my own behalf as an individual in this instance and not representing the board with these opinions. I think it would be quite onerous for small groups to have to report in detail as if they were larger groups. I warn against that course. Our members are all volunteers and most of them are professionals working in other business areas and while they bring a wide variety of skills with them to the group, they may have very little time nor inclination for extra bureaucracy or other impositions. I wouldn't want any extra imposition to be made upon our officers.
I don't see that we would benefit from it really. Furthermore when questioning the relevance of such information collection in the document, I have to say that I didn't see anything in the proposal that justified the use of it therefore I do question the validity of collecting it.
Yes, I agree there's a need to develop future leaders within our organization but I'm not sure we need to be very formal about that, rather we attract people who are self-motivated. Remote micromanagement we don't need. The covid pandemic eroded our active support base but ours is a community conservation project and our leadership has been recently refreshed. NB there is already a national mentoring organization called ANROSP that is available to us. Thank you for seeking our opinions.”
Agency Response to Comment 4: We will not seek any information that is not already being collected and reported to the refuge manager and the IRS. The justification for the collection is in part because it is being required by the OIG per the September 2020 audit, and in part because we will be able to paint a full picture of the contributions of Friends on a national scale, which has never been possible without any standardized data collection.
Comment 5: Electronic comment submitted via Regulations.gov (FWS-HQ-NWRS-2023-0135-0009) by Charles Paxton on 11/23/2023. The commenter states:
“The new regulations proposed here are not inclusive and do not facilitate improvements applicable to all friends groups, specifically those which operate and are managed by volunteers alone. Additionally, the proposal does not go into specifics regarding its “non-form” collection of information. And the stringency of the collection of the reports of activity from friends groups, applicable to what we assume is all friends groups, does not take into account that some groups are poorly staffed, underfunded, volunteer only, and limited in its capacity to report on the standards of groups who are of greater means and ability.”
Agency Response to Comment 5: We will not collect any information outside of the new form. We are establishing a tiered system for what is expected to be reported for smaller groups versus larger ones, with no information being requested that should not already be collected per guidelines from the IRS for any 501(c)3 nonprofit organization.
As part of our continuing effort to reduce paperwork and respondent burdens, we invite the public and other Federal agencies to comment on new, proposed, revised, and continuing collections of information. This helps us assess the impact of our information collection requirements and minimize the public's reporting burden. It also helps the public understand our information collection requirements and provide the requested data in the desired format.
We are especially interested in public comment addressing the following:
(1) Whether or not the collection of information is necessary for the proper performance of the functions of the agency, including whether or not the information will have practical utility;
(2) The accuracy of our estimate of the burden for this collection of information, including the validity of the methodology and assumptions used;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) How might the agency minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of response.
Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this ICR. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
Abstract: The U.S. Fish and Wildlife Service (Service) enters into agreements and partnerships with nonprofit Friends groups to facilitate and formalize collaboration between the parties in support of mutual goals and objectives as authorized by:
(1) The Fish and Wildlife Act of 1956 (16 U.S.C. 742a-742j);
(2) The National Wildlife Refuge System Administration Act of 1966 (16 U.S.C. 668dd-ee), as amended;
(3) The Refuge Recreation Act of 1962 (16 U.S.C. 460k et seq. ), as amended;
(4) The Anadromous Fish Conservation Act (16 U.S.C. 757a-757g), as amended;
(5) The Fish and Wildlife Coordination Act of 1934 (16 U.S.C. 661-667e), as amended;
(6) The National Wildlife Refuge System Volunteer and Community Partnership Enhancement Act of 1998 (16 U.S.C. 742f), as amended; and
(7) The National Fish Hatchery System Volunteer Act of 2006 (16 U.S.C. 760aa), as amended.
In September 2020, the OIG delivered its final audit report of the Service's Friends Program. The audit outlined six recommendations, including a requirement for Friends groups to report related data to the Service on a regular basis. In order to collect this information legally, we must complete the Information Collection Clearance process. The Service addressed and completed all audit recommendations and commitments (other than completion of the Information Collection Clearance process). For example, the Service amended and reissued agency policies (Service Manual chapters 633 FW 1, 633 FW 2, 633 FW 3, and 633 FW 4, available at https://www.fws.gov/program/policy-regulations/library ) which guide the program. We also trained Service staff and Friends on the new policies.
The Service uses the information collected to establish efficient and effective partnerships and working relationships with nonprofit Friends organizations. The agreements provide a method for the Service to legally accept donations of funds and other contributions by people and organizations through partnerships with nonprofit (and non-Federal) Friends organizations. The partnership agreements identify roles and responsibilities and identify mutual projects over the term of the agreement. Quarterly reviews provide an opportunity to update contact and financial information. Annual reporting documents contributions to the Service.
The Service utilizes a standardized agreement that describes the substantial involvement of both parties in mutually agreed-upon activities and ensures that both parties have a mutual understanding of their respective roles, responsibilities, rights, expectations, and requirements within the partnership. The agreement, preapproved by the DOI Office of the Solicitor, provides the suggested language common to most Service Friends partnerships. The content is based on DOI and Service policies, but the Friends and Service sites/programs may thoughtfully add and delete certain language to meet their varying partnership roles and responsibilities wherever Department and Service policies do not dictate otherwise. For use of Service property, we also use a supplemental partnership agreement, which provides additional terms and responsibilities beyond the general terms of the partnership agreement and is required only for those Friends groups that use Service land, facilities, or equipment.
The partnership agreement and supplemental agreement are effective for 5 years, with four annual modification options during the 5-year period. Each time the agreement is up for 5-year renewal, the Refuge or Fish Hatchery Project Leader and the Friends President or Board will meet to review, modify, and sign the agreement, as described above. For an agreement to become effective or be renewed, the Regional Director (or designee) must review, approve, and sign a new agreement every 5 years.
The Service collects the information listed below about the administration of the Friends Program to verify compliance with agency policy and to allow the Service to gauge the impact of the program as a whole. All information collected will be kept in a secure manner by the Service and will not be shared except as an aggregate report. If the Service wishes to share specific details to illustrate the strength of the Friends program, individual groups will be asked for their permission to do so.
In addition to the partnership agreement and supplemental agreement, and subsequent renewals of the agreements, the Service collects the following information about the administration of the Friends Program:
• Basic program information documentation, to include documents such as IRS determination letters recognizing an organization as tax exempt, submission of IRS Form 990-series forms, bylaws, and articles of incorporation;
• Internal financial control documentation for the organization;
• Recordkeeping requirements documenting accountability for donations and expenditures;
• Documentation providing assurance that donations, revenues, and expenditures benefit the applicable refuge or hatchery;
• Annual performance reporting (donations, revenues, and expenditures) and number of memberships (if applicable);
• Additional information that may be included as part of quarterly, annual, and in-depth program reviews; and
• Information related to fundraising agreements for activities described in 212 FW 8.
Over the life of this clearance, the Service plans to develop a digital platform and process to collect information directly from Friends groups. Until that occurs, Friends groups will submit information through form and non-form responses.

Proposed Revisions to This Information Collection
With this submission, we are proposing the following revisions to the existing information collection:
1. (New) National Friends Program: Friends Academy Application (Form 3-2565) —The Service will use the Friends Academy Application form with the Friends Academy, an advanced training program for board members and staff of Friends organizations who are beyond the formative stages of development. The overarching purpose of the Academy is to cultivate emerging Friends leaders by providing a broader understanding of the Service and enhancing skills to increase the effectiveness of Friends/Service partnerships.
This program will be exclusively offered to Friends board members and staff who have been serving for at least 1 year. In addition, people who have at least 2 years of involvement as Friends members or volunteers may be considered. People eligible for the program fall into two application pools—Service staff or other Friends may nominate a Friend, or a Friend may self-nominate. These application forms will be completed and submitted directly to the National Friends Coordinator specified in the “Application Submission Instructions” section.
• Part I (Region and Application Type) of each application simply gathers the servicing regional office and specifies the type of nomination (Self-nomination or Staff nominating a Friend) that dictates which sections will be filled out.
• Part II (Self-Nomination) and Part III (Nominating a Friend) both gather basic information to identify the nominee (name, address, phone number, and email address) and specify the nominee's baseline credentials for gaining entry to the Academy program (Friends organization affiliation, years of affiliation, Service programs supported, volunteer history, board position, committees served). In addition, these sections also solicit professional information that helps the Academy's selection personnel evaluate the nominee's merits as a candidate. Each of these parts gather identical information regarding the nominee.
• Part IV (Required Service Site or Program Manager Endorsement and Signature) requires gathering endorsements and signatures from both the nominee's Service Site Program Manager and from a member of the nominee's Friends Organization.
• Part V (Required Service Site or Program Manager Endorsement and Signature Continued) compiles the signatures of all the individuals involved in preparing the application: self-applicant or nominating official, project leader or manager, and Friends Organization representative.
2. (New) National Friends Program: Friends Mentoring Visit Form (Form 3-2566) —Friends groups will use the Mentoring Visit Form to request a mentor visit. The form is completed by the Friends group, but the Service staff at the field station which the Friends support must be consulted and must sign the form before it is submitted to Service headquarters.
3. (New) National Friends Program: Friends Mentor Application (Form 3-2567) —The National Friends Mentoring Program will be open to both Service staff and members of the public ( e.g., retired Service Employees, Friends members). Applicants will volunteer to serve in a cadre of trained mentor professionals. These professionals will use the National Friends Program Mentor Application form to apply to enter into mentoring relationships with current Friends groups who request this service. The mentor relationship typically lasts for one full year and involves an on-site visit to the Friends group and Service site which the Friends group supports in an official capacity ( i.e., has a Friends Partnership Agreement). The Service generally issues a call for mentor applications every 3 to 5 years, at most.
4. (Revised) Internal Financial Control Documentation (Forms 990 or 990-EZ Filers) —We reduced the number of respondents specific to this requirement to reflect only those Friends groups that file Forms 990 or 990-EZ. Tax information for this collection will be retrieved by Service members from information published on the IRS website and not requested from Friends groups.
5. (New) Internal Financial Control Documentation (Forms 990-N or Postcard Filers) —About 80 percent of the Service's Friends groups are very small, each with annual gross receipts totaling $50,000 or less. This means that they do not file a 990 or 990-EZ (the Internal IRS forms on which organizations must declare all donations and revenues). Rather, these smaller groups, which represent most of our partners, are required to file only the 990-N, or e-Postcard. The 990-N or e-Postcard simply asks for confirmation that the organization has annual gross receipts totaling $50,000 or less. Collection of this information, per the OIG audit, from Friends groups filing the 990-N or ePostcard is not duplicative of what the IRS requires from 80 percent of our Friends groups, nor is it publicly available information on the IRS website. Therefore, we need to request this information on our Annual Report (for only those small entities filing the 990-N or e-Postcard).
Title of Collection: U.S. Fish and Wildlife Service Agreements with Friends Organizations.
OMB Control Number: 1018-0193.
Form Numbers: 3-2565 through 3-2567.
Type of Review: Revision of a currently approved collection.
Respondents/Affected Public: Friends Groups of the National Wildlife Refuge System.
Total Estimated Number of Annual Respondents: 1,693.
Total Estimated Number of Annual Responses: 1,693.
Estimated Completion Time per Response: Varies from 2 hours to 40 hours, depending on activity.
Total Estimated Number of Annual Burden Hours: 20,285.
Respondent's Obligation: Required to obtain or retain a benefit.
Frequency of Collection: On occasion.
Total Estimated Annual Nonhour Burden Cost: None.
An agency may not conduct or sponsor and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.
The authority for this action is the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ).
Madonna Baucum,

Information Collection Clearance Officer, U.S. Fish and Wildlife Service.
DEPARTMENT OF THE INTERIOR
Fish and Wildlife Service
[Docket No. FWS-HQ-MB-2024-0044; FXMB1231099BPP0-245-FF09M30000; OMB Control Number 1018-New]
Agency Information Collection Activities; National Double-Crested Cormorant Survey

AGENCY:
Fish and Wildlife Service, Interior.

ACTION:
Notice of information collection; request for comment.

SUMMARY:
In accordance with the Paperwork Reduction Act of 1995, we, the U.S. Fish and Wildlife Service (Service), are proposing a new information collection.

DATES:
Interested persons are invited to submit comments on or before June 21, 2024.

ADDRESSES:
Send your comments on the information collection request (ICR) by one of the following methods (please reference “1018-DCC” in the subject line of your comments):
• Internet (preferred): https://www.regulations.gov. Follow the instructions for submitting comments on Docket No. FWS-HQ-JAO-2024-0044.
• U.S. Mail: Service Information Collection Clearance Officer, U.S. Fish and Wildlife Service, 5275 Leesburg Pike, MS: PRB (JAO/3W), Falls Church, VA 22041-3803.

FOR FURTHER INFORMATION CONTACT:
To request additional information about this ICR, contact Madonna L. Baucum, Service Information Collection Clearance Officer, by email at Info_Coll@fws.gov, or by telephone at (703) 358-2503. Individuals in the United States who are deaf, deafblind, hard of hearing, or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to access telecommunications relay services. Individuals outside the United States should use the relay services offered within their country to make international calls to the point-of-contact in the United States.

SUPPLEMENTARY INFORMATION:
In accordance with the Paperwork Reduction Act (PRA, 44 U.S.C. 3501 et seq. ) and its implementing regulations at 5 CFR 1320.8(d)(1), all information collections require approval under the PRA. We may not conduct or sponsor and you are not required to respond to a collection of information unless it displays a currently valid OMB control number.
As part of our continuing effort to reduce paperwork and respondent burdens, we invite the public and other Federal agencies to comment on new, proposed, revised, and continuing collections of information. This helps us assess the impact of our information collection requirements and minimize the public's reporting burden. It also helps the public understand our information collection requirements and provide the requested data in the desired format.
We are especially interested in public comment addressing the following:
(1) Whether or not the collection of information is necessary for the proper performance of the functions of the agency, including whether or not the information will have practical utility;
(2) The accuracy of our estimate of the burden for this collection of information, including the validity of the methodology and assumptions used;
(3) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(4) How might the agency minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of response.
Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this ICR. Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
Abstract: The U.S. Fish and Wildlife Service (Service, we) is the Federal agency delegated with the primary responsibility for managing migratory birds. Our authority derives from the Migratory Bird Treaty Act of 1918 (MBTA; 16 U.S.C. 703-712), as amended, which implements conventions with Great Britain (for Canada), Mexico, Japan, and Russia. We implement the provisions of the MBTA through the regulations in parts 10, 13, 20, 21, 22, and 92 of title 50 of the Code of Federal Regulations (CFR). The MBTA protects migratory birds (listed in 50 CFR 10.13) from take directed at birds, except as authorized under the MBTA. Regulations pertaining to specific migratory bird permit types are at 50 CFR parts 21 and 22.
The double-crested cormorant (cormorant; Phalacrocorax auritus ) is a fish-eating migratory bird that is distributed across a large portion of North America. There are five different breeding populations—the Alaska, Pacific (or Western), Interior, Atlantic, and Southern populations. Although each of these populations is categorized by breeding range, the populations commingle to various extents on their migration and wintering areas, with birds from populations closer to each other overlapping more than those that are more distant.
In response to ongoing damage at aquaculture facilities and other damage and conflicts associated with increasing cormorant populations, the Service administers regulations that authorize the take of cormorants through regular depredation permits (50 CFR 21.100) or the special double-crested cormorant permit available only to State and Tribal fish and wildlife agencies (50 CFR 21.123). Take through these two permit types is supported by assessments that were completed in 2017 and 2020 under the National Environmental Policy Act (NEPA; 42 U.S.C. 4321 et seq. ). The 2017 environmental assessment (EA) supported issuance of depredation permits (82 FR 52936; November 15, 2017), and the 2020 environmental impact statement (EIS) supported creation of the special double-crested cormorant permit (85 FR 85535; December 29, 2020). To determine sustainable take of cormorants, the 2020 EIS contained a potential take limit (PTL) assessment that is used to inform permitting decisions.
Federal, State, Tribal, and many private entities share the Service's goal of maintaining sustainable cormorant populations. Many of these entities conduct cormorant monitoring and contribute to ongoing research and regional or local cormorant management efforts. However, to date, coordinated monitoring across the four North American flyways (Pacific, Central, Mississippi, and Atlantic), with shared objectives and standardized sampling design, does not exist. The desire to enhance existing monitoring efforts was shared in comments by States, Tribes, nongovernment organizations, and members of the public during the 2020 rulemaking process. Therefore, the Service committed to work in partnership with the Flyways to develop a monitoring program for each subpopulation of cormorants. In the 2020 final EIS, the Service made the commitment to monitor cormorant populations and produce a report every 5 years that provides analyses from population monitoring and other status information. The survey, which was develop in coordination with the four Flyways, will be conducted for the first time in 2024 and is scheduled to be repeated every 5 years in order to update population estimates and PTL assessments.
A combination of Federal (Service and U.S. Department of Agriculture Wildlife Services) and State biologists, coordinated through Flyway working groups, will conduct the survey during April through June 2024. All surveys will use a standardized data sheet that documents the following:
1. Completion data:
a. State, county, names of observers, and agency; and
b. Date/time, weather conditions (wind, sky, temperature).
2. Nesting colony information:
a. Colony name;
b. Latitude/longitude;
c. Whether the colony was existing, reestablished, or new;
d. Nest substrate; and
e. Site habitat condition.
3. Method used to survey the colony ( i.e., ground count or aerial count).
4. Nest counts:
a. Number of active or inactive nests (with number of unknown);
b. Whether the entire colony was surveyed;
c. Whether co-nesting species were observed; and
d. Whether photos and/or videos were taken.
5. General comments from the observer.
To be flexible, States will have the option to use an electronic version of the datasheet (ArcGIS Survey123 software) or a paper-based survey form. The data the Service collects through the range-wide cormorant monitoring program will be used to update cormorant population estimates and to update PTL assessments with the most up-to-date information as specified in the 2020 EIS. The updated take limits would also inform future Service permit allocation. The Service will share the population estimates and PTL assessments with State and Tribal fish and wildlife agencies to inform their respective management actions, as well as with other Federal agencies, including the U.S. Department of Agriculture Wildlife Services program.
Title of Collection: National Double-Crested Cormorant Survey.
OMB Control Number: 1018-New.
Form Number: None.
Type of Review: New.
Respondents/Affected Public: State/local/Tribal government (State biologists coordinated through the four North American Flyways (Pacific, Central, Mississippi, and Atlantic)).
Total Estimated Number of Annual Respondents: 40.
Total Estimated Number of Annual Responses: 1,016.
Estimated Completion Time per Response: 4 hours (30 minutes reporting and 3.5 hours recordkeeping).
Total Estimated Number of Annual Burden Hours: 4,064.
Respondent's Obligation: Voluntary.
Frequency of Collection: One time.
Total Estimated Annual Nonhour Burden Cost: None.
An agency may not conduct or sponsor and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.
The authority for this action is the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ).
Madonna Baucum,

Information Collection Clearance Officer, U.S. Fish and Wildlife Service.
DEPARTMENT OF JUSTICE
Antitrust Division
Notice Pursuant to the National Cooperative Research and Production Act of 1993—Countering Weapons of Mass Destruction
Notice is hereby given that, on January 8, 2024, pursuant to section 6(a) of the National Cooperative Research and Production Act of 1993, 15 U.S.C. 4301 et seq. (“the Act”), Countering Weapons of Mass Destruction (“CWMD”) has filed written notifications simultaneously with the Attorney General and the Federal Trade Commission disclosing changes in its membership. The notifications were filed for the purpose of extending the Act's provisions limiting the recovery of antitrust plaintiffs to actual damages under specified circumstances. Specifically, Cam Lock (UAS) LLC, Fallbrook, CA; Columbus Nanowork Inc, Columbus, OH; Defense Industry Advisors LLC, Dayton, OH; The Henry M. Jackson Foundation for the Advancement of Military Medicine Inc, Bethesda, MD; and SC&A Inc, Arlington, VA have been added as parties to this venture.
Also, Accurate Energetic Systems LLC, McEwen, TN; Armtec Countermeasures, Coachella, CA; Blueforce Development Corp, Newburyport, MA; Chenega Support Services LLC, San Antonio, TX; Gates Defense Systems LLC, St. Petersburg, FL; Lockheed Martin Corp, Morrestown, NJ; Murtech Inc, Glen Burnie, MD; NexGen Communications LLC, Nashua, NH; and OmniMask LLC, Lafayette, CA have withdrawn from this venture.
No other changes have been made in either the membership or planned activity of the group research project. Membership in this group research project remains open, and CWMD intends to file additional written notifications disclosing all changes in membership.
On January 31, 2018, CWMD filed its original notification pursuant to section 6(a) of the Act. The Department of Justice published a notice in the Federal Register pursuant to section 6(b) of the Act on March 12, 2018 (83 FR 10750).
The last notification was filed with the Department on October 9, 2023. A notice was published in the Federal Register pursuant to section 6(b) of the Act on December 15, 2023 (88 FR 86929).
Suzanne Morris,

Deputy Director Civil Enforcement Operations, Antitrust Division.
DEPARTMENT OF JUSTICE
[OMB Number 1121-0030]
Agency Information Collection Activities; Proposed eCollection eComments Requested; Reinstatement of a Previously Approved Collection; Capital Punishment Report of Inmates Under Sentence of Death

AGENCY:
Department of Justice.

ACTION:
30-Day notice.

SUMMARY:
The Department of Justice (DOJ), Bureau of Justice Statistics, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.

DATES:
Comments are encouraged and will be accepted for 30 days until May 22, 2024.

FOR FURTHER INFORMATION CONTACT:
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact: Tracy L. Snell, Statistician, Bureau of Justice Statistics, 810 Seventh St NW, Washington, DC 20531 (email: Tracy.L.Snell@usdoj.gov; telephone: 202-598-1660).

SUPPLEMENTARY INFORMATION:
The proposed information collection was previously published in the Federal Register , 89 FR 10098-10099 on February 13, 2024, allowing a 60-day comment period.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
—Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
—Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
—Enhance the quality, utility, and clarity of the information to be collected; and/or
—Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Written comments and recommendations for this information collection should be submitted within 30 days of the publication of this notice on the following website www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function and entering either the title of the information collection or the OMB Control Number 1121-0030. This information collection request may be viewed at www.reginfo.gov. Follow the instructions to view Department of Justice, information collections currently under review by OMB.
DOJ seeks PRA authorization for this information collection for three (3) years. OMB authorization for an ICR cannot be for more than three (3) years without renewal. The DOJ notes that information collection requirements submitted to the OMB for existing ICRs receive a month-to-month extension while they undergo review.

Overview of This Information Collection
1. Type of Information Collection: Extension of a currently approved collection.
2. Title of the Form/Collection: Capital Punishment Report of Inmates Under Sentence of Death.
3. Agency form number, if any, and the applicable component of the Department of Justice sponsoring the collection: The Capital Punishment Report of Inmates Under Sentence of Death (NPS-8) contains four forms: NPS-8 (Report of Inmates Under Sentence of Death; NPS-8A (Update Report of Inmates Under Sentence of Death); NPS-8B (Status of Death Penalty Statutes—No Statute in Force); and NPS-8C (Status of Death Penalty Statutes—Statute in Force). The applicable component within the Department of Justice is the Bureau of Justice Statistics (BJS), in the Office of Justice Programs. The NPS-8 collection is fielded annually. BJS requests clearance for the 2023, 2024, and 2025 NPS-8 under OMB Control No. 1121-0030. The NPS-8 was last approved under OMB Control No. 1121-0030 (exp. date 01/31/2024).
4. Affected public who will be asked or required to respond, as well as a brief abstract: Affected Public: State departments of correction, state Attorneys General, the Federal Bureau of Prisons, the Federal Bureau of Prisons, and the U.S. Attorney for the District of Columbia.
Abstract: For the NPS-8 and NPS-8A forms, the affected public consists for 33 respondents from state departments of correction and the Federal Bureau of Prisons (DOC staff). Staff responsible for keeping records on inmates under sentence of death in their jurisdiction and in their custody are asked to provide information for the following categories: condemned inmates' demographic characteristics, legal status at the time of capital offense, capital offense for which imprisoned, number of death sentences imposed, criminal history information, reason for removal and current status if no longer under sentence of death, method of execution, and cause of death by means other than execution. For the NPS-8B and NPS-8C, the affected public includes 52 respondents from state Attorneys General, and the U.S. Attorney for the District of Columbia (AG staff). These reporters provide information pertaining to the status of and changes to death penalty statutes in their jurisdictions during the calendar year. BJS plans to publish this information in reports and reference it when responding to queries from the U.S. Congress, Executive Office of the President, the U.S. Supreme Court, state officials, international organizations, researchers, students, the media, and others interested in criminal justice statistics.
5. Obligation to Respond: Voluntary.
6. Total Estimated Number of Respondents: 85.
7. Estimated Time per Respondent: 38 hours for DOC staff and 16 minutes for AG staff.
8. Frequency: Once a year.
9. Total Estimated Annual Time Burden: 1,292 hours
10. Total Estimated Annual Other Costs Burden: $0.
Table 1—Total Estimated Burden Hours
Form | Number of respondents | Freq | Total annual responses | Time per survey (mins) | Follow-up responses | Time for follow-up (mins) | Total time (mins) | Total annual burden (hrs)
NPS-8 | 33 | 1 | 19 | 30 | 10 | 15 | 720 | 12 (720 min/60 min).
NPS-8A | 33 | 1 | 2,469 | 30 | 124 | 15 | 75,930 | 1,266 (75930 min/60 min).
NPS-8B/8C | 52 | 1 | 52 | 15 | 5 | 10 | 830 | 14 (830 min/60 min).
Unduplicated Totals | 85 | | 2,540 | | | | | 1,292
If additional information is required, contact: Darwin Arceo, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, United States Department of Justice, Two Constitution Square, 145 N Street NE, 4W-218 Washington, DC 20530.
Dated: April 16, 2024.
Darwin Arceo,

Department Clearance Officer for PRA, U.S. Department of Justice.
DEPARTMENT OF JUSTICE
[OMB 1140-0106]
Agency Information Collection Activities; Proposed eCollection eComments Requested; The Arson and Explosives Training Registration for Non-ATF Employees—ATF Form 6310.1

AGENCY:
Bureau of Alcohol, Tobacco, Firearms and Explosives, Department of Justice.

ACTION:
30-Day notice.

SUMMARY:
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.

DATES:
Comments are encouraged and will be accepted for 30 days until May 22, 2024.

FOR FURTHER INFORMATION CONTACT:
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact: Warren Smith, NCETR, by email at NCETR-mailbox@atf.gov or by telephone at 256-261-7684.

SUPPLEMENTARY INFORMATION:
The proposed information collection was previously published in the Federal Register , 89 FR 11870, on Thursday, February 15, 2024, allowing a 60-day comment period.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
—Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
—Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
—Enhance the quality, utility, and clarity of the information to be collected; and/or
—Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Written comments and recommendations for this information collection should be submitted within 30 days of the publication of this notice on the following website www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function and entering either the title of the information collection or the OMB Control Number 1140-0106. This information collection request may be viewed at www.reginfo.gov. Follow the instructions to view Department of Justice, information collections currently under review by OMB.
DOJ seeks PRA authorization for this information collection for three (3) years. OMB authorization for an ICR cannot be for more than three (3) years without renewal. The DOJ notes that information collection requirements submitted to the OMB for existing ICRs receive a month-to-month extension while they undergo review.

Overview of This Information Collection
1. Type of Information Collection: Extension of a previously approved collection.
2. Title of the Form/Collection: The Arson and Explosives Training Registration for Non-ATF Employees.
3. Agency form number, if any, and the applicable component of the Department of Justice sponsoring the collection: ATF Form 6310.1.
Component: Bureau of Alcohol, Tobacco, Firearms and Explosives, U.S. Department of Justice.
4. Affected public who will be asked or required to respond, as well as a brief abstract:
Affected Public: Local and Tribal Governments, Federal Government.
Abstract: ATF currently provides varying levels of arson and explosive training, to include techniques and procedures, to federal, state and local, military and international law enforcement investigators. The attached form is the Arson and Explosives Training Registration Request for Non-ATF Employees (ATF R 6310.1). The form is used by prospective students when applying to attend the various trainings provided by ATF.
5. Obligation to Respond: Required to obtain or retain benefits.
6. Total Estimated Number of Respondents: 500 respondents.
7. Estimated Time per Respondent: 6 minutes.
8. Frequency: Once annually.
9. Total Estimated Annual Time Burden: 50 hours.
10. Total Estimated Annual Other Costs Burden: $0.
If additional information is required, contact: Darwin Arceo, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, United States Department of Justice, Two Constitution Square, 145 N Street NE, 4W-218 Washington, DC 20530.
Dated: April 16. 2024.
Darwin Arceo,

Department Clearance Officer for PRA, U.S. Department of Justice.
DEPARTMENT OF JUSTICE
Notice of Lodging of Proposed Consent Decree Under the Comprehensive Environmental Response, Compensation, and Liability Act
On April 11, 2024, the Department of Justice lodged a proposed consent decree with the United States District Court for the District of New Jersey in the lawsuit entitled United States, New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection, and the Administrator of the New Jersey Spill Compensation Fund v. PPG Industries, Inc., Civil Action No. 2:24-04771.
The United States filed this lawsuit under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), on behalf of the U.S. Environmental Protection Agency (“EPA”). The New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection, and the Administrator of the New Jersey Spill Compensation Fund (collectively, “NJDEP”) are co-plaintiffs. PPG Industries, Inc. (“PPG”) is the defendant named in the complaint. The complaint seeks injunctive relief and reimbursement of response costs in connection with the Riverside Industrial Park Superfund Site (“Site”) located in Newark, New Jersey.
Under the proposed consent decree, PPG is required to (a) design and implement the components of the remedy selected for the Site in EPA's September 28, 2021, Record of Decision that relate to waste material, sewer water, soil gas, and soil/fill material, and (b) perform groundwater monitoring and implement institutional controls (the “Work”). The estimated cost of the Work is about $15 million. PPG will also reimburse the United States $2,883,120 and NJDEP $116,880 for past costs relating to the Site and will pay the United States and NJDEP for future response costs they incur relating to the Work. In return, the United States agrees not to sue or take administrative action under sections 106 and 107 of CERCLA against PPG for the Work, EPA past costs relating to the Site, and future response costs EPA will incur relating to the Work. NJDEP also agrees not to sue or take administrative action against PPG for NJDEP past costs relating to the Site and for future response costs NJDEP will incur relating to the Work.
The publication of this notice opens a period for public comment on the proposed consent decree. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to United States and NJDEP v. PPG Industries, Inc, D.J. Ref. No. 90-11-2-12543. All comments must be submitted no later than sixty (60) days after the publication date of this notice. This notice is meant to replace a notice published in the Federal Register on April 16, 2024, which provided a thirty-day public comment period, and extends the public comment period on the proposed consent decree from thirty days to sixty days. Comments may be submitted either by email or by mail:
To submit comments: | Send them to:
By email | pubcomment-ees.enrd@usdoj.gov .
By mail | Assistant Attorney General, U.S. DOJ—ENRD, P.O. Box 7611, Washington, DC 20044-7611.
Any comments submitted in writing may be filed in whole or in part on the public court docket without notice to the commenter.
During the public comment period, the proposed consent decree may be examined and downloaded at this Justice Department website: https://www.justice.gov/enrd/consent-decrees. If you require assistance accessing the proposed consent decree, you may request assistance by email or by mail to the addresses provided above for submitting comments.
Henry S. Friedman,

Assistant Section Chief, Environmental Enforcement Section, Environment and Natural Resources Division.
DEPARTMENT OF JUSTICE
[OMB 1140-0030]
Agency Information Collection Activities; Proposed eCollection eComments Requested; Records and Supporting Data: Importation, Receipt, Storage, and Disposition by Explosives Importers, Manufacturers, Dealers, and Users Licensed Under Title 18 U.S.C. Chapter 40 Explosives

AGENCY:
Bureau of Alcohol, Tobacco, Firearms and Explosives, Department of Justice.

ACTION:
30-Day notice.

SUMMARY:
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.

DATES:
Comments are encouraged and will be accepted for 30 days until May 22, 2024.

FOR FURTHER INFORMATION CONTACT:
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact: Michael O'Lena, Explosives Industry Programs Branch by email at eipb-informationcollection@atf.gov or telephone at 202-648-7120.

SUPPLEMENTARY INFORMATION:
The proposed information collection was previously published in the Federal Register , 89 FR 8248, on Tuesday, February 6, 2024, allowing a 60-day comment period.
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
—Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
—Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
—Enhance the quality, utility, and clarity of the information to be collected; and/or
—Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology, e.g., permitting electronic submission of responses.
Written comments and recommendations for this information collection should be submitted within 30 days of the publication of this notice on the following website www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function and entering either the title of the information collection or the OMB Control Number 1140-0030. This information collection request may be viewed at www.reginfo.gov. Follow the instructions to view Department of Justice, information collections currently under review by OMB.
DOJ seeks PRA authorization for this information collection for three (3) years. OMB authorization for an ICR cannot be for more than three (3) years without renewal. The DOJ notes that information collection requirements submitted to the OMB for existing ICRs receive a month-to-month extension while they undergo review.

Overview of This information Collection:
1. Type of Information Collection: Extension of a previously approved collection.
2. Title of the Form/Collection: Records and Supporting Data: Importation, Receipt, Storage, and Disposition by Explosives Importers, Manufacturers, Dealers, and Users Licensed Under Title 18 U.S.C. Chapter 40 Explosives.
3. Agency form number, if any, and the applicable component of the Department of Justice sponsoring the collection: None.
Component: Bureau of Alcohol, Tobacco, Firearms and Explosives, U.S. Department of Justice.
4. Affected public who will be asked or required to respond, as well as a brief abstract:
Affected Public: Private Sector-for or not for profit institutions, Federal Government.
Abstract: These records show daily activities in the importation, manufacture, receipt, storage, and disposition of all explosives materials covered under 18 U.S.C. Chapter 40. The records are used to show where and to whom explosives materials are distributed.
5. Obligation to Respond: Mandatory per 18 U.S.C. 842(f), (g), (j), (k), 843(f) and 847, and are established in the manner set forth in 27 CFR 555.121-129.
6. Total Estimated Number of Respondents: 9,096.
7. Estimated Time per Respondent: 12.6 hours.
8. Frequency: Once annually.
9. Total Estimated Annual Time Burden: 573,048 hours.
10. Total Estimated Annual Other Costs Burden: $0.
If additional information is required, contact: Darwin Arceo, Department Clearance Officer, Policy and Planning Staff, Justice Management Division, United States Department of Justice, Two Constitution Square, 145 N Street NE, 4W-218 Washington, DC 20530.
Dated: April 16, 2024.
Darwin Arceo,

Department Clearance Officer for PRA, U.S. Department of Justice.
DEPARTMENT OF LABOR
Agency Information Collection Activities; Submission for OMB Review; Comment Request; Demographic Information Collection for MSHA Grants

ACTION:
Notice of availability; request for comments.

SUMMARY:
The Department of Labor (DOL) is submitting this Mine Safety and Health Administration (MSHA)-sponsored information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995 (PRA). Public comments on the ICR are invited.

DATES:
The OMB will consider all written comments that the agency receives on or before May 22, 2024.

ADDRESSES:
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting “Currently under 30-day Review—Open for Public Comments” or by using the search function.

FOR FURTHER INFORMATION CONTACT:
Michael Howell by telephone at 202-693-6782, or by email at DOL_PRA_PUBLIC@dol.gov.

SUPPLEMENTARY INFORMATION:
Section 103(h) of the Federal Mine Safety and Health Act of 1977 (Mine Act), Public Law 95-164 as amended, 30 U.S.C. 813(h), authorizes the Mine Safety and Health Administration (MSHA) to collect information necessary to carry out its duty in protecting the safety and health of miners. Further, section 101(a) of the Mine Act, 30 U.S.C. 811(a), authorizes the Secretary of Labor (Secretary) to develop, promulgate, and revise as may be appropriate, improved mandatory health or safety standards for the protection of life and prevention of injuries in coal and metal and nonmetal mines. MSHA works to prevent death, illness, and injury from mining and to promote safe and healthful workplaces for U.S. miners. Section 115 of the Mine Act, 30 U.S.C. 825, requires MSHA to approve mine operators' health and safety training programs for miners. MSHA administers two grant programs: State Grants and Brookwood-Sago Grants. The grant programs provide training for individuals, miners, employers, and contractors in the recognition, avoidance, and prevention of unsafe and unhealthful working conditions in accordance with section 503 of the Mine Act, 30 U.S.C. 953, and section 14 of the Mine Improvement and New Emergency Response Act of 2006 (MINER Act), 30 U.S.C. 965.
Executive Order 13985 on “Advancing Racial Equity and Support for Underserved Communities Through the Federal Government” emphasizes that the Federal Government's goal in advancing equity is to provide everyone with the opportunity to reach their full potential. Consistent with these aims, each agency must assess whether, and to what extent, its programs and policies perpetuate systemic barriers to opportunities and benefits for people of color and other underserved groups. For additional substantive information about this ICR, see the related notice published in the Federal Register on January 31, 2024 (89 FRN 6134).
Comments are invited on: (1) whether the collection of information is necessary for the proper performance of the functions of the Department, including whether the information will have practical utility; (2) the accuracy of the agency's estimates of the burden and cost of the collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility and clarity of the information collection; and (4) ways to minimize the burden of the collection of information on those who are to respond, including the use of automated collection techniques or other forms of information technology.
This information collection is subject to the PRA. A Federal agency generally cannot conduct or sponsor a collection of information, and the public is generally not required to respond to an information collection, unless the OMB approves it and displays a currently valid OMB Control Number. In addition, notwithstanding any other provisions of law, no person shall generally be subject to penalty for failing to comply with a collection of information that does not display a valid OMB Control Number. See 5 CFR 1320.5(a) and 1320.6.
Agency: DOL-MSHA.
Title of Collection: Demographic Information Collection for MSHA Grants.
OMB Control Number: 1219-0NEW.
Affected Public: Businesses or other for-profits.
Number of Respondents: 150,706.
Frequency: On occasion, quarterly, and annually.
Number of Responses: 150,930.
Annual Burden Hours: 8,093 hours.
Total Estimated Annual Other Costs Burden: $0.
(Authority: 44 U.S.C. 3507(a)(1)(D))
Michael Howell,

Senior Paperwork Reduction Act Analyst.
NATIONAL FOUNDATION ON THE ARTS AND THE HUMANITIES
National Endowment for the Arts
60-Day Notice for the “NEA Panelist Profile Data”

AGENCY:
National Endowment for the Arts, National Foundation on the Arts and the Humanities.

ACTION:
Notice of proposed collection; comment request.

SUMMARY:
The National Endowment for the Arts (NEA), as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995. This program helps to ensure that requested data is provided in the desired format; reporting burden (time and financial resources) is minimized; collection instruments are clearly understood; and the impact of collection requirements on respondents is properly assessed. Currently, the NEA is soliciting comments concerning the proposed information collection of NEA panelist profile data. A copy of the current information collection request can be obtained by contacting the office listed below in the address section of this notice.

DATES:
Written comments must be submitted to the office listed in the ADDRESSES section below within 60 days from the date of this publication in the Federal Register .

ADDRESSES:
Email comments to Daniel Beattie, Director, Office of Guidelines and Panel Operations, National Endowment for the Arts, at: beattied@arts.gov .

FOR FURTHER INFORMATION CONTACT:
Daniel Beattie, Director of Guidelines and Panel Operations, National Endowment for the Arts, at: beattied@arts.gov or 202-682-5688.
The NEA is particularly interested in comments that:
• Evaluate whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility;
• Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
• Enhance the quality, utility, and clarity of the information to be collected; and
• Can help the agency minimize the burden of the collection of information on those who are to respond, including through the electronic submission of responses.
Dated: April 16, 2024.
Daniel Beattie,

Director of Guidelines and Panel Operations, National Endowment for the Arts.
NATIONAL SCIENCE FOUNDATION
Sunshine Act Meetings
The National Science Board's (NSB) Committee on Science and Engineering Policy (SEP) hereby gives notice of the scheduling of a videoconference for the transaction of National Science Board business pursuant to the National Science Foundation Act and the Government in the Sunshine Act.

TIME AND DATE:
Thursday, April 25, 2024, from 1:00 p.m.-2:00 p.m. Eastern.

PLACE:
The meeting will be held by videoconference through the National Science Foundation. Members of the public can observe this meeting through a YouTube livestream. The YouTube link will be available from the NSB meetings web page.

STATUS:
Open.

MATTERS TO BE CONSIDERED:
Chair's opening remarks; discussion of potential contents for Indicators 2026 reports on STEM Talent and Discovery; and discussion and vote on draft NSB brief on the Skilled Technical Workforce.

CONTACT PERSON FOR MORE INFORMATION:
Point of contact for this meeting is Chris Blair, cblair@nsf.gov, 703/292-7000.
Ann E. Bushmiller,

Senior Counsel to the National Science Board.
NATIONAL SCIENCE FOUNDATION
Sunshine Act Meetings
The National Science Board's Committee on Strategy hereby gives notice of the scheduling of a teleconference for the transaction of National Science Board business pursuant to the NSF Act and the Government in the Sunshine Act.

TIME AND DATE:
Thursday, April 25, from 4:00-5:00 p.m. Eastern.

PLACE:
This meeting will be via videoconference through the National Science Foundation, 2415 Eisenhower Avenue, Alexandria, VA 22314.

STATUS:
Closed.

MATTERS TO BE CONSIDERED:
The agenda is: Chair's Opening Remarks about the Agenda; Update and Discussion of NSF's FY 2024 Current Plan and Implications; Long term Planning and FY 2026 Budget Development.

CONTACT PERSON FOR MORE INFORMATION:
Point of contact for this meeting is: Chris Blair, cblair@nsf.gov, 703/292-7000. Meeting information and updates may be found at www.nsf.gov/nsb.
Ann E. Bushmiller,

Senior Counsel to the National Science Board.
NUCLEAR REGULATORY COMMISSION
[NRC-2024-0001]
Sunshine Act Meetings

TIME AND DATE:
Weeks of April 22, 29, and May 6, 13, 20, 27, 2024. The schedule for Commission meetings is subject to change on short notice. The NRC Commission Meeting Schedule can be found on the internet at: https://www.nrc.gov/public-involve/public-meetings/schedule.html.

PLACE:
The NRC provides reasonable accommodation to individuals with disabilities where appropriate. If you need a reasonable accommodation to participate in these public meetings or need this meeting notice or the transcript or other information from the public meetings in another format ( e.g., braille, large print), please notify Anne Silk, NRC Disability Program Specialist, at 301-287-0745, by videophone at 240-428-3217, or by email at Anne.Silk@nrc.gov. Determinations on requests for reasonable accommodation will be made on a case-by-case basis.

STATUS:
Public and closed.
Members of the public may request to receive the information in these notices electronically. If you would like to be added to the distribution, please contact the Nuclear Regulatory Commission, Office of the Secretary, Washington, DC 20555, at 301-415-1969, or by email at Betty.Thweatt@nrc.gov or Samantha.Miklaszewski@nrc.gov.

MATTERS TO BE CONSIDERED:

Week of April 22, 2024

Tuesday, April 23, 2024
9:00 a.m. Strategic Programmatic Overview of the Fuel Facilities and the Spent Fuel Storage and Transportation Business Lines (Public Meeting) (Contact: Haile Lindsay: 301-415-0616)
Additional Information: The meeting will be held in the Commissioners' Hearing Room, 11555 Rockville Pike, Rockville, Maryland. The public is invited to attend the Commission's meeting in person or watch live via webcast at the Web address— https://video.nrc.gov/.

Thursday, April 25, 2024
10:00 a.m. Briefing on the Annual Threat Environment (Closed Ex. 1)

Week of April 29, 2024—Tentative
There are no meetings scheduled for the week of April 29, 2024.

Week of May 6, 2024—Tentative
There are no meetings scheduled for the week of May 6, 2024.

Week of May 13, 2024—Tentative
There are no meetings scheduled for the week of May 13, 2024.

Week of May 20, 2024—Tentative
There are no meetings scheduled for the week of May 20, 2024.

Week of May 27, 2024—Tentative
There are no meetings scheduled for the week of May 27, 2024.

CONTACT PERSON FOR MORE INFORMATION:
For more information or to verify the status of meetings, contact Wesley Held at 301-287-3591 or via email at Wesley.Held@nrc.gov.
The NRC is holding the meetings under the authority of the Government in the Sunshine Act, 5 U.S.C. 552b.
Dated: April 17, 2024.
For the Nuclear Regulatory Commission.
Wesley W. Held,

Policy Coordinator, Office of the Secretary.
NUCLEAR REGULATORY COMMISSION
[Docket No. 70-7004; NRC-2024-0063]
American Centrifuge Operating, LLC; Completion of Operational Readiness Reviews

AGENCY:
Nuclear Regulatory Commission.

ACTION:
Inspection reports; issuance.

SUMMARY:
The U.S. Nuclear Regulatory Commission (NRC) has conducted inspections at the American Centrifuge Plant (ACP) located in Piketon, Ohio and has authorized the introduction of uranium hexafluoride (UF 6 ) to the High-Assay Low-Enriched Uranium (HALEU) demonstration cascade module.

DATES:
April 22, 2024.

ADDRESSES:
Please refer to Docket ID NRC-2024-0063 when contacting the NRC about the availability of information regarding this document. You may obtain publicly available information related to this document using any of the following methods:
• Federal Rulemaking Website: Go to https://www.regulations.gov and search for Docket ID NRC-2024-0063. Address questions about Docket IDs in Regulations.gov to Stacy Schumann; telephone: 301-415-0624; email: Stacy.Schumann@nrc.gov. For technical questions, contact the individual listed in the FOR FURTHER INFORMATION CONTACT section of this document.
• NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly available documents online in the ADAMS Public Documents collection at https://www.nrc.gov/reading-rm/adams.html. To begin the search, select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, at 301-415-4737, or by email to PDR.Resource@nrc.gov. For the convenience of the reader, instructions about obtaining materials referenced in this document are provided in the “Availability of Documents” section.
• NRC's PDR: The PDR, where you may examine and order copies of publicly available documents, is open by appointment. To make an appointment to visit the PDR, please send an email to PDR.Resource@nrc.gov or call 1-800-397-4209 or 301-415-4737, between 8 a.m. and 4 p.m. eastern time (ET), Monday through Friday, except Federal holidays.

FOR FURTHER INFORMATION CONTACT:
Yawar Faraz, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-7220; email: Yawar.Faraz@nrc.gov.

SUPPLEMENTARY INFORMATION:

I. Discussion
The NRC staff conducted an operational readiness and management measures verification review and prepared inspection reports documenting its findings in accordance with the requirements of the NRC's Inspection Manual. The reports are available for review and are listed in Section II of this notice. The publication of this notice satisfies the requirements of paragraph 70.32(k) of title 10 of the Code of Federal Regulations (10 CFR), and section 193(c) of the Atomic Energy Act of 1954, as amended.
License Condition 11 of the ACP license authorized the HALEU demonstration program on June 11, 2021, but prohibited the introduction of UF 6 into the HALEU demonstration cascade modules until the NRC completed an operational readiness and management measures verification review. The NRC staff's review verified that the licensee was in compliance with the performance requirements of 10 CFR 70.61, and that the systems, structures, and components designed to support safe operation of the HALEU Demonstration Cascade were constructed in accordance with license requirements. By letter dated June 12, 2023, the NRC authorized the American Centrifuge Operating, LLC (ACO) to introduce UF 6 into the HALEU demonstration cascade module to produce Category III quantities of special nuclear material (SNM) at the ACP. By letter dated September 21, 2023, the NRC authorized ACO to commence enrichment operations in the HALEU demonstration cascade module to produce Category II quantities of SNM up to the quantity approved on June 11, 2021 at the ACP.

II. Availability of Documents
The documents identified in the following table are available to interested persons through ADAMS, as indicated.
Document description | ADAMS accession No.
Centrus Energy Corp., American Centrifuge Operating—License Amendment 13—Approval to Operate Sixteen Centrifuges to Demonstrate Production of HALEU, dated June 11, 2021 | ML21138A827
Enclosure 1 | LML21148A291
Enclosure 8 | ML21138A828
American Centrifuge Operating, LLC—American Centrifuge Plant, Authorization to Introduce UF 6 into HALEU Demonstration Cascade Module, dated June 12, 2023 | ML23163A168
American Centrifuge Operating, LLC—American Centrifuge Plant, Authorization to Commence Enrichment Operations in the HALEU Demonstration Cascade Module to Produce Category II Quantities of SNM, dated September 21, 2023 | ML23261A587
Inspection Report 2021-006: Construction and Quality Assurance, dated May 10, 2021 | ML21130A343
Inspection Report 2021-009: Operational Safety, Radiation Protection, Nuclear Criticality Safety, Permanent Plant Modifications, Fire Protection, Effluent Control and Environmental Protection, and Permanent Plant Modifications, dated January 27, 2022 | ML22026A367
Inspection Report 2023-007: Operational Safety, Radiation Protection, Nuclear Criticality Safety, Permanent Plant Modification, and Fire Protection, dated May 9, 2023 | ML23128A350
Cover Letter to Inspection Report 2023-405 *: Material Control and Accounting Program, dated May 9, 2023 | ML23128A357
Cover Letter to Inspection Report 2023-406 *: Physical Security, dated June 5, 2023 | ML23152A276
Cover Letter to Inspection Report 2023-407 *: Physical Security, dated September 7, 2023 | ML23248A544
Cover Letter to Inspection Report 2021-408 *: Material Control and Accounting Program, dated September 12, 2023 | ML23256A229
* These report enclosures contain “Security Related Information” and will not be made publicly available in accordance with 10 CFR 2.390(d)(1). The ADAMS accession number for the associated public cover letter is provided.
Dated: April 16, 2024.
For the Nuclear Regulatory Commission.
Samantha C. Lav,

Chief, Fuel Facility Licensing Branch, Division of Fuel Management, Office of Nuclear Material Safety and Safeguards.
NUCLEAR REGULATORY COMMISSION
[Docket Nos. 72-0028, 50-387, and 50-388; NRC-2024-0068]
Susquehanna Nuclear, LLC; Susquehanna Steam Electric Station, Units 1 and 2; Independent Spent Fuel Storage Installation; Environmental Assessment and Finding of No Significant Impact

AGENCY:
Nuclear Regulatory Commission.

ACTION:
Notice; issuance.

SUMMARY:
The U.S. Nuclear Regulatory Commission (NRC) is issuing an environmental assessment (EA) and a finding of no significant impact (FONSI) for an exemption request submitted by Susquehanna Nuclear, LLC (Susquehanna) that would permit Susquehanna Steam Electric Station (SSES) to load six new 89 multi-purpose canisters (MPC) with continuous basket shims (CBS) in the HI-STORM Flood/Wind (FW) MPC Storage System at its SSES Units 1 and 2 independent spent fuel storage installation (ISFSI) in a storage condition where the terms, conditions, and specifications in the Certificate of Compliance (CoC) No. 1032, Amendment No. 5, are not met.

DATES:
The EA and FONSI referenced in this document are available on April 22, 2024.

ADDRESSES:
Please refer to Docket ID NRC-2024-0068 when contacting the NRC about the availability of information regarding this document. You may obtain publicly available information related to this document using any of the following methods:
• Federal Rulemaking Website: Go to https://www.regulations.gov and search for Docket ID NRC-2024-0068. Address questions about Docket IDs in Regulations.gov to Stacy Schumann; telephone: 301-415-0624; email: Stacy.Schumann @nrc.gov. For technical questions, contact the individual listed in the FOR FURTHER INFORMATION CONTACT section of this document.
• NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly available documents online in the ADAMS Public Documents collection at https://www.nrc.gov/reading-rm/adams.html. To begin the search, select “Begin Web-based ADAMS Search.” For problems with ADAMS, please contact the NRC's Public Document Room (PDR) reference staff at 1-800-397-4209, at 301-415-4737, or by email to PDR.Resource@nrc.gov. For the convenience of the reader, instructions about obtaining materials referenced in this document are provided in the “Availability of Documents” section.
• NRC's PDR: The PDR, where you may examine and order copies of publicly available documents, is open by appointment. To make an appointment to visit the PDR, please send an email to PDR.Resource@nrc.gov or call 1-800-397-4209 or 301-415-4737, between 8 a.m. and 4 p.m. eastern time (ET), Monday through Friday, except Federal holidays.

FOR FURTHER INFORMATION CONTACT:
Christian Jacobs, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555; telephone: 301-415-6825; email: Christian.Jacobs@nrc.gov.

SUPPLEMENTARY INFORMATION:

I. Introduction
The NRC is reviewing an exemption request from Susquehanna, dated March 19, 2024, and supplemented on March 21, 2024. Susquehanna is requesting an exemption, pursuant to section 72.7 of title 10 of the Code of Federal Regulations (10 CFR), in paragraphs 72.212(a)(2), 72.212(b)(3), 72.212(b)(5)(i), 72.212(b)(11), and 72.214 that require Susquehanna to comply with the terms, conditions, and specifications of the CoC No. 1032, Amendment No. 5. If approved, the exemption would allow Susquehanna to load six new MPC-89-CBS in the HI-STORM FW MPC Storage System at the SSES ISFSI in a storage condition where the terms, conditions, and specifications in the CoC No. 1032, Amendment No. 5, are not met.

II. Environmental Assessment

Background
SSES is located in Salem Township, Luzerne County, Pennsylvania, just west of the Susquehanna River. The largest community within 10 miles (16 km) of the site is the borough of Berwick, which is approximately 5 miles (8 km) southwest of SSES, in Luzerne County, Pennsylvania. The nearest major metropolitan areas are Wilkes-Barre, Pennsylvania, approximately 20 mi (32 km) to the northeast, and Allentown, Pennsylvania, approximately 50 mi (80 km) to the southeast. Unit 1 began operating in 1981 and Unit 2 began operating in 1982. Susquehanna has been storing spent fuel in an ISFSI at SSES under a general license as authorized by 10 CFR part 72, subpart K, “General License for Storage of Spent Fuel at Power Reactor Sites.” Susquehanna currently uses the HI-STORM FW MPC Storage System under CoC No. 1032, Amendment No. 5, for dry storage of spent nuclear fuel at the SSES ISFSI.

Description of the Proposed Action
The CoC is the NRC approved design for each dry cask storage system. The proposed action would exempt the applicant from the requirements of 10 CFR 72.212(a)(2), 72.212(b)(3), 72.212(b)(5)(i), 72.212(b)(11), and 72.214 only as these requirements pertain to the use of the MPC-89-CBS in the HI-STORM FW MPC Storage System for the near-term planned loading of the canisters. The exemption would allow SSES to load six new MPC-89-CBS in the HI-STORM FW MPC Storage System at the SSES ISFSI, despite the MPC-89-CBS in the HI-STORM FW MPC Storage System not being in compliance with the terms, conditions, and specifications in CoC No. 1032, Amendment No. 5.
The HI-STORM FW MPC Storage System CoC provides the requirements, conditions, and operating limits necessary for use of the system to store spent fuel. Holtec International (Holtec), the designer and manufacturer of the HI-STORM FW MPC Storage System, developed a variant of the design with CBS for the MPC-89, known as MPC-89-CBS. Holtec originally implemented the CBS variant design under the provisions of 10 CFR 72.48, which allows licensees to make changes to cask designs without a CoC amendment under certain conditions (listed in 10 CFR 72.48(c)). After evaluating the specific changes to the cask designs, the NRC determined that Holtec erred when it implemented the CBS variant design under 10 CFR 72.48, as this was not the type of change allowed without a CoC amendment. For this reason, the NRC issued three Severity Level IV violations to Holtec. Susquehanna plans to load six new MPC-89-CBS in the HI-STORM FW MPC Storage System beginning in August 2024. This exemption considers the near-term planned loading of the six canisters with the CBS variant basket design.

Need for the Proposed Action
Susquehanna requested this exemption to allow SSES to load six new MPC-89-CBS in the HI-STORM FW MPC Storage System at the SSES ISFSI for the future loading campaign scheduled to begin in August 2024.
Approval of the exemption request would allow Susquehanna to effectively manage the margin for full core reserve in the SSES spent fuel pool to enable refueling and offloading fuel from the reactor. It would also allow Susquehanna to manage logistical considerations, such as personnel and specific equipment resources, needed to support refueling outages at SSES and across the industry.

Environmental Impacts of the Proposed Action
This EA evaluates the potential environmental impacts of granting an exemption from the terms, conditions, and specifications in CoC No. 1032, Amendment No. 5. The exemption would allow six new MPC-89-CBS to be loaded in the HI-STORM FW MPC Storage System in a near-term loading campaign beginning in August 2024 and maintained in storage at the SSES ISFSI.
The potential environmental impacts of storing spent nuclear fuel in NRC-approved storage systems have been documented in previous assessments. On July 18, 1990 (55 FR 29181), the NRC amended 10 CFR part 72 to provide for the storage of spent fuel under a general license in cask designs approved by the NRC. The EA for the 1990 final rule analyzed the potential environmental impacts of using NRC-approved storage casks. The EA for the HI-STORM FW MPC Storage System, CoC No. 1032, Amendment No. 5, (85 FR 28479), published in 2015, tiers off of the EA issued for the July 18, 1990, final rule. “Tiering” off earlier EAs is a standard process encouraged by the regulations implementing the National Environmental Policy Act of 1969 (NEPA) that entails the use of impact analyses of previous EAs to bound the impacts of a proposed action where appropriate. The Holtec HI-STORM FW MPC Storage System is designed to mitigate the effects of design basis accidents that could occur during storage. Considering the specific design requirements for the accident conditions, the design of the cask would prevent loss of containment, shielding, and criticality control. If there is no loss of containment, shielding, or criticality control, the environmental impacts would not be significant.
The exemptions requested by Susquehanna at the SSES site as they relate to CoC No. 1032, Amendment No. 5, for the HI-STORM FW MPC Storage System are limited to the use of the CBS variant basket design only for the near-term planned loading of six new canisters utilizing the CBS variant basket design. The staff has determined that this change in the basket would not result in either radiological or non-radiological environmental impacts that significantly differ from the environmental impacts evaluated in the environmental assessment supporting the issuance of CoC No. 1032, Amendment No. 5. If the exemption is granted, there would be no significant change in the types or amounts of any effluents released, no significant increase in individual or cumulative public or occupational radiation exposure, and no significant increase in the potential for or consequences from radiological accidents. Accordingly, the Commission concludes that there would be no significant environmental impacts associated with the proposed action.

Alternative to the Proposed Action
The staff considered the no-action alternative. The no-action alternative (denial of the exemption request) would require Susquehanna to keep the spent fuel in the spent fuel pool until older design canisters can be fabricated and delivered to site. Not allowing the planned future loading campaign could affect Susquehanna's ability to manage pool capacity, reactor fuel offloading, and refueling. It could also impact Susquehanna's availability to manage personnel resources and coordinate refueling outages at SSES and across the industry. The NRC has determined that these potential impacts of the no-action alternative could be avoided by proceeding with the proposed exemption, especially given that the staff has concluded in NRC's Safety Determination Memorandum, issued with respect to the enforcement action against Holtec regarding these violations, that fuel can be stored safety in the MPC-89-CBS.

Agencies Consulted
The NRC provided the Pennsylvania Department of Environmental Protection (PDEP) a copy of this draft EA for review by an email dated April 10, 2024. On April 12, 2024, the PDEP provided its concurrence by email.

III. Finding of No Significant Impact
The environmental impacts of the proposed action have been reviewed in accordance with the requirements in 10 CFR part 51, which implement NEPA. Based upon the foregoing environmental assessment, the NRC finds that the proposed action of granting the exemption from the regulations in 10 CFR 72.212(a)(2), 72.212(b)(3), 72.212(b)(5)(i), 72.212(b)(11) and 72.214, which require the licensee to comply with the terms, conditions, and specifications of the CoC, would not significantly impact the quality of the human environment. The exemption in this case would be limited to specific future loading of six canisters with the CBS variant design beginning in August 2024. Accordingly, the NRC has determined that a FONSI is appropriate, and an environmental impact statement is not warranted.

IV. Availability of Documents
The documents identified in the following table are available to interested persons through ADAMS, as indicated.
Document description | ADAMS accession No. or Federal Register notice
Susquehanna's request for exemption, dated March 19, 2024 | ML24079A070
Supplement to request for exemption, dated March 21, 2024 | ML24081A335
Certificate of Compliance No. 1032, Amendment 5, dated June 25, 2020 | ML20163A701 (Package).
Holtec International, Inc.—Notice of Violation; The U.S. Nuclear Regulatory Commission Inspection Report No. 07201014/2022-201, EA-23-044, dated January 30, 2024 | ML24016A190
10 CFR part 72 amendment to allow spent fuel storage in NRC-approved casks, dated July 18, 1990 | 55 FR 29181
EA for part 72 amendment to allow spent fuel storage in NRC-approved casks, dated March 8, 1989 | ML051230231
Final rule for List of Approved Spent Fuel Storage Casks: Holtec International HI-STORM Flood/Wind Multipurpose Canister Storage System CoC No. 1032, Amendment 5, dated May 13, 2020 | 85 FR 28479
Safety Determination of a Potential Structural Failure of the Fuel Basket During Accident Conditions for the HI-STORM 100 and HI-STORM Flood/Wind Dry Cask Storage Systems, dated January 31, 2024 | ML24018A085
NRC email to PDEP requesting review of EA/FONSI for SSES Exemption, dated April 10, 2024 | ML24106A066
Email from PDEP regarding review of EA/FONSI for SSES Exemption, dated April 12, 2024 | ML24106A067
Dated: April 16, 2024.
For the Nuclear Regulatory Commission.
Bernard H. White,

Acting Chief, Storage and Transportation Licensing Branch, Division of Fuel Management, Office of Nuclear Material Safety and Safeguards.
POSTAL REGULATORY COMMISSION
[Docket No. CP2024-130]
New Postal Products

AGENCY:
Postal Regulatory Commission.

ACTION:
Notice.

SUMMARY:
The Commission is noticing a recent Postal Service filing for the Commission's consideration concerning a negotiated service agreement. This notice informs the public of the filing, invites public comment, and takes other administrative steps.

DATES:
Comments are due: April 23, 2024.

ADDRESSES:
Submit comments electronically via the Commission's Filing Online system at http://www.prc.gov. Those who cannot submit comments electronically should contact the person identified in the FOR FURTHER INFORMATION CONTACT section by telephone for advice on filing alternatives.

FOR FURTHER INFORMATION CONTACT:
David A. Trissell, General Counsel, at 202-789-6820.

SUPPLEMENTARY INFORMATION:

Table of Contents
I. Introduction
II. Docketed Proceeding(s)

I. Introduction
The Commission gives notice that the Postal Service filed request(s) for the Commission to consider matters related to negotiated service agreement(s). The request(s) may propose the addition or removal of a negotiated service agreement from the Market Dominant or the Competitive product list, or the modification of an existing product currently appearing on the Market Dominant or the Competitive product list.
Section II identifies the docket number(s) associated with each Postal Service request, the title of each Postal Service request, the request's acceptance date, and the authority cited by the Postal Service for each request. For each request, the Commission appoints an officer of the Commission to represent the interests of the general public in the proceeding, pursuant to 39 U.S.C. 505 (Public Representative). Section II also establishes comment deadline(s) pertaining to each request.
The public portions of the Postal Service's request(s) can be accessed via the Commission's website ( http://www.prc.gov ). Non-public portions of the Postal Service's request(s), if any, can be accessed through compliance with the requirements of 39 CFR 3011.301. ^1
^1 See Docket No. RM2018-3, Order Adopting Final Rules Relating to Non-Public Information, June 27, 2018, Attachment A at 19-22 (Order No. 4679).
The Commission invites comments on whether the Postal Service's request(s) in the captioned docket(s) are consistent with the policies of title 39. For request(s) that the Postal Service states concern Market Dominant product(s), applicable statutory and regulatory requirements include 39 U.S.C. 3622, 39 U.S.C. 3642, 39 CFR part 3030, and 39 CFR part 3040, subpart B. For request(s) that the Postal Service states concern Competitive product(s), applicable statutory and regulatory requirements include 39 U.S.C. 3632, 39 U.S.C. 3633, 39 U.S.C. 3642, 39 CFR part 3035, and 39 CFR part 3040, subpart B. Comment deadline(s) for each request appear in section II.

II. Docketed Proceeding(s)
1. Docket No(s).: CP2024-130; Filing Title: USPS Notice of Amendment to Priority Mail & USPS Ground Advantage Contract 148, Filed Under Seal; Filing Acceptance Date: April 12, 2024; ^2
Filing Authority: 39 CFR 3035.105; Public Representative: Jennaca D. Upperman; Comments Due: April 23, 2024.
^2 Docket Nos. MC2024-124 and CP2024-130, USPS Notice of Filing Revised Financials for Priority Mail & USPS Ground Advantage Contract 148, with Portions Filed Under Seal, April 12, 2024 (Errata).
This Notice will be published in the Federal Register .
Erica A. Barker,

Secretary.
POSTAL REGULATORY COMMISSION
[Docket Nos. MC2024-232 and CP2024-238; MC2024-233 and CP2024-239]
New Postal Products

AGENCY:
Postal Regulatory Commission.

ACTION:
Notice.

SUMMARY:
The Commission is noticing a recent Postal Service filing for the Commission's consideration concerning a negotiated service agreement. This notice informs the public of the filing, invites public comment, and takes other administrative steps.

DATES:
Comments are due: April 24, 2024.

ADDRESSES:
Submit comments electronically via the Commission's Filing Online system at http://www.prc.gov . Those who cannot submit comments electronically should contact the person identified in the FOR FURTHER INFORMATION CONTACT section by telephone for advice on filing alternatives.

FOR FURTHER INFORMATION CONTACT:
David A. Trissell, General Counsel, at 202-789-6820.

SUPPLEMENTARY INFORMATION:

Table of Contents
I. Introduction
II. Docketed Proceeding(s)

I. Introduction
The Commission gives notice that the Postal Service filed request(s) for the Commission to consider matters related to negotiated service agreement(s). The request(s) may propose the addition or removal of a negotiated service agreement from the Market Dominant or the Competitive product list, or the modification of an existing product currently appearing on the Market Dominant or the Competitive product list.
Section II identifies the docket number(s) associated with each Postal Service request, the title of each Postal Service request, the request's acceptance date, and the authority cited by the Postal Service for each request. For each request, the Commission appoints an officer of the Commission to represent the interests of the general public in the proceeding, pursuant to 39 U.S.C. 505 (Public Representative). Section II also establishes comment deadline(s) pertaining to each request.
The public portions of the Postal Service's request(s) can be accessed via the Commission's website (http://www.prc.gov). Non-public portions of the Postal Service's request(s), if any, can be accessed through compliance with the requirements of 39 CFR 3011.301. ^1
^1 See Docket No. RM2018-3, Order Adopting Final Rules Relating to Non-Public Information, June 27, 2018, Attachment A at 19-22 (Order No. 4679).
The Commission invites comments on whether the Postal Service's request(s) in the captioned docket(s) are consistent with the policies of title 39. For request(s) that the Postal Service states concern Market Dominant product(s), applicable statutory and regulatory requirements include 39 U.S.C. 3622, 39 U.S.C. 3642, 39 CFR part 3030, and 39 CFR part 3040, subpart B. For request(s) that the Postal Service states concern Competitive product(s), applicable statutory and regulatory requirements include 39 U.S.C. 3632, 39 U.S.C. 3633, 39 U.S.C. 3642, 39 CFR part 3035, and 39 CFR part 3040, subpart B. Comment deadline(s) for each request appear in section II.

II. Docketed Proceeding(s)
1. Docket No(s).: MC2024-232 and CP2024-238; Filing Title: USPS Request to Add Priority Mail USPS Ground Advantage Contract 218 to Competitive Product List and Notice of Filing Materials Under Seal; Filing Acceptance Date: April 16, 2024; Filing Authority: 39 U.S.C. 3642, 39 CFR 3040.130 through 3040.135, and 39 CFR 3035.105; Public Representative: Jennaca D. Upperman; Comments Due: April 24, 2024.
2. Docket No(s).: MC2024-233 and CP2024-239; Filing Title: USPS Request to Add Priority Mail Express, Priority Mail USPS Ground Advantage Contract 55 to Competitive Product List and Notice of Filing Materials Under Seal; Filing Acceptance Date: April 16, 2024; Filing Authority: 39 U.S.C. 3642, 39 CFR 3040.130 through 3040.135, and 39 CFR 3035.105; Public Representative: Jennaca D. Upperman; Comments Due: April 24, 2024.
This Notice will be published in the Federal Register .
Erica A. Barker,

Secretary.
PRESIDIO TRUST
Privacy Act of 1974; System of Records

AGENCY:
The Presidio Trust.

ACTION:
Notice of a new system of records.

SUMMARY:
Pursuant to the provisions of the Privacy Act of 1974, as amended, the Presidio Trust is issuing a public notice of its intent to establish an Automated License Plate Recognition Program, system of records. INTERIOR PRESIDIO TRUST/Department of Public Safety-01, Automated License Plate Recognition (ALPR) system.

DATES:
This system of records is effective upon publication. New routine uses will be effective May 22, 2024.

ADDRESSES:
You may send comments via email to the interim Privacy Officer, within Presidio Trust's Department of Administration, Luke Donohue, LDonohue@presidiotrust.gov.or via U.S. Mail 1750 Lincoln Blvd. San Francisco, CA, 94129.

FOR FURTHER INFORMATION CONTACT:
Luke Donohue, interim Privacy Officer, Presidio Trust, 1750 Lincoln Blvd. San Francisco, CA, 94129, LDonohue@presidiotrust.gov, (415) 317-8910.

SUPPLEMENTARY INFORMATION:
The Presidio Trust, Internal-01, is establishing Automated License Plate Recognition (ALPR) systems of records. The purpose of the Automated License Plate Recognition (ALPR) system is to provide law enforcement agencies and the Director of the Department of Public Safety with a tool to assist with investigations and crime prevention. Additionally, vehicular behavior habits through its gates of entry can be observed. The Flock Safety ALPR technology captures images of license plates and stores the plate data along with the location and time of capture.
Flock Safety's system consists of cameras and a cloud-based computing system which captures a whole or partial license plate number as well as make, model, and color of the vehicle. All collected data is encrypted using AES-256 encryption with a secure cloud server. Flock Safety allows the customer to own the data collected; the information is not shared or sold with third parties. The images in the system are collected from areas visible to the public where there is no reasonable expectation of privacy. The data collected may include license plate (whole or partial) images, vehicle make/model/color, and a record of the date, time, and location when the image was collected. The system creates a searchable computerized database, segmented by customer, resulting from the Flock Safety ALPR cameras in use by Flock Safety customers. The Flock Safety cameras are installed in a position to capture the license plate area of the vehicle and are focused in such a manner, that avoids collecting unintended images such as the driver or pedestrian(s).
Individuals generally will not have the opportunity to consent to the collection or use of the recording of their images or activities. Individuals who enter onto Federal properties and public areas do not have a reasonable expectation of privacy. Presidio Trust areas may have signs posted that inform individuals of surveillance activities, but in many cases notice may not be provided, or consent obtained for images captured during law enforcement operations or activities.
The Privacy Act of 1974 articulates concepts of how the Federal Government should treat individuals and their information, and imposes duties upon Federal agencies regarding the collection, use, dissemination, and maintenance of personally identifiable information. The Homeland Security Act of 2002 section 222(2) states that the Chief Privacy Officer shall assure that information is handled in full compliance with the fair information practices as set out in the Privacy Act of 1974.45 6 U.S.C. 142(a)(2).
Flock Safety stores all collected data on a secured portal for 30 days on their cloud through Amazon Web Services (AWS) using AES256 bit encryption, which is one of the highest encryption protections in industry standards. All information is encrypted in transit from camera to cloud storage and encrypted at rest in the cloud. Multi-factor secured VPN access is needed to use the secured off-site database.

SYSTEM NAME AND NUMBER:
Automated License Plate Recognition (ALPR) Program, Internal-01.

SECURITY CLASSIFICATION:
Unclassified.

SYSTEM LOCATION:
Presidio Trust, Department of Public Safety, 1750 Lincoln Blvd., San Francisco, CA 94129. watchcenter@presidiotrust.gov

SYSTEM MANAGER(S):
Director of Public Safety, Tomas Kaselionis, tkaselionis@presidiotrust.gov 1750 Lincoln Blvd. San Francisco, CA 94129.

AUTHORITY FOR MAINTENANCE OF THE SYSTEM:
Title I, Omnibus Parks Public Lands Act of 1996, Public Law 104-333, 110 Stat. 4097. 54 U.S.C. 100704, Inventory and Monitoring Program; 54 U.S.C. 100707, Confidentiality of Information.

PURPOSE(S) OF THE SYSTEM:
The purpose of the system is to provide the Director of the Department of Public Safety and law enforcement with a tool (the ALPR system) to assist with investigations and crime prevention.

CATEGORIES OF INDIVIDUALS COVERED BY THE SYSTEM:
The data collected by the system will be stored for the sole purpose of identifying the vehicles of individuals engaged in unlawful conduct. Data may be collected from Presidio Park Visitors, Presidio Trust Staff, and Presidio Park Residents and/or Commercial Tenants.

CATEGORIES OF RECORDS IN THE SYSTEM:
The system contains records of license plate (whole or partial), vehicle make and model, capture time, capture network, capture camera, capture location (latitude, longitude) and image/s of the vehicle.

RECORD SOURCE CATEGORIES:
Authorized Trust staff can import the data from Flock Safety in three ways:
CSV—The authorized user can export a CSV file containing the plate (whole or partial), capture time, capture network, capture camera, capture location (latitude, longitude) and image file name for a specific time frame. The Plate State is not included nor is additional vehicle information such as make and model.
IMAGES only—zip file of JPG files only identifiable by matching file name from the CSV.
PDF Report—Created by (username), date created, search reason, single vehicle image, zoomed in LPR image, GPS Map of camera location, license plate state and number, date captured, camera, camera location, vehicle body, make and color. License plate images and affiliated data will be purged after a 30-day period.

ROUTINE USES OF RECORDS MAINTAINED IN THE SYSTEM, INCLUDING CATEGORIES OF USERS AND PURPOSES OF SUCH USES:
In addition to those disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act, all or a portion of the records or information contained in this system may be disclosed outside the Department of Interior as a routine use pursuant to 5 U.S.C. 552a(b)(3) may be made to:
(1) The appropriate Federal, State, local or foreign agency responsible for obtaining information relevant for investigating, prosecuting, enforcing, or implementing a statue, rule, regulation, or order when Presidio Trust becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
(2) The U.S. Department of Justice or in a proceeding before a court or adjudicative body when:
(a) The United States, the Presidio Trust, a component of the Presidio Trust, or, when represented by the government, an employee of the Presidio Trust is a party to litigation or anticipated litigation or has an interest in such litigation, and
(b) The Presidio Trust determines that the disclosure is relevant and necessary to the litigation and is compatible with the purpose for which the records were compiled.
(3) To a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of that individual.
(4) To appropriate agencies, entities, and persons when:
(a) The Presidio Trust suspects or has confirmed that there has been a breach of the system of records
(b) The Presidio Trust has determined that as a result of the suspected or confirmed breach there is a risk of harm to individuals, The Presidio Trust (including its information systems, programs, and operations), the Federal Government, or national security.
(c) The disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with The Presidio Trusts efforts to respond to the suspected or confirmed breach or to prevent, minimize, or remedy such harm.
(5) To another Federal agency or Federal entity, when the Presidio Trust determines that information from this system of records is reasonably necessary to assist the recipient agency or entity in:
(a) Responding to a suspected or confirmed breach.
(b) Preventing, minimizing, or remedying the risk of harm to individuals, the recipient agency or entity (including its information systems, programs, and operations), the Federal Government, or national or national security, resulting from a suspected or confirmed breach.
(6) To Contractors when the contractor is working on a contract, service, job, or other activity for the Agency and who have a need to have access to the information in performance of their duties or activities for the Agency. Recipients will be required to comply with the requirements of the Privacy Act of 1974 as provided in 5 U.S.C. 552a(m).

POLICIES AND PRACTICES FOR STORAGE OF RECORDS:
Records in this system can be retrieved by an authorized user, either by querying within the application or generating a report. All functions and features are password protected, with multi-factor authorization. The physical security of the Flock Safety data center is managed by Amazon AWS data centers, using AES256 bit encryption, and physical access to the Flock Safety office is restricted to authorized personnel only. Additionally, The Information Security program at Flock Safety aligns with industry recognized security frameworks including: System and Organization Controls (SOC) 2 Type II, SOC 3 Type II, NIST Cybersecurity Framework, Cloud Security Alliance's Cloud Control Matrix, AWS Foundational Security Best Practices, and CIS AWS Foundations Benchmarks.

POLICIES AND PRACTICES FOR RETRIEVAL OF RECORDS:
Flock Safety uses administrative, operational, technical, and physical safeguards to protect ALPR information from unauthorized access, use, destruction, modification, or disclosure. Access to the system is granted by an agency administrator (the Director of Public Safety) and is protected by Username, password, and multi-factor authentication.
Flock Safety gives the Presidio Trust full discretion as to how to manage its system and can limit access for the individual user or their role within the Presidio Trust's administration. Furthermore, Flock Safety tracks all user activity within the system. In addition, system searches are strictly tracked and require the user to provide a reason for every inquiry. This limits misuse or abuse of the system. Monitoring and auditing usage of the system can be conducted by the agency administrator. All logins and queries will be stored and monitored including: Username, Date, Time, Purpose of query, License plate and other elements used to query the system.
These data points will be stored in the Flock Safety system, and periodic audits will be conducted according to the policies of each Flock Safety customer to ensure access was made by authorized persons for legitimate purposes.

POLICIES AND PRACTICES FOR RETENTION AND DISPOSAL OF RECORDS:
V Flock Safety will store the data (data hosting) and ensure proper maintenance and security of data stored in their cloud-based system. Flock Safety will also oversee purging data at the end of the 30 days of storage. Multi-factor secured VPN access to database, and a secure off-site database are used. In the unlikely event of an information breach, all individuals who are believed to be affected or have their information compromised will be notified by the Flock Safety Chief Technology Officer (CTO) or Chief Product Office (CPO).
After the retention period has passed, temporary records are disposed of in accordance with the applicable records schedule and Presidio Trust policy. Data is automatically deleted after 30 day retention period. Records documenting incidents, investigations, or activities requiring retention as evidence are exported as a hashed copy and provided to the appropriate evidence custodian. Records may be retained and disposed of by a receiving agency pursuant to their applicable records schedule(s). Monitoring and auditing usage of the system can be conducted by the administrator, the Director of Public Safety.

ADMINISTRATIVE, TECHNICAL, AND PHYSICAL SAFEGUARDS:
Flock Safety uses administrative, operational, technical, and physical safeguards to protect ALPR information from unauthorized access, use, destruction, modification, or disclosure. The Information Security program at Flock Safety aligns with SOC 2 Type II, SOC 3 Type II, NIST Cybersecurity Framework, Cloud Security Alliance's Cloud Control Matrix, AWS Foundational Security Best Practices, and CIS AWS Foundations Benchmarks.
Flock Quality Assurance: ALPR is automated. License plate images, and details of collection are included in the system without review. Although infrequent, license plate translation may be incomplete or inaccurate. Users will confirm the computer translation prior to taking any action based on ALPR results. Furthermore, Flock Safety cannot release any information collected in the Presidio without expressed consent from the Presidio Trust, Director of Public Safety, as per the contract agreement.

RECORD ACCESS PROCEDURES:
Some of the records in this system may be shared with the Incident Management, Analysis and Reporting System (IMARS) for criminal acts committed on National Park Service (NPS) lands and inside and on the perimeter of protected NPS facilities.
An individual requesting access to their records should send a written inquiry to the applicable System Manager or the Privacy Act Officer identified above. A Privacy Act request must meet the requirements of 36 CFR 1008. The request must include a general description of the records sought and the requester's full name, current address, and sufficient identifying information such as date of birth or other information required for verification of the requestor's identity. The request must be signed and dated and be either notarized or submitted under penalty of perjury in accordance with 28 U.S.C. 1746. Requests submitted by mail must be clearly marked “PRIVACY ACT REQUEST FOR ACCESS” on both the envelope and letter. A request to access records must meet the requirements of 36 CFR 1008 and 36 CFR 1008.13-14, .16-17.

CONTESTING RECORD PROCEDURES:
An individual requesting amendment of their records should send a written request to the applicable System Manager or the Privacy Act Officer as identified above. Instructions for submitting a request for amendment of records are available on the Presidio Trust Privacy Act Requests website at https://www.PresidioTrust.gov/privacy/privacy-act-requests. Requests must clearly identify the records for which amendment is being sought, the reasons for requesting the amendment, and the proposed amendment to the record. The request must include the requester's full name, current address, and sufficient identifying information such as date of birth or other information required for verification of the requestor's identity. The request must be signed and dated and be either notarized or submitted under penalty of perjury in accordance with 28 U.S.C. 1746. Requests submitted by mail must be clearly marked “PRIVACY ACT REQUEST FOR AMENDMENT” on both the envelope and letter. A request for amendment must meet the requirements of 36 CFR 1008 and 36 CFR 1008.18-19, .22, .24.

NOTIFICATION PROCEDURES:
An individual requesting notification of the existence of records about them should send a written inquiry to the applicable System Manager or the Privacy Act Officer as identified above. A Privacy Act request must meet the requirements of 36 CFR 1008. The request must include a general description of the records and the requester's full name, current address, and sufficient identifying information such as date of birth or other information required for verification of the requestor's identity. The request must be signed and dated and be either notarized or submitted under penalty of perjury in accordance with 28 U.S.C. 1746. Requests submitted by mail must be clearly marked “PRIVACY ACT INQUIRY” on both the envelope and letter. A request for notification must meet the requirements of 43 CFR 2.235.

EXEMPTIONS PROMULGATED FOR THE SYSTEM:
None.

HISTORY:
None.
Luke Donohue,

Director of Administration.
RAILROAD RETIREMENT BOARD
Proposed Collection; Comment Request
In accordance with the requirement of section 3506 (c)(2)(A) of the Paperwork Reduction Act of 1995 which provides opportunity for public comment on new or revised data collections, the Railroad Retirement Board (RRB) will publish periodic summaries of proposed data collections.
Comments are invited on: (a) Whether the proposed information collection is necessary for the proper performance of the functions of the agency, including whether the information has practical utility; (b) the accuracy of the RRB's estimate of the burden of the collection of the information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden related to the collection of information on respondents, including the use of automated collection techniques or other forms of information technology.
1. Title and purpose of information collection: Application for Employee Annuity Under the Railroad Retirement Act; OMB 3220-0002.
Section 2(a) of the Railroad Retirement Act (RRA) (45 U.S.C. 231a) provides for payments of age and service, disability, and supplemental annuities to qualified employees. An annuity cannot be paid until the employee stops working for a railroad employer. In addition, the age and service employee must relinquish any rights held to such jobs. A disabled employee does not need to relinquish employee rights until attaining Full Retirement Age, or if earlier, when their spouse is awarded a spouse annuity. Benefits become payable after the employee meets certain other requirements, which depend on the type of annuity payable. The requirements for obtaining the annuities are prescribed in 20 CFR 216 and 220.
To collect the information needed to help determine an applicant's entitlement to, and the amount of, an employee retirement annuity the RRB uses Forms AA-1, Application for Employee Annuity; AA-1d, Application for Determination of Employee Disability; G-204, Verification of Workers Compensation/Public Disability Benefit Information, and electronic Forms AA-1cert, Application Summary and Certification, AA-1sum, Application Summary, and AA-1 (internet), Application for Employee Annuity.
The AA-1 application process obtains information from an applicant about their marital history, work history, military service, benefits from other governmental agencies, railroad pensions and Medicare entitlement for either an age and service or disability annuity. An RRB representative interviews the applicant either at a field office, an itinerant point, or by telephone. During the interview, the RRB representative enters the information obtained into an on-line information system. Upon completion of the interview, the on-line information system generates Form AA-1cert, Application Summary and Certification, or Form AA-1sum, Application Summary, a summary of the information that was provided for the applicant to review and approve. Form AA-1cert documents approval using the traditional pen and ink “wet” signature, and Form AA-1sum documents approval using the alternative signature method called Attestation. When the RRB representative is unable to contact the applicant in person or by telephone, for example, the applicant lives in another country, a manual version of Form AA-1 is used.
Form AA-1d, Application for Determination of Employee's Disability, is completed by an employee who is filing for a disability annuity under the RRA, or a disability freeze under the Social Security Act, for early Medicare based on a disability. Form G-204, Verification of Worker's Compensation/Public Disability Benefit Information, is used to obtain and verify information concerning a worker's compensation or a public disability benefit that is or will be paid by a public agency to a disabled railroad employee. Form AA-1 (internet) can be completed by the applicant and submitted through the RRB's website at www.rrb.gov. One response is requested of each respondent. Completion of the forms is required to obtain/retain a benefit. The RRB proposes no changes to Form AA-1, Form AA-1 (internet), and Form G-204. The RRB proposes a minor editorial change to Form AA-1cert and Form AA-1sum to correct the title of the RB-9 booklet. The RRB proposes minor changes to Form AA-1d:
• Section 1, General Instructions, the date is being updated to 06/06/23 in the 3rd paragraph.
• Section 7 question 38, The entry in parentheses associated with the question now reads (Do not include any self-employment, unemployment or sickness benefits.)
• Section 8 question 45, has been changed to: Are you filing a form AA-1, Application for Employee Annuity, in connection with this application?
• Section 12 of the form. Under the Receipt for your claim section, the last sentence should read: Offices are open to public 9:00 a.m. to 3:00 p.m., Monday through Friday, and closed Federal holidays.
Estimate of Annual Respondent Burden
Form number | Annual responses | Time (minutes) | Burden (hours)
AA-1 (without assistance) | 30 | 62 | 31
AA-1cert (with assistance) | 5,425 | 30 | 2,712
AA-1sum (with assistance) | 2,750 | 29 | 1,329
AA-1 (internet) (without assistance) | 0 | 45 | 0
AA-1d (with assistance) | 2,600 | 60 | 2,600
AA-1d (without assistance) | 5 | 85 | 7
G-204 | 20 | 15 | 5
Total | 10,830 | | 6,684
2. Title and purpose of information collection: Railroad Service and Compensation Reports/System Access Application; OMB 3220-0008.
Under section 9 of the Railroad Retirement Act (RRA) (45 U.S.C. 231h) and section 6 of the Railroad Unemployment Insurance Act (RUIA) (45 U.S.C. 356), the Railroad Retirement Board (RRB) maintains for each railroad employee, a record of compensation paid to that employee by all railroad employers for whom the employee worked after 1936. This record, which is used by the RRB to determine eligibility for, and amount of, benefits due under the laws it administers, is conclusive as to the amount of compensation paid to an employee during such period(s) covered by the report(s) of the compensation by the employee's railroad employer(s), except in cases when an employee files a protest pertaining to his or her reported compensation within the statute of limitations cited in section 9 of the RRA and section 6 of the RUIA.
To enable the RRB to establish and maintain the record of compensation, employers are required to file with the RRB, reports of their employees' compensation, in such manner and form and at such times as the RRB prescribes. Railroad employers' reports and responsibilities are prescribed in 20 CFR 209. The RRB currently utilizes Form BA-3, Annual Report of Creditable Compensation, and Form BA-4, Report of Creditable Compensation Adjustments, to secure the required information from railroad employers. Form BA-3 provides the RRB with information regarding annual creditable service and compensation for each individual who worked for a railroad employer covered by the RRA and RUIA in a given year. Form BA-4 provides for the adjustment of any previously submitted reports and also the opportunity to provide any service and compensation that had been previously omitted. Requirements specific to Forms BA-3 and BA-4 are prescribed in 20 CFR 209.8 and 209.9.
Employers currently have the option of submitting BA-3 and BA-4 reports electronically by CD-ROM, secure Email, File Transfer Protocol (FTP), or online via the RRB's Employer Reporting System (ERS).
The information collection also includes RRB Form BA-12, Application for Employer Reporting internet Access, and Form G-440, Report Specifications Sheet. Form BA-12 is completed by railroad employers to obtain system access to ERS. Once access is obtained, authorized employees may submit reporting forms online to the RRB. The form determines what degree of access (view/only, data entry/modification or approval/submission) is appropriate for that employee. It is also used to terminate an employee's access to ERS. Form G-440, Report Specifications Sheet, serves as a certification document for Forms BA-3 and BA-4 as well as other RRB employer reporting forms (Form BA-6a, BA-6 Address Report (OMB 3220-0005), Form BA-9, Report of Separation Allowance or Severance Pay (OMB 3220-0173) and Form BA-11, Report of Gross Earnings (OMB 3220-0132). It records the type of medium the report was submitted on and serves as a summary recapitulation sheet for reports filed on paper. The RRB proposes no changes to Forms BA-3 (internet), BA-4 (internet), and G-440. The RRB proposes Form BA-12 to add the statement “I understand that I am acting as a trusted referee on behalf of the RRB and I have identity proofed the applicant by resolving, validating, and verifying a state and/or federal government-issued photo ID from the applicant. I also understand that I am responsible for notifying the RRB if, in the future, this individual's access should be terminated.
Estimate of Annual Respondent Burden—Current Burden
Reporting | Responses | Time (minutes) | Burden (hours)
BA-3:
Electronic Media 2 / | 96 | 46.25 (2,775 min) | 4,440
BA-3 (internet) | 617 | 46.25 (2,775 min) | 28,536
Total BA-3 | 713 | | 32,976
BA-4:
Electronic Media 2 / | 355 | 1.00 (60 min) | 355
BA-4 (internet) | 3,942 | .33 (20 min) | 1,314
Total BA-4 | 4,297 | | 1,669
BA-12:
Initial Access | 295 | .33 (20 min) | 123
Access Termination | 38 | .166 (10 min) | 7
Total BA-12 | 333 | | 130
| G-440 (certification):
Form BA-3 (no employees) | 19 | .25 (15 min) | 5
Form BA-11 (no employees) | 60 | .25 (15 min) | 15
Paper forms (without recap) | 7 | .25 (15 min) | 1
Form BA-15 | 600 | .25 (15 min) | 150
Electronic transactions | 94 | .50 (30 min) | 47
BA-3 and BA-4 (with recap) | 125 | 1.25 (75 min) | 156
Total G-440 | 905 | | 374
Grand Total | 6,248 | | 35,149
3. Title and purpose of information collection: Certification of Termination of Service and Relinquishment of Rights; OMB 3220-0016.
Under section 2(e)(2) of the Railroad Retirement Act (RRA) (45 U.S.C. 231a), an age and service annuity, spouse annuity, or divorced spouse annuity cannot be paid unless the Railroad Retirement Board (RRB) has evidence that the applicant has ceased railroad employment and relinquished rights to return to the service of a railroad employer. Under section 2(f)(6) of the RRA, earnings deductions are required for each month an annuitant works in certain non-railroad employment termed Last Pre-Retirement Non-Railroad Employment.
Normally, the employee, spouse, or divorced spouse relinquishes rights and certifies that employment has ended as part of the annuity application process. However, this is not always the case. In limited circumstances, the RRB utilizes Form G-88, Certification of Termination of Service and Relinquishment of Rights, to obtain an applicant's report of termination of employment and relinquishment of rights. One response is required of each respondent. Completion is required to obtain or retain benefits. The RRB proposes no changes to Form G-88.
Estimate of Annual Respondent Burden
Form No. | Annual responses | Time (minutes) | Burden (hours)
G-88 | 20 | 6 | 2
4. Title and purpose of information collection: Statement of Authority to Act for Employee; OMB 3220-0034.
Under section 5(a) of the Railroad Unemployment Insurance Act (RUIA) (45 U.S.C. 355), claims for benefits are to be made in accordance with such regulations as the Railroad Retirement Board (RRB) shall prescribe. The provisions for claiming sickness benefits as provided by section 2 of the RUIA are prescribed in 20 CFR 335.2. Included in these provisions is the RRB's acceptance of forms executed by someone else on behalf of an employee if the RRB is satisfied that the employee is sick or injured to the extent of being unable to sign forms.
The RRB utilizes Form SI-10, Statement of Authority to Act for Employee, to provide the means for an individual to apply for authority to act on behalf of an incapacitated employee and also to obtain the information necessary to determine that the delegation should be made. Part I of the form is completed by the applicant for the authority and Part II is completed by the employee's doctor. One response is requested of each respondent. Completion is required to obtain benefits. The RRB proposes no changes to Form SI-10.
Estimate of Annual Respondent Burden
Form No. | Annual responses | Time (minutes) | Burden (hours)
SI-10 | 17 | 6 | 2
5. Title and purpose of information collection: Supplemental Information on Accident and Insurance; OMB 3220-0036.
Under section 12(o) of the Railroad Unemployment Insurance Act (RUIA) (45 U.S.C 362 (o)), the Railroad Retirement Board (RRB) is entitled to reimbursement of the sickness benefits paid to a railroad employee if the employee receives a sum or damages for the same infirmity for which the benefits are paid. Section 2(f) of the RUIA requires employers to reimburse the RRB for days in which salary, wages, pay for time lost or other remuneration is later determined to be payable. Reimbursements under section 2(f) generally result from the award of pay for time lost or the payment of guaranteed wages. The RUIA prescribes that the amount of benefits paid be deducted and held by the employer in a special fund for reimbursement to the RRB.
The RRB currently utilizes Forms SI-1c, Supplemental Information on Accident and Insurance; SI-5, Report of Payments to Employee Claiming Sickness Benefits Under the RUIA; ID-3s and ID-3s (internet), Request for Lien Information—Report of Settlement; ID-3s-1, Lien Information Under section 12(o) of the RUIA; ID-3u and ID-3u (internet), Request for Section 2(f) Information; ID-30k, Notice to Request Supplemental Information on Injury or Illness; and ID-30k-1, Notice to Request Supplemental Information on Injury or Illness; to obtain the necessary information from claimants and railroad employers. Completion is required to obtain benefits. One response is requested of each respondent. The RRB proposes no changes to Forms SI-1c, SI-5, ID-3s-1, ID-30k, ID-3s (internet), ID-3u (internet). The RRB proposes the following minor non-burden impacting editorial changes to Form ID-3u & Form ID-3s:
• change PRA/PA notice to update the officer title and
• update RRB zip code.
Estimate of Annual Respondent Burden
Form No. | Annual responses | Time | Burden (hours)
SI-1c | 890 | 5 | 74
SI-5 | 10 | 5 | 1
ID-3s (paper & telephone) | 1,700 | 3 | 85
ID-3s (internet) | 4,853 | 3 | 243
ID-3s-1 (paper & telephone) | 1,845 | 3 | 93
ID-3u (paper & telephone) | 152 | 3 | 8
ID-3u (internet) | 596 | 3 | 30
ID-30k | 24 | 5 | 3
Total | 10,070 | | 537
6. Title and purpose of information collection: Employee Non-Covered Service Pension Questionnaire; OMB 3220-0154
Section 215(a)(7) of the Social Security Act provides for a reduction in social security benefits based on employment not covered under the Social Security Act or the Railroad Retirement Act (RRA). This provision applies a different social security benefit formula to most workers who are first eligible after 1985 to both a pension based in whole or in part on non-covered employment and a social security retirement or disability benefit. There is a guarantee provision that limits the reduction in the social security benefit to one-half of the portion of the pension based on non-covered employment after 1956. Section 8011 of Public Law 100-647 changed the effective date of the onset from the first month of eligibility to the first month of concurrent entitlement to the non-covered service benefit and the RRA benefit.
Section 3(a)(1) of the RRA (45 U.S.C. 231b) provides that the Tier I benefit of an employee annuity shall be equal to the amount (before any reduction for age or deduction for work) the employee would receive if entitled to a like benefit under the Social Security Act. The reduction for a non-covered service pension also applies to a Tier I portion of the employee annuity under the RRA when the annuity or non-covered service pension begins after 1985. Since the amount of a spouse's Tier I benefit is one-half of the employee's Tier I, the spouse annuity is also affected.
Form G-209, Employee Non-Covered Service Pension Questionnaire, is used by the RRB to obtain needed information (1) from a railroad employee who while completing Form AA-1, Application for Employee Annuity (OMB No. 3220-0002), indicates entitlement to or receipt of a pension based on employment not covered under the Railroad Retirement Act or the Social Security Act; or (2) from a railroad employee when an independently-entitled divorced spouse applicant believes the employee to be entitled to a non-covered service pension. However, this development is unnecessary if RRB records indicate the employee has 30 or more years of coverage; or (3) from an employee annuitant who becomes entitled to a pension based on employment not covered under the Railroad Retirement Act or the Social Security Act. One response is requested of each respondent. Completion is required to obtain or retain benefits. The RRB proposes no changes to Form G-209.
Estimate of Annual Respondent Burden
Form No. | Annual responses | Time (minutes) | Burden (hours)
G-209 (Partial Questionnaire) | 50 | 1 | 1
G-209 (Full Questionnaire) | 100 | 8 | 13
Total | 150 | | 14
7. Title and purpose of information collection: Availability for Work; OMB 3220-0164
Under section 1(k) of the Railroad Unemployment Insurance Act (45 U.S.C. 231k), unemployment benefits are not payable for any day for which the claimant is not available for work.
Under Railroad Retirement Board (RRB) regulation 20 CFR 327.5, “available for work” is defined as being willing and ready for work. A claimant is “willing” to work if willing to accept and perform for hire such work as is reasonably appropriate to his or her employment circumstances. A claimant is “ready” for work if he or she (1) is in a position to receive notice of work and is willing to accept and perform such work, and (2) is prepared to be present with the customary equipment at the location of such work within the time usually allotted.
Under RRB regulation 20 CFR 327.15, a claimant may be requested at any time to show, as evidence of willingness to work, that reasonable efforts are being made to obtain work. In order to determine whether a claimant is a) available for work, and b) willing to work, the RRB utilizes Forms UI-38, UI Claimant's Report of Efforts to Find Work, and UI-38s, School Attendance and Availability Questionnaire, to obtain information from the claimant and Form ID-8k, Questionnaire—Reinstatement of Discharged or Suspended Employee, from the union representative. One response is completed by each respondent.
The RRB proposes the following changes to the Forms UI-38 and UI-38s. The RRB proposes no changes to Forms UI-38 and ID-8k. The RRB proposes the following minor non-burden editorial changes to Form UI-38s:
• change PRA/PA notice to update the officer title and
• update RRB zip code.
Estimate of Annual Respondent Burden
Form No. | Annual responses | Time (minutes) | Burden (hours)
UI-38s (in person) * | 59 | 6 | 6
UI-38s (by mail) * | 119 | 10 | 20
UI-38 | 3,485 | 11.5 | 668
ID-8k | 6,461 | 5 | 538
Total | 10,124 | | 1,232
8. Title and purpose of information collection: Representative Payee Parental Custody Monitoring; OMB 3220-0176
Under section 12(a) of the Railroad Retirement Act (RRA) (45 U.S.C. 231k), the Railroad Retirement Board (RRB) is authorized to select, make payments to, and to conduct transactions with, a beneficiary's relative or some other person willing to act on behalf of the beneficiary as a representative payee. The RRB is responsible for determining if direct payment to the beneficiary or payment to a representative payee would best serve the beneficiary's interest. Inherent in the RRB's authorization to select a representative payee is the responsibility to monitor the payee to assure that the beneficiary's interests are protected. The RRB utilizes Form G-99D, Parental Custody Report, to obtain information needed to verify that a parent-for-child representative payee still has custody of the child. One response is required from each respondent.
The RRB proposes the following changes to Form G-99d:
• update office hours in top left corner, and
• add the Reporting Period at the top of the form.
Estimate of Annual Respondent Burden
Form No. | Annual responses | Time (minutes) | Burden (hours)
G-99d | 2,100 | 15 | 525
Total | 2,100 | | 525
Additional information or Comments
Additional Information or Comments: To request more information or to obtain a copy of the information collection justification, forms, and/or supporting material, contact Kennisha Money at (312) 469-2591 or Kennisha.Money@rrb.gov. Comments regarding the information collection should be addressed to Brian Foster, Railroad Retirement Board, 844 North Rush Street, Chicago, Illinois 60611-1275 or emailed to Brian.Foster@rrb.gov. Written comments should be received within 60 days of this notice.
Brian Foster,

Clearance Officer.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99968; File No. SR-NYSEAMER-2024-25]
Self-Regulatory Organizations; NYSE American LLC; Notice of Filing and Immediate Effectiveness of Proposed Change To Amend the Connectivity Fee Schedule
April 16, 2024.
Pursuant to Section 19(b)(1) ^1 of the Securities Exchange Act of 1934 (“Act”) ^2 and Rule 19b-4 thereunder, ^3 notice is hereby given that, on March 2, 2024, NYSE American LLC (“NYSE American” or the “Exchange”) filed with the Securities and Exchange Commission (the “Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been prepared by the self-regulatory organization. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.
^1 15 U.S.C. 78s(b)(1).
^2 15 U.S.C. 78a.
^3 17 CFR 240.19b-4.

I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada. The proposed rule change is available on the Exchange's website at www.nyse.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and the Statutory Basis for, the Proposed Rule Change

1. Purpose
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada.
The Exchange expects that the proposed rule change would become operative no later than June 30, 2024. It will announce the proposed change to all Fixed Income and Data Services (“FIDS”) customers in the Markham, Canada third party access center (“Markham”).

Current Markham Services
Currently, a market participant in Markham may purchase a wireless connection to connect to a selection of symbols from the NYSE BBO and Trades data feeds or the NYSE Arca BBO and Trades data feeds (the “Current Market Data Connection”) distributed from the Mahwah, New Jersey data center (“MDC”). ^4 Customers that purchase a Current Market Data Connection are charged a non-recurring initial charge of $5,000 and a $6,500 monthly fee (“MRC”).
^4 See Securities Exchange Act Release No. 90209 (October 15. 2020), 85 FR 67044 (October 21, 2020). Through its FIDS business, Intercontinental Exchange, Inc. (“ICE”) operates the MDC. The New York Stock Exchange LLC (“NYSE”), NYSE Arca, Inc. (“NYSE Arca”), NYSE Chicago, Inc. and NYSE National, Inc. are national securities exchanges that are affiliates of the Exchange (collectively, the “Affiliate SROs”). The Exchange and the Affiliate SROs are indirect subsidiaries of ICE.
There is limited bandwidth available on the wireless network to Markham. Accordingly, the Current Market Data Connection does not transport information for all the symbols included in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds. Rather, FIDS provides connectivity to a selection of such symbols, including the data for which there is demand (the “Current Market Data”). When a market participant requests a Current Market Data Connection, it receives connectivity to the portions of the NYSE BBO and Trades and NYSE Arca BBO and Trades data that FIDS transmits wirelessly. The customer then determines the symbols in the Current Market Data for which it will receive data.

Proposed Changes to Markham Services
The Exchange proposes to replace (a) the source of the selection of symbols from the NYSE BBO and Trades to the NYSE Integrated Feed (“NYSE IF”), and (b) the source of the selection of symbols from the NYSE Arca BBO and Trades to the NYSE Arca Integrated Feed (“NYSE Arca IF” and together with the NYSE IF, the “Integrated Feeds”).
As there is limited bandwidth available on the wireless network to Markham, the Exchange proposes that, similar to the Current Market Data Connection, the proposed market data connection (“Proposed Market Data Connection”) would not transport information for all the symbols included in the NYSE IF and NYSE Arca IF. Rather, FIDS would provide connectivity to a selection of such symbols, including the symbols in the Integrated Feeds for which there is demand (the “Proposed Market Data”). When a market participant requested a Proposed Market Data Connection, it would receive connectivity to the portions of the NYSE IF and NYSE Arca IF that FIDS transmits wirelessly. The customer would then determine the symbols in the Proposed Market Data for which it would receive data. As now, the Exchange would not have visibility into which portions of the data feed a given customer chooses to receive.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, ^5 FIDS anticipates that customers will continue to connect to the same selection of symbols and information, and so there will be no impact on the customers due to the change. It does not currently plan to do so, but if in the future FIDS changes the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data.
^5 Although their list of symbols is the same, the Integrated Feeds provide the information in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds, and more. The NYSE BBO and NYSE Arca BBO data feeds distribute on a real-time basis the same best bid and offer (“BBO”) information that NYSE and NYSE Arca, respectively, report under the Consolidated Quotation (“CQ”) Plan for inclusion in the CQ Plan's consolidated quotation information data stream. The NYSE Trades and NYSE Arca Trades data feeds distribute on a real-time basis the same last sale information that NYSE and NYSE Arca, respectively, report under the Consolidated Tape Association (“CTA”) Plan for inclusion in the CTA Plan's consolidated data streams. See Securities Exchange Act Release No. 99591 (February 23, 2024), 89 FR 14915 (February 29, 2024) (SR-NYSE-2024-08) (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Content of the NYSE Best Quotes & Trades Data Feed). In addition to the BBO and last sale information, the Integrated Feeds provide real-time market data in a unified view of events, in sequence, as they appear on the NYSE and NYSE Arca matching engine, respectively. They include depth of book order data, and opening and closing imbalance data, as well as security status updates ( e.g., trade corrections and trading halts) and stock summary messages. See Securities Exchange Act Release Nos. 99689 (March 7, 2024), 89 FR 18466 (March 13, 2024) (SR-NYSE-2024-12, at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Aggregated Lite Market Data Feed), and 19381 (March 12, 2024), 89 FR 19381 (March 18, 2024) (SR-NYSEArca-2024-22), at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Arca Aggregated Lite Market Data Feed).
The charges for the services would not change. As is true now, the proposal would waive the first month's MRC, to allow customers to test a new Proposed Market Data Connection for a month before incurring any MRC. ^6 Also as currently true, the fees for a Proposed Market Data Connection would not include the cost of the Integrated Feeds themselves, just the connection.
^6 Customers that have a Current Market Data Connection would not receive a second waiver.
In order to implement the proposed change, the Exchange proposes to make the following changes to the Connectivity Fee Schedule under “C. Wireless Connectivity to Market Data” (proposed additions italicized and proposed deletions in brackets):
Type of service | Amount of charge
NYSE [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
NYSE Arca [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
As now, the Proposed Market Data Connections would not utilize the pole on the grounds of the MDC.

The Proposed Market Data
Like the NYSE BBO and Trades and NYSE Arca BBO and Trades, the Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. In each case, the NYSE or NYSE Arca, as applicable, files with the Commission for the Integrated Feed it generates, and the related fees. ^7 The filed market data fees apply to all customers of the Integrated Feeds, no matter what form of connectivity or connectivity provider they use.
^7 See Securities Exchange Act Release Nos. 74128 (January 23, 2015), 80 FR 4951 (January 29, 2015) (SR-NYSE-2015-03) (notice of filing and immediate effectiveness of proposed rule change establishing the NYSE Integrated Feed data feed); 76485 (November 20, 2015), 80 FR 74158 (November 27, 2015) (SR-NYSE-2015-57) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for the NYSE Integrated Feed); 65669 (November 2, 2011), 76 FR 69311 (November 8, 2011) (SR-NYSEArca-2011-78) (notice of filing and immediate effectiveness of proposed rule change offering the NYSE Arca Integrated Feed); and 66128 (January 10, 2012), 77 FR 2331 (January 17, 2012) (SR-NYSEArca-2011-96) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for NYSE Arca Integrated Feed).
When a market participant wants to connect to an Integrated Feed, it requests a connection from the provider of its choice. All providers, including FIDS, may only provide the market participant with connectivity once the provider has received confirmation from the NYSE or NYSE Arca, as applicable, that the market participant is authorized to receive the requested data feed.

Application and Impact of the Proposed Change
The proposed change would apply to all customers equally. The proposed change would not apply differently to distinct types or sizes of market participants. As is currently the case, the purchase of any connectivity service is completely voluntary and the Connectivity Fee Schedule is applied uniformly to all customers.
The Exchange is proposing the change at the request of FIDS customers. The customers in Markham that would be affected by the proposed change have stated to FIDS that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. It is the Exchange's understanding that they connect to the Integrated Feeds in Markham over a fiber connection. Given that, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
FIDS does not expect that the proposed change will result in new customers in Markham.
The proposed change is not intended to address any other issues relating to connectivity or related fees, and the Exchange is not aware of any problems that customers would have in complying with the proposed change.

2. Statutory Basis
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act, ^8 in general, and furthers the objectives of Section 6(b)(5) of the Act, ^9 in particular, because it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to, and perfect the mechanisms of, a free and open market and a national market system and, in general, to protect investors and the public interest and does not unfairly discriminate between customers, issuers, brokers, or dealers. The Exchange further believes that the proposed rule change is consistent with Section 6(b)(4) of the Act, ^{10} because it provides for the equitable allocation of reasonable dues, fees, and other charges among its members and issuers and other persons using its facilities and does not unfairly discriminate between customers, issuers, brokers, or dealers.
^8 15 U.S.C. 78f(b).
^9 15 U.S.C. 78f(b)(5).
^{10} 15 U.S.C. 78f(b)(4).

The Proposed Change Is Reasonable
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would remove impediments to, and perfect the mechanisms of, a free and open market and a national market system, and, in general, protect investors and the public interest, as the change would respond to customer requests while keeping the cost the same.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is reasonable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange is not aware of any other public, commercially available wireless connections between the MDC and Markham that connect to the Proposed Market Data. However, the third party McKay Brothers LLC (“McKay”) offers wireless connectivity between the MDC and Markham. Such wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data.
In addition, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or more of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection. The Exchange does not know how many firms distribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Wireless connections and fiber connections to the Proposed Market Data in Markham would compete with each other. Given the various advantages and disadvantages of both wireless and fiber connections, a market participant interested in purchasing a connection to the Proposed Market Data in Markham is likely to consider a variety of factors in deciding whether to use a wireless versus fiber connection, including latency; the amount of network uptime; the equipment the network uses; the cost of the connection; and the applicable contractual provisions. Indeed, fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions.
The Exchange does not believe that FIDS would have any competitive advantage over any future providers of wireless connectivity to the Proposed Market Data in Markham. The Proposed Market Data Connection does not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
The Exchange believes that the proposed rule change is reasonable because a market participant in Markham that opted for a Proposed Market Data Connection would be able to select the specific Proposed Market Data that it wanted to receive in accordance with its needs, thereby helping it tailor its operations to the requirements of its business operations.

The Proposed Change Is an Equitable Allocation of Fees and Credits
The Exchange believes that its proposal equitably allocates its fees among market participants.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would be equitable as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data as well as the data in the NYSE and NYSE Arca BBO and Trades Feeds. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is equitable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Proposed Market Data Connection, as customers could use the McKay wireless connection to transport Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham. Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
The Exchange believes that the proposed change is equitable because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are equitably allocated because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.

The Proposed Change Is Not Unfairly Discriminatory
The Exchange believes that the proposed rule change is not unfairly discriminatory, for the following reasons.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham is not unfairly discriminatory, as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the cost for the Current Market Data Connection. The Exchange believes that it is not unfairly discriminatory that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange believes that the proposed change is not unfairly discriminatory because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are not unfairly discriminatory because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.
For these reasons, the Exchange believes that the proposal is consistent with the Act.

B. Self-Regulatory Organization's Statement on Burden on Competition
The proposed rule changes will not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of Section 6(b)(8) of the Act. ^{11}
^{11} 15 U.S.C. 78f(b)(8).
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. As noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham.
Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or both of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions. Market participants' considerations in determining what connectivity to purchase may include latency; the amount of network uptime; the equipment that the network uses; the cost of the connection; and the applicable contractual provisions.
In addition, due to bandwidth considerations, not all of the symbols included in the NYSE IF and NYSE Arca IF would be transported to Markham, Canada. Accordingly, market participants in Markham that wish to obtain information for all of the symbols in the NYSE IF or NYSE Arca IF may prefer to use a fiber connection offered by a FIDS or one of its competitors.
The Proposed Market Data in Markham would not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
Because the Exchange does not control Markham and could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange, the Exchange believes that the proposed change would not impose a burden on competition that is not necessary or appropriate.
For the reasons described above, the Exchange believes that the proposed rule changes reflect this competitive environment.

C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others
No written comments were solicited or received with respect to the proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act ^{12} and Rule 19b-4(f)(6) thereunder. ^{13} Because the proposed rule change does not: (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative prior to 30 days from the date on which it was filed, or such shorter time as the Commission may designate, if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6)(iii) thereunder. ^{14}
^{12} 15 U.S.C. 78s(b)(3)(A)(iii).
^{13} 17 CFR 240.19b-4(f)(6).
^{14} 17 CFR 240.19b-4(f)(6). In addition, Rule 19b-4(f)(6) requires the Exchange to give the Commission written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B) ^{15} of the Act to determine whether the proposed rule change should be approved or disapproved.
^{15} 15 U.S.C. 78s(b)(2)(B).

IV. Solicitation of Comments
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:

Electronic Comments
• Use the Commission's internet comment form ( https://www.sec.gov/rules/sro.shtml ); or
• Send an email to rule-comments@sec.gov. Please include file number SR-NYSEAMER-2024-25 on the subject line.

Paper Comments
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.
All submissions should refer to file number SR-NYSEAMER-2024-25. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website ( https://www.sec.gov/rules/sro.shtml ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-NYSEAMER-2024-25 and should be submitted on or before May 13, 2024.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^{16}
^{16} 17 CFR 200.30-3(a)(12).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99971; File No. SR-NYSECHX-2024-15]
Self-Regulatory Organizations; NYSE Chicago, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Connectivity Fee Schedule
April 16, 2024.
Pursuant to Section 19(b)(1) ^1 of the Securities Exchange Act of 1934 (“Act”) ^2 and Rule 19b-4 thereunder, ^3 notice is hereby given that, on April 2, 2024, the NYSE Chicago, Inc. (“NYSE Chicago” or the “Exchange”) filed with the Securities and Exchange Commission (the “Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been prepared by the self-regulatory organization. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.
^1 15 U.S.C. 78s(b)(1).
^2 15 U.S.C. 78a.
^3 17 CFR 240.19b-4.

I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada. The proposed rule change is available on the Exchange's website at www.nyse.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and the Statutory Basis for, the Proposed Rule Change

1. Purpose
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada.
The Exchange expects that the proposed rule change would become operative no later than June 30, 2024. It will announce the proposed change to all Fixed Income and Data Services (“FIDS”) customers in the Markham, Canada third party access center (“Markham”).

Current Markham Services
Currently, a market participant in Markham may purchase a wireless connection to connect to a selection of symbols from the NYSE BBO and Trades data feeds or the NYSE Arca BBO and Trades data feeds (the “Current Market Data Connection”) distributed from the Mahwah, New Jersey data center (“MDC”). ^4 Customers that purchase a Current Market Data Connection are charged a non-recurring initial charge of $5,000 and a $6,500 monthly fee (“MRC”).
^4 See Securities Exchange Act Release No. 90209 (October 15. 2020), 85 FR 67044 (October 21, 2020). Through its FIDS business, Intercontinental Exchange, Inc. (“ICE”) operates the MDC. The New York Stock Exchange LLC (“NYSE”), NYSE American LLC, NYSE Arca, Inc. (“NYSE Arca”), and NYSE National, Inc. are national securities exchanges that are affiliates of the Exchange (collectively, the “Affiliate SROs”). The Exchange and the Affiliate SROs are indirect subsidiaries of ICE.
There is limited bandwidth available on the wireless network to Markham. Accordingly, the Current Market Data Connection does not transport information for all the symbols included in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds. Rather, FIDS provides connectivity to a selection of such symbols, including the data for which there is demand (the “Current Market Data”). When a market participant requests a Current Market Data Connection, it receives connectivity to the portions of the NYSE BBO and Trades and NYSE Arca BBO and Trades data that FIDS transmits wirelessly. The customer then determines the symbols in the Current Market Data for which it will receive data.

Proposed Changes to Markham Services
The Exchange proposes to replace (a) the source of the selection of symbols from the NYSE BBO and Trades to the NYSE Integrated Feed (“NYSE IF”), and (b) the source of the selection of symbols from the NYSE Arca BBO and Trades to the NYSE Arca Integrated Feed (“NYSE Arca IF” and together with the NYSE IF, the “Integrated Feeds”).
As there is limited bandwidth available on the wireless network to Markham, the Exchange proposes that, similar to the Current Market Data Connection, the proposed market data connection (“Proposed Market Data Connection”) would not transport information for all the symbols included in the NYSE IF and NYSE Arca IF. Rather, FIDS would provide connectivity to a selection of such symbols, including the symbols in the Integrated Feeds for which there is demand (the “Proposed Market Data”). When a market participant requested a Proposed Market Data Connection, it would receive connectivity to the portions of the NYSE IF and NYSE Arca IF that FIDS transmits wirelessly. The customer would then determine the symbols in the Proposed Market Data for which it would receive data. As now, the Exchange would not have visibility into which portions of the data feed a given customer chooses to receive.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, ^5 FIDS anticipates that customers will continue to connect to the same selection of symbols, and information and so there will be no impact on the customers due to the change. It does not currently plan to do so, but if in the future FIDS changes the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data.
^5 Although their list of symbols is the same, the Integrated Feeds provide the information in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds, and more. The NYSE BBO and NYSE Arca BBO data feeds distribute on a real-time basis the same best bid and offer (“BBO”) information that NYSE and NYSE Arca, respectively, report under the Consolidated Quotation (“CQ”) Plan for inclusion in the CQ Plan's consolidated quotation information data stream. The NYSE Trades and NYSE Arca Trades data feeds distribute on a real-time basis the same last sale information that NYSE and NYSE Arca, respectively, report under the Consolidated Tape Association (“CTA”) Plan for inclusion in the CTA Plan's consolidated data streams. See Securities Exchange Act Release No. 99591 (February 23, 2024), 89 FR 14915 (February 29, 2024) (SR-NYSE-2024-08) (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Content of the NYSE Best Quotes & Trades Data Feed). In addition to the BBO and last sale information, the Integrated Feeds provide real-time market data in a unified view of events, in sequence, as they appear on the NYSE and NYSE Arca matching engine, respectively. They include depth of book order data, and opening and closing imbalance data, as well as security status updates ( e.g., trade corrections and trading halts) and stock summary messages. See Securities Exchange Act Release Nos. 99689 (March 7, 2024), 89 FR 18466 (March 13, 2024) (SR-NYSE-2024-12, at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Aggregated Lite Market Data Feed), and 19381 (March 12, 2024), 89 FR 19381 (March 18, 2024) (SR-NYSEArca-2024-22), at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Arca Aggregated Lite Market Data Feed).
The charges for the services would not change. As is true now, the proposal would waive the first month's MRC, to allow customers to test a new Proposed Market Data Connection for a month before incurring any MRC. ^6 Also as currently true, the fees for a Proposed Market Data Connection would not include the cost of the Integrated Feeds themselves, just the connection.
^6 Customers that have a Current Market Data Connection would not receive a second waiver.
In order to implement the proposed change, the Exchange proposes to make the following changes to the Connectivity Fee Schedule under “C. Wireless Connectivity to Market Data” (proposed additions italicized and proposed deletions in brackets):
Type of service | Amount of charge
NYSE [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
NYSE Arca [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
As now, the Proposed Market Data Connections would not utilize the pole on the grounds of the MDC.

The Proposed Market Data
Like the NYSE BBO and Trades and NYSE Arca BBO and Trades, the Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. In each case, the NYSE or NYSE Arca, as applicable, files with the Commission for the Integrated Feed it generates, and the related fees. ^7 The filed market data fees apply to all customers of the Integrated Feeds, no matter what form of connectivity or connectivity provider they use.
^7 See Securities Exchange Act Release Nos. 74128 (January 23, 2015), 80 FR 4951 (January 29, 2015) (SR-NYSE-2015-03) (notice of filing and immediate effectiveness of proposed rule change establishing the NYSE Integrated Feed data feed); 76485 (November 20, 2015), 80 FR 74158 (November 27, 2015) (SR-NYSE-2015-57) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for the NYSE Integrated Feed); 65669 (November 2, 2011), 76 FR 69311 (November 8, 2011) (SR-NYSEArca-2011-78) (notice of filing and immediate effectiveness of proposed rule change offering the NYSE Arca Integrated Feed); and 66128 (January 10, 2012), 77 FR 2331 (January 17, 2012) (SR-NYSEArca-2011-96) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for NYSE Arca Integrated Feed).
When a market participant wants to connect to an Integrated Feed, it requests a connection from the provider of its choice. All providers, including FIDS, may only provide the market participant with connectivity once the provider has received confirmation from the NYSE or NYSE Arca, as applicable, that the market participant is authorized to receive the requested data feed.

Application and Impact of the Proposed Change
The proposed change would apply to all customers equally. The proposed change would not apply differently to distinct types or sizes of market participants. As is currently the case, the purchase of any connectivity service is completely voluntary and the Connectivity Fee Schedule is applied uniformly to all customers.
The Exchange is proposing the change at the request of FIDS customers. The customers in Markham that would be affected by the proposed change have stated to FIDS that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. It is the Exchange's understanding that they connect to the Integrated Feeds in Markham over a fiber connection. Given that, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
FIDS does not expect that the proposed change will result in new customers in Markham.
The proposed change is not intended to address any other issues relating to connectivity or related fees, and the Exchange is not aware of any problems that customers would have in complying with the proposed change.

2. Statutory Basis
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act, ^8 in general, and furthers the objectives of Section 6(b)(5) of the Act, ^9 in particular, because it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to, and perfect the mechanisms of, a free and open market and a national market system and, in general, to protect investors and the public interest and does not unfairly discriminate between customers, issuers, brokers, or dealers. The Exchange further believes that the proposed rule change is consistent with Section 6(b)(4) of the Act, ^{10} because it provides for the equitable allocation of reasonable dues, fees, and other charges among its members and issuers and other persons using its facilities and does not unfairly discriminate between customers, issuers, brokers, or dealers.
^8 15 U.S.C. 78f(b).
^9 15 U.S.C. 78f(b)(5).
^{10} 15 U.S.C. 78f(b)(4).

The Proposed Change Is Reasonable
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would remove impediments to, and perfect the mechanisms of, a free and open market and a national market system, and, in general, protect investors and the public interest, as the change would respond to customer requests while keeping the cost the same.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is reasonable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange is not aware of any other public, commercially available wireless connections between the MDC and Markham that connect to the Proposed Market Data. However, the third party McKay Brothers LLC (“McKay”) offers wireless connectivity between the MDC and Markham. Such wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data.
In addition, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or more of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection. The Exchange does not know how many firms distribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Wireless connections and fiber connections to the Proposed Market Data in Markham would compete with each other. Given the various advantages and disadvantages of both wireless and fiber connections, a market participant interested in purchasing a connection to the Proposed Market Data in Markham is likely to consider a variety of factors in deciding whether to use a wireless versus fiber connection, including latency; the amount of network uptime; the equipment the network uses; the cost of the connection; and the applicable contractual provisions. Indeed, fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions.
The Exchange does not believe that FIDS would have any competitive advantage over any future providers of wireless connectivity to the Proposed Market Data in Markham. The Proposed Market Data Connection does not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
The Exchange believes that the proposed rule change is reasonable because a market participant in Markham that opted for a Proposed Market Data Connection would be able to select the specific Proposed Market Data that it wanted to receive in accordance with its needs, thereby helping it tailor its operations to the requirements of its business operations.

The Proposed Change Is an Equitable Allocation of Fees and Credits
The Exchange believes that its proposal equitably allocates its fees among market participants.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would be equitable as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data as well as the data in the NYSE and NYSE Arca BBO and Trades Feeds. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is equitable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Proposed Market Data Connection, as customers could use the McKay wireless connection to transport Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham. Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
The Exchange believes that the proposed change is equitable because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are equitably allocated because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.

The Proposed Change Is Not Unfairly Discriminatory
The Exchange believes that the proposed rule change is not unfairly discriminatory, for the following reasons.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham is not unfairly discriminatory, as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the cost for the Current Market Data Connection. The Exchange believes that it is not unfairly discriminatory that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange believes that the proposed change is not unfairly discriminatory because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are not unfairly discriminatory because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.
For these reasons, the Exchange believes that the proposal is consistent with the Act.

B. Self-Regulatory Organization's Statement on Burden on Competition
The proposed rule changes will not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of Section 6(b)(8) of the Act. ^{11}
^{11} 15 U.S.C. 78f(b)(8).
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. As noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham.
Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or both of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions. Market participants' considerations in determining what connectivity to purchase may include latency; the amount of network uptime; the equipment that the network uses; the cost of the connection; and the applicable contractual provisions.
In addition, due to bandwidth considerations, not all of the symbols included in the NYSE IF and NYSE Arca IF would be transported to Markham, Canada. Accordingly, market participants in Markham that wish to obtain information for all of the symbols in the NYSE IF or NYSE Arca IF may prefer to use a fiber connection offered by a FIDS or one of its competitors.
The Proposed Market Data in Markham would not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
Because the Exchange does not control Markham and could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange., the Exchange believes that the proposed change would not impose a burden on competition that is not necessary or appropriate.
For the reasons described above, the Exchange believes that the proposed rule changes reflect this competitive environment.

C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others
No written comments were solicited or received with respect to the proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act ^{12} and Rule 19b-4(f)(6) thereunder. ^{13} Because the proposed rule change does not: (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative prior to 30 days from the date on which it was filed, or such shorter time as the Commission may designate, if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6)(iii) thereunder. ^{14}
^{12} 15 U.S.C. 78s(b)(3)(A)(iii).
^{13} 17 CFR 240.19b-4(f)(6).
^{14} 17 CFR 240.19b-4(f)(6). Rule 19b-4(f)(6) requires the Exchange to give the Commission written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B) ^{15} of the Act to determine whether the proposed rule change should be approved or disapproved.
^{15} 15 U.S.C. 78s(b)(2)(B).

IV. Solicitation of Comments
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:

Electronic Comments
• Use the Commission's internet comment form ( https://www.sec.gov/rules/sro.shtml ); or
• Send an email to rule-comments@sec.gov . Please include file number SR-NYSECHX-2024-15 on the subject line.

Paper Comments
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.
All submissions should refer to file number SR-NYSECHX-2024-15. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website ( https://www.sec.gov/rules/sro.shtml ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-NYSECHX-2024-15 and should be submitted on or before May 13, 2024.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^{16}
^{16} 17 CFR 200.30-3(a)(12).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99963; File No. SR-CBOE-2024-008]
Self-Regulatory Organizations; Cboe Exchange, Inc.; Notice of Designation of a Longer Period for Commission Action on a Proposed Rule Change To Adopt a New Rule Regarding Order and Execution Management Systems
April 16, 2024.
On February 13, 2024, Cboe Exchange, Inc. filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”) ^1 and Rule 19b-4 thereunder, ^2 a proposal to adopt a new rule regarding order and execution management systems. The proposed rule change was published for comment in the Federal Register on March 5, 2024. ^3 The Commission has received three comment letters regarding the proposed rule change. ^4
^1 15 U.S.C. 78s(b)(1).
^2 17 CFR 240.19b-4.
^3 See Securities Exchange Act Release No. 99620 (February 28, 2024), 89 FR 15907 (“Notice”).
^4 The public comment file for SR-CBOE-2024-008 is available on the Commission's website at https://www.sec.gov/comments/sr-cboe-2024-008/srcboe2024008.htm.
Section 19(b)(2) of the Act ^5 provides that within 45 days of the publication of notice of the filing of a proposed rule change, or within such longer period up to 90 days as the Commission may designate if it finds such longer period to be appropriate and publishes its reasons for so finding, or as to which the self-regulatory organization consents, the Commission will either approve the proposed rule change, disapprove the proposed rule change, or institute proceedings to determine whether the proposed rule change should be disapproved. The 45th day after publication of the notice for this proposed rule change is April 19, 2024. The Commission is extending this 45-day time period.
^5 15 U.S.C. 78s(b)(2).
The Commission finds it appropriate to designate a longer period within which to issue an order approving or disapproving the proposed rule change, so that it has sufficient time to consider the proposed rule change. Accordingly, the Commission, pursuant to Section 19(b)(2) of the Act, ^6 designates June 3, 2024, as the date by which the Commission shall either approve or disapprove the proposed rule change (File No. SR-CBOE-2024-008).
^6 15 U.S.C. 78s(b)(2).
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^7
^7 17 CFR 200.30-3(a)(31).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99965; File No. SR-CboeBYX-2023-020]D
Self-Regulatory Organizations; Cboe BYX Exchange, Inc.; Notice of Filing of Amendment No. 1 and Order Instituting Proceedings To Determine Whether To Approve or Disapprove a Proposed Rule Change, as Modified by Amendment No. 1, To Introduce an Enhanced RPI Order and Expand Its Retail Price Improvement Program To Include Securities Priced Below $1.00
April 16, 2024.
On December 27, 2023, Cboe BYX Exchange, Inc. (“BYX” or the “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”), ^1 and Rule 19b-4 thereunder, ^2 a proposed rule change to modify Rule 11.24 to introduce an Enhanced RPI Order and expand its Retail Price Improvement program to include securities priced below $1.00. The proposed rule change was published for comment in the Federal Register on January 17, 2024. ^3 On February 27, 2024, pursuant to Section 19(b)(2) of the Act, ^4 the Commission designated a longer period within which to approve the proposed rule change, disapprove the proposed rule change, or institute proceedings to determine whether to disapprove the proposed rule change. ^5 On March 6, 2024, the Exchange submitted Amendment No. 1 to the proposed rule change as described in Items I and II below, which Items have been prepared by the Exchange. ^6 To date, the Commission has received no comments on the proposed rule change. ^7 The Commission is publishing this notice and order to solicit comment on the proposed rule change, as modified by Amendment No. 1, from interested persons and to institute proceedings under Section 19(b)(2)(B) of the Act ^8 to determine whether to approve or disapprove the proposed rule change, as modified by Amendment No. 1.
^1 15 U.S.C. 78s(b)(1).
^2 17 CFR 240.19b-4.
^3 See Securities Exchange Act Release No. 99311 (Jan. 10, 2024), 89 FR 2993.
^4 15 U.S.C. 78s(b)(2).
^5 See Securities Exchange Act Release No. 99610, 89 FR 15621 (Mar. 4, 2024). The Commission designated April 16, 2024 as the date by which the Commission shall approve or disapprove, or institute proceedings to determine whether to disapprove, the proposed rule change.
^6 In Amendment No. 1, the Exchange amended the proposed rule change to provide additional examples, justification and support for its proposal and made certain changes to the proposed rule text. The full text of Amendment No. 1 is available on the Commission's website at: https://www.sec.gov/comments/sr-cboebyx-2023-020/srcboebyx2023020-442119-1127142.pdf.
^7 Comments received on the proposed rule change are available at: https://www.sec.gov/comments/sr-cboebyx-2023-020/srcboebyx2023020.htm.
^8 15 U.S.C. 78s(b)(2)(B).

I. The Exchange's Description of the Terms of Proposed Rule Change, as Modified by Amendment No. 1
The Exchange filed with the Commission a proposal to modify Rule 11.24 to introduce an Enhanced RPI Order and expand its Retail Price Improvement program to include securities priced below $1.00. The text of the proposed rule change is provided in Exhibit 5.
The text of the proposed rule change is also available on the Exchange's website ( http://markets.cboe.com/us/equities/regulation/rule_filings/bzx/ ), at the Exchange's Office of the Secretary, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change

1. Purpose
The Exchange proposes to amend Rule 11.24 to enhance the Exchange's Retail Price Improvement Program (the “Program”) for the benefit of retail investors. Specifically, the Exchange proposes to introduce a new type of RPI Interest ^9 to be known as an “Enhanced RPI Order.” The proposed Enhanced RPI Order will allow retail liquidity providers to post orders at their limit price but have the opportunity to provide a greater amount of price improvement as compared to other resting orders on the same side of the BYX Book with higher price-time priority in order to execute with an incoming Retail Order ^{10} by exercising at a price within their established step-up range. The proposed change is designed to provide retail investors with additional opportunities for meaningful price improvement by introducing a new order type that will “step-up” its price against orders with a higher priority resting on the BYX Book. ^{11} Additionally, the Exchange proposes to expand the Program to securities priced below $1.00. ^{12}
^9 See proposed Rule 11.24(e). RPI Interest means an order submitted to the Exchange that is designated as either an RPI Order or an Enhanced RPI Order. See also Rule 11.24(a)(3) (“Retail Price Improvement Order”).
^{10} See Rule 11.24(a)(2) (“Retail Order”).
^{11} See Rule 1.5(e) (“BYX Book”). The “BYX Book” is the System's electronic file of orders. The “System” shall mean the electronic communications and trading facility designated by the Board through which securities orders of Users are consolidated for ranking, execution, and when applicable, routing away. See Rule 1.5(aa) (“System”).
^{12} See Rule 11.24(h). The Program is currently limited to trades occurring at prices equal to or greater than $1.00 per share.

Background
In November 2012, the Exchange received approval to operate its Program on a pilot basis. ^{13} The Program operated under a pilot basis until September 30, 2019, when the Program was approved on a permanent basis. ^{14} In addition, the Exchange was granted a limited exemption from the Sub-Penny Rule, as well as Regulation NMS Rule 602 (Quote Rule) No Action relief ^{15} to operate the Program. ^{16} The Program is currently designed to attract Retail Orders to the Exchange and allow such order flow to receive potential price improvement. The Program is currently limited to trades occurring at prices equal to or greater than $1.00 per share. ^{17} Under the Program, a class of market participant called a Retail Member Organization (“RMO”) ^{18} is eligible to submit certain retail order flow (“Retail Orders”) to the Exchange. Users ^{19} are permitted to provide potential price improvement for Retail Orders ^{20} in the form of non-displayed interest that is better than the national best bid that is a Protected Quotation (“Protected NBB”) or the national best offer that is a Protected Quotation (“Protected NBO”, and together with the Protected NBB, the “Protected NBBO”). ^{21}
^{13} See Securities Exchange Act Release No. 68303 (November 27, 2012), 77 FR 71652 (December 3, 2012), SR-BYX-2012-019 (“Pilot Approval Order”).
^{14} See Securities Exchange Act Release No. 87154 (September 30, 2019), 84 FR 53183 (October 4, 2019), SR-CboeBYX-2019-014 (“RPI Approval Order”).
^{15} See Letter from David Shillman to Eric Swanson (November 27, 2012) (“No Action Letter”), available at https://www.sec.gov/divisions/marketreg/mr-noaction/byx-112712-602.pdf.
^{16} Supra note 14 at 53185.
^{17} Supra note 12. The Exchange will periodically notify the membership regarding the securities included in the Program through an information circular. The Exchange is proposing to make the Program available to all securities (discussed infra ).
^{18} See Rule 11.24(a)(1). A “Retail Member Organization” or “RMO” is a Member (or a division thereof) that has been approved by the Exchange under Rule 11.24 to submit Retail Orders.
^{19} See Rule 1.5(cc). A “User” is defined as any member or sponsored participant of the Exchange who is authorized to obtain access to the System.
^{20} Supra note 10. A “Retail Order” is defined as an agency or riskless principal order that originates from a natural person and is submitted to the Exchange by an RMO, provided that no change is made to the terms of the order with respect to price or side of market and the order does not originate from a trading algorithm or any computerized methodology.
^{21} See Rule 1.5(t). The term “Protected Quotation” has the same meaning as is set forth in Regulation NMS Rule 600(b)(71). The terms Protected NBB and Protected NBO are defined in BYX Rule 1.5(s). The Protected NBB is the best-priced protected bid and the Protected NBO is the best-priced protected offer. Generally, the Protected NBB and Protected NBO and the national best bid (“NBB”) and national best offer (“NBO”, together with the NBB, the “NBBO”) will be the same. However, a market center is not required to route to the NBB or NBO if that market center is subject to an exception under Regulation NMS Rule 611(b)(1) or if such NBB or NBO is otherwise not available for an automatic execution. In such case, the Protected NBB or Protected NBO would be the best-priced protected bid or offer to which a market center must route interest pursuant to Regulation NMS Rule 611.
The Exchange developed this Program with the goal of incentivizing RMOs to execute their Retail Orders on the Exchange, rather than off-exchange venues, by providing Retail Orders with greater access to potential opportunities for price improvement on the Exchange. However, as noted by the Commission, even with the presence of retail liquidity programs (“RLPs”) offered by Cboe and other national securities exchanges, ^{22} the great majority of marketable orders of retail investors continue to be sent to wholesalers. ^{23} Indeed, as noted in the Commission's recent rule proposal related to minimum pricing increments, RLPs have not yet attracted a significant volume of retail order flow. ^{24} In fact, since RLPs have been adopted, the percentage of on-exchange share volume has continued to decrease from approximately 71% to approximately 56% as of November 2023. ^{25}
^{22} See, e.g. , NYSE Retail Liquidity program, which promotes cost savings through price improvement for individual investors provided by retail liquidity providers that submit non-displayed interest priced better than the best protected best bid or protected best offer. See also NYSE National Retail Liquidity program, which seeks to attract retail order flow to the Exchange through the potential of price improvement at the midpoint or better. Available at https://www.nyse.com/markets/liquidity-programs. See also IEX Retail Program, which incentivizes midpoint liquidity for retail orders through the use of retail liquidity provider orders. Available at https://www.iexexchange.io/products/retail-program. See also Nasdaq BX Retail Price Improvement, which allows retail orders to interact with price-improving liquidity. Available at https://www.nasdaqtrader.com/content/BXRPIfs.pdf.
^{23} See Securities Exchange Act Release No. 96495 (December 14, 2022), 88 FR 128 (January 3, 2023) (“Order Competition Rule”) at 144.
^{24} See Securities Exchange Act Release No. 96494 (December 14, 2022), 87 FR 80266 (December 29, 2022) (“Tick Size Proposal”) at 80273.
^{25} Source: Cboe internal data.
Accordingly, the Exchange now seeks to enhance its current Program by offering retail liquidity providers an optional Enhanced RPI Order type. The Exchange believes the Enhanced Order type will incentivize additional retail liquidity provision by enabling RPI liquidity providers to submit an order that is ranked at a less aggressive price than the step-up range at which the provider is willing to execute, but have the opportunity to “step up” to provide a greater amount of price improvement as compared to other higher priority resting orders on the same side of the BYX Book in order to execute with an incoming contra-side Retail Order. As discussed in more detail, below, the Enhanced RPI Order type will have price priority over resting orders when its step-up range allows for additional price improvement when a contra-side Retail Order is submitted to the Exchange. With the deeper pool of retail liquidity-providing orders, the Exchange believes that RMOs will see increased opportunities for on-exchange price improvement and seek to execute more of their Retail Orders on the Exchange.

Proposal
The Exchange proposes to amend Rule 11.24(a) to include the proposed Enhanced RPI Order, which allows a retail liquidity provider to post a limit order to the Exchange, but also the opportunity to “step-up” its price within their defined step-up range by providing a greater amount of price improvement as compared to orders with higher priority that are resting on the same side of the BYX Book in order to execute against an incoming Retail Order seeking to remove liquidity. An Enhanced RPI Order is designed to be entered with a limit price, but must also include a step-up range, which is the most aggressive price it is willing to execute against a contra-side Retail Order. If the Enhanced RPI Order includes a step-up range that improves against the price of the highest-ranked resting order on the same side of the BYX Book, the Enhanced RPI Order will be given price priority over the highest-ranked resting order. In order for an Enhanced RPI Order to receive price priority, the Enhanced RPI Order must be able to provide a greater amount of price improvement to an incoming contra-side Retail Order than would otherwise be available by stepping up to the next minimum price increment. ^{26}
^{26} The Exchange notes that the minimum amount of required price improvement will vary between $0.001 and $0.01, based on the order types resting on the BYX Book (discussed infra ).
The Exchange believes this proposed change would further the purpose of the Program to attract retail marketable order flow to the Exchange, while also increasing opportunities for price improvement. By offering the Enhanced RPI Order, the Exchange has created an enhancement to its current Program that offers a greater incentive for liquidity providers to provide liquidity eligible to execute against marketable retail order flow on the Exchange. The Enhanced RPI Order would allow Users to post orders at their limit price but step-up to a more aggressive price in order to execute against marketable retail order flow that is less prone to adverse selection. Marketable retail order flow, in turn, would receive price improvement greater than what is currently available under the Program. The Exchange believes that the proposed change will lead to increased participation in the Program by Users seeking to provide liquidity for marketable retail order flow, which in turn will attract additional marketable retail order flow to the Exchange in search of price improvement opportunities.
The Exchange also proposes to introduce Rule 11.24(a)(5) in order to define the term RPI Interest as either RPI Orders or Enhanced RPI Orders. Additionally, the Exchange proposes to amend Rule 11.24(g) in order to describe order priority for Enhanced RPI Orders. The Exchange also proposes to make corresponding changes within Rule 11.24 to replace certain references to RPI Order with the term RPI Interest in order to have language inclusive of both RPI Orders and Enhanced RPI Orders. Further, the Exchange proposes to delete Rule 11.24(h), as the Exchange proposes to expand the Program to sub-dollar securities. The Exchange will announce that the RPI Program has expanded to all securities in a Trade Desk notice, and periodic updates will no longer be required. The Exchange also proposes to renumber Rule 11.24(i) in conjunction with the deletion of Rule 11.24(h).
Additionally, with the introduction of the Enhanced RPI Order, the Exchange proposes to amend Rule 11.24(a)(2) to permit a Retail Order to be entered as a Mid-Point Peg Order. ^{27} The Exchange also proposes to amend Rule 11.24(a)(2) to better describe that the time-in-force requirement for all Retail Orders, including those entered as a Mid-Point Peg Order, is required to be Immediate or Cancel (“IOC”). The Exchange believes that allowing the Mid-Point Peg Order instruction on a Retail Order will benefit Users who choose to submit Retail Orders because it will permit a Retail Order to guarantee price improvement at the midpoint or better. The Mid-Point Peg Order instruction will be optional, and not required for Users of Retail Orders.
^{27} See Rule 11.9(c)(9). A Mid-Point Peg Order is a limit order that, after entry into the System, the price of the order is automatically adjusted by the System in response to changes in the NBBO to be pegged to the mid-point of the NBBO, or, alternatively, pegged to the less aggressive of the midpoint of the NBBO or one minimum price variation inside the same side of the NBBO as the order.

Current RPI Orders
Rule 11.24(a)(3) currently defines an RPI Order as “non-displayed interest on the Exchange that is priced better than the Protected NBB or Protected NBO by at least $0.001 and that is identified as such.” ^{28} The Exchange now proposes to amend the definition of RPI Order to more accurately reflect how an RPI Order may be entered by defining an RPI Order as “non-displayed interest on the Exchange that is eligible to execute at prices better than the Protected NBB or Protected NBO by at least $0.001 in securities priced at or above $1.00 and by at least $0.0001 in securities priced below $1.00 and that is identified as such.” As the Exchange is also proposing to expand the Program to prices below $1.00, more specificity is required regarding the minimum pricing increment. Further, the Exchange is clarifying that an RPI Order may be entered at any price but may execute only at prices better than the Protected NBB or Protected NBO.
^{28} Supra note 9.
As stated in Rule 11.24(a)(3), RPI Orders are non-displayed and are ranked in accordance with Rule 11.12(a). Furthermore, under Rule 11.24(g), competing RPI Orders in the same security are ranked and allocated according to price then time of entry into the System. Executions occur in price/time priority in accordance with Rule 11.12. Any remaining unexecuted RPI interest remains available to interact with other incoming Retail Orders if such interest is at an eligible price. Any remaining unexecuted portion of the Retail Order will cancel or execute in accordance with Rule 11.24(f). The following example illustrates this method:
• Protected NBBO for security ABC is $10.00-$10.05
• User 1 enters an RPI Order to buy ABC at $10.015 for 500 shares
• User 2 then enters an RPI Order to buy ABC at $10.02 for 500 shares
• User 3 then enters an RPI Order to buy ABC at $10.035 for 500 shares
An incoming Retail Order to sell ABC for 1,000 shares executes first against User 3's bid for 500 shares at $10.035, because it is the best priced bid, then against User 2's bid for 500 shares at $10.02, because it is the next best priced bid. User 1 is not filled because the entire size of the Retail Order to sell 1,000 shares is depleted. The Retail Order executes against RPI Orders in price/time priority. ^{29}
^{29} See Rule 11.24(f) for additional examples of priority and order allocation in the current Program.

Enhanced RPI Order
The Exchange now proposes to introduce a new type of RPI Order that Users seeking to provide RPI liquidity may utilize on an optional basis. The proposed Enhanced RPI Order will be eligible to obtain price priority over resting orders in the same security on the same side of the BYX Book in order to execute against a Retail Order by including a step-up range when entered. Enhanced RPI Orders will be ranked in accordance with proposed Rule 11.24(g)(2) (discussed infra ). In order to effect the proposed change, the Exchange proposes to introduce Rule 11.24(a)(4), which would define an Enhanced RPI Order as:
• An “Enhanced Retail Price Improvement Order” or “Enhanced RPI Order” consists of non-displayed interest on the Exchange that is eligible to execute against contra-side Retail Orders. An Enhanced RPI Order will be ranked at its limit price and must also include a step-up range, which is the maximum price (for buy orders) or minimum price (for sell orders) at which the Enhanced RPI Order is willing to execute. An Enhanced RPI Order may execute at: (i) its limit price; (ii) for securities priced at or above $1.00, at a price within the step-up range that is able to improve upon the price of a same-side resting order on the BYX Book by stepping up to the next half cent or full cent, and for securities priced below $1.00 by stepping up to the next minimum price increment; or (iii) at a price within the step-up range when the limit price of a contra-side Retail Order is within the step-up range. An Enhanced RPI Order may be a Primary Pegged order or a limit order. The System will monitor whether Enhanced RPI interest, including the step-up range, and adjusted by any offset and subject to the ceiling or floor price, is eligible to interact with incoming Retail Orders. An Enhanced RPI Order (the buy or sell interest, the step-up range, the offset, and the ceiling or floor) remains non-displayed in its entirety. Any User is permitted, but not required, to submit Enhanced RPI Orders. An Enhanced RPI Order may be an odd lot, round lot or mixed lot. An Enhanced RPI Order shall have priority as described in Rule 11.24(g)(2).
The price of an Enhanced RPI Order will be determined by a User's entry of the following into the Exchange: (1) Enhanced RPI buy or sell interest; (2) the step-up range; (3) an offset, if any; and (4) a ceiling or floor price, if any. The step-up range of an Enhanced RPI Order is the maximum amount above the order's limit price at which a User is willing to execute. If the Enhanced RPI Order can improve upon resting liquidity on the same side of the BYX Book by stepping up to the nearest whole cent tick or half cent midpoint tick, it will receive price priority over the resting liquidity on the BYX Book. An Enhanced RPI Order, however, will not improve upon the price of another resting Enhanced RPI Order to receive price priority. ^{30}
^{30} The Exchange plans to submit a request for an exemption under Regulation NMS Rule 612 that would permit it to accept and rank non-displayed RPI Interest. As outlined in the request, the Exchange has received an exemption from Rule 612 for the current Program, but believes it is appropriate to renew its request as the Program seeks to introduce Enhanced RPI Orders even as the fundamental nature of the Program is not changing.

Enhanced RPI Order Priority
As discussed above, the proposed Enhanced RPI Order will be ranked at its limit price, which is less aggressive than its step-up range. With the introduction of the proposed Enhanced RPI Order, the Exchange proposes to reorganize Rule 11.24(g) into Rule 11.24(g)(1) and (2). Proposed Rule 11.24(g)(1) would contain the existing rule text that describes order priority with respect to RPI Orders, which the Exchange does not propose to amend. Proposed Rule 11.24(g)(2) would describe order priority with respect to Enhanced RPI Orders.
An Enhanced RPI Order will be ranked and allocated according to its limit price then time of entry into the System. The Exchange proposes, however, that an Enhanced RPI Order will be granted price priority over orders resting on the BYX Book in the event that the Enhanced RPI Order is able to provide a greater amount of price improvement to an incoming contra-side Retail Order by stepping up to the next half cent ^{31} or full cent (for securities priced at or above $1.00) or the next minimum price increment (for securities priced below $1.00). The step-up range of an Enhanced RPI Order will be utilized to determine price priority when: (1) the range is needed to gain priority over a resting order with higher order book priority that is not an Enhanced RPI Order; (2) in situations where: (a) a contra-side Retail Order is entered at a less aggressive price than the ranked price of the Enhanced RPI Order and all other resting liquidity and (b) the Enhanced RPI Order's step-up range is equal to or more aggressively priced than the Retail Order's limit price; and (3) to determine order book priority when multiple Enhanced RPI Orders are resting on the BYX Book and are eligible to trade ahead of higher priority orders resting on the BYX Book that are not Enhanced RPI Orders. The Exchange notes when multiple Enhanced RPI Orders are resting on the BYX Book, there are no other resting orders on the same side of the BYX Book with higher priority, and a contra-side Retail Order is entered at a price equal to or more aggressive than the highest-priced Enhanced RPI Order resting on the BYX Book, the Enhanced RPI Orders will execute in standard price/time priority according to their limit price rather than utilize the step-up range to determine order book priority.
^{31} Discussed infra Examples 1 and 2. An Enhanced RPI Order may only need to step-up one half cent in order to provide meaningful price improvement in situations where: i) the NBBO midpoint is priced at a half cent and the Enhanced RPI Order is stepping up to the next full cent; or ii) the best-priced resting order is ranked at a full cent and the NBBO midpoint is priced in a half cent increment, then the Enhanced RPI Order will only need to step up to the NBBO.
The Exchange has included the examples below to show how order priority with an Enhanced RPI Order will be determined. In the examples below, the Retail Liquidity Identifier (discussed infra ) is presumed to be displayed unless stated otherwise.

Example 1 ^{32}
^{32} See proposed Rule 11.24(g)(2)(A).
In order to illustrate priority of an Enhanced RPI Order over other non-displayed orders resting on the BYX Book, consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters a Mid-Point Peg ^{33} order to buy ABC at $10.03 for 100. User 1's order is ranked at $10.025 as the User elected that the Mid-Point Peg order be pegged to the mid-point of the NBBO.
^{33} Supra note 27.
○ User 2 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 2's step-up range is $0.02. User 2's order is ranked at $10.01 and is willing to step-up to a maximum price of $10.03.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 3's Retail Order for 100 will execute against User 2's Enhanced RPI Order at $10.03. While User 1's order is ranked at a higher price ($10.025) than User 2's order ($10.01), User 2's order includes a step-up range of $0.02 and is willing to step up to a maximum price of $10.03, which provides additional price improvement to User 3's Retail Order than User 1's Mid-Point Peg Order. As User 2's order provides an additional $0.005 of price improvement over User 1's midpoint price, the Exchange gives priority to User 2's Enhanced RPI Order.

Example 2 ^{34}
^{34} See proposed Rule 11.24(g)(2)(A).
There are two situations in which an Enhanced RPI Order may only need to step-up one-half cent in order to provide meaningful price improvement. First, when the NBBO midpoint is priced in a half cent and the Enhanced RPI Order is stepping up from the half-cent midpoint to the next full cent in order to provide price improvement (see Example 1 above). The second instance occurs when the best-priced resting order on the BYX Book is ranked at a whole cent, and the NBBO midpoint is priced in a half cent increment, the Enhanced RPI Order will only need to step-up to the NBBO midpoint order to provide meaningful price improvement. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters a non-displayed order to buy ABC at $10.02 for 100.
○ User 2 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 2's step-up range is $0.02. User 2's order is ranked at $10.01 and is willing to step up to a maximum price of $10.03.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 3's Retail Order for 100 will execute against User 2's Enhanced RPI Order at $10.025. While User 1's order is ranked at a higher price ($10.02) than User 2's order ($10.01), User 2 has included a step-up range of $0.02 on its order and is willing to step up to a maximum price of $10.03 in order to provide additional price improvement as compared to other orders resting on the BYX Book. Even though User 2's order may execute up to a price of $10.03, it only needs to provide one-half cent price improvement over User 1's ranked price of $10.02 in order to provide meaningful price improvement at the midpoint.

Example 3 ^{35}
^{35} See proposed Rule 11.24(g)(2)(A).
There are instances where an Enhanced RPI Order may need to step-up a full penny in order to provide meaningful price improvement. Consider the following:
• The Protected NBBO for security ABC is $10.00 × $10.10.
○ User 1 enters a non-displayed order to buy ABC at $10.03 for 100.
○ User 2 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 2's step-up range is $0.04. User 2's order is ranked at $10.01 and is willing to step up to a maximum price of $10.05.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 3's Retail Order for 100 will execute against User 2's Enhanced RPI Order at $10.04. While User 1's order is ranked at a higher price ($10.03) than User 2's order ($10.01), User 2 has included a step-up range of $0.04 on its order and is willing to step up to a maximum price of $10.05 in order to provide additional price improvement as compared to other orders resting on the BYX Book. Even though User 2's order may execute up to a price of $10.05, it only needs to provide one penny of price improvement above User 1's ranked price of $10.03 in order to provide meaningful price improvement.

Example 4 ^{36}
^{36} See proposed Rule 11.24(a)(4).
There may be instances where there is no other liquidity resting on the BYX Book against which the Enhanced RPI Order can step up against. In these instances, the Enhanced RPI Order will trade at its ranked price. Consider the following example.
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 1's step-up range is $0.015. User 1's order is ranked at $10.01 and is willing to step up to a maximum price of $10.025.
○ User 2 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 2's Retail Order for 100 will execute against User 1's Enhanced RPI Order at $10.01 as there are no better-priced orders resting on the BYX Book against which User 1 would need to provide greater price improvement to User 2.

Example 5 ^{37}
^{37} See proposed Rule 11.24(g)(2)(A).
Enhanced RPI Orders will only have priority against other better-priced liquidity resting on the BYX Book in the event that the Enhanced RPI Order can step-up to the next half cent or full cent. In the example below, the Enhanced RPI Order is unable to step up against the best priced order on the BYX Book but is able to step up against an order ranked at the next best price level. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters a non-displayed order to buy ABC at $10.04 for 100.
○ User 2 enters a non-displayed order to buy ABC at $10.02 for 100.
○ User 3 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 3's step-up range is $0.03. User 3's order is ranked at $10.01 and is willing to step up to a maximum price of $10.04.
○ User 4 enters a Retail Order to sell ABC at $10.00 for 150.
• Result: User 4's Retail Order will execute 100 shares first with User 1's non-displayed order as User 1's non-displayed order has price priority over the orders submitted by Users 2 and 3. While User 3's Enhanced RPI Order includes a step-up range of $0.03 and is willing to execute up to a maximum price of $10.04, the step-up range does not provide greater price improvement for User 4's Retail Order as compared to User 1's non-displayed order and as such, User 3's Enhanced RPI Order does not have priority over User 1's non-displayed order. Once User 4's Retail Order executes against User 1's non-displayed order, 50 shares remain on User 4's Retail Order. User 4's Retail Order will then execute its remaining 50 shares with User 3's Enhanced RPI Order at a price of $10.025. While User 2's non-displayed order is ranked at a higher price ($10.02) than User 3's Enhanced RPI Order ($10.01), User 3's Enhanced RPI Order has a step-up range of $0.03 and is willing to execute up to a maximum price of $10.04 and User 2's non-displayed order does not contain a step-up range. As User 3's Enhanced RPI Order is willing to provide greater price improvement as compared to a better-priced order resting on the same side of the BYX Book, it is given priority over User 2's non-displayed order. User 3's Enhanced RPI Order executes 50 shares against User 4's non-displayed order at a price of $10.025 because it provides one-half cent of price improvement over User 2's ranked price of $10.02.

Example 6 ^{38}
^{38} See proposed Rule 11.24(a)(4).
Enhanced RPI Orders will execute within their step-up range when the incoming Retail Order's price is not executable at the Enhanced RPI Order's ranked price. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 1's step-up range is $0.03. User 1's order is ranked at $10.01 and is willing to step up to a maximum price of $10.04.
○ User 2 enters a Retail Order to sell ABC at $10.03 for 100.
• Result: User 2's Retail Order will execute with User 1's Enhanced RPI Order at $10.03 as the limit price of User 2's Retail Order ($10.03) is within the maximum price provided by User 1's step-up range.

Example 7 ^{39}
^{39} See proposed Rule 11.24(g)(2).
When there are multiple Enhanced RPI Orders resting on the BYX Book, no other same side liquidity with higher priority, and the contra-side Retail Order is priced more aggressively than the resting Enhanced RPI Orders, execution priority will be determined by the higher ranked price and not by the step-up ranges of the Enhanced RPI Orders. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 1's step-up range is $0.04. User 1's order is ranked at $10.01 and is willing to step up to a maximum price of $10.05.
○ User 2 enters an Enhanced RPI Order to buy ABC at $10.02 for 100. User 2's step-up range is $0.02. User 2's order is ranked at $10.02 and is willing to step up to a maximum price of $10.04.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 3's Retail Order will execute with User 2's Enhanced RPI Order at $10.02 because User 2's Enhanced RPI Order has price priority over User 1's Enhanced RPI Order due to its higher ranked price of $10.02. Given that User 3's Retail Order was priced more aggressively than the resting Enhanced RPI Orders at its time of entry, the Exchange believes that priority should be determined by using the ranked price of the Enhanced RPI Orders resting on the BYX Book at the time of User 3's Retail Order entry.

Example 8 ^{40}
^{40} See proposed Rule 11.24(g)(2)(B).
The step-up range will be used to determine order book priority in situations where: (i) a contra-side Retail Order is entered at a less aggressive price than the Enhanced RPI Order's limit price and all other resting liquidity in the same security and (ii) the Enhanced RPI Order's step-up range is equal to or more aggressively priced than the Retail Order's limit price. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 1's step-up range is $0.04. User 1's order is ranked at $10.01 and is willing to step up to a maximum price of $10.05.
○ User 2 enters a non-displayed order to buy ABC at $10.02 for 100. User 2's order is ranked at $10.02.
○ User 3 enters a Retail Order to sell ABC at $10.03 for 100.
• Result: User 3's order will execute with User 1's Enhanced RPI Order at $10.03 because (i) User 3's Retail Order was entered at a less aggressive price than the ranked price of both User 1 and User 2's orders; and (ii) the maximum price provided by the step-up range of User 1's Enhanced RPI Order is more aggressively priced ($10.05) than the limit price of User 3's Retail Order ($10.03). Even though User 2's ranked price is higher than User 1's ranked price, User 2's order is not marketable against User 3's Retail Order. User 3's Retail Order would otherwise be unable to execute if the Exchange did not look to the price improvement provided by User 1's step-up range to permit an execution between User 1 and User 3.

Example 9 ^{41}
^{41} See proposed Rule 11.24(g)(2)(C).
The step-up range will be used to determine order book priority in situations where multiple Enhanced RPI Orders are resting on the BYX Book and are eligible to trade ahead of higher priority orders resting on the BYX Book. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 1's step-up range is $0.04. User 1's order is ranked at $10.01 and is willing to step up to a maximum price of $10.05.
○ User 2 enters an Enhanced RPI Order to buy ABC at $10.02 for 100. User 2's step-up range is $0.02. User 2's order is ranked at $10.02 and is willing to step up to a maximum price of $10.04.
○ User 3 enters a non-displayed order to buy ABC at $10.03 for 100. User 3's order is ranked at $10.03.
○ User 4 enters a Retail Order to sell ABC at $10.03 for 100.
• Result: User 4's Retail Order will execute with User 1's Enhanced RPI Order at $10.04 because the Exchange looks to the step-up range to determine order book priority when there are multiple Enhanced RPI Orders resting on the BYX Book that are willing to provide additional price improvement as compared to other orders resting on the BYX Book. While both User 1 and User 2 can execute at a price of $10.04, User 1's Enhanced RPI Order can result in a higher maximum possible execution price (step up range of $0.04; maximum price of $10.05) as compared to User 2's Enhanced RPI Order (step up range of $0.02; maximum price of $10.04). As such, User 1's Enhanced RPI Order is given priority ahead of User 2's Enhanced RPI Order to execute against User 4's Retail Order. In this instance, when there are multiple Enhanced RPI Orders that can provide price improvement to the contra-side Retail Order, the Exchange believes it is appropriate to grant order book priority to the Enhanced RPI Order containing the step-up range that could result in the highest (in the event of a buy order) or lowest (in the event of a sell order) potential maximum execution price, even if the resulting execution does not occur at the highest (lowest) maximum execution price. By granting execution priority to the User who's Enhanced RPI Order results in the highest (lowest) potential maximum execution price, the Exchange is encouraging Users to submit aggressively priced orders. As such, the Exchange believes it is appropriate to give priority to User 1's Enhanced RPI Order in this instance because User 1's Enhanced RPI Order (step-up range of $0.04; maximum price of $10.05) could potentially result in a higher maximum execution price than User 2's Enhanced RPI Order (step-up range of $0.02; maximum price of $10.04) and is therefore willing to provide additional price improvement to Retail Orders as compared to User 2's Enhanced RPI Order.

Example 10 ^{42}
^{42} See proposed Rule 11.24(g)(2)(A).
Enhanced RPI Orders will have price priority over resting RPI orders (that do not contain a step-up range) on the BYX Book so long as the step-up range of the Enhanced RPI Order is greater than the limit price of the resting RPI order. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 1's step-up range is $0.04. User 1's order is ranked at $10.01 and is willing to step up to a maximum price of $10.05.
○ User 2 enters an RPI Order to buy ABC at $10.02.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 3's Retail Order will execute with User 1's Enhanced RPI Order at a price of $10.025 because User 1's Enhanced RPI Order containing a step-up range allows User 3's Retail Order to receive an additional one-half cent price improvement as compared to the ranked price of User 2's RPI Order. While User 2's RPI Order had a higher ranked price ($10.02) than User 1's Enhanced RPI Order ($10.01), User 2's RPI Order did not contain a step-up range. Given that Enhanced RPI Orders are designed to provide meaningful price improvement against all resting orders on the BYX Book, the Exchange believes this factor favors using the price improvement provided by the step-up range in order to determine priority in situations where there are both resting RPI and Enhanced RPI Orders on the BYX Book. While RPI Orders do provide at least $0.001 of price improvement as compared to the Protected NBBO, Enhanced RPI Orders allow for price improvement to the next valid half cent or full cent as the transaction is priced above $1.00. ^{43} Thus, using the step-up range to determine priority when RPI Orders are resting on the BYX Book results in an increased amount of price improvement for the contra-side Retail Order.
^{43} The Exchange notes that there may be situations in which an Enhanced RPI Order that is granted order book priority over an RPI Order will provide only $0.001 of price improvement over the RPI Order when stepping up to the next half cent or full cent. For example, the Protected NBBO is $10.00 × $10.05. Assume that a buy-side Enhanced RPI Order for 100 shares has a step-up range to $10.04 and is granted order book priority over a buy-side RPI Order for 100 shares with a limit price of $10.024. A sell-side Retail Order for 100 shares is entered at $10.00. In this instance, the buy-side Enhanced RPI Order steps-up to a price of $10.025 to execute against the sell-side Retail Order. While the Enhanced RPI Order is only providing $0.001 of price improvement as compared to the RPI Order with a limit price of $10.024, the Enhanced RPI Order provides a total of $0.025 of price improvement to the Retail Order as compared to the Retail Order's limit price of $10.00.

Example 11 ^{44}
^{44} See proposed Rule 11.24(g)(2)(A).
Enhanced RPI Orders may also improve against displayed orders resting on the BYX Book in order to provide price improvement to a contra-side Retail Order. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters an Enhanced RPI Order to buy ABC at $9.99 for 100. User 1's step-up range is $0.06. User 1's order is ranked at $9.99 and is willing to step up to a maximum price of $10.05. The Retail Liquidity Identifier is not displayed as the limit price of $9.99 is below the NBB and the Retail Liquidity Identifier will only display when there is RPI Interest priced at least $0.001 better than the Protected NBB or Protected NBO.
○ User 2 enters a displayed order to buy ABC at $10.00 for 100.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 3's Retail Order will execute with User 1's Enhanced RPI Order at a price of $10.01. While User 2's displayed order is displayed and ranked at a higher price ($10.00) than User 1's Enhanced RPI Order ($9.99), User 1's Enhanced RPI Order includes a step-up range of $0.06 on its order, which permits the order to execute up to a maximum price of $10.05. In this instance, executing User 2's displayed order at $10.00 does not provide any price improvement to the Retail Order when User 1's Enhanced RPI Order is resting on the BYX Book and is willing to provide additional price improvement to Order 3 than Order 2 is willing to provide. User 1's Enhanced RPI Order is willing to step up to the next full cent above $10.00 (in this case, $10.01), which provides a full penny of price improvement to User 3's Retail Order., As such, this is the price at which User 3's Retail Order executes with User 1's Enhanced RPI Order.

Example 12 ^{45}
^{45} See proposed Rule 11.24(g)(2)(A).
An Enhanced RPI Order that is also a Primary Pegged Order ^{46} without an offset will behave in the same manner as an Enhanced RPI Order that is entered without a Primary Pegged Order instruction. Consider the following example:
^{46} See Rules 11.9(c)(8) and 11.9(c)(8)(A). A Pegged Order is a limit order that after entry into the System, the price of the order is automatically adjusted by the System in response to changes in the NBBO. A Primary Pegged Order is a type of Pegged Order where a User includes a limit priced and a predetermined amount by which the User is willing to improve the Protected NBBO, subject to a ceiling or floor price. The ceiling or floor price is the amount above or below which the User does not wish to trade.
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters a hidden order to buy ABC at $10.03 for 100.
○ User 2 enters an Enhanced RPI Order that is also Primary Pegged Order to buy ABC at $10.02 for 100. User 2's step-up range is $0.03. User 2's order does not include an offset. User 2's order is ranked at $10.00 and is willing to step up to a maximum price of $10.03.
• The Protected NBBO for security ABC changes to $10.01 × $10.05.
○ User 2's Enhanced RPI Order that is also a Primary Pegged Order is now ranked at $10.01 and is willing to step up to a maximum price of $10.04.
○ User 3 enters a Retail Order to sell ABC at $10.01 for 100.
• Result: User 3's Retail Order will execute with User 2's Enhanced RPI Order at a price of $10.04 because User 2's Enhanced RPI Order includes a step-up range of $0.03 and is willing to execute up to a maximum price of $10.04 (based on the Protected NBBO at the time User 3's order is entered) in order to provide additional price improvement as compared to other orders resting on the BYX Book. While User 1's order has a higher limit price ($10.03) than User 2's Enhanced RPI Order ($10.01, based on the Protected NBBO at the time User 3's order is entered), User 2's Enhanced RPI Order is given queue priority due to its ability to provide $0.01 of price improvement over User 1's order.

Example 13 ^{47}
^{47} See proposed Rule 11.24(g)(2)(A).
An Enhanced RPI Order that is also a Primary Pegged Order that contains a positive offset will behave in the same manner as an Enhanced RPI Order that is entered without a Primary Pegged Order instruction, except that the offset amount will determine where the order is ranked. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters a hidden order to buy ABC at $10.03 for 100.
○ User 2 enters an Enhanced RPI Order that is also Primary Pegged Order to buy ABC at $10.02 for 100. User 2's step-up range is $0.03. User 2's order includes an offset of $0.01. User 2's order is ranked at $10.01 and is willing to step up to a maximum price of $10.04.
• The Protected NBBO for security ABC changes to $10.01 × $10.05.
○ User 2's Enhanced RPI Order that is also a Primary Pegged Order is now ranked at $10.02 and is willing to step up to a maximum price of $10.05.
○ User 3 enters a Retail Order to sell ABC at $10.01 for 100.
• Result: User 3's Retail Order will execute with User 2's Enhanced RPI Order at a price of $10.04 because User 2's Enhanced RPI Order includes a step-up range of $0.03 and is willing to execute up to a maximum price of $10.05 (based on the Protected NBBO and the offset of $0.01 at the time User 3's order is entered) in order to provide additional price improvement as compared to other orders resting on the BYX Book. While User 1's order has a higher limit price ($10.03) than User 2's Enhanced RPI Order ($10.02, based on the Protected NBBO and the offset of $0.01 at the time User 3's order is entered), User 2's Enhanced RPI Order is given queue priority due to its ability to provide $0.01 of price improvement over User 1's order.

Example 14 ^{48}
^{48} See proposed Rule 11.24(g)(2)(A).
An Enhanced RPI Order that is also a Primary Pegged Order that contains a negative offset will behave in the same manner as an Enhanced RPI Order that is entered without a Primary Pegged Order instruction, except that the offset amount will determine where the order is ranked. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters a hidden order to buy ABC at $10.03 for 100.
○ User 2 enters an Enhanced RPI Order that is also Primary Pegged Order to buy ABC at $10.02 for 100. User 2's step-up range is $0.03. User 2's order includes an offset of ($0.01). User 2's order is ranked at $9.99 and is willing to step up to a maximum price of $10.02.
• The Protected NBBO for security ABC changes to $10.01 × $10.05.
○ User 2's Enhanced RPI Order that is also a Primary Pegged Order is now ranked at $10.00 and is willing to step up to a maximum price of $10.03.
○ User 3 enters a Retail Order to sell ABC at $10.01 for 100.
• Result: User 3's Retail Order will execute with User 1's hidden order at a price of $10.03. As User 2's Enhanced RPI Order is unable to provide additional price improvement to User 1's hidden order, User 1's order retains priority and executes with User 3's Retail Order. The negative offset of $0.01 causes User 2's order to be ranked at $10.00 after the Protected NBBO changed from $10.00 × $10.05 to $10.01 × $10.05, and User 2's step-up range of $0.03 was unable to provide the minimum amount of price improvement in order to gain queue priority ahead of User 1's hidden order.

Example 15 ^{49}
^{49} See proposed Rule 11.24(g)(2)(A).
Enhanced RPI Orders may also improve upon resting orders that are BYX Post Only Orders in order to provide price improvement to contra-side Retail Orders. Consider the following example:
• The Protected NBBO for security ABC is $10.00 × $10.05.
○ User 1 enters BYX Post Only Order to buy ABC at $10.02 for 100.
○ User 2 enters an Enhanced RPI Order to buy ABC at $10.01 for 100. User 2's step-up range is $0.04. User 2's order is ranked at $10.01 and is willing to step up to a maximum price of $10.05.
○ User 3 enters a Retail Order to sell ABC at $10.00 for 100.
• Result: User 2's Enhanced RPI Order executes against User 3's Retail Order at $10.03. While User 1's BYX Post Only Order is ranked at a higher price ($10.02) than User 2's order, User 2's Enhanced RPI Order is willing to step-up $0.04 over the best-priced resting order to gain queue priority. While User 2 can step-up to a price of $10.05, User 2's Enhanced RPI Order only needs to step-up to a price of $10.03 in order to gain queue priority over User 1's BYX Post Only Order.

Example 16 ^{50}
^{50} See proposed Rule 11.24(g)(2)(A).
Enhanced RPI Orders will also be available for securities priced below $1.00. In order for an Enhanced RPI Order in a security priced below $1.00 to gain queue priority over a same-side resting order, the Enhanced RPI Order must be able to step up to the next minimum price increment. Consider the following example:
• The Protected NBBO for security ABC is $0.2001 × $0.2025.
○ User 1 enters a hidden order to buy ABC at $0.2003 for 100.
○ User 2 enters an Enhanced RPI Order to buy ABC at $0.2002 for 100. User 2's step-up range is $0.001. User 2's order is ranked at $0.2002 and is willing to step up to a maximum price of $0.2012.
○ User 3 enters a Retail Order to sell ABC at $0.2001.
• Result: User 2's Enhanced RPI Order executes against User 3's Retail Order at a price of $0.2004. While User 1's hidden order is ranked at a higher price ($0.2003) than User 2's Enhanced RPI Order ($0.2002), User 2's Enhanced RPI Order included a step-up range of $0.001 and is willing to execute at a price up to $0.2012 in order to gain queue priority. The next minimum price increment above $0.2003 is $0.2004, which is inside User 2's step-up range and as such, User 2's order will have queue priority over User 1's order.
As demonstrated in the examples above, the Exchange is proposing to grant an Enhanced RPI Order price priority over equal-priced or better-priced resting orders on the BYX Book so long as the Enhanced RPI Order can provide meaningful price improvement over such resting orders. The Exchange believes that allowing liquidity providers to post orders outside of the range at which they are willing to execute yet maintain the opportunity to step-up against resting orders on the same side of the BYX Book in exchange for price priority will incentivize these liquidity providers to provide additional liquidity on the Exchange. As a result of additional, aggressively priced liquidity submitted to the Exchange designed specifically to interact with Retail Orders, RMOs will therefore be incentivized to submit additional retail order flow to the Exchange which has the potential to interact with an Enhanced RPI Order and receive meaningful price improvement.

Retail Liquidity Identifier
The Exchange currently disseminates an identifier pursuant to Rule 11.24(e) when RPI Interest priced at least $0.001 better than the Protected NBB or Protected NBO for a particular security is available in the System (“Retail Liquidity Identifier” or “Identifier”). The Identifier is disseminated through consolidated data streams ( i.e., pursuant to the Consolidated Tape Association Plan/Consolidated Quotation Plan, or CTA/CQ, for Tape A and Tape B securities, and the Nasdaq UTP Plan for Tape C securities) as well as through proprietary Exchange data feeds. ^{51} The Identifier reflects the symbol and the side (buy or sell) of the RPI Interest, but does not include the price or size of the RPI Interest. In particular, CQ and UTP quoting outputs include a field for codes related to the Retail Liquidity Identifier. The codes indicate RPI Interest that is priced better than the Protected NBB or Protected NBO by at least the minimum level of price improvement as required by the Program.
^{51} The Exchange notes that the Retail Liquidity Identifier for Tape A and Tape B securities are disseminated pursuant to the CTA/CQ Plan. The identifier is also available through the consolidated public market data stream for Tape C securities. The processor for the Nasdaq UTP disseminates the Retail Liquidity Identifier and analogous identifiers from other market centers that operate programs similar to the RPI Program.
The Exchange proposes to continue to disseminate the Retail Liquidity Identifier in its current form should the Enhanced RPI Order be approved. ^{52} For Enhanced RPI Orders, the indicator will be based off of the ranked price only and the step-up range will not be used. The purpose of the Identifier is to provide relevant market information to RMOs that there is available RPI interest available on the Exchange, thereby incentivizing RMOs to send Retail Orders to the Exchange. The Exchange proposes to make clear in Rule 11.24(e) that both RPI Orders and Enhanced RPI Orders constitute RPI Interest and that the Retail Liquidity Identifier shall be disseminated when RPI Interest (as defined in proposed Rule 11.24(e)) priced at least $0.001 better than the Protected NBB or Protected NBO for a particular security is available in the System for securities priced at or above $1.00. A separate liquidity identifier that identifies Enhanced RPI Order interest will not be disseminated. For securities priced at or above $1.00, displaying the Retail Liquidity Identifier will provide an indication to RMOs that at least $0.001 of price improvement is available in the System, with the opportunity of potentially receiving additional price improvement should the available RPI Interest be in the form of an Enhanced RPI Order.
^{52} The Exchange plans on submitting a letter requesting assurance from staff of the Division of Trading and Markets that it will not recommend enforcement action to the Commission pursuant to Rule 602 of Regulation NMS (the “Quote Rule”) with respect to: (1) the Exchange with respect to collecting, processing, and making available to vendors the best bid, best offer, and quotation sizes communicated by members of the Exchange, or (2) liquidity providers entering RPI Interest under the Program.
As discussed below, the Exchange proposes to expand the Program to include securities priced below $1.00. Given that the minimum price variation (“MPV”) of a sub-dollar security is $0.0001, ^{53} the Identifier for sub-dollar securities will be displayed when there is at least $0.0001 of price improvement over the Protected NBB or Protected NBO. The Exchange will not make any other changes to the Identifier for sub-dollar securities other than the minimum amount of price improvement required to display the Identifier.
^{53} See 17 CFR 242.612 (“Minimum pricing increment”).

Securities Priced Below $1.00
Rule 11.24(h) currently limits the Program to trades occurring at prices equal to or greater than $1.00 per share and the Exchange periodically notifies Members ^{54} regarding securities included in the Program through an information circular. ^{55} Now, the Exchange proposes to expand the Program to all securities, including those priced below $1.00. The rationale behind expanding the Program to all securities regardless of execution price stems from the growth of sub-dollar trading ( i.e., trading at prices below $1.00), both on- and off-exchange. As of March 2023, an analysis of SIP ^{56} data by the Exchange found that sub-dollar average daily volume has increased 313% as compared to first quarter 2019. ^{57} In this period, sub-dollar on-exchange average daily volume grew from 442 million shares per day to 1.8 billion shares per day. ^{58} An analysis of SIP and FINRA Trade Reporting Facility (“TRF”), ^{59} data indicates that exchanges represented approximately 39.8% market share in sub-dollar securities, with a total of 1,638 securities trading below $1.00. ^{60} As an exchange group, Cboe had approximately 13.3% of market share of sub-dollar securities in the first quarter of 2023. ^{61}
^{54} See Rule 1.5(n). The term “Member” shall mean ay registered broker or dealer that has been admitted to membership in the Exchange. A Member will have the status of a “member” of the Exchange as that term is defined in Section 3(a)(3) of the Act. Membership may be granted to a sole proprietor, partnership, corporation, limited liability company or other organization which is a registered broker or dealer pursuant to Section 15 of the Act, and which has been approved by the Exchange.
^{55} Supra note 12.
^{56} The “SIP” refers to the centralized securities information processors.
^{57} See “How Subdollar Securities are Trading Now” (March 16, 2023). Available at https://www.cboe.com/insights/posts/how-subdollar-securities-are-trading-now/.
^{58} Id.
^{59} Trade Reporting Facilities are facilities through which FINRA members report off-exchange transactions in NMS stocks, as defined in SEC Rule 600(b)(47) of Regulation NMS. See Tick Size Proposal at 80315.
^{60} Supra note 57.
^{61} Id.
As trading in sub-dollar securities has grown steadily since 2020, the Exchange believes it is appropriate to expand the Program to include securities priced below $1.00. The Exchange notes, however, that the MPV for sub-dollar securities differs from the MPV for securities priced at or above $1.00. As provided for by Regulation NMS Rule 612, for securities priced below $1.00, the MPV is $0.0001, whereas for securities priced at or above $1.00 the MPV is $0.01. ^{62} The Exchange proposes that in order for an Enhanced RPI Order to gain queue priority ahead of resting orders on the same side of the BYX Book, the Enhanced RPI Order will be stepped-up to the nearest MPV ($0.0001) for securities priced below $1.00. This differs from the treatment of Enhanced RPI Orders for securities priced at or above $1.00, which are proposed to be stepped-up to the nearest half-cent midpoint or whole cent tick ahead of resting orders on the same side of the BYX Book. The Exchange believes that the different treatment of Enhanced RPI Orders for securities priced below $1.00 is appropriate given that the MPV for securities priced below $1.00 is significantly less than the MPV for securities priced at or above $1.00. Currently, all Regulation NMS securities traded on the Exchange priced at or above $1.00 are eligible for inclusion in the Program. The Exchange will announce to its Members via a Trade Desk Notice that the Exchange will no longer provide periodic updates of securities included in the Program as the Program is being expanded to include all Regulation NMS securities traded on the Exchange, regardless of price.
^{62} Supra note 53.

Implementation
The Exchange plans to implement the proposed rule change during the second half of 2024 and will announce the implementation date via Trade Desk Notice.

2. Statutory Basis
The Exchange believes the proposed rule change is consistent with the Securities Exchange Act of 1934 (the “Act”) and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act. ^{63} Specifically, the Exchange believes the proposed rule change is consistent with the Section 6(b)(5) ^{64} requirements that the rules of an exchange be designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to and perfect the mechanism of a free and open market and a national market system, and, in general, to protect investors and the public interest. Additionally, the Exchange believes the proposed rule change is consistent with the Section 6(b)(5) ^{65} requirement that the rules of an exchange not be designed to permit unfair discrimination between customers, issuers, brokers, or dealers.
^{63} 15 U.S.C. 78f(b).
^{64} 15 U.S.C. 78f(b)(5).
^{65} Id.
The Commission has repeatedly emphasized that the U.S. capital markets should be structured with the interests of retail investors in mind ^{66} and has recently proposed a series of rules designed, in part, to attempt to bring order flow back to the exchanges from off-exchange trading venues. ^{67} The Exchange believes its proposed enhancements to the Program are consistent with the Commission's goal of ensuring that the equities markets continue to serve the needs of the investing public. Specifically, introducing the Enhanced RPI Order type would protect investors and the public interest by providing retail investors the ability to obtain meaningful price improvement on BYX, a national securities exchange. The Exchange is committed to innovation that improves the quality of the equities markets and believes that the proposed Enhanced RPI Order may increase the attractiveness of the Exchange for the execution of Retail Orders submitted on behalf of the millions of ordinary investors that rely on these markets for their investment needs.
^{66} See U.S. Securities and Exchange Commission, Strategic Plan, Fiscal Years 2018-2022, available at https://www.sec.gov/files/SEC_Strategic_Plan_FY18-FY22_FINAL_0.pdf.
^{67} Supra notes 23-24. See also, Securities Exchange Act Release No. 96496 (December 14, 2022), 88 FR 5440 (January 27, 2023) (“Regulation Best Execution”); Securities Exchange Act Release No. 96493 (December 14, 2022), 88 FR 3786 (January 20, 2023) (“Disclosure of Order Execution Information”).
The Exchange believes the proposed Enhanced RPI Order promotes just and equitable principles of trade and is not unfairly discriminatory because the order type will be available for all Users, and is not limited to a certain subset of market participants. Even though Enhanced RPI Orders may be entered by any market participant, the Exchange believes that the majority of Enhanced RPI Orders will be entered by or on behalf of institutional investors that are willing to provide additional price improvement as a way to minimize their adverse selection costs. ^{68} The Exchange does not believe that such segmentation is inconsistent with section 6(b)(5) of the Act, as it does not permit unfair discrimination. The Commission has previously stated that the markets generally distinguish between retail investors, whose orders are considered desirable by liquidity providers because such retail investors are presumed to be less informed about short-term price movements, and professional traders, whose orders are presumed to be more informed. ^{69} The Commission has further stated that without opportunities for price improvement, retail investors may encounter wider spreads that are a consequence of liquidity providers interacting with more informed order flow. ^{70} The Exchange believes that its proposed Enhanced RPI Order is reasonably designed to attract marketable retail order flow to the exchange as it will help to ensure that retail investors benefit from the better price that liquidity providers are willing to provide to retail orders in exchange for minimizing their adverse selection costs.
^{68} Adverse selection is the phenomenon where the price of a stock drops right after a liquidity provider purchases the stock. Marketable retail order flow is generally seen as more desirable by institutional liquidity providers as executions against retail orders are less prone to adverse selection. The Commission has previously opined that retail liquidity programs may be beneficial to institutional investors as they may be able to reduce their possible adverse selection costs by interacting with retail order flow. See Pilot Approval Order at 71656.
^{69} Id.
^{70} Id.
Additionally, the Exchange believes that the proposed Enhanced RPI Order type is not unfairly discriminatory to institutional investors as it rewards the User that enters the most aggressively priced Enhanced RPI Order with order book priority. Ultimately, execution priority amongst orders resting on the BYX Book will be determined by the step-up range entered on each Enhanced RPI Order. If the step-up range for an Enhanced RPI Order provides a marketable, contra-side Retail Order with greater price improvement than would otherwise be available from other resting orders by stepping up to the next half cent or full cent (for securities priced at or above $1.00) or the next minimum price increment (for securities priced below $1.00), then the Enhanced RPI Order will be granted order book priority. In the event that multiple Enhanced RPI Orders are resting on the BYX Book, the Enhanced RPI Order with the highest step-up range will be given order book priority. The Exchange believes rewarding the most aggressively priced step-up range will encourage Users to submit Enhanced RPI Orders with step-up ranges that are likely to provide meaningful price improvement to Retail Orders, which ultimately benefits both retail investors, who will receive price improvement over the NBBO, and the User entering the Enhanced RPI Order, who is able to execute against a marketable Retail Order to minimize its adverse selection costs and interact with retail order flow that they are currently unable to access on the Exchange given that such order flow is largely executed off-exchange.
As noted in the Exchange's initial RPI filings, ^{71} most equities exchanges, including BYX, determine priority based on a price/time/display allocation model. ^{72} This has contributed to deep and liquid markets for equity securities as liquidity providers compete to be the first to establish a particular price. While the price/time/display allocation model generally works well for institutional investors, retail investors are traditionally not able to compete with market makers and other automated liquidity providers to set an aggressive price on orders submitted to the Exchange. Importantly, retail investors, in contrast to institutional investors, tend to have longer investment time horizons, which means they are not in the business of optimizing queue placement under a time-based allocation model. Therefore, in order to facilitate the needs of retail investors, the Exchange believes an alternative approach—such as this Enhanced RPI Order proposal—would benefit the retail investor community.
^{71} Supra notes 29-30.
^{72} Nasdaq PSX, however, offers a price setter pro rata model that rewards liquidity providers that set the best price and then rewards other market participants that enter larger sized orders. See Securities Exchange Act Release No. 72250 (May 23, 2014), 79 FR 31147 (May 30, 2014) (SR-Phlx-2014-24).
As discussed earlier, the proposed introduction of the Enhanced RPI Order is designed to provide retail investors with enhanced opportunities to obtain meaningful price improvement by providing them with potential opportunities to execute versus non-displayed Enhanced RPI Orders that offer price improvement beyond that offered by resting orders on the Exchange. Marketable retail order flow is routinely executed in full on entry at the national best bid or offer or better, ^{73} but many retail liquidity programs, including the Exchange's current Program, are designed to offer at least $0.001 of price improvement over the Protected NBB or Protected NBO to Retail Orders. ^{74} By introducing Enhanced RPI Orders, the Exchange is proposing to prioritize Enhanced RPI Orders ahead of other resting orders on the same side of the BYX Book in exchange for the Enhanced RPI Order offering meaningful price improvement to Retail Orders by stepping up to the next half cent or whole cent (for securities priced at or above $1.00) or the next minimum price increment (for securities priced below $1.00). The Exchange believes the ability to post an order at a price outside of the range at which it is willing to execute with the ability to gain priority in exchange for executing at a more aggressive price will (1) encourage Users to submit aggressively priced Enhanced RPI Orders, and (2) attract Retail Order flow to the Exchange, both of which will benefit all investors. Increased order flow will create a deeper pool of liquidity on the Exchange, which provides for greater execution opportunities for all Users and provides for overall enhanced price discovery and price improvement opportunities on the Exchange. If successful, the proposed rule change would benefit market participants by increasing the diversity of order flow with which they can interact on a national securities exchange, thereby increasing order interaction and contributing to price formation.
^{73} A review of internal Exchange data found that 60% of retail orders across the Exchange and its affiliates executed at the NBBO year-to-date in 2023. Similarly, 59% of retail orders across the Exchange and its affiliates executed at the NBBO in calendar year 2022.
^{74} See, e.g., IEX Rule 11.232; Nasdaq BX Rule 4780; NYSE National Rule 7.44-E; NYSE Rule 7.44.
Giving queue priority to certain order types is not a novel concept in the securities markets. In fact, on the Exchange's affiliate, Cboe EDGX Exchange, Inc. (“EDGX”), the displayed portion of Retail Priority Orders are given allocation priority ahead of all other available interest on the EDGX Book (“EDGX Retail Priority”). ^{75} The Commission found that EDGX Retail Priority represented a reasonable effort to enhance the ability of bona fide retail trading interest to compete for executions with orders entered by other market participants that may be better equipped to optimize their place in the intermarket queue. ^{76} The Exchange believes that grating queue priority to an Enhanced RPI Order as discussed in the Purpose section similarly reflects a reasonable effort by the Exchange to create additional price improvement opportunities for retail investors, as has been the standard identified by the Commission in several approval orders written in regards to RLPs. ^{77} While the Exchange is not proposing to prioritize Retail Orders as EDGX has done, it is proposing to prioritize Enhanced RPI Orders that provide price improvement and may only interact with contra-side Retail Orders.
^{75} See EDGX Rule 11.9(a)(2)(A).
^{76} See Securities Exchange Act Release No. 87200 (October 2, 2019), 84 FR 53788 (October 8, 2019), SR-CboeEDGX-2019-012 (“EDGX Retail Priority Approval Order”).
^{77} Supra note 14. See also Securities Exchange Act Release No. 67347 (July 3, 2012), 77 FR 40673 (July 10, 2012) (SR-NYSE-2011-55; SR-NYSEAmex-2011-84) (“RLP Approval Order”) at 40679.
The Exchange believes that the prioritization of Enhanced RPI Orders that offer meaningful price improvement over other resting orders on the same side of the BYX Book promotes just and equitable principles of trade and is consistent with Section 6(b)(5) of the Act as it encourages Users to submit aggressively priced Enhanced RPI Orders in exchange for queue priority ahead of all resting orders on the same side of the BYX Book so long as meaningful price improvement is provided to a contra-side Retail Order. The Exchange proposes to provide queue priority for Enhanced RPI Orders over all other types of orders and is not limiting queue priority to a certain subset of order types. As previously stated, all Users are eligible to submit Enhanced RPI Orders. And while the Exchange believes that most Enhanced RPI Orders will be submitted by or on behalf of professional traders, retail investors will have the opportunity to receive better-priced executions should their executing broker choose to submit a marketable Retail Order to the Exchange. The Exchange believes the introduction of Enhanced RPI Orders will deepen the Exchange's pool of available liquidity, increase marketable retail order flow to the Exchange and provide additional competition for marketable retail order flow, most of which is currently executed off-exchange in the OTC markets. Promoting competition for retail order flow among execution venues stands to benefit retail investors, who may be eligible to receive greater price improvement on the Exchange by interacting with an Enhanced RPI Order than they would if their order was internalized by a broker-dealer on the OTC market.
Furthermore, the Exchange believes that its proposal to limit the use of the step-up range to determine order book priority is consistent with Section 6(b)(5) of the Act because the use of the step-up range rather than limit price to determine order priority is limited to the following: (1) the range is needed to gain priority over a resting order with higher order book priority; (2) in situations where (i) a contra-side Retail Order is entered at a less aggressive price than the Enhanced RPI Order's limit price and all other resting liquidity in the same security and (ii) the Enhanced RPI Order's step-up range is equal to or more aggressively priced than the Retail Order's limit price; and (3) to determine order book priority when multiple Enhanced RPI Orders are resting on the BYX Book and are eligible to trade ahead of higher priority orders. The primary use case of the Enhanced RPI Order identified in the first scenario listed above is to provide price improvement to marketable retail order flow. As previously discussed in the Statutory Basis section, the Exchange believes allowing the use of a step-up range in order to provide an additional, more aggressive price at which an Enhanced RPI Order may execute is essential in order to deepen the pool of liquidity available to retail investors. In exchange for providing aggressively priced orders, these liquidity providers will be rewarded with executions against marketable retail order flow, which is generally preferred over more informed order flow. Retail investors, on the other hand, will receive meaningful price improvement should their order execute against an Enhanced RPI Order.
In the situation where (i) a contra-side Retail Order is entered at a less aggressive price than the Enhanced RPI Order's limit price and all other resting liquidity in the same security and (ii) the Enhanced RPI Order's step-up range is equal to or more aggressively priced than the limit price of the Retail Order, the Exchange believes using the step-up range to determine order priority promotes just and equitable principles of trade because it rewards the Enhanced RPI Order with the most aggressive step-up range rather than forego an execution due to the limit price of all orders resting on the BYX Book being ineligible to trade with the contra-side Retail Order. The intent of the Enhanced RPI Order is to reward aggressively priced liquidity with queue priority while simultaneously providing price improvement to Retail Orders. The Exchange believes that determining order priority using the step-up range in this limited situation is aligned with the intent of liquidity providers that choose to submit Enhanced RPI Orders and emphasizes a benefit of using the Enhanced RPI Order—the ability to enter an order at a less aggressive price yet also provide a step-up range that the liquidity provider is willing to execute in order to execute against marketable retail order flow rather than forego an execution and remain on the BYX Book. The Exchange seeks to encourage liquidity providers to submit order flow designed to interact with marketable retail order flow in an effort to increase the amount of Retail Order executions occurring on-exchange. By rewarding aggressively priced Enhanced RPI Orders in situations where the order would otherwise not execute, the Exchange believes its pool of liquidity available to marketable retail order flow will deepen, thus incentivizing RMOs to submit additional marketable retail order flow to the Exchange.
Likewise, using the step-up range rather than the limit price of an Enhanced RPI Order in situations where multiple Enhanced RPI Orders are resting on the BYX Book and are eligible to trade ahead of higher priority orders promotes the use of the Enhanced RPI Order type as the Exchange seeks to encourage RMOs to submit marketable Retail Orders to the Exchange. Determining order priority of Enhanced Orders based on their step-up range over the limit price of all other higher priority orders rewards the Enhanced RPI Order that provides the most aggressive step-up range. The Exchange believes that using the step-up range rather than the limit price in situations where there are multiple Enhanced RPI Orders will encourage Users to submit aggressively priced Enhanced RPI Orders to the Exchange, as they will be given priority to interact with more desirable marketable retail order flow based on their step-up range. Additionally, the Exchange believes that RMOs will be encouraged to direct marketable retail order flow to the Exchange knowing that the worst price they will receive is $0.001 better than the Protected NBB or Protected NBO for securities priced at or above $1.00 ^{78} and there is potential to receive more meaningful price improvement should an Enhanced RPI Order be present on the opposite side of the BYX Book. ^{79}
^{78} For securities priced below $1.00, the minimum amount of price improvement as compared to the Protected NBB or Protected NBO is $0.0001.
^{79} Retail Orders may only receive $0.001 price improvement in certain situations, including where an Enhanced RPI Order steps up against the limit price of an RPI Order priced in sub-pennies. An Enhanced RPI Order would be given order book priority over RPI Orders in the event that the Enhanced RPI Order was priced equal to or less aggressive than the limit price of a resting RPI Order but had a step-up range that was priced more aggressive than the limit price of the resting RPI Order ( supra note 26).
An analysis of internal Exchange data found that the current Program provided approximately $33 million in price improvement to retail investors during calendar year 2022, which is a substantial increase from the 4.5 million provided to retail investors between January 2016 and June 2018. ^{80} It is reasonable to believe that the proposed Enhanced RPI Order, by virtue of providing at least $0.005 of price improvement in exchange for execution priority, would only add to the Exchange's ability to provide price improvement to retail investors. The Exchange does not believe that offering additional price improvement to retail investors through Enhanced RPI Orders would cause harm to the broader market. On the contrary, the Exchange believes that rewarding Enhanced RPI Orders with order book priority in exchange for price improvement would further the Commission's goal of providing additional opportunities for retail investors to interact directly with a large volume of individual investor orders. The Exchange created the Enhanced RPI Order with the goal of encouraging liquidity providers to submit orders eligible to interact with marketable retail order flow with the competition from these liquidity providers resulting in a reasonable alternative for marketable retail order flow to receive executions at a price better than the Protected NBBO. As the Commission noted in its Order Competition Rule proposal, over 90% of marketable NMS retail stock orders are routed to wholesalers where the orders are not exposed to order-by-order competition. ^{81} While wholesalers generally achieve price improvement relative to the NBBO, the Commission has indicated that exchanges often have liquidity available at the NBBO midpoint, which would be a more favorable price than a retail order receives when executed by a wholesaler. ^{82} Here, the Exchange is proposing price improvement of at least $0.005, and in some cases $0.01, which the Exchange believes would further the Commission's goal of “increasing competition and enhancing the direct exposure of individual investor orders to a broader spectrum of market participants” as set forth in section 11A of the Exchange Act. ^{83}
^{80} See RPI Approval Order at 53184.
^{81} Supra note 23 at 178.
^{82} Id.
^{83} Id.
In addition to the proposed introduction of the Enhanced RPI Order, the Exchange also believes that expanding the Program to include securities priced below $1.00 is consistent with Section 6(b)(5) of the Act because it promotes just and equitable principles of trade by allowing liquidity providers to submit orders designed to interact with retail order flow in all securities, rather than only in securities priced at or above $1.00. As stated above, a significant majority of the increased volume in sub-dollar securities comes from executions occurring off-exchange. ^{84} By permitting the Exchange to expand its Program to include securities priced below $1.00, the Exchange would be a more attractive venue for liquidity providers seeking to interact with retail order flow, which furthers the Commission's goal of bringing retail order executions back on-exchange. Further, the proposal to expand the Program to include securities priced below $1.00 is not unfairly discriminatory because all Users will be able to submit RPI Orders or Enhanced RPI Orders at prices below $1.00. As noted above, the Exchange, along with its affiliates, maintained a market share of 13.3% in sub-dollar securities during the first quarter of 2023. ^{85} The Exchange believes that its expansion of the Program to include sub-dollar securities would lead to more liquidity providers submitting order flow to the Exchange in an attempt to execute against Retail Orders. In turn, RMOs would submit additional Retail Order flow to the Exchange to interact with RPI Orders and Enhanced RPI Orders as there would be additional opportunities for price improvement in sub-dollar securities. The proposal removes impediments to and perfect the mechanism of a free and open market and a national market system and protects investors and the public interest by allowing executions in Retail Orders priced below $1.00 to receive price improvement by executing against RPI Orders or Enhanced RPI Orders, which are currently only available at prices at or above $1.00. In addition to the changes described above, the Exchange believes that the changes to certain existing rule text within Rule 11.24 is consistent with Section 6(b)(5) of the Act because it provides additional certainty as to how Rule 11.24 is to be applied. The proposed revised definition of RPI Interest in Rule 11.24(a)(5) is necessary in order to capture the proposed Enhanced RPI Order type, in addition to the existing RPI Order. Additionally, amending Rule 11.24(e) and Rule 11.24(f)(1)-(2) to reflect the changes made in Rule 11.24(a)(5) is necessary in order to ensure that RPI Interest is properly defined throughout Rule 11.24. The deletion of Rule 11.24(h) and renumbering of Rule 11.24(i) are consistent with the Exchange's proposal to expand the Program to securities priced below $1.00. The proposed changes to Rule 11.24(a)(2) are intended to: (i) clarify that a Retail Order must be submitted with a time-in-force of IOC; and (ii) introduce the ability for Users to submit Retail Orders as Mid-Point Peg Orders, both of which changes serve to provide additional guidance to Users of Retail Orders about the order modifiers permitted by the Exchange. The Exchange believes these changes are ministerial in nature and serve to ensure that Rule 11.24 is properly describing order behavior after the proposed introduction of the Enhanced RPI Order and proposed expansion of the Program to securities priced below $1.00.
^{84} Supra note 57.
^{85} Id.

B. Self-Regulatory Organization's Statement on Burden on Competition
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The Exchange believes that the proposal does not impose any burden on intramarket competition that is not necessary or appropriate in furtherance of the purposes of the Act. Rather, the proposed rule change is designed to increase intramarket competition for retail order flow by introducing a new order type that is designed to provide price improvement to Retail Orders in exchange for price priority over resting orders on the same side of the BYX Book. The proposal, which seeks to provide an innovative form of price improvement to Retail Orders through the creation of the Enhanced RPI Order, represents an effort by the Exchange to encourage on-exchange liquidity an incentivize the trading of Retail Orders on a national securities exchange.
The Exchange also believes the proposed rule change does not impose any burden on intermarket competition that is not necessary or appropriate in furtherance of the Act. As discussed above, IEX, NYSE, NYSE National, and Nasdaq BX each operate RLPs and the Exchange believes that its proposed rule change will allow it to compete for additional retail order flow with the aforementioned exchanges. ^{86} Furthermore, the Exchange's proposal will promote competition between the Exchange and off-exchange trading venues where the majority of retail order flow trades today. The proposed Enhanced RPI Order is designed to foster innovation within the market and increase the quality of the national market system by allowing national securities exchanges to compete both with each other and with off-exchange venues for order flow. Expanding the program to include securities priced below $1.00 similarly would not impose any burden on intermarket competition that is not necessary or appropriate in furtherance of the Act. The Exchange's proposal is designed to increase competition for trading in all securities, including but not limited to securities priced below $1.00. Given the growth of trading in sub-dollar securities since 2020, the Exchange believes that expanding the Program to include sub-dollar securities will make the Program an attractive option for retail investors seeking to trade in lower-priced securities, and as such is a competitive measure designed to compete directly with other exchanges for order flow.
^{86} Supra note 74.

C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others
The Exchange neither solicited nor received comments on the proposed rule change.

III. Proceedings To Determine Whether To Approve or Disapprove SR-CboeBYX-2023-020, as Modified by Amendment No. 1, and Grounds for Disapproval Under Consideration
The Commission is instituting proceedings pursuant to Section 19(b)(2)(B) of the Act ^{87} to determine whether the proposed rule change, as modified by Amendment No. 1, should be approved or disapproved. Institution of proceedings is appropriate at this time in view of the legal and policy issues raised by the proposed rule change, as modified by Amendment No. 1. Institution of proceedings does not indicate that the Commission has reached any conclusions with respect to any of the issues involved. Rather, as described below, the Commission seeks and encourages interested persons to provide comment on the proposed rule change, as modified by Amendment No.1, to inform the Commission's analysis of whether to approve or disapprove the proposed rule change.
^{87} 15 U.S.C. 78s(b)(2)(B).
Pursuant to Section 19(b)(2)(B) of the Act, ^{88} the Commission is providing notice of the grounds for disapproval under consideration. The Commission is instituting proceedings to allow for additional analysis of, and input from commenters with respect to, the consistency of the proposal with the Act, and in particular with Sections 6(b)(5) ^{89} and 6(b)(8) ^{90} of the Act. Section 6(b)(5) of the Act requires that the rules of a national securities exchange be designed, among other things, to promote just and equitable principles of trade, to remove impediments to and perfect the mechanism of a free and open market and a national market system and, in general, to protect investors and the public interest, and not be designed to permit unfair discrimination between customers, issuers, brokers, or dealers. Section 6(b)(8) of the Act requires that the rules of a national securities exchange not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act.
^{88} Id.
^{89} 15 U.S.C. 78f(b)(5).
^{90} 15 U.S.C. 78f(b)(8).

IV. Procedure: Request for Written Comments
The Commission requests that interested persons provide written submissions of their data, views, and arguments with respect to the issues identified above, as well as any other concerns they may have with the proposal. In particular, the Commission invites the written views of interested persons concerning whether the proposed rule change is consistent with the Exchange Act and the rules and regulations thereunder.
Although there do not appear to be any issues relevant to approval or disapproval that would be facilitated by an oral presentation of data, views, and arguments, the Commission will consider, pursuant to Rule 19b-4 under the Act, ^{91} any request for an opportunity to make an oral presentation. ^{92}
^{91} 17 CFR 240.19b-4.
^{92} Section 19(b)(2) of the Act, as amended by the Securities Acts Amendments of 1975, Pub. L. 94-29 (Jun. 4, 1975), grants to the Commission flexibility to determine what type of proceeding—either oral or notice and opportunity for written comments—is appropriate for consideration of a particular proposal by a self-regulatory organization. See Securities Acts Amendments of 1975, Senate Comm. on Banking, Housing & Urban Affairs, S. Rep. No. 75, 94th Cong., 1st Sess. 30 (1975).
Interested persons are invited to submit written data, views, and arguments regarding whether the proposed rule change should be approved or disapproved by May 13, 2024. Any person who wishes to file a rebuttal to any other person's submission must file that rebuttal by May 28, 2024.
Comments may be submitted by any of the following methods:

Electronic Comments
• Use the Commission's internet comment form ( https://www.sec.gov/rules/sro.shtml ); or
• Send an email to rule-comments@sec.gov. Please include file number
SR-CboeBYX-2023-020 on the subject line.

Paper Comments
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.
All submissions should refer to file number SR-CboeBYX-2023-020. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website ( https://www.sec.gov/rules/sro.shtml ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-CboeBYX-2023-020 and should be submitted by May 13, 2024. Rebuttal comments should be submitted by May 28, 2024.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^{93}
^{93} 17 CFR 200.30-3(a)(57).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99973/April 17, 2024]
Order Making Fiscal Year 2024 Annual Adjustments to Transaction Fee Rates

I. Background
Section 31 of the Securities Exchange Act of 1934 (“Exchange Act”) requires each national securities exchange and national securities association to pay transaction fees to the Commission. ^1 Specifically, Section 31(b) requires each national securities exchange to pay to the Commission fees based on the aggregate dollar amount of sales of certain securities (“covered sales”) transacted on the exchange. ^2 Section 31(c) requires each national securities association to pay to the Commission fees based on the aggregate dollar amount of covered sales transacted by or through any member of the association other than on an exchange. ^3
^1 15 U.S.C. 78ee.
^2 15 U.S.C. 78ee(b).
^3 15 U.S.C. 78ee(c).
Section 31 of the Exchange Act requires the Commission to annually adjust the fee rates applicable under Sections 31(b) and (c) to a uniform adjusted rate. ^4 Specifically, the Commission must adjust the fee rates to a uniform adjusted rate that is reasonably likely to produce aggregate fee collections (including assessments on security futures transactions) equal to the regular appropriation to the Commission for the applicable fiscal year. ^5
^4 In some circumstances, the SEC also must make a mid-year adjustment to the fee rates applicable under Sections 31(b) and (c).
^5 15 U.S.C. 78ee(j)(1) (the Commission must adjust the rates under Sections 31(b) and (c) to a “uniform adjusted rate that, when applied to the baseline estimate of the aggregate dollar amount of sales for such fiscal year, is reasonably likely to produce aggregate fee collections under [Section 31] (including assessments collected under [Section 31(d)]) that are equal to the regular appropriation to the Commission by Congress for such fiscal year.”).
The Commission is required to publish notice of the new fee rates under Section 31 not later than 30 days after the date on which an Act making a regular appropriation for the applicable fiscal year is enacted. ^6 On March 23, 2024, the President signed into law the Further Consolidated Appropriations Act, 2024, which includes total appropriations of $2,188,658,000 to the SEC for fiscal year 2024.
^6 15 U.S.C. 78ee(g).

II. Fiscal Year 2024 Annual Adjustment to the Fee Rate
The new fee rate is determined by (1) subtracting the sum of fees estimated to be collected prior to the effective date of the new fee rate ^7 and estimated assessments on security futures transactions to be collected under Section 31(d) of the Exchange Act for all of fiscal year 2024 ^8 from an amount equal to the regular appropriation to the Commission for fiscal year 2024, and (2) dividing by the estimated aggregate dollar amount of covered sales for the remainder of the fiscal year following the effective date of the new fee rate. ^9
^7 The sum of fees to be collected prior to the effective date of the new fee rate is determined by applying the current fee rate to the dollar amount of covered sales prior to the effective date of the new fee rate. The exchanges and FINRA have provided data on the dollar amount of covered sales through Feb. 2024. To calculate the dollar amount of covered sales from Mar. 2024 to the effective date of the new fee rate, the Commission is using the same methodology it used in fiscal year 2020. This methodology is described in Appendix A of this order.
^8 Currently, security futures do not trade on any market, therefore the Commission has not collected any assessments for transactions in security futures. Accordingly, the forecast for the assessments for all of fiscal year 2024 for single stock futures is zero.
^9 To estimate the aggregate dollar amount of covered sales for the remainder of fiscal year 2024 following the effective date of the new fee rate, the Commission is using the same methodology it used previously. This methodology is described in Appendix A of this order.
As noted above, the Further Consolidated Appropriations Act, 2024, includes total appropriations of $2,188,658,000 to the Commission for fiscal year 2024. ^{10} The Commission estimates that it will collect $913,739,887 in fees for the period prior to the effective date of the new fee rate and $0 in assessments on round turn transactions in security futures products during all of fiscal year 2024. Using the methodology described in Appendix A, the Commission estimates that the aggregate dollar amount of covered sales for the remainder of fiscal year 2024 to be $45,844,550,874,710.
^{10} The President signed into law the “Further Consolidated Appropriations Act, 2024” on Mar. 23, 2024. This legislation included an appropriation of $2,149,000,000 to the SEC for fiscal year 2024 operations. The Act further directed that “[i]n addition to the foregoing appropriation, for move, replication, and related costs associated with a replacement leases [sic] for the Commission's office facilities, not to exceed $39,658,000, to remain available until expended . . .”. The sum of these amounts is $2,188,658,000. Finally, the Act further directed that “for purposes of calculating the fee rate under section 31(j) . . . all amounts appropriated under this heading shall be deemed to be the regular appropriation to the Commission for fiscal year 2024”. Pub. L. 118-xx.
The uniform adjusted rate is computed by dividing the residual fees to be collected of $1,274,918,113 by the estimated aggregate dollar amount of covered sales for the remainder of fiscal year 2024 of $45,844,550,874,710; this results in a uniform adjusted rate for fiscal year 2024 of $27.80 per million. ^{11}
^{11} Appendix A shows the process of calculating the fiscal year 2024 annual adjustment and includes the data used by the Commission in making this adjustment.

III. Effective Date of the Uniform Adjusted Rate
Under Section 31(j)(4)(A) of the Exchange Act, the fiscal year 2024 annual adjustments to the fee rates applicable under Sections 31(b) and (c) of the Exchange Act shall take effect on the later of October 1, 2023, or 60 days after the date on which a regular appropriation to the Commission for fiscal year 2024 is enacted. ^{12} The regular appropriation to the Commission for fiscal year 2024 was enacted on March 23, 2024, and accordingly, the new fee rates applicable under Sections 31(b) and (c) of the Exchange Act will take effect on May 22, 2024.
^{12} 15 U.S.C. 78ee(j)(4)(A).

IV. Conclusion
Accordingly, pursuant to Section 31 of the Exchange Act,
It is hereby ordered that the fee rates applicable under Sections 31(b) and (c) of the Exchange Act shall be $27.80 per $1,000,000 effective on May 22, 2024.
By the Commission.
Sherry R. Haywood,

Assistant Secretary.

APPENDIX A
This appendix provides the methodology for determining the annual adjustment to the fee rates applicable under Sections 31(b) and (c) of the Exchange Act for fiscal year 2024. Section 31 of the Exchange Act requires the fee rates to be adjusted so that it is reasonably likely that the Commission will collect aggregate fees equal to its regular appropriation for fiscal year 2024.
To make the adjustment, the Commission must project the aggregate dollar amount of covered sales of securities on the securities exchanges and certain over-the-counter (“OTC”) markets over the course of the year. The fee rate equals the ratio of the Commission's regular appropriation for fiscal year 2024 (less the sum of fees to be collected during fiscal year 2024 prior to the effective date of the new fee rate and aggregate assessments on security futures transactions during all of fiscal year 2024) to the estimated aggregate dollar amount of covered sales for the remainder of the fiscal year following the effective date of the new fee rate.
For 2024, the Commission has estimated the aggregate dollar amount of covered sales by projecting forward the trend established in the previous decade. More specifically, the dollar amount of covered sales was forecasted for months subsequent to February 2024, the last month for which the Commission has data on the dollar volume of covered sales. ^1
^1 To determine the availability of data, the Commission compares the date of the appropriation with the date the transaction data are due from the exchanges (10 business days after the end of the month). If the business day following the date of the appropriation is equal to or subsequent to the date the data are due from the exchanges, the Commission uses these data. The appropriation was signed on Mar. 23, 2024. The first business day after this date was Mar. 25, 2024. Data for Feb. were due from the exchanges on Mar. 14, 2024. As a result, the Commission used Feb. 2024 and earlier data to forecast volume for Mar. 2024 and later months.
The following sections describe this process in detail.

A. Baseline Estimate of the Aggregate Dollar Amount of Covered Sales for Fiscal Year 2024
First, calculate the average daily dollar amount of covered sales (“ADS”) for each month in the sample (August 2013 through February 2024). The monthly total dollar amount of covered sales (exchange plus certain OTC markets) is presented in column C of Table A.
The model forecasts the monthly moving average of the average daily dollar amount of covered sales. Each month's average daily dollar amount of covered sales is calculated by dividing the total covered sales for that month (column C of Table A) by the number of trading days for that month (column B of Table A). These amounts are shown in column D of Table A. The moving average will span the same number of months required to be forecast for the remainder of the fiscal year. The trailing moving average used in the forecast model is presented in column E of Table A.
To capture the recent trends in the monthly changes in the moving averages, calculate the one- and two-month lags of the trailing moving average shown in column E in Table A. These amounts are shown in columns F and G, respectively, of Table A.
Next, model the monthly trailing moving average of ADS as function of a constant term and the two lagged trailing moving averages using the ordinary least squares technique.
Use the estimated model to forecast the trailing moving average of ADS of the first month after the last available monthly data. Estimate the trailing moving average of the second month using the forecasted value of the first month and the actual value of the month before that. Similarly, estimate the trailing moving average of the third month using the forecasted values of the two previous months. Continue in this fashion until the end of the fiscal year.
The estimate of the trailing moving average ADS for the last applicable month in the fiscal year is a prediction of the moving average for those months that need to be predicted. This estimate is used as the predicted value of ADS for each month in the forecast period; to obtain the forecast total covered sales for each month, multiply the predicted ADS by the number of days in each month.
The following is a more formal (mathematical) description of the procedure:
1. Begin with the monthly data for total dollar volume of covered sales (column C). The sample spans ten years, from August 2013 through February 2024. ^2 Divide each month's total dollar volume by the number of trading days in that month (column B) to obtain the average daily dollar volume (ADS, column D).
^2 Because the model uses a two period lag in the 6-month trailing moving average of average daily covered sales, seven additional months of data are added to the table so that the model is estimated with 120 observations.
2. For each month t, calculate the six-month trailing moving average of ADS (shown in column E). For example, the value for March 2014 is the average of the six months ending in March 2014, or October 2013 through March 2014 inclusive.
3. Calculate the one- and two-month lags of the trailing moving average. For example, the one-month lag of the six-month trailing moving average for March 2014 is equal to the six-month trailing moving average for February 2014. The two-month lag of the six-month trailing moving average for March 2024 is equal to the six-month trailing moving average for January 2014. These are shown in columns F and G.
4. Estimate the model using ordinary least squares:
γ t = α + β 1 γ t−1 + β 2 γ t−2 + u t
Where γ t is the six-month trailing moving average of the average daily sales for month t, and γ t−1 and γ t−2 are the one- and two-month lags of γ t, and u t representing the error term for month t. The model can be estimated using standard commercially available software. The estimated parameter values are α = +4,213,794,716, β 1 = +1.672194, β 2 = -0.679948. The root-mean squared error (RMSE) of the regression is 11,776,068,990.
5. The predicted value of the six-month trailing moving average of the last month to be forecast represents the final forecast of covered sales for the entire prediction period. This value is shown in column H. This represents the prediction for August 2024. To calculate this value from the model above, one needs the one-month and two-month lag of the six-month trailing moving average ADS, i.e., the six-month trailing moving average for June and July. The six-month trailing moving average for July is obtained by using the one- and two-month lags for July, that is, the six-month trailing moving averages for June and May. To arrive at all the necessary inputs, one begins with the first month to be forecast, in this case, March 2024, and iterates predictions forward until the last month is predicted. One then multiplies the final predicted six-month trailing moving average ADS by the number of days in each month to arrive at the forecast total dollar amount of covered sales. This is shown in column I.
6. For example, for March 2024, using the a, b 1 , and b 2 parameter estimates shown above, along with the one- and two-month lags in the six-month trailing moving average ADS (representing the six-month trailing moving average ADS for January and February 2024, respectively), one can estimate the forecast six-month trailing moving average ADS for March: +4,213,794,716 + (1.672194 × 620,578,082,121) + (−0.679948 × 597,620,038,362) = 635,590,443,613.
7. With the estimated six-month trailing moving average ADS for March 2024 calculated above, one can estimate the six-month trailing moving average ADS for April 2024. The estimate obtained from March 2024 becomes the one-month lag for April, and the one-month lag used in the March forecast becomes the two-month lag for the April forecast. Thus, the predicted six-month trailing moving average ADS for April 2024 is calculated as: +4,213,794,716 + (1.672194 × 635,590,443,613) + (−0.679948 × 620,578,082,121) = 645,083,757,473.
8. Using the forecasts for March and April, one can estimate the value for May. Repeat this procedure for subsequent months, until the estimate for August 2024 is obtained. This value is 654,922,155,353. ^3 This value is then used to calculate the final forecast total monthly covered sales for all six months from March 2024 through August 2024.
^3 One obtains insignificantly different values using the rounded parameter estimates shown above. The predicted ADS values displayed above represents the full precision estimate.
9. To obtain the estimate of total monthly covered sales for each month, multiply the number of trading days in the month, shown in column B in Table A, by the final forecast six-month trailing moving average ADS, shown in column H of Table A. This product is shown in column I of Table A, and these figures are used to calculate the new fee rate.

B. Using the Forecasts From A To Calculate the New Fee Rate
1. Use Table A to estimate fees collected for the period September 1, 2023, through May 21, 2024. The projected aggregate dollar amount of covered sales for this period is $114,217,485,918,804. Actual and projected fee collections at the current fee rate of $8.00 per million are $913,739,887.
2. Estimate the amount of assessments on security futures products collected from September 1, 2023, through August 31, 2024. The only entity reporting assessable security futures products ceased operations in September 2020. ^4 Consequently, the estimated amount of assessments on security futures products collected from September 2023 through August 2024 is zero.
^4 Currently, security futures do not trade on any market, therefore the Commission has not collected any assessments for transactions in security futures. Accordingly, the forecast for the assessments for all of fiscal year 2024 for single stock futures is zero.
3. Subtract the amount $913,739,887 from the target off-setting collection amount set by Congress of $2,188,658,000, leaving $1,274,918,113 to be collected on dollar volume for the period May 22, 2024, through August 31, 2024.
4. Use Table A to estimate dollar volume for the period May 22, 2024, through August 31, 2024. The estimate is $45,844,550,874,710. Finally, compute the fee rate required to produce the additional $1,274,918,113 in revenue. This rate is $1,274,918,113 divided by $45,844,550,874,710 or 0.00002780959.
5. Round the result to the seventh decimal point, yielding a rate of 0.00002780 (or $27.80 per million).
This table summarizes the estimates of the aggregate dollar amount of covered sales, by time period. The figures in this table can be used to determine the new fee rate.
Table A—Baseline Estimate of the Aggregate Dollar Amount of Sales
Fee rate calculation |
a. Baseline estimate of the aggregate dollar amount of sales, 09/01/2023 to 04/30/2024 ($Millions) | 104,393,654
b. Baseline estimate of the aggregate dollar amount of sales, 05/01/2024 to 05/21/2024 ($Millions) | 9,823,832
c. Baseline estimate of the aggregate dollar amount of sales, 05/22/2024 to 05/31/2024 ($Millions) | 4,584,455
d. Baseline estimate of the aggregate dollar amount of sales, 06/01/2024 to 08/31/2024 ($Millions) | 41,260,096
e. Estimated collections in assessments on security futures products in fiscal year 2023 ($Millions) | 0.000
f. Implied fee rate (($2,188,658,000 − $8.00 * (a + b) − e)/(c + d) | $27.80
Month | # of trading days in month | Total dollar amount of sales | Average daily dollar amount of sales (ADS) | 6-Month trailing moving average ADS | 1 Month lag of 6-month trailing moving average ADS | 2 Month lag of 6-month trailing moving average ADS | Forecast 6-month trailing moving average ADS | Forecast total dollar amount of sales
(A) | (B) | (C) | (D) | (E) | (F) | (G) | (H) | (I)
Aug-13 | 22 | $4,925,611,193,095 | $223,891,417,868 | | | | |
Sep-13 | 20 | 4,959,197,626,713 | 247,959,881,336 | | | | |
Oct-13 | 23 | 5,928,804,028,970 | 257,774,088,216 | | | | |
Nov-13 | 20 | 5,182,024,612,049 | 259,101,230,602 | | | | |
Dec-13 | 21 | 5,265,282,994,173 | 250,727,761,627 | | | | |
Jan-14 | 21 | 5,808,700,114,288 | 276,604,767,347 | 252,676,524,499 | | | |
Feb-14 | 19 | 6,018,926,931,054 | 316,785,627,950 | 268,158,892,846 | 252,676,524,499 | | |
Mar-14 | 21 | 6,068,617,342,988 | 288,981,778,238 | 274,995,875,663 | 268,158,892,846 | 252,676,524,499 | |
Apr-14 | 21 | 6,013,948,953,528 | 286,378,521,597 | 279,763,281,227 | 274,995,875,663 | 268,158,892,846 | |
May-14 | 21 | 5,265,594,447,318 | 250,742,592,729 | 278,370,174,915 | 279,763,281,227 | 274,995,875,663 | |
Jun-14 | 21 | 5,159,506,989,669 | 245,690,809,032 | 277,530,682,815 | 278,370,174,915 | 279,763,281,227 | |
Jul-14 | 22 | 5,364,099,567,460 | 243,822,707,612 | 272,067,006,193 | 277,530,682,815 | 278,370,174,915 | |
Aug-14 | 21 | 5,075,332,147,677 | 241,682,483,223 | 259,549,815,405 | 272,067,006,193 | 277,530,682,815 | |
Sep-14 | 21 | 5,507,943,363,243 | 262,283,017,297 | 255,100,021,915 | 259,549,815,405 | 272,067,006,193 | |
Oct-14 | 23 | 7,796,638,035,879 | 338,984,262,430 | 263,867,645,387 | 255,100,021,915 | 259,549,815,405 | |
Nov-14 | 19 | 5,340,847,027,697 | 281,097,211,984 | 268,926,748,596 | 263,867,645,387 | 255,100,021,915 | |
Dec-14 | 22 | 6,559,110,068,128 | 298,141,366,733 | 277,668,508,213 | 268,926,748,596 | 263,867,645,387 | |
Jan-15 | 20 | 6,185,619,541,044 | 309,280,977,052 | 288,578,219,786 | 277,668,508,213 | 268,926,748,596 | |
Feb-15 | 19 | 5,723,523,235,641 | 301,238,065,034 | 298,504,150,088 | 288,578,219,786 | 277,668,508,213 | |
Mar-15 | 22 | 6,395,046,297,249 | 290,683,922,602 | 303,237,634,306 | 298,504,150,088 | 288,578,219,786 | |
Apr-15 | 21 | 5,625,548,298,004 | 267,883,252,286 | 291,387,465,949 | 303,237,634,306 | 298,504,150,088 | |
May-15 | 20 | 5,521,351,972,386 | 276,067,598,619 | 290,549,197,054 | 291,387,465,949 | 303,237,634,306 | |
Jun-15 | 22 | 6,005,521,460,806 | 272,978,248,218 | 286,355,343,969 | 290,549,197,054 | 291,387,465,949 | |
Jul-15 | 22 | 6,493,670,315,390 | 295,166,832,518 | 284,002,986,546 | 286,355,343,969 | 290,549,197,054 | |
Aug-15 | 21 | 6,963,901,249,270 | 331,614,345,203 | 289,065,699,908 | 284,002,986,546 | 286,355,343,969 | |
Sep-15 | 21 | 6,434,496,770,897 | 306,404,608,138 | 291,685,814,164 | 289,065,699,908 | 284,002,986,546 | |
Oct-15 | 22 | 6,592,594,708,082 | 299,663,395,822 | 296,982,504,753 | 291,685,814,164 | 289,065,699,908 | |
Nov-15 | 20 | 5,822,824,015,945 | 291,141,200,797 | 299,494,771,783 | 296,982,504,753 | 291,685,814,164 | |
Dec-15 | 22 | 6,384,337,478,801 | 290,197,158,127 | 302,364,590,101 | 299,494,771,783 | 296,982,504,753 | |
Jan-16 | 19 | 6,696,059,796,055 | 352,424,199,792 | 311,907,484,647 | 302,364,590,101 | 299,494,771,783 | |
Feb-16 | 20 | 6,659,878,908,747 | 332,993,945,437 | 312,137,418,019 | 311,907,484,647 | 302,364,590,101 | |
Mar-16 | 22 | 6,161,943,754,542 | 280,088,352,479 | 307,751,375,409 | 312,137,418,019 | 311,907,484,647 | |
Apr-16 | 21 | 5,541,076,988,322 | 263,860,808,968 | 301,784,277,600 | 307,751,375,409 | 312,137,418,019 | |
May-16 | 21 | 5,693,520,415,112 | 271,120,019,767 | 298,447,414,095 | 301,784,277,600 | 307,751,375,409 | |
Jun-16 | 22 | 6,317,212,852,759 | 287,146,038,762 | 297,938,894,201 | 298,447,414,095 | 301,784,277,600 | |
Jul-16 | 20 | 5,331,797,261,269 | 266,589,863,063 | 283,633,171,413 | 297,938,894,201 | 298,447,414,095 | |
Aug-16 | 23 | 5,635,976,607,786 | 245,042,461,208 | 268,974,590,708 | 283,633,171,413 | 297,938,894,201 | |
Sep-16 | 21 | 5,942,072,286,976 | 282,955,823,189 | 269,452,502,493 | 268,974,590,708 | 283,633,171,413 | |
Oct-16 | 21 | 5,460,906,573,682 | 260,043,170,175 | 268,816,229,361 | 269,452,502,493 | 268,974,590,708 | |
Nov-16 | 21 | 6,845,287,809,886 | 325,966,086,185 | 277,957,240,431 | 268,816,229,361 | 269,452,502,493 | |
Dec-16 | 21 | 6,208,579,880,985 | 295,646,660,999 | 279,374,010,803 | 277,957,240,431 | 268,816,229,361 | |
Jan-17 | 20 | 5,598,200,907,603 | 279,910,045,380 | 281,594,041,190 | 279,374,010,803 | 277,957,240,431 | |
Feb-17 | 19 | 5,443,426,609,533 | 286,496,137,344 | 288,502,987,212 | 281,594,041,190 | 279,374,010,803 | |
Mar-17 | 23 | 6,661,861,914,530 | 289,646,170,197 | 289,618,045,047 | 288,502,987,212 | 281,594,041,190 | |
Apr-17 | 19 | 5,116,714,033,499 | 269,300,738,605 | 291,160,973,118 | 289,618,045,047 | 288,502,987,212 | |
May-17 | 22 | 6,305,822,460,672 | 286,628,293,667 | 284,604,674,365 | 291,160,973,118 | 289,618,045,047 | |
Jun-17 | 22 | 6,854,993,097,601 | 311,590,595,346 | 287,261,996,756 | 284,604,674,365 | 291,160,973,118 | |
Jul-17 | 20 | 5,394,333,070,522 | 269,716,653,526 | 285,563,098,114 | 287,261,996,756 | 284,604,674,365 | |
Aug-17 | 23 | 6,206,204,906,864 | 269,834,995,951 | 282,786,241,215 | 285,563,098,114 | 287,261,996,756 | |
Sep-17 | 20 | 5,939,886,169,525 | 296,994,308,476 | 284,010,930,928 | 282,786,241,215 | 285,563,098,114 | |
Oct-17 | 22 | 6,134,529,538,894 | 278,842,251,768 | 285,601,183,122 | 284,010,930,928 | 282,786,241,215 | |
Nov-17 | 21 | 6,289,748,560,897 | 299,511,836,233 | 287,748,440,217 | 285,601,183,122 | 284,010,930,928 | |
Dec-17 | 20 | 6,672,181,323,001 | 333,609,066,150 | 291,418,185,351 | 287,748,440,217 | 285,601,183,122 | |
Jan-18 | 21 | 7,672,288,677,308 | 365,347,079,872 | 307,356,589,742 | 291,418,185,351 | 287,748,440,217 | |
Feb-18 | 19 | 8,725,420,462,639 | 459,232,655,928 | 338,922,866,405 | 307,356,589,742 | 291,418,185,351 | |
Mar-18 | 21 | 8,264,755,011,030 | 393,559,762,430 | 355,017,108,730 | 338,922,866,405 | 307,356,589,742 | |
Apr-18 | 21 | 7,490,308,402,446 | 356,681,352,497 | 367,990,292,185 | 355,017,108,730 | 338,922,866,405 | |
May-18 | 22 | 7,242,077,467,361 | 329,185,339,426 | 372,935,876,051 | 367,990,292,185 | 355,017,108,730 | |
Jun-18 | 21 | 7,936,783,802,579 | 377,942,085,837 | 380,324,712,665 | 372,935,876,051 | 367,990,292,185 | |
Jul-18 | 21 | 6,807,593,326,456 | 324,171,110,784 | 373,462,051,150 | 380,324,712,665 | 372,935,876,051 | |
Aug-18 | 23 | 7,363,115,477,823 | 320,135,455,558 | 350,279,184,422 | 373,462,051,150 | 380,324,712,665 | |
| Sep-18 | 19 | 6,781,988,459,996 | 356,946,761,052 | 344,177,017,526 | 350,279,184,422 | 373,462,051,150 | |
Oct-18 | 23 | 10,133,514,482,168 | 440,587,586,181 | 358,161,389,806 | 344,177,017,526 | 350,279,184,422 | |
Nov-18 | 21 | 8,414,847,862,204 | 400,707,041,057 | 370,081,673,412 | 358,161,389,806 | 344,177,017,526 | |
Dec-18 | 19 | 9,075,221,733,736 | 477,643,249,144 | 386,698,533,963 | 370,081,673,412 | 358,161,389,806 | |
Jan-19 | 21 | 7,960,664,643,749 | 379,079,268,750 | 395,849,893,624 | 386,698,533,963 | 370,081,673,412 | |
Feb-19 | 19 | 6,676,391,653,247 | 351,389,034,381 | 401,058,823,428 | 395,849,893,624 | 386,698,533,963 | |
Mar-19 | 21 | 7,828,979,311,928 | 372,808,538,663 | 403,702,453,030 | 401,058,823,428 | 395,849,893,624 | |
Apr-19 | 21 | 6,907,923,076,080 | 328,948,717,909 | 385,095,974,984 | 403,702,453,030 | 401,058,823,428 | |
May-19 | 22 | 7,895,053,976,747 | 358,866,089,852 | 378,122,483,117 | 385,095,974,984 | 403,702,453,030 | |
Jun-19 | 20 | 7,070,583,442,058 | 353,529,172,103 | 357,436,803,610 | 378,122,483,117 | 385,095,974,984 | |
Jul-19 | 22 | 6,792,811,319,721 | 308,764,150,896 | 345,717,617,301 | 357,436,803,610 | 378,122,483,117 | |
Aug-19 | 22 | 8,059,527,400,976 | 366,342,154,590 | 348,209,804,002 | 345,717,617,301 | 357,436,803,610 | |
Sep-19 | 20 | 6,958,132,871,506 | 347,906,643,575 | 344,059,488,154 | 348,209,804,002 | 345,717,617,301 | |
Oct-19 | 23 | 7,235,982,824,882 | 314,607,948,908 | 341,669,359,987 | 344,059,488,154 | 348,209,804,002 | |
Nov-19 | 20 | 6,784,888,230,209 | 339,244,411,510 | 338,399,080,264 | 341,669,359,987 | 344,059,488,154 | |
Dec-19 | 21 | 7,252,856,724,647 | 345,374,129,745 | 337,039,906,538 | 338,399,080,264 | 341,669,359,987 | |
Jan-20 | 21 | 8,178,172,797,805 | 389,436,799,895 | 350,485,348,037 | 337,039,906,538 | 338,399,080,264 | |
Feb-20 | 19 | 8,951,554,790,521 | 471,134,462,659 | 367,950,732,716 | 350,485,348,037 | 337,039,906,538 | |
Mar-20 | 22 | 16,218,726,536,159 | 737,214,842,553 | 432,835,432,545 | 367,950,732,716 | 350,485,348,037 | |
Apr-20 | 21 | 10,289,596,902,933 | 489,980,804,902 | 462,064,241,877 | 432,835,432,545 | 367,950,732,716 | |
May-20 | 20 | 9,435,524,799,540 | 471,776,239,977 | 484,152,879,955 | 462,064,241,877 | 432,835,432,545 | |
Jun-20 | 22 | 12,093,857,552,130 | 549,720,797,824 | 518,210,657,968 | 484,152,879,955 | 462,064,241,877 | |
Jul-20 | 22 | 10,355,334,352,448 | 470,697,016,020 | 531,754,027,322 | 518,210,657,968 | 484,152,879,955 | |
Aug-20 | 21 | 9,763,364,099,611 | 464,922,099,981 | 530,718,633,543 | 531,754,027,322 | 518,210,657,968 | |
Sep-20 | 21 | 11,545,564,207,158 | 549,788,771,769 | 499,480,955,079 | 530,718,633,543 | 531,754,027,322 | |
Oct-20 | 22 | 10,052,383,314,951 | 456,926,514,316 | 493,971,906,648 | 499,480,955,079 | 530,718,633,543 | |
Nov-20 | 20 | 11,039,477,432,965 | 551,973,871,648 | 507,338,178,593 | 493,971,906,648 | 499,480,955,079 | |
Dec-20 | 22 | 12,172,302,216,779 | 553,286,464,399 | 507,932,456,356 | 507,338,178,593 | 493,971,906,648 | |
Jan-21 | 19 | 12,396,479,814,996 | 652,446,306,052 | 538,224,004,694 | 507,932,456,356 | 507,338,178,593 | |
Feb-21 | 19 | 12,103,659,666,497 | 637,034,719,289 | 566,909,441,246 | 538,224,004,694 | 507,932,456,356 | |
Mar-21 | 23 | 16,485,012,205,966 | 716,739,661,129 | 594,734,589,472 | 566,909,441,246 | 538,224,004,694 | |
Apr-21 | 21 | 11,602,282,119,601 | 552,489,624,743 | 610,661,774,543 | 594,734,589,472 | 566,909,441,246 | |
May-21 | 20 | 11,729,455,630,914 | 586,472,781,546 | 616,411,592,860 | 610,661,774,543 | 594,734,589,472 | |
Jun-21 | 22 | 13,038,812,281,463 | 592,673,285,521 | 622,976,063,047 | 616,411,592,860 | 610,661,774,543 | |
Jul-21 | 21 | 11,623,478,100,180 | 553,498,957,151 | 606,484,838,230 | 622,976,063,047 | 616,411,592,860 | |
Aug-21 | 22 | 11,493,350,851,643 | 522,425,038,711 | 587,383,224,800 | 606,484,838,230 | 622,976,063,047 | |
Sep-21 | 21 | 12,312,072,157,576 | 586,289,150,361 | 565,641,473,005 | 587,383,224,800 | 606,484,838,230 | |
Oct-21 | 21 | 12,011,570,888,110 | 571,979,566,100 | 568,889,796,565 | 565,641,473,005 | 587,383,224,800 | |
Nov-21 | 21 | 13,996,377,941,116 | 666,494,187,672 | 582,226,697,586 | 568,889,796,565 | 565,641,473,005 | |
Dec-21 | 22 | 15,494,373,840,971 | 704,289,720,044 | 600,829,436,673 | 582,226,697,586 | 568,889,796,565 | |
Jan-22 | 20 | 16,002,717,162,409 | 800,135,858,120 | 641,935,586,835 | 600,829,436,673 | 582,226,697,586 | |
Feb-22 | 19 | 14,483,452,476,259 | 762,286,972,435 | 681,912,575,789 | 641,935,586,835 | 600,829,436,673 | |
Mar-22 | 23 | 17,089,275,084,128 | 743,011,960,179 | 708,033,044,092 | 681,912,575,789 | 641,935,586,835 | |
Apr-22 | 20 | 13,123,148,685,917 | 656,157,434,296 | 722,062,688,791 | 708,033,044,092 | 681,912,575,789 | |
May-22 | 21 | 15,039,352,606,836 | 716,159,647,945 | 730,340,265,503 | 722,062,688,791 | 708,033,044,092 | |
Jun-22 | 21 | 13,021,062,095,851 | 620,050,575,993 | 716,300,408,161 | 730,340,265,503 | 722,062,688,791 | |
Jul-22 | 20 | 10,112,087,348,637 | 505,604,367,432 | 667,211,826,380 | 716,300,408,161 | 730,340,265,503 | |
Aug-22 | 23 | 11,593,039,396,644 | 504,045,191,158 | 624,171,529,501 | 667,211,826,380 | 716,300,408,161 | |
Sep-22 | 21 | 12,052,452,021,792 | 573,926,286,752 | 595,990,583,929 | 624,171,529,501 | 667,211,826,380 | |
Oct-22 | 21 | 11,962,224,366,908 | 569,629,731,758 | 581,569,300,173 | 595,990,583,929 | 624,171,529,501 | |
Nov-22 | 21 | 11,900,801,868,077 | 566,704,850,861 | 556,660,167,326 | 581,569,300,173 | 595,990,583,929 | |
Dec-22 | 21 | 11,980,859,826,961 | 570,517,134,617 | 548,404,593,763 | 556,660,167,326 | 581,569,300,173 | |
Jan-23 | 20 | 11,045,225,185,619 | 552,261,259,281 | 556,180,742,404 | 548,404,593,763 | 556,660,167,326 | |
Feb-23 | 19 | 10,787,317,510,620 | 567,753,553,191 | 566,798,802,743 | 556,180,742,404 | 548,404,593,763 | |
Mar-23 | 23 | 13,985,409,202,169 | 608,061,269,660 | 572,487,966,561 | 566,798,802,743 | 556,180,742,404 | |
Apr-23 | 19 | 9,399,552,596,651 | 494,713,294,561 | 560,001,893,695 | 572,487,966,561 | 566,798,802,743 | |
May-23 | 22 | 11,791,806,548,751 | 535,991,206,761 | 554,882,953,012 | 560,001,893,695 | 572,487,966,561 | |
Jun-23 | 21 | 13,061,036,476,029 | 621,954,117,906 | 563,455,783,560 | 554,882,953,012 | 560,001,893,695 | |
Jul-23 | 20 | 11,366,116,854,082 | 568,305,842,704 | 566,129,880,797 | 563,455,783,560 | 554,882,953,012 | |
Aug-23 | 23 | 12,671,358,964,418 | 550,928,650,627 | 563,325,730,370 | 566,129,880,797 | 563,455,783,560 | |
| Sep-23 | 20 | 11,205,898,765,006 | 560,294,938,250 | 555,364,675,135 | 563,325,730,370 | 566,129,880,797 | |
Oct-23 | 22 | 13,188,976,620,062 | 599,498,937,276 | 572,828,948,921 | 555,364,675,135 | 563,325,730,370 | |
Nov-23 | 21 | 11,988,333,174,115 | 570,873,008,291 | 578,642,582,509 | 572,828,948,921 | 555,364,675,135 | |
Dec-23 | 20 | 13,128,847,387,720 | 656,442,369,386 | 584,390,624,422 | 578,642,582,509 | 572,828,948,921 | |
Jan-24 | 21 | 13,601,328,853,198 | 647,682,326,343 | 597,620,038,362 | 584,390,624,422 | 578,642,582,509 | |
Feb-24 | 20 | 13,773,538,263,581 | 688,676,913,179 | 620,578,082,121 | 597,620,038,362 | 584,390,624,422 | |
Mar-24 | 20 | | | | 620,578,082,121 | 597,620,038,362 | 654,922,155,353 | 13,098,443,107,060
Apr-24 | 22 | | | | | 620,578,082,121 | 654,922,155,353 | 14,408,287,417,766
May-24 | 22 | | | | | | 654,922,155,353 | 14,408,287,417,766
Jun-24 | 19 | | | | | | 654,922,155,353 | 12,443,520,951,707
Jul-24 | 22 | | | | | | 654,922,155,353 | 14,408,287,417,766
Aug-24 | 22 | | | | | | 654,922,155,353 | 14,408,287,417,766
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99969; File No. SR-NYSE-2024-20]
Self-Regulatory Organizations; New York Stock Exchange LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Connectivity Fee Schedule
April 16, 2024.
Pursuant to Section 19(b)(1) ^1 of the Securities Exchange Act of 1934 (“Act”) ^2 and Rule 19b-4 thereunder, ^3 notice is hereby given that on April 2, 2024, New York Stock Exchange LLC (“NYSE” or the “Exchange”) filed with the Securities and Exchange Commission (the “Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been prepared by the self-regulatory organization. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.
^1 15 U.S.C. 78s(b)(1).
^2 15 U.S.C. 78a.
^3 17 CFR 240.19b-4.

I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada. The proposed rule change is available on the Exchange's website at www.nyse.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and the Statutory Basis for, the Proposed Rule Change

1. Purpose
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada.
The Exchange expects that the proposed rule change would become operative no later than June 30, 2024. It will announce the proposed change to all Fixed Income and Data Services (“FIDS”) customers in the Markham, Canada third party access center (“Markham”).

Current Markham Services
Currently, a market participant in Markham may purchase a wireless connection to connect to a selection of symbols from the NYSE BBO and Trades data feeds or the NYSE Arca BBO and Trades data feeds (the “Current Market Data Connection”) distributed from the Mahwah, New Jersey data center (“MDC”). ^4 Customers that purchase a Current Market Data Connection are charged a non-recurring initial charge of $5,000 and a $6,500 monthly fee (“MRC”).
^4 See Securities Exchange Act Release No. 90209 (October 15. 2020), 85 FR 67044 (October 21, 2020). Through its FIDS business, Intercontinental Exchange, Inc. (“ICE”) operates the MDC. NYSE American LLC, NYSE Arca, Inc. (“NYSE Arca”), NYSE Chicago, Inc. and NYSE National, Inc. are national securities exchanges that are affiliates of the Exchange (collectively, the “Affiliate SROs”). The Exchange and the Affiliate SROs are indirect subsidiaries of ICE.
There is limited bandwidth available on the wireless network to Markham. Accordingly, the Current Market Data Connection does not transport information for all the symbols included in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds. Rather, FIDS provides connectivity to a selection of such symbols, including the data for which there is demand (the “Current Market Data”). When a market participant requests a Current Market Data Connection, it receives connectivity to the portions of the NYSE BBO and Trades and NYSE Arca BBO and Trades data that FIDS transmits wirelessly. The customer then determines the symbols in the Current Market Data for which it will receive data.

Proposed Changes to Markham Services
The Exchange proposes to replace (a) the source of the selection of symbols from the NYSE BBO and Trades to the NYSE Integrated Feed (“NYSE IF”), and (b) the source of the selection of symbols from the NYSE Arca BBO and Trades to the NYSE Arca Integrated Feed (“NYSE Arca IF” and together with the NYSE IF, the “Integrated Feeds”).
As there is limited bandwidth available on the wireless network to Markham, the Exchange proposes that, similar to the Current Market Data Connection, the proposed market data connection (“Proposed Market Data Connection”) would not transport information for all the symbols included in the NYSE IF and NYSE Arca IF. Rather, FIDS would provide connectivity to a selection of such symbols, including the symbols in the Integrated Feeds for which there is demand (the “Proposed Market Data”). When a market participant requested a Proposed Market Data Connection, it would receive connectivity to the portions of the NYSE IF and NYSE Arca IF that FIDS transmits wirelessly. The customer would then determine the symbols in the Proposed Market Data for which it would receive data. As now, the Exchange would not have visibility into which portions of the data feed a given customer chooses to receive.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, ^5 FIDS anticipates that customers will continue to connect to the same selection of symbols and information, and so there will be no impact on the customers due to the change. It does not currently plan to do so, but if in the future FIDS changes the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data.
^5 Although their list of symbols is the same, the Integrated Feeds provide the information in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds, and more. The NYSE BBO and NYSE Arca BBO data feeds distribute on a real-time basis the same best bid and offer (“BBO”) information that NYSE and NYSE Arca, respectively, report under the Consolidated Quotation (“CQ”) Plan for inclusion in the CQ Plan's consolidated quotation information data stream. The NYSE Trades and NYSE Arca Trades data feeds distribute on a real-time basis the same last sale information that NYSE and NYSE Arca, respectively, report under the Consolidated Tape Association (“CTA”) Plan for inclusion in the CTA Plan's consolidated data streams. See Securities Exchange Act Release No. 99591 (February 23, 2024), 89 FR 14915 (February 29, 2024) (SR-NYSE-2024-08) (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Content of the NYSE Best Quotes & Trades Data Feed). In addition to the BBO and last sale information, the Integrated Feeds provide real-time market data in a unified view of events, in sequence, as they appear on the NYSE and NYSE Arca matching engine, respectively. They include depth of book order data, and opening and closing imbalance data, as well as security status updates ( e.g., trade corrections and trading halts) and stock summary messages. See Securities Exchange Act Release Nos. 99689 (March 7, 2024), 89 FR 18466 (March 13, 2024) (SR-NYSE-2024-12, at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Aggregated Lite Market Data Feed), and 19381 (March 12, 2024), 89 FR 19381 (March 18, 2024) (SR-NYSEArca-2024-22), at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Arca Aggregated Lite Market Data Feed).
The charges for the services would not change. As is true now, the proposal would waive the first month's MRC, to allow customers to test a new Proposed Market Data Connection for a month before incurring any MRC. ^6 Also as currently true, the fees for a Proposed Market Data Connection would not include the cost of the Integrated Feeds themselves, just the connection.
^6 Customers that have a Current Market Data Connection would not receive a second waiver.
In order to implement the proposed change, the Exchange proposes to make the following changes to the Connectivity Fee Schedule under “C. Wireless Connectivity to Market Data” (proposed additions italicized and proposed deletions in brackets):
Type of service | Amount of charge
NYSE [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
NYSE Arca [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
As now, the Proposed Market Data Connections would not utilize the pole on the grounds of the MDC.

The Proposed Market Data
Like the NYSE BBO and Trades and NYSE Arca BBO and Trades, the Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. In each case, the NYSE or NYSE Arca, as applicable, files with the Commission for the Integrated Feed it generates, and the related fees. ^7 The filed market data fees apply to all customers of the Integrated Feeds, no matter what form of connectivity or connectivity provider they use.
^7 See Securities Exchange Act Release Nos. 74128 (January 23, 2015), 80 FR 4951 (January 29, 2015) (SR-NYSE-2015-03) (notice of filing and immediate effectiveness of proposed rule change establishing the NYSE Integrated Feed data feed); 76485 (November 20, 2015), 80 FR 74158 (November 27, 2015) (SR-NYSE-2015-57) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for the NYSE Integrated Feed); 65669 (November 2, 2011), 76 FR 69311 (November 8, 2011) (SR-NYSEArca-2011-78) (notice of filing and immediate effectiveness of proposed rule change offering the NYSE Arca Integrated Feed); and 66128 (January 10, 2012), 77 FR 2331 (January 17, 2012) (SR-NYSEArca-2011-96) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for NYSE Arca Integrated Feed).
When a market participant wants to connect to an Integrated Feed, it requests a connection from the provider of its choice. All providers, including FIDS, may only provide the market participant with connectivity once the provider has received confirmation from the NYSE or NYSE Arca, as applicable, that the market participant is authorized to receive the requested data feed.

Application and Impact of the Proposed Change
The proposed change would apply to all customers equally. The proposed change would not apply differently to distinct types or sizes of market participants. As is currently the case, the purchase of any connectivity service is completely voluntary and the Connectivity Fee Schedule is applied uniformly to all customers.
The Exchange is proposing the change at the request of FIDS customers. The customers in Markham that would be affected by the proposed change have stated to FIDS that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. It is the Exchange's understanding that they connect to the Integrated Feeds in Markham over a fiber connection. Given that, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
FIDS does not expect that the proposed change will result in new customers in Markham.
The proposed change is not intended to address any other issues relating to connectivity or related fees, and the Exchange is not aware of any problems that customers would have in complying with the proposed change.

2. Statutory Basis
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act, ^8 in general, and furthers the objectives of Section 6(b)(5) of the Act, ^9 in particular, because it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to, and perfect the mechanisms of, a free and open market and a national market system and, in general, to protect investors and the public interest and does not unfairly discriminate between customers, issuers, brokers, or dealers. The Exchange further believes that the proposed rule change is consistent with Section 6(b)(4) of the Act, ^{10} because it provides for the equitable allocation of reasonable dues, fees, and other charges among its members and issuers and other persons using its facilities and does not unfairly discriminate between customers, issuers, brokers, or dealers.
^8 15 U.S.C. 78f(b).
^9 15 U.S.C. 78f(b)(5).
^{10} 15 U.S.C. 78f(b)(4).

The Proposed Change Is Reasonable
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would remove impediments to, and perfect the mechanisms of, a free and open market and a national market system, and, in general, protect investors and the public interest, as the change would respond to customer requests while keeping the cost the same.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is reasonable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange is not aware of any other public, commercially available wireless connections between the MDC and Markham that connect to the Proposed Market Data. However, the third party McKay Brothers LLC (“McKay”) offers wireless connectivity between the MDC and Markham. Such wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data.
In addition, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or more of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection. The Exchange does not know how many firms distribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Wireless connections and fiber connections to the Proposed Market Data in Markham would compete with each other. Given the various advantages and disadvantages of both wireless and fiber connections, a market participant interested in purchasing a connection to the Proposed Market Data in Markham is likely to consider a variety of factors in deciding whether to use a wireless versus fiber connection, including latency; the amount of network uptime; the equipment the network uses; the cost of the connection; and the applicable contractual provisions. Indeed, fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions.
The Exchange does not believe that FIDS would have any competitive advantage over any future providers of wireless connectivity to the Proposed Market Data in Markham. The Proposed Market Data Connection does not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
The Exchange believes that the proposed rule change is reasonable because a market participant in Markham that opted for a Proposed Market Data Connection would be able to select the specific Proposed Market Data that it wanted to receive in accordance with its needs, thereby helping it tailor its operations to the requirements of its business operations.

The Proposed Change Is an Equitable Allocation of Fees and Credits
The Exchange believes that its proposal equitably allocates its fees among market participants.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would be equitable as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data as well as the data in the NYSE and NYSE Arca BBO and Trades Feeds. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is equitable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Proposed Market Data Connection, as customers could use the McKay wireless connection to transport Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham. Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
The Exchange believes that the proposed change is equitable because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are equitably allocated because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.

The Proposed Change Is Not Unfairly Discriminatory
The Exchange believes that the proposed rule change is not unfairly discriminatory, for the following reasons.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham is not unfairly discriminatory, as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the cost for the Current Market Data Connection. The Exchange believes that it is not unfairly discriminatory that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange believes that the proposed change is not unfairly discriminatory because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are not unfairly discriminatory because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.
For these reasons, the Exchange believes that the proposal is consistent with the Act.

B. Self-Regulatory Organization's Statement on Burden on Competition
The proposed rule changes will not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of Section 6(b)(8) of the Act. ^{11}
^{11} 15 U.S.C. 78f(b)(8).
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. As noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham.
Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or both of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions. Market participants' considerations in determining what connectivity to purchase may include latency; the amount of network uptime; the equipment that the network uses; the cost of the connection; and the applicable contractual provisions.
In addition, due to bandwidth considerations, not all of the symbols included in the NYSE IF and NYSE Arca IF would be transported to Markham, Canada. Accordingly, market participants in Markham that wish to obtain information for all of the symbols in the NYSE IF or NYSE Arca IF may prefer to use a fiber connection offered by a FIDS or one of its competitors.
The Proposed Market Data in Markham would not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
Because the Exchange does not control Markham and could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange., the Exchange believes that the proposed change would not impose a burden on competition that is not necessary or appropriate.
For the reasons described above, the Exchange believes that the proposed rule changes reflect this competitive environment.

C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others
No written comments were solicited or received with respect to the proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act ^{12} and Rule 19b-4(f)(6) thereunder. ^{13} Because the proposed rule change does not: (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative prior to 30 days from the date on which it was filed, or such shorter time as the Commission may designate, if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6)(iii) thereunder. ^{14}
^{12} 15 U.S.C. 78s(b)(3)(A)(iii).
^{13} 17 CFR 240.19b-4(f)(6).
^{14} 17 CFR 240.19b-4(f)(6). In addition, Rule 19b-4(f)(6) requires the Exchange to give the Commission written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B) ^{15} of the Act to determine whether the proposed rule change should be approved or disapproved.
^{15} 15 U.S.C. 78s(b)(2)(B).

IV. Solicitation of Comments
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:

Electronic Comments
• Use the Commission's internet comment form ( https://www.sec.gov/rules/sro.shtml ); or
• Send an email to rule-comments@sec.gov. Please include file number SR-NYSE-2024-20 on the subject line.

Paper Comments
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.
All submissions should refer to file number SR-NYSE-2024-20. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website ( https://www.sec.gov/rules/sro.shtml ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-NYSE-2024-20 and should be submitted on or before May 13, 2024.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^{16}
^{16} 17 CFR 200.30-3(a)(12).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99970; File No. SR-NYSEARCA-2024-32]
Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Connectivity Fee Schedule
April 16, 2024.
Pursuant to Section 19(b)(1) ^1 of the Securities Exchange Act of 1934 (“Act”) ^2 and Rule 19b-4 thereunder, ^3 notice is hereby given that, on April 2, 2024, NYSE Arca, Inc. (“NYSE Arca” or the “Exchange”) filed with the Securities and Exchange Commission (the “Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been prepared by the self-regulatory organization. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.
^1 15 U.S.C. 78s(b)(1).
^2 15 U.S.C. 78a.
^3 17 CFR 240.19b-4.

I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada. The proposed rule change is available on the Exchange's website at www.nyse.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and the Statutory Basis for, the Proposed Rule Change

1. Purpose
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada.
The Exchange expects that the proposed rule change would become operative no later than June 30, 2024. It will announce the proposed change to all Fixed Income and Data Services (“FIDS”) customers in the Markham, Canada third party access center (“Markham”).

Current Markham Services
Currently, a market participant in Markham may purchase a wireless connection to connect to a selection of symbols from the NYSE BBO and Trades data feeds or the NYSE Arca BBO and Trades data feeds (the “Current Market Data Connection”) distributed from the Mahwah, New Jersey data center (“MDC”). ^4 Customers that purchase a Current Market Data Connection are charged a non-recurring initial charge of $5,000 and a $6,500 monthly fee (“MRC”).
^4 See Securities Exchange Act Release No. 90209 (October 15. 2020), 85 FR 67044 (October 21, 2020). Through its FIDS business, Intercontinental Exchange, Inc. (“ICE”) operates the MDC. The New York Stock Exchange LLC (“NYSE”), NYSE American LLC, NYSE Chicago, Inc. and NYSE National, Inc. are national securities exchanges that are affiliates of the Exchange (collectively, the “Affiliate SROs”). The Exchange and the Affiliate SROs are indirect subsidiaries of ICE.
There is limited bandwidth available on the wireless network to Markham. Accordingly, the Current Market Data Connection does not transport information for all the symbols included in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds. Rather, FIDS provides connectivity to a selection of such symbols, including the data for which there is demand (the “Current Market Data”). When a market participant requests a Current Market Data Connection, it receives connectivity to the portions of the NYSE BBO and Trades and NYSE Arca BBO and Trades data that FIDS transmits wirelessly. The customer then determines the symbols in the Current Market Data for which it will receive data.

Proposed Changes to Markham Services
The Exchange proposes to replace (a) the source of the selection of symbols from the NYSE BBO and Trades to the NYSE Integrated Feed (“NYSE IF”), and (b) the source of the selection of symbols from the NYSE Arca BBO and Trades to the NYSE Arca Integrated Feed (“NYSE Arca IF” and together with the NYSE IF, the “Integrated Feeds”).
As there is limited bandwidth available on the wireless network to Markham, the Exchange proposes that, similar to the Current Market Data Connection, the proposed market data connection (“Proposed Market Data Connection”) would not transport information for all the symbols included in the NYSE IF and NYSE Arca IF. Rather, FIDS would provide connectivity to a selection of such symbols, including the symbols in the Integrated Feeds for which there is demand (the “Proposed Market Data”). When a market participant requested a Proposed Market Data Connection, it would receive connectivity to the portions of the NYSE IF and NYSE Arca IF that FIDS transmits wirelessly. The customer would then determine the symbols in the Proposed Market Data for which it would receive data. As now, the Exchange would not have visibility into which portions of the data feed a given customer chooses to receive.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, ^5 FIDS anticipates that customers will continue to connect to the same selection of symbols and information, and so there will be no impact on the customers due to the change. It does not currently plan to do so, but if in the future FIDS changes the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data.
^5 Although their list of symbols is the same, the Integrated Feeds provide the information in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds, and more. The NYSE BBO and NYSE Arca BBO data feeds distribute on a real-time basis the same best bid and offer (“BBO”) information that NYSE and NYSE Arca, respectively, report under the Consolidated Quotation (“CQ”) Plan for inclusion in the CQ Plan's consolidated quotation information data stream. The NYSE Trades and NYSE Arca Trades data feeds distribute on a real-time basis the same last sale information that NYSE and NYSE Arca, respectively, report under the Consolidated Tape Association (“CTA”) Plan for inclusion in the CTA Plan's consolidated data streams. See Securities Exchange Act Release No. 99591 (February 23, 2024), 89 FR 14915 (February 29, 2024) (SR-NYSE-2024-08) (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Content of the NYSE Best Quotes & Trades Data Feed). In addition to the BBO and last sale information, the Integrated Feeds provide real-time market data in a unified view of events, in sequence, as they appear on the NYSE and NYSE Arca matching engine, respectively. They include depth of book order data, and opening and closing imbalance data, as well as security status updates ( e.g., trade corrections and trading halts) and stock summary messages. See Securities Exchange Act Release Nos. 99689 (March 7, 2024), 89 FR 18466 (March 13, 2024) (SR-NYSE-2024-12, at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Aggregated Lite Market Data Feed), and 19381 (March 12, 2024), 89 FR 19381 (March 18, 2024) (SR-NYSEArca-2024-22), at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Arca Aggregated Lite Market Data Feed).
The charges for the services would not change. As is true now, the proposal would waive the first month's MRC, to allow customers to test a new Proposed Market Data Connection for a month before incurring any MRC. ^6 Also as currently true, the fees for a Proposed Market Data Connection would not include the cost of the Integrated Feeds themselves, just the connection.
^6 Customers that have a Current Market Data Connection would not receive a second waiver.
In order to implement the proposed change, the Exchange proposes to make the following changes to the Connectivity Fee Schedule under “C. Wireless Connectivity to Market Data” (proposed additions italicized and proposed deletions in brackets):
Type of service | Amount of charge
NYSE [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
NYSE Arca [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
As now, the Proposed Market Data Connections would not utilize the pole on the grounds of the MDC.

The Proposed Market Data
Like the NYSE BBO and Trades and NYSE Arca BBO and Trades, the Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. In each case, the NYSE or NYSE Arca, as applicable, files with the Commission for the Integrated Feed it generates, and the related fees. ^7 The filed market data fees apply to all customers of the Integrated Feeds, no matter what form of connectivity or connectivity provider they use.
^7 See Securities Exchange Act Release Nos. 74128 (January 23, 2015), 80 FR 4951 (January 29, 2015) (SR-NYSE-2015-03) (notice of filing and immediate effectiveness of proposed rule change establishing the NYSE Integrated Feed data feed); 76485 (November 20, 2015), 80 FR 74158 (November 27, 2015) (SR-NYSE-2015-57) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for the NYSE Integrated Feed); 65669 (November 2, 2011), 76 FR 69311 (November 8, 2011) (SR-NYSEArca-2011-78) (notice of filing and immediate effectiveness of proposed rule change offering the NYSE Arca Integrated Feed); and 66128 (January 10, 2012), 77 FR 2331 (January 17, 2012) (SR-NYSEArca-2011-96) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for NYSE Arca Integrated Feed).
When a market participant wants to connect to an Integrated Feed, it requests a connection from the provider of its choice. All providers, including FIDS, may only provide the market participant with connectivity once the provider has received confirmation from the NYSE or NYSE Arca, as applicable, that the market participant is authorized to receive the requested data feed.

Application and Impact of the Proposed Change
The proposed change would apply to all customers equally. The proposed change would not apply differently to distinct types or sizes of market participants. As is currently the case, the purchase of any connectivity service is completely voluntary and the Connectivity Fee Schedule is applied uniformly to all customers.
The Exchange is proposing the change at the request of FIDS customers. The customers in Markham that would be affected by the proposed change have stated to FIDS that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. It is the Exchange's understanding that they connect to the Integrated Feeds in Markham over a fiber connection. Given that, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
FIDS does not expect that the proposed change will result in new customers in Markham.
The proposed change is not intended to address any other issues relating to connectivity or related fees, and the Exchange is not aware of any problems that customers would have in complying with the proposed change.

2. Statutory Basis
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act, ^8 in general, and furthers the objectives of Section 6(b)(5) of the Act, ^9 in particular, because it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to, and perfect the mechanisms of, a free and open market and a national market system and, in general, to protect investors and the public interest and does not unfairly discriminate between customers, issuers, brokers, or dealers. The Exchange further believes that the proposed rule change is consistent with Section 6(b)(4) of the Act, ^{10} because it provides for the equitable allocation of reasonable dues, fees, and other charges among its members and issuers and other persons using its facilities and does not unfairly discriminate between customers, issuers, brokers, or dealers.
^8 15 U.S.C. 78f(b).
^9 15 U.S.C. 78f(b)(5).
^{10} 15 U.S.C. 78f(b)(4).

The Proposed Change is Reasonable
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would remove impediments to, and perfect the mechanisms of, a free and open market and a national market system, and, in general, protect investors and the public interest, as the change would respond to customer requests while keeping the cost the same.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is reasonable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange is not aware of any other public, commercially available wireless connections between the MDC and Markham that connect to the Proposed Market Data. However, the third party McKay Brothers LLC (“McKay”) offers wireless connectivity between the MDC and Markham. Such wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data.
In addition, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or more of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection. The Exchange does not know how many firms distribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Wireless connections and fiber connections to the Proposed Market Data in Markham would compete with each other. Given the various advantages and disadvantages of both wireless and fiber connections, a market participant interested in purchasing a connection to the Proposed Market Data in Markham is likely to consider a variety of factors in deciding whether to use a wireless versus fiber connection, including latency; the amount of network uptime; the equipment the network uses; the cost of the connection; and the applicable contractual provisions. Indeed, fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions.
The Exchange does not believe that FIDS would have any competitive advantage over any future providers of wireless connectivity to the Proposed Market Data in Markham. The Proposed Market Data Connection does not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
The Exchange believes that the proposed rule change is reasonable because a market participant in Markham that opted for a Proposed Market Data Connection would be able to select the specific Proposed Market Data that it wanted to receive in accordance with its needs, thereby helping it tailor its operations to the requirements of its business operations.

The Proposed Change Is an Equitable Allocation of Fees and Credits
The Exchange believes that its proposal equitably allocates its fees among market participants.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would be equitable as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data as well as the data in the NYSE and NYSE Arca BBO and Trades Feeds. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is equitable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Proposed Market Data Connection, as customers could use the McKay wireless connection to transport Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham. Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
The Exchange believes that the proposed change is equitable because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are equitably allocated because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.

The Proposed Change Is Not Unfairly Discriminatory
The Exchange believes that the proposed rule change is not unfairly discriminatory, for the following reasons.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham is not unfairly discriminatory, as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the cost for the Current Market Data Connection. The Exchange believes that it is not unfairly discriminatory that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange believes that the proposed change is not unfairly discriminatory because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are not unfairly discriminatory because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.
For these reasons, the Exchange believes that the proposal is consistent with the Act.

B Self-Regulatory Organization's Statement on Burden on Competition
The proposed rule changes will not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of Section 6(b)(8) of the Act. ^{11}
^{11} 15 U.S.C. 78f(b)(8).
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. As noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham.
Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or both of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions. Market participants' considerations in determining what connectivity to purchase may include latency; the amount of network uptime; the equipment that the network uses; the cost of the connection; and the applicable contractual provisions.
In addition, due to bandwidth considerations, not all of the symbols included in the NYSE IF and NYSE Arca IF would be transported to Markham, Canada. Accordingly, market participants in Markham that wish to obtain information for all of the symbols in the NYSE IF or NYSE Arca IF may prefer to use a fiber connection offered by a FIDS or one of its competitors.
The Proposed Market Data in Markham would not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
Because the Exchange does not control Markham and could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange, the Exchange believes that the proposed change would not impose a burden on competition that is not necessary or appropriate.
For the reasons described above, the Exchange believes that the proposed rule changes reflect this competitive environment.

C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others
No written comments were solicited or received with respect to the proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act ^{12} and Rule 19b-4(f)(6) thereunder. ^{13} Because the proposed rule change does not: (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative prior to 30 days from the date on which it was filed, or such shorter time as the Commission may designate, if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6)(iii) thereunder. ^{14}
^{12} 15 U.S.C. 78s(b)(3)(A)(iii).
^{13} 17 CFR 240.19b-4(f)(6).
^{14} 17 CFR 240.19b-4(f)(6). In addition, Rule 19b-4(f)(6) requires the Exchange to give the Commission written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B) ^{15} of the Act to determine whether the proposed rule change should be approved or disapproved.
^{15} 15 U.S.C. 78s(b)(2)(B).

IV. Solicitation of Comments
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:

Electronic Comments
• Use the Commission's internet comment form ( https://www.sec.gov/rules/sro.shtml ); or
• Send an email to rule-comments@sec.gov . Please include file number SR-NYSEARCA-2024-32 on the subject line.

Paper Comments
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.
All submissions should refer to file number SR-NYSEARCA-2024-32. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website ( https://www.sec.gov/rules/sro.shtml ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-NYSEARCA-2024-32 and should be submitted on or before May 13, 2024.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^{16}
^{16} 17 CFR 200.30-3(a)(12).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
[Release No. 34-99972; File No. SR-NYSENAT-2024-13]
Self-Regulatory Organizations; NYSE National, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Connectivity Fee Schedule
April 16, 2024.
Pursuant to Section 19(b)(1) ^1 of the Securities Exchange Act of 1934 (“Act”) ^2 and Rule 19b-4 thereunder, ^3 notice is hereby given that on April 2, 2024, NYSE National, Inc. (“NYSE National” or the “Exchange”) filed with the Securities and Exchange Commission (the “Commission”) the proposed rule change as described in Items I, II, and III below, which Items have been prepared by the self-regulatory organization. The Commission is publishing this notice to solicit comments on the proposed rule change from interested persons.
^1 15 U.S.C. 78s(b)(1).
^2 15 U.S.C. 78a.
^3 17 CFR 240.19b-4.

I. Self-Regulatory Organization's Statement of the Terms of Substance of the Proposed Rule Change
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada. The proposed rule change is available on the Exchange's website at www.nyse.com, at the principal office of the Exchange, and at the Commission's Public Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and Statutory Basis for, the Proposed Rule Change
In its filing with the Commission, the self-regulatory organization included statements concerning the purpose of, and basis for, the proposed rule change and discussed any comments it received on the proposed rule change. The text of those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and the Statutory Basis for, the Proposed Rule Change

1. Purpose
The Exchange proposes to amend the Connectivity Fee Schedule to amend the wireless connectivity services that transport market data to Markham, Canada.
The Exchange expects that the proposed rule change would become operative no later than June 30, 2024. It will announce the proposed change to all Fixed Income and Data Services (“FIDS”) customers in the Markham, Canada third party access center (“Markham”).

Current Markham Services
Currently, a market participant in Markham may purchase a wireless connection to connect to a selection of symbols from the NYSE BBO and Trades data feeds or the NYSE Arca BBO and Trades data feeds (the “Current Market Data Connection”) distributed from the Mahwah, New Jersey data center (“MDC”). ^4 Customers that purchase a Current Market Data Connection are charged a non-recurring initial charge of $5,000 and a $6,500 monthly fee (“MRC”).
^4 See Securities Exchange Act Release No. 90209 (October 15. 2020), 85 FR 67044 (October 21, 2020). Through its FIDS business, Intercontinental Exchange, Inc. (“ICE”) operates the MDC. The New York Stock Exchange LLC (“NYSE”), NYSE American LLC, NYSE Arca, Inc. (“NYSE Arca”), and NYSE Chicago, Inc. are national securities exchanges that are affiliates of the Exchange (collectively, the “Affiliate SROs”). The Exchange and the Affiliate SROs are indirect subsidiaries of ICE.
There is limited bandwidth available on the wireless network to Markham. Accordingly, the Current Market Data Connection does not transport information for all the symbols included in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds. Rather, FIDS provides connectivity to a selection of such symbols, including the data for which there is demand (the “Current Market Data”). When a market participant requests a Current Market Data Connection, it receives connectivity to the portions of the NYSE BBO and Trades and NYSE Arca BBO and Trades data that FIDS transmits wirelessly. The customer then determines the symbols in the Current Market Data for which it will receive data.

Proposed Changes to Markham Services
The Exchange proposes to replace (a) the source of the selection of symbols from the NYSE BBO and Trades to the NYSE Integrated Feed (“NYSE IF”), and (b) the source of the selection of symbols from the NYSE Arca BBO and Trades to the NYSE Arca Integrated Feed (“NYSE Arca IF” and together with the NYSE IF, the “Integrated Feeds”).
As there is limited bandwidth available on the wireless network to Markham, the Exchange proposes that, similar to the Current Market Data Connection, the proposed market data connection (“Proposed Market Data Connection”) would not transport information for all the symbols included in the NYSE IF and NYSE Arca IF. Rather, FIDS would provide connectivity to a selection of such symbols, including the symbols in the Integrated Feeds for which there is demand (the “Proposed Market Data”). When a market participant requested a Proposed Market Data Connection, it would receive connectivity to the portions of the NYSE IF and NYSE Arca IF that FIDS transmits wirelessly. The customer would then determine the symbols in the Proposed Market Data for which it would receive data. As now, the Exchange would not have visibility into which portions of the data feed a given customer chooses to receive.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, ^5 FIDS anticipates that customers will continue to connect to the same selection of symbols and information, and so there will be no impact on the customers due to the change. It does not currently plan to do so, but if in the future FIDS changes the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data.
^5 Although their list of symbols is the same, the Integrated Feeds provide the information in the NYSE BBO and Trades and NYSE Arca BBO and Trades data feeds, and more. The NYSE BBO and NYSE Arca BBO data feeds distribute on a real-time basis the same best bid and offer (“BBO”) information that NYSE and NYSE Arca, respectively, report under the Consolidated Quotation (“CQ”) Plan for inclusion in the CQ Plan's consolidated quotation information data stream. The NYSE Trades and NYSE Arca Trades data feeds distribute on a real-time basis the same last sale information that NYSE and NYSE Arca, respectively, report under the Consolidated Tape Association (“CTA”) Plan for inclusion in the CTA Plan's consolidated data streams. See Securities Exchange Act Release No. 99591 (February 23, 2024), 89 FR 14915 (February 29, 2024) (SR-NYSE-2024-08) (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Content of the NYSE Best Quotes & Trades Data Feed). In addition to the BBO and last sale information, the Integrated Feeds provide real-time market data in a unified view of events, in sequence, as they appear on the NYSE and NYSE Arca matching engine, respectively. They include depth of book order data, and opening and closing imbalance data, as well as security status updates ( e.g., trade corrections and trading halts) and stock summary messages. See Securities Exchange Act Release Nos. 99689 (March 7, 2024), 89 FR 18466 (March 13, 2024) (SR-NYSE-2024-12, at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Aggregated Lite Market Data Feed), and 19381 (March 12, 2024), 89 FR 19381 (March 18, 2024) (SR-NYSEArca-2024-22), at note 10 (Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Establish the NYSE Arca Aggregated Lite Market Data Feed).
The charges for the services would not change. As is true now, the proposal would waive the first month's MRC, to allow customers to test a new Proposed Market Data Connection for a month before incurring any MRC. ^6 Also as currently true, the fees for a Proposed Market Data Connection would not include the cost of the Integrated Feeds themselves, just the connection.
^6 Customers that have a Current Market Data Connection would not receive a second waiver.
In order to implement the proposed change, the Exchange proposes to make the following changes to the Connectivity Fee Schedule under “C. Wireless Connectivity to Market Data” (proposed additions italicized and proposed deletions in brackets):
Type of service | Amount of charge
NYSE [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
NYSE Arca [BBO and Trades] Integrated Feed: Wireless Connection in Markham, Canada access center | $5,000 per connection initial charge plus monthly charge per connection of $6,500.
As now, the Proposed Market Data Connections would not utilize the pole on the grounds of the MDC.

The Proposed Market Data
Like the NYSE BBO and Trades and NYSE Arca BBO and Trades, the Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. In each case, the NYSE or NYSE Arca, as applicable, files with the Commission for the Integrated Feed it generates, and the related fees. ^7 The filed market data fees apply to all customers of the Integrated Feeds, no matter what form of connectivity or connectivity provider they use.
^7 See Securities Exchange Act Release Nos. 74128 (January 23, 2015), 80 FR 4951 (January 29, 2015) (SR-NYSE-2015-03) (notice of filing and immediate effectiveness of proposed rule change establishing the NYSE Integrated Feed data feed); 76485 (November 20, 2015), 80 FR 74158 (November 27, 2015) (SR-NYSE-2015-57) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for the NYSE Integrated Feed); 65669 (November 2, 2011), 76 FR 69311 (November 8, 2011) (SR-NYSEArca-2011-78) (notice of filing and immediate effectiveness of proposed rule change offering the NYSE Arca Integrated Feed); and 66128 (January 10, 2012), 77 FR 2331 (January 17, 2012) (SR-NYSEArca-2011-96) (notice of filing and immediate effectiveness of a proposed rule change establishing fees for NYSE Arca Integrated Feed).
When a market participant wants to connect to an Integrated Feed, it requests a connection from the provider of its choice. All providers, including FIDS, may only provide the market participant with connectivity once the provider has received confirmation from the NYSE or NYSE Arca, as applicable, that the market participant is authorized to receive the requested data feed.

Application and Impact of the Proposed Change
The proposed change would apply to all customers equally. The proposed change would not apply differently to distinct types or sizes of market participants. As is currently the case, the purchase of any connectivity service is completely voluntary and the Connectivity Fee Schedule is applied uniformly to all customers.
The Exchange is proposing the change at the request of FIDS customers. The customers in Markham that would be affected by the proposed change have stated to FIDS that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. It is the Exchange's understanding that they connect to the Integrated Feeds in Markham over a fiber connection. Given that, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
FIDS does not expect that the proposed change will result in new customers in Markham.
The proposed change is not intended to address any other issues relating to connectivity or related fees, and the Exchange is not aware of any problems that customers would have in complying with the proposed change.

2. Statutory Basis
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act, ^8 in general, and furthers the objectives of Section 6(b)(5) of the Act, ^9 in particular, because it is designed to prevent fraudulent and manipulative acts and practices, to promote just and equitable principles of trade, to foster cooperation and coordination with persons engaged in regulating, clearing, settling, processing information with respect to, and facilitating transactions in securities, to remove impediments to, and perfect the mechanisms of, a free and open market and a national market system and, in general, to protect investors and the public interest and does not unfairly discriminate between customers, issuers, brokers, or dealers. The Exchange further believes that the proposed rule change is consistent with Section 6(b)(4) of the Act, ^{10} because it provides for the equitable allocation of reasonable dues, fees, and other charges among its members and issuers and other persons using its facilities and does not unfairly discriminate between customers, issuers, brokers, or dealers.
^8 15 U.S.C. 78f(b).
^9 15 U.S.C. 78f(b)(5).
^{10} 15 U.S.C. 78f(b)(4).

The Proposed Change Is Reasonable
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would remove impediments to, and perfect the mechanisms of, a free and open market and a national market system, and, in general, protect investors and the public interest, as the change would respond to customer requests while keeping the cost the same.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is reasonable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange is not aware of any other public, commercially available wireless connections between the MDC and Markham that connect to the Proposed Market Data. However, the third party McKay Brothers LLC (“McKay”) offers wireless connectivity between the MDC and Markham. Such wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data.
In addition, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or more of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection. The Exchange does not know how many firms distribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Wireless connections and fiber connections to the Proposed Market Data in Markham would compete with each other. Given the various advantages and disadvantages of both wireless and fiber connections, a market participant interested in purchasing a connection to the Proposed Market Data in Markham is likely to consider a variety of factors in deciding whether to use a wireless versus fiber connection, including latency; the amount of network uptime; the equipment the network uses; the cost of the connection; and the applicable contractual provisions. Indeed, fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions.
The Exchange does not believe that FIDS would have any competitive advantage over any future providers of wireless connectivity to the Proposed Market Data in Markham. The Proposed Market Data Connection does not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
The Exchange believes that the proposed rule change is reasonable because a market participant in Markham that opted for a Proposed Market Data Connection would be able to select the specific Proposed Market Data that it wanted to receive in accordance with its needs, thereby helping it tailor its operations to the requirements of its business operations.

The Proposed Change Is an Equitable Allocation of Fees and Credits
The Exchange believes that its proposal equitably allocates its fees among market participants.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham would be equitable as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data as well as the data in the NYSE and NYSE Arca BBO and Trades Feeds. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. The Exchange believes that it is equitable that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Proposed Market Data Connection, as customers could use the McKay wireless connection to transport Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham. Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
The Exchange believes that the proposed change is equitable because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are equitably allocated because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.

The Proposed Change Is Not Unfairly Discriminatory
The Exchange believes that the proposed rule change is not unfairly discriminatory, for the following reasons.
The Exchange believes that the proposed rule change to the wireless connectivity services that transport market data to Markham is not unfairly discriminatory, as the change would respond to customer requests while keeping the cost the same. The customers in Markham that would be affected by the proposed change have stated that they would prefer connectivity to the Proposed Market Data instead of the Current Market Data. If they already subscribe to one or more of the Integrated Feeds, changing to the Proposed Market Data may remove the necessity of their also subscribing to NYSE BBO and Trades or NYSE Arca BBO and Trades.
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on the customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the cost for the Current Market Data Connection. The Exchange believes that it is not unfairly discriminatory that the fee remain the same because, as noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The Exchange believes that the proposed change is not unfairly discriminatory because it will result in fees being charged only to market participants that voluntarily select to receive the corresponding services and because those services will be available to all market participants. Furthermore, the Exchange believes that the services and fees proposed herein are not unfairly discriminatory because, in addition to the services being completely voluntary, they are available to all market participants on an equal basis ( i.e., the same products and services are available to all market participants). All market participants that voluntarily select a Proposed Market Data Connection would be charged the same amount for the same services.
For these reasons, the Exchange believes that the proposal is consistent with the Act.

B. Self-Regulatory Organization's Statement on Burden on Competition
The proposed rule changes will not impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of Section 6(b)(8) of the Act. ^{11}
^{11} 15 U.S.C. 78f(b)(8).
Importantly, FIDS does not plan to change the symbols and information available. Because NYSE IF includes all data in the NYSE BBO and Trades feeds, and NYSE Arca IF includes all data in the NYSE Arca BBO and Trades feeds, FIDS anticipates that customers will continue to connect to the same selection, and so there will be no impact on customers due to the change.
It does not currently plan to do so, but if FIDS does change the symbols or information available, customers may have the option of connecting to additional symbols or information that are not part of the Current Market Data but are part of the Proposed Market Data. NYSE IF and NYSE Arca IF include additional data, such as depth of book order data, last sale data, and opening and closing imbalance data, as well as the data in the Current Market Data. As a result, customers in Markham may be able to select what market data they wish to receive from an expanded set.
At the same time, there would be no change to the costs for the Current Market Data Connection. As noted above, FIDS anticipates that customers will continue to connect to the same selection of symbols and, even if there is a change in the information available, there is limited bandwidth available on the wireless network to Markham, and that would not change.
The McKay wireless connection would compete with the Exchange's Proposed Market Data Connection, as customers could use the McKay wireless connection to transport the Proposed Market Data. The Exchange is not aware of any other public, commercially available wireless connections to the Proposed Market Data between the MDC and Markham.
Based on the information available to it, the Exchange understands that other providers offer connectivity to the Proposed Market Data in Markham through fiber connections. Such third party providers obtain one or both of the Integrated Feeds from FIDS at the MDC and send it over their own fiber networks to Markham. It is the Exchange's understanding that various customers already connect to the Proposed Market Data over a fiber connection, and so the Proposed Market Data Connection may act as a supplement to their existing fiber connections. The Exchange does not know how many firms redistribute the Proposed Market Data in Markham.
Additional third party competitors could offer fiber or wireless connectivity to the Proposed Market Data in Markham by obtaining the market data at the MDC and sending it over a fiber or wireless network to Canada. A market participant in Markham also may create a proprietary market data connection, whether fiber or wireless; connect through another market participant; utilize fiber connections offered by third parties; or utilize fiber connections offered by FIDS. The Exchange could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange.
Fiber network connections may be more attractive to some market participants as they are more reliable and less susceptible to weather conditions. Market participants' considerations in determining what connectivity to purchase may include latency; the amount of network uptime; the equipment that the network uses; the cost of the connection; and the applicable contractual provisions.
In addition, due to bandwidth considerations, not all of the symbols included in the NYSE IF and NYSE Arca IF would be transported to Markham, Canada. Accordingly, market participants in Markham that wish to obtain information for all of the symbols in the NYSE IF or NYSE Arca IF may prefer to use a fiber connection offered by a FIDS or one of its competitors.
The Proposed Market Data in Markham would not have any special access to or advantage within the MDC. The Integrated Feeds are generated at the MDC in the trading and execution systems of the NYSE and NYSE Arca. FIDS would collect the Proposed Market Data, then send it over the Proposed Market Data Connection by connecting to equipment in an MDC meet-me-room and from there to a pole. The pole is owned by a third party and is not on the grounds of the MDC, and the path into the MDC through a meet-me-room is available to any telecommunications provider. Further, all distances in the MDC are normalized.
Because the Exchange does not control Markham and could not impose any impediments to a third party seeking to offer a similar service, including by placing them at a latency or other competitive disadvantage with respect to the Exchange., the Exchange believes that the proposed change would not impose a burden on competition that is not necessary or appropriate.
For the reasons described above, the Exchange believes that the proposed rule changes reflect this competitive environment.

C. Self-Regulatory Organization's Statement on Comments on the Proposed Rule Change Received From Members, Participants, or Others
No written comments were solicited or received with respect to the proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for Commission Action
The Exchange has filed the proposed rule change pursuant to Section 19(b)(3)(A)(iii) of the Act ^{12} and Rule 19b-4(f)(6) thereunder. ^{13} Because the proposed rule change does not: (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative prior to 30 days from the date on which it was filed, or such shorter time as the Commission may designate, if consistent with the protection of investors and the public interest, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6)(iii) thereunder. ^{14}
^{12} 15 U.S.C. 78s(b)(3)(A)(iii).
^{13} 17 CFR 240.19b-4(f)(6).
^{14} 17 CFR 240.19b-4(f)(6). Rule 19b-4(f)(6) requires the Exchange to give the Commission written notice of its intent to file the proposed rule change, along with a brief description and text of the proposed rule change, at least five business days prior to the date of filing of the proposed rule change, or such shorter time as designated by the Commission. The Exchange has satisfied this requirement.
At any time within 60 days of the filing of such proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings under Section 19(b)(2)(B) ^{15} of the Act to determine whether the proposed rule change should be approved or disapproved.
^{15} 15 U.S.C. 78s(b)(2)(B).

IV. Solicitation of Comments
Interested persons are invited to submit written data, views and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:

Electronic Comments
• Use the Commission's internet comment form ( https://www.sec.gov/rules/sro.shtml ); or
• Send an email to rule-comments@sec.gov. Please include file number SR-NYSENAT-2024-13 on the subject line.

Paper Comments
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.
All submissions should refer to file number SR-NYSENAT-2024-13. This file number should be included on the subject line if email is used. To help the Commission process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's internet website ( https://www.sec.gov/rules/sro.shtml ). Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for website viewing and printing in the Commission's Public Reference Room, 100 F Street NE, Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. Do not include personal identifiable information in submissions; you should submit only information that you wish to make available publicly. We may redact in part or withhold entirely from publication submitted material that is obscene or subject to copyright protection. All submissions should refer to file number SR-NYSENAT-2024-13 and should be submitted on or before May 13, 2024.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority. ^{16}
^{16} 17 CFR 200.30-3(a)(12).
Vanessa A. Countryman,

Secretary.
SECURITIES AND EXCHANGE COMMISSION
Sunshine Act Meetings

TIME AND DATE:
2:00 p.m. on Thursday, April 25, 2024.

PLACE:
The meeting will be held via remote means and/or at the Commission's headquarters, 100 F Street NE, Washington, DC 20549.

STATUS:
This meeting will be closed to the public.

MATTERS TO BE CONSIDERED:
Commissioners, Counsel to the Commissioners, the Secretary to the Commission, and recording secretaries will attend the closed meeting. Certain staff members who have an interest in the matters also may be present.
In the event that the time, date, or location of this meeting changes, an announcement of the change, along with the new time, date, and/or place of the meeting will be posted on the Commission's website at https://www.sec.gov.
The General Counsel of the Commission, or her designee, has certified that, in her opinion, one or more of the exemptions set forth in 5 U.S.C. 552b(c)(3), (5), (6), (7), (8), 9(B) and (10) and 17 CFR 200.402(a)(3), (a)(5), (a)(6), (a)(7), (a)(8), (a)(9)(ii) and (a)(10), permit consideration of the scheduled matters at the closed meeting.
The subject matter of the closed meeting will consist of the following topics:
Institution and settlement of injunctive actions;
Institution and settlement of administrative proceedings;
Resolution of litigation claims; and
Other matters relating to examinations and enforcement proceedings.
At times, changes in Commission priorities require alterations in the scheduling of meeting agenda items that may consist of adjudicatory, examination, litigation, or regulatory matters.

CONTACT PERSON FOR MORE INFORMATION:
For further information; please contact Vanessa A. Countryman from the Office of the Secretary at (202) 551-5400.
Authority: 5 U.S.C. 552b.
Dated: April 18, 2024.
Vanessa A. Countryman,

Secretary.
OFFICE OF THE UNITED STATES TRADE REPRESENTATIVE
[Docket Nos. USTR-2024-0004, USTR-2024-0005]
Initiation of Section 301 Investigation: China's Acts, Policies, and Practices Targeting the Maritime, Logistics, and Shipbuilding Sectors for Dominance

AGENCY:
Office of the United States Trade Representative.

ACTION:
Notice of investigation initiation, hearing, and request for comments.

SUMMARY:
On March 12, 2024, the Office of the United States Trade Representative (USTR) received a petition requesting an investigation of China's acts, policies, and practices targeting the maritime, logistics, and shipbuilding sectors for dominance. On consideration of the petition and the advice of the Section 301 Committee, the U.S. Trade Representative has initiated an investigation into the issues raised in the petition. The inter-agency Section 301 Committee will hold a public hearing and is seeking public comments in connection with this investigation.

DATES:
April 17, 2024: The U.S. Trade Representative initiated the investigation.
May 22, 2024: To be assured of consideration, submit written comments and any requests to appear at the hearing, along with a summary of the testimony, by this date.
May 29, 2024: The Section 301 Committee will convene a public hearing in the main hearing room of the U.S. International Trade Commission Building, 500 E Street SW, Washington DC, beginning at 10 a.m. If necessary, the hearing may continue on May 31, 2024.
Seven days after the last day of the public hearing: Submit post-hearing rebuttal comments.

ADDRESSES:
Submit documents in response to this notice, including written comments, hearing appearance requests, summaries of testimony, and post-hearing rebuttal comments through the appropriate online USTR portal at: https://comments.ustr.gov/s/.

FOR FURTHER INFORMATION CONTACT:
Megan Grimball and Philip Butler, Chairs of the Section 301 Committee, or Assistant General Counsels Thomas Au and Henry Smith, (202) 395-5725.

SUPPLEMENTARY INFORMATION:

I. Summary of the Petition
On March 12, 2024, five labor unions ^1 filed a Section 301 petition regarding the acts, policies, and practices of China to dominate the maritime, logistics, and shipbuilding sector. ^2 The petition was filed pursuant to section 302(a)(1) of the Trade Act of 1974, as amended (Trade Act) (19 U.S.C. 2412(a)(1)), requesting action pursuant to Section 301(b) (19 U.S.C. 2411(b)).
^1 The five petitioners are the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO CLC (USW), the International Brotherhood of Electrical Workers (IBEW), the International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers, AFL-CIO/CLC (IBB), the International Association of Machinists and Aerospace Workers (IAM), and the Maritime Trades Department of the AFL-CIO (MTD).
^2 For additional information, the full text of the petition and accompanying exhibits are available at: https://ustr.gov/issue-areas/enforcement/section-301-investigations/section-301-petition-china-maritime-logistics-and-shipbuilding-sector.
Petitioners allege that China targets the maritime, logistics, and shipbuilding sector for dominance and engages in a wide range of unreasonable or discriminatory acts, policies, and practices that provide unfair advantages across maritime industries, such as shipbuilding, shipping, and maritime equipment, including:
• Implementing industrial planning and policies that are designed to unfairly capture market share, distort global markets, and advantage Chinese enterprises;
• Directing mergers and anticompetitive activities;
• Providing non-market advantages to Chinese firms to dominate key upstream inputs and technologies;
• Providing advanced financing mechanisms advantaging Chinese industry;
• Creating a Chinese network of upstream suppliers, foreign ports and terminals, shippers, and equipment and logistics software that allow advantageous use of information;
• Tolerating intellectual property theft and industrial espionage; and
• Controlling shipping freight rates and capacity allocations.
The petitioners also aver that China threatens to discriminate against U.S. commerce and disrupt supply chains.
Petitioners allege that China's acts, policies, and practices burden or restrict U.S. commerce by:
• Dramatically increasing China's shipbuilding excess capacity and global market share, contributing to declines in U.S. shipbuilding capacity, production, and market share;
• Artificially depressing prices, which makes it more difficult for U.S. companies to compete for sales;
• Impeding U.S. investment, production, and employment;
• Reducing the number of U.S.-produced ships in the domestic and global merchant fleets; and
• Providing unfair advantages and preferences that burden or restrict trade in inputs, and burden or restrict trade opportunities for upstream inputs and downstream industries.
In addition, the petitioners assert that China threatens to undermine U.S. national and economic security.

II. Initiation of a Section 301 Investigation
Pursuant to section 302(a)(2) of the Trade Act, the U.S. Trade Representative reviewed the allegations in the petition, and after receiving the advice of the section 301 Committee, the U.S. Trade Representative determined to initiate an investigation regarding the issues raised in the petition. In accordance with Section 303(a) of the Trade Act, USTR is requesting consultations with the government of China. Petitioners have requested a public hearing. In accordance with section 302(a)(4), and with the agreement of the petitioners, the section 301 Committee will hold a public hearing on this matter on May 29, 2024.

III. Relevant Provisions of the Trade Act
Section 302(a)(4) of the Trade Act authorizes the U.S. Trade Representative to initiate an investigation to determine whether an act, policy, or practice of a foreign country is actionable under section 301 of the Trade Act. Actionable matters under section 301 include acts, policies, and practices of a foreign country that are unreasonable or discriminatory and burden or restrict U.S. commerce. See Section 301(b)(1). An act, policy, or practice is unreasonable if, while not necessarily in violation of, or inconsistent with, the international legal rights of the United States, it is otherwise unfair and inequitable. See Section 301(d)(3)(A). The statute provides that acts, policies, and practices that are unreasonable include any act, policy, or practice, or any combination of acts, policies, or practices, which constitutes export targeting. See Section 301(d)(3)(B)(ii). Export targeting means any government plan or scheme consisting of a combination of coordinated actions (whether carried out severally or jointly) that are bestowed on a specific enterprise, industry, or group thereof, the effect of which is to assist the enterprise, industry, or group to become more competitive in the export of a class or kind of merchandise. See Section 301(d)(3)(E). The statute also provides that an act, policy, or practice of a foreign country that burdens or restricts U.S. commerce may include the provision, directly or indirectly, by that foreign country of subsidies for the construction of vessels used in the commercial transportation by water of goods between foreign countries and the United States. See Section 301(d)(2).
Pursuant to section 304 of the Trade Act, the U.S. Trade Representative will determine on the basis of the investigation whether any act, policy, or practice described under section 301(b) exists. If that determination is affirmative, the U.S. Trade Representative will determine whether action is appropriate, and if so, what action to take. See Section 304(a)(1)(B).

IV. Request for Public Comments
You may submit written comments on any issue covered by the investigation. In particular, USTR invites comments on:
• China's acts, policies, and practices targeting the maritime, logistics, and shipbuilding sectors for dominance;
• Whether China's acts, policies, and practices targeting the maritime, logistics, and shipbuilding sectors for dominance are unreasonable or discriminatory;
• China's efforts to dominate the global maritime, logistics, and shipbuilding sectors, including the upstream and downstream supply chain, as well as shipping services;
• Information on other acts, policies, and practices of China relating to the maritime, logistics and shipbuilding sectors, including:
• political guidance, directives, and control within state and private enterprises,
• activities of state-owned or state-controlled enterprises,
• market access and investment restrictions,
• opaque regulatory preferences and discrimination,
• wage-suppressing labor practices,
• state support of industry (including government guidance funds),
• forced technology transfer (including state-sponsored cyber theft of intellectual property), or
• other means employed by China to achieve its goals, which might be included in this investigation, or be addressed through other applicable mechanisms;
• Whether China's acts, policies, and practices burden or restrict U.S. commerce, and if so, the nature and level of the burden or restriction. Such comments may include economic assessments of the burden or restriction on any sector or industry, as well as assessments of the burden or restriction on labor in the United States related to the acts, policies, and practices under investigation;
• The determinations required under section 304 of the Trade Act; and
• Any other views concerning issues raised in the petition.
To be assured of consideration, USTR must receive written comments by May 22, 2024. Additional instructions on how to submit written comments are provided in section V below.
The Section 301 Committee will convene a public hearing on May 29, 2024, in the main hearing room of the U.S. International Trade Commission, 500 E Street SW, Washington DC 20436, beginning at 10 a.m. Persons wishing to appear at the hearing must provide written notification of their intention and a summary of the proposed testimony by 11:59 p.m. on May 22, 2024, using the procedures in section V below. Remarks at the hearing are limited to five minutes to allow for possible questions from the Section 301 Committee.
Post-hearing rebuttal comments, which should be limited to rebutting or supplementing testimony at the hearing, may be submitted within seven calendar days after the last day of the public hearing. Post-hearing rebuttal comments must be submitted using the electronic portal following the instructions in section V below.

V. Procedures for Notification of Intent To Testify and Written Submissions, Including Rebuttal Submissions
You must submit written comments, requests to appear at the hearing, summaries of testimony, and post-hearing rebuttal comments using the appropriate docket on the portal at https://comments.ustr.gov/s/. To submit written comments, including post-hearing rebuttal comments, use the docket on the portal entitled “Request for Comments on the Section 301 Investigation of China's Acts, Policies, and Practices Targeting the Maritime, Logistics, and Shipbuilding Sectors for Dominance”, docket number USTR-2024-0005.
Persons wishing to provide testimony at the hearing must submit a notification of intent and summary of testimony using the docket entitled: “Request to Appear at the Hearing on the Section 301 Investigation of China's Acts, Policies, and Practices Targeting the Maritime, Logistics, and Shipbuilding Sectors for Dominance”, docket number USTR-2024-0004.
You do not need to establish an account to submit comments or notification of intent to testify. The first screen of each docket allows you to enter identification and contact information. Third party organizations such as law firms, trade associations, or customs brokers, should identify the full legal name of the organization they represent, and identify the primary point of contact for the submission. Information fields are optional; however, your comment or request may not be considered if insufficient information is provided.
Fields with a gray Business Confidential Information (BCI) notation are for BCI information which will not be made publicly available. Fields with a green (Public) notation will be viewable by the public.
After entering the identification and contact information, you can complete the remainder of the comment, or any portion of it by clicking “Next.” You may upload documents at the end of the form and indicate whether USTR should treat the documents as business confidential or public information.
Any page containing BCI must be clearly marked `BUSINESS CONFIDENTIAL' on the top of that page and the submission should clearly indicate, via brackets, highlighting, or other means, the specific information that is BCI. If you request business confidential treatment, you must certify in writing that disclosure of the information would endanger trade secrets or profitability, and that the information would not customarily be released to the public.
Parties uploading attachments containing BCI also must submit a public version of their comments. If these procedures are not sufficient to protect BCI or otherwise protect business interests, please contact the USTR section 301 support line at (202) 395-5725 to discuss whether alternative arrangements are possible.
USTR will post attachments uploaded to the docket for public inspection, except for properly designated BCI. You can view submissions on USTR's electronic portal at https://comments.ustr.gov/s/.
Juan Millan,

Acting General Counsel, Office of the United States Trade Representative.
DEPARTMENT OF TRANSPORTATION
Federal Motor Carrier Safety Administration
[Docket No. FMCSA-2015-0323; FMCSA-2017-0251; FMCSA-2018-0058; FMCSA-2020-0052; FMCSA-2021-0026]
Qualification of Drivers; Exemption Applications; Epilepsy and Seizure Disorders

AGENCY:
Federal Motor Carrier Safety Administration (FMCSA), Department of Transportation (DOT).

ACTION:
Notice of final disposition.

SUMMARY:
FMCSA announces its decision to renew exemptions for 13 individuals from the requirement in the Federal Motor Carrier Safety Regulations (FMCSRs) that interstate commercial motor vehicle (CMV) drivers have “no established medical history or clinical diagnosis of epilepsy or any other condition which is likely to cause loss of consciousness or any loss of ability to control a CMV.” The exemptions enable these individuals who have had one or more seizures and are taking anti-seizure medication to continue to operate CMVs in interstate commerce.

DATES:
The exemptions were applicable on March 15, 2024. The exemptions expire on March 15, 2026.

FOR FURTHER INFORMATION CONTACT:
Ms. Christine A. Hydock, Chief, Medical Programs Division, FMCSA, DOT, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, (202) 366-4001, fmcsamedical@dot.gov. Office hours are from 8:30 a.m. to 5 p.m. ET Monday through Friday, except Federal holidays. If you have questions regarding viewing or submitting material to the docket, contact Dockets Operations, (202) 366-9826.

SUPPLEMENTARY INFORMATION:

I. Public Participation

A. Viewing Comments
To view comments go to www.regulations.gov. Insert the docket number (FMCSA-2015-0323, FMCSA-2017-0251, FMCSA-2018-0058, FMCSA-2020-0052, or FMCSA-2021-0026) in the keyword box and click “Search.” Next, sort the results by “Posted (Newer-Older),” choose the first notice listed, and click “Browse Comments.” If you do not have access to the internet, you may view the docket online by visiting Dockets Operations on the ground floor of the DOT West Building, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, between 9 a.m. and 5 p.m. ET Monday through Friday, except Federal holidays. To be sure someone is there to help you, please call (202) 366-9317 or (202) 366-9826 before visiting Dockets Operations.

B. Privacy Act
In accordance with 49 U.S.C. 31315(b)(6), DOT solicits comments from the public on the exemption request. DOT posts these comments, without edit, including any personal information the commenter provides, to www.regulations.gov. As described in the system of records notice DOT/ALL 14 (Federal Docket Management System), which can be reviewed at https://www.transportation.gov/individuals/privacy/privacy-act-system-records-notices, the comments are searchable by the name of the submitter.

II. Background
On February 27, 2024, FMCSA published a notice announcing its decision to renew exemptions for 13 individuals from the epilepsy and seizure disorders prohibition in 49 CFR 391.41(b)(8) to operate a CMV in interstate commerce and requested comments from the public (89 FR 14735). The public comment period ended on March 29, 2024, and no comments were received.
FMCSA has evaluated the eligibility of these applicants and determined that renewing these exemptions would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved by complying with § 391.41(b)(8).
The physical qualification standard for drivers regarding epilepsy found in § 391.41(b)(8) states that a person is physically qualified to drive a CMV if that person has no established medical history or clinical diagnosis of epilepsy or any other condition which is likely to cause the loss of consciousness or any loss of ability to control a CMV.
In addition to the regulations, FMCSA has published advisory criteria ^1 to assist medical examiners in determining whether drivers with certain medical conditions are qualified to operate a CMV in interstate commerce.
^1 These criteria may be found in Appendix A to Part 391—Medical Advisory Criteria, section H. Epilepsy: § 391.41(b)(8), paragraphs 3, 4, and 5, which is available on the internet at https://www.gpo.gov/fdsys/pkg/CFR-2015-title49-vol5/pdf/CFR-2015-title49-vol5-part391-appA.pdf.

III. Discussion of Comments
FMCSA received no comments in this proceeding.

IV. Conclusion
Based on its evaluation of the 13 renewal exemption applications and comments received, FMCSA announces its decision to exempt the following drivers from the epilepsy and seizure disorders prohibition in § 391.41(b)(8).
As of March 15, 2024, and in accordance with 49 U.S.C. 31136(e) and 31315(b), the following 13 individuals have satisfied the renewal conditions for obtaining an exemption from the epilepsy and seizure disorders prohibition in the FMCSRs for interstate CMV drivers (89 FR 14735):
Andrew Anzalone (MA)
Robert Drake (AZ)
Jeffrey Green (CA)
Dylan Hill (KS)
Alan Keil (HI)
Christian Mandahl (MT)
Richard Packer (ID)
Steven Paul (WI)
Richard Riley (IA)
Brian Adam Runk (PA)
Bradley Scruggs (CA)
Robert Spencer (FL)
Kip West (CO)
The drivers were included in docket number FMCSA-2015-0323, FMCSA-2017-0251, FMCSA-2018-0058, FMCSA-2020-0052, or FMCSA-2021-0026. Their exemptions were applicable as of March 15, 2024 and will expire on March 15, 2026.
In accordance with 49 U.S.C. 31315(b), each exemption will be valid for 2 years from the effective date unless revoked earlier by FMCSA. The exemption will be revoked if the following occurs: (1) the person fails to comply with the terms and conditions of the exemption; (2) the exemption has resulted in a lower level of safety than was maintained prior to being granted; or (3) continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315(b).
Larry W. Minor,

Associate Administrator for Policy.
DEPARTMENT OF TRANSPORTATION
Federal Motor Carrier Safety Administration
[Docket No. FMCSA-2024-0020]
Qualification of Drivers; Exemption Applications; Epilepsy and Seizure Disorders

AGENCY:
Federal Motor Carrier Safety Administration (FMCSA), Department of Transportation (DOT).

ACTION:
Notice of denials.

SUMMARY:
FMCSA announces its decision to deny applications from 14 individuals who requested an exemption from the Federal Motor Carrier Safety Regulations (FMCSRs) prohibiting persons with a clinical diagnosis of epilepsy or any other condition that is likely to cause a loss of consciousness or any loss of ability to operate a commercial motor vehicle (CMV) from operating CMVs in interstate commerce.

FOR FURTHER INFORMATION CONTACT:
Ms. Christine A. Hydock, Chief, Medical Programs Division, FMCSA, Department of Transportation, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, (202) 366-4001, fmcsamedical@dot.gov. Office hours are from 8:30 a.m. to 5 p.m. ET Monday through Friday, except Federal holidays. If you have questions regarding viewing material in the docket, contact Dockets Operations, (202) 366-9826.

SUPPLEMENTARY INFORMATION:

I. Public Participation

A. Comments
To view comments go to www.regulations.gov. Insert the docket number (FMCSA-2024-0020) in the keyword box, and click “Search.” Next, choose the only notice listed, and click “Browse Comments.” If you do not have access to the internet, you may view the docket online by visiting Dockets Operations on the ground floor of the DOT West Building, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, between 9 a.m. and 5 p.m. ET Monday through Friday, except Federal holidays. To be sure someone is there to help you, please call (202) 366-9317 or (202) 366-9826 before visiting Dockets Operations.

B. Privacy Act
In accordance with 49 U.S.C. 31315(b)(6), DOT solicits comments from the public on the exemption request. DOT posts these comments, without edit, including any personal information the commenter provides, to www.regulations.gov. As described in the system of records notice DOT/ALL 14 (Federal Docket Management System), which can be reviewed at https://www.transportation.gov/individuals/privacy/privacy-act-system-records-notices, the comments are searchable by the name of the submitter.

II. Background
FMCSA received applications from 14 individuals who requested an exemption from the FMCSRs prohibiting persons with a clinical diagnosis of epilepsy or any other condition that is likely to cause a loss of consciousness or any loss of ability to operate a CMV from operating CMVs in interstate commerce.
FMCSA has evaluated the eligibility of these applicants and concluded that granting these exemptions would not provide a level of safety that would be equivalent to, or greater than, the level of safety that would be obtained by complying with § 391.41(b)(8).

III. Basis for Exemption Determination
Under 49 U.S.C. 31136(e) and 31315(b), FMCSA may grant an exemption from the FMCSRs for no longer than a 5-year period if it finds such exemption would likely achieve a level of safety that is equivalent to, or greater than, the level that would be achieved absent such exemption. The statute also allows the Agency to renew exemptions at the end of the 5-year period. FMCSA grants medical exemptions from the FMCSRs for a 2-year period to align with the maximum duration of a driver's medical certification. The Agency's decision regarding these exemption applications is based on the eligibility criteria, the terms and conditions for Federal exemptions, and an individualized assessment of each applicant's medical information provided by the applicant.

IV. Conclusion
The Agency has determined that these applicants do not satisfy the eligibility criteria or meet the terms and conditions of the Federal exemption and granting these exemptions would not provide a level of safety that would be equivalent to, or greater than, the level of safety that would be obtained by complying with § 391.41(b)(8). Therefore, the 14 applicants in this notice have been denied exemptions from the physical qualification standards in § 391.41(b)(8).
Each applicant has, prior to this notice, received a letter of final disposition regarding his/her exemption request. Those decision letters fully outlined the basis for the denial and constitute final action by the Agency. This notice summarizes the Agency's recent denials as required under 49 U.S.C. 31315(b)(4) by periodically publishing names and reasons for denial.
The following 14 applicants do not meet the minimum time requirement for being seizure-free, either on or off anti-seizure medication:
Randall Bernath (MI)
Kyle Cattelona (NJ)
Dennis Gilles (IN)
Donald Gloy (AZ)
Jerome Hayes (OK)
Corey Mehrwerth (MN)
Brandon Murray (IN)
Geethma Perera (NY)
Connor Quinlan (TX)
Scott Summers (IL)
Hunter Thompson (PA)
Sarah Warner (CA)
Alex Weddle (OR)
Ammon Zimmerman (PA)
Larry W. Minor,

Associate Administrator for Policy.
DEPARTMENT OF THE TREASURY
Financial Crimes Enforcement Network
Agency Information Collection Activities; Proposed Renewal; Comment Request; Renewal Without Change of Anti-Money Laundering Programs for Certain Financial Institutions

AGENCY:
Financial Crimes Enforcement Network (FinCEN), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
As part of its continuing effort to reduce paperwork and respondent burden, FinCEN invites comments on the renewal, without change, of existing information collection requirements related to Bank Secrecy Act regulations that require banks lacking a Federal functional regulator, money services businesses, mutual funds, insurance companies, dealers in precious metals, precious stones, or jewels, operators of credit card systems, and loan or finance companies to develop and implement written anti-money laundering (AML) programs. This notice does not address requirements that may be imposed under the Anti-Money Laundering Act of 2020 (AML Act). Paperwork and respondent burden for those requirements will be addressed in a separate notice of proposed rulemaking (NPRM). This request for comments is made pursuant to the Paperwork Reduction Act of 1995 (PRA).

DATES:
Written comments are welcome and must be received on or before June 21, 2024.

ADDRESSES:
Comments may be submitted by any of the following methods:
• Federal E-rulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments. Refer to Docket Number FINCEN-2024-0010 and the specific Office of Management and Budget (OMB) control numbers 1506-0020, 1506-0030, and 1506-0035.
• Mail: Policy Division, Financial Crimes Enforcement Network, P.O. Box 39, Vienna, VA 22183. Refer to Docket Number FINCEN-2024-0010 and OMB control numbers 1506-0020, 1506-0030, and 1506-0035.
Please submit comments by one method only. Comments will be reviewed consistent with the PRA and applicable OMB regulations and guidance. All comments submitted in response to this notice will become a matter of public record. Therefore, you should submit only information that you wish to make publicly available.

FOR FURTHER INFORMATION CONTACT:
FinCEN's Regulatory Support Section at 1-800-767-2825 or electronically at frc@fincen.gov.

SUPPLEMENTARY INFORMATION:

I. Statutory and Regulatory Provisions
The legislative framework generally referred to as the Bank Secrecy Act (BSA) consists of the Currency and Foreign Transactions Reporting Act of 1970, as amended by the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001 (USA PATRIOT Act) ^1 and other legislation, including the AML Act. ^2 The BSA is codified at 12 U.S.C. 1829b and 1951-1960 and 31 U.S.C. 5311-5314 and 5316-5336, and notes thereto, with implementing regulations at 31 CFR Chapter X.
^1 USA PATRIOT Act, Pub. L. 107-56.
^2 The AML Act was enacted as Division F, sections 6001-6511, of the William M. (Mac) Thornberry National Defense Authorization Act for Fiscal Year 2021, Pub. L. 116-283, 134 Stat. 3388 (NDAA).
The BSA authorizes the Secretary of the Treasury (Secretary) to, inter alia, require financial institutions to keep records and file reports that are determined to have a high degree of usefulness in criminal, tax, or regulatory matters, risk assessments or proceedings, or in the conduct of intelligence or counter-intelligence activities to protect against terrorism, and to implement anti-money laundering/countering the financing of terrorism (AML/CFT) programs and compliance procedures. ^3 The authority of the Secretary to administer the BSA has been delegated to the Director of FinCEN. ^4
^3 Section 358 of the USA PATRIOT Act expanded the purpose of the BSA by including a reference to reports and records “that have a high degree of usefulness in intelligence or counterintelligence activities to protect against international terrorism.” See 12 U.S.C. 1829b(a). Section 6101 of the AML Act further expanded the purpose of the BSA to cover such matters as preventing money laundering, tracking illicit funds, assessing risk, and establishing appropriate frameworks for information sharing. See 31 U.S.C. 5311.
^4 Treasury Order 180-01 (Jan. 14, 2020).
31 U.S.C. 5318(h)(1) of the BSA mandates that financial institutions establish AML/CFT programs to guard against money laundering and the financing of terrorism. ^5 Such programs must include, at a minimum: (a) the development of internal policies, procedures, and controls, (b) the designation of a compliance officer, (c) an ongoing employee training program, and (d) an independent audit function to test programs. ^6 Pursuant to 31 U.S.C. 5318(h)(2), FinCEN issued regulations requiring banks lacking a Federal functional regulator (31 CFR 1020.210(b)), money services businesses (MSBs) (31 CFR 1022.210), mutual funds (31 CFR 1024.210), insurance companies (31 CFR 1025.210), dealers in precious metals, precious stones, or jewels (31 CFR 1027.210), operators of credit card systems (31 CFR 1028.210), and loan or finance companies (31 CFR 1029.210) to develop and implement written AML programs.
^5 The provision was added to the BSA through Section 352 of the USA PATRIOT Act. Section 6101(b) of the AML Act amended the provision to include explicit references to terrorism finance.
^6 The provision, which was added to the BSA through Section 352 of the USA PATRIOT Act, authorized FinCEN to prescribe minimum standards for AML programs and to exempt certain financial institutions from application of those standards. Section 6101(b) of the AML Act amended the provision to specify the factors that FinCEN must consider in prescribing minimum standards.
This notice renews the OMB control numbers associated with these specific AML program regulations. This notice is not renewing the OMB control numbers associated with other types of financial institutions' AML program regulatory requirements at this time for the reasons described below. This notice also does not address any changes to requirements governing AML programs that FinCEN may make pursuant to section 6101(b) of the AML Act; FinCEN will address the paperwork and respondent burden of such changes in a separate NPRM, when it proposes implementing rules.
On April 29, 2002, FinCEN issued an interim final rule to provide guidance to certain financial institutions concerning implementation of statutory requirements related to AML programs. The interim final rule provided that banks, savings associations, credit unions, brokers or dealers in securities, futures commission merchants, and casinos would be deemed to be in compliance if they established and maintained AML programs as required by existing FinCEN regulations, or their respective Federal regulator or self-regulatory organization (SRO). ^7
^7 See FinCEN, Anti-Money Laundering Programs for Financial Institutions Interim Final Rule, 67 FR 21110 (Apr. 29, 2022).
Of the types of financial institutions subject to the interim final rule, only casinos were already subject to AML program regulations issued by FinCEN. ^8 Federally insured depository institutions and credit unions were (and have continued to be) required by their respective federal functional regulators (as defined in section 509 of the Gramm-Leach-Bliley Act (12 U.S.C. 6809) to have AML programs. Brokers and dealers in securities and futures commission merchants were not then subject to an AML program requirement, and FinCEN stated in the interim final rule that it was appropriate to implement section 5318(h) of the BSA with respect to those types of financial institutions through their respective SROs. FinCEN therefore does not maintain OMB control numbers for the AML program regulatory requirements of banks, savings associations, credit unions, brokers or dealers in securities, or futures commission merchants. ^9
^8 See the Department of the Treasury, Amendments to the Bank Secrecy Act; Regulations Regarding Reporting and Recordkeeping Requirements by Casinos Final Rule, 58 FR 13538 (Mar. 12, 1993) and FinCEN, Amendments to the Bank Secrecy Act Regulations Regarding Reporting and Recordkeeping Requirements by Casinos Final Rule, 59 FR 61660 (Dec. 1, 1994).
^9 The casino AML program regulations are covered under FinCEN OMB control number 1506-0051, which is not scheduled to expire before October 2024. The renewal of that control number, therefore, will be addressed in a separate FinCEN notice released later this year. Since 1987, all federally insured depository institutions and credit unions have been required by their Federal regulators to have AML programs. The applicable Federal regulator maintains the OMB control number for the AML program regulatory requirements of depository institutions and credit unions as follows: (a) Office of Comptroller of the Currency (AML program regulations at 12 CFR 21.21—covered by OMB control number 1557-0180); (b) Federal Reserve Board (AML program regulations at 12 CFR 208.63—covered by OMB control number 7100-0310); (c) Federal Deposit Insurance Corporation (AML program regulations at 12 CFR 326.8—covered by OMB control number 3064-0087); and (d) National Credit Union Administration (AML program regulations at 12 CFR 748.2—covered by OMB control number 3133-0108). In the 2002 interim final rule, FinCEN also noted it was appropriate to implement section 5318(h)(1) of the BSA with respect to brokers or dealers in securities and futures commission merchants through their respective SROs, because the Securities and Exchange Commission (SEC) and the Commodity Futures Trade Commission (CFTC) and their SROs significantly accelerated the implementation of AML programs for their regulated financial institutions. Accordingly, 31 CFR 1023.210 and 31 CFR 1026.210 provided that brokers or dealers in securities, and futures commission merchants and introducing brokers in commodities, respectively, would be deemed to be in compliance with the requirements of section 5318(h)(1) of the BSA if they implement and maintain AML programs that, among other things, comply with rules, regulations, or requirements of their SROs governing such programs. The SEC's SRO for brokers and dealers is the Financial Industry Regulatory Authority (FINRA). The AML program requirements for brokers or dealers in securities is FINRA Rule 331. The CFTC's SRO for futures commission merchants is the National Futures Association (NFA). The AML program requirements for futures commission merchant and introducing brokers in commodities is NFA Rule 2-9(c). The SROs are not required to comply with the PRA. Therefore, there are no OMB control numbers for the AML program regulatory requirements of brokers or dealers in securities, futures commission merchants, and introducing brokers in commodities.
In implementing section 6101(b) of the AML Act, FinCEN intends to propose amendments to FinCEN's AML program regulations, including regulations for banks lacking a Federal functional regulator, MSBs, mutual funds, insurance companies, dealers in precious metals, precious stones, or jewels, operators of credit card systems, and loan or finance companies. FinCEN will assess the PRA burden of these amendments when it issues an NPRM; it does not do so here.

II. Paperwork Reduction Act of 1995 10
^{10} Paperwork Reduction Act of 1995, Pub. L. 104-13, 44 U.S.C. 3506(c)(2)(A).
Title: AML program requirements for banks lacking a Federal functional regulator (31 CFR 1020.210(b)), MSBs (31 CFR 1022.210), mutual funds (31 CFR 1024.210), insurance companies (31 CFR 1025.210), dealers in precious metals, precious stones, or jewels (31 CFR 1027.210), operators of credit card systems (31 CFR 1028.210), and loan or finance companies (31 CFR 1029.210).
OMB Control Numbers: 1506-0020, 1506-0030, and 1506-0035. ^{11}
^{11} The AML program regulatory requirements are currently covered under the following OMB control numbers: 1506-0020 (31 CFR 1022.210—AML programs for MSBs, 31 CFR 1024.210—AML programs for mutual funds, and 31 CFR 1028.210—AML programs for operators of credit card systems); 1506-0030 (31 CFR 1027.210—AML programs for dealers in precious metals, precious stones, or jewels); and 1506-0035 (31 CFR 1020.210(b)—AML program requirements for banks lacking a Federal functional regulator, 31 CFR 1025.210—AML programs for insurance companies, and 31 CFR 1029.210—AML programs for loan and finance companies). There is no OMB control number associated with 31 CFR 1030.210—AML programs for housing government sponsored enterprises (HGSEs), because the PRA does not apply to the collection of information by one federal agency (FinCEN) from another federal entity (the HGSEs).
Form Number: Not applicable.
Abstract: FinCEN is issuing this notice to renew the OMB control numbers for the AML program regulatory requirements for certain financial institutions.
Affected Public: Businesses or other for-profit institutions, and non-profit institutions.
Type of Review: Renewal without change of currently approved information collections.
Frequency: As required.
Estimated Number of Respondents: 283,043 financial institutions. ^{12}
^{12} Table 1 below breaks down the types of financial institutions covered by this notice.
Estimated Recordkeeping Burden: In Part 1 of this notice, FinCEN describes the breakdown of the estimated number of financial institution, by type. In Part 2, FinCEN proposes for review and comment a renewal of the calculation of the annual PRA burden that includes a scope and methodology similar to that used in the 2020 notice to renew the OMB control numbers for the AML programs of certain financial institutions. ^{13}
^{13} See FinCEN, Agency Information Collection Activities; Proposed Renewal; Comment Request; Renewal Without Change of Anti-Money Laundering Programs for Certain Financial Institutions , 85 FR 49418 (Aug. 13, 2020).

Part 1. Breakdown of Financial Institutions Covered by This Notice
The breakdown of financial institutions, by type, covered by this notice, is reflected in Table 1 below:
Table 1—Number of Covered Financial Institutions by Type
Type of financial institution | Number of financial institutions
Banks lacking a Federal functional regulator | ^a 600
Principal MSBs ^b | ^c 27,500
Providers or sellers of prepaid access | 2,605
Other types of principal MSBs | 24,895
Agent MSBs | ^d 229,161
Mutual funds | ^e 1,400
Insurance companies | ^f 4,678
Dealers in precious metals, stones, and jewels | ^g 6,700
Operators of credit card systems | ^h 4
Loan or finance companies | ^i 13,000
Total | 283,043
^a This estimate of active entities as of year-end 2023 incorporates data from both public and non-public sources, including: Call Reports; various state banking/financial institution regulators' websites and directories; the Federal Reserve Board of Governors' Master Account and Services database ( https://www.federalreserve.gov/paymentsystems/master-account-and-services-database-existing-access.htm ); and data from the OCIF (Oficina del Comisionado de Instituciones Financieras); and was derived in consultation with staff from the Internal Revenue Service's Small Business/Self-Employed Division.
^b The definition of MSB covers both principal MSBs and agents. Under 31 CFR 1022.210(d)(1)(iii), a person that is an MSB solely because it is an agent for another MSB and the MSB for which it serves as an agent (the principal MSB) may by agreement allocate between themselves responsibility for developing policies, procedures, and internal controls. However, neither the agent nor the principal MSB can avoid liability for failing to establish or maintain an effective AML program by pointing to a contract assigning the responsibility to the other party.
^c This value represents the number of uniquely identifiable principal MSBs with indicia of ongoing operations as of year-end 2023. The estimate is derived from FinCEN's publicly available MSB data available at https://www.fincen.gov/msb-registrant-search , accessed February 28, 2024.
^d In the absence of public comments in prior renewals of the OMB control number applicable to this regulatory requirement, FinCEN considers it reasonable to continue to rely upon its previous estimate that the number of agent MSBs remains approximately 229,161. This value was previously published in the 2020 notice to renew OMB control numbers 1506-0020, 1506-0030, and 1506-0035 (85 CFR 49420 (Aug. 13, 2020)).
^e This estimate of the number of active mutual funds as of year-end 2023 is based on Form N-CEN filings received by the U.S. Securities and Exchange Commission through January 20, 2023, as represented by data downloaded from SEC Open Data (https://www.sec.gov/dera/data/form-ncen-data-sets) , accessed February 29, 2024.
^f This estimate is based on data on entities with NAICS code 423940 (Jewelry, Watch, Precious Stone, and Precious Metal Merchant Wholesalers) published at year end 2023 in the 2021 Survey of U.S. Businesses (https://www.census.gov/data/datasets/2021/econ/susb/2021-susb.html) , accessed March 1, 2024.
^g This estimate includes 667 L&H insurers, 2,656 P&C insurers, and 1,355 health insurers licensed in the United States during 2022. From US Treasury “Annual Report on the Insurance Industry,” published September 2023 (https://home.treasury.gov/system/files/311/FIO%20Annual%20Report%202023%209292023.pdf) , accessed February 28, 2024.
^h This value is based on FinCEN review of active, U.S. based market participants at year end 2023.
^i This estimate is based on data on entities with NAICS codes 522292 (Real Estate Credit) and 522310 (Mortgage and Non-Mortgage Loan Brokers) published at year end 2023 in the 2021 Survey of U.S. Businesses (https://www.census.gov/data/datasets/2021/econ/susb/2021-susb.html), accessed March 1, 2024.
As noted above, 31 U.S.C. 5318(h) mandates that financial institutions establish AML/CFT programs to guard against money laundering and the financing of terrorism. Such programs must include, at a minimum: (a) the development of internal policies, procedures, and controls, (b) the designation of a compliance officer, (c) an ongoing employee training program, and (d) an independent audit function to test programs.
The AML program regulations for banks lacking a Federal functional regulator, MSBs, mutual funds, insurance companies, dealers in precious metals, precious stones, or jewels, operators of credit card systems, and loan or finance companies require these financial institutions to implement AML programs that are reasonably designed. The AML program must be in writing and must be commensurate with the financial institution's risk profile.
The AML program regulations for banks lacking a Federal functional regulator and mutual funds, for which the corresponding OMB control numbers are being renewed as part of this notice, include customer due diligence (CDD) requirements. In connection with a variety of initiatives FinCEN is undertaking to implement the AML Act, FinCEN intends to conduct, in the future, additional assessments of the PRA burden associated with BSA requirements, including CDD requirements for banks lacking a Federal functional regulator and mutual funds.

Part 2. Annual PRA Burden and Cost
The scope of the annual PRA burden and cost estimates of the AML program in this renewal is limited to: maintaining and updating the AML program documentation (Action A); storing the written AML program (Action B); producing a copy of the written AML program if requested by regulatory examiners or law enforcement (Action C); for banks lacking a Federal functional regulator and mutual funds, securing approval of the AML program by the board of directors or trustees (Action D); ^{14} and for providers or sellers of prepaid access, obtaining, verifying, and maintaining cardholder identifying information (Action E). ^{15}
^{14} The AML program regulations for banks lacking a Federal functional regulator and mutual funds are the only AML program regulations being renewed in this notice with a regulatory requirement to secure board of directors' or trustees' approval of the AML program. FinCEN recognizes, however, that the other financial institutions covered by this notice may also get their board of directors or trustees to approve their AML programs as a best practice.
^{15} The MSB AML program regulations have a unique requirement. Specifically, 31 CFR 1022.210(d)(1)(iv) provides that an MSB that is a provider or seller of prepaid access must establish procedures to verify the identity of a person who obtains prepaid access under a prepaid program and obtain identifying information concerning such a person, including name, date of birth, address, and identification number. Sellers of prepaid access must also establish procedures to verify the identity of a person who obtains prepaid access to funds that exceed $10,000 during any one day and obtain identifying information concerning such a person, including name, date of birth, address, and identification number.
For purposes of the estimate of the AML program annual PRA burden, FinCEN generally assumes:
(a) Agent MSBs agree to abide by, and in practice do abide by, the policies, procedures, and internal controls established by their principal MSBs.
(b) Principal MSBs establish minimum training and independent review standards for their agents. ^{16}
^{16} According to FIN-2016-G001, “ Guidance on Existing AML Program Rule Compliance Obligations for MSB Principals with Respect to Agent Monitoring,” (Mar. 11, 2016), MSB principals are required to develop and implement risk-based policies, procedures, and internal controls that ensure adequate ongoing monitoring of agent activity, as part of the principal's implementation of its AML program. Imposing a minimum level of general training and a minimum frequency of independent review allows principal MSBs to standardize in part these agent monitoring responsibilities. This document is available at https://www.fincen.gov/resources/statutes-regulations/guidance/guidance-existing-aml-program-rule-compliance-obligations.
(c) Required written AML programs are stored as electronic files. The estimated annual burden (five minutes per financial institution) represents the administrative burden involved in processing the storage of the written program.
(d) Producing the written AML program to regulatory or law enforcement agencies, upon their request, is performed electronically. FinCEN estimates the annual burden of producing the written program at five minutes per financial institution. The estimated annual burden represents the administrative burden involved in producing the program upon request once per year.
(e) The estimated number of prepaid access arrangements established annually remains at approximately 2.6 million. The collection and storage of cardholder identification information is automated. ^{17}
^{17} In the absence of public comments in all prior renewals of the OMB control number applicable to this regulatory requirement, FinCEN considers it reasonable to continue to rely upon its previous estimate that the number of prepaid arrangements established annually is 2.6 million.
The estimated burden associated with each portion of the annual PRA estimate is as follows:
Table 2—Burden Associated With Each Action of the Annual PRA Estimate
Action | Instances per year | Time per instance | Type of financial institution | Number of financial institutions ^a | Total hourly burden
A. Maintaining and updating the written AML program | 1 per financial institution | 1 hour | All except agent MSBs | 53,882 | 53,882
B. Storing the written AML program | 1 per financial institution | 5 minutes | All | 283,043 | 23,587
C. Producing the AML program upon request | 1 per financial institution | 5 minutes | All | 283,043 | 23,587
D. Board of directors/trustees approval of the AML program | 1 per financial institution | 1 hour | Banks lacking a Federal functional regulator and mutual funds | 2,000 | 2,000
E. Obtaining, verifying, and storing cardholder identifying information | 2.6 million (once per card) | 2 minutes | Providers or sellers of prepaid access | 2,605 | 86,667
| Total Hourly Burden | | | | | 189,723
^a As set out in Table 1 above.
FinCEN's estimate for the total hourly annual PRA burden is 189,723 hours.
FinCEN identified four roles and corresponding staff positions involved in maintaining an AML program to estimate the hourly costs associated with the burden hour estimates calculated in this part. Those are: (i) general approval (board of directors/trustees approval of the AML program); (ii) general supervision (providing process management); (iii) direct supervision (reviewing operational-level work and cross-checking all or a sample of the work product against their supporting documentation); and (iv) clerical work (engaging in research and administrative review and filing and producing the AML program on request).
FinCEN calculated the fully loaded hourly wage for each of these four roles by taking the median wage as estimated by the U.S. Bureau of Labor Statistics (BLS), and computing an additional benefits cost as follows: ^{18}
^{18} BLS, Occupational Employment Statistics-National (May 2022), available at https://www.bls.gov/oes/tables.htm. The most recent data from the BLS corresponds to May 2022. The ratio between benefits and wages for private industry workers is $12.77 (hourly benefits)/$30.33 (hourly wages) = 0.42, as of December 2023. The benefit factor is 1 plus the benefit/wages ratio, or 1.42. See BLS, Employee Costs for Employee Compensation (Dec. 2023), available at ECEC Home: U.S. Bureau of Labor Statistics ( bls.gov ).
Table 3—Total Hourly Remuneration (Fully Loaded Hourly Wage) per Role and BLS Job Position
Role | BLS-code | BLS-name | Median hourly wage | Benefit factor | Fully loaded hourly wage
Board of directors/trustees | 11-1010 | Chief Executive ^a | $91.12 | 1.42 | ^b $129.39
General supervision | 11-3031 | Financial Manager | 67.21 | 1.42 | 95.44
Direct supervision | 13-1041 | Compliance Officer | 34.47 | 1.42 | 48.95
Clerical work (research, review, and filing and producing the program upon request) | 43-3099 | Financial Clerk | 22.66 | 1.42 | 32.18
^a FinCEN recognizes that a board of directors/trustees would be on a different pay scale than a chief executive officer, however, chief executive officer is the highest paid category in the BLS Occupational Employment Statistics. For that reason, FinCEN is conservatively estimating the highest wage rate available for its cost analysis.
^b $129.39 rounded to $129.00.
FinCEN estimates that, in general and on average, ^{19} each role would spend different amounts of time on each portion of the annual PRA burden, as follows:
^{19} By “in general,” FinCEN is speaking without regard to outliers ( e.g., financial institutions with AML programs with complexities that are uncommonly higher or lower than those of the population at large). By “on average,” FinCEN means the mean of the distribution of each subset of the population.
For Action A set out in Table 2 above, annually maintaining and updating the AML program documentation, the cost of each hour of burden is estimated to be $49.00, as shown in Table 4 below. Action A applies to all financial institutions covered by this notice, except agent MSBs.
Table 4—Weighted Average Hourly Cost of Maintaining and Updating AML Program Documentation
General supervision | %time | Hourly cost | Direct supervision | %time | Hourly cost | Clerical work (case review) | %time | Hourly cost | Weighted average hourly cost
10 | $9.54 | 60 | $29.37 | 30 | $9.65 | ^a $49.00
^a $48.57 rounded to $49.00.
For Actions B, C, and E, set out in Table 2 above, the cost of each hour of burden is estimated to be $34.00, as shown in Table 5 below:
• Action B—storing the AML program. (Applies to all financial institutions covered by this notice).
• Action C—producing of the AML program upon request. (Applies to all financial institutions covered by this notice).
• Action E—obtaining, verifying, and storing prepaid access customer identifying information. (Only applies to providers and sellers of prepaid access).
Table 5—Weighted Average Hourly Cost of Storing and Producing AML Program Documentation Upon Request, and Obtaining, Verifying, and Storing Prepaid Access Customer Identifying Information
General supervision | %time | Hourly cost | Direct supervision | %time | Hourly cost | Clerical work (recordkeeping) | %time | Hourly cost | Weighted average hourly cost
1 | $0.95 | 9 | $4.41 | 90 | $28.96 | ^a $34.00
^a $34.32 rounded to $34.00.
For Action D set out in Table 2 above, approval of the AML program by the board of directors or trustees of a bank lacking a Federal functional regulator or mutual fund, the cost of each hour of burden would be $129.00, as shown in Table 3 above. Action D only applies to banks lacking a Federal functional regulator and mutual funds. ^{20}
^{20} See supra note 14.
The total cost of the annual PRA burden would be $7,448,812, as reflected in Table 6 below:
Table 6—Total Cost of Annual PRA Burden
Action | Total burden in hours | (Table 2) | Hourly cost | ($) | Source | Total cost
A. Maintaining and updating the written AML program | 53,882 | 49 | Table 4 | 2,640,218
B. Storing the written AML program | 23,587 | 34 | Table 5 | 801,958
C. Producing the written AML program upon request | 23,587 | 34 | Table 5 | 801,958
D. Board of directors/trustees approval of the AML program | 2,000 | 129 | Table 3 | 258,000
E. Obtaining, verifying, and storing prepaid access customer identifying information | 86,667 | 34 | Table 5 | 2,946,678
Total Cost | | | | 7,448,812
Estimated Recordkeeping Burden: Due to the different scope and criteria used for the estimate, the average estimated annual PRA burden, measured in hours per respondent, is: (Action A) one hour per principal financial institution, for maintaining and updating the AML program; (Action B) five minutes per financial institution, for storing the written AML program; (Action C) five minutes per financial institution, for producing a copy of the AML program if requested by regulatory examiners or law enforcement; (Action D) one hour per bank lacking a Federal functional regulator or mutual fund, for securing approval of the AML program by the board of directors or trustees; and (Action E) two minutes per provider or seller of prepaid access, for obtaining, verifying, and maintaining customer identifying information.
Estimated Number of Respondents: 283,043, as described in Table 1.
Estimated Total Annual Responses: Due to unique AML program requirements for banks lacking a Federal functional regulator, mutual funds, and MSBs, each of the five actions listed below impact a different estimated number of financial institutions as follows:
(1) 53,882 (all financial institutions except agent MSBs) for the maintaining the written AML program (Action A);
(2) 283,043 (total number of financial institutions) for storing the written AML program (Action B);
(3) 283,043 (total number of financial institutions) for producing a copy of the written AML program if requested by regulatory examiners or law enforcement (Action C);
(4) 2,000 (number of banks lacking a Federal functional regulator and mutual funds) for securing approval of an AML program by the board of directors or trustees (Action D); and
(5) 2,600,000 (number of new prepaid access arrangements added per year) for providers and sellers of prepaid access for obtaining, verifying, and maintaining customer identifying information (Action E).
Estimated Total Annual Recordkeeping Burden: The estimated total annual PRA burden is 189,723 hours, as described in Table 2.
Estimated Total Annual Recordkeeping Cost: The cost of the estimated total annual PRA is $7,448,812, as described in Table 6.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a valid OMB control number. Records required to be retained under the BSA must be retained for five years.
Request for Comments: Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Andrea M. Gacki,

Director, Financial Crimes Enforcement Network.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Digital Asset Proceeds From Broker Transactions

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Internal Revenue Service, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on continuing information collections, as required by the Paperwork Reduction Act of 1995. The IRS is soliciting comments concerning information collection requirements related to digital asset proceeds from broker transactions.

DATES:
Written comments should be received on or before June 21, 2024 to be assured of consideration.

ADDRESSES:
Direct all written comments to Andres Garcia, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW, Washington, DC 20224, or by email to pra.comments@irs.gov. Include “Digital Asset Proceeds From Broker Transactions” in the subject line of the message.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of the form should be directed to Andres Garcia, (202) 317-4542, or at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW, Washington, DC 20224, or through the internet, at pra.comments@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Digital Asset Proceeds From Broker Transactions.
OMB Number: 1545-NEW
Form Number: 1099-DA.
Abstract: Form 1099-DA is used by brokers to report proceeds from (and in some cases, basis for) digital asset dispositions to taxpayers and to the IRS (Internal Revenue Code section 6045(a)). Taxpayers may be required to recognize gain from these dispositions of digital assets. Reporting is also required when brokers know or have reason to know that a corporation in which a taxpayer owns digital assets, that is also stock, has had a reportable change in control or capital structure. Taxpayers may be required to recognize gain from the receipt of cash, services, digital assets, or other property that was exchanged for a digital asset that is also the corporation's stock.
Current Actions: This is a new collection.
Type of Review: New collection.
Affected Public: Business or other for-profit organizations, individuals or households, and not-for-profit institutions.
Estimated Number of Respondents: 5,050.
Estimated Number of Responses per Respondents: 2,833.
Estimated Time per Response: 0.15 hours.
Estimated Total Annual Burden Hours: 2,146,250 hours.
The following paragraph applies to all the collections of information covered by this notice.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained if their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Request for Comments: Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval. All comments will become a matter of public record. Comments are invited on: (a) whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
Approved: April 16, 2024.
Andres Garcia Leon,

Supervisory Tax Analyst.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Internal Revenue Service Advisory Council (IRSAC); Nominations

AGENCY:
Internal Revenue Service, Department of the Treasury.

ACTION:
Request for nominations.

SUMMARY:
The Internal Revenue Service (IRS) is accepting applications for the 2025 Internal Revenue Service Advisory Council (IRSAC), including nominees for a new subcommittee focused on fairness issues. IRSAC members are drawn from substantially diverse backgrounds representing a cross-section of the taxpaying public with substantial, disparate experience in: tax preparation for individuals, small businesses and large, multi-national corporations; tax-exempt and government entities; information reporting; taxpayer or consumer advocacy; fairness in tax administration; and civil rights and community engagement. Nominations of qualified individuals may come from individuals or organizations.

DATES:
Applications must be received on or before May 31, 2024.

ADDRESSES:
Applications should be submitted to IRS National Public Liaison via email to publicliaison@irs.gov or electronic fax to 855-811-8021. Applications are available on the IRS website at https://www.irs.gov/irsac.

FOR FURTHER INFORMATION CONTACT:
Anna Millikan at 202-317-6564 (not a toll-free number) or send an email to publicliaison@irs.gov.

SUPPLEMENTARY INFORMATION:
The IRSAC serves as an advisory body to the IRS commissioner and agency leadership. The group is organized under the Federal Advisory Committee Act, 5 U.S.C. 10, and includes volunteer members with a diverse set of interests in tax issues. IRSAC provides an organized forum for discussion of relevant tax administration issues between IRS officials and representatives of the public.
The advisory council: proposes enhancements to IRS operations; recommends administrative and policy changes to improve taxpayer services, fairness in tax administration and compliance; discusses issues and recommends solutions relevant to information reporting; addresses matters concerning tax exempt and government entities; and conveys the public's perception of professional standards and best practices for tax professionals.
In addition, this January IRSAC will launch its first-ever Subcommittee on Fairness in Tax Administration. This subcommittee will review and issue specific recommendations related to fairness in tax administration for low-income communities, communities of color and other historically underserved populations. The subcommittee will focus on how the IRS can address tax administration disparities that may keep some communities from fully benefiting from and contributing to the nation's economic growth and prosperity. Potential focus areas will include disparities in audit selection, tax credit uptake and financial access, scam prevention, data analysis as well as outreach and education strategies among others.
The new IRSAC Subcommittee on Fairness in Tax Administration will closely coordinate with the Treasury Advisory Committee on Racial Equity (TACRE) which previously provided recommendations to Treasury and IRS on addressing racial disparities in audit selection.
IRSAC members are appointed to three-year terms by the IRS commissioner and submit a report to IRS leadership annually at a public meeting. Applications are currently being accepted for appointments that will begin in January 2025.
Nominations of qualified individuals may come from individuals or organizations. IRSAC members are drawn from diverse backgrounds representing a cross-section of the taxpaying public with experience in: tax preparation for individuals, small businesses and large multi-national corporations; tax exempt and government entities; information reporting; taxpayer or consumer advocacy; fairness in tax administration; and civil rights and community engagement.
Applications should document the proposed member's qualifications. Applicants must be in good standing with their own tax obligations and demonstrate high professional and ethical standards. In accordance with the Department of Treasury Directive 21-03, all applicants must apply and pass a tax compliance and practitioner check. For those applicants deemed “best qualified,” FBI fingerprint checks are required.
The IRSAC is also seeking applicants with specific knowledge and background in the following areas:
Individual Wage & Investment—Knowledge of tax law application/tax preparation experience, income tax issues related to refundable credits, including tax credit uptake, experience educating on tax issues and topics (especially outreach to and engagement with underserved communities), with multi-lingual taxpayer communications, with prevention of tax-related scams and schemes, with taxpayer advocacy or contact center operations, with civil rights, marketing/applying industry benchmarks to operations, with tax software industry, deductions, withholding, or other information for tax purposes; familiarity with IRS tax forms and publications; familiarity with IRS's online applications ( e.g., Online Account, EITC Assistant, etc.); background with knowledge of technology innovations in public and private customer service sectors; experience in application and use of qualitative and quantitative data for use in improving taxpayer/customer experience, including for addressing audit disparities.
Information Reporting—Knowledge of banking industry and/or possess broker-dealer background with experience filing information returns; knowledge of payroll industry; experience with retirement withholding and reporting.
Large Business & International—Experience as a certified public accountant or tax attorney working in or for a large, sophisticated multinational organization; experience working in-house at a major firm dealing with tax planning for complex organizations including large multinational corporations and large partnerships.
Small Business & Self-Employed—Knowledge or experience with digital assets and/or peer to peer payment applications; knowledge of passthrough entities and/or fiduciary tax; experience with online or digital businesses, audit representation and/or educating on tax issues and topics; knowledge base and/or background related to Collection activities and balance due case resolution options; experience as a practitioner in underserved communities ( e.g., where English is not the first language); experience with digitalization systems, tools, or processes; marketing experience to help with ideas for increasing uptake of digital tools offered by the IRS; knowledge of IRS modernization projects; understanding of the Inflation Reduction Act and how it will impact the IRS in the coming years; experience developing and/or delivering virtual presentations.
Tax Exempt & Government Entities—Experience with Indian tribal governments; experience in federal, state, or local governments; experience in tax-exempt bonds and/or employee plans.
The IRSAC holds approximately four, two-day working sessions and at least one public meeting per year. Members are not paid for their services; any travel expenses are reimbursed within federal government guidelines.
All applicants will be sent an acknowledgment of receipt.
Equal opportunity practices will be followed for all appointments to the IRSAC in accordance with the Department of Treasury and IRS policies. The IRS has special interest in assuring that women and men, members of all races and national origins, and individuals with disabilities have an opportunity to serve on advisory committees. Therefore, the IRS extends particular encouragement to nominations from such appropriately qualified candidates.
Dated: April 16, 2024.
John A. Lipold,

Designated Federal Officer, Office of National Public Liaison, Internal Revenue Service.
DEPARTMENT OF THE TREASURY
Department of the Treasury.
Privacy Act of 1974; System of Records

ACTION:
Notice of modified systems of records.

SUMMARY:
In accordance with the Privacy Act of 1974, the Department of the Treasury (“Treasury” or the “Department”), proposes to modify 10 of its systems of records notices below by adding one new routine use to all 10 systems.

DATES:
Submit comments on or before May 22, 2024. The new routine use will be applicable on May 22, 2024 unless Treasury receives comments and determines that changes to the system of records notice are necessary.

ADDRESSES:
Comments may be submitted to the Federal eRulemaking Portal electronically at https://www.regulations.gov identified by docket number TREAS-DO-2024-0007. Comments can also be sent to the Deputy Assistant Secretary for Privacy, Transparency, and Records, Department of the Treasury, 1500 Pennsylvania Avenue NW, Washington, DC 20220, Attention: Modified Privacy Act Systems of Records. All comments received, including attachments and other supporting documents, are part of the public record and subject to public disclosure. All comments received will be posted without change to http://www.regulations.gov, including any personal information provided. You should submit only information that you wish to make publicly available.

FOR FURTHER INFORMATION CONTACT:
For general questions and for privacy issues please contact: Ryan Law, Deputy Assistant Secretary for Privacy, Transparency, and Records (202-622-5710), Department of the Treasury, 1500 Pennsylvania Avenue NW, Washington, DC 20220.

SUPPLEMENTARY INFORMATION:
In accordance with the Privacy Act of 1974, 5 U.S.C. 552a, the Department of the Treasury proposes to modify the Treasury systems of records notices, as identified below, to include one new routine use permitting disclosure to the United States Department of Justice for purposes of the National Law Enforcement Accountability Database (the “NLEAD”). On May 25, 2022, the President issued Executive Order 14074, Advancing Effective, Accountable Policing and Criminal Justice Practices to Enhance Public Trust and Public Safety (the “Executive Order”). Section 5 of the Executive Order directs the Attorney General to establish the National Law Enforcement Accountability Database as “a centralized repository of official records documenting instances of law enforcement officer misconduct as well as commendations and awards.” As required by the Executive Order, in developing the NLEAD, the Department of Justice regularly consulted with other federal law enforcement agencies, at both leadership and staff levels. This new routine use authorizes disclosure to the Department of Justice pursuant to the Executive Order.
Treasury has provided a report of this system of records to the House Committee on Oversight and Accountability, the Senate Committee on Homeland Security and Governmental Affairs, and OMB, pursuant to 5 U.S.C. 552a(r) and OMB Circular A-108, “Federal Agency Responsibilities for Review, Reporting, and Publication under the Privacy Act,” dated December 23, 2016.
Ryan Law,

Deputy Assistant Secretary for Privacy, Transparency, and Records.
The NLEAD routine use is being added to the following Treasury systems of records notices. The addition of this new routine use disclosure to each of the SORNs referenced below is consistent with the purpose(s) for which the information was collected because these SORNs already include a routine use for making similar disclosures directly to federal agencies upon request.
System name and number (security classification) | System location and system manager(S) | Routine use added will be numbered | History
DO .190, OIG Investigations Management Information System (Unclassified) | Departmental Offices—OIG, Assistant Inspector General for Investigations and Counsel to the Inspector General. Assistant Inspector General for Investigations | (11) | 81 FR 78298 (Nov. 7, 2016).
DO .301, TIGTA General Personnel and Payroll (Unclassified) | Departmental Offices—TIGTA (National Headquarter, field offices listed in Appendices A, B and C, Bureau of the Fiscal Service, and Transaction Processing Center, U.S. Department of Agriculture, National Finance Center.) General Personnel Records—Deputy Inspector General for Mission Support/Chief Financial Officer. Time-reporting records: (1) For Office of Audit employees—Deputy Inspector General for Audit; (2) For Office of Chief Counsel employees—Chief Counsel; (3) For Office of Investigations employees—Deputy Inspector General for Investigations; (4) For Office of Inspections and Evaluations employees—Deputy Inspector General for Inspections and Evaluations; (5) For Office of Information Technology employees—Chief Information Officer; (6) For Office of Mission Support/Chief Financial Officer employees—Deputy Inspector General for Mission Support/Chief Financial Officer; and (7) For Inspector General staff employees—Principal Deputy Inspector General | (25) | 87 FR 68797 (Nov. 16, 2022).
DO .307, TIGTA Employee Relations Matters, Appeals, Grievances, and Complaint Files (Unclassified) | Departmental Offices—TIGTA (Office of Mission Support/Chief Financial Officer) Deputy Inspector General for Mission Support/Chief Financial Officer | (14) | 87 FR 68797 (Nov. 16, 2022).
DO .311, TIGTA Office of Investigation Files (Unclassified) | Departmental Offices—TIGTA (Office of Investigation) Deputy Inspector General for Investigations, Office of Investigations | (15) | 87 FR 68797 (Nov. 16, 2022).
IRS 36.001, Appeals, Grievances and Complaint Records (Unclassified) | IRS (National Office, field, computer center, and campus offices). Chief, Office of Equal Employment and Diversity and Human Capital Officer | (12) | 80 FR 54063 (Sept. 8, 2015).
IRS 36.003, General Personnel and Payroll Records (unclassified) | IRS (Current employee personnel records: National Office, field, computing center and campus offices. Current employee payroll records: Transactional Processing Center (TPC), U.S. Department of Agriculture, National Finance Center. Former employee personnel records: The National Archives and Records Administration, National Personnel Records Center) Chief, Human Capital Office | (21) | 80 FR 54063 (Sept. 8, 2015).
| IRS 90.002, Chief Counsel Litigation and Advice (Civil) Records (Unclassified) | IRS (Office of the Chief Counsel; Offices of the Associate Chief Counsel (Corporate), (Financial Institutions & Products), (General Legal Services), (Income Tax & Accounting), (International), (Passthroughs & Special Industries), and (Procedure & Administration); Office of the Division Counsel/Associate Chief Counsel (Tax Exempt & Government Entities); Offices of the Division Counsel (Large Business & International), (Small Business/Self Employed) and (Wage & Investment); Office of the Special Counsel to the National Taxpayer Advocate; Office of the Special Counsel to the Office of Professional Responsibility; and Area Counsel offices) The Chief Counsel, Special Counsel to the National Taxpayer Advocate, Special Counsel to the Office of Professional Responsibility, each Associate Chief Counsel, and each Division Counsel is the system manager of the system in that office | (23) | 80 FR 54063 (Sept. 8, 2015).
IRS 90.003, Chief Counsel Litigation and Advice (Criminal) Records (Unclassified) | IRS (Office of the Chief Counsel; Office of the Division Counsel/Associate Chief Counsel (Criminal Tax); and Area Counsel (Criminal Tax) offices) The Division Counsel/Associate Chief Counsel (Criminal Tax) is the system manager | (16) | 80 FR 54063 (Sept. 8, 2015).
Mint .012, Union Agency Negotiated Grievances; Adverse Personnel Actions; Discrimination Complaints, Complaints and Actions before Arbitrators, Administrative Tribunals and Courts (Unclassified) | U.S. Mint (United States Mint's Workforce Solutions Department, its Office of Chief Counsel, and any other office within the United States Mint where an action arose) (1) Chief, Human Resources Division, (2) Plant Manager(s), and (3) Officer-in-Charge | (9) | 78 FR 1307 (Jan. 8, 2013).
BEP .021, Investigative Files (Unclassified) | BEP (Office of Security, Bureau of Engraving and Printing, Eastern Currency Facility and Security Division, Bureau of Engraving and Printing, Western Currency Facility), Chief, Office of Security, Bureau of Engraving and Printing, Eastern Currency Facility, and Security Officer, Security Division, Bureau of Engraving and Printing, Western Currency Facility. | (10) | 78 FR 22604 (Apr. 16, 2013).
All of the Treasury's system of records referenced above are being modified to add the NLEAD routine use is as follows:

ROUTINE USES OF RECORDS MAINTAINED IN THE SYSTEM, INCLUDING CATEGORIES OF USERS AND THE PURPOSES OF SUCH USES:
( ) To disclose, to the extent permitted by law, official records documenting former or current Treasury law enforcement officers' commendations, awards, and misconduct to the Department of Justice (DOJ) as required pursuant to Executive Order 14074, Advancing Effective, Accountable Policing and Criminal Justice Practices to Enhance Public Trust and Public Safety, to provide a central source for federal, state, local, and tribal agencies to search when making suitability determinations during the recruitment, investigation, hiring, promotion, and retention of law enforcement personnel.
The new routine use number in each SORN is indicated in the second column of the chart above.
The remainder of Treasury's systems of records notices referenced above remain unchanged except for the addition of the NLEAD routine use identified above.
DEPARTMENT OF VETERANS AFFAIRS
[OMB Control No. 2900-0715]
Agency Information Collection Activity Under OMB Review: Servicer's Staff Appraisal Reviewer (SAR) Application

AGENCY:
Veterans Benefits Administration, Department of Veterans Affairs.

ACTION:
Notice.

SUMMARY:
In compliance with the Paperwork Reduction Act (PRA) of 1995, this notice announces that the Loan Guaranty Service, Department of Veterans Affairs, will submit the collection of information abstracted below to the Office of Management and Budget (OMB) for review and comment. The PRA submission describes the nature of the information collection and its expected cost and burden and it includes the actual data collection instrument.

DATES:
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice by clicking on the following link www.reginfo.gov/public/do/PRAMain, select ”Currently under 30-day Review—Open for Public Comments” then search the list for the information collection by Title or “OMB Control No. 2900-0715”.

FOR FURTHER INFORMATION CONTACT:
Maribel Aponte, Office of Enterprise and Integration, Data Governance Analytics (008), 810 Vermont Ave. NW, Washington, DC 20420, (202) 266-4688 or email maribel.aponte@va.gov. Please refer to “OMB Control No. 2900-0715” in any correspondence.

SUPPLEMENTARY INFORMATION:
Under the PRA of 1995, Federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. This request for comment is being made pursuant to section 3506(c)(2)(A) of the PRA.
Authority: Public Law 104-13; 44 U.S.C. 3501-3521.
Title: VA FORM 26-0829, Servicer's Staff Appraisal Reviewer (SAR) Application.
OMB Control Number: 2900-0715.
Type of Review: Revision of a currently approved collection.
Abstract: Title 38 U.S.C. 3702(d) authorizes the Department of Veterans Affairs (VA) to establish standards for servicers making automatically guaranteed loans and 38 U.S.C. 3731(f) authorizes VA to establish, in regulation, standards and procedures to authorize a lender to determine the reasonable value of property. VA has implemented this authority through its Servicer Appraisal Processing Program (SAPP), codified in 38 CFR 36.4348.
An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The Federal Register Notice with a 60-day comment period soliciting comments on this collection of information was published at 89 FR 9289, on February 9, 2024, page 9289.
Affected Public: Individuals (employees of lenders making applications).
Estimated Annual Burden: 0.8 hours.
Estimated Average Burden per Respondent: 5 minutes.
Frequency of Response: On occasion.
Estimated Number of Respondents: 10 per year.
By direction of the Secretary.
Maribel Aponte,

VA PRA Clearance Officer, Office of Enterprise and Integration, Data Governance Analytics, Department of Veterans Affairs.
89
78
Monday, April 22, 2024
Rules and Regulations
Part II
Environmental Protection Agency
40 CFR Parts 86, 1036, 1037, et al.

Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3; Final Rule
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 86, 1036, 1037, 1039, 1054, and 1065
[EPA-HQ-OAR-2022-0985; FRL-8952-02-OAR]
RIN 2060-AV50
Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
The Environmental Protection Agency (EPA) is promulgating new greenhouse gas (GHG) emissions standards for model year (MY) 2032 and later heavy-duty highway vehicles that phase in starting as early MY 2027 for certain vehicle categories. The phase in revises certain MY 2027 GHG standards that were established previously under EPA's Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 2 rule (“HD GHG Phase 2”). This document also updates discrete elements of the Averaging Banking and Trading program, including providing additional flexibilities for manufacturers to support the implementation of the Phase 3 program balanced by limiting the availability of certain advanced technology credits initially established under the HD GHG Phase 2 rule. EPA is also adding warranty requirements for batteries and other components of zero-emission vehicles and requiring customer-facing battery state-of-health monitors for plug-in hybrid and battery electric vehicles. In this action, we are also finalizing additional revisions, including clarifying and editorial amendments to certain highway heavy-duty vehicle provisions and certain test procedures for heavy-duty engines.

DATES:
This final rule is effective on June 21, 2024. The incorporation by reference of certain material listed in this rule is approved by the Director of the Federal Register beginning June 21, 2024. The incorporation by reference of certain other material listed in this rule was previously approved by the Director of the Federal Register as of March 27, 2023.

ADDRESSES:
Docket: EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2022-0985. Publicly available docket materials are available either electronically at www.regulations.gov or in hard copy at Air and Radiation Docket and Information Center, EPA Docket Center, EPA/DC, EPA WJC West Building, 1301 Constitution Ave. NW, Room 3334, Washington, DC. For further information on EPA Docket Center services and the current status, please visit us online at www.epa.gov/dockets .
Public Participation: Docket: All documents in the docket are listed on the www.regulations.gov website. Although listed in the index, some information is not publicly available, e.g., confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form through the EPA Docket Center at the location listed in the ADDRESSES section of this document.

FOR FURTHER INFORMATION CONTACT:
Brian Nelson, Assessment and Standards Division, Office of Transportation and Air Quality, Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 48105; telephone number: (734) 214-4278; email address: nelson.brian@epa.gov .

SUPPLEMENTARY INFORMATION:

Does this action apply to me?
This action relates to companies that manufacture, sell, or import into the United States new heavy-duty highway vehicles and engines. This action also relates to state and local governments. Potentially affected categories and entities include the following:
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities potentially affected by this action. This table lists the types of entities that EPA is now aware could potentially be affected by this action. Other types of entities not listed in the table could also be affected. To determine whether your entity is regulated by this action, you should carefully examine the applicability criteria found in 40 CFR parts 86, 1036, 1037, 1039, 1054, and 1065. ^1 If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section.
^1 See 40 CFR 1036.1 through 1036.15 and 1037.1 through 1037.15.

What action is the agency taking?
The Environmental Protection Agency (EPA) is promulgating new GHG standards for model year (MY) 2032 and later heavy-duty highway vehicles that phase in starting as early MY 2027 for certain vehicle categories. The phase in revises certain MY 2027 GHG standards that were established previously under EPA's Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 2 rule. We believe these “Phase 3” standards are appropriate and feasible considering lead time, costs, and other factors. EPA also finds that it is appropriate (1) to limit the availability of certain advanced technology credits initially established under the HD GHG Phase 2 rule, and (2) to include additional flexibilities for manufacturers in applying credits from these incentives in the early model years of this Phase 3 program. EPA is also adding warranty requirements for batteries and other components of zero-emission vehicles and requiring customer-facing battery state-of-health monitors for plug-in hybrid and battery electric vehicles. We are also finalizing revisions and clarifying and editorial amendments to certain highway heavy-duty vehicle provisions of 40 CFR part 1037 and certain test procedures for heavy-duty engines in 40 CFR parts 1036 and 1065. We also note that EPA included in this action's notice of proposed rulemaking (hereafter referred to as the “HD GHG Phase 3 NPRM”) a proposal to revise its regulations addressing preemption of state regulation of new locomotives and new engines used in locomotives; those revisions were finalized in a separate action on November 8, 2023. 2 3
^2 Notice of Proposed Rulemaking for Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3. 88 FR 25926, April 27, 2023.
^3 Final Rulemaking for Locomotives and Locomotive Engines; Preemption of State and Local Regulations. 88 FR 77004, November 8, 2023.

What is the agency's authority for taking this action?
Clean Air Act (CAA) section 202(a), 42 U.S.C. 7521(a), requires that EPA establish emission standards for air pollutants from new motor vehicles or new motor vehicle engines, which, in the Administrator's judgment, cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. The Administrator has found that GHG emissions from highway heavy-duty vehicles and engines cause or contribute to air pollution that may endanger public health or welfare. Therefore, the Administrator is exercising his authority under CAA section 202(a)(1)-(2) to establish standards for GHG emissions from highway heavy-duty vehicles. See section I.D of this preamble for more information on the agency's authority for this action.

Did EPA conduct a peer review before issuing this action?
This regulatory action is supported by influential scientific information. EPA, therefore, conducted peer review in accordance with the Office of Management and Budget's (OMB) Final Information Quality Bulletin for Peer Review. First, we conducted a peer review of the underlying data and algorithms in MOVES4 that served as the basis for MOVES4.R3 used to estimate the emissions impacts of the final standards. In addition, we conducted a peer review of the Heavy-Duty Technology Resource Use Case Scenario (HD TRUCS) tool used to analyze HD vehicle energy usage and associated component costs. We also conducted a peer review of a Heavy-Duty Vehicle Industry Characterization, Technology Assessment, and Costing Report developed by FEV Consulting. All peer review was in the form of letter reviews conducted by a contractor. The peer review reports for each analysis are in the docket for this action and at EPA's Science Inventory ( https://cfpub.epa.gov/si/ ).

Table of Contents
Executive Summary
A. Purpose of This Regulatory Action
B. The Opportunity for New Standards Based on Advancements in Heavy-Duty Vehicle Technologies Which Prevent or Control GHG Emissions
C. Overview of the Final Regulatory Action
D. Impacts of the Standards
E. Coordination With Federal and State Partners
F. Stakeholder Engagement
I. Statutory Authority for the Final Rule
A. Summary of Key Clean Air Act Provisions
B. Authority To Consider Technologies in Setting Motor Vehicle GHG Standards
C. Response to Other Comments Raising Legal Issues
II. Final HD Phase 3 GHG Emission Standards
A. Public Health and Welfare Need for GHG Emission Reductions
B. Summary of Comments and the HD GHG Phase 3 Standards and Updates From Proposal
C. Background on the CO2 Emission Standards in the HD GHG Phase 2 Program
D. Vehicle Technologies and Supporting Infrastructure
E. Technology, Charging Infrastructure, and Operating Costs
F. Final Standards
G. EPA's Basis for Concluding That the Final Standards Are Feasible and Appropriate Under the Clean Air Act
H. Alternatives Considered
I. Small Businesses
III. Compliance Provisions, Flexibilities, and Test Procedures
A. Revisions to the ABT Program
B. Battery Durability Monitoring and Warranty Requirements
C. Additional Revisions to the Regulations
IV. Program Costs
A. IRA Tax Credits
B. Technology Package Costs
C. Manufacturer Costs
D. Purchaser Costs
E. Social Costs
V. Estimated Emission Impacts From the Final Standards
A. Model Inputs
B. Estimated Emission Impacts From the Final Standards
VI. Climate, Health, Air Quality, Environmental Justice, and Economic Impacts
A. Climate Change Impacts
B. Health and Environmental Effects Associated With Exposure to Non-GHG Pollutants
C. Air Quality Impacts of Non-GHG Pollutants
D. Environmental Justice
E. Economic Impacts
F. Oil Imports and Electricity and Hydrogen Consumption
VII. Benefits of the Program
A. Climate Benefits
B. Non-GHG Health Benefits
C. Energy Security
VIII. Comparison of Benefits and Costs
A. Methods
B. Results
IX. Analysis of Alternative CO 2 Emission Standards
A. Comparison of Final Standards and Alternative
B. Emission Inventory Comparison of Final Rule and Slower Phase-In Alternative
C. Program Costs Comparison of the Final Rule and Alternative
D. Benefits
E. How do the final standards and alternative compare in overall benefits and costs?
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 14094: Modernizing Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments
G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51
J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: Revitalizing Our Nation's Commitment to Environmental Justice for All
K. Congressional Review Act (CRA)
L. Judicial Review
M. Severability
XI. Statutory Authority and Legal Provisions

Executive Summary

A. Purpose of This Regulatory Action
The Environmental Protection Agency (EPA) is finalizing this action to further reduce greenhouse gas (GHG) air pollution from highway heavy-duty (hereafter referred to as “heavy-duty” or HD) engines and vehicles across the United States. This final rule establishes new CO 2 emission standards for MY 2032 and later HD vehicles with more stringent CO 2 standards phasing in as early as MY 2027 for certain vehicle categories. We have assessed and demonstrated that these standards are appropriate and feasible considering cost, lead time, and other relevant factors, as described throughout this preamble and supporting materials in the docket for this final rule. Under the Clean Air Act (CAA) “the Administrator shall by regulation prescribe (and from time to time revise) . . . standards applicable to the emission of any air pollutant from any class or classes of new motor vehicles or new motor vehicle engines, . . . which in his judgment cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The regulation “shall take effect after such period as the Administrator finds necessary to permit the development and application of the requisite technology, giving appropriate consideration to the cost of compliance within such period.” Despite the significant emissions reductions achieved by previous rulemakings, GHG emissions from HD vehicles continue to adversely impact public health and welfare, and there is a critical need for further GHG reductions. The transportation sector is the largest U.S. source of GHG emissions, representing 29 percent of total GHG emissions, ^4 and within this, heavy-duty vehicles are the second largest contributor to GHG emissions and are responsible for 25 percent of GHG emissions in the sector. ^5 At the same time, there have been significant advances in technologies to prevent and control GHG emissions from heavy-duty vehicles, and we project there will be more such advances. These final regulations appropriately take advantage of those projected available and cost-reasonable motor vehicle technologies to set more stringent GHG standards that will significantly reduce GHG emissions from heavy-duty vehicles. In general, the final standards are less stringent than proposed for the early model years of the program and more stringent or equivalent to the proposed standards in later model years (expect for heavy-heavy vocational vehicles which are less stringent in later model years; see section ES.C.2.ii of this preamble for more details).
^4 EPA (2023). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 (EPA-430-R-23-002, published April 2023).
^5 EPA (2023). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 (EPA-430-R-23-002, published April 2023).
GHG emissions have significant adverse impacts on public health and welfare. In 2009, the Administrator issued an Endangerment Finding under CAA section 202(a), concluding that GHG emissions from new motor vehicles and engines, including heavy-duty vehicles and engines, cause or contribute to air pollution that may endanger public health or welfare. ^6 After making such a finding, EPA is mandated to issue GHG standards “to regulate emissions of the deleterious pollutant from new motor vehicles.” State of Massachusetts v. EPA, 549 U.S. 497, 533 (2007). Therefore, following the 2009 Endangerment Finding, EPA promulgated GHG regulations for heavy-duty vehicles and engines in 2011 and 2016. ^7 We refer to the EPA-specific GHG regulations found within the “Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 1” and “Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 2” final rulemakings as “HD GHG Phase 1” and “HD GHG Phase 2” respectively throughout this preamble ( i.e., we are not including any reference to the Department of Transportation (DOT) fuel efficiency standards in those rulemakings in using these terms in this preamble). In the HD GHG Phase 1 and Phase 2 programs, EPA set GHG emission standards that the Agency found appropriate and feasible at that time, considering cost, lead time, and other relevant factors, in 2011 and 2016, respectively. ^8 Meanwhile, major scientific assessments continue to be released that further advance our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations, as discussed in detail in section II.A.
^6 74 FR 66496, December 15, 2009.
^7 76 FR 57106, September 15, 2011; 81 FR 73478, October 25, 2016.
^8 See, e.g., 40 CFR 1036.101(a)(2) (engines, overview of emission standards); 40 CFR 1036.108 (engine GHG standards, exhaust emissions of CO2, CH4, and N2O); 40 CFR 1037.101(a)(2) (vehicles, overview of emission standards); 40 CFR 1037.105 and 1037.106 (vehicle GHG standards, exhaust emissions of CO2 for vocational vehicles and tractors).
At the same time, manufacturers have continued to find ways to further reduce and eliminate tailpipe emissions from new motor vehicles, resulting in a range of technologies with the potential for further significant reductions of GHG emissions from HD motor vehicles. These include but are not limited to reductions reflecting increased use of advanced internal combustion vehicle and engine technologies and including increased use of hybrid technologies. These also include technologies with the greatest potential HD vehicle GHG emission reductions, such as battery electric vehicle technologies (BEV) and fuel cell electric vehicle technologies (FCEV). These technologies—which are already being adopted by the HD industry—present an opportunity for significant reductions in heavy-duty GHG emissions over the long term. While standards promulgated pursuant to CAA section 202(a)(1)-(2) are based on application of technology, the statute does not specify a particular technology or technologies that must be used to set such standards; rather, Congress has authorized and directed EPA to adapt its standards to “the development and application of the requisite technology” as determined by the Administrator. ^9
^9 CAA section 202(a)(2).
Major trucking fleets, HD vehicle and engine manufacturers, and U.S. states have announced plans to increase the use of these technologies in the coming years. Tens of billions of dollars are being invested not only in these technologies, but also to increase the infrastructure necessary for their successful deployment, including electric charging and hydrogen refueling infrastructure, manufacturing and production of batteries, and domestic sources of critical minerals and other important elements of the supply chain. The 2021 Infrastructure Investment and Jobs Act (commonly referred to as the “Bipartisan Infrastructure Law” or BIL) and the Inflation Reduction Act of 2022 (“Inflation Reduction Act” or IRA) accelerate these ongoing trends by together including many incentives for the development, production, and sale of a wide range of advanced technologies (including BEVs, plug-in hybrid electric vehicles (PHEVs), FCEVs, and others), electric charging infrastructure, and hydrogen, which are expected to spur significant innovation in the heavy-duty sector. ^{10} Technical assessments and data provided by commenters during the public comment period for this action's notice of proposed rulemaking (hereafter referred to as the “HD GHG Phase 3 NPRM”) as well as comments on related rules, which proposed strengthening existing MY 2027 GHG standards for heavy-duty vehicles, support that significant adoption of technologies with the greatest potential to reduce GHG emissions and associated infrastructure growth is expected to occur over the next decade. 11 12 13 14 We summarize these developments in section B of this Executive Summary, and provide further detail in section I of the HD GHG Phase 3 NPRM, section II of this final rule, and Regulatory Impact Analysis (RIA) Chapters 1 and 2. 15 16
^{10} Infrastructure Investment and Jobs Act, Public Law 117-58, 135 Stat. 429 (2021) (“Bipartisan Infrastructure Law” or “BIL”), available at https://www.congress.gov/117/plaws/publ58/PLAW-117publ58.pdf ; Inflation Reduction Act of 2022, Public Law 117-169, 136 Stat. 1818 (2022) (“Inflation Reduction Act” or “IRA”), available at https://www.congress.gov/117/bills/hr5376/BILLS-117hr5376enr.pdf .
^{11} Notice of Proposed Rulemaking for Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards. 87 FR 17414 (March 28, 2022).
^{12} U.S. EPA, “Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards—Response to Comments.” Section 28. Docket EPA-HQ-OAR-2019-0055.
^{13} Notice of Proposed Rulemaking for Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3. 88 FR 25926, April 27, 2023.
^{14} U.S. EPA. Response to Comments (RTC)—Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles: Phase 3. EPA-420-R-24-007. March 2024.
^{15} Notice of Proposed Rulemaking for Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3. 88 FR 25926, April 27, 2023.
^{16} U.S. EPA. Regulatory Impact Analysis—Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles: Phase 3. EPA-420-R-24-006. March 2024.
In addition, technologies for vehicles with ICE, along with a range of electrification, exist today and continue to evolve to further reduce and eliminate exhaust emissions from new motor vehicles. For example, some of these technologies include improvements to the efficiency of the engine, transmission, drivetrain, aerodynamics, and tire rolling resistance in HD vehicles that reduce their GHG emissions. Another example of a technology under development by manufacturers that reduces vehicle GHG emissions is HD vehicles that use hydrogen-fueled internal combustion engines (H2-ICE), which have zero engine-out CO 2 emissions. The heavy-duty industry has also been developing hybrid powertrains, which consist of an ICE as well as an electric drivetrain and some designs also incorporate plug-in capability. Hybrid powered vehicles may provide CO 2 emission reductions through the use of downsized engines, recovering energy through regenerative braking system that is normally lost while braking, and providing additional engine-off operation during idling and coasting. Hybrid powertrains are available today in a number of heavy-duty vocational vehicles including passenger van/shuttle bus, transit bus, street sweeper, refuse hauler, and delivery truck applications—and as noted in the preceding paragraph, plug-in hybrid technologies are included in advanced technology incentives under IRA. We discuss these technology developments further in section II of this final rule, and Regulatory Impact Analysis (RIA) Chapters 1 and 2.
With respect to the need for GHG reductions and after consideration of these and other heavy-duty sector developments, EPA is finalizing in this action new CO 2 emission standards for MY 2032 and later HD vehicles with more stringent CO 2 standards phasing in as early as MY 2027 for certain vehicle categories ( i.e., more stringent than what was finalized in HD GHG Phase 2). We have assessed and demonstrated that these standards are appropriate and feasible considering cost, lead time, and other relevant factors, as described throughout this preamble and supporting materials in the docket for this final rule. EPA considers safety, consistent with CAA section 202(a)(4), and may consider other factors such as the impacts of potential GHG standards on the industry, fuel savings, oil conservation, energy security, and other relevant considerations. These standards build on decades of EPA regulation of harmful pollution from HD vehicles. Pursuant to our section 202(a) authority, EPA first established standards for the heavy-duty sector in the 1970s. Since then, the Agency has revised the standards multiple times based upon updated data and information, the continued need to mitigate air pollution, and congressional enactments directing EPA to regulate emissions from the heavy-duty sector more stringently. Since 1985, HD engine and vehicle manufacturers have been able to comply with standards using averaging; ^{17} EPA also introduced banking and trading compliance flexibilities in the HD program in 1990; ^{18} and EPA explained that manufacturers could use the Averaging, Banking and Trading (ABT) flexibilities to meet more stringent standards at lower cost. EPA's HD GHG standards and regulations have consistently included an ABT program from the start, ^{19} and have relied on averaging as the basis for standards of greater stringency. ^{20} Since the first CAA section 202(a) HD standards in 1972, subsequent standards have extended to additional pollutants ( e.g., particulate matter and GHGs), have increased in stringency, and have spurred the development and deployment of numerous new vehicle and engine technologies to reduce pollution. For example, the Phase 2 GHG standards for HD vehicles (81 FR 73478, October 25, 2016) were projected to reduce CO 2 emissions by approximately 1.1 billion metric tons over the lifetime of the new vehicles sold under the program (see, e.g., 81 FR 73482), and the most recent “criteria-pollutant” ^{21} standards are projected to reduce oxides of nitrogen (NO X ) emissions from the in-use HD fleet by almost 50 percent by 2045 (“Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards” (hereafter referred to as “HD2027 Low NO X final rule,” 88 FR 4296, January 24, 2023)). This final rule builds upon EPA's multi-decadal tradition of regulating heavy-duty vehicles and engines, by applying the Agency's clear and longstanding statutory authority to consider the feasibility and costs of reducing harmful pollution using new real-world data and information, including the effects of recent congressional action in the BIL and IRA.
^{17} 50 FR 10606, March 15, 1985; see also NRDC v. Thomas, 805 F.2d 410, 425 (D.C. Cir. 1986) (upholding emissions averaging in the 1985 HD final rule).
^{18} 55 FR 30584, July 26, 1990.
^{19} 76 FR 57128, September 15, 2011 (explaining ABT is a flexibility that provides an opportunity for manufacturers to make necessary technological improvements while reducing the overall cost of the program); 81 FR 73495, October 25, 2016 (explaining that ABT plays an important role in providing manufacturers flexibilities, including helping reduce costs).
^{20} For example, in promulgating the HD GHG Phase 2 standards, we explained that the stringency of the HD GHG Phase 2 standards were derived on a fleet average technology mix basis and that the emission averaging provisions of ABT meant that the regulations did not require all vehicles to meet the standards. See, e.g., 81 FR 73715.
^{21} We refer to PM, oxides of nitrogen (NO X ), Volatile Organic Compounds (VOCs), hydrocarbons (HC), carbon monoxide (CO), sulfur dioxide (SO 2 ), more generally as “criteria pollutants” throughout this preamble.
We are issuing this HD vehicle GHG Phase 3 Final Rulemaking (“HD GHG Phase 3 final rule”) which finalizes certain revised HD vehicle carbon dioxide (CO 2 ) standards for MY 2027 and certain new HD vehicle CO 2 standards for MYs 2028, 2029, 2030, 2031, and 2032 that will achieve significant GHG reductions for these and later model years. (Note that the MY 2032 standards will remain in place for MY 2033 and thereafter unless and until new standards are promulgated.) The final standards we are promulgating take into account the ongoing technological innovation in the HD vehicle space and reflect CO 2 emission standards that we have assessed and demonstrated are appropriate and feasible considering cost, lead time, and other relevant factors, as described throughout this preamble and supporting materials in the docket for this final rule. ^{22}
^{22} We note that EPA also included in the HD GHG Phase 3 NPRM a proposal to revise its regulations addressing preemption of state regulation of new locomotives and new engines used in locomotives; those revisions were finalized in a separate action on November 8, 2023, and therefore are not discussed further in this final rule. Final Rulemaking for Locomotives and Locomotive Engines; Preemption of State and Local Regulations. 88 FR 77004, November 8, 2023.
In this rulemaking, EPA did not reopen (1) the other HD GHG standards, including nitrous oxide (N 2 O), methane (CH 4 ), and CO 2 emission standards that apply to heavy-duty engines and the hydrofluorocarbon (HFC) emission standards that apply to heavy-duty vehicles, (2) any portion of our heavy-duty compliance provisions, flexibilities, and testing procedures, including those in 40 CFR parts 1037, 1036, and 1065, other than those specifically identified in our proposal ( e.g., EPA did not reopen the general availability of Averaging, Banking, and Trading), and (3) the existing approach taken in both HD GHG Phase 1 and Phase 2 that compliance with vehicle emission standards is based on emissions from the vehicle, including that compliance with vehicle exhaust CO 2 emission standards is based on CO 2 emissions from the vehicle. We further note that we did not reopen anything on which we did not propose or solicit comment.

B. The Opportunity for New Standards Based on Advancements in Heavy-Duty Vehicle Technologies Which Prevent or Control GHG Emissions

1. Brief Overview of the Heavy-Duty Industry
Heavy-duty highway vehicles range from commercial pickup trucks; to vocational vehicles that support local and regional transportation, construction, refuse collection, and delivery work; to line-haul tractors (semi-trucks) that move freight cross-country. This diverse array of vehicles is categorized into weight classes based on gross vehicle weight ratings (GVWR). These weight classes span Class 2b pickup trucks and vans from 8,500 to 10,000 pounds GVWR through Class 8 line-haul tractors and other commercial vehicles that exceed 33,000 pounds GVWR. While Class 2b and 3 complete pickups and vans are not included in this rulemaking, Class 2b and 3 vocational vehicles are included in this rulemaking (as discussed further in section II.C). ^{23}
^{23} Class 2b and 3 vehicles with GVWR between 8,500 and 14,000 pounds are primarily commercial pickup trucks and vans and are sometimes referred to as “medium-duty vehicles”. The vast majority of Class 2b and 3 vehicles are chassis-certified vehicles, and we included those vehicles in the proposed combined light-duty and medium-duty rulemaking action, consistent with E.O. 14037, section 2a. Heavy-duty engines and vehicles are also used in nonroad applications, such as construction equipment; nonroad heavy-duty engines, equipment, and vehicles are not within the scope of this FRM.
Heavy-duty highway vehicles are powered through an array of different means. Currently, the HD vehicle fleet is primarily powered by diesel-fueled, compression-ignition (CI) engines. However, gasoline-fueled, spark-ignition (SI) engines are common in the lighter weight classes, and smaller numbers of alternative fuel engines ( e.g., liquified petroleum gas, compressed natural gas) are found in the heavy-duty fleet. We refer to the vehicles powered by internal combustion engines as ICE vehicles (or ICEV) throughout this preamble. An increasing number of HD vehicles are powered by technologies that do not have any tailpipe emissions such as battery electric vehicle (BEV) technologies and hydrogen fuel cell electric vehicles (FCEVs). These technologies have seen significant growth in recent years, for example, EPA certified approximately 400 HD BEVs in MY 2020, 1,200 HD BEVs in MY 2021, and 3,400 HD BEVs in MY 2022 across several vehicle categories. We use the term zero-emission vehicle (ZEV) technologies throughout the preamble to refer to technologies that result in zero tailpipe emissions, and vehicles that use these ZEV technologies we refer to collectively as ZEVs in this preamble. ^{24} Hybrid vehicles (including plug-in hybrid electric vehicles) include energy storage features such as batteries and also include an ICE. ^{25} Further background on the HD industry can be found in section II.D, RIA Chapter 1, and HD GHG Phase 3 NPRM section I.A. ^{26}
^{24} Throughout the preamble, we use the term ZEV technologies to refer to technologies that result in zero tailpipe emissions. Example ZEV technologies include battery electric vehicles and fuel cell vehicles.
^{25} Furthermore, hydrogen-powered internal combustion engines (H2-ICE) fueled with neat hydrogen emit zero engine-out CO 2 emissions (as well as zero engine-out HC, CH 4 , CO emissions). We recognize that there may be negligible, but non-zero, CO 2 emissions at the tailpipe of H2-ICE that use selective catalytic reduction (SCR) aftertreatment systems and are fueled with neat hydrogen due to contributions from the aftertreatment system from urea decomposition. As further explained in preamble section III, H2-ICE are considered to emit near zero CO 2 emissions under our part 1036 regulations and are deemed zero under out part 1037 regulations, consistent with our treatment of CO 2 emissions that are attributable to the aftertreatment systems in compression-ignition ICEs. H2-ICE also emit certain criteria pollutants. H2-ICE are not included in what we refer to collectively as ZEVs throughout this final rule. Note, NO X and PM emission testing is required under existing 40 CFR part 1036 for engines fueled with neat hydrogen.
^{26} Notice of Proposed Rulemaking for Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3. 88 FR 25926, April 27, 2023.
The industry that designs and manufactures HD vehicles is composed of three primary segments: vehicle manufacturers, engine manufacturers and other major component manufacturers, and secondary manufacturers ( i.e., body builders). Some vehicle manufacturers are vertically integrated (designing, developing, and testing their engines in-house for use in their vehicles). Others purchase some or all of their engines from independent engine suppliers. At the time of this rulemaking, only one major independent engine manufacturer supports the HD industry, though some vehicle manufacturers sell their engines or “incomplete vehicles” ( i.e., a chassis that includes the engine, the frame, and a transmission) to body builders who design and assemble the final vehicle. Each of these subindustries is often supported by common suppliers for subsystems such as transmissions, axles, engine controls, and emission controls.
In addition to the manufacturers and suppliers responsible for producing HD vehicles, an extended network of dealerships, repair and service facilities, and rebuilding facilities contributes to the sale, maintenance, and extended life of these vehicles and engines. HD vehicle dealerships offer customers a place to order such vehicles from a specific manufacturer and often include service facilities for those vehicles and their engines. Dealership service technicians are generally trained to perform regular maintenance and make repairs, which generally include repairs under warranty and in response to manufacturer recalls. Some trucking fleets, businesses, and large municipalities hire their own technicians to service their vehicles in their own facilities. Many refueling centers along major trucking routes have also expanded their facilities to include roadside assistance and service stations to diagnose and repair common problems.
The end-users for HD vehicles are as diverse as the applications for which these vehicles are purchased. Smaller weight class HD vehicles are commonly purchased by delivery services, contractors, and municipalities. The middle weight class vehicles tend to be used as commercial vehicles for business purposes and municipal work that transport people and goods locally and regionally or provide services such as utilities. Vehicles in the heaviest weight classes are generally purchased by businesses with high load demands, such as construction, towing or refuse collection, or freight delivery fleets and owner-operators for regional and long-haul goods movement. The competitive nature of the businesses and owner-operators that purchase and operate HD vehicles means that any time at which the vehicle is unable to operate due to maintenance or repair ( i.e., downtime) can lead to a loss in income. The customers' need for reliability drives much of the vehicle manufacturers' innovation and research efforts.

2. History of Greenhouse Gas Emission Standards for Heavy-Duty Engines and Vehicles
EPA has a longstanding practice of regulating GHG emissions from the HD sector. In 2009, EPA and the U.S. Department of Transportation's (DOT's) National Highway Traffic Safety Administration (NHTSA) began working on a coordinated regulatory program to reduce GHG emissions and fuel consumption from HD vehicles and engines. ^{27} The first phase of the HD GHG and fuel efficiency program was finalized in 2011 (76 FR 57106, September 15, 2011) (“HD GHG Phase 1”). ^{28} The HD GHG Phase 1 program set performance-based standards and largely adopted approaches consistent with recommendations from the National Academy of Sciences. The HD GHG Phase 1 program, which began in MY 2014 and was phased in through MY 2018, included separate standards for HD vehicles and HD engines. The program offered flexibility allowing manufacturers to attain these standards through any mix of technologies and the option to participate in an ABT program.
^{27} Greenhouse gas emissions from heavy-duty vehicles are primarily carbon dioxide (CO 2 ), but also include methane (CH 4 ), nitrous oxide (N 2 O), and hydrofluorocarbons (HFC).
^{28} National Research Council; Transportation Research Board. The National Academies' Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; “Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles.” 2010. Available online: https://www.nap.edu/catalog/12845/technologies-and-approaches-to-reducing-the-fuel-consumption-of-medium-and-heavy-duty-vehicles .
In 2016, EPA and NHTSA finalized the HD GHG Phase 2 program. ^{29} The HD GHG Phase 2 program included more stringent, performance-based emission standards for HD vehicles and HD engines that phase in over the long term, with initial standards for most vehicles and engines commencing in MY 2021, increasing in stringency in MY 2024, and culminating in even more stringent MY 2027 standards. HD GHG Phase 2 built upon the Phase 1 program and set standards based not only on then-currently available technologies, but also on technologies that were either still under development or not yet widely deployed at the time of the HD GHG Phase 2 final rule. To ensure adequate time for technology development, HD GHG Phase 2 provided up to 10 years lead time to allow for the development and phase-in of these control technologies. EPA recently finalized technical amendments to the HD GHG Phase 2 rulemaking (“HD Technical Amendments”) that included changes to the test procedures for heavy-duty engines and vehicles to improve accuracy and reduce testing burden. ^{30}
^{29} 81 FR 73478, October 25, 2016.
^{30} 86 FR 34308, June 29, 2021.
As with the previous HD GHG Phase 1 and Phase 2 rules and light-duty GHG rules, EPA has coordinated with the DOT and NHTSA during the development of this final rule. This included coordination prior to and during the interagency review conducted under E.O. 12866. EPA has also consulted with the California Air Resources Board (CARB) during the development of this final rule, as EPA also did during the development of the HD GHG Phase 1 and 2 and light-duty rules. See section ES.E of this preamble for additional detail on EPA's coordination with DOT/NHTSA, additional Federal agencies, and CARB.

3. What has changed since EPA finalized the HD GHG Phase 2 rule?

i. Technology Advancements
When EPA promulgated the HD GHG Phase 2 rule in 2016, the agency established the CO 2 standards on the premise of GHG-reducing technologies for vehicles with ICE including technologies such as hybrid powertrains. However, in 2016 we projected that ZEV technologies, such as BEVs and FCEVs, would become more widely available in the heavy-duty market over time, but would not be available and cost-competitive in significant volume in the timeframe of the Phase 2 program. EPA finalized BEV, PHEV, and FCEV advanced technology credit multipliers to encourage the development and availability of these advanced technologies at a faster pace because of their potential for large GHG emissions reductions.
Several significant developments have occurred since 2016 that point to ZEV technologies becoming more readily available much sooner than EPA had previously projected for the HD sector. These developments are summarized here, but more detail can be found in the section II and HD GHG NPRM section ES.B or I.C). ^{31} These developments support the feasibility of ZEV technologies and render adoption of ZEV technologies to reduce GHG emissions more cost-competitive than ever before. First, the HD market has evolved such that early ZEV models are in use today for some applications and are expected to expand to many more; costs of ZEV technologies have gone down and are projected to continue to fall; and manufacturers have announced and begun to implement plans to rapidly increase their investments in ZEV technologies over the next decade. While some HD vehicle manufacturers and firms that purchase HD fleets cautioned in comments that such announcements may change, several HD vehicle manufacturers also commented that their MYs 2024-2027 production plans include ZEVs for their planned compliance with the previously promulgated Phase 2 standards. ^{32} In 2022 and 2023, there were several manufacturers producing fully electric HD vehicles for use in a variety of applications, and these volumes are expected to rise (see RIA Chapter 1.5). The cost to manufacture lithium-ion batteries (the single most expensive component of a BEV) has dropped significantly in the past eight years, and that cost is projected to continue to fall during this decade, all while the performance of the batteries (in terms of energy density) improves. ^{33} ^{34} Many of the manufacturers that produce HD vehicles and major firms that purchase HD vehicles have announced billions of dollars' worth of investments in ZEV technologies and significant plans to transition to a zero-carbon fleet over the next ten to fifteen years. 35 36 37 See section II.D of this preamble, RIA Chapter 1, and HD GHG NPRM section I.C.1 for further information. ^{38} Furthermore, we also have seen development of technologies such as H2-ICE that also will significantly reduce CO 2 emissions from HD vehicles.
^{31} Notice of Proposed Rulemaking for Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3. 88 FR 25926, April 27, 2023.
^{32} See RTC section 10.3.1.
^{33} Mulholland, Eamonn. “Cost of electric commercial vans and pickup trucks in the United States through 2040.” Page 7. January 2022. Available at https://theicct.org/wp-content/uploads/2022/01/cost-ev-vans-pickups-us-2040-jan22.pdf .
^{34} Sharpe, Ben and Hussein Basma. “A meta-study of purchase costs for zero-emission trucks”. The International Council on Clean Transportation, Working Paper 2022-09 (February 2022). Available online: https://theicct.org/publication/purchase-cost-ze-trucks-feb22 .
^{35} Environmental Defense Fund (2022) September 2022 Electric Vehicle Market Update: Manufacturer Commitments and Public Policy Initiatives Supporting Electric Mobility in the U.S. and Worldwide, available online at: https://blogs.edf.org/climate411/files/2022/09/ERM-EDF-Electric-Vehicle-Market-Report_September2022.pdf .
^{36} EDF Comments to the HD GHG Phase 3 NPRM. EPA-HQ-OAR-2022-0985-1644-A1.
^{37} Heavy Duty Trucking Staff, `Autocar, GM to Produce Fuel-Cell Electric Vocational Trucks,' Trucking Info (December 11, 2023). https://www.truckinginfo.com/10211875/autocar-and-gm-announce-electric-truck-joint-venture .
^{38} 88 FR 25926, April 27, 2023.
Second, in enacting the 2021 BIL and the 2022 IRA laws, Congress chose to provide significant and unprecedented monetary incentives for the production and purchase of qualified ZEVs in the HD market, as well as certain key components. These laws also provide incentives for qualifying electric charging infrastructure and for clean hydrogen production and refueling infrastructure, which will further support a rapid increase in market penetration of HD ZEVs. As a few examples, BIL provisions include $5 billion to fund the replacement of school buses with clean and zero- or low-emission buses (EPA's “Clean School Bus Program”) and over $5.5 billion to support the purchase of zero- or low-emission transit buses and associated infrastructure, with up to $7.5 billion to help build out a national network of EV charging and hydrogen refueling infrastructure through DOT's Federal Highway Administration (FHWA), some of which can be used for refueling of heavy-duty vehicles. ^{39} The IRA creates a tax credit available from calendar year (CY) 2023 through CY 2032 of up to $40,000 per vehicle for vehicles over 14,000 pounds (and up to $7,500 per vehicle for vehicles under 14,000 pounds) for the purchase of qualified commercial clean vehicles; provides tax credits available from CY 2023 through CY 2032 (phasing down starting in CY 2030) for the production and sale of battery cells and modules of up to $45 per kilowatt-hour (kWh); and also provides tax credits for 10 percent of the cost of producing applicable critical minerals (including those found in batteries and fuel cells, provided that the minerals meet certain specifications), when such components or minerals are produced in the United States. The IRA also modifies an existing tax credit that applies to alternative fuel refueling property ( e.g., electric vehicle chargers and hydrogen fueling stations) and extends the tax credit through CY 2032; starting in CY 2023, this provision provides a tax credit of up to 30 percent of the cost of the qualified alternative fuel refueling property ( e.g., HD BEV charging and hydrogen refueling equipment) and up to $100,000 per item when located in low-income or non-urban area census tracts and certain other requirements are met. Further, the IRA includes the “Clean Heavy-Duty Vehicles” program, which includes $400 million to make awards to eligible recipients/contractors that propose to replace eligible vehicles to serve one or more communities located in an air quality area designated pursuant to CAA section 107 as nonattainment for any air pollutant, in fiscal year (FY) 2022 and available through FY 2031. The IRA also includes the “Grants to Reduce Air Pollution at Ports” program, which appropriates $3 billion ($750 million of which is for projects located in areas of nonattainment for any air pollutant) in FY 2022 and available through FY 2027, to reduce air pollution at ports. These are only a few examples of a wide array of incentives in both laws that will help to reduce the costs to manufacture, purchase, and operate ZEVs, thereby bolstering their adoption in the market. See section II.E.4 of this preamble, RIA Chapter 1, and HD GHG NPRM section I.C.2 for further information. ^{40}
^{39} While jurisdictions are not required to build stations specifically for heavy-duty vehicles, FHWA's guidance encourages states to consider station designs and power levels that could support heavy-duty vehicles. U.S. Department of Transportation, Federal Highway Administration. “National Electric Vehicle Infrastructure Formula Program: Bipartisan Infrastructure Law—Program Guidance (Update)”. June 2, 2023. Available online: https://www.fhwa.dot.gov/environment/nevi/formula_prog_guid/90d_nevi_formula_program_guidance.pdf .
^{40} 88 FR 25926, April 27, 2023.
Third, there have been multiple actions by states to accelerate the adoption of HD ZEV technologies. As of February 15, 2023, the State of California and ten other states have adopted the Advanced Clean Trucks (ACT) program that includes a manufacturer requirement for zero-emission truck sales, and CAA section 177 empowers additional states to adopt California's ACT program if they wish. ^{41} ^{42} ^{43} The ACT program requires that “manufacturers who certify Class 2b-8 chassis or complete vehicles with combustion engines would be required to sell zero-emission or near-zero emission such as plug-in hybrid trucks as an increasing percentage of their annual [state] sales from 2024 to 2035.” ^{44} ^{45} In addition, 17 states plus the District of Columbia and Quebec (in Canada) have signed a Memorandum of Understanding establishing goals to support widespread electrification of the HD vehicle market. ^{46} See RIA Chapter 1 and HD GHG NPRM section I.C.3 for further information. ^{47} While independent of EPA's section 202 standards, these efforts nonetheless indicate the interest at the state level for increasing electrification of the HD vehicle market.
^{41} California Air Resources Board, Final Regulation Order—Advanced Clean Trucks Regulation. Filed March 15, 2021. Available at: https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2019/act2019/fro2.pdf .
^{42} Oregon, Washington, New York, New Jersey, and Massachusetts adopted ACT beginning in MY 2025 while Vermont and New Mexico adopted ACT beginning in MY 2026, and Colorado, Maryland, and Rhode Island in MY 2027.
^{43} California Air Resources Board. States that have Adopted California's Vehicle Regulations. Available at: https://ww2.arb.ca.gov/our-work/programs/advanced-clean-cars-program/states-have-adopted-californias-vehicle-regulations ; See also, e.g., Final Advanced Clean Truck Amendments, 1461 Mass. Reg. 29 (January 21, 2022) (Massachusetts).; Medium- and Heavy-Duty (MHD) Zero Emission Truck Annual Sales Requirements and Large Entity Reporting, 44 N.Y. Reg. 8 (January 19, 2022) (New York), available at https://dos.ny.gov/system/files/documents/2022/01/011922.pdf .; Advanced Clean Trucks Program and Fleet Reporting Requirements, 53 N.J.R. 2148(a) (December 20, 2021) (New Jersey), available at https://www.nj.gov/dep/rules/adoptions/adopt_20211220a.pdf (pre-publication version); Clean Trucks Rule 2021, DEQ-17-2021 (November 17, 2021), available at http://records.sos.state.or.us/ORSOSWebDrawer/Recordhtml/8581405 (Oregon); Low emission vehicles, Wash. Admin. Code 173-423-070 (2021), available at https://app.leg.wa.gov/wac/default.aspx?cite=173-423-070 ; 2021 Wash. Reg. 587356 (December 15, 2021); Wash. Reg. 21-24-059 (November 29, 2021) (amending Wash. Admin. Code 173-423 and 173-400), available at https://lawfilesext.leg.wa.gov/law/wsrpdf/2021/24/21-24-059.pdf (Washington); “More electric, hydrogen, and hybrid passenger and commercial vehicles coming to New Mexico starting in 2026” https://www.env.nm.gov/wp-content/uploads/2023/11/2023-11-16-COMMS-More-electric-hydrogen-and-hybrid-passenger-and-commercial-vehicles-coming-to-New-Mexico-starting-in-2026-Final.pdf .
^{44} California Air Resources Board, Advanced Clean Trucks Fact Sheet (August 20, 2021), available at https://ww2.arb.ca.gov/resources/fact-sheets/advanced-clean-trucks-fact-sheet . See also California Air Resources Board, Final Regulation Order—Advanced Clean Trucks Regulation. Filed March 15, 2021. Available at: https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2019/act2019/fro2.pdf .
^{45} EPA granted the ACT rule waiver requested by California under CAA section 209(b) on March 30, 2023. 88 FR 20688, April 6, 2023 (signed by the Administrator on March 30, 2023).
^{46} Multi-State MOU (July 2022), available at https://www.nescaum.org/documents/multi-state-medium-and-heavy-duty-zev-action-plan.pdf. States include California, Colorado, Connecticut, Hawaii, Maine, Maryland, Massachusetts, Nevada, New Jersey, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Vermont, Virginia, and Washington.
^{47} 88 FR 25926, April 27, 2003.

ii. Development of a HD GHG Phase 3 Program
Recognizing the need for additional GHG reductions from HD vehicles and the growth of advanced HD vehicle technologies, including ZEV technologies, EPA believes this increased application of technologies in the HD sector that prevent and control GHG emissions from HD vehicles presents an opportunity to strengthen GHG standards, which can result in significant reductions in heavy-duty vehicle emissions. Based on an in-depth analysis of the potential for the development and application of such technologies in the HD sector, in April 2023 we proposed in the HD GHG Phase 3 NPRM GHG standards for MYs 2027 through 2032 and later HD vehicles more stringent than the Phase 2 GHG standards. ^{48} The proposed Phase 3 standards included (1) revised GHG standards for many MY 2027 HD vehicles, with a subset of standards that we did not propose to change, and (2) new GHG standards starting in MYs 2028 through 2032, of which the MY 2032 standards would remain in place for MYs 2033 and later. In the HD GHG Phase 3 NPRM, EPA requested comment on setting more stringent GHG standards beyond the MYs proposed for MYs 2033 through 2035. EPA also requested comment on an alternative set of GHG standards for MYs 2027 through 2032 that were less stringent than those proposed yet still more stringent than the Phase 2 standards. We also requested comment, including supporting data and analysis, as to whether there are certain market segments, such as heavy-haul vocational trucks or long-haul tractors which may require significant energy content for their intended use, for which it may be appropriate to set standards less stringent than the alternative for the specific corresponding regulatory subcategories in order to provide additional lead time to develop and introduce ZEV or other low emission HD vehicle technologies for those specific vehicle applications. In consideration of the environmental impacts of HD vehicles and the need for significant emission reductions, we also requested comment on a more stringent set of GHG standards starting in MYs 2027 through 2032 whose values would go beyond the proposed standards, such as values that would be comparable to the stringency levels in California's ACT program, values in between these proposed standards and those that would be comparable to stringency levels in ACT, and values beyond those that would be comparable to stringency levels in ACT, such as stringency levels comparable to the 50-60 percent ZEV adoption range represented by the publicly stated goals of several major original equipment manufacturers (OEMs) for 2030. 49 50 51 52 53 Finally, after considering the state of the HD market, new incentives, and comments received on the HD2027 NPRM regarding Advanced Technology Credit Multipliers (“credit multipliers”) under the HD GHG Phase 2 program, EPA proposed to end credit multipliers for BEVs and PHEVs one year earlier than provided in the existing HD GHG Phase 2 program ( i.e., no credit multipliers for BEVs and PHEVs in MYs 2027 and later).
^{48} 88 FR 25926, April 27, 2003.
^{49} California Air Resources Board, Final Regulation Order—Advanced Clean Trucks Regulation. Filed March 15, 2021. Available at: https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2019/act2019/fro2.pdf .
^{50} Scania, `Scania's Electrification Roadmap,' Scania Group, November 24, 2021, https://www.scania.com/group/en/home/newsroom/news/2021/Scanias-electrification-roadmap.html .
^{51} AB Volvo, `Volvo Trucks Launches Electric Truck with Longer Range,' Volvo Group, January 14, 2022, https://www.volvogroup.com/en/news-and-media/news/2022/jan/news-4158927.html .
^{52} Deborah Lockridge, `What Does Daimler Truck Spin-off Mean for North America?,' Trucking Info (November 11, 2021). https://www.truckinginfo.com/10155922/what-does-daimler-truck-spin-off-mean-for-north-america .
^{53} Navistar presentation at the Advanced Clean Transportation (ACT) Expo, Long Beach, CA (May 9-11, 2022).
The final standards and requirements we are promulgating in this action are based on further consideration of the data and analyses included in the proposed rule, additional supporting data and analyses we conducted in support of this final rule, and consideration of the extensive public input EPA received in response to the proposed rule. These considerations and analyses are described in detail throughout this preamble, the RIA, and the Response to Comments document (RTC) accompanying this preamble, found in the docket to this rule (EPA-HQ-OAR_2022-0985). In the remainder of this section, we summarize the final program and key changes from the proposal in the section immediately following, followed by a summary of the impacts of the standards, EPA's statutory authority, and coordination with partners and stakeholders.

C. Overview of the Final Regulatory Action
EPA carefully considered input from stakeholders, as discussed throughout this preamble and in our accompanying RTC. This preamble section contains an overview of stakeholders' key concerns, an overview of how EPA has adjusted approaches in the final rule after further consideration, and an overview of the final standards. More detailed discussion of the final rule and key comments and EPA's consideration of them is included in the rest of the preamble, and the RTC contains detailed comment excerpts, comment summaries and EPA's responses.

1. Overview of Stakeholder Positions on Standards' Stringency
EPA's HD GHG Phase 3 Proposed Rule was signed by Administrator Michael Regan on April 11, 2023, and published in the Federal Register on April 27, 2023 (88 FR 25926). EPA held two days of public hearings on May 2 and 3, 2023, and the public comment period ended on June 16, 2023. EPA received over 172,000 comments in the public docket, of which over 230 had detailed comments. In addition, 185 people testified over the two-day public hearing period and EPA held dozens of follow-up meetings with a broad range of stakeholders including environmental justice (EJ) stakeholders, labor unions, manufacturers, fleets, truck dealerships, power sector-related organizations, environmental and public health non-governmental organizations (NGOs), and states. Memoranda regarding these meetings are in the rulemaking docket.
We note that very generally, in comments on the NPRM stakeholders demonstrated strong and opposing views on major issues, including: stringency of the standards, the rate of increasing stringency of the standards year over year from early model years to later model years, availability and readiness of future ZEV infrastructure, availability of minerals critical to battery production and assurance of supply chain readiness for those materials, impact of the IRA tax credits, and key elements of EPA's analysis such as technical feasibility, costs of ZEV technologies, and other elements. For example, many commenters representing environmental NGOs, public health NGOs, environmental justice organizations, front-line communities and some state and local governments supported standards that would be more stringent than our proposed standards in terms of both stringency level and year-over-year pacing of increased stringency, with many supporting standards comparable with stringency levels used in California's ACT program, and some supporting even higher levels ( e.g., 100 percent ZEVs by 2035). A number of these commenters provided EPA with technical analyses and data to support their view that infrastructure necessary to support ZEVs is projected to be ready within the rule time frame, and that there would be sufficient critical minerals as well, such that standards more stringent than those EPA proposed are feasible. Generally, many of these commenters included various technical submissions on how EPA purportedly underestimated ZEV feasibility and adoption, underestimated the impacts of the BIL and IRA in contributing to the further development of the ZEV market, and overestimated ZEV-related costs—which, they argue when accounted for, would have led EPA to consider standards that are more stringent than those proposed. Citing the public health and environmental needs for pollutant reductions that can be achieved with ZEV technology, especially in places such as fence-line and overburdened communities, many of these commenters also suggested more stringent or faster pacing of standards for specific subcategories of vehicles such as tractors, school/transit buses, etc. These commenters generally supported EPA's proposed elimination of credit multipliers for BEVs and PHEVs one year earlier than provided in the existing HD GHG Phase 2 program and some asked EPA to finalize even further limitations of the credit multipliers. EPA requested comment on what, if any, additional information and data EPA should consider collecting and monitoring during the implementation of the Phase 3 standards, including with respect to the important issues of refueling and charging infrastructure for ZEVs; on this topic, this general set of commenters expressed strong opposition to any action EPA would take to create a regulatory self-adjusting link between such monitoring and amending standards to decrease their stringency.
In stark contrast, commenters representing many truck manufacturers, owners, fleets, and dealers, along with some labor groups and some states, voiced support for standards less stringent than even the lowest levels of stringency on which we requested comment in the proposal, i.e., considerably less stringent than the alternative presented in the HD GHG Phase 3 NPRM. A few commenters representing certain truck manufacturers supported the proposed MY 2032 standards but were concerned about the stringency of the early model year standards. Many commenters representing truck manufacturers, owners, fleets, and dealers opposed any revision to the model year 2027 standards and, even at lower overall stringency levels, voiced support for a much more gradual pace of increasing stringency of the standards—with some suggesting standards not commencing until model years 2030 and 2033. Part of their argument is that Phase 2 established GHG vehicle and engine standards for MY 2027 which are challenging, and manufacturers have made compliance plans to meet those standards. In their view, amending those MY 2027 standards cuts against these plans. These commenters also state that, although manufacturers intend to introduce ZEVs in larger numbers over time (and have invested billions of dollars already to do so), ^{54} there is too much uncertainty regarding availability of supporting electrification (or hydrogen) infrastructure, critical minerals, and supply chains to increase the stringency of the MY 2027 standards. Some of these commenters further asserted that the CAA mandates four years of lead time and three years of standard stability for revisions of heavy-duty vehicle and engine emissions standards for any pollutant, including GHGs, citing CAA section 202(a)(3)(B) and (C). A number of these commenters provided EPA with technical analyses and data to support their view that ZEV infrastructure would fall far short of what would be needed to support ZEV adoption levels presented in the potential compliance pathway on which the proposed standards were predicated, and that critical minerals would remain a limitation to ZEV growth in the HD sector. Generally, many of these commenters included various technical submissions on how EPA purportedly overestimated ZEV adoption, overestimated the impacts of the BIL and IRA in contributing to the further development of the ZEV market, and underestimated ZEV-related costs. Citing the concerns that unexpectedly slow infrastructure development could impact manufacturers' ability to comply with Phase 3, a number of these commenters called for EPA to conduct extensive monitoring of post-rule infrastructure buildout and further suggested that EPA establish mechanisms for the standards to self-adjust to become less stringent if the infrastructure deployment was found to be insufficient. These commenters generally opposed EPA's proposed elimination of credit multipliers for BEVs and PHEVs one year earlier than provided in the existing HD GHG Phase 2 program and some asked for an extension of certain technology credit multipliers beyond MY 2027. The commenters representing certain truck manufacturers who supported the proposed MY 2032 standards but expressed concern with early model year standards more specifically cited the early MY standards as being too stringent and progressing in stringency at too steep of an increase given uncertainties associated with sufficiency of supportive electrical infrastructure in the program's initial years.
^{54} See, for example, comments from the Truck and Engine Manufactures (EMA), EPA-HQ-OAR-2022-0985-2668-A1.
Commenters from the petroleum industry and others challenged EPA's authority to issue the proposed standards at all. ^{55} Terming the proposal a “ZEV mandate,” they asserted that the question of whether EPA has authority to issue standards reflecting performance of different vehicle powertrains under the CAA implicates the Major Questions Doctrine, and assert that CAA section 202(a) does not contain the correspondingly requisite clear statement authorizing EPA to do so. These commenters also assert that EPA predicating the proposed standards on averaging under the ABT program, such that vehicles with zero tailpipe emissions purportedly must be averaged with emitting vehicles for manufacturers to be able to meet the standards, is beyond EPA's authority. These commenters stated they were asserting this lack of authority both because, in their view, such averaging implicates the Major Questions Doctrine and EPA lacks a clear statement of authorization from Congress to do so, and because, in their view, averaging and the ABT program are inconsistent with CAA statutory provisions for certification, warranty, and civil penalties, all of which they state contemplate individualized determinations, not determinations on average.
^{55} See, for example, comments from American Free Enterprise Chamber of Commerce, EPA-HQ-OAR-2022-0985-1660.
EPA heard from some representatives from the heavy-duty vehicle manufacturing industry both optimism regarding the heavy-duty industry's ability to produce ZEV applications in future years at high volume, but also concern that a slow deployment of electrification infrastructure (magnitude of potential upgrades to the electrical distribution system necessary to support depot charging, and public charging infrastructure) could slow the growth of heavy-duty ZEV adoption, and that this may present challenges for vehicle manufacturers' ability to comply with EPA HD GHG Phase 3 standards. Concerns about uncertainties relating to supporting infrastructure included: limited nature of today's HD charging infrastructure, the magnitude of buildout of electrical distribution systems necessary to support (BEVs especially in the early model years of the program), the cost and length of time needed for infrastructure buildout, a chicken-egg dynamic whereby prospective BEV purchasers will not act until assured of adequate supporting infrastructure, and utilities will not build out the infrastructure without assurance of demand, and the lack of availability of hydrogen infrastructure. Some commenters further noted that fleets and owners will be reluctant to buy, or may cancel orders for, ZEVs, if/when ZEV infrastructure is a barrier. Commenters raised these concerns on top of those voiced by some manufacturers that more lead time is needed for product development, especially given uncertainty regarding purchasers' decisions, noting customer reluctance to utilize an unfamiliar technology, and asserted barriers associated with limited range and cargo penalty due to need for large batteries. These comments are discussed in more detail in section II and in Chapters 6, 7, and 8 of the RTC.

2. Overview of Consideration of Key Concerns From Stakeholders and the Final Standards

i. Improvements to EPA's Technical and Infrastructure Analyses
EPA considered the wide-ranging perspectives, data and analyses submitted in support of stakeholder positions, as well as new studies and data that became available after the proposal. As a consequence, EPA believes that the technical analyses supporting the final rule are improved and more robust. For example, in our technology analysis tool (HD TRUCS, see section II of this preamble) we have adjusted our battery and other component cost assumptions, revised vehicle efficiency values, refined the battery sizing determination, added public charging, increased depot charging costs and diesel prices, added Federal excise tax (FET) and state tax, increased charging equipment installation costs, included more charger sharing, and increased hydrogen fuel costs. Based on consideration of feedback from commenters, in HD TRUCS we also adjusted the technology payback schedule using a publicly-available model. After consideration of comment (and as EPA signaled at proposal), we also have adjusted our analytical baseline by increasing the amount of ZEV adoption in our “no-action” scenario ( i.e., without this rule) to reflect ZEV adoption required by California's ACT program, as well as further ZEV adoption in other states. These and many more updates described throughout this preamble and the RIA strengthen the analyses supporting the final standards.
We also improved our analysis of infrastructure readiness and cost by including projected needed upgrades to the electricity distribution system under our potential compliance pathway in our analysis. As described in section II of this preamble, our improved analysis of charging infrastructure needs and costs supports the feasibility of the future growth of ZEV technology of the magnitude EPA is projecting in this final rule's potential compliance pathway's technology packages. EPA further notes that we recognize that charging and refueling infrastructure for BEVs and FCEVs is necessary for success in the increasing development and adoption of those vehicle technologies (further discussed in section II and RIA Chapters 1 and 2). There are significant efforts already underway to develop and expand heavy-duty vehicle electric charging and hydrogen refueling infrastructure. The U.S. government is making large investments through the BIL and the IRA, as discussed in more detail in RIA Chapter 1.3 ( e.g., this includes a tax credit for charging or hydrogen refueling infrastructure as well as billions of additional dollars for programs that could help fund charging infrastructure if purchased alongside an electric vehicle). 56 57 Private investments will also play a critical role in meeting future infrastructure needs, as discussed in more detail in RIA Chapter 1.6. We expect many BEV or fleet owners to invest in depot-based charging infrastructure (see RIA Chapter 2.6 for information on our analysis of charging needs and costs). Manufacturers, charging network providers, energy companies and others are also investing in high-power public or other stations that will support public charging. For example, Daimler Truck North America is partnering with electric power generation company NextEra Energy Resources and BlackRock Renewable Power to collectively invest $650 million to create a nationwide U.S. charging network for commercial vehicles with a later phase of the project also supporting hydrogen fueling stations. ^{58} Volvo Group and Pilot announced their intent to offer public charging for medium- and heavy-duty BEVs at priority locations throughout the network of 750 Pilot and Flying J North American truck stops and travel plazas. ^{59} A recent assessment by Atlas Public Policy estimated that $30 billion in public and private investments had been committed as of the end of 2023 specifically for charging infrastructure for medium- and heavy-duty BEVs. ^{60}
^{56} Inflation Reduction Act, Public Law 117-169 (2022).
^{57} Bipartisan Infrastructure Law, Public Law 117-58, 135 Stat. 429 (2021).
^{58} NextEra Energy. News Release: “Daimler Truck North America, NextEra Energy Resources and BlackRock Renewable Power Announce Plans to Accelerate Public Charging Infrastructure for Commercial Vehicles Across The U.S.” January 31, 2022. Available online: https://newsroom.nexteraenergy.com/news-releases?item=123840 .
^{59} Adler, Alan. “Pilot and Volvo Group add to public electric charging projects.” FreightWaves. November 16, 2022. Available online: https://www.freightwaves.com/news/pilot-and-volvo-group-add-to-public-electric-charging-projects .
^{60} Lepre, Nicole. “Estimated $30 Billion Committed to Medium- and Heavy-Duty Charging Infrastructure in the United States.” Atlas Public Policy. EV Hub. January 26, 2024. Available online: https://www.atlasevhub.com/data_story/estimated-30-billion-committed-to-medium-and-heavy-duty-charging-infrastructure-in-the-united-states .
Domestic manufacturing capacity is also increasing. Department of Energy (DOE) estimates over $500 million in announced investments have been made to support the domestic manufacturing of BEV charging equipment, with companies planning to produce more than one million BEV chargers in the U.S. each year. 61 62 Workforce development is on the rise. For example, the Siemens Foundation announced they will invest $30 million over ten years focused on the EV charging sector. ^{63} As of early 2023, about 20,000 people had been certified through a national Electric Vehicle Infrastructure Training Program. 64 65 These important early actions and market indicators suggest strong growth in charging and refueling ZEV infrastructure in the coming years. See RIA Chapters 1.3 and 1.6 for more information on public and private investments in charging infrastructure.
^{61} DOE, “Building America's Clean Energy Future”. 2024. Available online: https://www.energy.gov/invest .
^{62} U.S. Department of Energy, Vehicle Technologies Office. “FOTW #1314, October 30, 2023: Manufacturers Have Announced Investments of Over $500 million in More Than 40 American-Made Electric Vehicle Charger Plants”. October 30, 2023. Available online: https://www.energy.gov/eere/vehicles/articles/fotw-1314-october-30-2023-manufacturers-have-announced-investments-over-500 .
^{63} Lienert, Paul. “Siemens to invest $30 million to train U.S. EV charger technicians”. Reuters. September 6, 2023. Available online: https://www.reuters.com/business/autos-transportation/siemens-invest-30-million-train-us-ev-charger-technicians-2023-09-06 .
^{64} IBEW. “IBEW Members Answer Call for National Electric Vehicle Program”. April 2023. Available online: https://www.ibew.org/articles/23ElectricalWorker/EW2304/Politics.0423.html .
^{65} The White House. “FACT SHEET: Biden Harris Administration Announces New Standards and Major Progress for a Made-in-America National Network of EV Chargers.” February 15, 2023. Available online: https://www.whitehouse.gov/briefing-room/statements-releases/2023/02/15/fact-sheet-biden-harris-administration-announces-new-standards-and-major-progress-for-a-made-in-america-national-network-of-electric-vehicle-chargers .

ii. Summary of Final Standards
Our improved analyses for the final rule continue to show that it is appropriate and feasible to revise the MY 2027 standards promulgated under the HD GHG Phase 2 program for most vehicles, and to set new standards for MYs 2028 through 2032 with year-over- year increases in stringency. In consideration of the opposing concerns raised by commenters, EPA believes it is critical to balance the public health and welfare need for GHG emissions reductions over the long term with the time needed for product development and manufacturing as well as infrastructure development in the near term. After further consideration of the lead times necessary to support both the vehicle technologies' development and deployment and the infrastructure needed, as applicable, under the potential compliance pathway's technology packages described in section ES.C.2.iii, EPA is finalizing GHG emission standards for heavy-duty vehicles that, compared to the proposed standards, include less stringent standards for all vehicle categories in MYs 2027, 2028, 2029, and 2030. The final standards increase in stringency at a slower pace through MYs 2027 to 2030 compared to the proposal, and day cab tractor standards start in MY 2028 and heavy heavy-duty vocational vehicles start in MY 2029 (we proposed Phase 3 standards for day cabs and heavy heavy-duty vocational vehicles starting in MY 2027). As proposed, the final standards for sleeper cabs start in MY 2030 but are less stringent than proposed in that year and in MY 2031, and equivalent in stringency to the proposed standards in MY 2032. Our updated analyses for the final rule show that model years 2031 and 2032 GHG standards in the range of those we requested comment on in the HD GHG Phase 3 NPRM are feasible and appropriate considering feasibility, lead time, cost, and other relevant factors as described throughout this preamble and particularly section II. Specifically, we are finalizing MY 2031 standards that are on par with the proposal for light and medium heavy-duty vocational vehicles and day cab tractors. Heavy heavy-duty vocational vehicle final standards are less stringent than proposed for all model years, including 2031 and 2032. For MY 2032, we are finalizing more stringent standards than proposed for light and medium heavy-duty vocational vehicles and day cab tractors. Our assessment is that setting this level of standards starting in MY 2032 achieves meaningful GHG emission reductions at reasonable cost, and that heavy-duty vehicle technologies, charging and refueling infrastructure, and critical minerals and related supply chains will be available to support this level of stringency (as many commenters agreed with and provided technical information to support). Our assessment of the final program as a whole is that it takes a balanced and measured approach while still applying meaningful requirements in MY 2027 and later to reducing GHG emissions from the HD sector.
A summary of the final standards can be found in this Executive Summary, with more details on the standards themselves and our supporting analysis found in section II and Chapter 2 of the RIA. The standards for MY 2027 through 2032 and later are presented in Table ES-1 and Table ES-2 with additional tables showing the final custom chassis and heavy-haul tractor standards in section II.F. ^{66} When compared to the existing Phase 2 standards, the Phase 3 standards begin in MY 2027 with a 13 percent increase in the stringency of the medium heavy-duty vocational vehicle standards and a 17 percent increase in the light heavy-duty vocational vehicle standards, the Phase 3 day cab tractor standards begin in MY 2028 with an 8 percent increase in stringency over the Phase 2 standards, the heavy heavy-duty vocational standards begin in MY 2029 with a 13 percent increase over Phase 2, and the sleeper cab tractor standards begin in MY 2030 with a 6 percent increase over Phase 2. Each vehicle category then increases in stringency each year, through MY 2032, at which time compared to the Phase 2 program the light heavy-duty vocational standards are a 60 percent increase in stringency of the CO 2 standard, the medium heavy-duty vocational vehicle standards are a 40 percent increase, the day cab standards are a 40 percent increase, the heavy heavy-duty vocational standards are a 30 percent increase, and the sleeper cab standards are a 25 percent increase in the stringency of the standards. As described in section II of this preamble, our analysis shows that the final Phase 3 standards, including revisions to HD GHG Phase 2 CO 2 standards for MY 2027 and the new, progressively more stringent numeric values of the CO 2 standards starting in MYs 2028 through 2032, are feasible and appropriate considering feasibility, lead time, costs, and other relevant factors.
^{66} See regulations 40 CFR 1037.105 and 1037.106.
Table ES-1 MY 2027 through 2032 and Later Vocational Vehicle CO 2 Emission Standards (grams/ton-mile) by Regulatory Subcategory (with Phase 2 2024 through 2026 Standards for Reference)

iii. Updated Technology Packages for Example Potential Compliance Pathways
The standards do not mandate the use of a specific technology, and EPA anticipates that a compliant fleet under the standards would include a diverse range of HD motor vehicle technologies ( e.g., transmission technologies, aerodynamic improvements, engine technologies, hybrid technologies, battery electric powertrains, hydrogen fuel cell powertrains, etc.). The technologies that have played (and that the Phase 2 rule projected would play) a fundamental role in meeting the Phase 2 GHG standards will continue to play an important role going forward, as they remain key to reducing the GHG emissions of HD vehicles powered by internal combustion engines. In our assessment that supports the appropriateness and feasibility of these final standards, we developed projected technology packages for potential compliance pathways that could be used to meet each of the final standards. ^{67} Because our standards are technology neutral and there are flexibilities built into the ABT program, there are many variations in the exact mix of technologies manufacturers can use to meet the standards, and this mix can include technologies that EPA has not envisioned. We have projected a few compliance pathways with technology packages that are purposely different. One example potential compliance pathway's projected technology package includes a mix of HD motor vehicle technologies that prevent and control GHG emissions, including technologies for vehicles with ICE and ZEV technologies (Table ES-3). In Table ES-4, we present another example compliance pathway's technology package that does not include ZEVs but does include a suite of GHG-reducing technologies for vehicles with ICE ranging from: ICE improvements in engine, transmission, drivetrain, aerodynamics, and tire rolling resistance; the use of lower carbon fuels (Compressed Natural Gas (CNG)/Liquified Natural Gas (LNG)); hybrid powertrains (Hybrid Electric Vehicles (HEV) and Plug-in Hybrid Electric Vehicles (PHEV)); and hydrogen-fueled ICE (H2-ICE). Except for H2-ICE, these technologies exist today and continue to evolve to improve their CO 2 emissions reductions. To demonstrate feasibility and project emissions impacts, costs, benefits, etc. in this final rule, we present a detailed analysis of the compliance pathway represented by the technology packages shown in Table ES-3, which we believe is one reasonable pathway. Details on several additional example potential technology compliance pathways we considered can be found in section II.F.4 and RIA Chapter 2.11, and details on our projected technology mix in a “reference” scenario that represents the United States without the final standards can be found in section V and RIA Chapter 4. EPA emphasizes that its standards are performance-based, and manufacturers are not required to use particular technologies to meet the standards. Tables ES-3 and ES-4 are just two examples of potential technology compliance pathways and do not reflect a requirement of how manufacturers will ultimately meet the standards finalized in this rule.
^{67} As further explained in sections I and II (including II.G), EPA is required by law to assess feasibility and compliance costs of standards issued pursuant to CAA section 202(a), and thus practically must demonstrate a potential means of complying with the standards in order to do so ( e.g., a potential compliance pathway's projected technology packages that manufacturers may, but are not required, to utilize). Long-standing case law regarding EPA's CAA section 202(a) authority supports the necessity of this approach. See NRDC v. EPA, 655 F. 2d 321, 332 (D.C. Cir. 1981) (indicating that EPA is to state the engineering basis underlying a section 202 standard ( i.e., the technology package which could be utilized to meet a standard), indicate potential impediments to that technology package's feasibility, and plausibly explain how those impediments could be resolved within the lead time afforded).

iv. Revisions to Advanced Technology Vehicle Credit Multipliers
Along with retaining EPA's historical approach to setting performance-based standards and providing manufacturers flexibility in meeting the standards by allowing them to choose their own mix of vehicle technologies, we are retaining and did not reopen the general structure of the Averaging, Banking and Trading (ABT) program, which allows manufacturers further flexibility in meeting standards using averaging provisions. In other words, consistent with EPA's practice for over fifty years of setting emissions standards for HD vehicles, we are retaining the existing regulatory scheme that does not require each vehicle to meet the standards individually and instead allows manufacturers to meet the standards on average within each weight class of their fleet. ^{68} As described in section III.A of this preamble, we are finalizing updates to the advanced technology incentives in the ABT program for HD GHG Phase 2 for PHEVs, BEVs, and FCEVs. As further explained in section III, after consideration of comments, we are retaining the advanced technology vehicle credit multipliers for PHEV, BEV, and FCEV technologies through MY 2027, consistent with the previously promulgated HD GHG Phase 2 program. In order to ensure meaningful vehicle GHG emission reductions under the Phase 3 program, we are limiting the period over which manufacturers can use the multiplier portion of credits earned from advanced technologies. However, in recognition that the final HD GHG Phase 3 standards will require meaningful investments from manufacturers to reduce GHG emissions from HD vehicles, we requested comment on and are finalizing certain additional transitional flexibilities to assist manufacturers in the implementation of Phase 3. See section III of this preamble for further details.
^{68} As further described in section III, as has been the case since the ABT program was first promulgated, although manufacturers choosing to use ABT as a compliance strategy must assure that their vehicle families comply with the standard on average, each individual vehicle is certified to an individual limit (called a Family Emission Limit) as well.

v. Commitment to Engagement and Monitoring Elements of Phase 3 Compliance and Supporting Technology and Infrastructure Development
As we noted in the HD GHG Phase 3 NPRM, EPA has a vested interest in monitoring industry's performance in complying with mobile source emission standards, including the highway heavy-duty industry. In fact, EPA already monitors and reports out industry's performance through a range of approaches, including publishing industry compliance reports (such as has been done during the heavy-duty GHG Phase 1 program). ^{69} After consideration of the divergent comments received on the topic of collecting and monitoring ZEV infrastructure during the implementation of the Phase 3 standards, as further described in section II, we are committing in this final rule to actively engage and monitor both manufacturer compliance and the major elements of heavy-duty technology and supporting infrastructure development. EPA, in consultation with other Federal agencies, will issue periodic reports reflecting collected information. These reports will track HD electric charging and hydrogen refueling infrastructure buildout throughout Phase 3 implementation as well as an evaluation of zero and low GHG-emitting HD vehicle production and the evolution of the HD battery production and material supply, including supply of critical minerals. Based on these reports, as appropriate and consistent with CAA section 202(a) authority, EPA may decide to issue guidance documents, initiate a rulemaking to consider modifications to the Phase 3 rule, or make no changes to the Phase 3 rule program. We are not finalizing any mechanisms for including a self-adjusting linkage between the standards' stringency and ZEV infrastructure as requested by some industry stakeholders. Further details on EPA's Phase 3 rule implementation engagement, data collection and monitoring and reporting commitments can be found in section II.B.2 of this preamble.
^{69} See EPA Reports EPA-420-R-21-001B covering Model Years 2014-2018, and EPA report EPA-420-R-22-028B covering Model Years 2014—2020, available online at https://www.epa.gov/compliance-and-fuel-economy-data/epa-heavy-duty-vehicle-and-engine-greenhouse-gas-emissions .

D. Impacts of the Standards
Our estimated emission impacts, average per-vehicle costs, monetized program costs, and monetized benefits of the final program are summarized in this section and detailed in sections IV through VIII of the preamble and Chapters 3 through 8 of the RIA. EPA notes that, consistent with CAA section 202(a)(1) and (2), in evaluating potential GHG standards, we carefully weigh the statutory factors, including GHG emissions impacts of the GHG standards, and the feasibility of the standards (including cost of compliance and available lead time).
We monetize benefits of the GHG standards and evaluate costs in part to better enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are benefits that we are currently unable to fully quantify and monetize. EPA's consistent practice has been to set standards to achieve improved air quality consistent with CAA section 202(a), and not to rely on cost-benefit calculations, with their uncertainties and limitations, in identifying the appropriate standards. Nonetheless, our conclusion that the estimated benefits exceed the estimated costs of the final program reinforces our view that the GHG standards represent an appropriate weighing of the statutory factors and other relevant considerations.
Our analysis of emissions impacts accounts for downstream emissions, i.e., from emission processes such as engine combustion, engine crankcase exhaust, vehicle evaporative emissions, vehicle refueling emissions, and brake and tire wear. Vehicle technologies would also affect emissions from upstream sources, i.e., emissions that are attributable to a vehicle's operation but not the vehicle itself, for example, electricity generation and the refining and distribution of fuel. Our analyses include emissions impacts from electrical generating units (EGUs) and refinery emission impacts. ^{70}
^{70} We are continuing and are not reopening the existing approach taken in both HD GHG Phase 1 and Phase 2, that compliance with the vehicle exhaust CO 2 emission standards is based solely on CO 2 emissions from the vehicle. Indeed, all of our vehicle emission standards are based on vehicle emissions.
The estimated impacts summarized in this section are based on our projection of a scenario that represents the United States with the final standards in place, relative to our projection of a “reference” scenario that represents the United States without the final standards. For a similar estimate for the alternative standards, please see preamble section IX. As suggested by many commenters, and as EPA suggested at proposal (88 FR 25989), we updated our reference scenario between the proposal and this final rule to include California's ACT program implementation in California and in the states that have adopted the ACT rule under CAA section 177, thus increasing the amount of ZEV technology in our projection of the United States without the final standards in place. ^{71} Further, we improved our projections of the rate of expected ZEV adoption across vehicle categories for the reference scenario, the result of which in the modeled compliance pathway was increased projected adoption in the light heavy-duty vocational vehicle subcategory and decreased adoption in other subcategories compared to the reference scenario in the proposal. These updates to the reference scenario resulted in changes to the estimated numeric values of emissions and costs as shown but reflect the same general expected impacts of the standards as we projected at the time of proposal, i.e., significant reductions in downstream GHG emissions, reductions in GHGs from lower demand for onroad fuels and therefore reduced emissions from fuel refineries, and increases in GHG emissions from EGUs (which we expect to decline over time as the electricity grid becomes cleaner). This same trend is expected for non-GHG pollutants as well, which are affected to the extent that zero- or lower-non-GHG emitting technologies are used to meet the GHG standards, i.e., we project significant reductions in downstream emissions of non-GHG pollutants, reductions in non-GHG pollutants resulting from lower demand for onroad fuels and therefore reduced emissions from fuel refineries, and increases in non-GHG pollutant emissions from EGUs (which we expect to decrease over time as previously noted).
^{71} EPA granted California's waiver request on March 30, 2023, which left EPA insufficient time to develop an alternative reference case for the proposal. 88 FR 25989.
As seen in Table ES-5, through 2055 the program will result in significant downstream GHG emission reductions—approximately 1.4 billion metric tons in reduced CO 2 -equivalent emissions. ^{72} From calendar years 2027 through 2055, we project a cumulative increase of approximately 0.39 billion metric tons of CO 2 -equivalent emissions from EGUs as a result of the increased demand for electricity associated with the rule. We also project reductions in CO 2 -equivalent emissions from refineries on the order of 0.013 billion metric tons during this time period. Considering both downstream and upstream cumulative emissions from calendar years 2027 through 2055 (a year when most of the regulated fleet will consist of HD vehicles subject to the Phase 3 standards due to fleet turnover), the standards will achieve approximately 1 billion metric tons in net CO 2 -equivalant emission reductions (see section V of this preamble and Chapter 4 of the RIA for more detail). Following improvements to our technical analysis as described in more detail in sections II and V of this preamble, we remodeled the GHG emission reductions from the proposed standards, and the results show the reductions from the final rule are close to but greater than projected reductions from the proposed standards ( e.g., net reductions are 998 million metric ton for the proposed standards). As summarized in section C2.ii of the Executive Summary and detailed in section II of this preamble, the final standards are less stringent and increase in stringency at a slower pace compared to the proposal in the early model years of the program, but the later model year final standards are more stringent than proposed for light and medium heavy-duty vocational vehicles and day cab tractors. This final rule's GHG emission reductions will make an important contribution to efforts to limit climate change and its anticipated impacts. These GHG reductions will benefit all U.S. residents, including populations such as people of color, low-income populations, indigenous peoples, and/or children that may be especially vulnerable to various forms of damages associated with climate change.
^{72} Note that these reductions are lower in the final rule than the proposal primarily due to the increased number of ZEVs considered in the reference case, see section V of this preamble for details.
In our modeled potential compliance pathway, we project that the GHG emission standards will lead to an increase in HD ZEVs relative to our reference case ( i.e., without the rule), which will also result in downstream reductions of vehicle emissions of non-GHG pollutants that contribute to ambient concentrations of ozone, particulate matter (PM 2.5 ), nitrogen dioxide (NO 2 ), CO, and air toxics. Exposure to these non-GHG pollutants is linked to adverse human health impacts such as premature death as well as other adverse public health and environmental effects (see section VI). As shown in Table ES-6, in 2055, we estimate a decrease in emissions from all criteria pollutants modeled ( i.e., NO X , PM 2.5 , VOC, and SO 2 ) from downstream sources. The reductions in non-GHG emissions from vehicles will reduce air pollution near roads. As described in section VI of this preamble, there is substantial evidence that people who live or attend school near major roadways are more likely to be of a non-White race, Hispanic ethnicity, and/or low socioeconomic status. In addition, emissions from HD vehicles and engines can significantly and adversely affect individuals living near truck freight routes. Based on a study EPA conducted of people living near truck routes, an estimated 72 million people live within 200 meters of a truck freight route. ^{73} Relative to the rest of the population, people of color and those with lower incomes are more likely to live near truck routes. ^{74} In addition, children who attend school near major roads are disproportionately more highly represented by children of color and children from low-income households. ^{75}
^{73} U.S. EPA (2021). Estimation of Population Size and Demographic Characteristics among People Living Near Truck Routes in the Conterminous United States. Memorandum to the Docket EPA-HQ-OAR-2019-0055.
^{74} See section VI.D of this preamble for additional discussion on our analysis of environmental justice impacts of this final rule.
^{75} Kingsley, S., Eliot, M., Carlson, L. et al. Proximity of U.S. schools to major roadways: a nationwide assessment. J Expo Sci Environ Epidemiol 24, 253-259 (2014). https://doi.org/10.1038/jes.2014.5 .
Table ES-6 also shows impacts on EGU and refinery emissions. Similar to GHG emissions, we project that non-GHG emissions from EGUs will increase in the near term as a result of the increased demand for electricity associated with the rule, and we expect those projected impacts to decrease over time as the electricity grid becomes cleaner. We project reductions in non-GHG emissions from refineries. ^{76} We project net reductions in NO X , VOC, and SO 2 emissions in 2055. Although there is a small net increase in direct PM 2.5 emissions in 2055, ambient PM 2.5 is formed from emissions of direct PM 2.5 as well as emissions of other precursors such as NOx and SO 2. We project overall PM 2.5 -related benefits based on the contribution of emissions from each of these pollutants (see Table ES-8). See section V of this preamble and RIA Chapter 4 for more details.
^{76} We note here that there is uncertainty surrounding how refinery activity would change in response to lower domestic demand for liquid transportation fuels and in response to comments received on the proposal, the estimates in Table ES-6 reflect the assumption that half of the projected drop in domestic fuel demand would be offset by an increase in exports.
EPA believes the non-GHG emissions reductions of this rule provide important health benefits to the 72 million people living near truck routes and even more broadly over the longer term. We note that the agency has broad authority to regulate emissions from the power sector ( e.g., the mercury and air toxics standards, and new source performance standards), as do the States and EPA through cooperative federalism programs ( e.g., in response to PM National Ambient Air Quality Standards (NAAQS) implementation requirements, interstate transport, emission guidelines, and regional haze), ^{77} and that EPA reasonably may address air pollution incrementally across multiple rulemakings, particularly across multiple industry sectors. For example, EPA has separately proposed new source performance standards and emission guidelines for greenhouse gas emissions from fossil fuel-fired power plants, which would also reduce emissions of criteria air pollutants such as PM 2.5 and SO 2 (88 FR 33240, May 23, 2023). ^{78}
^{77} See also CAA section 116.
^{78} New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule. 88 FR 33240, May 23, 2023. https://www.federalregister.gov/documents/2023/05/23/2023-10141/new-source-performance-standards-for-greenhouse-gas-emissions-from-new-modified-and-reconstructed.
In general, the final rule cost analysis methodology mirrors the approach we took for the proposal, but with a number of important updates to our modeling approach and the data used in our modeling projections. More details on specific updates after consideration of comments and new data can be found in sections II and IV of this preamble, but we note here that our final rule analysis was conducted using the latest dollar value, 2022 dollars (2022$), which represents an update from the 2021 dollars used in the NPRM analysis. We also note that updates to our reference scenario have lowered the overall costs and benefits of the final standards, as described briefly in this Executive Summary and in more detail in sections IV through VIII of this preamble. The decrease is attributable to the increase in the number of ZEVs in the reference case.
We estimate that for calendar years 2027 through 2055 and at an annualized 2 percent discount rate, costs to manufacturers will result in a cost savings of $0.19 billion dollars before considering the IRA battery tax credits. With those battery tax credits, which we estimate to be $0.063 billion, the cost to manufacturers of compliance with the program will result in a cost savings of $0.25 billion. The manufacturer cost of compliance with the rule on a per-vehicle basis are shown in Table ES-7. We estimate that the MY 2032 fleet average per-vehicle cost to manufacturers by regulatory group will range from a cost savings of between $700 and $3,000 per vehicle for vocational vehicles to costs of between $3,200 and $10,800 per tractor. EPA notes the projected fleet-average costs per-vehicle for this rule are less than the fleet average per-vehicle costs projected for the HD GHG Phase 2 MY 2027 standards which EPA found to be reasonable under our statutory authority, where the tractor standards were projected to cost between $12,750 and $17,125 (2022$) per vehicle and the vocational vehicle standards were projected to cost between $1,860 and $7,090 (2022$) per vehicle. ^{79} For this action, EPA finds that the expected additional vehicle costs are reasonable considering the related GHG emissions reductions. ^{80} EPA emphasizes again that manufacturers will choose their pathway for compliance and the pathway modeled here is just one of many potential compliance pathways.
^{79} The Phase 2 tractor MY 2027 standard cost increments were projected to be between $10,200 and $13,700 per vehicle in 2013$ (81 FR 73621). The Phase 2 vocational vehicle MY 2027 standards were projected to cost between $1,486 and $5,670 per vehicle in 2013$ (81 FR 73718).
^{80} For illustrative purposes, these average costs range between an approximate 0.03 percent decrease for light-heavy vocational vehicles up to a 6 percent increase for long-haul tractors based on a minimum vehicle price of $100,000 for vocational vehicles and $190,000 for long-haul tractors (see section II.G.2 of this preamble). We also note that these average upfront costs are taken across the HD vehicle fleet and are not meant as an indicator of average price increase.
The GHG standards will reduce adverse impacts associated with climate change and exposure to non-GHG pollutants and thus will yield significant benefits, including those we can monetize and those we are unable to quantify. Table ES-8 summarizes EPA's estimates of total monetized discounted costs, operational savings, and benefits. In our proposal, EPA used interim Social Cost of GHGs (SC-GHG) values developed for use in benefit-cost analyses until updated estimates of the impacts of climate change could be developed based on the best available science and economics. In response to recent advances in the scientific literature on climate change and its economic impacts, incorporating recommendations made by the National Academies of Science, Engineering, and Medicine ^{81} (National Academies, 2017), and to address public comments on this topic, for this final rule we are using updated SC-GHG values. EPA presented these updated values in a sensitivity analysis in the December 2022 Oil and Gas Rule RIA which underwent public comment on the methodology and use of these estimates as well as external peer review. ^{82} After consideration of public comment and peer review, EPA issued a technical report signed by the EPA Administrator on December 2, 2023, updating the estimates of SC-GHG in light of recent information and advances. ^{83} This is discussed further in preamble section VII and RIA Chapter 7.
^{81} National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National Academies Press. https://doi.org/10.17226/24651 .
^{82} Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review. 87 FR 74702.
^{83} Supplementary Material for the Regulatory Impact Analysis for the Supplemental Proposed Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review” EPA, 2022. Docket ID No. EPA-HQ-OAR-2021-0317. Available at: https://www.epa.gov/system/files/documents/2023-12/eo12866_oil-and-gas-nsps-eg-climate-review-2060-av16-ria-20231130.pdf.
The results presented in Table ES-8 project the monetized environmental and economic impacts associated with the program during each calendar year through 2055. EPA estimates that the annualized value of monetized net benefits to society at a 2 percent discount rate will be approximately $13 billion through the year 2055, roughly 12 times the cost in vehicle technology and associated electric vehicle supply equipment (EVSE) combined. Regarding social costs, EPA estimates that the cost of vehicle technology (not including the vehicle or battery tax credits) and EVSE at depots ^{84} will be approximately $1.1 billion. The HD industry will save approximately $3.5 billion in operating costs ( e.g., savings that come from less liquid fuel used, lower maintenance and repair costs for ZEV technologies as compared to ICE technologies, etc.). The program will result in significant social benefits including $10 billion in climate benefits (with the average SC-GHG at a 2 percent near-term Ramsey discount rate) and $0.3 billion in estimated benefits attributable to changes in emissions of PM 2.5 precursors. Finally, the benefits due to reductions in energy security externalities caused by U.S. petroleum consumption and imports will be approximately $0.45 billion under the program. A more detailed description and breakdown of these benefits can be found in section VIII of the preamble and Chapters 7 and 8 of the RIA.
^{84} EVSE costs include hardware and installation costs for electric vehicle supply equipment at depots. Costs for upgrades to the distribution system are incorporated in the operating costs (specifically within $/kWh charging costs). We also estimate infrastructure costs for vehicles we project to use public charging. See RIA 2.4.4 and 2.6 for more information.
Regarding the costs to purchasers as shown in Table ES-9, for the final program we estimated the average upfront incremental cost to purchase a new MY 2032 HD ZEV relative to a comparable ICE vehicle meeting the Phase 2 MY 2027 standards for a vocational ZEV and EVSE, a short-haul tractor ZEV and EVSE, and a long-haul tractor ZEV. These incremental costs account for the IRA tax credits, specifically battery and vehicle tax credits and tax credits applicable to EVSE installation and infrastructure, as discussed in section II.E.4 and RIA Chapter 2. We also estimated the operational savings each year ( i.e., savings that come from the lower costs to operate, maintain, and repair ZEV technologies) and payback period ( i.e., the year the initial cost increase would pay back). Table ES-9 shows that for the vocational vehicle ZEVs, short-haul tractor ZEVs, and long-haul tractor ZEVs the incremental upfront costs (after the tax credits) are recovered through operational savings such that payback occurs between two and four years on average for vocational vehicles, after two years for short-haul tractors and after five years on average for long-haul tractors. We discuss this in more detail in sections II and IV of this preamble and RIA Chapters 2 and 3.

E. Coordination With Federal and State Partners
EPA has coordinated and consulted with DOT/NHTSA, both on a bilateral level during the development of this program as well as through the interagency review of the action led by the Office of Management and Budget. EPA has set some previous heavy-duty vehicle GHG emission standards in joint rulemakings where NHTSA also established heavy-duty fuel efficiency standards. EPA notes that there is no statutory requirement for joint rulemaking, that the agencies have different statutory mandates and that their respective programs have always reflected those differences. As the Supreme Court has noted, “EPA has been charged with protecting the public's `health' and `welfare,' a statutory obligation wholly independent of DOT's mandate to promote energy efficiency.” ^{85} Although there is no statutory requirement for EPA to consult with NHTSA, EPA has consulted with NHTSA in the development of this program. For example, staff of the two agencies met frequently to discuss various technical issues and to share technical information. While assessing safety implications of this rule for the NPRM, EPA consulted with NHTSA. EPA further coordinated with NHTSA regarding safety implications of this rule, including EPA's response to safety related comments and identifying updates, for the final rule. ^{86}
^{85} Massachusetts v. EPA, 549 U.S. at 532.
^{86} Landgraf, Michael. Memorandum to docket EPA-HQ-OAR-2022-0985. Summary of NHTSA Safety Communication. February 2024.
EPA also has consulted with other Federal agencies in developing this rule and the light-duty vehicles GHG rulemaking, including the Federal Energy Regulatory Commission (FERC), the Joint Office for Energy and Transportation, the Department of Energy and several National Labs. EPA consulted with FERC on this rulemaking regarding potential impacts of these rulemakings on bulk power system reliability and related issues. ^{87} EPA collaborated with DOE and Argonne National Laboratory on battery cost analyses and critical minerals forecasting. EPA, National Renewable Energy Laboratory (NREL), and DOE collaborated on forecasting the development of a national charging infrastructure and projecting regional charging demand for input into EPA's power sector modeling. EPA also coordinated with the Joint Office of Energy and Transportation on charging infrastructure. EPA and the Lawrence Berkeley National Laboratory collaborated on issues of consumer acceptance of plug-in electric vehicles. EPA and the Oak Ridge National Laboratory collaborated on energy security issues. EPA also participated in the Federal Consortium for Advanced Batteries led by DOE and the Joint Office of Energy and Transportation. EPA and DOE also have entered into a Joint Memorandum of Understanding to provide a framework for interagency cooperation and consultation on electric sector resource adequacy and operational reliability. ^{88} EPA consulted with the Department of Labor (DOL) and DOE on labor and employment initiatives involving the battery and vehicle electrification spaces, and DOL provided a memorandum to EPA containing an overview of numerous Federal Government initiatives focused on these areas. ^{89} EPA also consulted with NHTSA on potential safety issues and NHTSA provided a number of studies to us concerning electric vehicle safety. In addition, EPA consulted with the Department of State on the Federal Government's initiatives concerning supply chains for critical minerals.
^{87} Although not a Federal agency, EPA also consulted with the North American Electric Reliability Corporation (NERC). NERC is the Electric Reliability Organization for North America, subject to oversight by FERC.
^{88} Joint Memorandum on Interagency Communication and Consultation on Electric Reliability, U.S. Department of Energy and U.S. Environmental Protection Agency, March 8, 2023.
^{89} See Memorandum from Employment and Training Administration (ETA), Office of Assistant Secretary for Policy (OASP), Office of the Solicitor (SOL) at the U.S. Department of Labor to EPA re Labor/Employment Initiatives in the Battery/Vehicle Electrification Space (February 2024), which is available in the docket for this action.
EPA has also engaged with the California Air Resources Board on technical issues in developing this program. EPA has considered certain aspects of the CARB ACT rule, as discussed elsewhere in this document. We also have engaged with other states, including members of the National Association of Clean Air Agencies, the Association of Air Pollution Control Agencies, the Northeast States for Coordinated Air Use Management, and the Ozone Transport Commission.

F. Stakeholder Engagement
EPA conducted extensive engagement with a diverse range of interested stakeholders in developing this final rule, including labor unions, states, industry, environmental justice organizations and public health experts. In addition, we have engaged with environmental NGOs, vehicle manufacturers, technology suppliers, dealers, utilities, charging providers, tribal governments, and other organizations. For example, in April-May 2022, EPA held a series of engagement sessions with organizations representing all of these stakeholder groups so that EPA could hear early input in developing its proposal. EPA has continued engagement with stakeholders throughout the development of this rule, throughout the public comment period and into the development of this final rule. ^{90}
^{90} Miller, Neil. Memorandum to docket EPA-HQ-OAR-2022-0985. Summary of Stakeholder Meetings. March 2024.

I. Statutory Authority for the Final Rule
This section summarizes the statutory authority for the final rule. Statutory authority for the GHG standards EPA is finalizing is found in CAA section 202(a)(1)-(2), 42 U.S.C. 7521(a)(1)-(2), which requires EPA to establish standards applicable to emissions of air pollutants from new motor vehicles and engines which in the Administrator's judgment cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare. Additional statutory authority for the action is found in CAA sections 202-209, 216, and 301, 42 U.S.C. 7521-7543, 7550, and 7601.
Section I.A overviews the text of the relevant statutory provisions read in their context. We discuss the statutory definition of “motor vehicles” in section 216 of the Act, EPA's authority to establish emission standards for such motor vehicles in section 202, and authorities related to compliance and testing in sections 203, 206, and 207.
Section I.B addresses comments regarding our legal authority to consider a wide range of technologies, including electrified technologies that completely prevent vehicle tailpipe emissions. EPA's standard-setting authority under section 202 is not limited to any specific type of emissions control technology, such as technologies applicable only to ICE vehicles; rather, the Agency must consider all technologies that reduce emissions from motor vehicles—including zero-emissions vehicle (ZEV) technologies that allow for complete prevention of emissions such as battery electric vehicle (BEV) and fuel-cell electric vehicle (FCEV) technologies—in light of the lead time provided and the costs of compliance. Many commenters, including the main trade group representing regulated entities under this rule, supported EPA's legal authority to consider such technologies. At the same time, the final standards do not require the manufacturers to adopt any specific technological pathway and can be achieved through the use of a variety of technologies, including without producing additional ZEVs to comply with this rule.
Section I.C summarizes our responses to certain other comments relating to our legal authority, including whether this rule implicates the major questions doctrine, whether EPA has authority for its Averaging, Banking, and Trading (ABT) program, whether EPA properly considered ZEVs as part of the class of vehicles for GHG regulation, and whether the 4-year lead time and 3-year stability requirements in CAA section 202(a)(3)(C) apply to this rule. We discuss our legal authority and rationale for battery durability and warranty separately in section III.B of the preamble. Additional discussion of legal authority for the entire rule is found in Chapters 2 and 10 of the RTC, and additional background on authority to regulate GHGs from heavy-duty motor vehicles and engines can be found in the HD GHG Phase 1 final rule. ^{91} EPA's assessment of the statutory and other factors in selecting the final GHG standards is found in section II.G of this preamble, and further discussion of our statutory authority in support of all the revised compliance provisions is found throughout section III of this preamble.
^{91} 76 FR 57129-57130, September 15, 2011.

A. Summary of Key Clean Air Act Provisions
Title II of the Clean Air Act provides for comprehensive regulation of emissions from mobile sources, authorizing EPA to regulate emissions of air pollutants from all mobile source categories, including motor vehicles under CAA section 202(a). To understand the scope of permissible regulation, we first must understand the scope of the regulated sources. CAA section 216(2) defines “motor vehicle” as “any self-propelled vehicle designed for transporting persons or property on a street or highway.” ^{92} Congress has intentionally and consistently used the broad term “any self-propelled vehicle” since the Motor Vehicle Air Pollution Control Act of 1965 to include vehicles propelled by various fuels ( e.g., gasoline, diesel, or hydrogen), or systems of propulsion, whether they be ICE engine, hybrid, or electric motor powertrains. ^{93} The subjects of this rulemaking all fit that definition: they are self-propelled, via a number of different powertrains, and they are designed for transporting persons or property on a street or highway. The Act's focus is on reducing emissions from classes of motor vehicles and the “requisite technologies” that could feasibly reduce those emissions, giving appropriate consideration to cost of compliance and lead time.
^{92} EPA subsequently interpreted this provision through a 1974 rulemaking. 39 FR 32611 (September 10, 1974), codified at 40 CFR 85.1703. The regulatory provisions establish more detailed criteria for what qualifies as a motor vehicle, including criteria related to speed, safety, and practicality for use on streets and ways. The regulation, however, does not draw any distinctions based on whether the vehicle emits pollutants or its powertrain.
^{93} The Motor Vehicle Air Pollution Act of 1965 defines “motor vehicle” as “any self-propelled vehicle designed for transporting persons or property on a street or highway.” Public Lae 89-272, 79 Stat. 992, 995 (October 20, 1965). See also, e.g., 116 S. Cong. Rec. at 42382 (December 18, 1970) (Clean Air Act Amendments of 1970—Conference Report) (“The urgency of the problems require that the industry consider, not only the improvement of existing technology, but also alternatives to the internal combustion engine and new forms of transportation.”).
Congress delegated to the Administrator the authority to identify available control technologies, and it did not place any restrictions on the types of emission reduction technologies EPA could consider, including different powertrain technologies. By contrast, other parts of the Act explicitly limit EPA's authority by powertrain type, ^{94} so Congress's conscious decision not to do so when defining “motor vehicle” in section 216 further highlights the breadth of EPA's standard-setting authority for such vehicles. As we explain further below, Congress did place some limitations on EPA's standard-setting under CAA section 202(a), ^{95} but these limitations generally did not restrict EPA's authority to broadly regulate motor vehicles to any particular vehicle type or emissions control technology.
^{94} See CAA section 213 (authorizing EPA to regulate “non-road” engines”), 216(10) (defining non-road engine to “mean[ ] an internal combustion engine”). Elsewhere in the Act, Congress also specified specific technological controls, further suggesting its decision to not to limit the technological controls EPA could consider in section 202(a)(1)-(2) was intentional. See, e.g., CAA section 407(d) (“Units subject to subsection (b)(1) for which an alternative emission limitation is established shall not be required to install any additional control technology beyond low NO X burners.”).
^{95} See, e.g., CAA section 202(a)(4)(A) (“no emission control device, system, or element of design shall be used in a new motor vehicle or new motor vehicle engine for purposes of complying with requirements prescribed under this subchapter if such device, system, or element of design will cause or contribute to an unreasonable risk to public health, welfare, or safety in its operation or function”). In addition, Congress established particular limitations for discrete exercises of CAA section 202(a)(1) authority which are not at issue in this rulemaking. See, e.g., CAA section 202(a)(3)(A)(i) (articulating specific parameters for standards for heavy-duty vehicles applicable to emissions of certain criteria pollutants).
We turn now to section 202(a)(1)-(2), which provides the statutory authority for the final GHG standards in this action. Section 202(a)(1) directs the Administrator to set “standards applicable to the emission of any air pollutant from any class or classes of new motor vehicles or new motor vehicle engines, which in his judgment cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare.” This core directive has remained the same, with only minor edits, since Congress first enacted it in the Motor Vehicle Pollution Control Act of 1965. ^{96} Thus the first step when EPA regulates emissions from motor vehicles is a finding (the “endangerment finding”), either as part of the initial standard setting or prior to it, that the emission of an air pollutant from a class or classes of new motor vehicles or new motor engines causes or contributes to air pollution which may reasonably be anticipated to endanger public health or welfare.
^{96} Public Law 89-272.
The statute directs EPA to define the class or classes of new motor vehicles for which the Administrator is making the endangerment finding. ^{97} EPA for decades has defined “classes” subject to regulation according to their weight and function. This is consistent with both Congress's functional definition of a “motor vehicle,” as discussed previously in this section, and Congress's explicit contemplation of functional classes or categories. See CAA section 202(b)(3)(C) (defining “heavy-duty vehicle” with reference to function and weight), 202(a)(3)(A)(ii) (“the Administrator may base such classes or categories on gross vehicle weight, horsepower, type of fuel used, or other appropriate factors.”). ^{98}
^{97} See CAA section 202(a)(1) (“The Administrator shall by regulation prescribe . . . standards applicable to the emission of any air pollutant from any class or classes of new motor vehicles or new motor vehicle engines, which in his judgment cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare.” (emphasis added)), 202(a)(3)(A)(ii) (“the Administrator may base such classes or categories on gross vehicle weight, horsepower, type of fuel used, or other appropriate factors” (emphasis added)).
^{98} Section 202(a)(3)(A)(ii) applies to standards established under section 202(a)(3), not to standards otherwise established under section 202(a)(1). However, we think it nonetheless provides guidance on what kinds of classifications and categorizations Congress generally thought were appropriate.
In 2009, EPA made an endangerment finding for GHG and explicitly stated that “[t]he new motor vehicles and new motor vehicle engines . . . addressed are: Passenger cars, light-duty trucks, motorcycles, buses, and medium and heavy-duty trucks.” 74 FR 66496, 66537 (December 15 2009). 99 100 Then EPA reviewed the GHG emissions data from “new motor vehicles” and determined that these classes of vehicles do contribute to air pollution that may reasonably be anticipated to endanger public health and welfare. The endangerment finding was made with regard to pollutants—in this case, GHGs—emitted from “any class or classes of new motor vehicles or new motor vehicle engines.” This approach—of identifying a class or classes of vehicles that contribute to endangerment—is how EPA has always implemented the statute.
^{99} EPA considered this list to be a comprehensive list of the new motor vehicle classes. See id. (“This contribution finding is for all of the CAA section 202(a) source categories.”); id. at 66544 (“the Administrator is making this finding for all classes of new motor vehicles under CAA section 202(a)”). By contrast, in making an endangerment finding for GHG emissions from aircraft, EPA limited the endangerment finding to engines used in specific classes of aircraft (such as civilian subsonic jet aircraft with maximum take off mass greater than 5,700 kilograms). 81 FR 54421, August 15, 2016.
^{100} EPA is not reopening the 2009 or any other prior endangerment finding in this action. Rather, we are discussing the 2009 endangerment finding to provide the reader with helpful background information relating to this action.
For purposes of establishing GHG emissions standards, EPA has regarded new heavy-duty trucks (also known as heavy-duty vehicles) as its own class and has then made further sub-categorizations based on weight and functionality in promulgating standards for the air pollutant, as further elaborated in section II of this preamble. ^{101} EPA's class and categorization framework allows the Agency to recognize real-world variations in the lead time and costs of emissions control technology for different vehicle types. It also ensures that consumers can continue to access a wide variety of vehicles to meet their mobility needs, while enabling continued emissions reductions for all vehicle types, including to the point of completely preventing emissions where appropriate.
^{101} See NRDC v. EPA, 655 F.2d 318, 338 (D.C. Cir. 1981) (the Court held that “the adoption of a single particulate standard for light-duty diesel vehicles was within EPA's regulatory discretion.”).
In setting standards, CAA section 202(a)(1) requires that any standards promulgated thereunder “shall be applicable to such vehicles and engines for their useful life (as determined under [CAA section 202(d)], relating to useful life of vehicles for purposes of certification), whether such vehicle and engines are designed as complete systems or incorporate devices to prevent or control such pollution.” ^{102} In other words, Congress specifically determined that EPA's standards could be based on a wide array of technologies, including technologies for the engine and for the other (non-engine) parts of the vehicle, technologies that “incorporate devices” on top of an existing motor vehicle system as well as technologies that are “complete systems” and that may involve a complete redesign of the vehicle. Congress also determined that EPA could base its standards on both technologies that “prevent” the pollution from occurring in the first place—such as the zero emissions technologies considered in this rule—as well as technologies that “control” or reduce the pollution once produced. ^{103}
^{102} See also Engine Mfrs. Ass'n v. S. Coast Air Quality Mgmt. Dist., 541 U.S. 246, 252-53 (2004) (As stated by the Supreme Court, a standard is defined as that which “is established by authority, custom, or general consent, as a model or example; criterion; test . . . . This interpretation is consistent with the use of ‘standard’ throughout Title II of the CAA . . . . to denote requirements such as numerical emission levels with which vehicles or engines must comply . . . , or emission-control technology with which they must be equipped.”).
^{103} Pollution prevention is a cornerstone of the Clean Air Act. The title of 42 U.S.C. Chapter 85 is “Air Pollution Prevention and Control”; see also CAA section 101(a)(3), (c). One of the very earliest vehicle pollution control technologies (one which is still in use by some vehicles) was exhaust gas recirculation, which reduces in-cylinder temperature and oxygen concentration, and, as a result, engine-out NO X emissions from the vehicles. More recent examples of pollution prevention technologies include cylinder deactivation, and electrification technologies such as idle start-stop or ZEVs.
While emission standards set by the EPA under CAA section 202(a)(1) generally do not mandate use of particular technologies, they are technology-based, as the levels chosen must be premised on a finding of technological feasibility. EPA must therefore necessarily identify potential control technologies, evaluate the rate each technology could be introduced, and its cost. Standards promulgated under CAA section 202(a) are to take effect only “after such period as the Administrator finds necessary to permit the development and application of the requisite technology, giving appropriate consideration to the cost of compliance within such period.” ^{104} This reference to “cost of compliance” means that EPA must consider costs to those entities which are directly subject to the standards, ^{105} but “does not mandate consideration of costs to other entities not directly subject to the standards.” ^{106} Given the prospective nature of standard-setting and the inherent uncertainties in predicting the future development of technology, Congress entrusted to EPA the authority to assess issues of technical feasibility and availability of lead time to implement new technology. Such determinations are “subject to the restraints of reasonableness” but “EPA is not obliged to provide detailed solutions to every engineering problem posed in the perfection of [a particular device]. In the absence of theoretical objections to the technology, the agency need only identify the major steps necessary for development of the device, and give plausible reasons for its belief that the industry will be able to solve those problems in the time remaining. The EPA is not required to rebut all speculation that unspecified factors may hinder `real world' emission control.” ^{107}
^{104} CAA section 202(a)(2); see also NRDC v. EPA, 655 F. 2d 318, 322 (D.C. Cir. 1981).
^{105} Motor & Equipment Mfrs. Ass'n Inc. v. EPA, 627 F. 2d 1095, 1118 (D.C. Cir. 1979).
^{106} Coal. for Responsible Regulation v. EPA, 684 F.3d 120, 128 (D.C. Cir. 2012).
^{107} NRDC, 655 F. 2d at 328, 333-34.
Although standards under CAA section 202(a)(1) are technology-based, they are not based exclusively on technological capability. Pursuant to the broad grant of authority in section 202, when setting GHG emission standards for HD vehicles, EPA must consider certain factors and may also consider other relevant factors and has done so previously when setting such standards. For instance, in HD GHG Phase 1 and Phase 2, EPA explained that when acting under this authority EPA has considered such issues as technology effectiveness, ability of the vehicle to perform its work for vehicle purchasers, its cost (including for manufacturers and for purchasers), the lead time necessary to implement the technology, and, based on this, the feasibility of potential standards; the impacts of potential standards on emissions reductions; the impacts of standards on oil conservation and energy security; the impacts of standards on fuel savings by vehicle operators; the impacts of standards on the heavy-duty vehicle industry; as well as other relevant factors such as impacts on safety. ^{108} EPA has considered these factors in this rulemaking as well.
^{108} 81 FR 73512, October 25, 2016; 76 FR 57129-30, September 15, 2011.
Rather than specifying levels of stringency in section 202(a)(1)-(2), Congress directed EPA to determine the appropriate level of stringency for the standards taking into consideration the statutory factors therein. EPA has clear authority to set standards under CAA section 202(a)(1)-(2) that are technology forcing when EPA considers that to be appropriate, ^{109} but is not required to do so. Section 202(a)(2) requires the Agency to give appropriate consideration to cost and lead time necessary to allow for the development and application of such technology. The breadth of this delegated authority is particularly clear when contrasted with section 202(b), (g), (h), which identifies specific levels of emissions reductions on specific timetables for past model years. ^{110} In determining the level of the standards, CAA section 202(a) does not specify the degree of weight to apply to each factor such that the Agency has authority to choose an appropriate balance among factors and may decide how to balance stringency and technology considerations with cost and lead time. 111 112
^{109} Indeed, the D.C. Circuit has repeatedly cited NRDC v. EPA , which construes section 202(a)(1), as support for EPA's actions when EPA acted pursuant to other provisions of section 202 or Title II that are explicitly technology forcing. See, e.g., NRDC v. Thomas, 805 F. 2d 410, 431-34 (D.C. Cir. 1986) (section 202 (a)(3)(B), 202 (a)(3)(A)); Husqvarna AB v. EPA, 254 F. 3d 195, 201 (D.C. Cir. 2001) (section 213(a)(3)); Nat'l Petroleum and Refiners Ass'n v. EPA, 287 F. 3d 1130, 1136 (D.C. Cir. 2002) (section 202(a)(3)).
^{110} See also CAA 202(a)(3)(A).
^{111} See Sierra Club v. EPA, 325 F.3d 374, 378 (D.C. Cir. 2003) (even where a provision is technology-forcing, the provision “does not resolve how the Administrator should weigh all [the statutory] factors”); Nat'l Petrochemical and Refiners Ass'n v. EPA, 287 F.3d 1130, 1135 (D.C. Cir. 2002) (EPA decisions, under CAA provision authorizing technology-forcing standards, based on complex scientific or technical analysis are accorded particularly great deference); see also Husqvarna AB v. EPA, 254 F. 3d 195, 200 (D.C. Cir. 2001) (great discretion to balance statutory factors in considering level of technology-based standard, and statutory requirement “to [give appropriate] consideration to the cost of applying . . . technology” does not mandate a specific method of cost analysis); Hercules Inc. v. EPA, 598 F. 2d 91, 106 (D.C. Cir. 1978) (“In reviewing a numerical standard we must ask whether the agency's numbers are within a zone of reasonableness, not whether its numbers are precisely right.”).
^{112} Additionally, with respect to regulation of vehicular GHG emissions, EPA is not “required to treat NHTSA's . . . regulations as establishing the baseline for the [section 202(a) standards].” Coal. for Responsible Regulation, 684 F.3d at 127 (noting that the section 202(a) standards provide “benefits above and beyond those resulting from NHTSA's fuel-economy standards”).
We now turn from section 202(a) to overview several other sections of the Act relevant to this action. CAA section 202(d) directs EPA to prescribe regulations under which the “useful life” of vehicles and engines shall be determined for the purpose of setting standards under CAA section 202(a)(1). For HD highway vehicles and engines, CAA section 202(d) establishes “useful life” minimum values of 10 years or 100,000 miles, whichever occurs first, unless EPA determines that greater values are appropriate. ^{113}
^{113} In 1983, EPA adopted useful life periods to apply for HD engines criteria pollutant standards (48 FR 52170, November 16, 1983). The useful life mileage for heavy HD engines criteria pollutant standards was subsequently increased for 2004 and later model years (62 FR 54694, October 21, 1997). In the GHG Phase 2 rule (81 FR 73496, October 25, 2016), EPA set the same useful life periods to apply for HD engines and vehicles greenhouse gas emission standards, except that the spark-ignition HD engine standards and the standards for model year 2021 and later light HD engines apply over a useful life of 15 years or 150,000 miles, whichever comes first. In the Heavy Duty (HD) 2027 Low NO X final rule (HD2027 rule) (88 FR 4359, January 24, 2023), EPA lengthened useful life periods for all 2027 and later model year HD engines criteria pollutant standards. See also 40 CFR 1036.104(e), 1036.108(d), 1037.105(e), and 1037.106(e).
Additional sections of the Act provide authorities relating to compliance, including certification, testing, and warranty. Under section 203 of the CAA, sales of vehicles are prohibited unless the vehicle is covered by a certificate of conformity, and EPA issues certificates of conformity pursuant to section 206 of the CAA. Compliance with standards is required not only at certification but throughout a vehicle's useful life, so that testing requirements may continue post-certification. To assure each engine and vehicle complies during its useful life, EPA may apply an adjustment factor to account for vehicle emission control deterioration or variability in use. EPA also establishes the test procedures through which compliance with the CAA emissions standards is measured. The regulatory provisions for demonstrating compliance with emissions standards have been successfully implemented for decades, including through our Averaging, Banking, and Trading (ABT) program. ^{114}
^{114} EPA's consideration of averaging in standard-setting dates back to 1985. 50 FR 1060, March 15, 1985 (“Emissions averaging, of both particulate and oxides of nitrogen emissions from heavy-duty engines, is allowed beginning with the 1991 model year. Averaging of NO, emissions from light-duty trucks is allowed beginning in 1988.”). The availability of averaging as a compliance flexibility has an even earlier pedigree. See 48 FR 33456, July 21, 1983 (EPA's first averaging program for mobile sources); 45 FR 79382, November 28, 1980 (advance notice of proposed rulemaking investigating averaging for mobile sources). We have included banking and trading in our rules dating back to 1990. 55 FR 30584, July 26, 1990 (“This final rule announces new programs for banking and trading of particulate matter and oxides of nitrogen emission credits for gasoline-, diesel- and methanol-powered heavy-duty engines.”). See section III.A of this preamble and RTC 10.2 for further background on the structure and history of our ABT program's regulations, including consistency with CAA section 206.
Under CAA section 207, manufacturers are required to provide emission-related warranties. The emission-related warranty period for HD engines and vehicles under CAA section 207(i) is “the period established by the Administrator by regulation (promulgated prior to November 15, 1990) for such purposes unless the Administrator subsequently modifies such regulation.” For HD vehicles, part 1037 currently specifies that the emission-related warranty for Light HD vehicles is 5 years or 50,000 miles and for Medium HD and Heavy HD vehicles is 5 years or 100,000 miles, and specifies the components covered for such vehicles. ^{115} Section 207 of the CAA also grants EPA broad authority to require manufacturers to remedy nonconformity if EPA determines there are a substantial number of noncomplying vehicles. These warranty and remedy provisions have also been applied for decades under our regulations, including where compliance occurs through use of ABT provisions. Further discussion of these sections of the Act, including as they relate to the compliance provisions we are finalizing, is found in section III of the preamble.
^{115} See 40 CFR 1037.120.

B. Authority To Consider Technologies in Setting Motor Vehicle GHG Standards
Having provided an overview of the key statutory authorities for this action, we now elaborate on the specific issue of the types of control technology that are to be considered in setting standards under section 202(a)(1)-(2). EPA's position on this issue is consistent with our position in the HD Phase 1 and Phase 2 GHG rules, and with the historical exercise of the Agency's section 202(a)(1)-(2) authority over the last five decades. That is, EPA's standard-setting authority under section 202(a)(1)-(2) is not a priori limited to consideration of specific types of emissions control technology; rather, in determining the level of the standards, the agency must account for emissions control technologies that are available or will become available for the relevant model year. ^{116} In this rulemaking, EPA has accounted for a wide range of emissions control technologies, including advanced ICE engine and vehicle technologies ( e.g., engine, transmission, drivetrain, aerodynamics, tire rolling resistance improvements, the use of low carbon fuels like CNG and LNG, and H2-ICE), hybrid technologies ( e.g., HEV and PHEV), and ZEV technologies ( e.g., BEV and FCEV). ^{117} These include technologies applied to motor vehicles with ICE (including hybrid powertrains) and without ICE, and a range of electrification across the technologies.
^{116} For example, in 1998, EPA published regulations for the voluntary National Low Emission Vehicle (NLEV) program that allowed LD motor vehicle manufacturers to comply with tailpipe standards for cars and light-duty trucks more stringent than that required by EPA in exchange for credits for such low emission and zero emission vehicles. 63 FR 926, January 7, 1998. In 2000, EPA promulgated LD Tier 2 emission standards which built upon “the recent technology improvements resulting from the successful [NLEV] program.” 65 FR 6698, February 10, 2000.
^{117} ZEV technologies include BEV and FCEV. Both rely on an electric powertrain to achieve zero tailpipe emissions. FCEVs run on hydrogen fuel, while BEVs are plugged in for charging.
In response to the proposed rulemaking, the agency received numerous comments on this issue, specifically on our consideration of BEV and FCEV technologies. Regulated entities generally offered support for the agency's legal authority to consider such technologies, noting that they themselves were also considering varying levels of these technologies in their own product plans. Their comments relating to these technologies, and those of most stakeholders, were more technical and policy in nature, for example, relating to the pace at which manufacturers could adopt and deploy such technologies in the real world or the pace at which enabling infrastructure could be deployed. We address these comments in detail in section II of this preamble and have revised the standards from those proposed after consideration of comments.
A few commenters, however, alleged that the agency lacked statutory authority altogether to consider BEV and FCEV technologies because they believed the Act limited EPA to considering only technologies applicable to ICE vehicles or to technologies that reduce, rather than altogether prevent, pollution. EPA disagrees. The constraints they would impose have no foundation in the statutory text, are contrary to the statutory purpose, are undermined by a substantial body of statutory and legislative history, and are inconsistent with how the agency has applied the statute in numerous rulemakings over five decades. The following discussion elaborates our position on this issue; further discussion is found in Chapter 2.1 of the RTC.
The text of the Act directly addresses this issue and provides unambiguous authority for EPA to consider all motor vehicle technologies, including a range of electrified technologies such as fully-electrified vehicle technologies without an ICE that achieve zero vehicle tailpipe emissions ( e.g., BEVs), fuel cell electric vehicle technologies that run on hydrogen and achieve zero tailpipe emissions ( e.g., FCEVs), plug-in hybrid partially electrified technologies, and other ICE vehicles across a range of electrification. As described earlier in this section, the Act directs EPA to prescribe emission standards for “motor vehicles,” which are defined broadly in CAA section 216(2) and do not exclude any forms of vehicle propulsion. The Act then directs EPA to promulgate emission standards for such vehicles, “whether such vehicles and engines are designed as complete systems or incorporate devices to prevent or control such pollution,” based on the “development and application of the requisite technology.” There is no question that electrified technologies, including various ICE, hybrid, BEV, and FCEV technologies, meet all of these specific statutory criteria. They apply to “motor vehicles”, are systems and incorporate devices that “prevent” and “control” emissions, ^{118} and qualify as “technology.”
^{118} The statute emphasizes that the agency must consider emission reductions technologies regardless of “whether such vehicles and engines are designed as complete systems or incorporate devices to prevent or control such pollution.” CAA section 202(a)(1); see also CAA section 202(a)(4)(B) (describing conditions for “any device, system, or element of design” used for compliance with the standards); Truck Trailer Manufacturers Ass'n, Inc v. EPA, 17 F.4th 1198, 1202 (D.C. Cir. 2021) (the statute “created two categories of complete motor vehicles. Category one: motor vehicles with built-in pollution control. Category two: motor vehicles with add-in devices for pollution control.”). While the statute does not define “system,” section 202 does use the word expansively, to include “vapor recovery system[s]” (CAA section 202(a)(5)(A)), “new power sources or propulsion systems” (CAA section 202(e)), and onboard diagnostics systems (CAA section 202(m)(1)(D)). In any event, the intentional use of the phrase “complete systems” shows that Congress expressly contemplated as methods of pollution control not only add-on devices (like catalysts that control emissions after they are produced by the engine), but wholesale redesigns of the motor vehicle and the motor vehicle engine to prevent and reduce pollution. Many technologies that reduce vehicle GHG emissions today can be characterized as systems that reduce or prevent GHG emissions, including advanced engine designs in ICE and hybrid vehicles; integration of electric drive units in hybrids, PHEVs, BEV and FCEV designs; high voltage batteries and controls; redesigned climate control systems improvements, and more.
While the statute also imposes certain specific limitations on EPA's consideration of technology, none of these statutory limitations preclude the consideration of electrified technologies, a subset of electrified technologies, or any other technologies that achieve zero vehicle tailpipe emissions. Specifically, the statute states that the following technologies cannot serve as the basis for the standards: first, technologies which cannot be developed and applied within the relevant time period, giving appropriate consideration to the cost of compliance; and second, technologies that “cause or contribute to an unreasonable risk to public health, welfare, or safety in its operation or function.” CAA section 202(a)(2), (4). ^{119} The statute does not contain any other exclusions or limitations relevant to the Phase 3 model years. EPA has undertaken a comprehensive assessment of the statutory factors, further discussed in section II of the preamble and throughout the RIA and the RTC, and has found that the CAA plainly authorizes the consideration of these technologies, including BEV and FCEV technologies, at the levels that support the modeled potential compliance pathway to achieve the final standards.
^{119} In addition, under section 202(a)(3)(A), EPA must promulgate under section 202(a)(1) certain criteria pollutant standards for “classes or categories” of heavy-duty vehicles that “reflect the greatest degree of emission reduction achievable through the application of technology which the Administrator determines will be available . . . giving appropriate consideration to cost, energy, and safety factors associated with the application of such technology.” EPA thus lacks discretion to base such standards on a technological pathway that reflects less than the greatest degree of emission reduction achievable for the class (giving consideration to cost, energy, and safety). In other words, where EPA has identified available control technologies that can completely prevent pollution and otherwise comport with the statute, the agency lacks the discretion to rely on less effective control technologies to set weaker standards that achieve fewer emissions reductions. And while section 202(a)(3)(A) does not govern any GHG standards, which are established only under section 202(a)(1)-(2), we think it is also informative as to the breadth of EPA's authority under those provisions.
Having discussed what the statutory text does say, we note what the statutory text does not say. Nothing in section 202(a)(1)-(2) distinguishes technologies that prevent vehicle tailpipe emissions from other technologies as being suitable for consideration in establishing the standards. Moreover, nothing in the statute suggests that certain kinds of electrified technologies are appropriate for consideration while other kinds of electrified technologies are not. While some commenters suggest that battery electric vehicles or fuel cell vehicles represent a difference in kind from all other emissions control technologies, that is simply untrue. As we explain in section II and RIA Chapter 1, electrified technologies comprise a large range of motor vehicle technologies. In fact, all new motor vehicles manufactured in the United States today have some degree of electrification and rely on electrified technology to control emissions.
ICE vehicles are equipped with alternators that generate electricity and batteries that store such electricity. The electricity in turn is used for numerous purposes, such as starting the ICE and powering various vehicle electronics and accessories. More specifically, electrified technology is a vital part of controlling emissions on all new motor vehicles produced today: motor vehicles rely on electronic control modules (ECM) for controlling and monitoring their operation, including the fuel mixture (whether gasoline fuel, diesel fuel, natural gas fuel, etc.), ignition timing, transmission, and emissions control system. In enacting the Clean Air Act Amendments of 1990, Congress itself recognized the great importance of this particular electrified technology for emissions control in certain vehicles. ^{120} It would be impossible to drive any ICE vehicle produced today or to control the emissions of such a vehicle without such electrified technology.
^{120} See CAA 207(i)(2) (for light-duty vehicles, statutorily designating “specified major emission control components” subject to extended warranty provisions as including “an electronic emissions control unit”). Congress also designated by statute “onboard emissions diagnostic devices” as “specified major emission control components”; OBD devices also rely on electrified technology.
Indeed, many of the extensive suite of technologies that manufacturers have devised for controlling emissions rely on electrified technology and do so in a host of different ways. These include technologies that improve the efficiency of the engine and system of propulsion, such as the ECMs, electronically-controlled fuel injection (for all manners of fuel, including but not limited to gasoline, diesel, natural gas, propane, and hydrogen), and automatic transmission; technologies that reduce the amount of ICE engine use such as engine stop-start technology and other idle reduction technologies; add-on technologies to control pollution after it has been generated by the engine, such as gasoline three-way catalysts, and diesel selective catalytic reduction and particulate filters that rely on electrified technology to control and monitor their performance; non-engine technologies that that rely on electrified systems to improve vehicle aerodynamics; technologies related to vehicle electricity production, such as high efficiency alternators; and engine accessory technologies that increase the efficiency of the vehicle, such as electric coolant pumps, electric steering pumps, and electric air conditioning compressors. Because electrified technologies reduce emissions, EPA has long considered them relevant for regulatory purposes under Title II. For example, EPA has relied on various such technologies to justify the feasibility of the standards promulgated under section 202(a), ^{121} promulgated requirements and guidance related to testing involving such technologies under section 206, ^{122} required manufacturers to provide warranties for them under section 207, ^{123} and prohibited their tampering under section 203. ^{124}
^{121} See, e.g., LD 2010 rule, 88 FR 25324, May 7, 2010; HD GHG Phase 2 rule, 81 FR 73478, October 25, 2016.
^{122} See, e.g., HD GHG Phase 1 rule, 76 FR 57106, September 15, 2011.
^{123} See, e.g., HD GHG Phase 1 rule, 76 FR 57106, September 15, 2011.
^{124} See, e.g., HD GHG Phase 1 rule, 76 FR 57106, September 15, 2011.
Certain vehicles rely to a greater extent on electrification as an emissions control strategy. These include (1) hybrid vehicles, which rely principally on an ICE to power the wheels, but also derive propulsion from an on-board electric motor, which can charge batteries through regenerative braking, and feature a range of larger batteries than non-hybrid ICE vehicles; ^{125} (2) plug-in hybrid vehicles (PHEV), which have an even larger battery that can also be charged by plugging it into an outlet and can rely principally on electricity for propulsion, along with an ICE; (3) hydrogen fuel-cell vehicles (FCEV), which are fueled by hydrogen to produce electricity to power the wheels and have a range of larger battery sizes; ^{126} and (4) battery electric vehicles (BEV), which rely entirely on plug-in charging and the battery to provide the energy for propulsion. Manufacturers may also choose to sell different models of the same vehicle with different levels of electrification. In many but not all cases, ^{127} electrified technologies are systems which “prevent” (partially or completely) the emission of pollution from the motor vehicle engine. ^{128} Nothing in the statute indicates that EPA is limited from considering any of these technologies. For instance, nothing in the statute says that EPA may only consider emissions control technologies with a certain kind or level of electrification, e.g., where the battery is smaller than a certain size, where the energy derived from the battery is less than a certain percentage of total vehicle energy, where certain energy can be recharged by plugging the vehicle into an outlet as opposed to running the internal combustion engine, etc. The statute does not differentiate in terms of such details, but simply commands EPA to adopt emissions standards based on the “development and application of the requisite technology, giving appropriate consideration to the cost of compliance within such period.”
^{125} Hybrid vehicles include both mild hybrids, which have a relatively smaller battery and can use the electric motor to supplement the propulsion provided by the ICE, as well as strong hybrids, which have a relatively larger battery and can drive for limited distances entirely on battery power.
^{126} As explained in section II.D.3.ii, the instantaneous power required to move a FCEV can come from either the fuel cell, the battery, or a combination of both. Interactions between the fuel cells and batteries of a FCEV can be complex and may vary based on application.
^{127} For example, some vehicles also use electrified technology to preheat the catalyst and improve catalyst efficiency especially when starting in cold temperatures.
^{128} CAA section 202(a)(1).
EPA's interpretation also accords the primary purpose and operation of section 202(a), which is to reduce emissions of air pollutants from motor vehicles that are anticipated to endanger public health or welfare. ^{129} This statutory purpose compels EPA to consider available technologies that reduce emissions of air pollutants most effectively, including vehicle technologies that result in no vehicle tailpipe emissions of GHGs and completely “prevent” such emissions. ^{130} And, given Congress's directive to reduce air pollution, it would make little sense for Congress to have authorized EPA to consider technologies that achieve 99 percent pollution reduction (for example, as some PM filter technologies do to control criteria pollutants), but not 100 percent pollution reduction. At minimum, the statute allows EPA to consider such technologies. Today, many of the available technologies that can achieve the greatest emissions control are those that rely on greater levels of electrification, with ZEV technologies capable of completely preventing vehicle tailpipe emissions.
^{129} See also Coal. for Responsible Regulation, Inc. v. EPA, 684 F.3d 102, 122 (D.C. Cir. 2012), aff'd in part, rev'd in part sub nom. Util. Air Regulation. Grp. v. EPA, 573 U.S. 302 (2014), and amended sub nom. Coal. for Responsible Regulation, Inc. v. EPA, 606 F. App'x 6 (D.C. Cir. 2015) (the purpose of section 202(a) is “utilizing emission standards to prevent reasonably anticipated endangerment from maturing into concrete harm”).
^{130} CAA section 202(a)(1); see also CAA section 202(a)(4)(B) directing EPA to consider whether a technology “eliminates the emission of unregulated pollutants” in assessing its safety.
The surrounding statutory context further highlights that Congress intended section 202 to lead to reductions to the point of complete pollution prevention. Consistent with section 202(a)(1), section 101(c), of the Act states), “A primary goal of this chapter is to encourage or otherwise promote reasonable Federal, State, and local governmental actions, consistent with the provisions of this chapter, for pollution prevention.” ^{131} Section 101(a)(3) further explains the term “air pollution prevention” (as contrasted with “air pollution control”) to mean “the reduction or elimination, through any measures, of the amount of pollutants produced or created at the source.” That is to say, EPA is not limited to requiring small reductions, but instead has authority to consider technologies that may entirely prevent the pollution from occurring in the first place. Congress also repeatedly amended the Act to itself impose extremely large reductions in motor vehicle pollution. ^{132} Similarly, Congress prescribed EPA to set standards achieving specific, numeric levels of emissions reductions (which in many instances cumulatively amount to multiple orders of magnitude), ^{133} while explicitly stating that EPA's 202(a) authority allowed the agency to go still further. ^{134} Consistent with these statutory authorities, prior rulemakings have also required very large emissions reductions, including to the point of completely preventing certain types of emissions. ^{135}
^{131} Clean Air Act Amendments, 104 Stat. 2399, 2468, November 15, 1990; see also 42 U.S.C. chapter 85 (“AIR POLLUTION PREVENTION AND CONTROL”).
^{132} See, e.g., CAA section 202(a)(3)(A)(i) (directed EPA to promulgate standards that “reflect the greatest decree of emission reduction achievable” for certain pollutants).
^{133} CAA section 202(a), (g)-(h), (j).
^{134} See, e.g., CAA section 202(b)(1)(C) (“The Administrator may promulgate regulations under subsection (a)(1) revising any standard prescribed or previously revised under this subsection . . . . Any revised standard shall require a reduction of emissions from the standard that was previously applicable.”), (i)(3)(B)(iii) (“Nothing in this paragraph shall prohibit the Administrator from exercising the Administrator's authority under subsection (a) to promulgate more stringent standards for light-duty vehicles and light-duty . . . at any other time thereafter in accordance with subsection (a).”).
^{135} See, e.g., 31 FR 5171, March 30, 1966 (“No crankcase emissions shall be discharged into the ambient atmosphere from any new motor vehicle or new motor vehicle engine subject to this subpart.”).
This reading of the statute accords with the practical reality of administering an effective emissions control program, a matter in which the Agency has developed considerable expertise over the last five decades. Such a program is necessarily predicated on the continuous development of increasingly effective emissions control technologies. In determining the standards, EPA appropriately considers updated data and analysis on pollution control technologies, without a priori limiting its consideration to a particular set of technologies. Given the continuous development of pollution control technologies since the early days of the CAA, this approach means that EPA has routinely considered new and projected technologies developed or refined since the time of the CAA's enactment, including for instance, electrification technologies. ^{136} The innumerable technologies on which EPA's standards have been premised, or which EPA has otherwise incentivized, are presented in summary form later in this section and then in full in section 2 of the RTC. This approach is inherent in the statutory text of section 202(a)(2): in requiring EPA to consider lead time for the development and application of technology before standards may take effect, Congress directed EPA to consider future technological advancements and innovation rather than limiting the Agency to only those technologies in place at the time the statute was enacted. In the report accompanying the Senate bill for the 1965 legislation establishing section 202(a), the Senate Committee wrote that it “believes that exact standards need not be written legislatively but that the Secretary should adjust to changing technology.” ^{137} This forward-looking regulatory approach keeps pace with real-world technological developments that have the potential to reduce emissions and comports with congressional intent and precedent. ^{138}
^{136} For example, when EPA issued its Tier 2 standards for light-duty and medium-duty vehicles in 2000, the Agency established “bins” of standards in addition to a fleet average requirement. 65 FR 6698, 6734-6735, February 10, 2000. One “bin” was used to certify electric vehicles that have zero criteria pollutant emissions. Id. Under the Tier 2 program, a manufacturer could designate which bins their different models fit into, and the weighted average across bins was required to meet the fleet average standard. Id. at 6746.
^{137} S. Rep. No. 89-192, at 4 (1965). Likewise, the report accompanying the House bill stated that “the objective of achieving fully effective control of motor vehicle pollution will not be accomplished overnight. [T]he techniques now available provide only a partial reduction in motor vehicle emissions. For the future, better methods of control will clearly be needed; the committee expects that [the agency] will accelerate its efforts in this area.” H.R. Rep. No. 89-899, at 4 (1965).
^{138} See also NRDC, 655 F.2d at 328 (EPA is “to project future advances in pollution control capability. It was `expected to press for the development and application of improved technology rather than be limited by that which exists today.' ;” To do otherwise would thwart congressional intent and leave EPA “unable to set pollutant levels until the necessary technology is already available.”).
For all these reasons, EPA's consideration of electrified technologies and technologies that prevent vehicle tailpipe emissions in establishing the standards is unambiguously permitted by the Act; indeed, given the Act's purpose to use technology to prevent air pollution from motor vehicles, and the agency's factual finding based on voluminous record evidence that BEV and FCEV technologies are the most effective and available technologies for doing so, the Agency's consideration of such technologies is compelled by the statute. Because the statutory text in its context is plain, we could end our interpretive inquiry here. However, we have taken the additional step of reviewing the extensive statutory and legislative history regarding the kinds of technology, including electric vehicle technology, that Congress expected EPA to consider in exercising its section 202(a) authority. Over six decades of congressional enactments and statements provide overwhelming support for EPA's consideration of electrified technologies and technologies that prevent vehicle tailpipe emissions in establishing the final standards.
As explained, section 202 does not specify or expect any particular type of motor vehicle propulsion system to remain prevalent, and it was clear to Congress as early as the 1960s that ICE vehicles might be inadequate to achieve the country's air quality goals. In 1967, the Senate Committees on Commerce and Public Works held five days of hearings on “electric vehicles and other alternatives to the internal combustion engine,” which Chairman Magnuson opened by saying “The electric [car] will help alleviate air pollution and urban congestion. The consumer will benefit from instant starting, reduced maintenance, long life, and the economy of electricity as a fuel. . . . The electric car does not mean a new way of life, but rather it is a new technology to help solve the new problems of our age.” ^{139} In a 1970 message to Congress seeking a stronger CAA, President Nixon stated he was initiating a program to develop “an unconventionally powered, virtually pollution free automobile” because of the possibility that “the sheer number of cars in densely populated areas will begin outrunning the technological limits of our capacity to reduce pollution from the internal combustion engine.” ^{140}
^{139} Electric Vehicles and Other Alternatives to the Internal Combustion Engine: Joint Hearings before the Comm. On Commerce and the Subcomm. On Air and Water Pollution of the Comm. On Pub. Works, 90th Cong. (1967).
^{140} Richard Nixon, Special Message to the Congress on Environmental Quality (February 10, 1970), https://www.presidency.ucsb.edu/documents/special-message-the-congress-environmental-quality.
Since the earliest days of the CAA, Congress has also emphasized that the goal of section 202 is to address air quality hazards from motor vehicles, not to simply reduce emissions from internal combustion engines to the extent feasible. In the Senate Report accompanying the 1970 CAA Amendments, Congress made clear the EPA “is expected to press for the development and application of improved technology rather than be limited by that which exists” and identified several “unconventional” technologies that could successfully meet air quality-based emissions targets for motor vehicles. ^{141} In the 1970 amendments, Congress further demonstrated its recognition that developing new technology to ensure that pollution control keeps pace with economic development is not merely a matter of refining the ICE, but requires considering new types of motor vehicle propulsion. ^{142} Congress provided EPA with authority to fund the development of “low emission alternatives to the present internal combustion engine” as well as a program to encourage Federal purchases of “low-emission vehicles.” See CAA section 104(a)(2) (previously codified as CAA section 212). ^{143} Congress also adopted section 202(e) expressly to grant the Administrator discretion under certain conditions regarding the certification of vehicles and engines based on “new power sources or propulsion system[s],” that is to say, power sources and propulsion systems beyond the existing internal combustion engine and fuels available at the time of the statute's enactment. As the D.C. Circuit stated in 1975, “We may also note that it is the belief of many experts—both in and out of the automobile industry—that air pollution cannot be effectively checked until the industry finds a substitute for the conventional automotive power plant—the reciprocating internal combustion ( i.e., `piston') engine. . . . It is clear from the legislative history that Congress expected the Clean Air Amendments to force the industry to broaden the scope of its research—to study new types of engines and new control systems.” ^{144}
^{141} S. Rep. No. 91-1196, at 24-27 (1970).
^{142} In the lead up to enactment of the CAA of 1970, Senator Edmund Muskie, Chair of the Subcommittee on Environmental Pollution of the Committee on Public Works (now the Committee on Environment and Public Works), stated that “[t]he urgency of the problems required that the industry consider, not only the improvement of existing technology, but also alternatives to the internal combustion engine and new forms of transportation.” 116 Cong. Rec. 42382, December 18, 1970.
^{143} A Senate report on the Federal Low-Emission Vehicle Procurement Act of 1970, the standalone legislation that ultimately became the low-emission vehicle procurement provisions of the 1970 CAA, stated that the purpose of the bill was to direct Federal procurement to “stimulate the development, production and distribution of motor vehicle propulsion systems which emit few or no pollutants” and explained that “the best long range method of solving the vehicular air pollution problem is to substitute for present propulsion systems a new system which, during its life, produces few pollutants and performs as well or better than the present powerplant.” S. Rep. No. 91-745, at 1, 4 (March 20, 1970).
^{144} Int'l Harvester Co. v. Ruckelshaus, 478 F.2d 615, 634-35 (D.C. Cir. 1975).
Moreover, Congress believed that the motor vehicle emissions program could achieve enormous emissions reductions, not merely modest ones, through the application and development of ever-improving emissions control technologies. For example, the Clean Air Act of 1970 required a 90 percent reduction in emissions, which was to be achieved with less lead time than this rule provides for its final standards. ^{145} Ultimately, although the industry was able to meet the standard using ICE technologies, the standard drove development of entirely new engine and emission control technologies such as exhaust gas recirculation and catalytic converters, which in turn required a switch to unleaded fuel and the development of massive new infrastructure (not present at the time the standard was finalized) to support the distribution of this fuel. ^{146}
^{145} See Clean Air Act Amendments of 1970, Public Law 91-604, at sec. 6, 84 Stat. 1676, 1690, December 31, 1970 (amending section 202 of the CAA and directing EPA to issue regulations to reduce carbon monoxide and hydrocarbons from LD vehicles and engines by 90 percent in MY 1975 compared to MY 1970 and directing EPA to issue regulations to reduce NO X emissions from LD vehicles and engines by 90 percent in MY 1976 when compared with MY 1971).
^{146} Since the new vehicle technology required on all model year 1975-76 vehicles would be poisoned by the lead in the existing gasoline, it required the rollout of an entirely new fuel to the marketplace with new refining technology needed to produce it. It was not possible for refiners to make the change that quickly to all of the nation's gasoline production, so this in turn required installation of a new parallel fuel distribution infrastructure to distribute and new retail infrastructure to dispense unleaded gasoline to the customers with MY1975 and later vehicles while still supplying leaded gasoline to the existing fleet. In order to ensure availability of unleaded gasoline across the nation, all refueling stations with sales greater than 200,000 gallons per year were required to dispense the new unleaded gasoline. In 1974, less than 10 percent of all gasoline sold was unleaded gasoline, but by 1980 nearly 50 percent was unleaded. See generally Richard G. Newell and Kristian Rogers, The U.S. Experience with the Phasedown of Lead in Gasoline, Resources for the Future (June 2003), available at https://web.mit.edu/ckolstad/www/Newell.pdf.
Since that time, Congress has continued to emphasize the importance of technology development to achieving the goals of the CAA. ^{147} In the 1990 amendments, Congress determined that evolving technologies could support further order of magnitude reductions in emissions. For example, the statutory Tier I light-duty standards required (on top of the existing standards) a further 30 percent reduction in nonmethane hydrocarbons, 60 percent reduction in NO X , and 80 percent reduction in PM for diesel vehicles. The Tier 2 light-duty standards in turn required passenger vehicles to be 77 to 95 percent cleaner. ^{148} Congress instituted a clean fuel vehicles program to promote further progress in emissions reductions, which also applied to motor vehicles as defined under section 216, see CAA section 241(1), and explicitly defined motor vehicles qualifying under the program as including vehicles running on an alternative fuel or “power source (including electricity),” CAA section 241(2). ^{149}
^{147} For example, in the lead up to the CAA Amendments of 1990, the House Committee on Energy and Commerce reported that “[t]he Committee wants to encourage a broad range of vehicles using electricity, improved gasoline, natural gas, alcohols, clean diesel fuel, propane, and other fuels.” H. Rep. No. 101-490, at 283 (May 17, 1990).
^{148} See 65 FR 28, February 10, 2000).
^{149} See also CAA section 246(f)(4) (under the clean fuels program, directing the Administrator to issue standards “for Ultra-Low Emission Vehicles (ULEV's) and Zero Emissions Vehicles (ZEV's)” and to conform certain such standards “as closely as possible to standards which are established by the State of California for ULEV and ZEV vehicles in the same class.”).
Congress also directed EPA to phase-in certain section 202(a) standards in CAA section 202(g)-(j). ^{150} In doing so, Congress recognized that certain technologies, while extremely potent at achieving lower emissions, would be difficult for the entire industry to adopt all at once. Rather, it would be more appropriate for the industry to gradually implement the standards over a longer period of time. This is directly analogous to EPA's assessment in this final rule, which finds that industry will gradually shift to more effective emissions control technologies over a period of time. Generally speaking, phase-ins, fleet averages, and ABT all are means of addressing the question, recognized by Congress in section 202, of how to achieve emissions reductions to protect public health when it may be difficult (or less preferable for manufacturers) to implement a stringency increase across the entire fleet simultaneously.
^{150} CAA section 202(g) required a phase in for LD trucks up to 6,000 lbs GVWR and LD vehicles beginning with MY 1994 for emissions of nonmethane hydrocarbons (NMHC), carbon monoxide (CO), nitrogen oxides (NO X ), and particular matter (PM). These standards phased in over several years. Similarly, CAA section 202(h) required standards to be phased in beginning with MY 1995 for LD trucks of more than 6,000 lbs GVWR for the same pollutants. CAA section 202(i) required EPA to study whether further emission reductions should be required with respect to MYs after January 1, 2003 for certain vehicles. CAA section 202(j) required EPA to promulgate regulations applicable to CO emissions from LD vehicles and LD trucks when operated under “cold start” conditions i.e., when the vehicle is operated at 20 degrees Fahrenheit. Congress directed EPA to phase in these regulations beginning with MY 1994 under Phase I, and to study the need for further reductions of CO and the maximum reductions achievable for MY 2001 and later LD vehicles and LD trucks when operated in cold start conditions. In addition, Congress specified that any “revision under this subchapter may provide for a phase-in of the standard.” CAA 202(b)(1)(C).
Similar to EPA's ABT program, these statutory phase-in provisions also evaluated compliance with respect to a manufacturers' fleet of vehicles over the model year. More specifically, CAA section 202(g)-(j) each required a specified percentage of a manufacturer's fleet to meet a specified standard for each model year ( e.g., 40 percent of a manufacturer's sales volume must meet certain standards by MY 1994). This made the level of a manufacturer's production over a model year a core element of the standard. In other words, the form of the standard mandated by Congress in these sections recognized that pre-production certification would be based on a projection of production for the upcoming model year, with actual compliance with the required percentages not demonstrated until after the end of the model year. Compliance was evaluated not only with respect to individual vehicles, but with respect to the fleet as a whole. EPA's ABT provisions use this same approach, adopting a similar, flexible form, that also makes the level of a manufacturer's production a core element of the standard and evaluates compliance at the fleet level, in addition to at the individual vehicle level.
In enacting the Energy Independence and Security Act of 2007, Congress also recognized the possibility that fleet-average standards also recognized the possibility of fleet-average standards. The statute barred Federal agencies from acquiring “a light duty motor vehicle or medium duty passenger vehicle that is not a low greenhouse gas emitting vehicle.” ^{151} It directed the Administrator to promulgate guidance on such “low greenhouse gas emitting vehicles,” but explicitly prohibited vehicles from so qualifying “if the vehicle emits greenhouse gases at a higher rate than such standards allow for the manufacturer's fleet average grams per mile of carbon dioxide-equivalent emissions for that class of vehicle, taking into account any emissions allowances and adjustment factors such standards provide.” ^{152} Congress thus explicitly contemplated the possibility of motor vehicle GHG standards with a fleet average form. ^{153}
^{151} 42 U.S.C. 13212(f)(2)(A).
^{152} 42 U.S.C. 13212(f)(3)(C) (emphasis added).
^{153} 42 U.S.C. 13212 does not specifically refer back to CAA section 202(a). However, we think it is plain that Congress intended for EPA in implementing section 13212 to consider relevant CAA section 202(a) standards as well as standards issued by the State of California. See 42 U.S.C. 13212(f)(3)(B) (“In identifying vehicles under subparagraph (A), the Administrator shall take into account the most stringent standards for vehicle greenhouse gas emissions applicable to and enforceable against motor vehicle manufacturers for vehicles sold anywhere in the United States.”). As explained in the text, EPA has historically set fleet average standards under CAA section 202(a) for certain emissions from motor vehicles. Under section 209(b) of the Clean Air Act, EPA may also authorize the State of California to adopt and enforce its own motor vehicle emissions standards subject the statutory criteria. California has also adopted certain fleet average motor vehicle emissions standards. No other Federal agency or State government has authority to establish emissions standards for new motor vehicles, although certain States may choose to adopt standards identical to California's pursuant to CAA section 177.
The recently-enacted IRA ^{154} demonstrates Congress's continued resolve to drive down emissions from motor vehicles through the application of the entire range of available technologies, and specifically highlights the importance of ZEV technologies. The IRA “reinforces the longstanding authority and responsibility of [EPA] to regulate GHGs as air pollutants under the Clean Air Act,” ^{155} and “the IRA clearly and deliberately instructs EPA to use” this authority by “combin[ing] economic incentives to reduce climate pollution with regulatory drivers to spur greater reductions under EPA's CAA authorities.” ^{156} To assist with this, as described in section II and RIA Chapter 1, the IRA provides a number of economic incentives for HD ZEVs and the infrastructure necessary to support them, and specifically affirms Congress's previously articulated statements that non-ICE technologies will be a key component of achieving emissions reductions from the mobile source sector, including the HD sector. ^{157} The legislative history reflects that “Congress recognizes EPA's longstanding authority under CAA section 202 to adopt standards that rely on zero emission technologies, and Congress expects that future EPA regulations will increasingly rely on and incentivize zero-emission vehicles as appropriate.” ^{158} These developments further confirm that the focus of CAA section 202 is on application of innovative technologies to reduce vehicular emissions, and not on the means by which vehicles are powered. This statutory and legislative history, beginning with the 1960s and through the recently enacted IRA, demonstrate Congress's historical and contemporary commitment to reducing motor vehicle emissions through the application of increasingly advanced technologies. Consistent with Congress's intent and this legislative history, EPA's rulemakings have taken the same approach, basing standards on ever-evolving technologies that have allowed for enormous emissions reductions. As required by the Act, EPA has consistently considered the lead time and costs of control technologies in determining whether and how they should be included in the technological packages for the standards, along with other factors that affect the real-world adoption or impacts of the technologies as appropriate. Over time, EPA's motor vehicle emission standards have been based on and stimulated the development of a broad set of advanced technologies—such as electronic fuel injection systems, gasoline catalytic convertors, diesel particulate filters, diesel NO X reduction catalysts, gasoline direct injection fuel systems, and advanced transmission technologies—which have been the building blocks of heavy-duty vehicle designs and have yielded not only lower pollutant emissions, but improved vehicle performance, reliability, and durability. Many of these technologies did not exist when Congress first granted EPA's section 202(a) authority in 1965, but these technologies nonetheless have been successfully adopted and reduced emissions by multiple orders of magnitude.
^{154} Inflation Reduction Act, Public Law 117-169, 136 Stat. 1818, (2022), available at https://www.congress.gov/117/bills/hr5376/BILLS-117hr5376enr.pdf.
^{155} 168 Cong. Rec. E868-02 (daily ed. August 12, 2022) (statement of Rep. Pallone, Chairman of the House Energy and Commerce Committee).
^{156} 168 Cong. Rec. E879-02, at 880 (daily ed. August 26, 2022) (statement of Rep. Pallone).
^{157} See Inflation Reduction Act, Public Law 117-169, at §§ 13204, 13403, 13404, 13501, 13502, 50142-50145, 50151-50153, 60101-60104, 70002 136 Stat. 1818, (2022), available at https://www.congress.gov/117/bills/hr5376/BILLS-117hr5376enr.pdf.
^{158} 168 Cong. Rec. E879-02, at 880 (daily ed. August 26, 2022) (statement of Rep. Pallone).
As previously discussed, beginning in 2011, EPA has set HD vehicle and engine standards under section 202(a)(1)-(2) for GHGs. ^{159} Manufacturers have responded to these standards over the past decade by continuing to develop and deploy a wide range of technologies, including more efficient engine designs, transmissions, aerodynamics, tires, and air conditioning systems that contribute to lower GHG emissions, as well as vehicles based on methods of propulsion beyond diesel- and gasoline-fueled ICE vehicles, including ICE running on alternative fuels, as well as various levels of electrified vehicle technologies from mild hybrids, to strong hybrids, and up through battery electric vehicles and fuel-cell vehicles.
^{159} 76 FR 57106, September 15, 2011 (establishing first ever GHG standards for heavy-duty vehicles).
EPA has long established performance-based emission standards that anticipate the use of new and emerging technologies. ^{160} In both the HD Phase 1 ^{161} and Phase 2 standards, ^{162} as in this rule, EPA specifically considered the availability of electrified technologies, including ZEV technologies. At the time of the HD Phase 1 and 2 rules, EPA determined based on the record before it that certain technologies, namely more electrified technologies like PHEV and BEV as well as FCEV, should not be part of the technology packages to support the feasibility of the standards given that they were not expected to be sufficiently available during the model years for those rules, giving consideration to lead time and costs of compliance. Instead, recognizing the possible future use of those technologies and their potential to achieve very large emissions reductions, EPA incentivized their development and deployment through advanced technology credit multipliers, which give manufacturers additional ABT credits for producing such vehicles. In this rule, EPA continues to consider these technologies, and based on the updated record, finds that such technologies will be available at a reasonable cost during the timeframe for this rule, and therefore has included them in the technology packages to support the level of the standards under the modeled potential compliance pathway.
^{160} For example, in EPA's 2016 HD Phase 2 regulations, the Agency explained that the emission standards were “predicated on use of both off-the-shelf technologies and emerging technologies that are not yet in widespread use” and which we projected would “require manufacturers to make extensive use of these technologies.” 81 FR 73478, October 25, 2016. See also, e.g., NRDC v. Thomas, 805 F. 2d 410, 431 (D.C. Cir. 1986) (upholding EPA rule where EPA identified trap oxidizers technology as the basis for compliance with numerical PM standard); Nat'l Petroleum and Refiners Ass'n v. EPA, 287 F. 3d 1130, 1136 (D.C. Cir. 2002) (NO X absorbers and catalyzed particulate filters as basis for complying with numerical NOs and PM standards.).
^{161} The Phase 1 GHG program set standards for MY 2014 through 2018 and later. See 76 FR 57106 (September 15, 2011).
^{162} The Phase 2 GHG program set standards for MY 2021 through 2027 and later for combination tractors, vocational vehicles, HD pickup trucks and vans, and engines.
The analysis of the statutory text, purpose and history, as well as EPA's history of implementing the statute, demonstrate that the agency must, or at a minimum may, appropriately consider available electrified technologies that completely prevent emissions in determining the final standards. In this rulemaking, EPA has done so. The agency has made the necessary predictive judgments as to potential technological developments that can support the feasibility of the final standards and also as to the availability of supporting charging and refueling infrastructure and critical minerals necessary to support those technological developments, as applicable. In making these judgments, EPA has adhered to the long-standing approach established by the D.C. Circuit, identifying a reasonable sequence of future developments, noting potential difficulties, and explaining how they may be obviated within the lead time afforded for compliance. EPA has also consulted with other organizations with relevant expertise such as the Departments of Energy and Transportation, including through careful consideration of their reports and related analytic work reflected in the administrative record for this rulemaking.
Although the standards are supported by the Administrator's predictive judgments regarding pollution control technologies and the modeled potential compliance pathway, we emphasize that the final standards are not a mandate for a specific type of technology. They do not legally or de facto require a manufacturer to follow a specific technological pathway to comply. Consistent with our historical practice, EPA is finalizing performance-based standards that provide compliance flexibility to manufacturers. While EPA projects that manufacturers may comply with the standards through the use of certain technologies, including a mix of advanced ICE vehicles, BEVs, and FCEVs, manufacturers may select any technology or mix of technologies that would enable them to meet the final standards.
These choices are real and valuable to manufacturers, as attested to by the historical record. The real-world results of our prior rulemakings make clear that industry sometimes chooses to comply with our standards in ways that the Agency did not anticipate, presumably because it is more cost-effective for them to do so. In other words, while EPA sets standards that are feasible based on our modeling of potential compliance pathways, manufacturers may find what they consider to be better pathways to meet the standards and may opt to follow those pathways instead.
For example, in promulgating the 2010 LD GHG rule, EPA modeled a technology pathway for compliance with the MY 2016 standards. In actuality, manufacturers diverged from EPA's projections across a wide range of technologies, instead choosing their own technology pathways best suited for their fleets. 163 164 For example, EPA projected greater penetration of dual-clutch transmissions than ultimately occurred in the MY 2016 fleet; by contrast, use of 6-speed automatic transmissions was twice what EPA had predicted. Both transmission technologies represented substantial improvements over the existing transmission technologies, with the manufacturers choosing which specific technology was best suited for their products and customers. Looking specifically at electrification technologies, start-stop systems were projected at 45 percent and were used in 10 percent of vehicles, while strong hybrids were projected to be 6.5 percent of the MY 2016 fleet and were actually only 2 percent. ^{165} Notwithstanding these differences between EPA's projections and actual manufacturer decisions, the industry as a whole was not only able to comply with the standards during the period of those standards (2012-2016), but to generate substantial additional credits for overcompliance. ^{166}
^{163} See EPA Memorandum to the docket for this rulemaking, “ Comparison of EPA CO2 Reducing Technology Projections between 2010 Light-duty Vehicle Rulemaking and Actual Technology Production for Model Year 2016”.
^{164} Similarly, in our 2001 final rule promulgating heavy-duty nitrogen oxide (NO X ) and particulate matter (PM) standards, for example, we predicted that manufacturers would comply with the new nitrogen oxide (NO X ) standards through the addition of NO X absorbers or “traps.” 66 FR 5002, 5036 (January 18, 2001) (“[T]he new NO X standard is projected to require the addition of a highly efficient NO X emission control system to diesel engines.”). We stated that we were not basing the feasibility of the standards on selective catalytic reduction (SCR) noting that SCR “was first developed for stationary applications and is currently being refined for the transient operation found in mobile applications.” Id. at 5053. However, industry's approach to complying with the 2001 standards ultimately included the use of SCR for diesel engines. We also projected that manufacturers would comply with the final PM standards through the addition of PM traps to diesel engines; however, industry was able to meet the PM standards without the use of PM traps or any other PM aftertreatment systems.
^{165} Although in 2010, EPA overestimated technology penetrations for strong hybrids, in 2012, we underestimated technology penetrations for PEVs, projecting on 1 percent penetration by MY 2021, while actual sales exceeded 4 percent. Compare 2012 Rule RIA, Table 3.5-22 with 2022 Automotive Trends Report, Table 4.1.
^{166} See 2022 Automotive Trends Report, Fig. ES-8 (industry generated credits each year from 2012-2015 and generated net credits for the years 2012-2016).
In support of the final standards, EPA has also performed additional modeling demonstrating that the standards can be met in multiple ways. As discussed in section II.F.4 of the final rule preamble, while our modeled potential compliance pathway includes a mix of ICE vehicles, BEV, and FCEV technologies, we also evaluated additional examples of potential technology packages and potential compliance pathways that include only additional vehicles with ICE across a range of electrification. These additional examples of technology pathways also support the feasibility of the final standards and show that the final standards may be met without producing additional ZEVs to comply with this rule. ^{167}
^{167} We stress, however, that these additional pathways are not necessary to justify this rulemaking; the statute requires EPA to demonstrate that the standards can be met by the development and application of technology, but it does not require the agency to identify multiple technological solutions to the pollution control problem before mandating more stringent standards. That EPA has done so in this rulemaking, identifying a wide array of technologies capable of further reducing emissions, only highlights the feasibility of the standards and the significant practical flexibilities manufacturers have to attain compliance. We observe that some past standards have been premised on the application of a single known technology at the time, such as the catalytic converter. See Int'l Harvester v. Ruckelshaus, 478 F.2d 615, 625 (D.C. Cir. 1973) (in setting standards for light duty vehicles, the Court upheld EPA's reliance on a single kind of technology); see also 36 FR 12657 (1971) (promulgating regulations for light duty vehicles based on the catalytic converter).

C. Response to Other Comments Raising Legal Issues
In this section, EPA summarizes our responses to certain other comments relating to our legal authority. These include three comments relating to our legal authority to consider certain technologies discussed in section I.B: whether this rule implicates the major questions doctrine, whether EPA has authority for its Averaging, Banking, and Trading (ABT) program, and whether EPA erred in considering heavy-duty ZEVs as part of the same class as other heavy-duty vehicles for GHG regulation. These comments were raised only by entities not regulated by this rule. This section also addresses a comment regarding whether the 4-year lead time and 3-year stability requirements in CAA section 202(a)(3)(C) apply to this rule. We separately discuss our legal authority and rationale for battery durability and warranty in section III.B of the preamble.
Major questions doctrine. While many commenters recognized EPA's legal authority to adopt the final GHG standards, certain commenters claimed that this rule asserts a novel and transformative exercise of regulatory power that implicates the major questions doctrine and exceeds EPA's legal authority. These arguments were intertwined with arguments challenging EPA's consideration of electrified technologies. Some commenters claimed that the agency's decision to do so and the resulting GHG standards would mandate a large increase in electric vehicles. According to these commenters, this in turn would cause indirect impacts, including relating to issues allegedly outside EPA's traditional areas of expertise, such as to the petroleum refining industry, electricity transmission and distribution infrastructure, grid reliability, and US national security.
EPA does not agree that this rule implicates the major questions doctrine as that doctrine has been elucidated by the Supreme Court in West Virginia v. EPA and related cases. ^{168} The Court has made clear that the doctrine is reserved for extraordinary cases involving assertions of highly consequential power beyond what Congress could reasonably be understood to have granted. This is not such an extraordinary case in which congressional intent is unclear. Here, EPA is acting within the heartland of its statutory authority and faithfully implementing Congress's precise direction and intent.
^{168} W. Virginia v. EPA, 142 S. Ct. 2587, 2605, 2610 (2022).
First, as we explain in section I.A-B of the preamble, the statute provides clear congressional authorization for EPA to consider updated data on pollution control technologies—including BEV and FCEV technologies—and to determine the emission standards accordingly. In section 202(a), Congress made the major policy decision to regulate air pollution from motor vehicles. Congress also prescribed that EPA should accomplish this mandate through a technology-based approach, and it plainly entrusted to the Administrator's judgment the evaluation of pollution control technologies that are or will become available given the available lead-time and the consequent determination of the emission standards. In the final rule, the Administrator determined that a wide variety of technologies exist to further control GHGs from HD vehicles—including various ICE, hybrid, and ZEV technologies such as BEVs and FCEVs—and that such technologies could be applied at a reasonable cost to achieve significant reductions of GHG emissions that contribute to the ongoing climate crisis. These subsidiary technical and policy judgments were clearly within the Administrator's delegated authority.
Second, the agency is not invoking a novel authority. As described previously in this section, EPA has been regulating emissions from motor vehicles based upon the availability of feasible technologies to reduce vehicle emissions for over five decades. EPA has specifically regulated GHG emissions from heavy-duty vehicles since 2011. Our rules, including this rule and the HD Phase 1 and HD Phase 2 rules, have consistently considered available technology to reduce or prevent emissions of the relevant pollutant, including technologies to reduce or completely prevent GHGs. Our consideration of ZEV technologies specifically has a long pedigree, beginning with the 1998 National Low Emission Vehicle (NLEV) program. Further, the administrative record here indicates the industry will likely choose to deploy an increasing number of vehicles with emissions control technologies such as BEV and FCEV, in light of new technological advances, the IRA and other government programs, as well as this rule. That the industry will continue to apply the latest technologies to reduce pollution is no different than how the industry has responded to EPA's rules for half a century. The agency's factual findings and resulting determination of the degree of stringency do not represent the exercise of a newfound power. Iterative increases to the stringency of an existing program based on new factual developments hardly reflect an unprecedented expansion of agency authority.
Not only does this rule not invoke any new authority, it also falls well within EPA's traditionally delegated powers. Through five decades of regulating vehicle emissions under the CAA, EPA has developed great expertise in the regulation of motor vehicle emissions, including specifically GHG emissions (see RIA Chapter 2.1). The agency's expertise is reflected in the comprehensive analyses present in the administrative record. The courts have recognized the agency's authority in this area. ^{169} The agency's analysis includes our assessment of available pollution control technologies; the design and application of a quantitative model (HD TRUCS) for assessing feasible rates of technology adoption; the economic costs of developing, applying, and using pollution control technologies; the context for deploying such technologies ( e.g., the supply of raw materials and components, and the availability of supporting charging and refueling infrastructure); the impacts of using pollution control technologies on emissions, and consequent impacts on public health, welfare, and the economy. While each rule necessarily deals with different facts, such as advances in new pollution control technologies at the time of that rule, the above factors are among the kinds of considerations that EPA regularly evaluates in its motor vehicle rules, including all our prior GHG rules.
^{169} See, e.g., Massachusetts v. EPA, 549 U.S. 497, 532 (2007) (“Because greenhouse gases fit well within the Clean Air Act's capacious definition of “air pollutant,” we hold that EPA has the statutory authority to regulate the emission of such gases from new motor vehicles.”).
Third, this rule does not involve decisions of vast economic and political importance exceeding EPA's delegated authority. To begin with, commenters err in characterizing this rule as an “EV mandate.” That is false as a legal matter and a practical matter. As a legal matter, this rule does not mandate that any manufacturer use any specific technology to meet the standards in this rule. And as a practical matter, as explained in section II.F.3 of the preamble and Chapter 1.4 of the RIA, manufacturers can adopt a wide array of technologies, including various ICE, hybrid, electric, and fuel-cell technologies, to comply with this rule. Specifically, EPA has identified several additional potential compliance pathways, including pathways without producing additional ZEVs to comply with this rule, that can be achieved in the lead-time provided and at a reasonable cost. Moreover, the adoption of additional control technologies, including ZEVs, are complementary to what the manufacturers are already doing regardless of this rule. As major HD vehicle manufacturers told EPA in their comments, they have already made considerable investments and shifted future product plans to focus on ZEV technologies, including in response to the significant incentives for ZEVs that Congress provided in the IRA, and they support EPA establishing the standards based on the increasing availability of ZEV technologies. Looking to the future under the No Action scenario, as shown in RIA Table 4-8, we project that by 2032 ZEVs will account for between 4.7 percent (long-haul tractors) and 30.1 percent (LHD vocational) of new HD vehicles, depending on regulatory group. The final rule builds on these industry trends. It will likely cause some heavy-duty manufacturers to adopt control technologies more rapidly than they otherwise would, and this will result in significant pollution reductions and large public health and welfare benefits. However, that is the entire point of section 202(a); that EPA and the regulated industry may be successful in achieving Congress's purposes does not mean the agency has exceeded its delegated authority.
The regulatory burdens of this rule are also reasonable and not different in kind from prior exercises of EPA's authority under section 202. The regulated community of heavy-duty vehicle manufacturers in this rule was also regulated by the earlier Phase 1 and Phase 2 rules. In terms of costs of compliance for regulated entities, EPA anticipates that the rule will result in aggregate cost savings for manufacturers, both in light of technological advances in ZEV technologies and the significant incentives provided by the IRA. When we assess the fleet average costs of compliance per HD vehicle during the year in which the program is fully phased-in, we also find relatively lower costs compared to Phase 2. ^{170} These costs, moreover, are a small fraction of the costs of new HD vehicles and small relative to what Congress itself accepted in enacting section 202. ^{171} The rule also does not create any other excessive regulatory burdens on regulated entities; for example, the rule does not require any manufacturer to shut down, or to curtail or delay production.
^{170} We further discuss costs in preamble sections IV and II.G, and we provide numerical comparisons of costs to the Phase 1 and 2 rules in section 2 of the RTC.
^{171} See Motor & Equip. Mfrs. Ass'n, Inc. v. EPA, 627 F.2d 1095, 1118 (DC Cir. 1979) (“Congress wanted to avoid undue economic disruption in the automotive manufacturing industry and also sought to avoid doubling or tripling the cost of motor vehicles to purchasers.”).
While section 202 does not require EPA to consider consumer costs, the agency recognizes that such costs, and consumer acceptance of new pollution control technologies more broadly, can affect the application of such technologies. As such, EPA carefully evaluated these issues. For purchasers of HD vehicles, we project a range of upfront costs, including savings for certain vehicle types. For all vehicle types, we expect that the final standards will be economically beneficial for purchasers because the lower operating costs during the operational life of the vehicle will offset the increase in upfront vehicle technology costs within the usual period of first ownership of the vehicle. Furthermore, purchasers will benefit from annual operating cost savings for each year after the payback occurs. EPA also carefully designed the final rule to avoid any other kinds of disruptions to purchasers. For example, we recognize that HD vehicles represent a diverse array of vehicles and use cases, and we carefully tailored the standards for each regulatory subcategory to ensure that purchasers could obtain the kinds of HD vehicles they need. We also recognized that HD vehicles require supporting infrastructure ( e.g., fueling and charging stations) to operate, and we accounted for sufficient lead-time for the development of that infrastructure, including private depot charging, public charging, and hydrogen refueling infrastructure. We also identified numerous industry standards and safety protocols to ensure the safety of HD vehicles, including BEVs and FCEVs.
We acknowledge the rule may have other impacts beyond those on regulated entities and their customers (for purposes of discussion here, referred to as “indirect impacts”). But indirect impacts are inherent in section 202 rulemakings, including past rulemakings going back half a century. As the DC Circuit has observed, in the specific context of EPA's Clean Air Act Title II authority to regulate motor vehicles, “[e]very effort at pollution control exacts social costs. Congress . . . made the decision to accept those costs.” ^{172} In EPA's long experience of promulgating environmental regulations, the presence of indirect impacts does not reflect the extraordinary nature of agency action, but rather the ordinary state of the highly interconnected and global supply chain for motor vehicles. In any event, EPA has considerable expertise in evaluating the broader social impacts of the agency's regulations, for example on public health and welfare, safety, energy, employment, and national security. Congress has recognized the agency's expertise in many of these areas, ^{173} and EPA has regularly considered such indirect impacts in our prior rules.
^{172} Motor & Equip. Mfrs. Ass'n, Inc. v. EPA, 627 F.2d 1095, 1118 (DC Cir. 1979); see also id. (“There is no indication that Congress intended section 202's cost of compliance consideration to embody social costs of the type petitioners advance,” and holding that the statute does not require EPA to consider antitrust concerns ); Coal. for Responsible Regul. Inc. v. EP A, 684 F.3d 102, 128 (DC Cir. 2012) (holding that the statute “does not mandate consideration of costs to other entities not directly subject to the proposed standards”); Massachusetts v. EPA, 549 U.S. 497, 534 (2007) (impacts on “foreign affairs” are not sufficient reason for EPA to decline making the endangerment finding under section 202(a)(1)).
^{173} See, e.g., CAA section 202(a)(1) (requiring EPA Administrator to promulgate standards for emissions from motor vehicles “which in his judgment cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare”), 202(a)(3)(A) (requiring the agency to promulgate certain motor vehicle emission standards “giving appropriate consideration to cost, energy, and safety factors associated with the application of such technology”), 203(b)(1) (authorizing the Administrator to “exempt any new motor vehicle or new motor vehicle engine” from certain statutory requirements “upon such terms and conditions as he may find necessary . . . for reasons of national security”), 312(a) (directing EPA to conduct a “comprehensive analysis of the impact of this chapter on the public health, economy, and environment of the United States”).
EPA carefully analyzed indirect impacts and coordinated with numerous Federal and other partners with relevant expertise, as described in sections ES.E and II of the preamble. ^{174} The consideration of many indirect impacts is included in our assessment of the rule's costs and-benefits. We estimate annualized net benefits of $13 billion through the year 2055 when assessed at a 2 percent discount rate (2022$). This number is actually smaller than the net benefits of the Phase 2 rule; it is also a small fraction when compared to the size of the heavy-duty industry itself, which is rapidly expanding. ^{175} and a tiny fraction of the size of the US economy. ^{176}
^{174} For example, we consulted with the following Federal agencies and workgroups on their relevant areas of expertise: National Highway Traffic Safety Administration (NHTSA) at the Department of Transportation (DOT), Department of Energy (DOE) including several national laboratories (Argonne National Laboratory (ANL), National Renewable Energy Laboratory (NREL), and Oak Ridge National Laboratory (ORNL)), United States Geological Survey (USGS) at the Department of Interior (DOI), Joint Office of Energy and Transportation (JOET), Federal Energy Regulatory Commission (FERC), Department of Commerce (DOC), Department of Defense (DOD), Department of State, Federal Consortium for Advanced Batteries (FCAB), and Office of Management and Budget (OMB). We also consulted with State and regional agencies, and we engaged extensively with a diverse set of stakeholders, including vehicle manufacturers, labor unions, technology suppliers, dealers, utilities, charging providers, environmental justice organizations, environmental organizations, public health experts, tribal governments, and other organizations.
^{175} See Precedence Research, Heavy Duty Trucks Market, https://www.precedenceresearch.com/heavy-duty-trucks-market (“The U.S. heavy duty trucks market size was valued at USD 52.23 billion in 2023 and is expected to reach USD 105.29 billion by 2032, growing at a CAGR of 8.10% from 2023 to 2032.”).
^{176} US GDP reached $25.46 trillion dollars in 2022. See Bureau of Economic Analysis, Gross Domestic Product, Fourth Quarter and Year 2022 (Second Estimate) (February 23, 2023), available at https://www.bea.gov/news/2023/gross-domestic-product-fourth-quarter-and-year-2022-third-estimate-gdp-industry-and .
EPA also carefully evaluated many indirect impacts outside of the net benefits assessment, and we identified no significant indirect harms and the potential for indirect benefits. Based on our analysis, EPA projects that this rulemaking will not cause significant adverse impacts on electric grid reliability or resource adequacy, that there will be sufficient battery production and critical minerals available to support increasing ZEV production including due to large anticipated increases in domestic battery and critical mineral production, that there will be sufficient lead-time to develop charging and hydrogen refueling infrastructure, and that the rule will have significant positive national security benefits. We also identified significant initiatives by the Federal government (such as the BIL and IRA), State and local government, and private firms, that complement EPA's final rule, including initiatives to reduce the costs to purchase ZEVs; support the development of domestic critical mineral, battery, and ZEV production; improve the electric grid; and accelerate the establishment of charging and hydrogen refueling infrastructure.
These and other kinds of indirect impacts, moreover, are similar in kind to the impacts of past EPA motor vehicle rules. For example, this rule may reduce the demand for gasoline and diesel for HD vehicles domestically and affect the petroleum refining industry, but that has been the case for all of EPA's past GHG vehicle rules, which also reduced demand for liquid fuels through advances in ICE engine and vehicle technologies and corresponding fuel efficiency. And while production of ZEVs does rely on a global supply chain, that is true for all motor vehicles, which rely extensively on imports, from raw materials like aluminum to components like semiconductors; addressing supply chain vulnerabilities is a key component of managing any significant manufacturing operation in today's global world. Further, while ZEVs may require supporting infrastructure to operate, the same is true for ICE vehicles; indeed, supporting infrastructure for ICE vehicles has changed considerably over time in response to environmental regulation, for example, with the elimination of lead from gasoline, the provisioning of diesel exhaust fluid (DEF) at truck stops to support selective catalytic reduction (SCR) technologies, and the introduction of low sulfur diesel fuel to support diesel particulate filter (DPF) technologies.
As with prior GHG vehicle rules, many indirect impacts are positive: ^{177} foremost, the significant benefits of mitigating climate change, which poses catastrophic risks for human health and the environment, water supply and quality, storm surge and flooding, electricity infrastructure, agricultural disruptions and crop failures, human rights, international trade, and national security. Other positive indirect impacts include reduced dependence on foreign oil and increased energy security and independence; increased regulatory certainty for domestic production of pollution control technologies and their components (including ZEVs, batteries, fuels cells, battery components, and critical minerals) and for the development of electric charging and hydrogen refueling infrastructure, with attendant benefits for employment and US global competitiveness in these sectors; and increased use of electric charging and potential for vehicle-to-grid technologies that can benefit electric grid reliability.
^{177} As noted, our use of “indirect impacts” in this section refers to impacts beyond those on regulated entities.
Moreover, many of the indirect impacts find close analogs in the impacts Congress itself recognized and accepted. For instance, in 1970 Congress debated whether to adopt standards that would depend heavily on platinum-based catalysts in light of a world-wide shortage of platinum, ^{178} and in the leadup to the 1977 and 1990 Amendments, Congress recognized that increasing use of three-way catalysts to control motor vehicle pollution risked relying on foreign sources of the critical mineral rhodium. ^{179} In each case, Congress nonetheless enacted statutory standards premised on this technology. Similarly, Congress recognized and accepted the potential for employment impacts caused by the Clean Air Act; it then chose to address such impacts not by limiting EPA's authority to promulgate motor vehicle rules, but by other measures, such as funding training and employment services for affected workers. ^{180}
^{178} See, e.g., Environmental Policy Division of the Congressional Research Service Volume 1, 93d Cong., 2d Sess., A Legislative History of the Clean Air Amendments of 1970 at 307 (Comm. Print 1974) (Senator Griffin opposed the vehicle emissions standards because the vehicle that had been shown capable of meeting the standards used platinum-based catalytic converters and “[a]side from the very high cost of the platinum in the exhaust system, the fact is that there is now a worldwide shortage of platinum and it is totally impractical to contemplate use in production line cars of large quantities of this precious material. . . .”).
^{179} See, e.g., 136 Cong. Rec. 5102-04 (1990) and 123 Cong. Rec. 18173-74 (1977) (In debate over both the 1977 and 1990 amendments to the Clean Air Act, some members of Congress supported relaxing NO X controls from motor vehicles due to concerns over foreign control of rhodium supplies); see also EPA, Tier 2 Report to Congress, EPA420-R-98-008, July 1998, p. E-13 (describing concerns about potential shortages in palladium that could result from the Tier 2 standards).
^{180} Public Law 101-549, at sec. 1101, amending the Job Training Partnership Act, 29 U.S.C. 1501 et seq. (since repealed).
In sum, the final rule is a continuation of what the Administrator has been doing for over fifty years: evaluate updated data on pollution control technologies and set emissions standards accordingly. The rule maintains the fundamental regulatory structure of the existing program and iteratively strengthens the GHG standards from its predecessor Phase 2 rule. The consequences of the rule are not different in kind, and in many key aspects, are smaller than those of Phase 2. And while the rule is associated with indirect impacts, EPA comprehensively assessed such impacts and found that the final rule does not cause significant indirect harms as alleged by commenters and on balance creates net benefits for society. We further discuss our response to the major questions doctrine comments in section 2.1 of the RTC.
ABT. Some commenters claim that the ABT program, or fleetwide averaging, or both, exceed EPA's statutory authority. As further explained in section III.A of the preamble, EPA has long employed fleetwide averaging and ABT compliance provisions. In upholding the first HD final rule that included an averaging provision, the D.C. Circuit rejected a petitioner's challenge to EPA's statutory authority for averaging. NRDC v. Thomas, 805 F.2d 410, 425 (D.C. Cir. 1986). ^{181} In the subsequent 1990 amendments, Congress, noting NRDC v. Thomas and EPA's ABT program, “chose not to amend the Clean Air Act to specifically prohibit averaging, banking and trading authority.” ^{182} “The intention was to retain the status quo,” i.e., EPA's existing authority to allow ABT and establish fleet average standards. ^{183} Since then, the agency has routinely used ABT in its motor vehicle programs, including in all of our motor vehicle GHG rules, and repeatedly considered the availability of ABT in determining the level of stringency of fleet average standards. Manufacturers have come to rely on ABT in developing their compliance plans. The agency did not reopen the ABT regulations in this rulemaking, except to make certain discrete changes discussed in section III.A of the preamble. Comments challenging the agency's authority for ABT regulations and use of fleet averaging are therefore beyond the scope of the rulemaking.
^{181} The court explained that “[l]acking any clear congressional prohibition of averaging, the EPA's argument that averaging will allow manufacturers more flexibility in cost allocation while ensuring that a manufacturer's overall fleet still meets the emissions reduction standards makes sense.” NRDC v. Thomas, 805 F.2d at 425.
^{182} 136 Cong. Rec. 35,367, 1990 WL 1222469, at *1.
^{183} 136 Cong. Rec. 35,367, 1990 WL 1222469, at *1; see also 136 Cong. Rec. 36,713, 1990 WL 1222468 at *1.
In any event, the CAA authorizes EPA to establish an ABT program and fleet average standards. ^{184} Section 202(a)(1) directs EPA to set standards “applicable to the emission of any air pollutant from any class or classes of new motor vehicles” that cause or contribute to harmful air pollution. The term “class or classes” refers expressly to groups of vehicles, indicating that EPA may set standards based on the emissions performance of the class as a whole, which is precisely what ABT enables. Moreover, as we detail in section II.G.2 of the preamble, consideration of ABT in standard setting relates directly to considerations of technical feasibility, cost, and lead time, the factors EPA is required to consider under CAA section 202(a)(2) in setting standards. For decades, EPA has found that considering ABT, particularly the averaging provisions, is consistent with the statute and affords regulated entities more flexibility in phasing in technologies in a way that is economically efficient, promotes the goals of the Act, supports vehicle redesign cycles, and responds to market fluctuations, allowing for successful deployment of new technologies and achieving emissions reductions at lower cost and with less lead time. ^{185}
^{184} As we explain in section II.G of this preamble, EPA relied on averaging, but not banking or trading, in supporting the feasibility of the standards.
^{185} Beyond the statute's general provisions regarding cost and lead time, Congress has also repeatedly endorsed the specific concept of phase-in of advanced emissions control technologies throughout section 202, which is analogous to ABT in that it considers a manufacturer's production volume and the performance of vehicles across the fleet in determining compliance. See discussion in section I.A of this preamble citing provisions including section 202(g)-(j), 202(b)(1)(C).
ABT and fleet average standards are also consistent with other provisions in Title II, including those related to compliance and enforcement in CAA sections 203, 206, and 207. Commenters who alleged inconsistency with the compliance and enforcement provisions fundamentally misapprehend the nature of EPA's HD GHG program and its ABT regulations, where compliance and enforcement do in fact apply to individual vehicles consistent with the statute. It is true that ABT allows manufacturers to meet emissions standards by offsetting emissions credits and debits for individual vehicles. However, individual vehicles must also continue to themselves comply with their own emissions limit, known as the Family Emission Limit (FEL). ^{186} Both the emission standard and FEL are specified in each vehicle's individual certificate of conformity, and apply both at certification and throughout that vehicle's useful life. As appropriate, EPA can suspend, revoke, or void certificates for individual vehicles. Manufacturers' warranties apply to individual vehicles. EPA and manufacturers perform testing on individual vehicles, and recalls can be implemented based on evidence of non-conformance by a substantial number of individual vehicles within the class. We further discuss our response to this comment, including detailed exposition of each of the relevant statutory provisions, in RTC 10.2.
^{186} See 40 CFR 1037.801 (adoption of FEL); 1037.105, 1037.106 (FEL appears on certificate of compliance). See generally RTC 10.2.1.d.
ZEVs as part of the regulated class. We now address related comments that EPA cannot consider averaging, especially of ZEVs, in supporting the feasibility of the standards. Some commenters allege that because ZEVs, in theory, do not emit GHGs, they cannot be part of the “class” of vehicles regulated by EPA under section 202(a)(1), and therefore EPA should not establish standards that consider manufacturers' ability to produce them. We disagree with these commenters' reading of the statute, and moreover, as we explain further below, their underlying factual premise—that ZEVs do not emit GHGs—is incorrect.
As discussed in section I.A of the preamble, Congress required EPA to prescribe standards applicable to the emission of any air pollutant from any class or classes of new motor vehicles, which in his judgment cause, or contribute to, air pollution which endangers public health and welfare. Congress defined “motor vehicles” by their function: “any self-propelled vehicle designed for transporting persons or property on a street or highway.” ^{187} Likewise, with regard to classes, Congress explicitly contemplated functional categories: “the Administrator may base such classes or categories on gross vehicle weight, horsepower, type of fuel used, or other appropriate factors.” ^{188} It is indisputable that ZEVs are “new motor vehicles” as defined by the statute and that they fall into the weight-based “classes” that EPA established with Congress's explicit support.
^{187} CAA section 216(2).
^{188} CAA section 202(a)(3)(A)(ii). This section applies to standards established under section 202(a)(3), not to standards otherwise established under section 202(a)(1). But it nonetheless provides guidance on what kinds of classifications and categorizations Congress thought were appropriate.
In making the GHG Endangerment Finding in 2009, EPA defined the “classes” of motor vehicles and engines as “Passenger cars, light-duty trucks, motorcycles, buses, and medium and heavy-duty trucks.” ^{189} Heavy-duty ZEVs fall within the class of heavy-duty trucks. EPA did not reopen the 2009 GHG Endangerment Finding in this rulemaking, and therefore comments on whether ZEVs are part of the “class” subject to GHG regulation are beyond the scope of this rulemaking.
^{189} 74 FR 66496, 66537, December 15, 2009.
Some commenters contend that ZEVs fall outside of EPA's regulatory reach under this provision because they do not cause, or contribute to, air pollution which endangers human health and welfare. That misreads the statutory text. As we explained previously in regard to ABT, section 202(a)(1)'s focus on regulating emissions from “class or classes” indicates that Congress was concerned with the air pollution generated by a class of vehicles, as opposed to from individual vehicles. Accordingly, Congress authorized EPA to regulate classes of vehicles, and EPA has concluded that the class of heavy-duty vehicles, as a whole causes or contributes to dangerous pollution. As noted, the class of heavy-duty vehicles includes ZEVs, along with ICE and hybrid vehicles. EPA has consistently viewed heavy-duty motor vehicles as a class of motor vehicles for regulatory purposes, including in the HD GHG Phase 1 and Phase 2 rules. As discussed in section I.A of the preamble, EPA has reasonably further subcategorized vehicles within the class based on weight and functionality to recognize real-world variations in emission control technology, ensure consumer access to a wide variety of vehicles to meet their mobility needs, and secure continued emissions reductions for all vehicle types.
These commenters also misunderstand the broader statutory scheme. Congress directed EPA to apply the standards to vehicles whether they are designed as complete systems or incorporate devices to prevent or control pollution. Thus, Congress understood that the standards may be premised on and lead to technologies that prevent pollution in the first place. It would be perverse to conclude that in a scheme intended to control the emissions of dangerous pollution, Congress would have prohibited EPA from premising its standards on controls that completely prevent pollution, while also permitting the agency to premise them on a technology that reduces 99 percent of pollution. Such a nonsensical reading of the statute would mean that the availability of technology that can reduce 99 percent of pollution could serve as the basis for highly protective standards, while the availability of a technology that completely prevents the pollution could not be relied on to set emission standards at all. Such a reading would also create a perverse safe harbor allowing polluting vehicles to be perpetually produced, resulting in harmful emissions and adverse impacts on public health, even where available technology permits the complete prevention of such emissions and adverse impacts at a reasonable cost. That result cannot be squared with section 202(a)(1)'s purpose to reduce emissions that “cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare,” ^{190} or with the statutory directive to not only “control” but also “prevent” pollution.
^{190} See also Coal. for Responsible Regul., 684 F. 3d at 122 (explaining that the statutory purpose is to “prevent reasonably anticipated endangerment from maturing into concrete harm”).
Commenters' suggestion that EPA define the class to exclude ZEVs would also be unreasonable and unworkable. Ex ante, EPA does not know which vehicles a manufacturer may produce and, without technological controls including add-on devices and complete systems, all of the vehicles have the potential to emit dangerous pollution. ^{191} Therefore, EPA establishes standards for the entire class of vehicles, based upon its consideration of all available technologies. It is only after the manufacturers have applied those technologies to vehicles in actual production that the pollution is prevented or controlled. To put it differently, even hypothetically assuming EPA could not set standards for vehicles that manufacturers intend to build as electric vehicles—a proposition which we do not agree with—EPA could still regulate vehicles manufacturers intend not to build as electric vehicles and that would emit dangerous pollution in the absence of EPA regulation. ^{192} When regulating those vehicles, Congress explicitly authorized EPA to premise its standards for those vehicles on a “complete system” technology that prevents pollution entirely, like ZEV technologies.
^{191} As noted, manufacturers in some cases choose to offer different models of the same vehicle with different levels of electrification. And it is the manufacturer who decides whether a given vehicle will be manufactured to produce no emissions, low emissions, or higher aggregate emissions controlled by add-on technology.
^{192} In other words, the additional ZEVs EPA projects in the modeled potential compliance pathway exist in the baseline case as pollutant-emitting vehicles with ICE. We further note that it would be odd for EPA to have authority to regulate a given class of motor vehicles—in this case heavy-duty motor vehicles—so long as those vehicles emit air pollution at the tailpipe, but to lose its authority to regulate those very same vehicles should they install emission control devices to limit such pollution or be designed to prevent the endangering pollution in the first place.
Finally, the commenters' argument is factually flawed. All vehicles, including ZEVs, ^{193} do in fact produce vehicle emissions. For example, all ZEVs produce emissions from brake and tire wear, as discussed in RIA Chapter 4. Furthermore, ZEVs have air conditioning units, which may produce GHG emissions from leakages, and these emissions are subject to regulation under the Act. Thus, even under the commenter's reading of the statute, ZEVs would be part of the class for GHG regulation. ^{194} We further address this issue in RTC 10.2.1.f, where we also discuss the related contention that ZEVs cannot be part of the same class because electric and ICE powertrains are fundamentally different.
^{193} As discussed in the Executive Summary, we use the term ZEVs to refer to vehicles that result in zero tailpipe emissions, such as battery electric vehicles and fuel cell electric vehicles. While vehicles equipped with H2-ICE engines emit zero engine-out CO 2 emissions, H2-ICE vehicles emit criteria pollutants and are therefore not included in our references to ZEVs.
^{194} Moreover, as already explained, manufacturers do not have to produce ZEVs to comply with the final standards. EPA's modeling of the alternate compliance pathway in section II.F.3 demonstrates that manufacturers could meet the standard using solely advanced technologies with ICEs.
202(a)(3)(B) and 202(a)(3)(C) lead time and stability. Finally, we address the comments regarding the applicability of the 4-year lead time and 3-year stability provisions in CAA section 202(a)(3)(C). As we noted in the HD Phase 1 final rule, the provision is not applicable here. ^{195} Section 202(a)(3)(C) only applies to emission standards for heavy-duty vehicles for the listed pollutants in section 202(a)(3)(A) or to revisions of such standards under 202(a)(3)(B). Section 202(a)(3) applies only to standards for enumerated pollutants, none of which are GHGs, namely, “hydrocarbons, carbon monoxide, oxides of nitrogen, and particulate matter.” Because this rule does not establish standards for any pollutant listed in section 202(a)(3)(A), that section clearly does not apply. Neither does section 202(a)(3)(B), which is limited to revisions of heavy-duty standards “promulgated under, or before the date of, the enactment of the Clean Air Act Amendments of 1990.” EPA's heavy-duty GHG standards, however, have consistently been promulgated under sections 202(a)(1)-(2), statutory provisions which were not enacted or revised by the 1990 amendments. Nor does the final rule revise any standard promulgated “before” the enactment of the 1990 amendments. Consequently, the four year lead time and three year stability requirements of section 202(a)(3)(C) are inapplicable. We further address this issue in RTC 2.3.3 and 2.11.
^{195} Greenhouse Gas Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles EPA Response to Comments Document for Joint Rulemaking, at 5-19 (“Phase 1 RTC”).

II. Final HD Phase 3 GHG Emission Standards
Under our CAA section 202(a)(1) and (2) authority, we are finalizing new Phase 3 GHG standards for MYs 2027 through 2032 and later HD vehicles. In this section II, we describe our assessment that the new Phase 3 GHG standards are appropriate and feasible considering lead time, costs, and other relevant factors. These final Phase 3 standards include (1) revised GHG standards for many MY 2027 HD vehicles, and (2) new GHG standards starting in MYs 2028 through 2032. Our development of the final standards considered all of the substantive comments received, including those that advocated stringency levels ranging from less stringent than the lower stringency alternative presented in the NPRM to values that would be comparable with stringency levels in the California Advanced Clean Truck (ACT) rule such as stringency levels comparable to 50- to 60-percent utilization of ZEV technologies range and beyond.
The final standards' feasibility is supported through our analysis reflecting one modeled potential compliance pathway, but the final standards do not mandate the use of any specific technology. EPA anticipates that a compliant fleet under the final standards will include a diverse range of technologies, including ZEV and ICE vehicle technologies, and we have also included additional example potential compliance pathways that meet and support the feasibility of the final standards including without producing additional ZEVs to comply with this rule. In developing the modeled potential compliance pathway on which the feasibility of the final standards is supported, EPA has considered the key issues associated with growth in penetration of zero-emission vehicles, including charging and refueling infrastructure and critical mineral availability. In this section, we describe our assessment of the appropriateness and feasibility of these final standards and support that assessment with a potential technology pathway for achieving each of those standards through increased utilization of ZEV and vehicles with ICE technologies, as well as additional technology pathways to meet the final standards using technologies for vehicles with ICE. In this section, we also present an alternative set of standards (“the alternative”) that we additionally developed and analyzed but are not adopting, that reflects an even more gradual phase-in and lower final stringency level than the final standards. Furthermore, we also developed but did not analyze alternative standards reflecting levels of stringency more stringent than the final standards that would be achieved from extrapolating the California ACT rule to the national level, that we are also not adopting.
In the beginning of this section, we first describe the public health and welfare need for GHG emission reductions (section II.A). In section II.B, we provide an overview of the comments the Agency received on the NPRM regarding the proposed Phase 3 GHG emission standards, an overview of the final standards, and updates to the analyses that support these standards. In section II.C, we provide a brief overview of the existing CO 2 emission standards that we promulgated in HD GHG Phase 2. Section II.D contains our technology assessment for the projected potential compliance pathway that supports the feasibility of the standards and section II.E includes our assessment of technology costs, EVSE costs, operating costs, and payback for that modeled potential compliance pathway. Section II.F sets out the final standards and the analysis demonstrating their feasibility, including additional example potential compliance pathways that meet and support the feasibility of the final including without producing additional ZEVs to comply with this rule. Section II.G discusses the appropriateness of the final emission standards under the Clean Air Act. Section II.H presents the alternative set of standards to the final standards that we considered but are not adopting. Finally, section II.I summarizes our consideration of small businesses.
The HD Phase 3 GHG standards are CO 2 vehicle exhaust standards; other GHG standards under the existing regulations for HD engines and vehicles remain applicable. As we explained in the proposal, we did not reopen and are not amending the other GHG standards, including nitrous oxide (N 2 O), methane (CH 4 ), and CO 2 emission standards that apply to heavy-duty engines and the HFC emission standards that apply to heavy-duty vehicles, or the general compliance structure of existing 40 CFR part 1037 except for some revisions described in sections II and III. ^{196} As also explained in the proposal, we did not reopen and are continuing the existing approach taken in both HD GHG Phase 1 and Phase 2, that compliance with the vehicle exhaust CO 2 emission standards is based on CO 2 emissions from the vehicle. Indeed, all of our vehicle emission standards are based on vehicle emissions. See 76 FR 57123 (September 15, 2011); see also 77 FR 51705 (August 24, 2012), 77 FR 51500 (August 27, 2012), and 81 FR 75300 (October 25, 2016). We respond to the comments we received on life cycle emissions in relation to standard setting in RTC section 17.1. Additionally, as proposed in the combined light-duty and medium-duty rulemaking, in a separate rulemaking we intend to finalize more stringent standards for complete and incomplete vehicles at or below 14,000 pounds GVWR that are certified under 40 CFR part 86, subpart S. This Phase 3 final rule does not alter manufacturers of incomplete vehicles at or below 14,000 pounds GVWR continuing to have the option of either meeting the greenhouse gas standards under 40 CFR parts 1036 and 1037, or instead meeting the greenhouse gas standards with chassis-based measurement procedures under 40 CFR part 86, subpart S.
^{196} See the HD GHG Phase 2 rule (81 FR 73478, October 25, 2016), the Heavy-Duty Engine and Vehicle Technical Amendment rule (86 FR 34308, June 29, 2021), and the HD2027 rule (88 FR 4296, January 24, 2023). In this rulemaking, EPA did not reopen any portion of our heavy-duty compliance provisions, flexibilities, and testing procedures, including those in 40 CFR parts 1037, 1036, and 1065, other than those specifically identified in our proposal. For example, while EPA is revising discrete elements of the HD ABT program, EPA did not reopen the general availability of ABT.

A. Public Health and Welfare Need for GHG Emission Reductions
The transportation sector is the largest U.S. source of GHG emissions, representing 29 percent of total GHG emissions and, within the transportation sector, heavy-duty vehicles are the second largest contributor at 25 percent. ^{197} GHG emissions have significant impacts on public health and welfare as set forth in EPA's 2009 Endangerment and Cause or Contribute Findings under CAA section 202(a) and as evidenced by the well-documented scientific record. ^{198}
^{197} EPA (2023). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 (EPA-430-R-23-002, published April 2023).
^{198} See 74 FR 66496, December 15, 2009; see also EPA's Denial of Petitions Relating to the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, available at
https://www.epa.gov/system/files/documents/2022-04/decision_document.pdf .
Elevated concentrations of GHGs have been warming the planet, leading to changes in the Earth's climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events; rising seas; and retreating snow and ice. The changes taking place in the atmosphere as a result of the well-documented buildup of GHGs due to human activities are altering the climate at a pace and in a way that threatens human health, society, and the natural environment. While EPA is not making any new scientific or factual findings with regard to the well-documented impact of GHG emissions on public health and welfare in support of this rule, EPA is providing some scientific background on climate change to offer additional context for this rulemaking and to increase the public's understanding of the environmental impacts of GHGs.
Extensive additional information on climate change is available in the scientific assessments and the EPA documents that are briefly described in this section, as well as in the technical and scientific information supporting them. One of those documents is EPA's 2009 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under section 202(a) of the CAA (74 FR 66496, December 15, 2009). In the 2009 Endangerment Finding, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs—CO 2 , methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 )—“may reasonably be anticipated to endanger the public health and welfare of current and future generations” (74 FR 66523). The 2009 Endangerment Finding, together with the extensive scientific and technical evidence in the supporting record, documented that climate change caused by human emissions of GHGs (including HFCs) threatens the public health of the U.S. population. It explained that by raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses (74 FR 66497). While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the United States (74 FR 66525). The 2009 Endangerment Finding further explained that compared with a future without climate change, climate change is expected to increase tropospheric ozone pollution over broad areas of the United States., including in the largest metropolitan areas with the worst tropospheric ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525). Climate change is also expected to cause more intense hurricanes and more frequent and intense storms of other types and heavy precipitation, with impacts on other areas of public health, such as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-related disorders (74 FR 66525). Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498).
The 2009 Endangerment Finding also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare ^{199} in the United States., including the following: changes in water supply and quality due to changes in drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to a lesser extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the United States that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530).
^{199} The CAA states in section 302(h) that “[a]ll language referring to effects on welfare includes, but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.” 42 U.S.C. 7602(h).
The most recent information demonstrates that the climate is continuing to change in response to the human-induced buildup of GHGs in the atmosphere. Recent scientific assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in human history and that they continue to climb, primarily because of both historic and current anthropogenic emissions, and that these elevated concentrations endanger our health by affecting our food and water sources, the air we breathe, the weather we experience, and our interactions with the natural and built environments.
Global average temperature has increased by about 1.1 degrees Celsius (°C) (2.0 degrees Fahrenheit (°F)) in the 2011-2020 decade relative to 1850-1900. The IPCC determined with medium confidence that this past decade was warmer than any multi-century period in at least the past 100,000 years. Global average sea level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate over the 1971 to 2006 period, and three times the rate of the 1901 to 2018 period. The rate of sea level rise during the 20th Century was higher than in any other century in at least the last 2,800 years. The CO 2 being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years ^{200} putting many marine species—particularly calcifying species—at risk. Human-induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts ^{201} in many regions. ^{202} The 4th National Climate Assessment (NCA4) found that it is very likely (greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years. ^{203} Coral reefs will be at risk for almost complete (99 percent) losses with 1 °C (1.8 °F) of additional warming from today (2 °C or 3.6 °F since preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over half of the geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland livestock would be projected to be lost. The IPCC similarly found that climate change has caused substantial damages and increasingly irreversible losses in terrestrial, freshwater, and coastal and open ocean marine ecosystems. ^{204}
^{200} IPCC (2018): Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Portner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Pe´an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)].
^{201} These are drought measures based on soil moisture.
^{202} IPCC (2021): Summary for Policymakers. In: Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekçi, R. Yu and B. Zhou (eds.)]. Cambridge University Press.
^{203} USGCRP (2018): Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
^{204} IPCC (2022): Summary for Policymakers [H.-O. Pörtner, D.C. Roberts, E.S. Poloczanska, K. Mintenbeck, M. Tignor, A. Alegría, M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem (eds.)]. In: Climate Change 2022: Impacts, Adaptation and Vulnerability. Contribution of Working Group II to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [H.-O. Pörtner, DC Roberts, M. Tignor, E.S. Poloczanska, K. Mintenbeck, A. Alegría, M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem, B. Rama (eds.)]. Cambridge University Press, Cambridge, UK and New York, NY, USA, pp. 3-33, doi:10.1017/9781009325844.001.
In 2016, the Administrator issued a similar finding for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA. ^{205} In the 2016 Endangerment Finding, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Finding compellingly supported a similar endangerment finding under CAA section 231(a)(2)(A), and also found that the science assessments released between the 2009 and 2016 Findings “strengthen and further support the judgment that GHGs in the atmosphere may reasonably be anticipated to endanger the public health and welfare of current and future generations” (81 FR 54424). Pursuant to the 2009 Endangerment Finding, CAA section 202(a) requires EPA to issue standards applicable to emissions of those pollutants from new motor vehicles. See Coalition for Responsible Regulation, 684 F.3d at 116-125, 126-27; Massachusetts, 549 U.S. at 533. See also Coalition for Responsible Regulation, 684 F.3d at 127-29 (upholding EPA's light-duty GHG emission standards for MYs 2012-2016 in their entirety). ^{206} Since the 2016 Endangerment Finding, the climate has continued to change, with new observational records being set for several climate indicators such as global average surface temperatures, GHG concentrations, and sea level rise. Additionally, major scientific assessments continue to be released that further advance our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both globally and in the United States. 207 208 209 210
^{205} “Finding that Greenhouse Gas Emissions from Aircraft Cause or Contribute to Air Pollution That May Reasonably Be Anticipated To Endanger Public Health and Welfare.” 81 FR 54422, August 15, 2016. (“2016 Endangerment Finding”).
^{206} See also EPA's Denial of Petitions Relating to the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (April 2022), available at https://www.epa.gov/system/files/documents/2022-04/decision_document.pdf .
^{207} USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018. https://nca2018.globalchange.gov .
^{208} Roy, J., P. Tschakert, H. Waisman, S. Abdul Halim, P. Antwi-Agyei, P. Dasgupta, B. Hayward, M. Kanninen, D. Liverman, C. Okereke, P.F. Pinho, K. Riahi, and A.G. Suarez Rodriguez, 2018: Sustainable Development, Poverty Eradication and Reducing Inequalities. In: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Pörtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. In Press. https://www.ipcc.ch/sr15/Chapter/Chapter-5 .
^{209} National Academies of Sciences, Engineering, and Medicine. 2019. Climate Change and Ecosystems. Washington, DC: The National Academies Press. https://doi.org/10.17226/25504 .
^{210} NOAA National Centers for Environmental Information, State of the Climate: Global Climate Report for Annual 2020, published online January 2021, retrieved on February 10, 2021, from https://www.ncdc.noaa.gov/sotc/global/202013 .

B. Summary of Comments and the HD GHG Phase 3 Standards and Updates From Proposal
EPA proposed this third phase of GHG standards for heavy-duty vehicles and supported the feasibility of those proposed standards based on our assessment of a projected compliance pathway using ZEV technologies and ICE vehicle technologies. As described further in the NPRM, the proposed standards commenced in MY 2027 for most of the HDV subcategories, and in MY 2030 for sleeper cab (long-haul) tractors. The proposed standards would increase in stringency through MY 2032, after which they would remain in place unless and until EPA set new standards ( e.g., Phase 4 standards).
The proposed vehicle standards were performance-based standards and did not specify or require use of any particular technology. The technology packages developed to support the feasibility of the proposed HD GHG Phase 3 vehicle standards included those improvements to ICE vehicle performance reflected in the HD GHG Phase 2 standards' technology packages. EPA did not reopen and did not propose any revisions to the HD Phase 2 engine GHG standards.

1. Summary of Comments
There were many comments on EPA's proposal. Certain commenters supported the proposed stringency levels and the proposed MY implementation schedule. Regarding the proposed implementation schedule, for example, one commenter supported EPA's proposal to amend many of the MY 2027 Phase 2 vehicle standards on the grounds advanced by EPA at proposal: facts have changed from 2016 when the agency promulgated its Phase 2 rule. Specifically, ZEVs are being actively deployed, there are plans to increase their adoption rate, and massive Federal and state efforts are underway to provide financial incentives and otherwise encourage heavy-duty ZEV implementation. The bulk of comments, however, supported standards of either greater or lesser stringency than proposed.
This preamble section summarizes these comments at a high level and highlights certain changes we have made in the final standards from those proposed after consideration of these comments. Detailed summaries and responses are found in section 2 of the RTC. ^{211}
^{211} For the complete set of comments, please see U.S. EPA, “Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3- Response to Comments.” RTC sections 2 and 3. Docket EPA-HQ-OAR-2022-0985.

i. Comments Urging Standards More Stringent Than Proposed
A number of commenters maintained that the proposed standards were insufficiently stringent. Many of these commenters centered their arguments on general legal and policy grounds, maintaining that the overriding public health and welfare protection goals of the Act and of section 202(a)(1) should be reflected in standard stringency. They pointed to the on-going climate crisis and indicated that emission reduction levels should be commensurate with the degree of harm posed by that endangerment. A number of these commenters also stressed the need for reductions in criteria pollutant emissions including via further improvements to ICE vehicles (both through vehicle and engine standards), stressing especially the benefits to disadvantaged communities that would be afforded by more stringent standards.
This group of commenters recommended standards at least as stringent as those in the California ACT rules. Other commenters suggested standards stricter still, including a standard of zero emission by MY 2035, basing the standard on the combined stringencies of the California ACT and Advanced Clean Fleets (ACF) programs (citing the record developed by California in support of each of these programs), and including the ACT sales mandates as part of a Federal standard. One commenter indicated that the baseline should account for both California programs, these programs' adoption by the CAA section 177 states, their presumed adoption by the NESCAUM MOU states, effects of the IRA and BIL, state and local initiatives, and manufacturer and fleet commitments.
As further support for more stringent standards, commenters cited a number of factors, including asserting the following, which we summarize and respond to in RTC section 2.4 or elsewhere as noted:
• Introduction into the market of HD ZEVs, numerous both in volume and types of applications. More specifically, CARB staff found (in the administrative record for the California ACF program) that ZEVs are available in every weight class of trucks, and each weight class includes a wide range of vehicle applications and configurations. CARB staff also found that there are currently 148 models in North American where manufacturers are accepting orders or pre-orders, and there are 135 models that are actively being supported and delivered. These commenters pointed to manufacturer sales announcements and publicly announced production plans as corroboration.
• Adoption of ACT by other states, plus commitments of other states to do so, indicates standards reflecting that level of ZEV acceptance can be replicated on a national basis.
• Massive Federal, state and local financial incentives in the BIL, IRA and elsewhere. See also RTC section 2.7.
• Federal standards themselves will provide needed certainty for investment in both ZEVs, including metals and minerals critical to battery production, and charging infrastructure.
• Tens of billions of dollars of announced investments from the private sector and utilities into charging infrastructure for heavy-duty ZEVs, as well as supporting state and local actions designed to ensure that the rate, scale, and distribution of infrastructure buildout supports rapid and diverse adoption of heavy-duty ZEVs.
Another commenter (to which we respond in RTC section 2.4) asserted a number of points, for which they provided empirical support, related to cost of BEVs in relation to comparable ICE-powered HDVs:
• Powertrain costs of most BEVs will be at par or cheaper than diesel ICE vehicles due to the battery tax credits under the IRA.
• The Total Cost of Ownership (TCO) of BEVs is significantly lower than diesel ICE vehicles across all segments. The payback period is less than three years for all vehicles.
• The cargo capacity of most BEVs will be at par with ICEVs due to a posited increase in battery energy density.
• 15 minutes of enroute charging from a megawatt charging system can add more than 80 percent of the full range of battery electric tractors, enabling them to meet the requirements of more demanding use cases.
• BEVs have a lower TCO per mile, even assuming significant public charging. With 30 percent of all charging required conducted en route (recharging 20-80 percent of a full charge on half of the operating days), the payback period of all HDVs is still less than five years.
A number of commenters urged adoption of more stringent standards predicated on further improvements to engine and vehicle GHG performance of ICE vehicles. The thrust of these comments is that there are various available technologies which either have not been utilized, or are underutilized, in the HDV fleet, and that significant incremental improvements in GHG performance are therefore available, and at reasonable cost. According to these commenters, these technologies include lightweighting, advanced aerodynamics, tire improvements, idle reduction including stop-start systems, hybrid technologies of all types, and predictive cruise control. Commenters stated that some of these technologies would even improve ZEV performance by increasing vehicle efficiency thereby enabling longer range for a given battery size. We summarize and address comments relating to vehicles with ICE technologies in section 9 of the RTC to this rule.
With regard to specific applications, proponents of more stringent standards stated that:
• Tesla alone intends to produce 50,000 BEV Class 8 day cabs for MY 2024, which on its own would exceed the percentage of ZEVs in the technology package on which EPA supported the proposed MY 2027 standard;
• The proposed standard for tractors could be at ACT levels if predicated on reduced battery size and opportunity (public) charging;
• There are many programs that support zero emission urban and school buses, which should be reflected in the standards;
• Drayage trucks should be subject to a more stringent standard, given their suitability for ZEV technologies (limited range, overnight charging in depots) plus the environmental benefits of reducing emissions given their use in heavily polluted areas like ports and railway yards.
We respond to these comments throughout section II of this preamble and in sections 2 and 3 of the RTC.

ii. Comments Urging Standards Less Stringent Than Proposed
Many commenters opposed the proposed standards as being too stringent. Some urged the agency to simply leave the MY 2027 Phase 2 standards in place, maintaining on general grounds that further technological improvements are too nascent to form the basis for more stringent standards. Other comments were more specific on the subject of implausibility. One commenter stated that the number of BEV buses would need to increase by a factor of 12, and that thousands of BEV drayage, day-cab tractors, sleeper tractors, and step vans would need to be sold to achieve the proposed standards. Another commenter asserted that the proposal was predicated on a ZEV sale growth rate of 63,000 percent from 2021-2032. One commenter stated that a predicated introduction of more than two orders of magnitude for some subcategories (0.2 percent to approximately 40 percent) in a few model years was inherently implausible.
Two vehicle manufacturer commenters, on the other hand, supported the MY 2032 standards but found the early model year standards inappropriate, citing among other things the large increase in stringency between MYs 2026 and 2027 and the uncertainties associated with sufficiency of supportive recharging infrastructure in the program's initial years.
A number of commenters opposed to the proposed standards offered alternative perspectives to some of the points made by commenters supporting more stringent standards. With regard to a nationalized version of the California ACT standards, these commenters asserted that certain assumptions and circumstances reflected in the ACT program would not be replicated nationally, including assumptions of high diesel prices, high ACT vehicle availability, and high demand from California's ACF program, plus local climate conditions which did not require BEVs designed for more extreme weather conditions. A commenter further asserted that not all states that have adopted California's ACT provisions have the same supporting regulations and therefore it is not clear how many ZEVs will be sold as a result of ACT. Others stated that manufacturers' aspirational goals did not translate to actual production, especially given uncertainties regarding supporting electric charging infrastructure, customer reactions to a new, unfamiliar product, and potential critical material shortages.
With respect to further improvements to ICE vehicles and engines suggested by commenters supporting more stringent standards, some manufacturer commenters asserted that some of the technologies on which the Phase 2 rule was predicated had proved unmarketable, others (like the Rankine engine and certain advanced aerodynamic features) had never been commercialized, and some had proved less efficient than projected, and as a result, some manufacturers had included ZEVs within their production plans as a Phase 2 compliance strategy. These commenters stated that non-utilization of various engine and vehicle technologies thus should not be viewed as either showing opportunity for further ICEV improvements, or as demand for BEV vehicles.
Uncertainties relating to key elements of the program which commenters stated are out of the control of the regulated entities formed the basis of many of the comments questioning the feasibility of the proposed program. These include:
• The availability of distribution electrical infrastructure necessary to support BEVs. Commenters cited the chicken-egg dynamic of ZEV purchasers needing assurance of supporting infrastructure before committing to purchases, but electric utilities needing (and, in many cases, legally requiring) assurance of demand before building out. These difficulties are compounded by issues of timing: it can take 40 weeks for utilities to acquire transformer parts, and 70 to acquire switchgear parts. Installation delays can be 1-3 years for smaller installations (cable, conductor systems), 3-5 years for medium (feeders and substation capacity), and 4-6 for large installations (subtransmission requiring licensing). Moreover, infrastructure buildout schedules rarely correlate with purchasers' resale schedules, or with BIL/IRA subsidy timings. These comments are summarized in more detail and addressed in section II.D.2.iii of this preamble and in RTC section 7 (Distribution).
• Uncertainty regarding availability of critical minerals and associated supply chain issues. These comments are summarized in more detail and addressed in section II.D.2.ii and in RTC section 17.2.
• Uncertainty regarding purchasers' decisions, noting customer reluctance to utilize an unfamiliar technology and unsuitability given limited range and cargo penalty due to need for large batteries. These comments are summarized in more detail and addressed in section II.F.1 of this preamble and in RTC sections 4.2 and 19.5.
• Assertions that estimating availability of hydrogen infrastructure is nearly futile at present because this technology is barely commercialized; commenters suggested that EPA has also mistakenly assumed availability of clean hydrogen, failed to consider costs of hydrogen infrastructure, ignored potential issues of permitting and interfaces with electric utilities with regard to hydrogen infrastructure, and failed to discuss physical requirements of hydrogen charging stations; and that EPA also did not consider issues relating to hydrogen handling or high initial costs of hydrogen infrastructure. These comments are summarized in more detail and addressed in section II.D.3.v and RTC section 8.
Regarding availability of Federal and state funding, these commenters made the following points:
• These subsidies may not be available in many instances, due to insufficient taxable revenue to qualify, or lack of domestic production required to be eligible for the tax subsidy;
• Purchase incentives for tractors are being offset, almost to the dollar, by Federal excise taxes;
• States are using National Electric Vehicle Infrastructure Formula program funds almost exclusively for light duty infrastructure, which will not be suitable for HDVs;
Given all of these uncertainties and issues, this group of commenters questioned the disproportionate weight EPA gave to payback in developing a ZEV-based compliance pathway. One commenter indicated that EPA should accord equal analytical weight to purchase price, limited range, excess weight, lack of electrification infrastructure, durability concerns, and unpromising state support. Commenters also noted the reality of the energy efficiency gap noted by EPA, whereby purchasers refrain from making seemingly economically rational decisions for various reasons.
EPA's proposed approach to quantifying when payback periods of given duration would support utilization of ZEV technologies as a potential compliance option was criticized by these commenters (and also by commenters urging standards of greater stringency). With regard to the payback metric generally, a number of commenters maintained that payback is not a guarantee of technology adoption, pointing to various technologies with rapid payback (like drive wheel fairings) which nonetheless proved unmarketable. These commenters also maintain that TCO is the proper, or superior, metric, better reflecting how purchase decisions are actually made. In any case, these commenters said that a 2-year payback period is more appropriate for HDVs, since initial purchasers typically have a 3- to 5-year resale schedule.
One commenter noted that the projected results based on the modified equation were highly conservative, and inconsistent with the technical literature. Other commenters suggested EPA utilize instead other of the methodologies discussed in the Draft Regulatory Impact Analysis (DRIA) that were not based on a proprietary equation, notably the TEMPO equation and methodology.
One commenter submitted an attachment from ACT Research (who developed the proprietary payback equation EPA had modified in the proposed approach) maintaining that EPA had misapplied the equation. EPA addresses this issue and summarizes in more detail and addresses these comments in section II.F.1 and RTC section 2.4.
With regard to standard stringency, one commenter submitted detailed comments urging that EPA adopt standards roughly 50 percent less stringent than proposed for each subcategory, commencing in MY 2030, with standards for HHD vocational vehicle and sleeper cab tractor applications commencing in MY 2033. Their recommended standards would also include three initial years of stability. This commenter derived these standards using EPA's HD TRUCS tool with different inputs. Reasons supplied by the commenter for the different inputs included omitted costs, underestimated costs, certain errors regarding various of the 101 models included in HD TRUCS, misapplication of the ACT Research payback algorithm, and the following purportedly unrealistic assumptions:
• Timing of infrastructure availability (including issues associated with supply chains for distribution infrastructure equipment, especially in light of overlapping demands from the LDV sector);
• Need to get pro-active involvement of electric utilities, and EPA's seeming lack of effort in encouraging such actions;
• Fuel cell efficiency;
• Lack of consideration of resale value;
• Assumption of domestic battery production, given the absence of any domestic lithium mining;
• The sheer magnitude of infrastructure buildout needed to support the levels of BEVs on which the proposal was predicated (estimated as a need for 15,000 new chargers each week for the next 8 years);
• Unrealistic estimates of cost of hydrogen infrastructure;
• Lack of accounting for land availability; and
• A cargo penalty of 30 percent is a significant deterrent.
This commenter further maintained that its suggested standards be adjusted automatically downwards if any of the assumptions on which a standard is predicated prove unfounded. They specifically suggest that these triggers include a linkage to infrastructure availability, with the standard being automatically reduced based on the percentage of infrastructure less than predicted. This commenter further suggested this linkage trigger could be based on infrastructure buildout in counties known to be freight corridors. In subsequent meetings with the agency, this commenter suggested a further trigger based on monitoring ZEV sales both within states which have adopted the California ACT program, and within states which have not done so. ^{212} These comments are summarized in more detail and addressed in section II.B.2.iii and RTC section 2.
^{212} Miller, Neil. Memorandum to Docket EPA-HQ-OAR-2022-0985. Summary of Stakeholder Meetings. March 2024.
Several commenters opposed amendment of the Phase 2 MY 2027 GHG vehicle standards. Some commenters alleged equitability arguments opposing amending the Phase 2 standards. They noted that the Phase 2 standards exhibited a rare consensus, reflecting a common understanding that the standard would remain unaltered through its final model year of phase-in (MY 2027). Some commenters stated that manufacturers have relied on those standards in devising compliance strategies. Moreover, some commenters stated that early adoption of ZEVs is part of the manufacturers' Phase 2 compliance strategies and is not a valid harbinger for a Phase 3 rule. That is, rather than adopt a number of technologies on which the Phase 2 rule was predicated (such as high adoption rates for advanced aerodynamics, stop start, electric steering accessories and others), these commenters stated that some companies instead have introduced ZEVs. These commenters stated that if the MY 2027 standards are amended, these companies are effectively punished for their adoption of an innovative technology, because they will need to seek unanticipated reductions from other vehicles. Some manufacturer commenters stated that if EPA is considering changed circumstances as a basis for amending MY 2027 standards, there are changed circumstances that cut in the other direction: under-utilization of GHG-reducing technologies in ICE vehicles, pandemic altered supply chains, inflationary prices, fewer qualified technicians, and parts shortages.

iii. Other Comments Related to the Standards
A final group of commenters urged EPA to predicate standards based on use of biofuels or other alternative fuels. They noted that such fuels, including varying degrees of biodiesel, not only provide emission reduction benefits, but can do so immediately, can do so at less cost, and are the subject of various Federal incentive programs, including those administered by the Department of Agriculture. These comments are summarized in more detail and addressed in section II.D.1 and in RTC section 9.1.

2. Summary of the Final Rule Standards and Updates From Proposal
This section briefly summarizes the Phase 3 final rule standards and includes discussion of key changes and updates from the proposed standards. This final rule updates the proposal in a number of ways, reflecting consideration of additional data received in comments, other new research that became available since the proposal, and considerations voiced in the public comments. This preamble subsection highlights many of these changes, while the following subsections provide additional detail of the changes.

i. Final Standards
As further described in the following subsections, the final Phase 3 GHG standards include new CO 2 emission standards for MY 2032 and later HD vehicles with more stringent CO 2 standards phasing in as early as MY 2027 for certain vehicle categories. The final standards for the vocational vehicles are shown in Table II-1 and for tractors in Table II-2. The final standards are discussed in detail in section II.F. Compared to the proposed Phase 3 standards, in general, after further consideration of the lead times necessary for the standards (including both the vehicle development and the projected infrastructure needed to support the modeled potential compliance pathway that demonstrates the feasibility of the standards), we are finalizing CO 2 emission standards for heavy-duty vehicles that, compared to the proposed standards, include less stringent standards for all vehicle categories in MYs 2027, 2028, 2029 and 2030. The final standards increase in stringency at a slower pace through MYs 2027 to 2030 compared to the proposal, and day cab tractor standards start in MY 2028 and heavy heavy-duty vocational vehicles start in MY 2029 (we proposed Phase 3 standards for day cabs and heavy-heavy vocational vehicles starting in MY 2027). As proposed, the final standards for sleeper cabs start in MY 2030 but are less stringent than proposed in that year and in MY 2031, and equivalent to the proposed standards in MY 2032. Our updated analyses for the final rule show that model years 2031 and 2032 GHG standards in the range of those we requested comment on in the HD GHG Phase 3 NPRM are feasible and appropriate considering feasibility, lead time, cost, and other relevant factors as described throughout this section. Specifically, we are finalizing MY 2031 standards that are on par with the proposal for light- and medium-duty vocational vehicles and day cab tractors. Heavy heavy-duty vocational vehicle final standards are less stringent than proposed for all model years, including 2031 and 2032. For MY 2032, we are finalizing more stringent standards than proposed for light and medium heavy-duty vocational vehicles and day cab tractors. EPA also revised various of the optional custom chassis standards from those proposed. Our assessment of the final program as a whole is that it takes a balanced and measured approach while still applying meaningful requirements in MY 2027 and later to reducing GHG emissions from the HD sector.
EPA emphasizes that its standards are performance-based, such that manufacturers are not required to use particular technologies to meet the standards. In this rulemaking, EPA has accounted for a wide range of emissions control technologies, including advanced ICE vehicle technologies ( e.g., engine, transmission, drivetrain, aerodynamics, tire rolling resistance improvements, the use of low carbon fuels like CNG and LNG, and H2-ICE), hybrid technologies ( e.g., HEV and PHEV), and ZEV technologies ( e.g., BEV and FCEV). These include technologies applied to motor vehicles with ICE (including hybrid powertrains) and without ICE. Electrification across the technologies ranges from fully electrified vehicle technologies without an ICE that achieve zero vehicle tailpipe emissions ( e.g., BEVs), fuel cell electric vehicle technologies that run on hydrogen and achieve zero tailpipe emissions ( e.g., FCEVs), as well as plug-in hybrid partially electrified technologies and ICEs with electrified accessories. There are many potential pathways to compliance with the final standards manufacturers may choose that involve different mixtures of HD vehicle technologies. Our potential compliance pathway that includes a projected mix across the range of HD vehicle technologies, including certain vehicle with ICE, BEV, and FCEV technologies, supports the feasibility of the final standards and was used in our modeling for rulemaking purposes (“modeled potential compliance pathway”). In addition, for the final rule, to further assess the feasibility of the standards under different potential scenarios and to further illustrate that there are many potential pathways to compliance with the final standards that include a wide range of potential technology mixes, we evaluated additional examples of other potential compliance pathway's technology packages that also support the feasibility of the final standards (“additional example potential compliance pathways”). These additional example potential compliance pathways only include vehicles with ICE technologies and include examples without producing additional ZEVs to comply with this rule.
We also are finalizing updates to and new flexibilities that support these final standards, as discussed in section III; however, we did not rely on those other aspects in justifying the feasibility of the final standards.

ii. Updates to Analyses
We have made a number of updates to our analyses from proposal, especially related to inputs to HD TRUCS, as detailed in section II.D.5, after consideration of comments submitted in response to our proposal and requests for comment in the NPRM. Some of the key updates in our analyses include updates to our assessment of BEV and FCEV component costs, efficiencies, and sizing; consideration of certain additional costs to purchasers, including taxes and insurance; refined dwell times for charging infrastructure sizing; EVSE costs; consideration of public charging (and associated costs) for certain BEVs; and a more detailed evaluation of the impact of HD charging on the U.S. electricity system.

iii. Commitment to Post-Rule Engagement and Monitoring
Some representatives from the heavy-duty vehicle manufacturing industry have expressed not only optimism regarding the heavy-duty industry's ability to produce ZEV technologies in future years at high volume, but also concern that a slow growth in ZEV charging and refueling infrastructure could slow the growth of heavy-duty ZEV adoption. ^{213} On the other hand, some representatives from state and local air pollution control agencies point to ongoing and planned activities as evidence that infrastructure for heavy-duty ZEVs can and will be built out at the pace, scale, and locations needed to support such technologies used to meet strong EPA GHG standards for heavy-duty vehicles. ^{214} Comments from advocacy organizations point to analyses from the International Council on Clean Transportation, ^{215} as well as announced investments in charging infrastructure from truck manufacturers, fleet owners, retailers, other private companies, and utilities as additional evidence to support this point. ^{216} Lack of such infrastructure may present challenges for vehicle manufacturers' ability to comply with future EPA GHG standards for manufacturers who pursues a ZEV-focused compliance pathway similar to the example projected potential compliance pathway EPA analyzed in this final rule, while good availability of such infrastructure would support the sale of HD ZEVs and support such a manufacturer's compliance strategy.
^{213} See, e.g., Comments of the Truck and Engine Manufacturers Association. Docket EPA-HQ-OAR-2022-0985-2668.
^{214} See, e.g., Comment submitted by the National Association of Clean Air Agencies. Docket EPA-HQ-OAR-2022-0985-1499.
^{215} Ragon, P.-L., et al. (2023). Near-term infrastructure deployment to support zero-emission medium- and heavy-duty vehicles in the United States. International Council on Clean Transportation.
^{216} See, e.g., Comment submitted by International Council on Clean Transportation. Docket EPA-HQ-OAR-2022-0985-1423.
EPA has a vested interest in monitoring industry's performance in complying with mobile source emission standards, including the highway heavy-duty industry. EPA currently monitors industry's performance through a range of approaches, including regular meetings with individual companies, regulatory requirements for data submission as part of the annual certification process, and performance under various EPA grant and rebate programs. EPA also provides transparency to the public through actions such as publishing industry compliance reports (such as has been done during the HD GHG Phase 1 program ^{217} ).
^{217} See EPA Reports EPA-420-R-21-001B covering Model Years 2014-2018, and EPA report EPA-420-R-22-028B covering Model Years 2014-2020, available online at https://www.epa.gov/compliance-and-fuel-economy-data/epa-heavy-duty-vehicle-and-engine-greenhouse-gas-emissions .
We requested comment on the pace of ZEV infrastructure development, and potential implications for compliance with the Phase 3 standards in the NPRM. 88 FR 25934. In comments, manufacturers suggest that we establish mechanisms for the CO 2 standards to self-adjust (become less stringent) if infrastructure deployment falls short of the amount necessary to support the rule. We heard similar comments from some Senators suggesting that the compliance deadline be delayed if the infrastructure is not there by a certain date. However, many other stakeholders opposed EPA including in the final rule a self-adjusting linkage between the standards and ZEV infrastructure. Many stakeholders also argued that heavy-duty ZEV infrastructure will be sufficient during the regulatory timeframe to support stronger GHG standards than those proposed by EPA in the NPRM.
We have carefully assessed infrastructure needed for the modeled potential compliance pathway as described in section II.F that supports the feasibility of the final standards, and as described in section II.G we conclude that the Phase 3 standards are feasible and appropriate within the meaning of section 202(a) of the Act. However, EPA also commits in this final rule to actively engage with stakeholders and monitor both OEM compliance and the major elements relating to heavy-duty ZEV infrastructure. EPA, in consultation with other agencies, will issue periodic reports reflecting this collected information throughout the lead up to the Phase 3 standards in MYs 2027 through 2032. These periodic status reports would begin as early as calendar year 2026 with a review of MY 2024 HD vehicle certification data and HD infrastructure growth that occurs over the next two years. As discussed below, these reports will be informed by comprehensive information collected by EPA as part of its certification and compliance programs. The Phase 3 standards are performance-based standards and the projected potential compliance pathway is not the only way that manufacturers may comply with the standards, and thus these reports will include but not be limited to assessing HD ZEV infrastructure. Based on these reports, as appropriate and consistent with CAA section 202(a) authority, EPA may decide to issue guidance documents, initiate a future rulemaking to consider modifications to the Phase 3 rule (including giving appropriate consideration to lead time as required by section 202(a)), or make no changes to the Phase 3 rule program.
EPA has taken similar actions in past rulemakings. For example, in 2000, EPA finalized stringent highway heavy-duty engine emission standards as well as national ultra-low diesel fuel sulfur standards, with implementation beginning in 2006 (for the fuel) and 2007 for the heavy-duty engines. These standards were premised on significant investments in both diesel fuel sulfur removal technology and heavy-duty engine and vehicle emission control technologies. Because of the significant scope of the regulations and the importance to public health and welfare, EPA published two major progress reports prior to the implementation dates of the standards, with one report published in 2002, and a second report in 2004. 218 219 These public reports allowed EPA to communicate what challenges and progress was being made by the regulated industry and other stakeholders in achieving the goals of the 2000 final rule. EPA believes this previous process for highway heavy-duty emission standards and ultra-low fuel sulfur standards can serve as a broad template for ensuring on-going engagement and monitoring of the Heavy-Duty Phase 3 GHG final standards (though we note for the 2000 rule, EPA established standards for the engine emission requirements and the highway diesel fuel sulfur levels, whereas in this rule EPA is establishing emission standard for heavy-duty vehicles).
^{218} “Highway Diesel Progress Review” EPA Report 420-R-02-016, June 2002. See Docket Entry EPA-HQ-OAR-2022-0985.
^{219} “Highway Diesel Progress Review Report 2,” EPA-420-R-04-004. March 2004. See Docket Entry EPA-HQ-OAR-2022-0985-77806.
As part of the Agency's on-going certification and compliance program, EPA receives data from every OEM to ensure compliance with heavy-duty emission standards, including the existing Phase 2 GHG standards (and, in the future, Phase 3 GHG standards as well). EPA will monitor the on-going implementation of the Phase 2 program as well as the Phase 3 program, to understand how each OEM's compliance with the GHG standards is occurring, including by vehicle class, and to understand the use of the CO 2 emissions averaging, banking, and trading program. This will include evaluating manufacturers' use of Phase 2 advanced technology multipliers, quantifying any banked credits generated from the use of multipliers, and considering the potential for those credits to undermine the overall goals of the Phase 3 program in the MY 2027 and later time frame.
This includes GHG-reducing technologies on HD ICEVs, BEVs, FCEVs, plug-in hybrid electric vehicles (PHEVs), hybrid electric vehicles, and vehicles with H2-ICE. Also consistent with commenters' suggestions, EPA intends to monitor data on HDV sales in California and other states that have adopted ACT. Such sales provide an early indication of ZEV technology adoption.
EPA agrees with commenters that information on battery production, and the related issue of availability of materials critical to that production (including viability of supply chains), is important to gauging pace and success of implementation of the Phase 3 standards. EPA intends to discuss any issues with HD vehicle manufacturers and consult other sources of information regarding these issues, including the United States Geological Survey (USGS) and DOE's tracking of critical minerals.
EPA will monitor the deployment of heavy-duty vehicle charging and hydrogen refueling infrastructure. EPA will begin to collect data in CY 2025 in coordination with DOE and DOT, to monitor the implementation of electric vehicle charging infrastructure designed to serve HD vehicles potentially including but not limited to the following:
• Depot charging infrastructure—number of EVSE ports, size, location, growth rate
• Public charging infrastructure—number of EVSE ports, size, location, growth rate
• EVSE sales—number, size, location, growth rate
• A sample of charging station installation timelines and distribution system upgrades ( e.g., covering small, mid-size, and large depots and public stations.) Samples could be selected to reflect different regions and utility types, among other factors.
Additionally, relevant data from each organization's relevant infrastructure funding programs will be assessed.
EPA will also collect data, in coordination with DOE and DOT, on the implementation of hydrogen fueling infrastructure, including data such as the number, capacity, location, and type of hydrogen production plants and hydrogen refueling stations available for HD vehicles.
During the development of the reports reflecting this information, EPA will consult with a wide range of stakeholders regarding the implementation of HD vehicle infrastructure on an on-going basis, to learn from their experiences and to gather relevant information and data from them. The stakeholders would likely include at a minimum trucking fleets and trucking trade associations; heavy-duty vehicle owner-operators; HD vehicle manufacturers; utilities including investor owned, publicly owned, and cooperatives; infrastructure providers and installers; state & local governments, EJ communities; and NGOs. As noted, we will also be in regular contact with DOE and DOT.

C. Background on the CO 2 Emission Standards in the HD GHG Phase 2 Program
In the HD GHG Phase 2 rule, we finalized GHG emission standards tailored to three regulatory categories of HD vehicles—heavy-duty pickups and vans, vocational vehicles, and combination tractors. ^{220} In addition, we set separate standards for the engines that power combination tractors and for the engines that power vocational vehicles. The heavy-duty vehicle CO 2 emission standards are in grams per ton-mile, which represents the grams of CO 2 emitted to move one ton of payload a distance of one mile. In addition, the Phase 2 program established certain subcategories of vehicles ( i.e., custom chassis vocational vehicles and heavy-haul tractors) that were specifically designed to recognize the limitations of certain vehicle applications to adopt some technologies due to specialized operating characteristics or generally low sales volumes with prohibitively long payback periods. The vehicles certified to the custom chassis vocational vehicle standards are not permitted to bank or trade credits and some have limited averaging provisions under the HD GHG Phase 2 ABT program. ^{221}
^{220} We also set standards for certain types of trailers used in combination with tractors (see 81 FR 73639, October 25, 2016). As described in section III of this preamble, in this final rule we removed the regulatory provisions related to trailers in 40 CFR part 1037 to carry out the mandate of the U.S. Court of Appeals for the D.C. Circuit, which vacated the portions of the HD GHG Phase 2 final rule that apply to trailers. Truck Trailer Manufacturers Association v. EPA, 17 F.4th 1198 (D.C. Cir. 2021).
^{221} See 40 CFR 1037.105(h)(2).

1. Vocational Vehicles
Vocational vehicles include a wide variety of vehicle types, spanning Class 2b-8, and serve a wide range of functions. The regulations define vocational vehicles as all heavy-duty vehicles greater than 8,500 pounds GVWR that are not certified under 40 CFR part 86, subpart S, or a combination tractor under 40 CFR 1037.106. ^{222} Some examples of vocational vehicles include urban delivery trucks, refuse haulers, utility service trucks, dump trucks, concrete mixers, transit buses, shuttle buses, school buses, emergency vehicles, motor homes, and tow trucks. The HD GHG Phase 2 vocational vehicle program also includes a special regulatory subcategory called vocational tractors, which covers vehicles that are technically tractors but generally operate more like vocational vehicles than line-haul tractors. These vocational tractors include those designed to operate off-road and in certain intra-city delivery routes.
^{222} See 40 CFR 1037.105(a).
The existing HD GHG Phase 2 CO 2 standards for vocational vehicles are based on the performance of a wide array of control technologies. In particular, the HD GHG Phase 2 vocational vehicle standards recognize detailed characteristics of vehicle powertrains and drivelines. Driveline improvements present a significant opportunity for reducing fuel consumption and CO 2 emissions from vocational vehicles. However, there is no single package of driveline technologies that will be equally suitable for all vocational vehicles, because there is an extremely broad range of driveline configurations available in the market. This is due in part to the variety of final vehicle build configurations, ranging from a purpose-built custom chassis to a commercial chassis that may be intended as a multi-purpose stock vehicle. Furthermore, the wide range of applications and driving patterns of these vocational vehicles leads manufacturers to offer a variety of drivelines, as each performs differently in use.
In the final HD GHG Phase 2 rule, we recognized the diversity of vocational vehicle applications by setting unique vehicle CO 2 emission standards evaluated over composite drive cycles for 23 different regulatory subcategories. The program includes vocational vehicle standards that allow the technologies that perform best at highway speeds and those that perform best in urban driving to each be properly recognized over appropriate drive cycles, while avoiding potential unintended results of forcing vocational vehicles that are designed to serve in different applications to be measured against a single drive cycle. The vehicle CO 2 emissions are evaluated using EPA's Greenhouse Gas Emissions Model (GEM) over three drive cycles, where the composite weightings vary by subcategory, with the intent of balancing the competing pressures to recognize the varying performance of technologies, serve the wide range of customer needs, and maintain a workable regulatory program. ^{223} The HD GHG Phase 2 primary vocational standards, therefore, contain subcategories for Regional, Multi-purpose, and Urban drive cycles in each of the three weight classes (Light Heavy-Duty (Class 2b-5), Medium Heavy-Duty (Class 6-7) and Heavy Heavy-Duty (Class 8)), for a total of nine unique subcategories. ^{224} These nine subcategories apply for compression-ignition (CI) vehicles. We separately, but similarly, established six subcategories of spark-ignition (SI) vehicles. In other words, there are 15 separate numerical performance-based emission standards for each model year.
^{223} GEM is an EPA vehicle simulation tool used to certify HD vehicles. A detailed description of GEM can be found in the Phase 2 Regulatory Impacts Analysis or at https://www.epa.gov/regulations-emissions-vehicles-and-engines/greenhouse-gas-emissions-model-gem-medium-and-heavy-duty .
^{224} See 40 CFR 1037.140(g) and (h).
EPA also established optional custom chassis categories in the Phase 2 rule in recognition of the unique technical characteristics of these applications. These categories also recognize that many manufacturers of these custom chassis are not full-line heavy-duty vehicle companies and thus do not have the same flexibilities as other firms in the use of the Phase 2 program emissions averaging program which could lead to challenges in meeting the standards EPA established for the overall vocational vehicle and combination tractor program. We therefore established optional custom chassis CO 2 emission standards for Motorhomes, Refuse Haulers, Coach Buses, School Buses, Transit Buses, Concrete Mixers, Mixed Use Vehicles, and Emergency Vehicles. ^{225} In total, EPA set CO 2 emission standards for 15 subcategories of vocational vehicles and eight subcategories of specialty vehicle types for a total of 23 vocational vehicle subcategories.
^{225} The numeric values of the optional custom chassis standards are not directly comparable to the primary vocational vehicle standards. As explained in the HD GHG Phase 2 rule, there are simplifications in GEM that produce higher or lower CO 2 emissions. 81 FR 73686-73688, October 25, 2016.
The HD GHG Phase 2 standards phase in over a period of seven years, beginning with MY 2021. The HD GHG Phase 2 program progresses in three-year stages with an intermediate set of standards in MY 2024 and final standards in MY 2027 and later. In the HD GHG Phase 2 final rule, we identified a potential technology path for complying with each of the three increasingly stringent stages of the HD GHG Phase 2 program standards. These standards' feasibility are demonstrated through a potential technology path that is based on the performance of more efficient engines, workday idle reduction technologies, improved transmissions including mild hybrid powertrains, axle technologies, weight reduction, electrified accessories, tire pressure systems, and tire rolling resistance improvements. We developed the Phase 2 vocational vehicle standards using the methodology where we applied fleet average technology mixes to fleet average baseline vehicle configurations, and each average baseline and technology mix was unique for each vehicle subcategory. ^{226} When the HD GHG Phase 2 final rule was promulgated in 2016, we established CO 2 standards on the premise that electrification of the heavy-duty market would occur in the future but was unlikely to occur at significant sales volumes of electric vehicles in the timeframe of the program. As a result, the Phase 2 vocational vehicle CO 2 standards were not premised on the application of ZEV technologies, though such technologies could be used by manufacturers to comply with the standards. We finalized BEV, PHEV, and FCEV advanced technology credit multipliers within the HD GHG ABT program to incentivize increased application of these technologies that had the potential for large GHG emission reductions (see section III of this preamble for further discussion on this program and the targeted ways we are amending it). Details regarding the HD GHG Phase 2 standards can be found in the HD GHG Phase 2 final rule preamble and record, and the HD GHG Phase 2 vocational vehicle standards are codified at 40 CFR part 1037. ^{227}
^{226} 81 FR 73715, October 25, 2016.
^{227} 81 FR 73677-73725, October 25, 2016.

2. Combination Tractors
The tractor regulatory structure is attribute-based in terms of dividing the tractor category into ten subcategories based on the tractor's weight rating, cab configuration, and roof height. The tractors are subdivided into three weight ratings—Class 7 with a gross vehicle weight rating (GVWR) of 26,001 to 35,000 pounds; Class 8 with a GVWR over 33,000 pounds; and Heavy-haul with a gross combined weight rating of greater than or equal to 120,000 pounds. ^{228} The Class 7 and 8 tractor cab configurations are either day cab or sleeper cab. Day cab tractors are typically used for shorter haul operations, whereas sleeper cabs are often used in long haul operations. EPA set CO 2 emission standards for 10 tractor subcategories.
^{228} See 40 CFR 1037.801.
Similar to the vocational program, implementation of the HD GHG Phase 2 tractor standards began in MY 2021 and will be fully phased in for MY 2027. In the HD GHG Phase 2 final rule, EPA analyzed the feasibility of achieving the CO 2 standards and identified technology pathways for achieving the standards. The existing HD GHG Phase 2 CO 2 emission standards for combination tractors reflect reductions that can be achieved through improvements in the tractor's powertrain, aerodynamics, tires, idle reduction, and other vehicle systems as demonstrated using GEM. As we did for vocational vehicles, we developed a potential technology package for each of the tractor subcategories that represented a fleet average application of a mix of technologies to demonstrate the feasibility of the standard for each MY. ^{229} EPA did not premise the HD GHG Phase 2 CO 2 tractor emission standards on application of hybrid powertrains or ZEV technologies. However, we predicted some limited use of these technologies in MY 2021 and beyond and we finalized BEV, PHEV, and FCEV advanced technology credit multipliers within the HD GHG ABT program to incentivize a transition to these technologies (see section III of this preamble for further discussion on this program and the targeted ways we are amending it). More details can be found in the HD GHG Phase 2 final rule preamble, and the HD GHG Phase 2 tractor standards are codified at 40 CFR part 1037. ^{230}
^{229} 81 FR 73602-73611, October 25, 2016.
^{230} 81 FR 73571, October 25, 2016.

3. Heavy-Duty Engines
In HD GHG Phase 1, we developed a regulatory structure for CO 2 , nitrous oxide (N 2 O), and methane (CH 4 ) emission standards that apply to the engine, separate from the HD vocational vehicle and tractor. The regulatory structure includes separate standards for spark-ignition engines (such as gasoline engines) and compression-ignition engines (such as diesel engines), and for heavy heavy-duty (HHD), medium heavy-duty (MHD) and light heavy-duty (LHD) engines, that also apply to alternative fuel engines. We also used this regulatory structure for HD engines in HD GHG Phase 2. More details can be found in the HD GHG Phase 2 final rule preamble, and the HD GHG Phase 2 engine standards are codified at 40 CFR part 1036. ^{231}
^{231} 81 FR 73553-73571, October 25, 2016.

4. Heavy-Duty Vehicle Averaging, Banking, and Trading Program
Beginning with the HD GHG Phase 1 for HD GHG standards, EPA adopted an ABT program for CO 2 emission credits that allows ABT within a vehicle weight class, meaning that the regulations did not require all vehicles to meet the standard. ^{232} In promulgating the Phase 2 standards, we explained that the stringency of the Phase 2 standards was derived on a fleet average technology mix basis. For example, we projected that diversified manufacturers would continue to use the averaging provisions in the ABT program to meet the standards on average for each of their vehicle families. For the HD GHG Phase 2 ABT program, we created three weight class-based credit averaging sets for HD vehicles: LHD Vehicles, MHD Vehicles, and HHD Vehicles. This approach allowed ABT between all vehicles in the same weight class, including CI-powered vehicles, SI-powered vehicles, BEVs, FCEVs, and hybrid vehicles, which have the same regulatory useful life. Although the vocational vehicle emission standards are subdivided by Urban, Multi-purpose, and Regional regulatory subcategories, credit exchanges are currently allowed between them within the same weight class. However, these averaging sets currently exclude vehicles certified to the separate optional custom chassis standards. Finally, the ABT program currently allows credits to exchange between vocational vehicles and tractors within a weight class.
^{232} 40 CFR 1037.701 through 1037.750.
ABT is commonly used by vehicle manufacturers to comply with the standards of the HD GHG Phase 2 program. In MY 2022, 93 percent of the certified vehicle families (256 out of 276 families) used ABT. ^{233} Similarly, 29 out of 40 manufacturers in MY 2022 used ABT to certify some or all of their vehicle families. Most of the manufacturers that did not use ABT produced vehicles that were certified to the optional custom chassis standards where the banking and trading components of ABT are not allowed, and averaging is limited. ^{234}
^{233} U.S. EPA Heavy-Duty Vehicle Certification Data. Last accessed on January 25, 2023, at https://www.epa.gov/compliance-and-fuel-economy-data/annual-certification-data-vehicles-engines-and-equipment .
^{234} See 40 CFR 1037.105(h)(2) for details. See also 40 CFR 1037.241(a) providing for individual certification of heavy-duty vehicles.

D. Vehicle Technologies and Supporting Infrastructure
For this final rule, as we did for HD Phase 1 and Phase 2, we are finalizing more stringent CO 2 emissions standards for many of the regulatory subcategories and demonstrating the feasibility of those final standards based on the performance of a potential compliance pathway comprising of a package of technologies that reduce CO 2 emissions. And in this rule, we developed technology packages that include both vehicles with ICE and ZEV technologies. In determining which technologies to model, EPA initially considered the entire suite of technologies that we expected would be technologically feasible and commercially available to achieve significant emissions reductions, including the GHG-reducing technologies considered in the Phase 2 standards—including BEVs, FCEVs, H2-ICE vehicles, hybrid powertrains, plug-in hybrid vehicles (PHEVs), and alternative fueled-ICEVs. Because the statute requires EPA to consider lead time and costs in establishing standards, and because manufacturers (and purchasers) of HD vehicles are profit-generating enterprises that are seeking to reduce costs, EPA then identified the technologies that the record showed would be most effective at reducing CO 2 emissions and are cost-effective at doing so in the MYs 2027-2032 time frame, as discussed in this section II.D. As a result, EPA chose to model certain ICE vehicle technologies, BEV technologies, and FCEV technologies to support the feasibility of the final standards and for analyses for regulatory purposes, not because we have an a priori interest in promoting certain HD vehicle technologies over other technologies, but rather because our analysis of lead time and costs showed these are effective technologies at reducing CO 2 emissions and are cost-effective. The record also shows that the modeled potential compliance pathway is the lowest cost one that we assessed for manufacturers overall and would be beneficial for purchasers because the lower operating costs during the operational life of the vehicle will offset the increase in vehicle technology costs within the usual period of first ownership of the vehicle. At the same time, EPA modeled other technologies (examples of other potential compliance pathways with different mixes of technologies, as discussed in section II.F.6) recognizing that manufacturers can choose many different ways to achieve CO 2 emissions reductions to comply with the final performance-based standards. These additional example potential compliance pathways also support the feasibility of the final standards.
More specifically, as explained in section II.B.2, this final rule establishes new CO 2 emission standards for MY 2032 and later HD vehicles with more stringent CO 2 emission standards phasing in as early as MY 2027 for certain vehicle categories. We found that these final Phase 3 vehicle standards are appropriate and feasible, including consideration of cost of compliance and other factors, for their respective MYs and vehicle subcategories through technology improvements in several areas. To support the feasibility and appropriateness of the final standards, we evaluated each technology and estimated potential technology adoption rates of a mix of projected available technologies in each vehicle subcategory per MY (our technology packages) that EPA projects are achievable based on nationwide production volumes, considering lead time, technical feasibility, cost, and other factors. At the same time, the final standards are performance-based and do not mandate any specific technology for any manufacturer or any vehicle subcategory. In identifying the CO 2 standards and demonstrating the technological feasibility of such standards, we considered the statutory purpose of reducing emissions and the need for such emissions reductions, technological feasibility, costs, lead time and related factors (including safety). To evaluate and balance these statutory factors and other relevant considerations, EPA must necessarily estimate a means of compliance: what technologies can be used, what do they cost, what is appropriate lead time for their deployment, and the like. Thus, to support the feasibility of the final standards, EPA identified a modeled potential compliance pathway. Having identified one means of compliance, EPA's task is to “answe[r] any theoretical objections” to that means of compliance, “identif[y] the major steps necessary,” and to “offe[r] plausible reasons for believing that each of those steps can be completed in the time available.” NRDC v. EPA, 655 F. 2d at 332. That is what EPA has done here in this final rule, and indeed what it has done in all the motor vehicle emission standard rules implementing section 202(a) of the Act. As we stated earlier in this preamble, manufacturers remain free to comply by any means they choose, including through strategies that may resemble the additional example potential compliance pathways. Based on our experience to date, it is the norm that manufacturers devise means other than those projected by EPA as a potential technology path in support of the feasibility of the standards to achieve compliance.
For each regulatory subcategory, we modeled various ICE vehicles with CO 2 -reducing technologies to represent the average MY 2027 vehicle that meets the MY 2027 Phase 2 standards. These vehicles are used as baselines from which to evaluate costs and effectiveness of additional technologies for each of these vehicle types and ultimately for each regulatory subcategory. The following subsections describe the GHG emission-reducing technologies for HD vehicles which EPA considered in this final rulemaking, including those for HD vehicles with ICE (section II.D.1), HD BEVs (section II.D.2), and HD FCEVs (section II.D.3), as well as a summary of the technology assessment that supports the feasibility of the final Phase 3 standards (section II.D.4) and the primary inputs we used in our technology assessment tool, Heavy-Duty Technology Resource Use Case Scenario (HD TRUCS), that we developed to evaluate the design features needed to meet the power and energy demands of various HD vehicles when using ZEV technologies, as well as costs related to manufacturing, purchasing and operating ICE vehicle and ZEV technologies used under the modeled potential compliance pathway (section II.D.5).
As previously noted, we did not propose and are not adopting changes to the existing Phase 2 GHG emission standards for HD engines. As noted in the following section and RIA Chapter 1.4, there are technologies available that can reduce GHG emissions from HD engines, and we anticipate that many of them will be used to meet the MY 2024 and MY 2027 and later Phase 2 CO 2 engine emission standards, while developments are underway to meet the new low NO X standards for MY 2027. ^{235} This final rule remains focused on GHG reductions through more stringent vehicle-level CO 2 emission standards, which will continue to account for engine CO 2 emissions, instead of also finalizing new CO 2 emission standards that apply to heavy-duty engines.
^{235} 40 CFR 1036.104.

1. Technologies To Reduce GHG Emissions From HD ICE Vehicles
The CO 2 emissions of HD vehicles vary depending on the configuration of the vehicle. Many aspects of the vehicle impact its emissions performance, including the engine, transmission, drive axle, aerodynamics, and rolling resistance.
The technologies we considered for tractors include technologies that we analyzed in Phase 2 such as improved aerodynamics; low rolling resistance tires; tire inflation systems; efficient engines, engines fueled with natural gas, transmissions, drivetrains, and accessories; and extended idle reduction for sleeper cabs. We analyzed the overall effectiveness of the technology packages using EPA's Greenhouse Gas Emissions Model (GEM), which was used for analyzing the technology packages that support the Phase 2 vehicle CO 2 emission standards and is used by manufacturers to demonstrate compliance with the Phase 2 standards. EPA's GEM model simulates road load power requirements over various duty cycles to estimate the energy required per mile for HD vehicles. The inputs for the individual technologies that make up the fleet average technology package that meets the Phase 2 MY 2027 CO 2 tractor emission standards are shown in Table II-3. ^{236} The comparable table for vocational vehicles is shown in Table II-4. ^{237} The technology package for vocational vehicles include technologies such as low rolling resistance tires; tire inflation systems; efficient engines, transmissions, and drivetrains; weight reduction; and idle reduction technologies. Note that the HD GHG Phase 2 standards (like the Phase 1 and 3 standards) are performance-based; EPA does not require this specific technology mix, rather the technologies shown in Table II-3 and Table II-4 are potential pathways for compliance.
^{236} 81 FR 73616, October 25, 2016.
^{237} 81 FR 73714, October 25, 2016.
Technologies exist today and continue to evolve to improve the efficiency of the engine, transmission, drivetrain, aerodynamics, and tire rolling resistance in HD vehicles and therefore reduce their CO 2 emissions. As discussed in the preamble to the HD GHG Phase 2 program and shown here in Table II-3 and Table II-4, there are a variety of such technologies. In developing the Phase 2 CO 2 emission standards, we developed technology packages that were premised on a mix of projected technologies and potential technology adoption rates of less than 100 percent. As discussed in section II.F.4 under the additional example potential compliance pathways, there is an opportunity for further improvements and increased adoption through MY 2032 for many of these technologies. Furthermore, as discussed in section II.F.4 under the additional example potential compliance pathways, we also considered additional technologies than those in the Phase 2 MY 2027 technology packages such as H2-ICE, hybrids, and natural gas engines. Each of these technologies is discussed in this section and RIA Chapter 1.4.

i. Aerodynamics
For example, we evaluated the potential for additional GHG performance gains from aerodynamic improvements. Up to 25 percent of the fuel consumed by a sleeper cab tractor traveling at highway speeds is used to overcome aerodynamic drag forces, making aerodynamic drag a significant contributor to a Class 7 or 8 tractor's GHG emissions and fuel consumption. ^{238} Because aerodynamic drag varies by the square of the vehicle speed, small changes in the tractor aerodynamics can have a large impact on the GHG emissions of a tractor. With much of their driving at highway speed, the GHG emission reductions of reduced aerodynamic drag for Class 7 or 8 tractors can be significant. ^{239}
^{238} Assumes travel on level road at 65 miles per hour. (21st Century Truck Partnership Roadmap and Technical White Papers, December 2006. U.S. Department of Energy, Energy Efficiency and Renewable Energy Program. 21CTP-003. p.36.
^{239} Reducing Heavy-Duty Long Haul Combination Truck Fuel Consumption and CO2 Emissions, ICCT, October 2009.
Improving the vehicle shape may include revising the fore components of the vehicle such as rearward canting/raking or smoothing/rounding the edges of the front-end components ( e.g., bumper, headlights, windshield, hood, cab, mirrors) or integrating the components at key interfaces ( e.g., windshield/glass to sheet metal) to alleviate fore vehicle drag. Finally, improvements may include redirecting the air to prevent areas of low pressure and slow-moving air (thus, eliminating areas where air builds creating turbulent vortices and increasing drag). Techniques such as blocking gaps in the sheet metal, ducting of components, shaping or extending sheet metal to reduce flow separation and turbulence are methods being considered by manufacturers to direct air from areas of high drag ( e.g., underbody and tractor-trailer gap).
As discussed in the Phase 2 RIA, the National Research Council of Canada performed an assessment of the aerodynamic drag effect of various tractor components. ^{240} Based on the results, there is the potential to improve tractor aerodynamics by 0.206 wind averaged coefficient of drag area (CdA) with the addition of wheel covers, drive axle wrap around splash guards, and roof fairing rear edge filler. Up to 0.460 CdA improvement is possible if the side and fender mirrors are replaced with a camera system, as suggested by the study, and combined with the wheel covers, drive axle wrap around splash guards, and roof fairing rear edge filler. In our Phase 2 analysis, considering the wind average drag performance of heavy-duty tractors at the time, this study demonstrated the possibility to improve tractors an additional ~1 percent with some simple changes.
^{240} Jason Leuschen and Kevin R. Cooper (National Research Council of Canada), Society of Automotive Engineer. (SAE) Paper #2006-01-3456: “Full-Scale Wind Tunnel Tests of Production and Prototype, Second-Generation Aerodynamic Drag-Reducing Devices for Tractor-Trailers.” November 2, 2006.
In Phase 2, the tractor aerodynamic performance was evaluated using the wind averaged coefficient of drag area results measured during aerodynamic testing as prescribed in 40 CFR 1037.525. The results of the aerodynamic testing are used to determine the aerodynamic bin and CdA input value for GEM, as prescribed in 40 CFR 1037.520 and shown in Table II-5.
EPA conducted aerodynamic testing for the Phase 2 final rule. ^{241} As shown in Phase 2 RIA Chapter 3.2.1.2, the most aerodynamic high roof sleeper cabs tested had a CdA of approximately 5.4 m ^2 , which is a Bin IV tractor. Therefore, we concluded that prior to 2016 manufacturers were producing high roof sleeper cabs that range in aerodynamic performance between Bins I and IV. Bin V is achievable through the addition of aerodynamic features that improve the aerodynamics on the best pre-2016 sleeper cabs tested by at least 0.3 m ^2 CdA. The features that could be added include technologies such as wheel covers, drive axle wrap around splash guards, and roof fairing rear edge filler, and active grill shutters. In addition, manufacturers continue to improve the aerodynamic designs of the front bumper, grill, hood, and windshield.
^{241} U.S. EPA. Regulatory Impact Analysis Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 2. Chapter 3. EPA-420-R-16-900. August 2016.
Our analysis of high roof day cabs is similar to our assessment of high roof sleeper cabs. Also, as shown in Phase 2 RIA Chapter 3.2.1.2, the most aerodynamic high roof day cab tested by EPA achieved Bin IV. Our assessment is that the same types of additional technologies that could be applied to high roof sleeper cabs could also be applied to high roof day cabs to achieve Bin V aerodynamic performance. Finally, because the manufacturers have the ability to determine the aerodynamic bin of low and mid roof tractors from the equivalent high roof tractor, this assessment also applies to low and mid roof tractors.
For our modeled potential compliance pathway in Phase 3 tractors' technology packages, the vehicles with ICE portion of the technology package for the MY 2027 high roof sleeper cab tractor includes 20 percent Bin III, 30 percent Bin IV, and 50 percent Bin V reflecting our assessment of the fraction of high roof sleeper cab tractors. We continue to project, as we projected in the Phase 2 rulemaking, that manufacturers could successfully apply these aerodynamic packages by MY 2027. The weighted average for tractors of this set of adoption rates is equivalent to a tractor aerodynamic performance near the border between Bin IV and Bin V.
The Phase 2 standards for vocational vehicles were not projected to be met with the use of aerodynamic improvements.

ii. Tire Rolling Resistance
Energy loss associated with tires is mainly due to deformation of the tires under the load of the vehicle, known as hysteresis, but smaller losses result from aerodynamic drag, and other friction forces between the tire and road surface and the tire and wheel rim. Collectively the forces that result in energy loss from the tires are referred to as rolling resistance. Tires with higher rolling resistance lose more energy, thus using more fuel and producing more CO 2 emissions in operation, while tires with lower rolling resistance lose less energy, and use less fuel, producing less CO 2 emissions in operation.
A tire's rolling resistance is a factor considered in the design of the tire and is affected by the tread and casing compound materials, the architecture of the casing, tread design, and the tire manufacturing process. It is estimated that 35 to 50 percent of a tire's rolling resistance is from the tread and the other 50 to 65 percent is from the casing. ^{242} Tire inflation can also impact rolling resistance in that under-inflated tires can result in increased deformation and contact with the road surface.
^{242} “Tires & Truck Fuel Economy,” A New Perspective. Bridgestone Firestone, North American Tire, LLC, Special Edition Four, 2008. EPA-HQ-OAR-2010-0162-0373.
In Phase 2, we developed four levels of tire rolling resistance, as shown in Table II-6. The levels included the baseline (average) from 2010, Level I and Level 2 from Phase 1, and Level 3 that achieves an additional 25 percent improvement over Level 2. The Level 2 threshold represents an incremental step for improvements beyond today's SmartWay level and represents the best in class rolling resistance of the tires we tested for Phase 1. ^{243} The Level 3 values represented the long-term rolling resistance value that EPA projected could be achieved in the MY 2025 timeframe. Given the multiple year phase-in of the Phase 2 standards, EPA expected that tire manufacturers will continue to respond to demand for more efficient tires and will offer increasing numbers of tire models with rolling resistance values significantly better than the typical low rolling resistance tires offered in 2016.
^{243} U.S. EPA. SmartWay Verified Low Rolling Resistance Tires Performance Requirements. Available online: https://www.epa.gov/sites/default/files/2016-02/documents/420f12024.pdf .
In the modeled compliance pathway for the Phase 3 tractors' technology packages, the vehicles with ICE portion of the technology package for the MY 2027 included steer and drive tires that on average performed at a Level 2 rolling resistance. We continue to project, as we projected in the Phase 2 rulemaking, that manufacturers could successfully apply tires that on average perform at this level by MY 2027.

iii. Natural Gas Engines
Natural-gas powered heavy-duty vehicles are very similar to gasoline and diesel fueled ICE-powered vehicles. The engine functions the same as a gasoline or diesel fueled ICE. Two key differences are the fuel storage and delivery systems. The fuel delivery system delivers high-pressure natural gas from the fuel tank to the fuel injectors located on the engine. Similar to gasoline or diesel fuel, natural gas is stored in a fuel tank, or cylinder, but requires the ability to store the fuel under high pressure.
There are different ways that heavy-duty engines can be configured to use natural gas as a fuel. The first is a spark-ignition natural gas engine. An Otto cycle SI heavy-duty engine uses a spark plug for ignition and burns the fuel stoichiometrically. Due to this, the engine-out emissions require use of a three-way catalyst to control criteria pollutant emissions. The second is a direct injection natural gas that utilizes a compression-ignition (CI) cycle. The CI engine uses a small quantity of diesel fuel (pilot injection) as an ignition source along with a high compression ratio engine design. The engine operates lean of stoichiometric operation, which leads to engine-out emissions that require aftertreatment systems similar to diesel ICEs, such as diesel oxidation catalysts, selective catalytic reduction systems, and diesel particulate filters. The CNG CI engine is more costly than a diesel CI engine because of the special natural gas/diesel fuel injection system. The NG SI engine and aftertreatment system is less costly than a NG CI engine and aftertreatment system but is less fuel efficient than a NG CI engine because of the lower compression ratio.
In addition to differences in engine architecture, the natural gas fuel can be stored two ways—compressed (CNG) or liquified (LNG). A CNG tank stores pressurized gaseous natural gas and the system includes a pressure regulator. An LNG tank stores liquified natural gas that is cryogenically cooled but stored at a lower pressure than CNG. The LNG tanks often are double walled to help maintain the temperature of the fuel, and include a gasification system to turn the fuel from a liquid to a gas before injecting the fuel into the engine. An important advantage of LNG is the increased energy density compared to CNG. Because of its higher energy density, LNG can be more suitable for applications such as long-haul applications.
Natural gas engines are a mature technology. Cummins manufactures natural gas engines that cover the complete range of heavy-duty vehicle applications, with engine displacements ranging from 6.7L to 12L. Heavy-duty CNG and LNG vehicles are available today in the fleet. EIA estimates that approximately 4,400 CNG and LNG heavy-duty vehicles were sold in 2022 and approximately 50,000 CNG and LNG vehicles are in the U.S. heavy-duty fleet. ^{244} Manufacturers are producing CNG and LNG vehicles in all of the vocational and tractor categories, especially buses, refuse hauler, street sweeper, and tractor applications, as discussed further in RIA Chapter 1.4.1.2. ^{245}
^{244} EIA. Annual Energy Outlook 2023. Table 49. Available Online: https://www.eia.gov/outlooks/aeo/data/browser/#/?id=58-AEO2023&cases=ref2023&sourcekey=0 .
^{245} Department of Energy Alternative Fuels Data Center. Available Online: https://afdc.energy.gov/vehicles/search/results?manufacturer_id=67,205,117,394,415,201,113,5,408,481,9,13,11,458,81,435,474,57,416,141,197,417,121,475,53,397,418,85,414,17,21,143,476,492,23,484,398,27,477,399,31,207,396,489,107,465,487,193,460,35,459,115,37,147,480,199 .

iv. Hydrogen-Fueled Internal Combustion Engines
Currently, hydrogen fueled internal combustion engines (H2-ICE) are in the demonstration stage. H2-ICE is a technology that provides nearly zero tailpipe emissions for hydrocarbons, carbon monoxide, and carbon dioxide. H2-ICE require less exhaust aftertreatment. These systems may not require the diesel particulate filter (DPF). However, NO X emissions are still formed during the H2-ICE combustion process and therefore a selective catalytic reduction (SCR) system would be required, as well a diesel oxidation catalyst, though it may be smaller in size than that used in a comparable diesel-fueled ICE. The use of lean air- fuel ratios, and not exhaust gas recirculation (EGR), is the most effective way to control NO X in a H2-ICE, as EGR is less effective with H2 due to the absence of CO 2 in the exhaust gas.
H2-ICE can be developed using an OEM's existing tooling, manufacturing processes, and engine design expertise. H2-ICE engines are very similar to existing ICEs and can leverage the extensive technical expertise manufacturers have developed with existing products. Similarly, H2-ICE products can be built on the same assembly lines as other ICE vehicles, by the same workers and with many of the same component suppliers.
H2-ICE incorporate several differences from their diesel baseline. Components such as the cylinder head, valves, seals, piston, and piston rings would be unique to the H2-ICE to control H2 leakage during engine operation. Another difference between a diesel-fueled ICE and a H2-ICE is the fuel storage tanks. The hydrogen storage tanks are more expensive than today's diesel fuel tanks. The fuel tanks likely to be used by H2-ICE are identical to those used by a fuel cell electric vehicle (FCEV) and they may utilize either compressed storage (350 or 700 Bar pressure) or cryogenic storage (temperatures as low as −253 Celsius). Please refer to Chapter 1.7.2 of this document for the discussion regarding H2 fuel storage tanks.
H2-ICE may hasten the development of hydrogen infrastructure because they do not require as pure of hydrogen as FCEVs. Hydrogen infrastructure exists in limited quantities in some parts of the country for applications such as forklifts, buses, and LDVs and HDVs at ports. Federal funds are being used to support the development of additional hubs and other hydrogen related infrastructure items through the BIL and IRA, as described in more detail in Chapter 1.8.
Since neat hydrogen fuel does not contain any carbon, H2-ICE fueled with neat hydrogen produce zero HC, CH 4 , CO, and CO 2 engine-out emissions. ^{246} However, as explained in section III.C.2.xviii, we recognize that, like CI ICE, there may be negligible, but non-zero, CO 2 exhaust emissions of H2-ICE that use SCR and are fueled with neat hydrogen due to contributions from the aftertreatment system from urea decomposition. Thus, for purposes of compliance with engine CO 2 exhaust emission standards under 40 CFR part 1036, we are finalizing an engine testing default CO 2 emission value (3 g/hp-hr) option (though manufacturers may instead conduct testing to demonstrate that the CO 2 emissions for their engine is below 3 g/hp-hr). Under our existing fuel-mapping test procedures that may be used as part of demonstrating compliance with vehicle CO 2 exhaust emission standards, the results are fuel consumption values and therefore the CO 2 emissions from urea decomposition are not included in the results. 247 248 Under this final rule, consistent with existing treatment of such contributions from the aftertreatment system from urea decomposition ( e.g., for diesel ICE vehicles) for compliance with vehicle CO 2 exhaust emission standards, we are not including such contributions in determining compliance with vehicle CO 2 exhaust emission standards for H2-ICE vehicles. Thus, H2-ICE technologies that run on neat hydrogen, as defined in 40 CFR 1037.150(f) and discussed in section III.C.3.ii of the preamble, have HD vehicle CO 2 emissions that are deemed to be zero for purposes of compliance with vehicle emission standards under 40 CFR part 1037. Therefore, the technology effectiveness (in other words CO 2 emission reduction) for the vehicles that are powered by this technology is 100 percent for compliance with vehicle CO 2 exhaust emission standards.
^{246} Note, NO X and PM emission testing is required under existing 40 CFR part 1036 for engines fueled with neat hydrogen.
^{247} See 81 FR 73552 (October 25, 2016), for the explanation on why CO 2 from urea decomposition is included when showing compliance with the engine standards and it is not included when showing compliance with the vehicle CO 2 standards.
^{248} See, e.g., 40 CFR 1037.501 (including reference to 40 CFR 1036.535, 1036.540, and 1036.545).

v. Hybrid and Plug-In Hybrid Powertrains
The heavy-duty industry has also been developing hybrid powertrains, as described in RIA Chapter 1.4.1.1. Hybrid powertrains consist of an ICE as well as an electric drivetrain. The ICE uses a consumable fuel ( e.g., diesel) to produce power which can either propel the vehicle directly or charge the traction battery from which the electric motor draws its energy. These two sources of power can be used in combination to do work and move the vehicle, or they may operate individually, switching between the two sources. Plug-in hybrid electric vehicles (PHEVs) are a combination of ICE and electric vehicles, so they have an ICE and a battery, an electric motor, and a fuel tank, and plug-in to the electric grid to recharge the battery. PHEVs use both gasoline or diesel and electricity as fuel sources.
Hybrid powered vehicles can provide CO 2 emission reductions from splitting or blending of ICE and electric operation. Hybrid vehicles reduce CO 2 emissions through four primary mechanisms:
• In a series hybrid powertrain, the ICE operates as a generator to create electricity for the battery. Series hybrids can be optimized through downsizing, modifying the operating cycle, or other control techniques to operate at or near its most efficient engine speed-load conditions more often than is possible with a conventional engine-transmission driveline. Power loss due to engine downsizing can be mitigated by employing power assist from the secondary, electric driveline.
• Hybrid vehicles typically include regenerative braking systems that capture some of the energy normally lost while braking and store it in the traction battery for later use. That stored energy is typically used to provide additional torque upon initial acceleration from stop or additional power for moving the vehicle up a steep incline.
• Hybrid powertrains allow the engine to be turned off when it is not needed, such as when the vehicle is coasting or when the vehicle is stopped. Furthermore, some vehicle systems such as cabin comfort and power steering can be electrified if a 48V or higher battery system is incorporated into the vehicle. The electrical systems are more efficient than their conventional counterparts which utilize an accessory drive belt on a running engine. When the engine is stopped these accessory loads are supported by the traction battery.
• Plug-in hybrid vehicles can further reduce CO 2 emissions by increasing the battery storage capacity and adding the ability to connect to the electrical power grid to fully charge the battery when the vehicle is not in service, which can significantly expand the amount of all-electric operation.
Hybrid vehicles can utilize a combination of some or all of these mechanisms to reduce fuel consumption and CO 2 emissions. The magnitude of the CO 2 reduction achieved depends on the utilization/optimization of the previously listed mechanisms and the powertrain design decisions made by the manufacturer.
Hybrid technology is well established in the U.S. light-duty market, where some manufacturers have been producing light-duty hybrid models for several decades and others are looking to develop hybrid models in the future. Hybrid powertrains are available today in a number of heavy-duty vocational vehicles including passenger van/ shuttle bus, transit bus, street sweeper, refuse hauler, and delivery truck applications. Hybrid transit buses have been purchased for use in cities including Philadelphia, PA, and Toronto, Canada. Heavy-duty hybrid vehicles may include a power takeoff (PTO) system that is used to operate auxiliary equipment, such as the boom/bucket on a utility truck or the water pump on a fire truck. Utility trucks with electric PTOs where the electricity to power the auxiliary equipment can be provided by the battery have been sold.
Plug-in hybrid electric vehicles run on both electricity and fuel. Many PHEV models are available today in the light-duty market. ^{249} Today there is a limited number of PHEV heavy-duty models. Light-duty manufacturers that also produce heavy-duty vehicle could bring PHEVs to market in the LHD and MHD segments in less time than for the HHD and tractor segments. The utility factor is the fraction of miles the vehicle travels in electric mode relative to the total miles traveled. The percent CO 2 emission reduction is directly related to the utility factor. The greater the utility factor, the lower the tailpipe CO 2 emissions from the vehicle. The utility factor depends on the size of the battery and the operator's driving habits.
^{249} US Department of Energy. Fueleconomy.gov. Available online: https://fueleconomy.gov/feg/PowerSearch.do?action=alts&path=3&year=2024&vtype=Plug-in+Hybrid&srchtyp=yearAfv&rowLimit=50&pageno=1 .

vi. ICE Vehicle Technologies in the Modeled Potential Compliance Pathway
We received a number of comments on technologies to reduce CO 2 emissions from ICE vehicles. One commenter indicated that vehicle improvements to ICE vehicles would be cost-effective and could lead to appreciable further reductions from ICE vehicles. Specifically, the commenter pointed to improvements of nearly 7 percent for vehicle improvements to high-roof sleeper cabs (aerodynamic improvements, tires, intelligent controls, weight reduction, axle efficiency, reduced accessory load); nearly 10 percent for vehicle improvements for multi-purpose vocational vehicles (stop-start, weight reduction, tires, axle efficiency, aerodynamic improvements, reduced accessory load); improvements from 6-12 percent from vehicle improvements to Class 7 and 8 tractors; and from 15-20 percent for vehicle improvements for vocational vehicles (all percentages reflecting incremental improvements beyond the MY 2027 Phase 2 standard). Further improvements are posited by the commenter if engine improvements are considered. Another commenter echoed those comments, urging that the standards reflect further improvements for ICE vehicles. Acknowledging that these improvements could be viewed as a different compliance pathway to meet the proposed standards (which is consistent with the proposal and final rule explaining the Phase 3 standards are performance-based standards), the commenter urged that these improvements be incremental to any improvements predicated on a ZEV technology package. A third commenter also supported the first commenter's assessment of engine and vehicle technologies and further cited a separate comment submitted to EPA that cylinder deactivation used as active thermal management also improves efficiency.
On the other hand, several HD vehicle manufacturers noted that some ICE vehicle technologies have lagged behind projections made by EPA to support the Phase 2 rule. These technologies include automatic tire inflation systems, electric accessories, and tamper proof idle reduction for vocational vehicles, stop-start technologies, and advanced transmission shifting strategies. Some of the reasons include lack of technology availability ( e.g., engine stop-start), technology costs ( e.g., auto tire inflation, electric accessories), customer adoption willingness ( e.g., one-minute idle shutdown timers), and high compliance costs ( e.g., powertrain testing).
For the final rule analysis, we evaluated the manufacturers' compliance with the MY 2021 standards (the first year of Phase 2). While the manufacturers note in comments that they are not seeing the adoption of certain engine and vehicle technologies at the rates shown in EPA's technology package to support the Phase 2 rule, this does not mean that the technologies EPA expected are not available; it just means manufacturers have found different ways to comply. In addition, we are still several years away from the MY 2027 vehicle production so there continues to be time for increased adoption of these technologies. Furthermore, EPA's emission standards are performance-based and manufacturers will use a number of different technologies to comply. These include all those listed in the Phase 2 package for MY 2027 because they are being installed on vehicles today, hybrids including PHEVs, and alternative fueled vehicles such as natural gas, as suggested by commenters. We are thus not convinced that these technologies are not available for Phase 3 consistent with the potential compliance pathway we projected in Phase 2 and currently project.
For the ICE vehicle technologies part of the analysis that supports the feasibility of the Phase 3 standards, our assessment is that technology packages developed for the Phase 2 rule are still appropriate for use in this final rule and thus the technology packages for the potential compliance pathway include a mix of ICE vehicle technologies and adoption rates of those technologies at the levels included in the Phase 2 MY 2027 technology packages. We also developed other additional potential compliance pathways, with different technology packages, to support the feasibility of the Phase 3 final standards that are based on vehicles with ICE technologies. See section II.F.4 of this preamble. These example compliance pathways include consideration of potential different pathways to compliance through the use of such ICE vehicle technologies beyond those included in the Phase 2 MY 2027 technology packages, plus technologies such as H2-ICE, plug-in hybrids, and natural gas engines. Additional discussion can be found in section 9.2 of the RTC.

2. HD Battery Electric Vehicle Technology and Infrastructure
In addition to assessing ICE technologies, EPA also assessed BEV technologies, which we anticipate will be widely available for many HD vehicle applications during the timeframe for this rule and which have the potential to achieve very large CO 2 emissions reductions. Our assessment of feasibility of the Phase 3 standards includes not only an assessment of the performance of projected potential emissions control technologies, but also the availability of this technology within the rule's timeframe. Our assessment of technology availability includes evaluating the availability of critical minerals for such technologies (including issues associated with supply chain readiness) and the readiness of sufficient supporting electrical infrastructure. The following subsections address each of these elements.
The HD BEV market has been growing significantly since MY 2018. RIA Chapter 1.5 includes BEV vehicle information on over 160 models produced by over 60 manufacturers that cover a broad range of applications, including school buses, transit buses, straight trucks, refuse haulers, vans, tractors, utility trucks, and others, available to the public through MY 2024. Others project significant growth of ZEV sales to continue into the future, achieving 50 percent by 2035. ^{250}
^{250} Truckinginfo.com “ACT: Half of Class 4-8 Sales to be BEV by 2035.” February 2022. Available online: https://www.truckinginfo.com/10161524/act-half-of-class-4-8-sales-to-be-bev-by-2035 .

i. Batteries Design Parameters
The battery electric propulsion system includes a battery pack that provides the energy to the motor that moves the vehicle. In this section, and in RIA Chapter 1.5.1 and 2.4, we discuss battery technology that can be found in both BEVs and FCEVs.
Battery design involves considerations related to cost ^{251} and performance including specific energy ^{252} and energy density, ^{253} temperature impact, durability, and safety. These parameters typically vary based on the cathode and anode materials, and on the conductive electrolyte medium at the cell level. Different battery chemistries have different intrinsic values. Here we provide a brief overview of the different energy and power parameters of batteries and battery chemistries.
^{251} Cost here is associated with cost of the battery design. This cost may be associated with using more expensive minerals ( e.g., nickel and cobalt instead of iron phosphate). Alternatively, some battery cell components may be more expensive for the same chemistry. For example, power battery cells are more expensive to manufacture than energy battery cells because these cells require thinner electrodes which are more complex to produce.
^{252} Battery specific energy (also referred to as gravimetric energy density) is a measure of battery energy per unit of mass.
^{253} Volumetric energy density (also called energy density) is a measure of battery energy per unit of volume.

a. Battery Energy and Power Parameters
Specific energy and power and energy density are a function of how much energy or power can be stored per unit mass (in Watt-hour per kilogram (Wh/kg) or Watt per kilogram (W/kg)) or volume (in Watt-hour per liter (Wh/L)). Therefore, for a given battery weight or mass, the energy (in kilowatt-hour or kWh) can be calculated. For example, a battery with high specific energy and a lower weight may yield the same amount of energy as a chemistry with a lower specific energy and more weight.
Battery packs have a “nested” design where a group of cells are combined to make a battery module and a group of modules are combined to make a battery pack. Therefore, the battery systems can be described on the pack, module, and cell levels. Common battery chemistries today include lithium-ion based cathode chemistries, such as nickel-manganese-cobalt (NMC), nickel-cobalt-aluminum (NCA), and iron-phosphate (LFP). Nickel-based chemistries typically have higher gravimetric and volumetric energy densities than iron phosphate-based chemistries. Since energy or power is only housed at the chemistry level, any additional mass such as the cell, module, and pack casings will only add to the weight of the battery without increasing the energy of the overall system. Therefore, some pack producers have eliminated the module in favor of a “cell-to-pack” design in recent years. ^{254}
^{254} BYD “blade” cells are an example of cell-to-pack technology.
External factors, especially temperature, can have a strong influence on the performance of the battery. Like all BEVs, heavy-duty BEVs today include thermal management systems to keep the battery operating within a desired temperature range, which is commonly referred to as conditioning of the battery. Therefore, while operating a vehicle in cold temperatures, some of the battery energy is used to heat both the battery packs and the vehicle interior. ^{255} Cold temperatures, in particular, can result in reduced mobility of the lithium ions in the liquid electrolyte inside the battery; for the driver, this may mean lower range. Battery thermal management is also used during hot ambient temperatures to keep the battery from overheating. We consider and account for the energy required for battery thermal management in our analysis, as discussed in section II.D.5.ii.b.
^{255} https://www.aaa.com/AAA/common/AAR/files/AAA-Electric-Vehicle-Range-Testing-Report.pdf .

b. Battery Durability
Another important battery design consideration is the durability of the battery. Durability is frequently associated with cycle life, where cycle life is the number of times a battery can fully charge and discharge before the battery capacity falls below the minimum design capacity. ^{256} In 2015 the United Nations Economic Commission for Europe (UN ECE) began studying the need for a Global Technical Regulation (GTR) governing battery durability in light-duty vehicles. In 2021 it finalized United Nations Global Technical Regulation No. 22, “In-Vehicle Battery Durability for Electrified Vehicles,” ^{257} or GTR No. 22, which provides a regulatory structure for contracting parties to set standards for battery durability in light-duty BEVs and PHEVs. Likewise, although not finalized, the UN ECE GTR working group began drafting language for HD BEVs and hybrid electric vehicles. Loss of electric range can lead to a loss of utility, meaning electric vehicles can be driven less and therefore displace less distance travelled than might otherwise be driven in ICE vehicles. Furthermore, a loss in utility can dampen purchaser sentiment.
^{256} The minimum design capacity is typically defined as the point where the usable battery energy (UBE) is less than 70 or 80 percent of the UBE of a new battery.
^{257} United Nations Economic Commission for Europe, Addendum 22: United Nations Global Technical Regulation No. 22, United Nations Global Technical Regulation on In-vehicle Battery Durability for Electrified Vehicles, April 14, 2022. Available at: https://unece.org/sites/default/files/202204/ECE_TRANS_180a22e.pdf .
For batteries that are used in HD BEVs, the state of health (SOH) is an important design factor. The performance of electrified vehicles may be affected by excess degradation of the battery system over time, thus reducing the range of the vehicle. However, the durability of a battery is not limited to the cycling of a battery; there are many phenomena that can impact the duration of usability of a battery. As a battery goes through charge and discharge cycles, the SOH of the battery decreases. Capacity fade, increase in internal resistance, and voltage loss, for example, are other common metrics to measure the SOH of a battery. These parameters together help better understand and define the longevity or durability of the battery. The SOH and, in turn, the cycle life of the battery are determined by both the chemistry of the battery and external factors including temperature. The rate at which the battery is discharged as well as the rate at which it is charged will also impact the SOH of the battery. Lastly, calendar aging, or degradation of the battery while not in use, can also contribute to the deterioration of the battery.
There are several ways to improve and prolong the battery life in a vehicle. In our assessment, we account for maintaining the battery temperature while driving by applying additional energy required for conditioning the battery. See section II.D.5 of this preamble.

c. HD BEV Safety Assessment
HD BEV systems must be designed to always maintain safe operation. As with any on-road vehicle, BEVs must be robust while operating in temperature extremes as well as in rain and snow. The BEV systems must be designed for reasonable levels of immersion, including immersion in salt water or brackish water. BEV systems must also be designed to be crashworthy and limit damage that compromises safety. If the structure is compromised by a severe impact, the systems must provide first responders with a way to safely conduct their work at an accident scene. The HD BEV systems must be designed to ensure the safety of users, occupants, and the general public in their vicinity.
In RIA Chapter 1.5.2, we discuss the industry codes and standards used by manufacturers that guide safe design and development of heavy-duty BEVs, including those for developing battery systems and charging systems that protect people and the equipment. These standards have already been developed by the industry and are in place for manufacturers to use to develop current and future products. The standards guide the design of BEV batteries to allow them to safely accept and deliver power for the life of the vehicle. The standards provide guidance to design batteries that also handle vibration, temperature extremes, temperature cycling, water, and mechanical impact from items such as road debris. For HD BEVs to uphold battery/electrical safety during and after a crash, they are designed to maintain high voltage isolation, prevent leakage of electrolyte and volatile gases, maintain internal battery integrity, and withstand external fire that can come from the BEV or other vehicle(s) involved in a crash. NHTSA continues work on battery safety requirements in FMVSS No. 305 to extend its applicability to HD vehicles, aligning it with the existing Global Technical Regulation (GTR) No. 20, and including safety requirements during normal operation, charging, and post-crash.
We requested comment on our assessment at proposal that HD BEV systems must be, and are, designed “to always maintain safe operation.” 88 FR 25962. Some commenters supported our assessment that there are industry codes and standards for the safe design and operation of HD BEVs. In addition, some commenters highlighted that HD BEVs are subject to, and necessarily comply with, the same Federal safety standards and the same safety testing as ICE heavy-duty vehicles. Commenters challenging the safety of HD BEVs failed to address the existence of these protocols and Federal standards. While considering safety for the NPRM, EPA obtained NHTSA input. EPA obtained additional NHTSA safety input regarding comments and updates for the final rulemaking. ^{258}
^{258} Landgraf, Michael. Memorandum to docket EPA-HQ-OAR-2022-0985. Summary of NHTSA Safety Communication. February 2024.
Moreover, empirical evidence from the light-duty sector (where BEVs have been on the road in greater numbers and for a longer period), shows that BEVs “are at least as safe” as combustion vehicles in terms of crashworthiness test performance, and “injury claims are substantially less frequent” for BEVs than for combustion vehicles. ^{259} A DOE study found that on some safety metrics, BEVs perform substantially better than ICE vehicles. Due to their battery architecture, for example, BEVs typically have a lower center of gravity than combustion vehicles, which increases stability and reduces the risk of rollovers (the cause of up to 35 percent of accident deaths). ^{260} Most vehicle weight classes do not change. The distribution of HD vehicle weights may shift higher with BEV adoption but the maximum allowed weight for a given weight class does not change. The one exception is for BEV Class 8 that are allowed to increase their GCWR from 80,000 lbs to 82,000, a 2.5 percent increase. ^{261} We coordinated with NHTSA to assess the safety concerns due to vehicle weight. NHTSA is not aware of differences in crash outcomes between electric and non-electric vehicles. See RTC section 4.8. NHTSA is monitoring this topic closely and is conducting extensive research on the potential differences between ICE and electric vehicles.
^{259} Insurance Institute for Highway Safety, “With More Electric Vehicles Comes More Proof of Safety” (April 22, 2021), https://www.iihs.org/news/detail/with-more-electric-vehicles-comes-more-proof-of-safety .
^{260} U.S. Department of Energy, “Maintenance and Safety of Electric Vehicles”, https://afdc.energy.gov/vehicles/electric_maintenance.html (October 23, 2023).
^{261} 23 U.S.C. 127(s).
Fire risk, emergency response, and maintenance can also be managed effectively. There is evidence (discussed more fully in RTC section 4.8) that BEVs are less likely to catch fire than internal combustion engine vehicles. Although BEVs can behave differently in fires from ICE vehicles, emergency responders have been gaining experience in BEV fire response as the number of BEVs on the road has grown, and there are protocols and guidance at the Federal and private levels in support of first responders. Similar protocols and guidance exist to mitigate shock risk to mechanics during maintenance and repair.
In sum, the public and private sectors have been working diligently to address BEV safety considerations. While current standards are appropriate, optimization efforts will continue as the HD BEV industry matures. Heavy-duty BEVs can be and are designed and operated safely, and EPA therefore did not treat safety as a constraining factor in this rulemaking.

ii. Assessment of Battery Materials and Production
ICE vehicles and BEVs both require manufacturing inputs in the form of materials such as structural metals, plastics, electrical conductors, electronics and computer chips, and many other materials, minerals, and components that are produced both domestically and globally. These inputs rely to varying degrees on a highly interconnected global supply chain that includes mining and recycling operations, processing of mined or reclaimed materials into pure metals or chemical products, manufacture of vehicle components, and final assembly of vehicles.
Compared to ICE vehicles, the electrified powertrain of BEVs commonly contains a greater proportion of conductive metals such as copper as well as specialized minerals and mineral products that are used in the high-voltage battery. Accordingly, many of the public comments we received were related to the need to secure sources of these inputs to support increased manufacture of BEVs for the U.S. market. ^{262}
^{262} FCEVs use smaller batteries than BEVs, but those batteries would require use of the same minerals. The text in this section is written in terms of BEVs but is relevant to FCEV batteries as well.
First, it is important to view this issue from a perspective that includes the inputs currently required by ICE vehicles, where comparable issues have arisen and have been successfully surmounted. Compared to BEVs, ICE vehicles rely to a greater degree on certain inputs, most notably refined crude oil products such as gasoline or diesel, and critical minerals (for example, platinum group metals) used in emission control catalysts. Historically, supply and price fluctuations of crude oil products have periodically created significant risks, costs, and uncertainties for the U.S. economy and for national security, and continue to pose them today. The critical minerals used in emission control catalysts of ICE products, such as cerium, palladium, platinum, and rhodium, historically have posed particular uncertainty and risk regarding their reliable supply. Although manufacturers have engineered emission control systems to reduce the amount of these minerals that are needed, they continue to be scarce and costly today, and continue to be largely sourced from other countries. For example, South Africa and Russia continue to be dominant suppliers of these metals as they were in the 1970s, and U.S. relations with both countries have periodically been strained. In this sense, the need for a secure supply chain for the inputs required for BEV production is not unlike that which continues to be important for ICE vehicle production.
The BEV supply chain is characterized as consisting of several activity stages including upstream, midstream, and downstream, which includes end-of-life. Upstream refers to extraction of raw materials from mining activities. Midstream refers to additional processing of raw materials into battery-grade materials, production of electrode active materials (EAM), production of other battery components ( i.e., electrolyte, foils, and separators), and electrode and cell manufacturing. Downstream refers to production of battery modules and packs from battery cells, and end-of-life refers to recovery and processing of used batteries for reuse or recycling. Global demand for zero-emission vehicles has already led to rapidly growing demand for capacity in each of these areas and subsequent buildout of this capacity across the world. We discuss each of these activity stages in the following sections of this preamble.
The value of developing a robust and secure supply chain that includes these activities and the products they create has accordingly received broad attention in the industry and is a key theme of comments we have received. The primary considerations here are (a) the capability of global and domestic supply chains to support U.S. manufacturing of batteries and other ZEV components, (b) the availability of critical minerals as manufacturing inputs, and (c) the possibility that sourcing of these items from other countries, to the extent it occurs, might pose a threat to national security. In addition, there is the further question of the adequacy of the battery supply chain to meet potential demand resulting from a Phase 3 rule. In this section, EPA considers how these factors relate to the feasibility of producing the BEVs that manufacturers may choose to produce to comply with the standards.
In the proposal, we highlighted several key reasons that led us to conclude that the proposed standards were appropriate with respect to minerals availability, the battery supply chain, and minerals security as it relates to national security. 88 FR 28962-969. First we noted that minerals, battery components, and batteries themselves are largely sourced from outside of the U.S., not because the products cannot be produced in the U.S., but because other countries have already invested in developing this supply chain, while the U.S. largely has begun developing a domestic battery supply chain more recently. The rapid growth in domestic demand for automotive lithium-ion batteries that is already taking place is driving the development of a supply chain for these products that includes development of domestic sources, as well as rapid buildout of production capacity in countries with which the U.S. has friendly relations, including countries with free trade agreements (FTAs) and long-established trade allies. For example (as described later in this section), U.S. manufacturers are increasingly seeking out secure, reliable and geographically proximate supplies of batteries, cells, components, and the minerals and materials needed to build them; this is also necessary to remain competitive in the global automotive market where electrification is proceeding rapidly. As a result, a large number of new domestic battery, cell, and component manufacturing facilities have recently been announced or are already under construction. ^{263} Many automakers, suppliers, startups, and related industries have already recognized the need for increased domestic and “friendshored” production capacity as a business opportunity and are investing in building out various aspects of the supply chain domestically.
^{263} See section II.D.2.c..ii.b of this preamble for further discussion.
Second, we noted that Congress and the Administration have taken significant steps to accelerate this activity by funding, facilitating, and otherwise promoting the rapid growth of U.S. and allied supply chains for these products through the Inflation Reduction Act (IRA), the Bipartisan Infrastructure Law (BIL), the National Defense Authorization Act (NDAA), and numerous Executive Branch initiatives. Recent and ongoing announcements of investment and construction activity stimulated by these measures indicate that they are having a strong impact on development of the domestic supply chain, as illustrated by recent analysis from Argonne National Lab and U.S. DOE. ^{264} Finally, while minerals may be imported to the U.S. for domestic vehicle or battery production in the U.S., minerals, in contrast to liquid fuels, have the potential to be reclaimed through recycling, reducing the need for new materials from either domestic or foreign sources over the long term. In this updated analysis for the final rule, we examine these themes again in light of the public comments and additional data that has become available since the proposal.
^{264} Argonne National Laboratories, “Quantification of Commercially Planned Battery Component Supply in North America through 2035” (ANL-24/14) (March 2024) (“Planned Battery Supply”).
We received many comments on our analysis of critical minerals, battery and mineral production capacity, and critical mineral security. Some common themes were: that the proposal did not adequately address critical minerals or battery manufacturing; that the proposal did not adequately address the risk associated with uncertain availability of critical minerals in the future; and that the timeline and/or degree of BEV penetration anticipated by the proposal cannot be supported by available minerals and/or growth in domestic supplies or battery manufacturing. Many of the concerns stated by commenters about the supply chain, critical minerals, and mineral security were stated as part of a broader argument that the proposed standards were too stringent; that is, that the commenter believed that the standards should be weakened (or withdrawn entirely) because the supply chain or the availability of critical minerals could not support the amount of vehicle electrification that would result from the standards, or it would create a reliance on imported products that would threaten national security.
For this final rule we considered the public comments carefully. We have provided detailed responses to comments relating to critical minerals, the supply chain, and mineral security in this preamble and in section 17.2 of the Response to Comments. We also continued our ongoing consultation with industry and government agency sources (including the Department of Energy (DOE) and National Labs, the U.S. Geological Survey (USGS), and several analysis firms) to collect information on production capacity forecasts, price forecasts, global mineral markets, and related topics. We also coordinated with DOE in their assessment of the outlook for supply chain development and critical mineral availability. DOE is well qualified for such research, as it routinely studies issues related to electric vehicles, development of the supply chain, and broad-scale issues relating to energy use and infrastructure, through its network of National Laboratories. DOE worked together with Argonne National Laboratory (ANL) beginning in 2022 to assess global critical minerals availability and North American battery components manufacturing, and coordinated with EPA to share the results of these analyses during much of 2023 and early 2024. In this subsection we review the main findings of this work, along with the additional information we have collected since the proposal. As in the proposal, we have considered the totality of information in the public record in reaching our conclusions regarding the influence of future manufacturing capacity, critical minerals and related supply chain availability, and mineral security on the feasibility of the final standards.
As will be discussed in the following sections, our updated assessment supports our conclusion that the standards are technically feasible taking into consideration issues of critical mineral and supply chain availability, adequacy of battery production, and critical mineral security. Our assessment of the evidence likewise continues to support the conclusion that the likely rate of development of the domestic and global supply chain and forecast availability of critical minerals or materials on the global market are consistent with the final standards being met at a reasonable cost (assuming compliance in the same or similar manner set out in the technology packages in the modeled potential compliance pathway). Further, based on DOE and ANL's analyses which analyze the current and future state of the global and domestic supply chains, along with other sources as described in this preamble, we find no evidence that compliance with the standards will adversely impact national security by creating a long-term dependence on imports of critical minerals or components from adversarial countries or associated suppliers. Moreover, we expect that the standards will provide increased regulatory certainty for domestic production of batteries and critical minerals, and for creating domestic supply chains, which in turn has the potential to strengthen the U.S.'s global competitiveness in these areas.
As explained in the following sections, these results indicate that in the near- and medium-term, the currently identified capacity for lithium, cobalt, and nickel in the U.S. and Free Trade Agreement and Mineral Security Partnership countries is significantly greater than U.S. demand under representative domestic demand scenarios. Sufficient supply of graphite is likewise available considering secure international trade partnerships, and taking into account supply of synthetic and recycled graphite if needed. In particular, the U.S. is poised to become a key global producer of lithium, and, along with supply from Free Trade Agreement partners, is positioned well for lithium through 2035. We note that an accounting of known mineral reserves in democratic countries across the world indicates that the reserves surpass projected global needs through 2030 for the five minerals assessed by ANL, under a demand scenario that limits global temperature rise to 1.5 °C. ^{265} `Reserves' here refers to “measured and indicated deposits that have been deemed economically viable” ^{266} and so is not measuring mere presence of a resource. While this statistic does not demonstrate that these reserves will be extracted in any specific time frame, it demonstrates their presence and potential availability. As demand increases, particularly for secure supplies, further exploration and development of existing resources in these countries is likely to further increase these reserves.
^{265} Allan, B. et al., “Friendshoring Critical Minerals: What Could the U.S. and Its Partners Produce?”, Carnegie Endowment for International Peace, May 3, 2023. At https://carnegieendowment.org/2023/05/03/friendshoring-critical-minerals-what-could-u.s.-and-its-partners-produce-pub-89659 .
^{266} Similarly, the USGS defines reserves as “that part of the reserve base which could be economically extracted or produced at the time of determination. The term reserves need not signify that extraction facilities are in place and operative.” U.S. Bureau of Mines and the U.S. Geological Survey, “Principles of a Resource/Reserve Classification For Minerals,” Geological Survey Circular 831, 1980.
EPA notes that no analysis of future outcomes with regard to supply chain viability, critical minerals availability, or mineral security can be absolutely certain. The presence of uncertainty is inherent in any forward-looking analysis and is typically approached as a matter of risk assessment, including sensitivity analysis conducted around costs, compliance paths, or other key factors. We also again note that compliance with the final standards is possible under a broad range of reasonable scenarios, including a pathway without additional production of ZEVs to comply with the final standards. Demand for battery production and critical minerals would be significantly reduced under such potential alternative pathways to compliance.
Section II.D.2.c. ii.a of this preamble examines the issues surrounding availability of critical mineral inputs. Section II.D.2.ii.b examines issues relating to adequacy of battery production. Section II.D.2.c.ii.c discusses the security implications of increased demand for critical minerals and other materials used to manufacture electrified vehicles. Additional details on these aspects of the analysis may be found in RIA Chapter 1.5.1.

a. Battery Critical Minerals Availability
The Energy Act of 2020 defines a “critical mineral” as a non-fuel mineral or mineral material essential to the economic or national security of the United States and which has a supply chain vulnerable to disruption. ^{267} The U.S. Geological Survey lists 50 minerals as “critical to the U.S. economy and national security.” 268 269 Risks to mineral availability may stem from geological scarcity, geopolitics, trade policy, or similar factors. ^{270} Critical minerals range from relatively plentiful materials that are constrained primarily by production capacity and refining, such as aluminum, to those that are both relatively difficult to source and costly to process, such as the rare-earth metals that are used in magnets for permanent-magnet synchronous motors, which are used as the electric motors to power heavy-duty ZEVs and some semiconductor products. Extraction, processing, and recycling of minerals are key parts of the supply chain that affect the availability minerals. For the purposes of this rule, we focus on a key set of minerals (lithium, cobalt, nickel, manganese, and graphite) commonly used in BEVs; their general availability impacts the production of battery cells and battery components.
^{267} See 2021 Draft List of Critical Minerals (86 FR 62199-62203).
^{268} U.S. Geological Survey, “U.S. Geological Survey Releases 2022 List of Critical Minerals,” February 22, 2022. Available at: https://www.usgs.gov/news/national-news-release/us-geological-survey-releases-2022-list-critical-minerals .
^{269} The full list includes: Aluminum, antimony, arsenic, barite, beryllium, bismuth, cerium, cesium, chromium, cobalt, dysprosium, erbium, europium, fluorspar, gadolinium, gallium, germanium, graphite, hafnium, holmium, indium, iridium, lanthanum, lithium, lutetium, magnesium, manganese, neodymium, nickel, niobium, palladium, platinum, praseodymium, rhodium, rubidium, ruthenium, samarium, scandium, tantalum, tellurium, terbium, thulium, tin, titanium, tungsten, vanadium, ytterbium, yttrium, zinc, and zirconium. Note that the Department of Energy (DOE) does not classify manganese as a critical mineral.
^{270} International Energy Agency, “The Role of Critical Minerals in Clean Energy Transitions,” World Energy Outlook Special Report, Revised version. March 2022.
Demand for these minerals is increasing, largely driven by the transportation and energy storage sectors, as the world seeks to reduce carbon emissions and as the electrified vehicles and renewable energy markets grow. As with any emerging technology, a transition period must take place in which robust supply chains develop to support production and distribution. At present, minerals used in BEV batteries are commonly sourced from global suppliers and do not rely on a fully developed domestic supply chain. ^{271} As demand for these materials increases due to projected increasing production of BEVs, production of critical minerals is expected to grow. As noted previously in this section, the need for a secure supply chain for the inputs required for BEV production is not unlike that which continues to be important for ICE vehicle production, given the presence of minerals in ICE vehicles, and given difficulties and challenges posed by sourcing liquid fuels for ICE vehicles described throughout this document. The focus on lithium, cobalt, nickel, manganese, and graphite, stems from the fact that their increased use is unique to BEVs compared with ICE vehicles. Electrified vehicles at present utilize lithium-ion batteries, though alternative battery types are in development or are already being deployed in some limited applications. In the near-term, there is not a viable alternative to lithium in BEV batteries. As noted previously, common cathode chemistries today for lithium-ion batteries include nickel-manganese-cobalt (NMC), nickel-cobalt-aluminum (NCA), and iron-phosphate (LFP). While lithium is used in all lithium-ion batteries, cathode chemistry is somewhat flexible, which can help adapt to both supply-based factors and end-use needs. For example, LFP batteries have been increasing in use given the constraints of cobalt and nickel sourcing. LFP batteries may also be better suited for vehicles without extended ranges, as they are less energy dense. Put more broadly, cathode chemistry varies, and as such can adjust the demand for certain minerals, or can eliminate the demand for certain minerals entirely.
^{271} As mentioned in preamble section I.C.2.i and in RIA 1.3.2.2, there are tax credit incentives in the IRA for the production and sale of battery cells and modules of up to $45 per kWh, which includes up to 10 percent of the cost of producing applicable critical minerals that meet certain specifications when such components or minerals are produced in the United States.
Anode chemistry can also accommodate alternative chemistries. Most commonly, BEVs use a graphite anode, supply constraints for which are described further below; however, silicon can replace graphite in an anode, and graphite anodes containing a portion of silicon now make up around 30 percent of anodes according to the IEA as of 2023. ^{272} It is also possible to use alternative forms of carbon in the anode, and unlike other minerals used for BEVs, graphite can be produced synthetically.
^{272} https://www.iea.org/reports/global-ev-outlook-2023/trends-in-batteries .
Given the possibilities for substitution for other minerals, EPA focused its own analysis on lithium availability as a potential limiting factor on the rate of growth of ZEV production, and thus the most appropriate basis for establishing a modeling constraint on the rate of ZEV penetration into the fleet over the time frame of this rule. At proposal, EPA found that the lithium market was responding robustly to demand, and that global supply would be adequate at least through 2035. 88 FR 25965 and sources there cited. We further found that notwithstanding short-term price fluctuations in price, the price of lithium “is expected to stabilize at or near its historical levels by the mid- to late-2020s.” 88 FR 25966 and sources there cited. At proposal, we concluded that the scale and pace of demand growth and investment in lithium supply means that it is well positioned to meet anticipated demand as demand increases and supply grows. See RIA Chapter 1.5.1.3 for further explanation of focus on lithium as the most important of the critical minerals as a potential constraint.
More recent information is corroborative and expands the scope of analysis to include the five minerals listed previously in this section. ANL has performed a review of international and domestic critical minerals availability as of February 2024, which EPA considers to be both thorough and up to date. ^{273} The analysis finds that while the U.S. will need imports to bolster supply for most key minerals, these imports can come from friendly nations, and be bolstered by growing domestic supply, especially for lithium. The analysis also finds that, with the appropriate policies and enabling approaches in place, the U.S. can secure the minerals it needs by relying on domestic production as well as on trade relationships with allies and partners (Figure II-1). USGS is engaged in activities that, while not yet quantifiable, are enabling the U.S. to expand a secure supply chain for critical minerals among U.S. allies and partner nations. There are substantial efforts to scale mining supply domestically and in partner countries underway, further described in this section II.D.2.c.ii.c.
^{273} Argonne National Laboratory, “Securing Critical Materials for the U.S. Electric Vehicle Industry ” (March, 2024) (ANL-24/06) (“ANL”).
The updated ANL critical minerals study finds that the U.S. is poised to become a key global producer of lithium by 2030, and could become one of the world's largest producers of lithium by 2035. In the near term (the next few years), manufacturers will need to import lithium, and ample capacity exists to source lithium from countries with whom the United States has free trade agreements (FTA). ^{274} As detailed in the ANL study, numerous lithium extraction projects are in various stages of development many of which were also cited in public comments, including Fort Cady, Thacker Pass, Rhyolite Ridge, and Kings Mountain. ^{275}
^{274} ANL at 36, 38 (Australia and Chile), 53. The Minerals Security Partnership (MSP) is a transnational association whose members seek to secure a stable supply of raw materials for their economies. As of September 16, 2023, the MSP was composed of: Australia, Canada, Finland, France, Germany, India, Japan, South Korea, Sweden, Norway, the United Kingdom, the United States, and the European Union.
^{275} ANL at 34.
The ANL study continues to confirm a trend of rapidly growing identification of U.S. lithium resources and extraction development. The identification of these resources, some of which were publicly announced within the last year, exemplifies the dynamic nature of the industry and the likely conservative aspect of existing assessments.
This update to DOE's lithium resource compilation continues to confirm the trend of growing U.S. mineral development. As depicted in Figure II-2, DOE and ANL assessed announced domestic lithium extraction projects to project domestic lithium supply through 2035, along with domestic lithium recycling potential, and compared these to estimated demand. The projects included in the updated analysis represent a significant increase over the domestic lithium supply considered for the proposal, exemplifying the dynamic nature of the industry.
Regarding global lithium production, we have also supplemented our lithium analysis from the proposal with newly available research and information. The outlook for lithium production has evolved rapidly, with new projects regularly identified and contributing to higher projections of resource availability and production. Benchmark Minerals Intelligence (BMI) conducted a comprehensive analysis of global and domestic lithium supply and demand in June 2023 that indicates that lithium supply is likely to keep pace with growing demand during the time frame of the rule. ^{276} In the Figure II-3 below, the vertical bars (at full height) represent estimated global demand, including U.S. demand. The top segment of each bar represents BMI's estimate of added U.S. demand under the proposed light and medium duty vehicle rule, and the proposed HD Phase 3 rule. The lower line represents BMI's projection of global lithium supply (including U.S.) in GWh equivalent, weighted by current development status of each project. The next line represents global supply where the U.S. portion is unweighted ( i.e., all included projects reach full expected production). These two lines together represent a potential range for future global supply bounded by a standard weighted scenario and a maximum scenario applied to U.S. production only. In both cases, projected global lithium supply meets or surpasses projected global demand through 2029. Past 2029, global demand is either generally met or within 10 percent of projected demand through 2032. For reference, the top line is a high supply scenario in which global supply is also unweighted.
^{276} Benchmark Mineral Intelligence (BMI), “Lithium Mining Projects—Supply Projections (June 2023). See also Supplemental Comment Letter re BMI Analysis from Natural Resources Defense Council (January 2024).
EPA notes that BMI based its estimate of U.S. demand on electrified vehicle penetrations under the proposed standards, which projected higher electrified vehicle penetrations than in the final standards. This means that the top segment of each bar would be shorter under the final standards, making the depicted results more conservative.
EPA also notes that although BMI states that it is aware of 330 lithium mining projects ranging from announced projects to fully operating projects and stages in between, the supply projections shown here are limited to only 153 projects that are already in production or have publicly identified production estimates as of December 2022 (more than one year ago). Excluded from both the weighted and unweighted supply projections are 177 projects for which no information on likely production level was available. It is standard practice to weight projects that have production estimates according to their stage of development, and BMI has followed this practice with the 153 projects. However, complete exclusion of the potential production of 177 projects (more than half of the total) suggests that the projections shown may be extremely conservative. If even a very conservative estimate of ultimate production from these 177 projects by 2030 were to be added to the chart, projected supply would increase and perhaps meet or surpass demand. At this time of rising mineral demand coupled with active private investment and U.S. government activities to promote mineral resource development, exclusion of potential production from these resources is not likely to reflect their future contribution to U.S. supply.
In mid-2023, some analysts began speaking of the possibility of a future tightness in global lithium supply. ^{277} Opinions varied, however, about its potential development and timing, with the most bearish opinions suggesting as early as 2025 with others suggesting 2028 or 2030. However, the projections from BMI and ANL discussed previously in this section suggest only a mild gap developing in global supply and demand in 2030 and only if the 177 projects that were not quantified do not contribute (BMI), or no significant gap in U.S. lithium supply and demand during the time frame of the rule (ANL). Further, the analysts quoted as predicting a future tightness stop well short of identifying an unavoidable hard constraint on lithium availability that would reasonably lead EPA to conclude that the standards cannot be met. Forecasts of potential supply and demand, including those that purport to identify a supply shortfall, typically are also accompanied by descriptions of burgeoning activity and investment oriented toward supplying demand, rather than a paucity of activity and investment that would be more indicative of a critical shortage. EPA also notes that since the time of the referenced article, demand for lithium has increasingly been depicted as having underperformed peak expectations. The final standards also project a lower ZEV penetration than in the proposal, which would lead to lower demand from the standards than the proposal would have suggested.
^{277} Shan, Lee Ying, “A worldwide lithium shortage could come as soon as 2025” (August 2023) at www.cnbc.com/2023/08/29/a-worldwide-lithium-shortage-could-come-as-soon-as-2025.html .
Regarding concerns about lithium price fluctuations addressed by commenters, recent unexpected drops in lithium prices beginning in early 2023 ^{278} and persisting to the present are believed to have been the result of robust growth in lithium supply from developments similar to these. This supports EPA's expectation that mineral prices will not continually rise as some commenters have suggested but will find an equilibrium within a reasonable range of prices as the rapidly growing supply chain continues to mature. Despite recent short-term fluctuations in price, the price of lithium is expected to stabilize at or near its historical levels by the mid-2020s, according to outside analysis. 279 280 This perspective is also supported by proprietary battery price forecasts by Wood Mackenzie that include the predicted effect of temporarily elevated mineral prices and show battery costs falling again past 2024. 281 282 This is also consistent with the BNEF's newly released 2023 Battery Price Survey which shows that pack prices have resumed their downward trend, and predicts that average pack prices across all automotive and stationary uses will fall to $113 per kWh in 2025 and $80 per kWh in 2030. ^{283}
^{278} New York Times, “Falling Lithium Prices Are Making Electric Cars More Affordable,” March 20, 2023. Accessed on March 23, 2023 at https://www.nytimes.com/2023/03/20/business/lithium-prices-falling-electric-vehicles.html . See also The Economist, January 6, 2024 at 54: “[m]ined supply of lithium and nickel is also booming; that of cobalt, a by-product of copper and nickel production, remains robust, dampening green-metal prices.”
^{279} Sun et al., “Surging lithium price will not impede the electric vehicle boom,” https://www.sciencedirect.com/science/article/pii/S2542435122003026 .
^{280} Green Car Congress, “Tsinghua researchers conclude surging lithium price will not impede EV boom,” July 29, 2022.
^{281} Wood Mackenzie, “Battery & raw materials—Investment horizon outlook to 2032,”September 2022 (filename: brms-q3-2022-iho.pdf). Available to subscribers.
^{282} Wood Mackenzie, “Battery & raw materials—Investment horizon outlook to 2032,”accompanying data set, September 2022 (filename: brms-data-q3-2022.xlsx). Available to subscribers.
^{283} BloombergNEF, “Lithium-Ion Battery Pack Prices Hit Record Low of $139/kWh,” November 27, 2023. Accessed on December 6, 2023 at https://about.bnef.com/blog/lithium-ion-battery-pack-prices-hit-record-low-of-139-kwh .
In addition to lithium, EPA carefully considered the availability of nickel, cobalt, manganese, and graphite at proposal and for this final rule. At proposal, we noted the global sources of these materials, and global refining sources. We further explained how United States domestic production of these materials lagged global production notwithstanding domestic reserves of nickel, cobalt, and lithium; however, the developing supply chain domestically and abroad can meet domestic demand over the next decade. 88 FR 25963.
More recent information from ANL confirms these initial findings and supports that supply and supply chains for these minerals will be adequate to meet domestic demand in the Phase 3 rule's timeframe. Below are summaries of the ANL report's findings.
While the U.S. nickel production industry is expanding, in the near- and medium-term, there is sufficient capacity in countries with which the U.S. has long-standing or emerging trade partnerships to meet demand for nickel. Some nickel will come from countries with free trade agreements (FTA) and in the Minerals Security Partnership (MSP), a multilateral effort to responsibly secure critical mineral supply chains (Canada, Australia, Finland, Norway), though likely much of it will come from other trade partners (Indonesia, Philippines and others). ^{284} The U.S. is engaged in several initiatives with these countries to expand and diversify nickel supply (detailed further in section II.D.2.ii.c of this preamble), and some domestic nickel production is also in development.
^{284} ANL at 44. We discuss availability of nickel refining capacity below in considering mineral security.
There are initial efforts to scale up cobalt production in FTA countries, but the bulk of supply will continue to come from the Democratic Republic of Congo, with Australia (which has an FTA with the U.S. and is a member of the MSP) and Indonesia being secondary sources, plus some domestic production from the six ^{285} prospective cobalt projects that have potential to come online before 2035. ^{286} This supply is projected to be sufficient to meet demand. BloombergNEF now similarly projects that cobalt and nickel reserves “are now enough to supply both our Economic Transition and Net Zero scenarios,” the latter of which is an aggressive global decarbonization scenario. ^{287} It is also significant that the U.S. cobalt spot price dropped by nearly 42 percent in the past year (2023-2024), indicating ample current supply. ^{288} U.S. efforts to secure the global cobalt supply chain are discussed further in section II.D.2.ii.c of this preamble.
^{285} ANL at 48.
^{286} We discuss availability of cobalt refining capacity below in our discussion of issues relating to mineral security.
^{287} BloombergNEF, “Electric Vehicle Outlook 2023,” Executive Summary, p. 5.
^{288} https://ycharts.com/indicators/us_cobalt_spot_price#:~:text=US%20Cobalt%20Spot%20Price%20is,22.79%25%20from%20one%20year%20ago (last accessed March 19, 2024).
Manganese is not considered to be a “critical” mineral as defined by USGS or by DOE; however, it is an important mineral for BEV batteries. ^{289} Capacity from FTA and MSP partners is projected to be sufficient to meet domestic demand in both the near and medium term, as significant reserves are located in Australia, Canada, and India. ^{290} In addition, recycling may prove to be a growing source of supply starting in the early 2030s. ^{291}
^{289} DOE Critical Materials Report—2023 ( www.energy.gov ).
^{290} ANL at 63.
^{291} ANL at 62-63.
In the near-term, graphite demand is unlikely to be met through domestic sources or through trade with FTA countries or directly from MSP countries. ^{292} However, scaling domestic synthetic graphite production and continued innovation can mitigate this risk. In the medium term, supply sources of natural graphite are expected to become more diverse with new planned capacity in both FTA (Canada and Australia) and other economic partners (Tanzania and Mozambique) and others supported by the MSP. Although the U.S. has significant deposits of natural graphite, graphite has not been produced in the U.S. since the 1950s and significant known resources remain largely undeveloped. ^{293} ANL notes that China dominates natural graphite production and has been a major source of U.S imports; however, China has recently moved to curb exports of graphite, imposing an export permit requirement on graphite in 2023, which will temporarily reduce graphite exports due to a 45-day application period for permits. This suggests that graphite exports from China may be controlled in the future. However, at this time it is not clear that this requirement will meaningfully impact exports over the long term, as similar permit requirements have existed on other exports, including those necessary in ICE vehicle production. ^{294} Wood Mackenzie reports that a change to material flows is unlikely, and that a graphite supply chain outside of China is rapidly developing. ^{295} In fact, this export restriction is expected to be a catalyst for swiftly expanding the domestic graphite supply from conventional and non-conventional sources. ^{296} ANL also indicates that synthetic graphite scaling has potential to mitigate graphite risk in the medium term. ^{297} Already, about 58 percent of the world's graphite is synthetic. ^{298} Innovation can also help curb pressure on the graphite supply chain, with silicon's use in battery anodes expected to expand tenfold by 2035 according to SNE research, displacing the need for some graphite. ^{299}
^{292} ANL at 52, 57
^{293} U.S. Geological Survey, “USGS Updates Mineral Database with Graphite Deposits in the United States,” February 28, 2022.
^{294} Rare earths, necessary for catalytic converters and magnet motors are presently subject to Chinese export license restrictions for example. https://www.fastmarkets.com/insights/chinas-commerce-ministry-to-add-rare-earths-to-export-report-directory .
^{295} Wood Mackenzie, “How will China's graphite export controls impact electric vehicle supply chain?” subscriber material presentation, November 2, 2023.
^{296} See China's Graphite Curbs Will Accelerate Plans Around Alternatives (usnews.com).
^{297} ANL at 56; see also Reuters, “China's graphite curbs will accelerate plans around alternatives,” October 23, 2023. Accessed on December 16, 2023 at https://www.reuters.com/business/autos-transportation/chinas-graphite-curbs-will-accelerate-plans-around-alternatives-2023-10-20 , and Korea Economic Daily, “EV battery makers' silicon anode demand set for take-off” (February 2024) at
https://www.kedglobal.com/batteries/newsView/ked202402230020 .
^{298} ANL at 52.
^{299} EV battery makers' silicon anode demand set for take-off—KED Global https://www.kedglobal.com/batteries/newsView/ked202402230020 .
The national security implications for all the mineral supply chains discussed previously in this section are examined further in section II.D.2.c.ii.c of this preamble. EPA posits that, if critical material availability were the type of profound constraint voiced by some commenters, one would expect there would be signs of trepidation in the amount of invested capital. However, we see the opposite, as demonstrated by ANL and outside analysis. At proposal, we cited one analysis indicating that 37 of the world's automakers are planning to invest a total of almost $1.2 trillion by 2030 toward electrification, a large portion of which will be used for construction of manufacturing facilities for vehicles, battery cells and packs, and materials, supporting up to 5.8 terawatt-hours of battery production and 54 million electric vehicles per year globally. ^{300} Similarly, an analysis by the Center for Automotive Research showed that a significant shift in North American investment is occurring toward electrification technologies, with $36 billion of about $38 billion in total automaker manufacturing facility investments announced in 2021 being slated for electrification-related manufacturing in North America, with a similar proportion and amount on track for 2022. ^{301} The State of California, in its public comments, documented that as of March 2023, “at least $45 billion in private-sector investment has been announced across the U.S. clean vehicle and battery supply chain.” ^{302} Companies have announced over 1,300 GWh/year in battery production in North America by 2030. ^{303} Over $100 billion of investment in domestic battery production has been announced in the past two years. ^{304}
^{300} Reuters, “A Reuters analysis of 37 global automakers found that they plan to invest nearly $1.2 trillion in electric vehicles and batteries through 2030,” October 21, 2022. Accessed on November 4, 2022, at https://graphics.reuters.com/AUTOS-INVESTMENT/ELECTRIC/akpeqgzqypr .
^{301} Center for Automotive Research, “Automakers Invest Billions in North American EV and Battery Manufacturing Facilities,” July 21, 2022. Retrieved on November 10, 2022 at https://www.cargroup.org/automakers-invest-billions-in-north-american-ev-and-battery-manufacturing-facilities .
^{302} Comments of State of California at 30, citing U.S. Department of the Treasury, Treasury Releases Proposed Guidance on New Clean Vehicle Credit to Lower Costs for Consumers, Build U.S. Industrial Base, Strengthen Supply Chains (March 31, 2023), https://home.treasury.gov/news/press-releases/jy1379.
^{303} Planned Battery Supply Fig. 10.
^{304} Planned Battery Supply at 4.
Robust growth in the domestic battery supply chain, including mineral production, is spurred growth is furthered by the BIL and IRA. The IRA offers sizeable incentives and other support for further development of domestic and North American manufacture of electrified vehicles and components, and the BIL provides direct funding to achieve this same end. These two policies have already been transformative for the North American battery supply chain, as evidenced in Figure II-4: More recent information indicates that approximately 67 percent of private investments in North American battery manufacturing—including extraction of raw materials necessary for battery production, processing of these ores into battery-grade materials, manufacturing of midstream battery precursors, and production of battery cells and packs—has occurred in the past two years: as just noted, approximately $100 billion of the $150 billion invested since 2000. ^{305} Furthermore, there is a sizeable amount of funding from both BIL and IRA that still has not been allocated, with the expectation that the domestic battery supply chain will continue to grow as those funds are rolled out. Additional investments are likely upon the finalization of policies pertaining to the battery supply chain at the Department of Energy and the Department of the Treasury. Specifically, the BIL and IRA have introduced several incentives to scale domestic processing and recycling of critical minerals including the $3 billion Battery Manufacturing and Recycling Grant Program, and tax credits including 45X and 48C.
^{305} Planned Battery Supply at 4. ANL has continued tracking investments in battery and electric vehicle manufacturing to estimate growth of battery production in North America, based on press releases, financial disclosures, and news articles.
Beyond BIL and IRA, a number of actions underscore the extent of U.S. efforts to grow the domestic minerals supply chain, including extraction, processing, and recycling (detailed more extensively in the ANL critical minerals study). For example, critical minerals projects were recently made eligible for a streamlined permitting process under the Federal Permitting Improvement Steering Council (FAST-41) EXIM is supporting critical minerals projects in the U.S. and abroad through various financing products. The USGS Earth Mapping Resources Initiative (Earth MRI) is improving mapping and exploration of domestic resources across the country. USGS, DOD, and DOE are collaborating on a series of “hackathons” to leverage AI and machine learning to domestic critical minerals resource assessment. Efforts to secure global critical minerals supply chains are detailed further in section II.D.2.ii.c of this preamble. In addition to the efforts described previously in this section, the U.S. can increase minerals availability and minerals security by increasing domestic recycling and pursuing materials innovation and substitution.
Substantial funding to scale and improve recycling, as well as to develop advanced batteries using less or more readily abundant materials, is ongoing and will continue given the high importance of securing the minerals in question. Recycling is an important part of the solution to issues of mineral security and critical mineral availability. 88 FR 25969 and RTC section 4.7. Over the long term, battery recycling can effectively serve as a domestically produced mineral source that reduces overall reliance on foreign-sourced products. While growth in the return of end-of-life ZEV batteries will lag the market penetration of ZEVs due to the long lifespan of EV batteries, we consider the ongoing development of a battery recycling supply chain during the time frame of the rule and beyond.
Battery recycling is an active area of research. The Department of Energy coordinates much research in this area through the ReCell Center, described as “a national collaboration of industry, academia and national laboratories working together to advance recycling technologies along the entire battery lifecycle for current and future battery chemistries.” ^{306} The ReCell Center is developing alternative, more efficient recycling methods that, if realized and scaled, can more efficiently expand recycled materials availability. These methods include direct recycling, in which materials can be recycled for direct use in cell production without destroying their chemical structure, and advanced resource recovery, which uses chemical conversion to recover raw minerals for processing into new constituents. ^{307} Battery recycling is the subject of several provisions of the BIL. It includes a Battery Processing and Manufacturing program, which grants significant funds to promote U.S. processing and manufacturing of batteries for electric vehicle and electric grid use, by awarding grants for demonstration projects, new construction, retooling and retrofitting, and facility expansion. It will provide a total of $3 billion for battery material processing, $3 billion for battery manufacturing and recycling, $10 million for a lithium-ion battery recycling prize competition, $60 million for research and development activities in battery recycling, an additional $50 million for state and local programs, and $15 million to develop a collection system for used batteries. In addition, the Electric Drive Vehicle Battery Recycling and Second-Life Application Program will provide $200 million in funds for research, development, and demonstration of battery recycling and second-life applications. ^{308} The DOE has announced the availability of $37 million in funding to improve the economics and industrial ecosystem for battery recycling, and another $30 million to enable a circular economy for EV batteries, to be awarded in 2024. ^{309}
^{306} ReCell Center. https://recellcenter.org/about .
^{307} Department of Energy, “The ReCell Center for Advanced Battery Recycling FY22 Q4 Report,” October 20, 2022. Available at: https://recellcenter.org/2022/12/15/recell-advanced-battery-recycling-center-fourth-quarter-progress-report-2022 .
^{308} Environmental Defense Fund and ERM, “Electric Vehicle Market Update: Manufacturer Commitments and Public Policy Initiatives Supporting Electric Mobility in the U.S. and Worldwide,” September 2022.
^{309} Department of Energy, Grants Notice: Bipartisan Infrastructure Law (BIL) FY23 BIL Electric Drive Vehicle Battery Recycling and Second Life Applications. Available online: grants.gov/search-results-detail/351544 ; See also: https://arpa-e.energy.gov/news-and-media/press-releases/us-department-energy-announces-30-million-develop-technologies-enable .
Battery recycling is also a focus of private investment as a growing number of private companies are entering the battery recycling market. For example, Panasonic has contracted with Redwood Materials Inc. to supply domestically processed cathode material, much of which will be sourced from recycled batteries. ^{310} Ford and Volvo have also partnered with Redwood to collect end-of-life batteries for recycling and promote a circular, closed-loop supply chain utilizing recycled materials. ^{311} Redwood has also announced a battery active materials plant in South Carolina with capacity to supply materials for 100 GWh per year of battery production, and is likely to provide these materials to many of the “battery belt” factories that are developing in a corridor between Michigan and Georgia. ^{312} General Motors and LG Energy Solution have partnered with Li-Cycle to recycle GM's Ultium cells. 313 314 Aqua Metals has developed a hydrometallurgical closed loop process capable of recovering all critical minerals with fewer associated emissions than pyrometallurgical processes. ^{315} Estimates vary for projections of recycling's ability to meet demand for minerals. According to one estimate, by 2050, battery recycling could be capable of meeting 25 to 50 percent of total lithium demand for battery production. 316 317
^{310} Randall, T., “The Battery Supply Chain Is Finally Coming to America,” Bloomberg, November 15, 2022.
^{311} Automotive News Europe, “Ford, Volvo join Redwood in EV battery recycling push in California,” February 17, 2022. https://europe.autonews.com/automakers/ford-volvo-join-redwood-ev-battery-recycling-push-california .
^{312} Wards Auto, “Battery Recycler Redwood Plans $3.5 Billion South Carolina Plant,” December 27, 2022. https://www.wardsauto.com/print/388968 .
^{313} General Motors, “Ultium Cells LLC and Li-Cycle Collaborate to Expand Recycling in North America,” Press Release, May 11, 2021. https://news.gm.com/newsroom.detail.html/Pages/news/us/en/2021/may/0511-ultium.html .
^{314} Other companies engaged in recycling of lithium ion batteries and other critical minerals include (and are not limited to) Umicore, Battery Solutions, RecycLi Battery Materials, American Battery Technology, and Glencore International.
^{315} Aqua Metals. Available online: https://aquametals.com .
^{316} Sun et al., “Surging lithium price will not impede the electric vehicle boom,” Joule, doi:10.1016/j.joule. 2022.06.028 ( https://dx.doi.org/10.1016/j.joule.2022.06.028 ).
^{317} Ziemann et al., “Modeling the potential impact of lithium recycling from EV batteries on lithium demand: a dynamic MFA approach,” Resour. Conserv. Recycl. 133, pp. 76-85. https://doi.org/10.1016/j.resconrec . 2018.01.031.

b. Production Capacity for Batteries and Battery Components
As described in the previous section, battery manufacturing consists of several distinct stages. This section examines the outlook for the “midstream” of the lithium-ion battery supply chain, which includes materials processing, component manufacturing, and cell fabrication, in light of anticipated demand as a result of the final standards. While other battery chemistries exist or are under development, this section focuses on supply chains for lithium-ion batteries given their wide use and lack of near-term alternatives.
In the proposal, we examined the outlook for U.S. and global battery manufacturing capacity for vehicle lithium-ion batteries and compared it to our projection of U.S. battery demand under the proposed standards, considering demand of both the proposed HDV and LMDV proposed rules. 88 FR 25967. We collected and reviewed a number of independent studies and forecasts, ^{318} including numerous studies by analyst firms and various stakeholders, as well as a study of announced North American cell and battery manufacturing facilities compiled by Argonne National Laboratory (ANL) and assessments by the Department of Energy. Our review of these studies included consideration of uncertainties of the sort that are common to any forward-looking analysis but did not identify any constraint that indicated that global or domestic battery manufacturing capacity would be insufficient to support battery demand under the proposed standards. The review indicated that the industry was already showing a rapidly growing and robust response to meet current and anticipated demand, that this activity was widely expected to continue, and that the level of U.S. manufacturing capacity that had been announced to date was largely sufficient to meet the demand projected under the proposed standards by 2030. 88 FR 25968. We assessed that battery manufacturing capacity was not likely to pose a limitation on the ability of manufacturers to meet the standards as proposed.
^{318} U.S. Electric Vehicle Battery Manufacturing on Track to Meet Demand. EDF. December 2023. Available Online: https://www.edf.org/sites/default/files/2023-12/EDF%20Analysis%20on%20US%20Battery%20Capacity%2012.13.23%20final%20v3.pdf .
EPA has carefully considered the substantive and detailed comments offered by the various commenters. In light of additional information that EPA has collected through continued research and the public comments, the evidence continues to support our previous assessment that domestic and global battery manufacturing is well positioned to deliver sufficient battery production to allow manufacturers to meet the standards.
The additional information EPA has collected addresses many of the points raised by the commenters. In particular, ANL has performed an updated assessment of North American battery components and cell manufacturing capacity that further reinforces our assessment that capacity is rapidly growing. EPA considers ANL's assessment through December 2023 to be thorough and up to date.
Based on announced investments in battery cell production, companies have announced over 1,300 GWh/year in battery production in North America by 2030 (Figure II-5). This is already a significant increase over the estimates discussed in the proposal of 1,000 GWh/year commencing in 2030. 88 FR 25967. EPA estimates that 11 GWh will be required for HDV BEVs in 2027 and 58 GWh in 2032 under the modeled potential compliance pathway. See RIA Chapter 2.10.2. Consequently, although most of this announced capacity is currently intended for light duty vehicles (and some for stationary sources), ^{319} EPA finds that there is sufficient North American battery production capacity for HDVs within the rule's timeframe, and ANL projects at least 45 GWh of announced cell production will be dedicated to HDV BEVs by 2030 (Figure II-6). Moreover, end use for some battery cell manufacturing facilities has not been announced, and it is likely that North American capacity can service HDV applications in greater than announced amounts. Importantly, in addition to the 13 new domestic battery plants we projected to become operational in the four years from proposal, 88 FR 25986, the new work performed by ANL indicates that even more battery production capacity has been announced since the release of those previous reports (Figure II-7). In addition, capacity from trade allies is another source of supply: the sum of announced battery cell production capacity in MSP countries (outside North America) exceeds the sum in North America, with both reaching 1,300 GWh/year by 2030. ^{320} See Figure II-9 below.
^{319} Planned Battery Supply at 22, 23.
^{320} Planned Battery Supply Appendix D.
A number of comments expressed concerns regarding ramp-up time. The latest ANL projections estimate the period from announcement to beginning of production for each individual plant based on numerous factors, and uses a baseline estimate of 3 years from beginning of production to full scale operation, based on historical cell manufacturing data. ^{321} ANL describes this as “a modestly conservative estimate,” acknowledging that plants could reach nominal capacity more quickly or more slowly. This estimate is consistent with the projections of significant increases in domestic production by the commencement of the Phase 3 program shown in the immediately preceding figures.
^{321} Planned Battery Supply at 57.
We also continue to see evidence that global lithium-ion battery cell production is growing rapidly ^{322} and is likely to keep pace with increasing global demand. In the proposal we noted a 2021 report from Argonne National Laboratory (ANL) ^{323} that examined the state of the global supply chain for electrified vehicles and included a comparison of recent projections of future global battery manufacturing capacity and projections of future global battery demand from various analysis firms out to 2030, as seen in Figure II-8. ^{324,325} The three most recent projections of capacity (from BNEF, Roland Berger, and S&P Global in 2020-2021) that were collected by ANL at that time exceeded the corresponding projections of demand by a significant margin in every year for which they were projected, suggesting that global battery manufacturing capacity is responding strongly to increasing demand.
^{322} “Lithium-ion battery manufacturing capacity, 2022-2030”. International Energy Agency. Last updated May 22, 2023. Available Online: https://www.iea.org/data-and-statistics/charts/lithium-ion-battery-manufacturing-capacity-2022-2030 .
^{323} Argonne National Laboratory, “Lithium-Ion Battery Supply Chain for E-Drive Vehicles in the United States: 2010-2020,” ANL/ESD-21/3, March 2021.
^{324} Argonne National Laboratory, “Lithium-Ion Battery Supply Chain for E-Drive Vehicles in the United States: 2010-2020,” ANL/ESD-21/3, March 2021.
^{325} Federal Consortium for Advanced Batteries, “National Blueprint for Lithium Batteries 2021-2030,” June 2021 (Figure 2). Available at https://www.energy.gov/sites/default/files/2021-06/FCAB%20National%20Blueprint%20Lithium%20Batteries%200621_0.pdf .
The updated ANL supports the continuation of this trend. Figure II-9 shows projected battery cell production in MSP countries through 2035: as noted previously in this section, the sum of announced battery cell production capacity in MSP countries (outside North America) exceeds the sum in North America, with both reaching 1,300 GWh/year by 2030.
In addition to battery cell manufacturing, we also consider manufacturing of battery components. In order to meet their projected operating capacities, the North American battery plants will need to manufacture or purchase these materials. Battery components include electrode active material (cathode active material CAM and anode active material AAM), electrolyte, foils, separators, and precursor materials, which include lithium carbonate, lithium hydroxide, nickel sulfate, cobalt sulfate, and manganese sulfate.
Figure II-10 repeats the chart that was shown in the proposal, showing preliminary projections of global cathode supply versus global cathode demand, prepared by Li-Bridge for DOE, ^{326} and presented to the Federal Consortium for Advanced Batteries (FCAB) ^{327} in November 2022. These projections were largely derived by DOE from projections by BMI and indicate that global supplies of cathode active material (CAM) are expected to be sufficient through 2035.
^{326} Slides 6 and 7 of presentation by Li-Bridge to Federal Consortium for Advanced Batteries (FCAB), November 17, 2022.
^{327} https://www.energy.gov/eere/vehicles/federal-consortium-advanced-batteries-fcab .
Following the proposal, ANL analyzed North American production capacity for battery components and precursor materials. ANL does project that some domestic demand will need to be satisfied through imports. Allies and partners outside of North America are likely to be integral in meeting U.S. battery component demand, though this does not indicate a deterrence to securing adequate battery components and precursor materials to meet domestic demand. Allies Japan and the Republic of Korea, for example, are the world's second and third largest producers of CAM and AAM. ^{328}
^{328} https://iea.blob.core.windows.net/assets/4eb8c252-76b1-4710-8f5e-867e751c8dda/GlobalSupplyChainsofEVBatteries.pdf .
Specifically, based on assessed announcements, ANL projects North American CAM production will reach 570 GWh by 2032, and that this will fall short of North American cell production by 2028. ^{329} Anode active material (AAM) is likewise projected to be primarily import dependent, with North American production capacity reaching 585 GWh in 2032; this would satisfy approximately 43 percent of forecast end demand in 2030 and remaining steady thereafter, with the remainder supplied from elsewhere. ^{330}
^{329} Planned Battery Supply at 33-34.
^{330} Planned Battery Supply at 30-31.
ANL emphasizes that its production projections are conservative and may understate domestic capacity, because the analysis does not include plant announcements not formally announced, and because cell production or other facilities may be vertically integrated without this fact being disclosed. ^{331} In fact, planned or considered but not formally announced plants for AAM would add enough capacity to meet projected cell production. ^{332} Another reason any projected shortfall can be remedied is that CAM and AAM production have a one- to- three year timeframe from initial announcement and opening, faster than cell production plants. Thus, “[b]ecause of their shorter construction and permitting time, most battery components can be responsive to the demand arising from battery cell plants” and can delay announcement building commitment while waiting for certainty in cell production. ^{333} Gaps in supply may also be satisfied by imports. ^{334}
^{331} Planned Battery Supply at 6 n.3, 31, 34.
^{332} The report identifies an additional 590 GWh/year in nominal anode active material North American production capacity by the end of this decade which is planned or considered, but not formally announced. Planned Battery Supply at 31.
^{333} Planned Battery Supply at 34, 31.
^{334} Planned Battery Supply at 31, 34.
This outlook is informed by efforts to build a secure, and largely domestic, supply chain for battery components and batteries by the U.S. government and industry. The IRA and BIL have already provided and continue to provide significant support to accelerate these efforts to build out a U.S. supply chain for batteries, and, as demonstrated in section II.D.2.c.ii.a of this preamble, uptake from industry has been considerable. As described in some detail earlier, the IRA offers sizeable incentives and other support for further development of domestic and North American manufacture of electrified vehicles and components, and BIL offers significant grant funding for batter component and cell manufacturing. The 45X tax credit offers up to $35/kWh for battery cell production, up to $10/kWh for battery pack production, and up to 10 percent of incurred costs for battery component production through 2032. The 48C tax credit offers up to $10 billion in products that could include battery component and cell manufacturing and recycling. The DOE Loan Programs Office (LPO) is supported battery component and cell manufacturing projects through the Advanced Technologies Vehicle Manufacturing (ATVM) and Title 17 programs. ^{335} (Some examples of recent projects are outlined in RIA Chapter 1.5.1.3.) Together, these provisions are continuing to motivate manufacturers to invest in the continued development of a North American supply chain, and already appear to have proven influential on the plans of manufacturers to procure domestic or North American mineral and component sources and to construct domestic manufacturing facilities to claim the benefits of the act. Manufacturers are investing in lithium-ion battery cell production, both independently and through joint ventures with battery companies. Tesla, Ford, Volkswagen, GM, Stellantis, Honda, and Hyundai have all announced battery supply chain investments in North America. ^{336} See also preamble section II.E.4 for further discussion and examples. Importantly, while the effects of BIL and IRA on the battery supply chain are well documented throughout this preamble, funds from these laws are still being disbursed, with billions of dollars available for the battery supply chain remaining (see Table II-8).
^{335} Planned Battery Supply at 8.
^{336} Planned Battery Supply at 23.
In consideration of this updated information on battery component and cell manufacturing, it continues to be our assessment that the industry is well positioned to support the battery demand that is projected under the Phase 3 standards including taking into consideration uncertainties that generally accompany forward-looking projections, and therefore EPA concludes that there will be adequate supply of battery cells and battery components to support the feasibility of the final standards under the modeled potential compliance pathway.

c. Critical Mineral Security
As stated at the beginning of this section II.D, it is our assessment that increased deployment of BEVs that could result from this final rule does not constitute a vulnerability to national security, for several reasons supported by the discussion in this preamble and in RIA 1.5.1.2.
Mineral security refers to potential national security risks posed by vulnerabilities in the mineral supply chain, and in particular reliance on sourcing of critical minerals from countries with which the U.S. has fragile trade relations or significant policy differences. This section examines the outlook for mineral security as it relates to demand for critical minerals resulting from increased BEV production under the final standards. We note that this section focuses on mineral security, and not on energy security, which relates to security of energy consumed by transportation and other needs. Energy security is discussed separately in section VII.C of this preamble.
Concern for U.S. mineral security relates to the global distribution of established supply chains for critical minerals and the fact that, at present, not all domestic demand can be supplied by domestic production. Currently, despite a wide distribution of mineral resources globally, mineral production is not evenly distributed across the world. At present, production is concentrated in a few countries due to several factors, including where the resources are found in nature, the level of investment that has occurred to develop the resources, economic factors such as infrastructure, and the presence or absence of government policy relating to their exploitation. While the U.S. is not a leading producer of minerals used in BEV batteries at present, substantial investment has already gone towards expanding domestic mineral supply, largely due to funding and incentives from BIL and IRA. This is described in greater detail in section II.D.2.ii.a of this preamble.
In the proposal, EPA analyzed the primary issues surrounding mineral security as it relates to critical mineral needs for BEV production. 88 FR 25968. We collected and reviewed information relating to the present geographical distribution of developed and known critical mineral resources and products, including information from the U.S. Geological Survey, analyst firms and various stakeholders. In considering these sources we highlighted and examined the potential for the U.S. supply chain to reduce dependence on critical minerals that at present are largely sourced from other countries. Our assessment of the available evidence indicated that the increase in BEV production projected to result from the proposed standards could be accommodated without causing harm to national security.
EPA has carefully considered the substantive and detailed comments offered by the various commenters. Much of the information provided by adverse commenters builds upon the evidence that EPA already presented in the proposal concerning the risks and uncertainties associated with the future impact of mineral demand on mineral security. Much of the information provided by supportive commenters also builds on the evidence EPA presented in the proposal about the pace of activity and overall outlook for buildout of the critical mineral supply chain. While contributing to the record, the information provided by the commenters largely serves to support the trends that were already identified and considered by EPA in the proposal, and do not identify new, specific aspects of mineral security that were not already acknowledged. Taken together, the totality of information in the public record continues to indicate that development of the critical mineral supply chains is proceeding both domestically and globally in a manner that supports the industry's compliance with the final standards under the modeled potential compliance pathway. In light of this information provided in the public comments and additional information that EPA has collected through continued research, it continues to be our assessment that the increase in ZEV production projected under the modeled potential compliance pathway for the standards is not expected to adversely impact national security, and in fact may result in national security benefits by reducing the need for imported petroleum (as discussed separately in section VII.C of this preamble) and providing regulatory and market certainty for the continued development of a domestic supply chain for critical minerals.
Regarding the adequacy of the supply chain in supporting the standards, EPA notes that it is a misconception to assume that the U.S. must establish a fully independent domestic supply chain for critical minerals or other inputs to BEV production in order to contemplate standards that may result in increased manufacture of BEVs. The supply chain that supports production of consumer products, including ICE vehicles, is highly interconnected across the world, and it has long been the norm that global supply chains are involved in providing many of the products that are commonly available in the U.S. market and that are used on a daily basis. As with almost any other product, the relevant standard is not complete domestic self-sufficiency, but rather a diversified supply chain that includes not only domestic production where possible and appropriate but also includes trade with allies and partners with whom the U.S. has good trade relations. As discussed below, bilateral and multilateral trade agreements and other arrangements (such as defense agreements and various development and investment partnerships), either long-standing or more recently established, already exist which greatly expands opportunities to develop a secure supply chain that reaches well beyond the borders of U.S.
As discussed previously in this section in connection with critical mineral availability, since the proposal, Argonne National Laboratory has conducted additional analysis on the outlook for U.S. production of nickel, cobalt, graphite, manganese and lithium and we have updated our analysis to reflect this work. For the minerals examined, there are prospects for growth among secure sources of supply, and the report details ongoing efforts to build and strengthen partnerships with friendly countries to fill any supply gaps that cannot be met domestically.
The United States is actively pursuing a whole-of-government strategy to secure materials that cannot be sufficiently produced domestically. This involves diversifying sourcing strategies through strengthening current trade agreements and actively building new economic, technology, and regional security alliances. The United States has international initiatives in place to secure nickel, cobalt, and graphite, the critical battery minerals for which imports from non-FTA, non-MSP countries are projected in the short, medium, and/or long term. These initiatives and agreements serve to secure supply chains, and to balance and counteract influence of potential threats to those supply chains, including potential threats posed by Foreign Entities of Concern, such as the concentration of mineral processing in China. We discuss below some specific examples of bilateral and multilateral efforts to secure minerals supply from non-U.S. sources.
Indonesia, for example, is a major source of nickel supply and refining capacity, and also has significant reserves of cobalt. The U.S. has been making concerted efforts to forge a strong partnership with Indonesia, culminating in the U.S. entering into a Comprehensive Strategic Partnership with Indonesia in 2023, with the intention of creating a clean nickel supply chain. Another avenue for building partnership with Indonesia is through the Indo-Pacific Framework for Prosperity (IPEF), an agreement between the U.S. and countries across the Indo-Pacific region to advance resilience, sustainability, inclusiveness, economic growth, fairness, and competitiveness for our economies. ^{337} IPEF recently announced a critical minerals dialogue, and the IPEF Supply Chain Agreement entered into force in February 2024. ^{338} Another avenue is through DOI's International Technical Assistance Program (DOI‐ITAP), which builds capacity in other countries by drawing from the diverse expertise of DOI employees, lending assistance and expertise to projects, including mining. ^{339} DOI and USAID partnered to advise Indonesia's Ministry of Mines on mining governance. The State Department also entered a memorandum of understanding with Indonesia's Ministry of Energy and Mineral Resources to cooperate on responsible mining and minerals processing. ^{340} The U.S. also supports the Just Energy Transition Partnership, which supports clean electricity development in Indonesia.
^{337} https://ustr.gov/trade-agreements/agreements-under-negotiation/indo-pacific-economic-framework-prosperity-ipef .
^{338} https://www.commerce.gov/news/press-releases/2024/01/us-department-commerce-announces-upcoming-entry-force-ipef-supply-chain .
^{339} https://www.doi.gov/intl/itap .
^{340} ANL at 45.
The Democratic Republic of Congo (DRC) is the world's largest source of cobalt, with 70 percent of current world production and 48 percent of reserves. ^{341} The U.S. is partnering with DRC to secure cobalt supply to close the gap between projected domestic demand and projected domestic supply. Through PGI, the United States is supporting the development of the Lobito Corridor, which connects the Democratic Republic of the Congo and Zambia with global markets through Angola, with an initial investment of $250 million in a rail expansion that intends to reduce transport time and lower costs for metals exports from the region. ^{342} Child and forced labor has been a particular concern for DRC, given the known presence of child workers at artisanal mines across the region, despite these mines making up a minority of cobalt mining operations. The U.S. and allies are partnering with the DRC to combat child and forced labor in the cobalt supply chain. A notable example is the Department of Labor (DOL)-funded Combatting Child Labor in the Democratic Republic of the Congo's Cobalt Industry (COTECCO) project. ^{343}
^{341} ANL at 46.
^{342} https://www.whitehouse.gov/briefing-room/statements-releases/2023/05/20/fact-sheet-partnership-for-global-infrastructure-and-investment-at-the-g7-summit .
^{343} https://www.dol.gov/agencies/ilab/comply-chain ; https://www.dol.gov/agencies/ilab/combatting-child-labor-democratic-republic-congos-cobalt-industry-cotecco . See also the further discussion in RTC section 17.2.
Elsewhere in Africa, the United States International Development Finance Corporation (DFC) has invested to expand graphite mining and processing in Mozambique. ^{344} The United States is working closely with its FTA partner Australia to develop graphite mining projects in Tanzania and other countries. ^{345}
^{344} ANL at 57.
^{345} ANL at 58.
Notably, the U.S. is a member of the Minerals Security Partnership, which a collaboration of 13 countries and the EU to invest in a responsible, secure critical minerals supply chains globally. ^{346}
^{346} https://www.state.gov/minerals-security-partnership .
The selected examples explore U.S. engagements with some of the most important international players in critical mineral supply chains, but they are by no means exhaustive. Below is a graphic overview of U.S. initiatives to secure electric vehicle battery minerals across the world (Figure II-11).
In addition, as we noted at proposal, it merits mention that utilization of critical minerals is different from the utilization of foreign oil, in that oil is consumed as a fuel while minerals become a constituent of manufactured vehicles. 88 FR 25968. That is, mineral security is not a perfect analogy to energy security. Supply disruptions and fluctuating prices are relevant to critical minerals as well, but the impacts of such disruptions are felt differently and by different parties. Disruptions in oil supply or gasoline price have an immediate impact on consumers through higher fuel prices and thus constrains the ability to travel. In contrast, supply disruptions or price fluctuations of minerals affect only the production and price of new vehicles. In practice, short-term price fluctuations do not always translate to higher production cost as most manufacturers purchase minerals via long-term contracts that insulate them to a degree from changes in spot prices. Moreover, critical minerals are not a single commodity but a number of distinct commodities, each having its own supply and demand dynamics, with many being capable of substitution by other minerals. ^{347} Importantly, while oil is consumed as a fuel and thus requires continuous supply, minerals become part of the vehicle and have the potential to be recovered and recycled. Thus, even when minerals are imported from other countries, their acquisition adds to the domestic mineral stock that is available for domestic recycling in the future.
^{347} For example, manganese can be subsituted by aluminum in the case of nickel-manganese-cobalt (NMC) and nickel-cobalt- aluminum (NCA) batteries. Likewise, an LFP battery uses iron phosphate chemistry without nickel, manganese, cobalt or aluminum. Research has also been conducted to study the replacement of lithium with sodium ions.
We thus reiterate our conclusion from proposal that there are short-term, medium-term, and long-term means of successfully dealing with issues of mineral security—both mineral availability and supply chains for the acquisition of minerals. Lithium supply in the mid- and long-term will largely be satisfied domestically, with supply gaps being filled by countries with which the U.S. has strong relations. Although we do not anticipate domestic supply to meet a large share of demand for cobalt, nickel, and graphite, we have indicated pathways by which a diversified and secure global supply chain for each may be achieved, describing a portfolio of bilateral and multilateral development efforts underway as of February 2024 to secure critical minerals from friendly countries, as described in the DOE Argonne Laboratory report on critical minerals availability. We anticipate these minerals security efforts to continue to expand subsequent to this final rulemaking. We consequently regard the Phase 3 standards as feasible in light of concerns regarding mineral security.

iii. Assessment of Heavy-Duty BEV Charging Infrastructure
As BEV adoption grows, more charging infrastructure will be needed to support the HD BEV fleet. ^{348} We received many comments on this topic. Vehicle manufacturers, dealers, fleet owners, and representatives of the fuels industry among others raised concerns that charging and supporting infrastructure, both front-of-the-meter (electricity generation, distribution, and transmission) and back-of-the-meter (such as EVSE installations), is inadequate today and that the pace of deployment is not on track to meet levels projected if the proposed standards are finalized. Commenters noted that fleets will not buy, or may cancel orders, if charging infrastructure is a barrier. A particular concern raised by commenters is that although back-of-the-meter issues ( e.g., how many EVSE ports to purchase, where to install EVSE, etc.) are largely in the control of the vehicle purchaser, front-of-the-meter issues are not. Commenters noted that if infrastructure is needed to support the EVSE hardware—generally termed distribution grid buildout—liaison with a utility is necessary. In this regard, many commenters spoke of a conundrum whereby owners will not purchase a BEV without assurance of adequate supporting infrastructure, but utilities will not build out without advance assurance of demand.
^{348} Infrastructure includes both charging infrastructure, which includes the EVSE on the customer side of the meter, and grid infrastructure, that is the power generation, transmission, and distribution on the utility side of the meter.
We also received comments from non-governmental organizations, electrification groups, electric vehicle manufacturers, and utilities indicating that there could be adequate supporting infrastructure, including distribution grid buildout, within the proposed Phase 3 rule's timeframe. They pointed out that buildout need not occur nationwide, nor all at once. Rather, they noted that initial buildout could be concentrated in a relatively few high-volume freight corridors. They also highlighted the many public and private investments in charging infrastructure that have been announced or are underway. Commenters flagged innovative charging solutions such as charging-as-a-service and mobile charging that can help meet the needs of fleets that experience delays installing EVSE or for which there are other barriers to depot charging. Some noted that public charging needs will be geographically concentrated in early years, allowing a phased approach for public infrastructure deployment. Finally, commenters noted that EPA finalizing stringent standards would provide certainty to OEMs, EVSE providers and utilities and spur further investments in charging infrastructure.
One point on which we received many comments was that there would need to be public charging to support the Phase 3 standards under the modeled potential compliance pathway. In this regard, the first group of commenters raised issues about the adequacy and availability of public charging networks. They noted that HD BEVs have different charging needs from LD vehicles, and that the power levels and site designs of public charging stations available today may not be able to serve HD vehicles. While some of these commenters noted the importance of public investments in charging infrastructure, they expressed concern that programs such as the $5 billion National Electric Vehicle Infrastructure (NEVI) program established under the BIL will primarily support infrastructure designed for LD vehicles. The second group of commenters were optimistic that a sufficient public charging network was feasible within the 2027-2032 time frame, and some of these commenters provided quantified information as to potential network extent and cost in support.
We note at the outset that we agree with the commenters regarding the need to assess and cost public charging corresponding to the modeled potential compliance pathway supporting feasibility of the final standards. EPA's potential compliance pathway at proposal posited that all HDV charging needs could be met with depot charging, and EPA's cost estimates consequently reflected depot charging only. DRIA at 195. EPA acknowledged at proposal that public charging would ultimately be necessary, DRIA at 195-96, and now agrees with commenters that the need is nearer-term and that analysis of public charging should be included as part of the modeled potential compliance pathway that supports the feasibility of the final standards. Accordingly, the analysis for the final rule reflects incorporation of public charging for certain HDV subcategories starting in MY 2030. We have made the appropriate modifications to our cost estimates, and to HD TRUCS, to reflect public charging needs in the modeled potential compliance pathway. Further details are in sections II.D.5.iv, II.E.2, and II.E.5.ii.

a. Depot Charging

(1) Behind-the-Meter Infrastructure
In both the NPRM and here in the final rule, we expect that much of the infrastructure development may be purchased by individual BEV or fleet owners for depot charging or be subject to third-party contracts to provide charging as a service. ^{349} Manufacturers are working closely with their customers to support this type of EVSE infrastructure, many making recent announcements since the NPRM was issued.
^{349} “EV charging as a service”. IRENA—International Renewable Energy Agency. Accessed February 23, 2024. Available online: https://www.irena.org/Innovation-landscape-for-smart-electrification/Power-to-mobility/31-EV-charging-as-a-service .
For example, PACCAR sells a range of EVSEs to customers directly. ^{350} Mack Trucks partnered with two charging solution companies so that they can offer customers the ability to acquire EVSE solutions directly from their dealers. ^{351} DTNA also announced a partnership to provide their customers with EVSE solutions. ^{352} Similarly, Navistar partnered with Quanta Services, Inc. to provide BEV infrastructure solutions, that include support in the design, construction, and maintenance of EVSE at depots. ^{353} Nikola has partnered with ChargePoint to provide fleet customers with a suite of options for charging infrastructure and software ( e.g., for charge management). ^{354} AMPLY Power, which was acquired by BP in 2021, provides charging equipment and services for a variety of fleets, including van, truck, and bus fleets. ^{355}
^{350} PACCAR. “Electric Vehicle Chargers.” Accessed on November 1, 2023. Available online: https://www.paccarparts.com/technology/ev-chargers .
^{351} Volvo Group Press Release. “Mack Trucks Enters Partnerships with Heliox, Gilbarco to Increase Charging Accessibility.” February 14, 2023. Available online: https://www.volvogroup.com/en/news-and-media/news/2023/feb/mack-trucks-enters-partnerships-with-heliox-gilbarco-to-increase-charging-accessibility.html .
^{352} Daimler Trucks North America Press Release. “Electrada, Daimler partner for electric charging.” October 3, 2023. Available online: https://www.truckpartsandservice.com/alternative-power/battery-electric/article/15635568/electrada-daimler-partner-for-chargers .
^{353} Navistar Press Release. “Navistar Partners With Infrastructure Solutions Provider Quanta Services.” May 3, 2023. Available online: https://news.navistar.com/2023-05-03-Navistar-Partners-With-Infrastructure-Solutions-Provider-Quanta-Services .
^{354} Nikola. “Nikola and ChargePoint Partner to Accelerate Charging Infrastructure Solutions.” November 8, 2022. Available online: https://nikolamotor.com/press_releases/nikola-and-chargepoint-partner-to-accelerate-charging-infrastructure-solutions-212 .
^{355} BP. Press Release: “bp takes first major step into electrification in the US by acquiring EV fleet charging provider AMPLY Power”. December 7, 2021. Available online: https://www.bp.com/en/global/corporate/news-and-insights/press-releases/bp-takes-first-major-step-into-electrification-in-us-by-acquiring-ev-fleet-charging-provider-amply-power.html .
Some companies are starting with mobile charging units while they test or pilot vehicles. ^{356} For example, PACCAR has partnered with Heliox to offer 40 kW and 50 kW mobile charging units to its dealers and customers of the Kenworth and Peterbilt brands, ^{357} and Sysco, which plans to deploy 800 Class 8 BEV tractors in the next few years, plans to use mobile charging units to begin their truck deployments while 14 charging stations are being installed. ^{358}
^{356} Mobile charging units are EVSE that can move to different locations to charge vehicles. Depending on the unit's specifications and site, mobile charging units may be able to utilize a facility's existing infrastructure ( e.g., 240 V wall outlets) to recharge. Mobile charging units may have wheels for easy transport.
^{357} Hampel, Carrie. “Heliox to be global charging partner for Paccar”. Electrive.com. September 24, 2022. Available online: https://www.electrive.com/2022/09/24/heliox-to-be-global-charging-partner-for-paccar/ .
^{358} Morgan, Jason. “How Sysco Corp. plans to deploy 800 battery electric Class 8 trucks (and that's just the beginning)”. Fleet Equipment. November 14, 2022. Available online: https://www.fleetequipmentmag.com/sysco-battery-electric-trucks .
While we agree with commenters that dedicated HD charging infrastructure may be limited today, we expect both depot and public charging to expand significantly over the next decade. The U.S. government is making large investments in charging infrastructure through the BIL ^{359} and the IRA, ^{360} as discussed in RIA Chapter 1.3.2. For example, the Charging and Fueling Infrastructure Discretionary Grant Program (CFI Program) recently announced the first-year grant recipients under the program. ^{361} In total, over $600 million in grants will support the deployment of charging and alternative fueling infrastructure in communities and along corridors in 22 states (see RTC 6.1 for a summary of grants that will specifically support HD charging infrastructure). The IRA extends and modifies the “Alternative Fuel Refueling Property Credit” tax credit under section 30C of title 26 of the Internal Revenue Code (“30C”) that could cover up to 30 percent of the costs for procuring and installing charging infrastructure (subject to a $100,000 per item cap) in eligible census tracts through 2032. Based on its assessment of the share of heavy-duty charging stations that may be located in qualifying areas (and other 30C provisions), DOE projects an average value of this tax credit of 18 percent of the installed EVSE costs at depots and up to 27 percent ^{362} at public charging stations. 363 364 In addition, there are billions of dollars in funding programs that could support HD charging infrastructure either on its own or alongside the purchase of a HD BEV. As detailed in the following sections, private investments will also play an important role in meeting future infrastructure needs. We also agree with commenters that the existence of the final standards themselves provides regulatory certainty that will spur further infrastructure investments—both by HD vehicle purchasers installing EVSE at depots and by manufacturers, utilities, EVSE providers, and others installing public charging stations.
^{359} Infrastructure Investment and Jobs Act, Public Law 117-58, 135 Stat. 429 (2021). Available online: https://www.congress.gov/117/plaws/publ58/PLAW-117publ58.pdf.
^{360} Inflation Reduction Act, Public Law 117-169, 136 Stat. 1818 (2022). Available online: https://www.congress.gov/117/plaws/publ169/PLAW-117publ169.pdf.
^{361} JOET, “Biden-Harris Administration Bolsters Electric Vehicle Future with More than $600 Million in New Funding,” January 11, 2024, https://driveelectric.gov/news/new-cfi-funding.
^{362} The average value of 27 percent for public charging infrastructure is for EVSE under 1 MW; for 1 MW and higher, DOE estimates an average tax credit value of 19 percent.
^{363} U.S. DOE, “Estimating Federal Tax Incentives for Heavy Duty Electric Vehicle Infrastructure and for Acquiring Electric Vehicles Weighing Less than 14,000 Pounds.” Memorandum, March 2024.
^{364} See preamble section II.E.2 and RIA Chapter 2.6.2.1 for a discussion of how we accounted for this tax credit in our analysis of depot EVSE costs.
EVSE for HD BEVs is available today for purchase. However, EPA recognizes that it takes time for individual or fleet owners to develop charging site plans for their facility, obtain permits, purchase the EVSE, and have it installed. For the depots that may be charging a greater number of vehicles or with high-power DCFC ports, an upgrade to the electricity distribution system may be required adding to the installation timeline. As described in RIA Chapter 2.10.3, we estimated the total number of EVSE ports that will be required to support the depot-charged BEVs in the potential compliance pathway's technology packages developed to support the MYs 2027-2032 standards. We estimated about 520,000 EVSE ports will be needed across all six model years, but only about half of those will be required to support the MY 2027 through MY 2030 vehicles. The majority (88 percent) of EVSE ports (for MY2027-2032) are Level 2 ports, which are less likely to require lengthy upgrades to the distribution system as described in section II.E.2. See also RTC section 7 (Distribution). In conclusion, there is time to install EVSE at depots to support projected utilization of BEV technologies beginning in MY 2027.

(2) Front-of-the-Meter Infrastructure/Distribution Grid Buildout
EPA has carefully considered the many comments concerning the need for, timing of, and cost for distribution grid buildout. ^{365} This issue relates to the infrastructure linking transmission lines to an electricity user. A typical grid infrastructure diagram shows a transmission line feeding into a distribution substation which serves several feeders to distribute power. From the feeders that serve thousands of customers, the service transformers step down the voltage to customer utilization levels. Of these three elements of distribution grid infrastructure, the substation is by far the costliest and most time-intensive to construct (though less so to upgrade an existing substation), feeders are the next most resource intensive, and service transformers the least. Table II-9, based on information in RIA Chapter 1.6.5, shows timing estimates for each of these elements. 366 367
^{365} See, RTC section 7 (Distribution) for a full discussion of the issues discussed in this preamble section; see also RIA Chapter 1.6.
^{366} Borlaug, B., Muratori, M., Gilleran, M. et al. “Heavy-duty truck electrification and the impacts of depot charging on electricity distribution systems”. Nat Energy 6, 673-682 (2021). Available online: https://www.nature.com/articles/s41560-021-00855-0 .
^{367} EPRI. “EVs2Scale2030TM Grid Primer”. August 29, 2023. Available online: https://www.epri.com/research/products/000000003002028010 .
New substation costs can vary, depending on location (urban/suburban/rural) and Megavolts ampere with estimates showing $4 to $35 million. ^{368} Feeders can cost from $100 to approximately $872 per foot, variables being above or below ground installation, and voltage (typically $1 million for 0 kV-25 kV and $1.5 million for 26kV-35kV)). ^{369} The estimated cost of a non-DCFC service transformer is $20,000. ^{370}
^{368} Borlaug, B., Muratori, M., Gilleran, M. et al. “Heavy-duty truck electrification and the impacts of depot charging on electricity distribution systems”. Nat Energy 6, 673-682 (2021). Available online: https://www.nature.com/articles/s41560-021-00855-0 .
^{369} National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Kevala Inc., and U.S. Department of Energy. “Multi-State Transportation Electrification Impact Study: Preparing the Grid for Light-, Medium-, and Heavy-Duty Electric Vehicles”. DOE/EE-2818. U.S. Department of Energy. March 2024. At 64-65 (“TEIS”).
^{370} TEIS at 96. Median cost of DCFC service transformers in the Study was $50,000. Id.
EPA has assessed the question of how much buildout might be needed (under the modeled potential compliance pathway supporting the feasibility of the standards) at the national level, at the regional level, and at the parcel level. ^{371} Assessment was conducted with EPA internal tools ^{372} as well as with a first of its kind ground up analysis from DOE. We find that electricity demand attributable to the Phase 3 standards under the modeled potential compliance pathway is minimal for any and all of these perspectives, and especially so in the initial years of the program when the lead time needed for distribution grid buildout installation could potentially otherwise be constraining.
^{371} A “parcel”, as used in the TEIS, means “a real estate property or land and any associated structures that are the property of a person with identification for taxation purposes.” TEIS at 2 n. 15.
^{372} See discussion of IPM modeling for the interim control case described in RIA Chapter 4.2.4.
In 2027, the Phase 3 rule is projected to increase transportation sector electricity demand by a modest 0.67 percent; that is, of the national demand for electricity posed by the transportation sector, less than 1 percent is attributable to the Phase 3 rule in 2027. In 2032, this rule is projected to increase transportation sector electricity demand to 9.27 percent. ^{373} We note that the modeling associated with these estimates uses the final rule adoption rate scenario, which corresponds to the modeled potential compliance pathway for the final rule.
^{373} Murray, Evan “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024). (National Demand tab).
Furthermore, since this demand is only that attributable to the transportation sector, the demand as a percentage of total demand on a utility would be less, since it would be a fraction of all other sources of demand. Thus, in 2030 and 2035 (the years we modeled for this analysis), increases in the demand for the modeled compliance pathway are only 0.41 percent and 2.59 percent. ^{374}
^{374} Murray, Evan “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024). (Generation National Demand tab).
Moreover, as commenters noted (see RTC sections 6.1 and 7 (Distribution)), charging infrastructure needed to meet this demand in the time frame of the rule is likely to be centered in a sub-set of states and counties where freight activity is concentrated and supportive ZEV polices exist. ICCT found that likely areas of high concentration include Texas (Harris, Dallas, and Bexar counties); southern California (Los Angeles, San Bernadino, San Diego and Riverside counties); New York State (Bronx, New York, Queens, Kings, and Richmond counties); Massachusetts (Suffolk county); Pennsylvania (Philadelphia county); New Jersey (Hudson county); and Florida (Miami-Dade county). ^{375} These areas are projected to experience either higher aggregate demand or higher energy demand per unit area attributable to HD BEV adoption. In the critical initial year of the Phase 3 standards, when there is the least lead time, EPA's projected increases in electricity demand are very modest, ranging from 0.002 percent (Los Angeles-Long Beach-Anaheim) to 0.88 percent (Phoenix-Mesa-Scottsdale). ^{376}
^{375} Comments of ICCT, July 2023 at 11. These comments reflect Ragon, Kelly, et al., 2023 (“ICCT May 2023 White Paper”).
^{376} Murray, Evan “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024). (MSA Demand tab).
These estimates are conservative. The projected increases represent increased electricity demand attributable to both the heavy-duty Phase 3 rule and demand from the light-duty sector absent the final rule. The portion of electricity demand attributable to the Phase 3 rule would be less.
We estimate that electricity demand in these high traffic freight corridors attributable to the transportation sector would increase in 2032, corresponding to need under the modeled potential compliance pathway to meet increased standard stringency (including standards for sleeper cab tractors and heavy heavy-duty vocational vehicles which commence after MY 2027, ranging from 0.014 percent (San Diego-Carlsbad) to 12.58 percent (San Antonio-New Braunfels). ^{377} EPA regards these projected increases as modest. The projected increases in 2027, when there is the shortest lead time for buildout, are small. As expected, demand is projected to increase in 2032 but there is considerably more available lead time in which buildout can be accommodated. Moreover, these increases are modest compared to total electricity demand on utilities within the states in these freight corridors. See RTC section 7 (Distribution).
^{377} Murray, Evan “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024). (MSA Demand tab).
The Department of Energy study, “Multi-State Transportation Electrification Impact Study” (“TEIS”) supports this conclusion at a more granular level. ^{378} This is the first study of this scale to be bottom up, comparing parcel level light, medium, and heavy-duty vehicle demand to parcel supply by PV (photovoltaic) and grid capacity at each examined parcel. The study focuses on 5 states (California, New York, Illinois, Oklahoma, and Pennsylvania) selected to capture diversity in population density (urban and rural areas), freight demand, BEV demand, state EV policies, utility type ( i.e., investor owned, municipality, or cooperative) and distribution grid composition. The TEIS used these states to extrapolate a national demand for where and when upgrades will be needed to the electricity distribution system—including substations, feeders, and service transformers—due to BEV load under the approximated combination of the EPA's combined light-duty and medium-duty rulemaking action (LMDV) ^{379} and HD Phase 3 rules and under a no action case. The research team also assessed the potential impact of managed EV charging at homes and depots to reduce the peak power needs and associated cost and timing of distribution upgrades. In the unmanaged case, the study assumes that EVs are charged immediately when the vehicle returns to a charger. In contrast, the managed charging case has vehicles arriving at charging locations and intentionally minimizing charging power such that the session is completed just prior to the vehicle's departure from that location ^{380} The study also incorporates public charging such that the corresponding high power needs are reflected.
^{378} National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Kevala Inc., and U.S. Department of Energy. “Multi-State Transportation Electrification Impact Study: Preparing the Grid for Light-, Medium-, and Heavy-Duty Electric Vehicles”. DOE/EE-2818. U.S. Department of Energy. March 2024. (“TEIS”).
^{379} EPA's combined light-duty and medium-duty rulemaking action “Multi-Pollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles” Docket ID: EPA-HQ-OAR-2022-0829. We refer to this action both as the Light- and Medium-Duty (LMDV) rule and/or LD rule for short in this preamble.
^{380} TEIS at 4.
The study estimates overload at the substation level (100 percent criteria), feeder level (100 percent criteria), and at the residential service transformer per feeder level (125 percent) criteria. ^{381} Scenarios examined are for 2027 “no action” ( i.e., baseline without the LMDV or HD Phase 3 emission standards under the two rulemakings) with and without mitigation ( i.e., the EV charging management just described), and the action case with EPA's LMDV and HD Phase 3 rules, again both with and without mitigation. The action case uses the same case EPA used for its national and regional estimates presented previously in this section, which include higher electricity demand than corresponds to the HD Phase 3 final standards under the modeled potential compliance pathway. The study examines the same scenarios for 2032. ^{382}
^{381} TEIS at 47 (substation), 47 (feeder), and 49 (transformer).
^{382} TEIS at 2-3. The No Action case includes current state and Federal policies and regulations as of April 2023. Id. at 3.
Consistent with the national demand and high freight corridor regional demand estimates, the TEIS projects minimal demand (energy consumption) and minimal peak demand for both 2027 and 2032, even without considering any mitigation. In 2032, that incremental increase ranged from 1.6 percent to 2.7 percent. ^{383} Incremental impact on peak demand, again from the unmanaged case, was 0.1-0.2 percent in 2027 and 0.6-3.0 percent in 2032. ^{384}
^{383} TEIS at 56.
^{384} TEIS at 62.
If BEV users engage in simple management strategies—shifting charging times as described previously in this section ^{385} —not only do these z2estimates of energy consumption and peak demand impacts decrease, but in some instances, peak demand is projected to decrease in absolute terms, that is, to be less than in the no action unmanaged case. Thus, for 2027, incremental peak demand decreases in four of the five states, and remains identical in the fifth. ^{386} For 2032, incremental peak demand is positive in two of the states but the increase is only 0.1 percent and 0.5 percent, and reduced in the other states by 0.5-1.8 percent potentially obviating the need for any buildout at all. ^{387}
^{385} TEIS at 4.
^{386} TEIS at 62.
^{387} TEIS at 62.
These minor increases reflect low numbers of transformers, feeders, and substations estimated to be needed (again, for the five states at issue, and for both LMDV and HD Phase 3 rules together). In 2027, only 1 additional substation is projected to be needed, and none in the managed case. ^{388} In 2032, the TEIS projects that only 8 substations would be needed in the unmanaged case, 4 if conservative mitigative measures are utilized. ^{389} Projections for feeders are 9 in 2027 (5 in the managed case), and 125 in 2032 (75 if managed). In 2027, the TEIS projects 2,800 transformers (2,400 if managed), and 30,000 in 2032 (21,000 in the managed case). ^{390}
^{388} TEIS at Table ES-2.
^{389} TEIS at Table ES-2.
^{390} TEIS at Table ES-2. Compare this with the estimated 50 million transformers in use presently. See RTC section 7 (Distribution).
Although new substations are a significant undertaking that can take multiple years as shown in Table II-9, as noted, the TEIS finds that only a small number are projected to be needed. We note further that the estimates in the TEIS Study of the amount of distribution buildout needed are conservative with respect to the HD Phase 3 rule. First, the TEIS Study considered both the light/medium duty standards and the HD Phase 3 emission standards together and did not disaggregate the results. Second, as just noted, the action scenario considered included higher electricity demand than corresponds to the Phase 3 final standards under the modeled potential compliance pathway. Third, the “unmanaged” scenario presented considers no mitigation efforts at all. If minimal mitigation efforts, characterized in the TEIS as “a conservative estimate of the benefits of managed charging”, ^{391} are considered estimated impacts decrease sharply. The action managed case is projected to reduce peak loads in all 5 States in 2027, and to reduce peak loads in 3 of the 5 States in 2032.
^{391} TEIS at 4.
We further have modeled a potential compliance pathway whereby almost all of the HD BEVs utilize Level 2 or DC-50 kW chargers for depot EVSE, rather than higher rated chargers. ^{392} These lower rated chargers will not pose the types of electricity demand potentially requiring distribution buildout upgrades as the higher-rated chargers posited by some of the commenters. ^{393}
^{392} RIA chapter 2 at Table 2-73. The only exceptions are for four tractors projected to utilize DC-150kW chargers (HD TRUCS vehicles 30, 31, 83, and 101), and one additional tractor and one transit bus projected to utilize DC-350kW chargers (HD TRUCS vehicles 80 and 87).
^{393} The ICCT White Paper likewise finds that “trucks with smaller batteries can charge overnight with 50 kW CCS chargers or 19 kW Level 2 chargers in some cases.” ICCT White Paper at p. 6.
EPA recognizes that from the standpoint of timing, it is important to consider not only incremental increases in demand attributable to the HD Phase 3 emission standards but also other demand from the light-duty, medium-duty, and heavy-duty transportation sector that might occasion the need for distribution grid buildout. For example, buildout potentially could be needed with respect to HD BEVs in the EPA reference case. We continue to find that this overall demand can be accommodated within the timeframe of the rule, for the following reasons.
As discussed previously in this section, buildout need not occur everywhere and all at once. In the rule's time frame, as shown in particular in the ICCT 2023 White Paper, it can be centered in a discrete number of high freight corridors.
In the early model years of the program, when lead time is the shortest, projected demand remains low. ^{394} When accounting for the increase from all vehicles (light-duty and heavy-duty), we find the portion of demand attributable to the entire heavy-duty vehicle sector (including ACT) increases by only 2.6 percent between 2024 and 2027. ^{395} That is, the increase in demand attributable specifically to electric heavy-duty vehicles (including ACT), and therefore the infrastructure buildout necessary to support those vehicles, is small compared to other factors.
^{394} TEIS at 75 showing national distribution costs in 2027 (reflecting both light- and heavy-duty sectors).
^{395} Murray, Evan, “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024).
We further project that a substantial majority of these ACT-compliant ZEVs would be light and medium heavy vocational vehicles which utilize EVSE types least likely to occasion demand triggering need for buildout. RIA Chapter 4.2.2. For example, the TEIS projects no need for new and upgraded substations in 2027 nationally, and need for only approximately 24-48 (managed and unmanaged cases) nationally in 2032. ^{396}
^{396} TEIS at 65 and using the TEIS analysis showing that the 5 states analyzed account for approximately one third of national costs (TEIS at 66).
Most of the demand comes from the states which have adopted ACT. ^{397} EPA notes that these states that have adopted the program have undertaken and have on-going efforts to achieve it. See RTC section 7 (Distribution) describing such on-going efforts.
^{397} Murray, Evan “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024). (Demand by State tab).
With respect to non-ACT states, most of the demand in these states is attributable to the HD Phase 3 rule itself. See RIA Chapter 4.2.2. As discussed in RTC section 7 (Distribution) with respect to high freight corridors in non-ACT states (including Pennsylvania, Texas, Arizona, and Illinois), that incremental demand is low, especially in the initial year of the program. State-by state results show similar small percentages of increased demand. ^{398}
^{398} Murray, Evan “Calculations of the Impacts of the Final Standards at Various Geographic Scales” (February 29, 2024) (Demand by State tab).
EPA agrees with this assessment from the Energy Strategy Coalition (speaking for some of the nation's largest investor-owned electric and gas utilities, public power authorities and generators of electricity): “[d]emand for electricity will increase under both the HDV Proposal and recently-proposed multi-pollutant standards for light-duty and medium-duty vehicles . . . . but the electricity grid is capable of planning for and accommodating such demand growth and has previously experienced periods of significant and sustained growth.” ^{399} We further note the comments of the Edison Electric Institute (trade association of the nation's investor-owned utilities) (“EEI”) that the degree of anticipated buildout is similar to increases experienced historically by the utility industry, and can be accommodated within the HD Phase 3 rule's timeframe. EEI Comments at 7, 8. The Analysis Group reached a similar conclusion. ^{400} Some commenters were concerned that interactions with utilities and their regulatory commissions vary state-by-state, and that this regime adds to grid buildout deployment timing difficulties. ^{401} Other commenters, however, persuasively maintained that this localized system is actually a plus, because each potential buildout is a localized decision, best handled by the local utility and grid operator. ^{402} As discussed further below, there are also many mitigative measures which BEV users can utilize to reduce demand, and the localized process could provide a means of developing local site optimized mitigative measures.
^{399} Comments of Energy Strategy Coalition, at pp. 1-2.
^{400} Hibbard et al., “Heavy Duty Vehicle Electrification” (June 2023) at 27 (“Adding significant new distribution system infrastructure is not a new experience for states, public utility commissions, or electric companies, and there are long-standing policies and practices in place to ensure timely planning for and development of the infrastructure needed to endure system, reliability. And for most states and electric companies in the country. The magnitude and pace of system demand growth associated with the rollout of the EPA's proposed phase 3 rule neither different from past periods of economically-driven demand growth, nor unusual with respect of the processes of forecasting, planning and development required.”).
^{401} Comments of DTNA at 47; see also Comments of Environmental Defense Fund at 67.
^{402} Comments of State of California at 29.
Finally, we expect that the HD Phase 3 rule itself will serve as a strong signal to the utility industry to make proactive investments and otherwise proactively analyze and plan for potential buildout needs. ^{403}
^{403} See Comments of CATF at 48; Comments of EDF at 75; Comments of ICCT at 10; Comments of Moving Forward Network at 114.
Commenters pointed out that “at the distribution system level it is not sufficient to simply compare potential charging station demand growth to system capacities.” ^{404} Numerous commenters also pointed to a chicken-egg conundrum, whereby potential fleet purchasers contemplating BEVs will not purchase without an assurance of adequate electrical supply, but utilities cannot build out without having assurance of demand.
^{404} Analysis Group Heavy Duty Vehicle Electrification at 10.
EPA believes that there are potential solutions to these issues. First, as demonstrated previously in this section, we have projected a potential compliance pathway to meet the final standards whereby there will be limited need for grid distribution buildouts. Those buildouts that we project largely involve transformers or feeders, and (in 2032) a handful of expanded substations. We emphasize again that this analysis is conservative in that we did not include ameliorative measures available to utilities to apportion demand (discussed below).
Second, utilities can and are acting proactively to provide added capacity when needed. As stated by EEI, “EPA's assessment that `there is sufficient time for the infrastructure, especially for depot charging, to gradually increase over the remainder of this decade to levels that support the stringency of the proposed standards for the timeframe they would apply' is accurate. . . . . As described previously in this section, EEI members actively are planning for and deploying infrastructure today”. EEI Comments at 14. EEI documents that a number of large utilities are finding ways to move away from a business model requiring demonstration of concrete demand so as to provide infrastructure readiness in advance of individual applications. EEI comments at 12-14 (actions of California and New York State investor-owned utilities, and their respective regulatory bodies); see RTC section 7 (Distribution) for additional examples. And as noted by the Energy Strategy Coalition (speaking for some of the nation's largest investor-owned electric and gas utilities, public power authorities and generators of electricity): “[d]emand for electricity will increase under both the HDV Proposal and recently-proposed multi-pollutant standards for light-duty and medium-duty vehicles . . . . but the electricity grid is capable of planning for and accommodating such demand growth and has previously experienced periods of significant and sustained growth.” ^{405}
^{405} Comments of Energy Strategy Coalition, at pp. 1-2.
Utilities, of course, are motivated to continue investment in the distribution system for reasons other than demand from the transportation sector, and so could be building out in some cases for their own purposes. ^{406} In addition, utilities themselves are pursuing innovative solutions to address the issue of needed buildout. One approach is for utilities to make non-firm capacity available immediately as they construct distribution system upgrades. See RTC 7 (Distribution) discussing Southern California Edison's two-year Automated Load Control Management Systems pilot program which would limit new customers' consumption during periods when the system is constrained while the utility completes needed upgrades providing those customers access to the distribution system sooner than would otherwise be possible.
^{406} TEIS at 99-100, noting the need to replace aging assets, and for scheduled maintenance.
Plans like Southern California Edison's to use load management systems to connect new EV loads faster in constrained sections of the grid will be bolstered by standards for load control technologies. UL, an organization that develops standards for the electronics industry, drafted the UL 3141 Outline of Investigation (OOI) for Power Control Systems (PCS). Manufacturers can use this standard for developing devices that utilities can use to limit the energy consumption of BEVs. With this standard in place and manufacturer completion of conforming products, utilities will have a clear technological framework available to use in load control programs that accelerate charging infrastructure deployment for their customers. ^{407}
^{407} UL LLC. January 11, 2024. “UL 3141: Outline for Investigation of Power Control Systems.” Available online: https://www.shopulstandards.com/ProductDetail.aspx?productId=UL3141_1_O_20240111 .
Third, there are means for utilities to ameliorate demand which do not require regulatory approval. Utilities can engage in short-term load rebalancing by optimizing use of existing distribution infrastructure. This can accommodate new HDV demand while maintaining overall system reliability. ^{408} In addition, because depot charging often occurs over nighttime hours corresponding to reduced system demand, utilities have the flexibility to use otherwise extra grid capacity for those hours (excess capacity being inherent in constructing to nameplate capacity). ^{409} Utilities also can reduce needed demand by incorporating so-called smart charging into feeder ratings and load forecasting whereby the utility need not provide capacity based on annual peak load, but can differentiate by daily and seasonal times. ^{410} An available variant of this practice is use of flexible interconnections, whereby customers agree to limit their peak load to a specified level below the cumulative nameplate capacity of their equipment (in this case, their EVSEs) until associated grid upgrades can be completed, in order to begin operating any new needed charging infrastructure more quickly. ^{411}
^{408} ICCT White Paper at 18-19.
^{409} ICCT White Paper at 19.
^{410} ICCT Comment at 12.
^{411} Comments of EDF at 69; Electric Power Research Institute (EPRI), “Understanding Flexible Interconnection” (September 2018) (describing flexible interconnection generally, and detailing its possibilities for reducing demands on time—and location-dependent hosting capacity).
Many utilities also provide hosting capacity maps. Utilities, developers, and other stakeholders can use these maps to better plan and site energy infrastructure. Hosting capacity maps provide greater transparency about where new loads such as EV chargers, can be readily connected without triggering a need for significant grid upgrades. Specifically, hosting capacity maps identify where power exists and at what level, where distributed energy resources (DERs) can alleviate grid constraints, or where an upgrade may be required. For example, EV companies can use the maps to identify new areas to expand their charging station networks more quickly and cost-effectively. While the information in hosting capacity maps does not address all the interconnection questions for individual sites, they can indicate relative levels of investment needed.
Fourth, there are many mitigative measures open to fleet owners utilizing depots. Readily available practices include use of managed charging software, energy efficiency measures, and onsite battery storage and solar generation. ^{412} Hardware solutions include bi-directional charging and V2G (vehicle to grid) whereby vehicles can return electricity to the grid during peak hours while drawing at low demand times. ^{413} Solar DER allows on site electricity generation that reduces the energy demand on the grid. Battery-integrated charging can simplify and accelerate EVSE deployment and potentially lower costs by avoiding the need for grid upgrades and reducing demand charges. These charging stations are easier for electric utilities to serve on relatively constrained portions of the distribution system. These charging stations use integrated batteries to provide high-powered charging to customers and recharge by drawing power from the grid at much lower rates throughout the day. ANL's study on battery-integrated charging shows that these systems can be deployed cost effectively for Class 1-3 BEV needs. ^{414} The use for LD BEV will at times eliminate the need for grid buildout, making that hardware available for HD BEV or other users that must have grid upgrades. While not a HD BEV analysis, the process can be applied to HD BEV to determine when this architecture provides value. Battery-integrated charging is commercially available and, for example, is being deployed across multiple states. 415 416 All of these can reduce demand below what would otherwise be nameplate capacity. See the comment summaries in RTC section 7 discussion of distribution costs. Other innovative charging solutions can also accelerate EV charging deployment. Mobile chargers can be deployed immediately because they do not require an on-site grid connection. They can be used as a temporary solution to bring additional charging infrastructure to locations before a stationary, grid-connected charger can be deployed. Additional innovative charging solutions can further accelerate charging deployment by optimizing the use of chargers that have already been installed. One company, EVMatch, developed a software platform for sharing, reserving, and renting EV charging stations, which can allow owners of charging stations to earn additional revenue while making their chargers available to more EV drivers to maximize the benefit of each deployed charger. ^{417} This scenario could allow HD BEV depots to earn revenue off of their chargers while the HD BEV are on the road doing work. Innovative charging models like these can be efficient ways to increase charging access for EVs with a smaller amount of physical infrastructure. We note that EPA's cost estimates do not include consideration of these mitigative measures, since we project a compliance pathway without needing them. However, these are all available measures to reduce demand and need for distribution buildout, and consequently form part of our basis for determining that there are reasonable means of providing needed distribution buildout in the rule's timeframe when there is a need to do so.
^{412} Comments of EDF at 69.
^{413} Comments of Advanced Energy United, EPA-HQ-OAR-2022-0985-1652-A2 at 4; Comments of Clean Air Task Force, EPA-HQ-OAR-2022-0985-1640-A1 at 54; Analysis Group Heavy Duty Vehicle Electrification at 33-4.
^{414} Poudel, Sajag, Jeffrey Wang, Krishna Reddi, Amgad Elgowainy, Joann Zhou. 2024. Innovative Charging Solutions for Deploying the National Charging Network: Technoeconomic Analysis. Argonne National Laboratory.
^{415} Blink. “Blink Charging Commissions First Battery Storage Energized DC Fast Charger in Pennsylvania Providing Off-Grid Charging Capabilities”. May 16, 2023. Available online: https://blinkcharging.com/news/blink-charging-commissions-first-battery-storage-energized-dc-fast-charger-in-pennsylvania-providing-off-grid-charging-capabilities .
^{416} Lewis, Michelle. “Texas trailblazes with DC fast chargers with integrated battery storage”. Electrek. February 12, 2024. Available online: https://electrek.co/2024/02/12/texas-dc-fast-chargers-integrated-battery-storage-xcharge-north-ameri .
^{417} EVmatch. Available online: https://evmatch.com/ .
A variety of solutions are being offered for, or explored by, fleets. For example, WattEV is planning a network of public charging depots connecting ports to warehouses and distribution centers as part of its “Truck-as-a-Service” model, in which customers pay a per mile rate for use of, and charging for, a HD electric truck. ^{418} The first station under construction in Bakersfield, CA, ^{419} is planned to have integrated solar and eventually be capable of charging 200 trucks each day; additional stations are under development in San Bernardino and near the Port of Long Beach. Zeem Solutions also offers charging to fleets along with a lease for one of its medium- or heavy-duty BEVs (via its “Transportation-as-a-Service” model). Zeem's first depot station opened last year in the Los Angeles area and will support the charging of vans, trucks, airport shuttles, and tour buses (among other vehicles) with its 77 DCFC ports and 53 L2 ports. ^{420} As many commenters noted, the question of availability of supporting electrification infrastructure is not fully in the control of the regulated entity (here, the manufacturer), nor is it fully in the direct control of prospective vehicle purchasers. As all agree, this necessitates some measure of coordination between a range of stakeholders and utilities. Utilities have a strong business incentive to coordinate to meet increased demand and many such means of coordination are described in the comments by utility associations like EEI, ^{421} and the transportation industry coalition ZETA. ^{422}
^{418} WattEV. “WattEV Orders 50 Volvo VNR Electric Trucks”. May 23, 2022. Available online: https://www.wattev.com/post/wattev-orders-50-volvo-vnr-electric-trucks .
^{419} WattEV. “WattEV Breaks Ground on 21st Century Truck Stop”. December 16, 2021. Available online: https://www.wattev.com/post/wattev-breaks-ground-on-21st-century-truck-stop .
^{420} Business Wire. “Zeem Solutions Launches First Electric Vehicle Transportation-As-A-Service Depot.” March 30, 2022. Available online: https://www.businesswire.com/news/home/20220330005269/en/Zeem-Solutions-Launches-First-Electric-Vehicle-Transportation-As-A-Service-Depot .
^{421} Comments of EEI pp. 10-16.
^{422} Comments of ZETA pp. 32-46.
In sum, we believe that distribution systems to meet the potential increase in charging station demand associated with depot charging under the HD Phase 3 rule will be available in the rule's timeframe. Quantified demand attributable to the rule is relatively modest, and, where buildout might be needed, can be met for the most part with the least time-intensive infrastructure buildout. We have also considered further potential issues, including the chicken-egg paradigm, and described means that are reasonably available to resolve them in the lead time provided by the rule. Utilities and fleets are already engaging in these practices. That the trade association of the investor-owned utility industry agrees provides further support for our finding. Comments of Edison Electric Institute at 14. See also preamble section II.E.5.ii.

b. Public Charging
As noted earlier in this section, EPA has revised its projected potential compliance pathway from proposal such that sleeper cab tractors and certain day cab tractors are projected to utilize public charging networks ^{423} rather than depot charging. See generally, preamble section II.D.5. We find here that there will be adequate lead time for development of supporting public charging infrastructure for these tractors under the modeled potential compliance pathway for the final standards.
^{423} En-route charging could occur at public or private charging stations though, for simplicity, we often refer to en-route charging as occurring at public stations.
First, as documented in the ICCT 2023 White Paper, there is no need to build out all at once. ^{424} It is reasonable to project that activity will center on the busiest long-haul freight routes and corridors. The White Paper further finds that in 2030, up to 85 percent of charging infrastructure needs for long-haul trucks could be met by building stations on discrete corridors of the National Highway Freight Network where energy demand is concentrated. ICCT White Paper at 14. Assuming an average of 50 miles between stops, this would mean a need for 844 public charging stations. Id. In a supplemental analysis assuming 100-mile intervals between stations, ICCT refined that estimate to needing between 100-210 electrified truck stops, assuming a given level of BEV long-haul tractors. ^{425} We note that the ICCT estimates in both the White Paper and the Supplemental comment assume more long-haul BEV adoption than in EPA's projected compliance pathway for 2030, and so, from that standpoint, can be considered to be conservative bounding estimates.
^{424} Ragon, et. al. “White Paper: Near-Term Infrastructure Deployment to Support Zero-Emission Medium- and Heavy-Duty Vehicles in the United States”. The International Council on Clean Transportation. May 2023. Available online: https://theicct.org/wp-content/uploads/2023/05/infrastructure-deployment-mhdv-may23.pdf .
^{425} ICCT. “Supplemental comments of the International Council on Clean Transportation on the EPA Phase 3 GHG proposal”. January 3, 2024. Docket ID EPA-HQ-OAR-2022-0985-.
In March 2024, the U.S. released a National Zero-Emission Freight Corridor Strategy ^{426} that, “sets an actionable vision and comprehensive approach to accelerating the deployment of a world-class, zero-emission freight network across the United States by 2040. The strategy focuses on advancing the deployment of zero-emission medium- and heavy-duty vehicle (ZE-MHDV) fueling infrastructure by targeting public investment to amplify private sector momentum, focus utility and regulatory energy planning, align industry activity, and mobilize communities for clean transportation.” ^{427} The strategy has four phases. The first phase, from 2024-2027, focuses on establishing freight hubs defined “as a 100-mile to a 150-mile radius zone or geographic area centered around a point with a significant concentration of freight volume ( e.g., ports, intermodal facilities, and truck parking), that supports a broader ecosystem of freight activity throughout that zone.” ^{428} The second phase, from 2027-2030, will connect key ZEV hubs, building out infrastructure along several major highways. The third phase, from 2030-2045, will expand the corridors, “including access to charging and fueling to all coastal ports and their surrounding freight ecosystems for short-haul and regional operations.” ^{429} The fourth phase, from 2035-2040, will complete the freight corridor network. This corridor strategy provides support for the development of HD ZEV infrastructure that corresponds to the modeled potential compliance pathway for meeting the final standards.
^{426} Joint Office of Energy and Transportation. “National Zero-Emission Freight Corridor Strategy” DOE/EE-2816 2024. March 2024. Available at https://driveelectric.gov/files/zef-corridor-strategy.pdf .
^{427} Joint Office of Energy and Transportation. “Biden-Harris Administration, Joint Office of Energy and Transportation Release Strategy to Accelerate Zero-Emission Freight Infrastructure Deployment.” March 12, 2024. Available online: https://driveelectric.gov/news/decarbonize-freight .
^{428} Joint Office of Energy and Transportation. “National Zero-Emission Freight Corridor Strategy” DOE/EE-2816 2024. March 2024. Available at https://driveelectric.gov/files/zef-corridor-strategy.pdf . See page 3.
^{429} Joint Office of Energy and Transportation. “National Zero-Emission Freight Corridor Strategy” DOE/EE-2816 2024. March 2024. Available at https://driveelectric.gov/files/zef-corridor-strategy.pdf . See page 8.
This level of public charging is achievable. As described in RIA Chapter 1.3, the U.S. government is making large investments in charging infrastructure through the BIL and the IRA. For example, in the past year, over $160 million in grants under the Charging and Fuel Infrastructure program were announced in the States of California, New Mexico, New York, and Washington for projects that will explicitly support HD charging. ^{430} (See RTC section 6.1.) As described in RIA Chapter 1.6, heavy-duty vehicle manufacturers, charging network providers, energy companies and others are also investing in public or other stations that could support public charging. For example, Daimler Truck North America is involved in an initiative in the U.S. with electric power generation company NextEra Energy Resources and BlackRock Renewable Power to collectively invest $650 million create a nationwide charging network for commercial electric vehicles. ^{431} They plan to start network construction in 2023 and by 2026 cover key routes on the East and West Coast and in Texas with a later stage of the project also supporting hydrogen fueling stations. DTNA is also working with the State of Michigan and DTE to develop a prototype truck stop charging station in Michigan that could serve as a model for broader truck stop deployment. ^{432} Volvo Group and Pilot recently announced their intent to offer public charging for medium- and heavy-duty BEVs at priority locations throughout the network of 750 Pilot and Flying J North American truck stops and travel plazas. ^{433} Tesla is developing charging equipment for their semi-trucks that will recharge up to 70 percent of the Tesla semi-truck's 500-mile range in 30 minutes. ^{434}
^{430} U.S. Department of Transportation, Federal Highway Administration. “Federal Highway Administrations' Charging and Fueling Infrastructure Discretionary Grants Program: FY 2022-FY 2023 Grant Selections”. Available online: https://highways.dot.gov/sites/fhwa.dot.gov/files/CFI%20Grant%20Awards%20Project%20Descriptions%20FY22-23.pdf.
^{431} NextEra Energy. News Release: “Daimler Truck North America, NextEra Energy Resources and BlackRock Renewable Power Announce Plans to Accelerate Public Charging Infrastructure for Commercial Vehicles Across The U.S.” January 31, 2022. Accessible online: https://newsroom.nexteraenergy.com/news-releases?item=123840.
^{432} Daimler Trucks North America Press Release. “State of Michigan partners with Daimler Truck North America and DTE Energy to build Michigan's `truck stop of the future.' ” June 29, 2023. Available online: https://northamerica.daimlertruck.com/pressdetail/state-of-michigan-partners-with-daimler-2023-06-29.
^{433} Adler, Alan. “Pilot and Volvo Group add to public electric charging projects”. FreightWaves. November 16, 2022. Available online: https://www.freightwaves.com/news/pilot-and-volvo-group-add-to-public-electric-charging-projects .
^{434} Tesla. “Semi: The Future of Trucking is Electric.” Available online: https://www.tesla.com/semi.
Other investments will support regional or local travel needs. For example, Forum Mobility announced a $400 million investment for 1,000 or more DCFCs for BEV trucks that are planned for operation at the San Pedro and Oakland ports. 435 436 Logistics and supply chain corporation NFI Industries is partnering with Electrify America to install 34 DCFC ports (150 kW and 350kW) to support their BEV drayage ^{437} fleet that will service the ports of LA and Long Beach. ^{438} With funding from California, Volvo is partnering with Shell Recharge Solutions and others to deploy five publicly accessible charging stations by 2023 that will serve medium- and heavy-duty BEVs in southern California between ports and industrial centers. ^{439}
^{435} As noted by the Joint Office of Energy and Transportation in a summary of recent private sector investments in charging infrastructure.
^{436} Joint Office of Energy and Transportation. “Private Sector Continues to Play Key Part in Accelerating Buildout of EV Charging Networks.” February 15, 2023. Available online: https://driveelectric.gov/news/private-innvestment.
^{437} Drayage trucks typically transport containers or goods a short distance from ports to distribution centers, rail facilities, or other nearby locations.
^{438} Electrify America. “Electrify America and NFI Industries Collaborate on Nation's Largest Heavy-Duty Electric Truck Charging Infrastructure Project.” August 31, 2021. Available online: https://media.electrifyamerica.com/en-us/releases/156 .
^{439} Borras, Jo. “Volvo Trucks Building an Electric Semi Charging Corridor”. CleanTechnica. July 16, 2022. Available online: https://cleantechnica.com/2022/07/16/volvo-trucks-building-an-electric-semi-charging-corridor/ .
States and utilities are also engaged. Seventeen states plus the District of Columbia (and the Canadian province Quebec) developed a “Multi-State Medium- and Heavy-Duty Zero-Emission Vehicle Action Plan,” which includes recommendations for planning for, and deploying, charging infrastructure. ^{440} California is investing $1.9 billion in state funding through 2027 in BEV charging and hydrogen fueling infrastructure (and related projects), including about one billion specific to infrastructure for trucks and buses. ^{441} The Edison Electric Institute estimates that electric companies are investing about $4 billion to advance charging infrastructure and fleets. ^{442} The National Electric Highway Coalition, a group that includes more than 60 electric companies and cooperatives that serve customers in 48 states and DC, ^{443} aims to provide fast charging along major highways in their service areas. Other utilities, like the Jacksonville Electric Authority (JEA), are supporting infrastructure through commercial electrification rebates. JEA is offering rebates of up to $30,000 for DCFC stations and up to $5,200 for Level 2 stations. ^{444} In the west, Nevada Energy was supporting fleets by offering rebates for up to 75 percent of the project costs for Level 2 ports and up to 50 percent of the project costs for DCFC stations (subject to caps and restrictions). 445 446 See generally RIA Chapter 1.6.2.
^{440} ZEV Task Force. “Multi-State Medium- and Heavy-Duty Zero-Emission Vehicle Action Plan: A Policy Framework to Eliminate Harmful Truck and Bus Emissions”. July 2022. Available online: https://www.nescaum.org/documents/multi-state-medium-and-heavy-duty-zev-action-plan-dual-page.pdf.
^{441} California Energy Commission. “CEC Approves $1.9 Billion Plan to Expand Zero-Emission Transportation Infrastructure”. February 14, 2024. Available online: https://www.energy.ca.gov/news/2024-02/cec-approves-19-billion-plan-expand-zero-emission-transportation-infrastructure.
^{442} Joint Office of Energy and Transportation. “Private Sector Continues to Play Key Part in Accelerating Buildout of EV Charging Networks.” February 15, 2023. Available online: https://driveelectric.gov/news/private-innvestment .
^{443} Edison Electric Institute. Issues & Policy: National Electric Highway Coalition. Available online: https://www.eei.org/en/issues-and-policy/national-electric-highway-coalition .
^{444} U.S. Department of Energy. Alternative Fuels Data Center. “Florida Laws and Incentives.” See Docket ID EPA-HQ-OAR-2022-0985-0290.
^{445} Level 2 rebates are applicable to fleets with between 2 and 10 ports, and subject to a $5,000/port cap. DCFC rebates are limited to 5 stations and are capped to the lesser of $400/kW or $40,000 per station.
^{446} U.S. Department of Energy. Alternative Fuels Data Center. “Commercial Electric Vehicle (EV) Charging Station Rebates—Nevada Energy (NV Energy).” (Note: the program ended in June 2023.) Available online: https://afdc.energy.gov/laws/12118 .
In sum, given the relatively low demand, ability to prioritize initial public charging deployment in discrete freight corridors, the extra lead time afforded for HDV applications projected to utilize public charging under the modeled potential compliance pathway, and the amount of public and private investment, EPA projects that the necessary public charging corresponding to the potential compliance pathway will be available within the lead time afforded by the HD Phase 3 final standards. We note further that we will continue to monitor the development of the HDV public charging infrastructure, as discussed in preamble section II.B.2.iii.

c. Associated Costs
The TEIS documents low overall financial impact associated with grid buildout. For 2027, the TEIS shows incremental distribution grid capital investment of $195 million for the unmanaged action scenario. When managed, that $195 million drops to $82 million. ^{447} For 2032, the TEIS shows incremental distribution grid capital investment of $2.3 billion for the unmanaged action scenario. When managed, the $2.3 billion drops to $1.6 billion. ^{448} The savings is driven by the reduction in peak incremental load achieved by the basic load management applied in this study. More effective load management is expected to be utilized in practice. ^{449} Incremental distribution grid investment to enable plug-in electric vehicle (PEV) charging ($2.3 billion across five states over 6 years assuming unmanaged charging) was found to be approximately 3 percent of existing utility distribution system investments (2027-2032). ^{450}
^{447} TEIS at Table ES-2.
^{448} TEIS at Table ES-2.
^{449} As noted in the previous section, the 5 state peak incremental load is increased 0.6% to 3.0% (Oklahoma and Illinois respectively) when unmanaged while the same increase is only 0.4% to 1.4% (same states) when managed. The total load is consistent across unmanaged and managed as the managed simply adjusts when the load is applied. The total incremental load is increased 1.6% to 2.7% (Oklahoma and California) as a result of the action case.
^{450} TEIS at 74.
We think this increase in distribution investment is modest and reasonable. Moreover, this value is conservative as it is inclusive of effects for both the light- and medium-duty vehicle standards and the heavy-duty Phase 3 rule and so overstates the amount of grid investment associated with the final rule, and as it does not reflect managed charging. The study finds that “[m]anaged charging techniques can decrease incremental distribution grid investment needs by 30 percent, illustrating the potential for significant cost savings by optimizing PEV charging and other loads at the local level.” ^{451} The managed charging practices analyzed in the TEIS are minimal and are characterized in the TEIS as “a conservative estimate of the benefits of managed charging.” ^{452} Given the very significant economic benefits of managed charging, we expect the market to adopt managed charging particularly under the influence of additional ZEV adoption associated with the modeled potential compliance pathway of the final rule.
^{451} TEIS at 76. PEV refers to Plug-in electric vehicles. Since the TEIS is considering effects of both rules, it includes plug-in hybrid vehicles as part of its analysis.
^{452} TEIS at 4.
We also estimated the impact on retail electricity prices based on the TEIS. The TEIS results were extrapolated to all IPM regions in order to estimate impacts on electricity rates using the Retail Price Model (see RIA Chapter 2.4.4.2). We modeled retail electricity rates in the no action case with unmanaged charging compared to the action case with managed charging. We think this is a reasonable approach for the reason just noted: ^{453} given the considerable economic benefits of managed charging, particularly in light of the increased PEV adoption associated with the modeled potential compliance pathway of the final rule, there is an extremely strong economic incentive for market actors to adopt managed charging practices. Our analysis projects that there is no difference in retail electricity prices in 2030 and the difference in 2055 is only 2.5 percent. ^{454} We estimate that the 2.5 percent difference is primarily due to distribution-level costs. Note also that this is comparable to the 3 percent increase in distribution-level investments estimated for the 5 states within the TEIS. ^{455}
^{453} Electricity demand in the action case was based on the interim control case described in RIA Chapter 4.2.4 for heavy-duty ZEVs and on Alternative 3 from the proposed “Multipollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles” for light- and medium-duty vehicles. This scenario was used in our modeling of charging costs in HD TRUCS, as described in RIA Chapter 2.4.4.2. The no action case described here is presented for comparative purposes, but was not utilized in our HD TRUCS modeling.
^{454} We note that had we compared an unmanaged action scenario with an unmanaged no-action scenario, or a managed action scenario with a managed no-action scenario, we would expect only marginally different electricity rates, given that distribution costs are a very small part of total electricity costs.
^{455} TEIS at 74.
A -3 percent increase in distribution system build out correlates to a small increase in manufacturing output so concerns regarding supply chain timing and cost are minimal. The total costs are modest both in and of themselves, as a percentage of grid investment even without considering mitigation strategies, and in terms of effect on electricity rates for users. EPA thus believes that the costs associated with distribution grid buildout attributable to the Phase 3 rule are reasonable. See further discussion in preamble section II.E.5.ii as to how we account for these costs in our analysis, and note further that the TEIS cost estimates are reflected in that analysis. See RIA Chapter 2.4.4.2. For a discussion of how we accounted for distribution upgrade costs in our final rule analysis, see preamble section II.E.5.ii and RIA Chapter 2.4.4.2.

d. Electricity Generation and, Transmission Reliability
As vehicle electrification load increases, alongside other new loads from data centers, industry, and building electrification, the grid will need to accommodate higher loads on generation and transmission (in addition to distribution buildout, which is already discussed). Our examination of the record, informed by our consultations with DOE, FERC, and other power sector stakeholders, is that the final standards of this rule, whether considered separately or in combination with the light and medium duty vehicle standards and upcoming power sector rules, are unlikely to adversely affect the reliability of the electric grid, and that widespread adoption of HD BEVs could have significant benefits for the electric power system.
In the balance of this section, we first provide an overview of the electric power system and grid reliability. We then discuss the impacts of this rule on generation. We find that the final rule, together with the light and medium duty rule, are associated with modest increases in electricity demand. We also conducted an analysis of resource adequacy, which is an important metric in North American Electric Reliability Corporation's (NERC) long-term reliability assessments. We find that the final rule, together with the light and medium duty rule as well as other EPA rules that regulate the EGU sector, are unlikely to adversely affect resource adequacy. We then discuss transmission and find that the need for new transmission lines associated with this rule and the light and medium duty rule between now and 2050 is projected to be very small, approximately one percent or less of transmission, and that nearly all of the additional buildout overlaps with existing transmission line right of ways. We find that this increase can reasonably be managed by the utility sector and project that transmission capacity will not constrain the increased demand for electricity associated with the final rule.
Our electric power system can be broken down into three subsystems: the electricity power generation, the electricity transmission network, and the electricity distribution grid. This review covers each of these subsystems in turn, beginning with generation. Electricity generation is currently reliable, with ample resource adequacy, and the power sector analysis conducted in support of this rule indicates that resource adequacy will continue to remain unaffected. In the NPRM, we modeled changes to power generation due to the increased electricity demand anticipated in the proposal as part of our upstream analysis. In the proposal, we concluded that grid reliability is not expected to be adversely affected by the modest increase in electricity demand associated with projected HD ZEV. 88 FR 25983. Several commenters stated that EPA had failed to account for the combined impact of various EPA rules when assessing the issue of grid reliability. These rules cited by commenters (many of which were proposed rules) include not only the proposed rule concerning emission standards for LDVs and MDVs, but also the proposed rule for CO 2 emissions from electricity generating units, the cross-state air pollution rule, the proposed rule for discharge to navigable waters for steam electric units (under the Clean Water Act), and the proposed rule to control leakage and other releases from of historic surface impoundments used to manage waste from coal combustion (under the Resource Conservation and Recovery Act). Other commenters agreed that the anticipated power needed for the HD Phase 3 rule is a relatively small share of the national electricity demand and that power generating capacity will not be a constraint. These comments came from the electric utility sector, from regulated entities themselves, from NGOs, and from affected states.
The electric power system in the U.S. has historically been a very reliable system, ^{456} with utilities, system planners, and reliability coordinators working together to ensure an efficient and reliable grid with adequate resources for supply to meet demand at all times, and we anticipate that this will continue in the future under these standards.
^{456} NREL, “Explained: Reliability of the Current Power Grid”, NREL/FS-6A40-87297, January 2024 ( https://www.nrel.gov/docs/fy24osti/87297.pdf ).
Power interruptions caused by extreme weather are the most-commonly reported, naturally-occurring factors affecting grid reliability, with the frequency of these severe weather events increasing significantly over the past twenty years due to climate change. ^{457} Conversely, decreasing emissions of greenhouse gases can be expected to help reduce future extreme weather events, which would serve to reduce the risks for electric power sector reliability. Extreme weather events include snowstorms, hurricanes, and wildfires. These power interruptions have significant impact on economic activity, with associated costs in the U.S. estimated to be $44 billion annually. ^{458} By requiring significant reductions in GHGs from new motor vehicles, this rule mitigates the harmful impacts of climate change, including the increased incidence of extreme weather events that affect grid reliability.
^{457} DOE, Electric Disturbance Events (OE-417) Annual Summaries for 2000 to 2023, https://www.oe.netl.doe.gov/OE417_annual_summary.aspx.
^{458} LaCommare, K.H., Eto, J.H., & Caswell, H.C. (2018, June). Distinguishing Among the Sources of Electric Service Interruptions. In 2018 IEEE International Conference on Probabilistic Methods Applied to Power Systems (PMAPS) (pp. 1-6). IEEE.
The average duration of annual electric power interruptions in the U.S., approximately two hours, decreased slightly from 2013 to 2021, when extreme weather events associated with climate change are excluded from reliability statistics. When extreme weather events associated with climate change are not excluded from reliability statistics, the national average length of annual electric power interruptions increased to about seven hours. ^{459}
^{459} EIA, U.S. electricity customers averaged seven hours of power interruptions in 2021, 2022, https://www.eia.gov/todayinenergy/detail.php?id=54639#.
Around 93 percent of all power interruptions in the U.S. occur at the distribution-level, with the remaining fraction of interruptions occurring at the transmission- and generation-levels. 460 461 As new light-duty PEV models continue to enter the U.S. market, they are demonstrating increasing capability for use as distributed grid energy resources. As of January 2024, manufacturers have introduced, or plan to introduce, 24 MYs 2024-2025 PEVs with bidirectional charging capable of supporting two to three days of residential electricity consumption. These PEVs have capability to discharge power on the order of 10 kW to residential loads or limited commercial loads. As more HD BEVs enter the market, BEVs with larger batteries and more power available will be available for bidirectional charging. Such a capability could be used to provide limited backup power to service stations providing petroleum fuels to emergency vehicles in response to a local disruption in electrical service. ^{462}
^{460} Eto, Joseph H, Kristina Hamachi LaCommare, Heidemarie C Caswell, and David Till. “Distribution system versus bulk power system: identifying the source of electric service interruptions in the US.” IET Generation, Transmission & Distribution 13.5 (2019) 717-723.
^{461} Larsen, P.H., LaCommare, K.H., Eto, J.H., & Sweeney, J.L. (2015). Assessing changes in the reliability of the US electric power system.
^{462} Mulfati, Justin. dcBel, “New year, new bidirectional cars: 2024 edition” January 15, 2024. Accessed March 10, 2024. Available at: https://www.dcbel.energy/blog/2024/01/15/new-year-new-bidirectional-cars-2024-edition/.
We now turn to the impacts of this rule on generation and resource adequacy. As discussed in Chapter 4 of the RIA and as part of our upstream analysis, we used MOVES to model changes to power generation due to the increased electricity demand anticipated under the final standards. Bulk generation and transmission system impacts are felt on a larger scale, and thus tend to reflect smoother load growth and be more predictable in nature. For a no action case, we project that generation will increase by 4.2 percent between 2028 and 2030 and by 36 percent between 2030 and 2050. Further, we project the additional generation needed to meet the projected demand of HD ZEVs from the final rule combined with our estimate of the light- and medium-duty PEVs under the light and medium duty multipollutant rule, to be relatively modest compared to a no action case, ranging from 0.93 percent in 2030 to approximately 12 percent in 2050 for both actions combined. Of that increased generation, approximately 16 percent in 2030 and approximately 34 percent in 2050 is due to heavy-duty ZEVs. Electric vehicle charging associated with the Action case (light- and medium-duty combined with heavy-duty) is expected to require 4 percent of the total electricity generated in 2030, which is slightly more than the increase in total U.S. electricity end-use consumption between 2021 and 2022. ^{463} This is also roughly equal to the combined latest U.S. annual electricity consumption estimates for data centers ^{464} and cryptocurrency mining operations, ^{465} both industries which have grown significantly in recent years and whose electricity demand the utility sector has capably managed. ^{466} EPA's assessment is that national power generation will continue to be sufficient as demand increases from electric vehicles associated with both the HD Phase 3 Rule and the light and medium duty rule.
^{463} U.S. Energy Information Agency, Use of Electricity, December 18, 2023. https://www.eia.gov/energyexplained/electricity/use-of-electricity.php.
^{464} U.S. DOE Office of Energy Efficiency and Renewable Energy, Data Centers and Servers ( https://www.energy.gov/eere/buildings/data-centers-and-servers ).
^{465} U.S. Energy Information Agency, Tracking Electricity Consumption From U.S. Cryptocurrency Mining Operations, February 1, 2024, ( https://www.eia.gov/todayinenergy/detail.php?id=61364 ).
^{466} As we noted at proposal, and as several commenters agreed, U.S. electric power utilities routinely upgrade the nation's electric power system to improve grid reliability and to meet new electric power demands. For example, when confronted with rapid adoption of air conditioners in the 1960s and 1970s, U.S. electric power utilities maintained reliability and met the new demand for electricity by planning and building upgrades to the electric power distribution system.
Given the additional electricity demand associated with increasing adoption of electric vehicles, some commenters raised concerns that the additional demand associated with the rule could impact the reliability of the power grid. ^{467} To further assess the impacts of this rule on grid reliability and resource adequacy, we conducted an additional grid reliability assessment of the impacts of the rule and how projected outcomes under the rule compare with projected baseline outcomes in the presence of the IRA. Because we recognize that this rule is being developed contemporaneously with the multipollutant emissions standards for light-duty passenger cars and light trucks and for Class 2b and 3 vehicles, which also is anticipated to increase demand for electricity, we analyzed the impacts of these two rules (the “Vehicle Rules”) on the grid together. EPA also considered several recently proposed rules related to the grid that may directly impact the EGU sector (which we refer to as “Power Sector Rules” ^{468} ).
^{467} EPA notes that manufacturers have a wide array of compliance options, as discussed in section II.F.4 of the preamble. For example, manufacturers could produce significantly fewer ZEVs than in the central case, or even no ZEVs beyond the no action baseline. Were manufacturers to choose these compliance pathways, the increasing in electricity demand associated with the rule would be smaller.
^{468} The recently proposed rules that we considered because they may impact the EGU sector (which we refer to as “Power Sector Rules”) include: the proposed Existing and Proposed Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generation Point Source Category (88 FR 18824) (“ELG Rule”), New Source Performance Standards for GHG Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired EGUs; Emission Guidelines for GHG emissions from Existing Fossil Fuel-Fired EGUs (88 FR 33240) (“111 EGU Rule”); and National Emissions Standards for Hazardous Air Pollutants: Coal-and Oil-Fired Electric Utility Steam Generating units Review of the Residual Risk and Technology Review (88 FR 24854) (“MATS RTR Rule”); EPA also considered all final rules affecting the EGU sector in the modeling for the Vehicle Rules. EPA also considered the impact of the proposed rule Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities (88 FR 31982 (May 18, 2023)). See RTC 7.1.
Specifically, we considered whether the Vehicles Rules alone and combined with the Power Sector Rules would result in anticipated power grid changes such that they (1) respect and remain within the confines of key National Electric Reliability Corporation (NERC) assumptions, ^{469} (2) are consistent with historical trends and empirical data, and (3) are consistent with goals, planning efforts and Integrated Resource Plans (IRPs) of industry itself. ^{470} We demonstrate that the effects of EPA's vehicle and power sector rules do not preclude the industry from meeting NERC resource adequacy criteria or otherwise adversely affect resource adequacy. This demonstration includes explicit modeling of the impacts of the Vehicle Rules, an additional quantitative analysis of the cumulative impacts of the Vehicles Rules and the Power Sector Rules, as well as a review of the existing institutions that maintain grid reliability and resource adequacy in the United States. We conclude that the Vehicles Rules, whether alone or combined with the Power Sector Rules, satisfy these criteria and are unlikely to adversely affect the power sector's ability to maintain resource adequacy or grid reliability.
^{469} NERC was designated by FERC as the Electric Reliability Organization (ERO) in 2005 and, therefore, is responsible for establishing and enforcing mandatory reliability standards for the North American bulk power system. Resource Adequacy Primer for State Regulators, 2021, National Association of Regulatory Utility Commissioners ( https://pubs.naruc.org/pub/752088A2-1866-DAAC-99FB-6EB5FEA73042 ).
^{470} Although this final rule was developed generally contemporaneously with the LMDV rule, the two rulemakings are separate and distinct. Since the LMDV rule was not complete as of the date of our analysis, we have been required to make certain assumptions for the purposes of this analysis to represent the results of that rule. Our analysis of the proposed Power Sector Rules is based on the modeling conducted for proposals. We believe this analysis is a reasonable way of accounting for the cumulative impacts of our rules affecting the EGU sector, including the proposed Power Sector Rules, at this time. Our cumulative analysis of the Vehicles and Power Sector Rules supports this final rule, and it does not reopen any of the Power Sector Rules, which are the subject of separate agency proceedings. Consistent with past practice, as subsequent rules are finalized, EPA will perform additional power sector modeling that accounts for the cumulative impacts of the rule being finalized together with existing final rules at that time.
Beginning with EPA's modeling of the Vehicle Rules, we used EPA's Integrated Planning Model (IPM), a model with built-in NERC resource adequacy constraints, to explicitly model the expected electric power sector impacts associated with the two vehicle rules. IPM is a state-of-the-art, peer-reviewed, multi-regional, dynamic, deterministic linear programming model of the contiguous U.S. electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, and emissions control strategies while meeting energy demand and environmental, transmission, dispatch, and resource adequacy constraints. IPM modeling we conducted for the Vehicle Rules includes in the baseline all final rules that may directly impact the power sector, including the final Good Neighbor Plan for the 2015 Ozone National Ambient Air Quality Standards (NAAQS), 88 FR 36654.
EPA has used IPM for over two decades, including for prior successfully implemented rulemakings, to better understand power sector behavior under future business-as-usual conditions and to evaluate the economic and emissions impacts of prospective environmental policies. The model is designed to reflect electricity markets as accurately as possible. EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis for the detailed power sector modeling in IPM. The model documentation provides additional information on the assumptions discussed here as well as all other model assumptions and inputs. EPA relied on the same model platform at final as it did at proposal, but made substantial updates to reflect public comments. Of particular relevance, the model framework relies on resource adequacy-related constraints that come directly from NERC. This includes NERC target reserve margins for each region, NERC Electricity Supply & Demand load factors, and the availability of each generator to serve load across a given year as reported by the NERC Generating Availability Data System. Note that unit-level availability constraints in IPM are informed by the average planned/unplanned outage hours for NERC Generating Availability Data System.
Therefore, the model projections for the Vehicle Rules are showing compliance pathways respecting these NERC resource adequacy criteria. These NERC resource adequacy criteria are standards by which FERC, NERC and the power sector industry judge that the grid is capable of meeting demand. Thus, we find that modeling results demonstrating that the grid will continue to operate within those resource adequacy criteria supports the conclusion that the rules will not have an adverse impact on resource adequacy, which is an essential element of grid reliability.
EPA also considered the cumulative impacts of the Vehicle Rules together with the Power Sector Rules, which, as noted, are several recent proposed rules regulating the EGU sector. In a given rulemaking, EPA does not generally analyze the impacts of other proposed rulemakings, because those rules are, by definition, not final and do not bind any regulated entities, and because the agency does not want to prejudge separate and ongoing rulemaking processes. However, some commenters on this rule expressed concern regarding the cumulative impacts of these rules when finalized, claiming that the agency's failure to analyze the cumulative impacts of the Vehicle Rules and its EGU-sector related rules rendered this rule arbitrary and capricious. In particular, commenters argued that renewable energy could not come online quickly enough to make up for generation lost due to fossil sources that may retire, and that this together the increasing demand associated with the Vehicle Rules would adversely affect resource adequacy and grid reliability. EPA conducted additional analysis of these cumulative impacts in response to these comments. Our analysis finds that the cumulative impacts of the Vehicle Rules and Power Sector Rules is associated with changes to the electric grid that are well within the range of fleet conditions that respect resource adequacy, as projected by multiple, highly respected peer-reviewed models. In other words, taking into consideration a wide range of potential impacts on the power sector as a result of the IRA and Power Sector Rules (including the potential for much higher variable renewable generation), as well the potential for increased demand for electricity from both this rule and the light and medium duty rule, EPA found that the Vehicle Rules and proposed Power Sector Rules are not expected to adversely affect resource adequacy and that EPA's rules will not inhibit the industry from its responsibility to maintain a grid capable of meeting demand without disruption.
Finally, we note the numerous existing and well-established institutional guardrails at the Federal- and state-level, as well as non-governmental organizations, which we expect to continue to maintain resource adequacy and grid reliability. These well-established institutions—including the Federal Energy Regulatory Commission (FERC), state Public Service Commissions (PSC), Public Utility Commissions (PUC), and state energy offices, as well as NERC and Regional Transmission Organization (RTO) and Independent System Operator (ISO)—have been in place for decades, during which time they have ensured the resource adequacy and reliability of the electric power sector. As such, we expect these institutions will continue to ensure that the electric power sector is safe and reliable, and that utilities will proactively plan for electric load growth associated with all future electricity demand, including those increases due to our final rule. We also expect that utilities will continue to collaborate with EGU owners to ensure that any EGU retirements will occur in an orderly and coordinated manner. We also note that EPA's proposed Power Sector rules include built-in flexibilities that accommodate a variety of compliance pathways and timing pathways, all of which helps to ensure the resource adequacy and grid reliability of the electric power system. ^{471} In sum, the power sector analysis conducted in support of this rule indicates that the Vehicle Rules, whether alone or combined with the Power Sector Rules, are unlikely to affect the power sector's ability to maintain resource adequacy and grid reliability. ^{472}
^{471} As noted, EPA is not prejudging the outcome of any of the Power Sector Rules.
^{472} See “Resource Adequacy Analysis Final Rule Technical Memorandum for Multi-Pollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles, and Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles—Phase 3,” available in the docket for this rulemaking.
EPA has studied the issue of grid reliability carefully and consulted with staff of DOE, FERC and the Electric Power Research Institute (EPRI) in reaching conclusions regarding bulk power system reliability and related issues. EPA's assessment is that national power generation will continue to be sufficient as demand increases from HD ZEVs as well as LD PEVs to the levels projected in the potential compliance pathways that support the feasibility of both final rules' standards while considering relevant electricity generation policy. EPA's assessment is supported by the quantified estimates from the utility industry, regulated entities, NGOs, and expert commenters, all of which corroborate EPA's conclusion and provide quantified estimates of minimal demand, which are quite similar to EPA's. ^{473}
^{473} Hibbard, Paul. “Heavy Duty Vehicle Electrification Planning for and Development of Needed Power System Infrastructure”. Analysis Group for EDF. June 2023. Available Online: https://blogs.edf.org/climate411/wp-content/blogs.dir/7/files/Analysis-Group-HDV-Charging-Impacts-Report.pdf.
A smaller number of commenters maintained that there could be shortages of electricity transmission capacity. We disagree. See RTC section 7.1. As described in that response, with respect to new transmission, the need for new transmission lines associated with the LMDV and HDP3 rules between now and 2050 is projected to be very small, approximately one percent or less of transmission. Nearly all of the projected new transmission builds appear to overlap with pre-existing transmission line right of ways (ROW), which makes the permitting process simpler. Approximately 41-percent of the potential new transmission line builds projected by IPM have already been independently publicly proposed by developers. The approximate regional distribution of the potential new transmission line builds are:
• 24 percent in the West (excluding Southern California), which are largely Federal lands, that are more-easily permittable for new transmission builds;
• 21 percent in the desert Southwest, which are largely Federal lands, that are more-easily permittable for new transmission builds;
• 14 percent in the Midwest;
• 9 percent for each of the Northeast, Mid-Atlantic, and Southeast and Mid-Atlantic regions; and
• 5 percent for each for Southern California and New York State/City regions. ^{474}
^{474} See Multi-Pollutant Emission Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Regulatory Impact Analysis at 5-22 (2024).
Other commenters pointed to recent regulatory actions approving several large-scale regional transmission expansions, plus actions by this Administration to expedite such expansions. DOE recently announced several programs and projects aimed at helping to alleviate the interconnection queue backlog, 475 476 including the Grid Resilience and Innovation Partnerships (GRIP) program, with $10.5 billion in Bipartisan Infrastructure Law funding to develop and deploy Grid Enhancing Technologies (GET). 477 478 479 FERC has issued various orders to address interconnection queue backlogs, improve certainty, and prevent undue discrimination for new technologies. 480 481 482 FERC Order 2023, for example, requires grid operators to adopt certain interconnection practices with the goal of reducing interconnection delays. These practices include a first-ready, first-served interconnection process that requires new generators to demonstrate commercial readiness to proceed, and a cluster study interconnection process that studies many new generators together. ^{483}
^{475} DOE Interconnection Innovation e-Xchange (i2X), https://www.energy.gov/eere/i2x/interconnection-innovation-e-xchange .
^{476} Abboud, A.W., Gentle, J.P., Bukowski, E.E., Culler, M.J., Meng, J.P., & Morash, S. (2022). A Guide to Case Studies of Grid Enhancing Technologies (No. INL/MIS-22-69711-Rev000). Idaho National Laboratory (INL), Idaho Falls, ID (United States).
^{477} Federal Energy Regulatory Commission, Implementation of Dynamic Line Ratings, Docket No. AD22-5-000 (87 FR 10349, February 24, 2022), https://www.federalregister.gov/documents/2022/02/24/2022-03911/implementation-of-dynamic-line-ratings .
^{478} DOE, Dynamic Line Rating, 2019, https://www.energy.gov/oe/articles/dynamic-line-rating-report-congress-june-2019 .
^{479} DOE, Advanced Transmission Technologies, 2020, https://www.energy.gov/oe/articles/advanced-transmission-technologies-report .
^{480} Federal Energy Regulatory Commission, Improvements to Generator Interconnection Procedures and Agreements, Docket No. RM22-14-000; Order No. 2023 (July 28, 2023), https://www.ferc.gov/media/e-1-order-2023-rm22-14-000 .
^{481} https://www.ferc.gov/news-events/news/staff-presentation-improvements-generator-interconnection-procedures-and.
^{482} FERC regulates interstate regional transmission planning and is currently finalizing a major rule to improve transmission planning. The rule would require that transmission operators do long term planning and would require transmission providers to work with states to develop a cost allocation formula, among other changes.
^{483} See generally FERC Order 1023, 184 FERC 61,054 (July 28, 2023) (Docket No. RM22-14-000).
Energy storage projects can also be used to help to reduce transmission line congestion and are seen as alternatives to transmission line construction in some cases. 484 485 These projects, known as Storage As Transmission Asset (SATA), ^{486} can help to reduce transmission line congestion, have smaller footprints, have shorter development, permitting, and construction times, and can be added incrementally, as required. Examples of SATA projects include the ERCOT Presidio Project, ^{487} a 4 MW battery system that improves power quality and reducing momentary outages due to voltage fluctuations, the APS Punkin Center, ^{488} a 2 MW, 8 MWh battery system deployed in place of upgrading 20 miles of transmission and distribution lines, the National Grid Nantucket Project, ^{489} a 6 MW, 48 MWh battery system installed on Nantucket Island, MA, as a contingency to undersea electric supply cables, and the Oakland Clean Energy Initiative Projects, ^{490} a 43.25 MW, 173 MWh energy storage project to replace fossil generation in the Bay area. Through such efforts, the interconnection queues can be reduced in length, transmission capacity on existing transmission lines can be increased, additional generation assets can be brought online, and electricity generated by existing assets will be curtailed less often. These factors help to improve overall grid reliability.
^{484} Federal Energy Regulatory Commission, Managing Transmission Line Ratings, Docket No. RM20-16-000; Order No. 881 (December 16, 2021), https://www.ferc.gov/media/e-1-rm20-16-000 .
^{485} Federal Energy Regulatory Commission, Staff Presentation Final Order Regarding Managing Transmission Line Ratings FERC Order 881 (December 16, 2021), https://www.ferc.gov/news-events/news/staff-presentation-final-order-regarding-managing-transmission-line-ratings .
^{486} Nguyen, T.A., & Byrne, R.H. (2020). Evaluation of Energy Storage As A Transmission Asset (No. SAND2020-9928C). Sandia National Lab. (SNL-NM), Albuquerque, NM (United States).
^{487} http://www.ettexas.com/Content/documents/NaSBatteryOverview.pdf.
^{488} Arizona Public Service Company, 2023 Integrated Resource Plan, https://www.aps.com/-/media/APS/APSCOM-PDFs/About/Our-Company/Doing-business-with-us/Resource-Planning-and-Management/APS_IRP_2023_PUBLIC.ashx .
^{489} Balducci, P.J., et al. (2019). Nantucket island energy storage system assessment (No. PNNL-28941). Pacific Northwest National Lab. (PNNL), Richland, WA (United States), https://energystorage.pnnl.gov/pdf/PNNL-28941.pdf.
^{490} https://www.pgecurrents.com/articles/2799-pg-e-proposes-two-energy-storage-projects-oakland-clean-energy-initiative-cpuc.
The previous sections cover grid reliability in the sense of adequacy and primarily address if the electricity generation and transmission subsystems can deliver the required power to the distribution subsystem. The ability of the distribution system to develop in a timely and cost effective manner and support what may be required for the HD Phase 3 and LMDV rules, is covered in section II.D.2.iii.a and iii.b of this preamble. Here, the issue of grid reliability and resilience assumes the required hardware is in place and assesses if that hardware will continue to deliver electricity with a high probability of success. Comments showed concern that the grid may not have adequate reliability due to severe storms, wildfires, and similar challenges. Commenters emphasized that without electricity supply, many HD BEV would not be able to deliver the work required.
We first note that most of these comments were general, posing potential issues of grid reliability unrelated to potential demand resulting from the HD Phase 3 standards. As noted, that demand is low and encompassable within the HD Phase 3 rule's time frame. In response to these general comments, we note that the U.S. electricity grid continues to be very reliable. Power interruptions caused by extreme weather are the most-commonly reported, naturally- occurring factors affecting grid reliability, ^{491} with the frequency of these severe weather events increasing significantly over the past twenty years due to climate change. ^{492} Conversely, decreasing emissions of greenhouse gases can be expected to avoid future extreme weather events, which would serve to increase electric power sector reliability. Extreme weather events include snowstorms, hurricanes, and wildfires. These power interruptions have significant impact on economic activity, with associated costs in the U.S. estimated to be $44 billion annually. ^{493}
^{491} DOE, Electric Disturbance Events (OE-417) Annual Summaries 2023, https://www.oe.netl.doe.gov/OE417_annual_summary.aspx .
^{492} DOE, Electric Disturbance Events (OE-417) Annual Summaries for 2000 to 2023, https://www.oe.netl.doe.gov/OE417_annual_summary.aspx .
^{493} LaCommare, K.H., Eto, J.H., & Caswell, H.C. (2018, June). Distinguishing Among the Sources of Electric Service Interruptions. In 2018 IEEE International Conference on Probabilistic Methods Applied to Power Systems (PMAPS) (pp. 1-6). IEEE.
The average duration of annual electric power interruptions in the U.S., approximately two hours, decreased slightly from 2013 to 2021, when extreme weather events associated with climate change are excluded from reliability statistics. When extreme weather events associated with climate change are not excluded from reliability statistics, the national average length of annual electric power interruptions increased to about seven hours. ^{494} Around 93 percent of all power interruptions in the U.S. occur at the distribution-level, with the remaining fraction of interruptions occurring at the generation- and transmission-levels. 495 496 We do not project the HD Phase 3 rule as having a significant effect on any of these trends given the low demand on the grid posed by the rule.
^{494} EIA, U.S. electricity customers averaged seven hours of power interruptions in 2021, 2022, https://www.eia.gov/todayinenergy/detail.php?id=54639# .
^{495} Eto, Joseph H, Kristina Hamachi LaCommare, Heidemarie C Caswell, and David Till. “Distribution system versus bulk power system: identifying the source of electric service interruptions in the US.” IET Generation, Transmission & Distribution 13.5 (2019) 717-723.
^{496} Larsen, P.H., LaCommare, K.H., Eto, J.H., & Sweeney, J.L. (2015). Assessing changes in the reliability of the U.S. electric power system.

3. HD Fuel Cell Electric Vehicle Technology and Supporting Infrastructure
Fuel cell technologies that run on hydrogen have been in existence for decades, though they are just starting to enter the heavy-duty transportation market. Hydrogen FCEVs are similar to BEVs in that they have batteries and use an electric motor instead of an internal combustion engine to power the wheels. Unlike BEVs that need to be plugged in to recharge, FCEVs have fuel cell stacks that use a chemical reaction involving hydrogen to generate electricity. Fuel cells with electric motors are more efficient than ICEs that run on gasoline or diesel, requiring less energy to fuel. ^{497}
^{497} U.S. Department of Energy, Alternative Fuels Data Center. “Hydrogen Basics”. Available online: https://afdc.energy.gov/fuels/hydrogen_basics.html.
Heavy-duty FCEVs are considered in the modeled potential compliance pathway due to several considerations. They do not emit air pollution at the tailpipe—only heat and pure water. ^{498} With current and near-future technologies, energy can be stored more densely onboard a vehicle as gaseous or liquid hydrogen than it can as electrons in a battery, which enables longer ranges. HD FCEVs can package more energy onboard with less weight than batteries in today's BEVs, which allows for their potential use in heavy-duty sectors that are difficult for BEV technologies due to payload impacts. HD FCEVs also have rapid refueling times. ^{499}
^{498} U.S. Department of Energy, Fuel Cell Technologies Office. “Fuel Cells”. November 2015. Available online: https://www.energy.gov/sites/prod/files/2015/11/f27/fcto_fuel_cells_fact_sheet.pdf.
^{499} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “The #H2IQ Hour: Heavy-Duty Vehicle Decarbonization”. September 21, 2023. Available online: https://www.energy.gov/sites/default/files/2023-10/h2iqhour-09212023.pdf.
In the following sections, and in RIA Chapter 1.7, we discuss key technology components unique to HD FCEVs.

i. Fuel Cell System
A fuel cell stack is a module that may contain hundreds of fuel cell units that generate electricity, typically combined in series. ^{500} A heavy-duty FCEV may have several fuel cell stacks to meet the power needs of a comparable ICE vehicle. A fuel cell system includes the fuel cell stacks and “balance of plant” (BOP) components ( e.g., pumps, sensors, compressors, humidifiers) that support fuel cell operations.
^{500} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “Fuel Cell Systems”. Available online: https://www.energy.gov/eere/fuelcells/fuel-cell-systems.
Though there are many types of fuel cell technologies, polymer electrolyte membrane (PEM) fuel cells are typically used in transportation applications because they offer high power density and therefore have low weight and volume. They can operate at relatively low temperatures, which allows them to start quickly. ^{501} PEM fuel cells are built using membrane electrode assemblies (MEA) and supportive hardware. The MEA includes the PEM electrolyte material, catalyst layers (anode and cathode), and gas diffusion layers. ^{502} Hydrogen fuel and oxygen enter the MEA and chemically react to generate electricity, which is either used to propel the vehicle or stored in a battery to meet future power needs. The process creates excess water vapor and heat.
^{501} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “Types of Fuel Cells”. Available online: https://www.energy.gov/eere/fuelcells/types-fuel-cells.
^{502} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “Parts of a Fuel Cell”. Available online: https://www.energy.gov/eere/fuelcells/parts-fuel-cell.
Key BOP components include the air supply system that provides oxygen, the hydrogen supply system, and the thermal management system. With the help of compressors and sensors, these components monitor and regulate the pressure and flow of the gases supplied to the fuel cell along with relative humidity and temperature. Similar to ICEs and batteries, PEM fuel cells require thermal management systems to control the operating temperatures. It is necessary to control operating temperatures to maintain stack voltage and the efficiency and performance of the system. There are different strategies to mitigate excess heat that comes from operating a fuel cell. For example, a HD vehicle may include a cooling system that circulates cooling fluid through the stack. ^{503} As the fuel cell ages and becomes less efficient, more waste heat will be generated that requires removal. A cooling system may be designed to accommodate end-of-life needs, which can be up to two times greater than they are at the beginning of life. ^{504} Waste heat recovery solutions are emerging. ^{505} The excess heat also can in turn be used to heat the cabin, similar to ICE vehicles. Power consumed to operate BOP components can also impact the fuel cell system's overall efficiency. 506 507
^{503} Hyfindr. “Fuel Cell Stack”. Available online: https://hyfindr.com/fuel-cell-stack/.
^{504} Pardhi, Shantanu, et. al. “A Review of Fuel Cell Powertrains for Long-Haul Heavy-Duty Vehicles: Technology, Hydrogen, Energy and Thermal Management Systems”. Energies 15(24). December 2022. Available online: https://www.mdpi.com/1996-1073/15/24/9557.
^{505} Baroutaji, Ahmad, et. al. “Advancements and prospects of thermal management and waste heat recovery of PEMFC”. Interational Journal of Thermofluids: Volume 9. February 2021. Available online: https://www.sciencedirect.com/science/article/pii/S2666202721000021.
^{506} Hoeflinger, Johannes and Peter Hofmann. “Air mass flow and pressure optimization of a PEM fuel cell range extender system”. International Journal of Hydrogen Energy. Volume 45:53. October 30, 2020. Available online: https://www.sciencedirect.com/science/article/pii/S0360319920327841.
^{507} Pardhi, Shantanu, et. al. “A Review of Fuel Cell Powertrains for Long-Haul Heavy-Duty Vehicles: Technology, Hydrogen, Energy and Thermal Management Systems”. Energies 15(24). December 2022. Available online: https://www.mdpi.com/1996-1073/15/24/9557.
To improve fuel cell performance, the air and hydrogen fuel that enter the system may be compressed, humidified, and/or filtered. ^{508} A fuel cell operates best when the air and the hydrogen are free of contaminants, since contaminants can poison and damage the catalyst. PEM fuel cells require hydrogen that is over 99 percent pure, which can add to the fuel production cost. 509 510 Hydrogen produced from natural gas tends to have more impurities initially ( e.g., carbon monoxide and ammonia, associated with the reforming of hydrocarbons) than hydrogen produced from water through electrolysis. ^{511} There are standards such as ISO 14687 that include hydrogen fuel quality specifications for use in vehicles to minimize impurities. ^{512}
^{508} U.S. Environmental Protection Agency. “Assessment of Fuel Cell Technologies at Ports”. Prepared for EPA by Eastern Research Group, Inc. EPA-420-R-22-013. July 2022. Available online: https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1015AQX.pdf.
^{509} Hyfindr. “Hydrogen PEM Fuel Cell”. Available online: https://hyfindr.com/pem-fuel-cell/ .
^{510} U.S. DRIVE Partnership. “Hydrogen Production Tech Team Roadmap”. U.S. Department of Energy. November 2017. Available online: https://www.energy.gov/eere/vehicles/articles/us-drive-hydrogen-production-technical-team-roadmap.
^{511} Nhuyen, Huu Linh, et. al. “Review of the Durability of Polymer Electrolyte Membrane Fuel Cell in Long-Term Operation: Main Influencing Parameters and Testing Protocols”. Energies 14(13). July 2021. Available online: https://www.mdpi.com/1996-1073/14/13/4048.
^{512} International Organization for Standardization. “ISO 14687: 2019, Hydrogen fuel quality—Product specification”. November 2019. Available online: https://www.iso.org/standard/69539.html.
Fuel cell durability is important in heavy-duty applications, given that vehicle owners and operators often have high expectations for drivetrain lifetimes in terms of years, hours, and miles. Fuel cells can be designed to meet durability needs ( i.e., the ability of the stack to maintain its performance over time). Considerations must be included in the design to accommodate operations in less-than-optimized conditions. For example, prolonged operation at high voltage (low power) or when there are multiple transitions between high and low voltage can stress the system. As a fuel cell system ages, a fuel cell's MEA materials can degrade, and performance and maximum power output can decline. The fuel cell can become less efficient, which can cause it to generate more excess heat and consume more fuel. ^{513} DOE's ultimate long-term technology target for Class 8 HD trucks is a fuel cell lifetime of 30,000 hours, corresponding to an expected vehicle lifetime of 1.2 million miles. ^{514} A voltage degradation of 10 percent at rated power ( i.e., the power level the cell is designed for) by end-of-life is considered by DOE when evaluating targets. ^{515}
^{513} Nhuyen, Huu Linh, et. al. “Review of the Durability of Polymer Electrolyte Membrane Fuel Cell in Long-Term Operation: Main Influencing Parameters and Testing Protocols”. Energies 14(13). July 2021. Available online: https://www.mdpi.com/1996-1073/14/13/4048.
^{514} Marcinkoski, Jason et. al. “Hydrogen Class 8 Long Haul Truck Targets”. U.S. Department of Energy. October 31, 2019. Available online: https://www.hydrogen.energy.gov/pdfs/19006_hydrogen_class8_long_haul_truck_targets.pdf.
^{515} Marcinkoski, Jason et. al. “Hydrogen Class 8 Long Haul Truck Targets”. U.S. Department of Energy. October 31, 2019. Available online: https://www.hydrogen.energy.gov/pdfs/19006_hydrogen_class8_long_haul_truck_targets.pdf.
Currently, the fuel cell stack is the most expensive component of a fuel cell system, ^{516} which is the most expensive part of a heavy-duty FCEV, primarily due to the technological requirements of manufacturing rather than raw material costs. ^{517} Larger production volumes are anticipated as global demand increases for fuel cell systems for HD vehicles, which could improve economies of scale. ^{518} Durability improvements are anticipated to also result in decreased operating costs, as they could extend the life of fuel cells and reduce the need for parts replacement. ^{519} Fuel cells contain PEM catalysts that typically are made using precious metals from the platinum group, which are expensive but efficient and can withstand conditions in a cell.
^{516} Papageorgopoulos, Dimitrios. “Fuel Cell Technologies Overview”. U.S. Department of Energy. June 6, 2023. Available online: https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/review23/fc000_papageorgopoulos_2023_o.pdf.
^{517} Deloitte China and Ballard. “Fueling the Future of Mobility: Hydrogen and fuel cell solutions for transportation, Volume 1”. 2020. Available online: https://www2.deloitte.com/content/dam/Deloitte/cn/Documents/finance/deloitte-cn-fueling-the-future-of-mobility-en-200101.pdf.
^{518} Deloitte China and Ballard. “Fueling the Future of Mobility: Hydrogen and fuel cell solutions for transportation, Volume 1”. 2020. Available online: https://www2.deloitte.com/content/dam/Deloitte/cn/Documents/finance/deloitte-cn-fueling-the-future-of-mobility-en-200101.pdf.
^{519} Deloitte China and Ballard. “Fueling the Future of Mobility: Hydrogen and fuel cell solutions for transportation, Volume 1”. 2020. Available online: https://www2.deloitte.com/content/dam/Deloitte/cn/Documents/finance/deloitte-cn-fueling-the-future-of-mobility-en-200101.pdf.
The U.S. Geological Survey's 2022 list of critical minerals includes platinum (as one of several platinum group metals, or PGMs), as used in catalytic converters. Critical minerals are defined in the Energy Act of 2020 as being essential to the economic or national security of the U.S. and vulnerable to supply chain disruption. ^{520} DOE's 2023 Critical Materials Assessment, performed independently from a global perspective and focused on the importance of materials to clean energy technologies in future years, identifies PGMs used in hydrogen electrolyzers such as platinum and iridium as critical. They screened out PGMs used in catalytic converters, such as rhodium and palladium. This distinction was made due to the increased focus on hydrogen technologies, including long-distance HD trucks, to achieve carbon emissions reductions, and an anticipated decrease in the importance of catalytic converters in the medium term ( i.e., the 2025 to 2035 timeframe). ^{521}
^{520} 87 FR 10381. “2022 Final List of Critical Minerals”. U.S. Geological Survey. February 24, 2022. Available online: https://www.federalregister.gov/documents/2022/02/24/2022-04027/2022-final-list-of-critical-minerals.
^{521} U.S. Department of Energy. “Critical Materials Assessment”. July 2023. Available online: https://www.energy.gov/sites/default/files/2023-07/doe-critical-material-assessment_07312023.pdf.
Efforts are underway to minimize or eliminate the use of platinum in catalysts. ^{522} DOE issued a Funding Opportunity Announcement (FOA) in 2023 in anticipation of growth in hydrogen and fuel cell technologies and systems. A portion of the FOA is designed to enable improvements in recovery and recycling, and applicants are encouraged to find ways to reduce or eliminate PGMs from catalysts in both PEM fuel cells and electrolyzers to reduce reliance on virgin feedstocks. ^{523}
^{522} Berkeley Lab. “Strategies for Reducing Platinum Waste in Fuel Cells. November 2021. Available online: https://als.lbl.gov/strategies-for-reducing-platinum-waste-in-fuel-cells/.
^{523} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “Bipartisan Infrastructure Law: Clean Hydrogen Electrolysis, Manufacturing, and Recycling: Funding Opportunity Announcement Number DE-FOA-0002922”. March 15, 2023 (Last Updated: March 31, 2023). Available online: https://eere-exchange.energy.gov/Default.aspx#FoaIda9a89bda-618a-4f13-83f4-9b9b418c04dc.

ii. Fuel Cell and Battery Interaction
The instantaneous power required to move a FCEV can come from either the fuel cell, the battery, or a combination of both. Interactions between the fuel cells and batteries of a FCEV can be complex and may vary based on application. Each manufacturer likely will employ a unique strategy to optimize the durability of these components and manage costs. The strategy selected will impact the size of the fuel cell and the size of the battery.
The fuel cell can be used to charge the battery that in turn powers the wheels ( i.e., series hybrid or range-extending), or it can work with the battery to provide power ( i.e., parallel hybrid or primary power) to the wheels. In the emerging HD FCEV market, when used to extend range, the fuel cell tends to have a lower peak power potential and may be sized to match the average power needed during a typical use cycle, including steady highway driving. At idle, the fuel cell may run at minimal power or turn off based on state of charge of the battery. The battery is used during prolonged high-power operations such as grade climbing and is typically in charge-sustaining mode, which means the average state of charge is maintained above a certain level while driving. When providing primary power, the fuel cell tends to have a larger peak power potential, sized to match all power needs of a typical duty cycle and to meet instantaneous power needs. The battery is mainly used to capture energy from regenerative braking and to help with acceleration and other transient power demands. ^{524}
^{524} Islam, Ehsan Sabri, Ram Vijayagopal, Aymeric Rousseau. “A Comprehensive Simulation Study to Evaluate Future Vehicle Energy and Cost Reduction Potential”, Report to the U.S. Department of Energy, Contract ANL/ESD-22/6. October 2022. See Full report. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/file/1406494585829.
Based on how the fuel cells and batteries are managed, manufacturers may use different types of batteries in HD FCEVs. Energy battery cells are typically used to store energy for applications with distance needs. Power battery cells are typically used to provide additional high power for applications with high power needs. ^{525}
^{525} Sharpe, Ben and Hussein Basma. “A Meta-Study of Purchase Costs for Zero-Emission Trucks”. International Council on Clean Transportation. February 2022. Available online: https://theicct.org/publication/purchase-cost-ze-trucks-feb22/.

iii. Onboard Hydrogen Storage Tanks
Fuel cell vehicles carry hydrogen fuel onboard using multiple large tanks. Hydrogen has high gravimetric density (amount of energy stored per unit of mass) but extremely low volumetric density (amount of energy stored per volume), so it must be compressed or liquified for use. There are various techniques for storing hydrogen onboard a vehicle, depending on how much fuel is needed to meet range requirements. Most transportation applications today use Type IV tanks, ^{526} which typically include a plastic liner wrapped with a composite material such as carbon fiber that can withstand high pressures with minimal weight. 527 528 High-strength carbon fiber accounts for over 50 percent of the cost of a Type IV onboard storage system at production volumes of over 100,000 systems per year. ^{529}
^{526} Type I-III tanks are not typically used in transportation for reasons related to low hydrogen density, metal embrittlement, weight, or cost.
^{527} Langmi, Henrietta et. al. “Hydrogen storage”. Electrochemical Power Sources: Fundamentals, Systems, and Applications. 2022. Portion available online: https://www.sciencedirect.com/topics/engineering/compressed-hydrogen-storage.
^{528} U.S. Department of Energy, Fuel Cell Technologies Office. “Hydrogen Storage”. March 2017. Available online: https://www.energy.gov/sites/prod/files/2017/03/f34/fcto-h2-storage-fact-sheet.pdf.
^{529} Houchins, Cassidy and Brian D. James. “2019 DOE Hydrogen and Fuel Cell Program Review: Hydrogen Storage Cost Analysis”. Strategic Analysis. May 2019. Available online: https://www.hydrogen.energy.gov/pdfs/review19/st100_james_2019_o.pdf.
Some existing fuel cell buses use compressed hydrogen gas at 350 bar (~5,000 pounds per square inch, or psi) of pressure, but other applications are using tanks with increased compressed hydrogen gas pressure at 700 bar (~10,000 psi) for extended driving range. ^{530} A Heavy-Duty Vehicle Industry Group was formed in 2019 to standardize 700 bar high-flow fueling hardware components globally that meet fueling speed requirements ( i.e., so that fill times are similar to comparable HD ICE vehicles, as identified in DOE technical targets for Class 8 long-haul tractor-trailers). ^{531} High-flow refueling rates for heavy-duty vehicles of 60 to 80 kg hydrogen in under 10 minutes were recently demonstrated in a DOE lab setting. 532 533 534
^{530} Basma, Hussein and Felipe Rodriquez. “Fuel cell electric tractor-trailers: Technology overview and fuel economy”. Working Paper 2022-23. International Council on Clean Transportation. July 2022. Available online: https://theicct.org/wp-content/uploads/2022/07/fuel-cell-tractor-trailer-tech-fuel-jul22.pdf.
^{531} NextEnergy. “Hydrogen Heavy Duty Vehicle Industry Group to Standardize Hydrogen Refueling, Bringing Hydrogen Closer to Wide Scale Adoption”. October 8, 2021. Available online: https://nextenergy.org/hydrogen-heavy-duty-vehicle-industry-group-partners-to-standardize-hydrogen-refueling/.
^{532} DOE suggests that 60 kg of H2 will be required to achieve a 750-mile range in a Class 8 tractor-trailer truck, assuming a fuel economy of 12.4 miles per kilogram. In the DOE lab, one fill (61.5 kg) was demonstrated from the fueling station into seven type-IV tanks of a HD vehicle simulator, and the second fill (75.9 kg) was demonstrated from the station into nine tanks.
^{533} Marcinkoski, Jason et. al. “Hydrogen Class 8 Long Haul Truck Targets”. U.S. Department of Energy. October 31, 2019. Available online: https://www.hydrogen.energy.gov/pdfs/19006_hydrogen_class8_long_haul_truck_targets.pdf.
^{534} Martineau, Rebecca. “Fast Flow Future for Heavy-Duty Hydrogen Trucks: Expanded Capabilities at NREL Demonstration High-Flow-Rate Hydrogen Fueling for Heavy-Duty Applications”. National Renewable Energy Lab. June 2022. Available online: https://www.nrel.gov/news/program/2022/fast-flow-future-heavy-duty-hydrogen-trucks.html.
As we stated in the NPRM, geometry and packaging challenges may constrain the amount of gaseous hydrogen that can be stored onboard and, thus, the maximum range of trucks that travel longer distances without a stop for fuel. ^{535} Liquid hydrogen is emerging as a cost-effective onboard storage option for long-haul operations; however, the technology readiness of liquid storage and refueling technologies is relatively low compared to compressed gas technologies. 536 537 Therefore, given our assessment of technology readiness, liquid storage tanks were not included in the potential compliance pathway that supports the feasibility and appropriateness of our standards.
^{535} Basma, Hussein and Felipe Rodriquez. “Fuel cell electric tractor-trailers: Technology overview and fuel economy”. Working Paper 2022-23. The International Council on Clean Transportation. July 2022. Available online: https://theicct.org/wp-content/uploads/2022/07/fuel-cell-tractor-trailer-tech-fuel-jul22.pdf.
^{536} Basma, Hussein and Felipe Rodriquez. “Fuel cell electric tractor-trailers: Technology overview and fuel economy”. Working Paper 2022-23. International Council on Clean Transportation. July 2022. Available online: https://theicct.org/wp-content/uploads/2022/07/fuel-cell-tractor-trailer-tech-fuel-jul22.pdf.
^{537} Gomez, Julian A. and Diogo M.F. Santos. “The Status of On-Board Hydrogen Storage in Fuel Cell Electric Vehicles”. Designs 2023: 7(4). Available online: https://www.mdpi.com/2411-9660/7/4/97.
In the NPRM, we requested comment and data related to packaging space availability associated with FCEVs and projections for the development and application of liquid hydrogen in the HD transportation sector over the next decade. 88 FR 25972. Only one comment was received on this issue, from a vehicle manufacturer, who stated that they believe liquid hydrogen is required to meet the packaging requirement for vehicles with a 500-mile range, consistent with our assessment at the proposal. The same commenter also included 90th percentile daily VMT estimates of 484 miles for Class 8 day cabs and 724 miles for sleeper cab tractors, based on an 18-day snapshot of telematics data, because they said they believe EPA is overestimating ZEV application suitability.
For the final rule, we contracted FEV Group to independently conduct a packaging analysis for Class 8 long-haul FCEVs that store 700-bar gaseous hydrogen onboard to see if space would be sufficient to accommodate hydrogen fuel for longer-range travel. ^{538} EPA conducted an external peer review of the final FEV report. FEV found ways to package six hydrogen tanks to deliver up to a 500-mile range with a sleeper cab using a 265-inch wheelbase. All tanks could be at the back of the cab in a zig-zag arrangement and the batteries mounted inside of the frame rails, or four of the tanks could be behind the cab with two tanks mounted to the outside of the frame rails under the cab and the batteries inside of the frame rails. This would allow a long-haul tractor to meet a daily operational VMT requirement of 420 miles. If a HD FCEV refuels once en route, then it could cover a 90th percentile VMT requirement of as far as 724 miles in a day (essentially matching the 90th percentile VMT noted by the commenter). A refueling event during the day should not be an unreasonable burden, given that refueling times are as short as 20 minutes or less (comparable to a diesel) and so are considered a key benefit of HD FCEVs. ^{539} See RTC section 5.3 for additional discussion.
^{538} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
^{539} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “The #H2IQ Hour. Today's Topic: Heavy-Duty Vehicle Decarbonization”. September 21, 2023. Available online: https://www.energy.gov/sites/default/files/2023-10/h2iqhour-09212023.pdf.
Based on our review of the literature for the NPRM and after consideration of the comments received and additional information, our assessment is that most HD vehicles have sufficient physical space to package gaseous hydrogen storage tanks onboard. ^{540} This remains the case for long-haul sleeper cabs if they refuel en route.
^{540} Kast, James et. al. “Designing hydrogen fuel cell electric trucks in a diverse medium and heavy duty market”. Research in Transportation Economics: Volume 70. October 2018. Available online: https://www.sciencedirect.com/science/article/pii/S0739885916301639.

iv. HD FCEV Safety Assessment
FCEVs have two potential risk factors that can be mitigated through proper design, process, and training: hydrogen and electricity. Electricity risks are identical to those of BEVs and, thus, are discussed in section II.D.2 and RIA Chapter 1.5.2. Hydrogen risks can occur throughout the process of fueling a vehicle. FCEVs must be designed so that hydrogen can be safely delivered to a vehicle and then transferred into a vehicle's onboard storage tanks and fuel cell stacks. Hydrogen has been handled, used, stored, and moved in industrial settings for more than 50 years, and there are many established methods for doing so safely. ^{541} There is also Federal oversight and regulation throughout the hydrogen supply chain system. ^{542} Safety training and education are key for maintaining reasonable risk while handling and using hydrogen. For example, hydrogen-related fuel cell vehicle risks can be mitigated by following various SAE and OSHA standards, as discussed in RIA Chapter 1.7.4.
^{541} Hydrogen Tools. “Best Practices Overview”. Pacific Northwest National Laboratory. Accessed on February 2, 2023. Available online: https://h2tools.org/bestpractices/best-practices-overview.
^{542} Baird, Austin R. et. al. “Federal Oversight of Hydrogen Systems”. Sandia National Laboratories. SAND2021-2955. March 2021. Available online: https://energy.sandia.gov/wp-content/uploads/2021/03/H2-Regulatory-Map-Report_SAND2021-2955.pdf.
We requested comment on our assessment that HD FCEVs can be designed to maintain safety. Two comments were received that questioned the safety of FCEV. One vehicle manufacturer commenter agreed that FCEVs will be designed to maintain safety. EPA's assessment at proposal was that HD FCEV systems must be, and are, designed to always maintain safe operation. EPA reiterates that conclusion here. As EPA explained at proposal, and as noted by the vehicle manufacturer commenter, there are industry codes and standards for the safe design and operation of HD FCEVs. The Hydrogen Industry Panel on Codes, International Code Council, and National Fire Protection Association work together to develop stringent standards for hydrogen systems and fuel cells. The FCEV codes and standards extend to service as well as emergency response. In addition, HD FCEVs are subject to, and necessarily comply with, the same Federal safety standards and the same safety testing as ICE heavy-duty vehicles. Commenters challenging the safety of HD FCEVs failed to address the existence of these protocols and Federal standards. EPA considers the multiple binding Federal safety standards and industry protocols to be effective and supports the conclusion that HD FCEV can be utilized safely. While considering safety for the NPRM, EPA coordinated with NHTSA. EPA additionally coordinated with NHTSA on safety regarding comments and updates for the final rulemaking. ^{543}
^{543} Landgraf, Michael. Memorandum to Docket EPA-HQ-OAR-2022-0985. Summary of NHTSA Safety Communication. February 2024.
Most if not all fuels, due to their nature of transporting energy, can do harm or be unsafe if not handled properly. Although hydrogen incidents (not with FCEVs) were provided in the comments, it is important to note that there has not been a FCEV accident due to leaking hydrogen. When compared to other fuels, hydrogen is nontoxic and lighter than air, so it quickly disperses upwards unlike gas vapors that stay at ground level and has a lower radiant heat so surrounding material is less likely to ignite. One commenter questioned FCEV safety in tunnels based on a modeling study. DOE is working with other authorities to evaluate safety in tunnels as discussed in RIA chapter 1.7.4. Additionally, FCEVs including their storage systems, like ICE vehicles, are required to meet the Federal Motor Vehicle Safety Standards (FMVSS) for crash safety so that the systems will maintain their integrity after the specified crash conditions. Additional FCEV safety information is available in RIA Chapter 1.7.4 and RTC section 4.9.

v. Assessment of Heavy-Duty Hydrogen Refueling Infrastructure
As FCEV adoption grows, more hydrogen refueling infrastructure will be needed to support the HD FCEV fleet. Infrastructure is required during the production, distribution, storage, and dispensing of hydrogen fuel.
Currently, DOE's Alternative Fuels Data Center (AFDC) lists 65 public retail hydrogen fueling stations in the United States, primarily for light-duty vehicles in California. ^{544} When including private, planned, and temporarily unavailable stations in a search, there are 99 refueling station locations nationwide. 545 546 547 There are also several nationally designated corridor-ready or corridor-pending Alternative Fueling Corridors for hydrogen. ^{548} Corridor-ready designations have a sufficient number of fueling stations to allow for corridor travel. The designation requires that public hydrogen stations be no greater than 150 miles apart and no greater than five miles off the highway. ^{549} Corridor-pending designations may have public stations separated by more than 150 miles, but stations cannot be greater than five miles off the highway. ^{550} The purpose of the Alternative Fuel Corridors program is to support the needed changes in the transportation sector that assists in reducing greenhouse gas emissions and improves the mobility of vehicles that employ alternative fuel technologies across the U.S. ^{551}
^{544} U.S. Department of Energy, Alternative Fuels Data Center. “Hydrogen Fueling Station Locations”. See Advanced Filters, Fuel, “Hydrogen” checked (not “include non-retail stations”). Accessed February 15, 2024. Available online: https://afdc.energy.gov/fuels/hydrogen_locations.html#/analyze?fuel=HY.
^{545} U.S. Department of Energy, Alternative Fuels Data Center. See Advanced Filters, Station, all “Access” and “Status” options checked. Accessed February 15, 2024. Available online: https://afdc.energy.gov/fuels/hydrogen_locations.html#/analyze?fuel=HY.
^{546} When including non-retail stations, there are 132. Non-retail stations involve special permissions from the original equipment manufacturers to fuel along with pre-authorization from the station provider.
^{547} U.S. Department of Transportation, Hydrogen and Fuel Cell Technologies Office. “Fact of the Month #18-01, January 29”. 2018. Available online: https://www.energy.gov/eere/fuelcells/fact-month-18-01-january-29-there-are-39-publicly-available-hydrogen-fueling.
^{548} U.S. Department of Transportation, Federal Highway Administration. HEPGIS. “Hydrogen (AFC Rounds 1-7)”. Accessed January 2024. Available online: https://hepgis-usdot.hub.arcgis.com/apps/e1552ac704284d30ba8e504e3649699a/explore.
^{549} U.S. Department of Transportation, Federal Highway Administration. “Memorandum, INFORMATION: Request for Nominations—Alternative Fuel Corridor (Round 7/2023)”. May 18, 2023. Available online: https://www.fhwa.dot.gov/environment/alternative_fuel_corridors/nominations/2023_request_for_nominations_r7.pdf.
^{550} U.S. Department of Transportation, Federal Highway Administration. “Alternative Fuel Corridors: Frequently Asked Questions FAST Act Section 1413—Alternative Fuel Corridor Designations Updated December 2020 to Support Round 5”. Available online: https://www.fhwa.dot.gov/environment/alternative_fuel_corridors/resources/faq/.
^{551} U.S. Department of Transportation, Federal Highway Administration. “Alternative Fuel Corridors”. Available online: https://www.fhwa.dot.gov/environment/alternative_fuel_corridors/.
Though few hydrogen refueling stations exist for HD FCEVs today, EPA has seen progress on the implementation of BIL and IRA funding and other provisions to incentivize the establishment of clean hydrogen supply chain infrastructure. In June 2021, DOE launched a Hydrogen Shot goal to reduce the cost of clean hydrogen production by 80 percent to $1 per kilogram in one decade. ^{552} In March 2023, DOE released a Pathways to Commercial Liftoff Report on “Clean Hydrogen” to catalyze more rapid and coordinated action across the full technology value chain. Since the NPRM, the Federal Government has continued to implement BIL and IRA commitments. In June 2023, the U.S. National Clean Hydrogen Strategy and Roadmap was finalized, informed by extensive industry and stakeholder feedback, setting forth an all-of-government approach for achieving large-scale production and use of hydrogen. It includes an assessment of the opportunity for hydrogen to contribute to national decarbonization goals across sectors over the next 30 years. ^{553} Also in June 2023, DOE updated Clean Hydrogen Production Standard (CHPS) guidance that establishes a target for lifecycle (defined as “well-to-gate”) GHG emissions associated with hydrogen production, accounting for multiple requirements within the BIL provisions. ^{554} In October 2023, DOE announced the selection of seven Regional Clean Hydrogen Hubs (H2Hubs) in different regions of the country that will receive a total of $7 billion to kickstart a national network of hydrogen producers, consumers, and connective infrastructure while supporting the production, storage, delivery, and end-use of hydrogen. The investment will be matched by recipients to leverage a total of nearly $50 billion for the hubs, which are expected to reduce 25 million metric tons of carbon dioxide emissions each year from end uses ranging from industrial steel to HD transportation. ^{555}
^{552} Satyapal, Sunita. “2022 AMR Plenary Session”. U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. June 6, 2022. Available online: https://www.energy.gov/sites/default/files/2022-06/hfto-amr-plenary-satyapal-2022-1.pdf.
^{553} U.S. Department of Energy. “U.S. National Clean Hydrogen Strategy and Roadmap”. June 2023. Available online: https://www.hydrogen.energy.gov/library/roadmaps-vision/clean-hydrogen-strategy-roadmap, https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/us-national-clean-hydrogen-strategy-roadmap.pdf.
^{554} U.S. Department of Energy, Hydrogen Program. “Clean Hydrogen Production Standard Guidance”. June 2023. Available online: https://www.hydrogen.energy.gov/library/policies-acts/clean-hydrogen-production-standard, https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/clean-hydrogen-production-standard-guidance.pdf.
^{555} U.S. Department of Energy. “Biden-Harris Administration Announces $7 Billion For America's First Clean Hydrogen Hubs, Driving Clean Manufacturing and Delivering New Economic Opportunities Nationwide”. October 13, 2023. Available online: https://www.energy.gov/articles/biden-harris-administration-announces-7-billion-americas-first-clean-hydrogen-hubs-driving.
Several programs initiated by BIL and IRA are under ongoing development. In March 2023, DOE announced $750 million for research, development, and demonstration efforts to reduce the cost of clean hydrogen. This is the first phase of $1.5 billion in BIL funding dedicated to advancing electrolysis technologies and improving manufacturing and recycling capabilities. In July 2023, DOE released a Notice of Intent to invest up to $1 billion in a demand-side initiative (to offer “demand pull”) to support the H2Hubs. ^{556} In January 2024, they selected a consortium to design and implement the program. ^{557} In December 2023, the Treasury Department and Internal Revenue Service proposed regulations to offer income tax credit of up to $3 per kg for the production of qualified clean hydrogen at a qualified clean hydrogen facility (often referred to as the production tax credit, PTC, or 45V), as established in the IRA. ^{558} Final program designs are expected after this rule is finalized. See section 8.1 of the RTC and Chapter 1.8 of the RIA for additional detail.
^{556} U.S. Department of Energy. “Biden-Harris Administration to Jumpstart Clean Hydrogen Economy with New Initiative to Provide Market Certainty and Unlock Private Investment”. July 5, 2023. Available online: https://www.energy.gov/articles/biden-harris-administration-jumpstart-clean-hydrogen-economy-new-initiative-provide-market.
^{557} U.S. Department of Energy, Office of Clean Energy Demonstrations. “DOE Selects Consortium to Bridge Early Demand for Clean Hydrogen, Providing Market Certainty and Unlocking Private Sector Investment”. January 14, 2024. Available online: https://www.energy.gov/oced/articles/doe-selects-consortium-bridge-early-demand-clean-hydrogen-providing-market-certainty.
^{558} 88 FR 89220. Section 45V Credit for Production of Clean Hydrogen; Section 48(a)(15) Election To Treat Clean Hydrogen Production Facilities as Energy Property. December 26, 2023. Available online: https://www.federalregister.gov/documents/2023/12/26/2023-28359/section-45v-credit-for-production-of-clean-hydrogen-section-48a15-election-to-treat-clean-hydrogen.
We received several comments on the topic of hydrogen infrastructure. Some commenters were optimistic and provided support for their view. One commenter acknowledged that producing HD FCEV trucks would incentivize the building of fueling stations. Another noted that DOE programs such as the 21st Century Truck Partnership are engaged in fuel cell and hydrogen work to reduce emissions from HD trucks. ^{559} At least two commenters recognized that Federal investment is expected to heavily influence the market. One commenter highlighted BIL and IRA incentives in addition to those referenced that will hasten buildout of HD FCEV refueling infrastructure, including $2.3 billion for a Port Infrastructure Development Program over five years (2022 to 2026). ^{560} The IRA also provided EPA with $3 billion to fund zero-emission port equipment and infrastructure and $1 billion to fund clean heavy-duty vehicles and supportive infrastructure, including hydrogen refueling infrastructure. 561 562 One commenter said they expect to see synergies between H2Hubs and FCEVs that can launch the market even before 2030. Others suggested that infrastructure may be more of a near-term challenge, or that uncertainty could diminish over time as ZEV technologies become increasingly affordable and ubiquitous.
^{559} U.S. Department of Energy. “U.S. National Clean Hydrogen Strategy and Roadmap”. June 2023. Available online: https://www.hydrogen.energy.gov/library/roadmaps-vision/clean-hydrogen-strategy-roadmap, https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/us-national-clean-hydrogen-strategy-roadmap.pdf.
^{560} U.S. Department of Transportation, Maritime Administration. “Port Infrastructure Development Program”. Available online: https://www.maritime.dot.gov/PIDPgrants.
^{561} U.S. Environmental Protection Agency. “Clean Ports Program”. Available online: https://www.epa.gov/ports-initiative/cleanports.
^{562} U.S. Environmental Protection Agency. “Clean Heavy-Duty Program”. Available online: https://www.epa.gov/inflation-reduction-act/clean-heavy-duty-vehicle-program.
At least two commenters agreed there is sufficient lead time. California, a state experienced in hydrogen refueling infrastructure, shared that LD stations take around two years to build on average. They expect similar construction times for HD stations, given that a hydrogen station for HD vehicles near the Port of Oakland is expected to move from approval to commissioning in just over two years, despite permitting challenges. They cited numerous entities developing mobile refueling solutions that could provide a fueling option “bridge” during the construction of permanent stations.
Other commenters were more cautious about the readiness and availability of hydrogen infrastructure. Several indicated there are few existing hydrogen refueling stations for HD FCEVs—mostly in California—and stated that it is overly optimistic and a massive undertaking to expect buildout of a national network by 2030. One commenter noted that hydrogen fueling infrastructure is still nascent compared to BEV charging infrastructure, and several identified challenges that still need to be addressed. Challenges raised by the commenter ranged from upstream emissions and energy required to produce hydrogen, to the cost-effectiveness of distributing and delivering hydrogen ( e.g., using gaseous or liquid technologies), to the inherent uncertainties associated with projecting emerging station needs in step with HD FCEV adoption timelines. At least one commenter suggested that we did not identify current private investment plans in the NPRM. In general, there was a sentiment from these commenters that more support for commercial facilities is necessary, and commenters urged Federal agencies to align resources and goals to ensure that buildout happens in a coordinated fashion and at a necessary pace.
Industry commenters anticipated lead time issues beyond their control. Several manufacturers suggested adjusting the standards in the case of unexpectedly slow infrastructure development, and there were calls to regularly evaluate infrastructure deployment and establish annual benchmarks for assessing progress.
In response to comments, we re-evaluated our assumptions about the retail price of hydrogen, in consultation with DOE, along with FCEV technology-related costs (see RIA Chapter 2.5). Our revised projections for HD FCEV adoption are based on relatively low production volumes in the MY 2030 to 2032 timeframe, indicative of an early market technology rollout. As a result, our hydrogen consumption estimates in the NPRM of about 830,000 metric tons of hydrogen per year in 2032 dropped in the final rule to about 130,000 metric tons of hydrogen per year by 2032, or 1.3 percent of current production. Our assessment is that early market buildout of a hydrogen refueling station network to support modest FCEV adoption levels in the modeled potential compliance pathway is feasible in the 2030 to 2032 timeframe. We are not suggesting that a full national hydrogen infrastructure network needs to be in place by 2030 or 2032, as implied by a few commenters, and specifically note that a full national hydrogen infrastructure network is not necessary to accommodate the demand that we posit for HD FCEVs in our modeled potential compliance pathway. This is further explained in RTC section 8.1.
In addition to the billions of dollars in Federal investment already referenced, RIA Chapter 1.7.5 includes information about known private investments in HD FCEVs and hydrogen infrastructure. According to Cipher's Clean Technology Tracker, as of September 2023, there is $45.752 billion in total clean hydrogen production project investment in the United States, ^{563} with 1 percent in projects that are in operation (close to $500,000), 7 percent ($3.2 million) under construction, and a majority still classified as announced. ^{564} DOE is tracking private sector announcements of domestic electrolyzers and fuel cell manufacturing facilities. So far, over $1.8 billion in new investments has been announced for over 10 new or expanded facilities with the capacity to manufacture approximately 10 GW of electrolyzers per year. ^{565} BIL and IRA programs are under ongoing development, but we anticipate that investment strategies ( e.g., that connect producers of hydrogen with end users of fuel) will amplify and become clearer in the near term. We also expect this rule will provide greater certainty to the market to support timely development of hydrogen refueling stations.
^{563} According to the Clean Technology Tracker, clean hydrogen production refers to the production of hydrogen fuel with proton exchange membrane (PEM) electrolyzers and solid oxide electrolyzer cells (SOEC) or through other methods such as methane pyrolysis and natural gas with carbon capture.
^{564} Cipher News. “Tracking a new era of climate solutions: Cleantech growth across the U.S.” Accessed February 2024. Available online: https://ciphernews.com/cleantech-tracker/#definitions.
^{565} U.S. Department of Energy. “Building America's Clean Energy Future—Hydrogen: Electrolyzers and Fuel Cells”. Accessed February 2024. Available online: https://www.energy.gov/invest.
Given that hydrogen refueling infrastructure for HD FCEVs is developing, we also reviewed literature that assesses hydrogen infrastructure needs for the HD transportation sector, as discussed further in RIA Chapter 1.8.3.5. The authors used differing analytical approaches and a large range of assumptions about the production, distribution and storage, and dispensing of hydrogen fuel to estimate hydrogen demand for HD FCEVs and the number of refueling stations required to meet that demand. Several papers examined infrastructure costs in the 2030 timeframe, as discussed further in Chapter 2.5.3.1. In general, the authors concluded that economies of scale are important to reduce costs throughout the supply chain. Most researchers of papers that we reviewed agree that it is not necessary to build a national infrastructure network for HD FCEVs all at once. Station financial prospects can vary by region and tend to be more favorable in areas with higher demand ( i.e., high energy needs from HD traffic flows), while station costs are anticipated to drop with growth in demand and related economies of scale. Similar to BEVs, as explained in RTC section 7.1, the infrastructure needed to meet this initial demand may be centered in a discrete sub-set of states and counties where freight activity is concentrated. Thus, the select vehicle applications for which we project FCEV adoption could start traveling within or between regional hubs in this timeframe where hydrogen development is prioritized initially.
Along these lines, in March 2024, the U.S. released a National Zero-Emission Freight Corridor Strategy ^{566} that “sets an actionable vision and comprehensive approach to accelerating the deployment of a world-class, zero-emission freight network across the United States by 2040. The strategy focuses on advancing the deployment of zero-emission medium- and heavy-duty vehicle (ZE-MHDV) fueling infrastructure by targeting public investment to amplify private sector momentum, focus utility and regulatory energy planning, align industry activity, and mobilize communities for clean transportation.” ^{567} The strategy has four phases. The first phase, from 2024-2027, focuses on establishing freight hubs defined “as a 100-mile to a 150-mile radius zone or geographic area centered around a point with a significant concentration of freight volume ( e.g., ports, intermodal facilities, and truck parking), that supports a broader ecosystem of freight activity throughout that zone.” ^{568} The second phase, from 2027-2030, will connect key ZEV hubs, building out infrastructure along several major highways. The third phase, from 2030-2045, will expand the corridors, “including access to charging and fueling to all coastal ports and their surrounding freight ecosystems for short-haul and regional operations.” ^{569} The fourth phase, from 2035-2040, will complete the freight corridor network. This corridor strategy provides further support for the development of HD ZEV infrastructure that corresponds to the modeled potential compliance pathway for meeting the final standards.
^{566} Joint Office of Energy and Transportation. “National Zero-Emission Freight Corridor Strategy” DOE/EE-2816 2024. March 2024. Available at https://driveelectric.gov/files/zef-corridor-strategy.pdf.
^{567} Joint Office of Energy and Transportation. “Biden-Harris Administration, Joint Office of Energy and Transportation Release Strategy to Accelerate Zero-Emission Freight Infrastructure Deployment.” March 12, 2024. Available online: https://driveelectric.gov/news/decarbonize-freight.
^{568} Joint Office of Energy and Transportation. “National Zero-Emission Freight Corridor Strategy” DOE/EE-2816 2024. March 2024. Available at https://driveelectric.gov/files/zef-corridor-strategy.pdf. See page 3.
^{569} Joint Office of Energy and Transportation. “National Zero-Emission Freight Corridor Strategy” DOE/EE-2816 2024. March 2024. Available at https://driveelectric.gov/files/zef-corridor-strategy.pdf. See page 8.
The literature also further supports that there is sufficient lead time. Fulton et. al. noted that heavy-duty refueling station funding, design, and planning should start one to two years before deployment. ^{570} The Coordinating Research Council noted that full station development ( i.e., design, permitting, construction, and commissioning) takes about two years, assuming no major hurdles. ^{571} The California Energy Commission has evaluated hydrogen refueling station development in California since 2010. Their planned network of 200 stations is mainly for light-duty vehicles but has at least 13 stations with the capability to serve HD FCEVs. ^{572} Station development times have generally decreased over time, from a median or typical time spent of around 1,500 days in 2010 to about 500 days in 2019 ( i.e., about two years if considering business days) for projects that have completed all phases of development. ^{573} They expect some increase in median development times as projects delayed by the COVID-19 pandemic are completed but regularly monitor progress and work to improve the deployment process. ^{574}
^{570} Fulton, et. al. “California Hydrogen Analysis Project: The Future Role of Hydrogen in a Carbon-Neutral California—Final Synthesis Modeling Report”. UC Davis Institute of Transportation Studies. April 19, 2023. Available online: https://escholarship.org/uc/item/27m7g841.
^{571} Coordinating Research Council, Inc. “Assess the Battery-Recharging and Hydrogen-Refueling Infrastructure Needs, Costs, and Timelines Required to Support Regulatory Requirements for Light-, Medium-, and Heavy-Duty Zero-Emission Vehicles: Final Report”. Prepared by ICF. CRC Report No. SM-CR-9. September 2023. Available online: https://crcao.org/wp-content/uploads/2023/09/CRC_Infrastructure_Assessment_Report_ICF_09282023_Final-Report.pdf.
^{572} The CEC has invested nearly $40 million in medium- and heavy-duty hydrogen infrastructure.
^{573} Berner, et al. “Joint Agency Staff Report on Assembly Bill 8: 2022 Annual Assessment of Time and Cost Needed to Attain 100 Hydrogen Refueling Stations in California”. California Energy Commission & California Air Resources Board. December 2022. Available online: https://www.energy.ca.gov/sites/default/files/2022-12/CEC-600-2022-064.pdf.
^{574} Berner, et al. “Joint Agency Staff Report on Assembly Bill 8: 2022 Annual Assessment of Time and Cost Needed to Attain 100 Hydrogen Refueling Stations in California”. California Energy Commission & California Air Resources Board. December 2022. Available online: https://www.energy.ca.gov/sites/default/files/2022-12/CEC-600-2022-064.pdf.
We recognize that these plans will require sustained support to come to fruition, and our assessment, in consultation with relevant Federal agencies, is that our projections are supported and correspond to our measured approach in our modeled compliance pathway for FCEVs. There are many complex factors at play, and we have taken a close look at how the ramp-up period over the next decade is critical. In our modeled potential compliance pathway, we evaluated the existing and projected future hydrogen refueling infrastructure and considered FCEVs only in the MY 2030 and later timeframe to better ensure that our compliance pathway provides adequate time for early market infrastructure development. We conclude that a phased and targeted approach can offer sufficient lead time to meet the projected refueling needs that correspond to the technology packages for the final rule's modeled potential compliance pathway, as further discussed in RIA Chapter 2.1. Additionally, EPA is committed to ensuring the Phase 3 program is successfully implemented, and as described in preamble section II.B.2.iii, in consideration of concerns raised regarding inherent uncertainties about the future, we are including a commitment to monitor progress on hydrogen refueling infrastructure development in the final rule.

4. Summary of Technology Assessment
In prior HD GHG rulemakings, EPA promulgated standards that could feasibly be met through technological improvements in many areas of the vehicle. For example, as discussed in section II.C, the HD GHG Phase 2 CO 2 emission standards were premised on technologies such as engine improvements, advanced transmissions, advanced aerodynamics and, in some cases, hybrid powertrains. We evaluated each technology's effectiveness as demonstrated over the regulatory duty cycles using EPA's GEM and estimated the appropriate projected adoption rate of each technology. ^{575} We then developed a technology package for each of the regulatory subcategories, which represented a potential compliance pathway to support the feasibility of the Phase 2 standards. We are following a similar approach in this Phase 3 final rule.
^{575} GEM is an EPA vehicle simulation tool used to certify HD vehicles. A detailed description of GEM can be found in the RIA for the HD GHG Phase 2 rulemaking, available at https://nepis.epa.gov/Exe/ZyPDF.cgi/P100P7NS.PDF?Dockey=P100P7NS.PDF.
In the HD GHG Phase 2 final rule, we included ZEV technologies in our assessment of the suite of technologies for HD vocational vehicles and tractors. However, in 2016, when the HD GHG Phase 2 rule was being developed, we stated that “adoption rates for these advanced technologies in heavy-duty vehicles are essentially non-existent today and seem unlikely to grow significantly within the next decade without additional incentives.” ^{576} Thus, at that time, instead of including ZEV technologies in the technology packages for setting the Phase 2 standards, we provided advanced technology credit multipliers to help incentivize the development of such technologies, as well as PHEVs, because they had the potential for very large GHG emission reductions.
^{576} 81 FR 73498 (October 25, 2016).
Since the 2016 promulgation of the HD GHG Phase 2 final rule, as discussed in section I.C of this preamble, several important factors have contributed to changes in the HD landscape. Therefore, as detailed in this section II and RIA Chapter 2, our assessment concludes that ICE technologies, BEV technologies and FCEV technologies will be technically feasible for HD motor vehicles, as assessed by vehicle type and each Phase 3 MY. Similar to Phase 1 and Phase 2, the technology packages used to support the feasibility of the standards in this final rule include a mix of technologies applied to HD motor vehicles, and development of those technology packages included an assessment of the projected feasibility of the development and application of BEV, FCEV, and other technologies that reduce GHG emissions from HD ICE vehicles. While our analysis in this section II.D focuses on certain technologies in the technology packages as a potential compliance pathway to support the feasibility of the final HD vehicle GHG emission standards, there are other technologies that can reduce CO 2 emissions and other example potential compliance pathways to meet the standards as discussed in RIA Chapters 1 and 2.11 and section II.F.4. Under the final rule, manufacturers may choose to utilize the technologies that work best for their business case and for the operator's needs in meeting the final standards. We reiterate that the standards are performance-based and do not mandate any specific technology for any manufacturer or any vehicle subcategory.
The range of GHG emission-reducing technologies for HD vehicles considered in this final rulemaking include those for HD vehicles with ICE (section II.D.1), HD BEVs (section II.D.2), and HD FCEVs (section II.D.3). For evaluating the BEV and FCEV technologies portion of the range for this analysis, for this rulemaking EPA developed a bottom-up approach to estimate the operational characteristics and costs of such technologies. As explained in the NPRM, we developed a new technology assessment tool, Heavy-Duty Technology Resource Use Case Scenario (HD TRUCS), to evaluate the design features needed to meet the energy and power demands of HD vehicle types when using different technologies, and comparing resulting manufacturing, operating and purchasing costs. In this rulemaking, we used HD TRUCS to assess the design features to meet the power and energy demands of various HD vehicles when using ZEV technologies, as well as costs related to manufacturing, purchasing and operating ICE vehicle and ZEV technologies. We chose to analyze the comparison with ZEV technologies for the modeled potential compliance pathway as the technology capable of achieving the greatest vehicle GHG emission reductions. Furthermore, we made a number of updates to HD TRUCS for the final rulemaking to reflect consideration of new information, including that received in comments. HD TRUCS is described in more detail in section II.D.5 and RIA Chapter 2, but we briefly summarize the approach here.
To use HD TRUCS as part of building the technology packages to support the feasibility of the standards, we created 101 representative HD vehicles that cover the full range of weight classes within the scope of this rulemaking (Class 2b through 8 vocational vehicles and tractors). The representative vehicles cover many aspects of work performed by HDVs. This work was translated into energy and power demands per vehicle type based on everyday use of HD vehicles, ranging from moving goods and people to mixing cement. We then identified the technical properties required for a BEV or FCEV to meet the operational needs of a comparable ICE vehicle. ^{577}
^{577} Heavy-duty vehicles are typically powered by a diesel-fueled compression-ignition (CI) engine, though the heavy-duty market includes vehicles powered by gasoline-fueled spark-ignition (SI) engines and alternative-fueled ICEs. We selected diesel-powered ICE vehicles as the baseline vehicle for the assessment in HD TRUCS in our analysis because a diesel-fueled CI engine is broadly available for all of the 101 vehicle types.
Since batteries can add weight and volume to a vehicle, ^{578} we evaluated battery mass and physical volume required to package a battery pack. If the performance needs of a BEV resulted in a battery that was too large or heavy, then we did not consider the BEV for that application in our technology package because of, for example, the impact on payload and, thus, potential work accomplished relative to a comparable ICE vehicle. ^{579}
^{578} Smith, David et. al. “Medium- and Heavy-Duty Vehicle Electrification: An Assessment of Technology and Knowledge Gaps”. U.S. Department of Energy: Oak Ridge National Laboratory and National Renewable Energy Laboratory. December 2019. Available online: https://info.ornl.gov/sites/publications/Files/Pub136575.pdf.
^{579} This does not necessarily mean that a BEV with a large battery weight and volume would not be technically feasible for a given HD vehicle use, but rather this is an acknowledgement that we considered impacts of increased battery size on feasibility considerations like payload capacity as well as cost and payback within the selection of HD vehicle technologies for the technology packages.
To evaluate costs for these technologies, including costs of compliance for manufacturers using this compliance pathway as well as user costs related to purchasing and operating ZEVs, we sized vehicle components that are unique to ZEVs to meet the work demands of each representative vehicle. We applied cost estimates to each vehicle component based on sizing to assess the difference in total powertrain costs between the ICE and ZEV powertrains. We accounted for the IRA battery tax credit and vehicle tax credit, as discussed in section II.E.4. We also compared operating costs due to fuel consumption, vehicle maintenance and repair, and insurance. We also included the upfront cost to procure and install depot charging infrastructure for certain BEVs. Costs of the needed distribution grid buildout infrastructure are reflected in the per kilowatt hour price of electricity used for both depot and public charging. For the BEVs where we project their charging needs will be met by public charging, instead of including the charging infrastructure costs upfront, we included these amortized costs in the charging cost in addition to the cost of electricity, demand charges, and EVSE maintenance costs. We took a similar approach for FCEVs, where we embedded the hydrogen infrastructure costs into the cost of hydrogen fuel. This approach is consistent with our assessment of fueling costs associated with ICE vehicles where the fuel station infrastructure costs are included in the per gallon price of fuel.
We relied on research and findings discussed in RIA Chapters 1 and 2 to conduct this analysis. For MYs 2027 through 2029, for the BEV and FCEV technologies portions of the analysis, we focused primarily on BEV technology using depot charging. Consistent with our analysis, research shows that some BEV technologies can become cost-competitive in terms of total cost of ownership for many HD vehicles by the late 2020s, but it will take longer for FCEVs. 580 581 582 Given that there are more BEV models available today compared to FCEV models (see, e.g., RIA Chapters 1.7.5 and 1.7.6), we project in our technology packages that BEV technology adoption is likely to happen sooner than the adoption of FCEV technology. Also, as discussed in RIA Chapter 1.6, we project that depot charging will occur at a faster rate than the development of a HD public charging network. Therefore, the modeled potential compliance pathway focuses on these types of BEVs in the initial Phase 3 MYs.
^{580} Ledna et. al. “Decarbonizing Medium- & Heavy-Duty On-Road Vehicles: Zero-Emission Vehicles Cost Analysis”. U.S. Department of Energy, National Renewable Energy Laboratory. March 2022. Available online: https://www.nrel.gov/docs/fy22osti/82081.pdf.
^{581} Hall, Dale and Nic Lutsey. “Estimating the Infrastructure Needs and Costs for the Launch of Zero-Emission Trucks”. White Paper: The International Council on Clean Transportation. August 2019. Available online: https://theicct.org/wp-content/uploads/2021/06/ICCT_EV_HDVs_Infrastructure_20190809.pdf.
^{582} Robo, Ellen and Dave Seamonds. Technical Memo to Environmental Defense Fund: Investment Reduction Act Supplemental Assessment: Analysis of Alternative Medium- and Heavy-Duty Zero-Emission Vehicle Business-As-Usual Scenarios. ERM. August 19, 2022. Available online: https://www.erm.com/contentassets/154d08e0d0674752925cd82c66b3e2b1/edf-zev-baseline-technical-memo-addendum.pdf.
Starting in MY 2030, we also considered FCEV technology using public refueling infrastructure and BEVs using public charging for select applications in our modeled compliance pathway and H2-ICE using public refueling infrastructure in our additional example potential compliance pathways. BEV technology is more energy efficient than FCEV technology but may not be suitable for all applications during the model years at issue in this rulemaking, such as when the performance needs result in additional battery mass that prohibitively affects payload. In cases like this, the pathway considered either BEVs with smaller batteries, that may require enroute charging and the consequent use of public charging away from the depot, or FCEVs, which may have shorter refueling times than BEVs with large batteries. 583 584 We considered FCEVs and BEVs using public charging in the technology packages for applications that travel longer distances and/or carry heavier loads ( i.e., for those that may be sensitive to refueling times or payload impacts). These included some coach buses and tractors.
^{583} A technology is more energy efficient if it uses less energy to do the same amount of work. Energy can be lost as it moves through the vehicle's components due to heat and friction.
^{584} Cunanan, Carlo et. al. “A Review of Heavy-Duty Vehicle Powertrain Technologies: Diesel Engine Vehicles, Battery Electric Vehicles, and Hydrogen Fuel Cell Electric Vehicles”. Clean Technol. Available online: https://www.mdpi.com/2571-8797/3/2/28.
After considering operational characteristics and costs in 2022$, for the BEV and FCEV technologies portions of the analysis, we determined the payback period, which is the number of years it would take to offset any incremental cost increase of a ZEV over a comparable ICE vehicle. Next, the inclusion of BEV and FCEV technologies in the technology packages as a potential compliance pathway that support the feasibility of the final standards was determined after considering the payback period for BEVs or FCEVs.
Lastly, the modeled potential compliance pathway that supports the final standards is a combination of the ICE vehicle technologies described in section II.D.1 along with BEV and FCEV technologies. As stated in section II.D.1 of this preamble, for the ICE vehicle technologies part of the analysis that supports the feasibility of the Phase 3 standards, our assessment is that the technology packages for the modeled potential compliance pathway include a mix of ICE vehicle technologies and adoption rates of those technologies at the levels included in the Phase 2 MY 2027 technology packages. Additionally, for the additional example potential compliance pathways that support the feasibility of the Phase 3 standards, our assessment is that those technology packages include a mix of vehicles with ICE technologies described in section II.D.1 and further discussed in section II.F.4 and adoption rates of those technologies at the levels described in section II.F.4.

5. EPA's HD TRUCS Analysis Tool
For the final rule, EPA further refined HD TRUCS, which (as just noted) was developed by EPA to evaluate the design features needed to meet the energy and power demands of various HD vehicle types when using ZEV technologies. We did this by sizing the BEV and FCEV components such that they could meet the driving demands based (in most instances) on the 90th percentile daily VMT for each application, while also accounting for the heating, ventilation, and air conditioning (HVAC) and battery thermal conditioning load requirements in hot and cold weather and any PTO demands for the vehicle. Furthermore, we accounted for the fact that the usable battery capacity is less than 100 percent and that batteries deteriorate over time. We also sized the ZEV powertrains to ensure that the vehicles would meet an acceptable level of acceleration from a stop and be able to maintain a cruise speed while going up a hill at six-percent grade. In this subsection, we discuss the primary inputs used in HD TRUCS along with the revisions made for the tool used in this final rulemaking. Additional details on HD TRUCS can be found in RIA Chapter 2. We received numerous comments on our approach to HD TRUCS; some key topic themes include, but are not limited to, vehicle sales distribution, battery sizing method, component efficiencies and costs, additional operating costs, EVSE costs and dwell time, payback curve, alternative sources for inputs and the feasibility of ZEVs. We also addressed the minor errors in inputs for a few of the 101 vehicles noted by one commenter.

i. Vehicles Analyzed
The version of HD TRUCS supporting this final rule continues to analyze 101 vehicle types. However, we refined certain inputs based on consideration of comments received. The 101 vehicle types encompass 22 different applications in the HD vehicle market, as shown in Table II-10. These vehicles applications are further differentiated by weight class, duty cycle, and daily VMT for each of these vehicle applications into 101 vehicle types. These 101 vehicle types cover all 33 of the heavy-duty regulatory subcategories, as shown in RIA Chapter 2.8.3.1. As explained at proposal, 88 FR 25974, the initial list of HD TRUCS vehicles contained 87 vehicle types and was based on work the Truck and Engine Manufacturers Association (EMA) and CARB conducted for CARB's ACT rule. ^{585} For the NPRM, we consolidated the list; eliminated some of the more unique vehicles with small populations like mobile laboratories; and assigned operational characteristics for vocational vehicles that correspond to the Urban, Multi-Purpose, and Regional duty cycles used in GEM. We also added additional vehicle types to reflect vehicle applications that were represented in EPA's certification data. Chapter 2.1 of the RIA summarizes the 101 unique vehicle types represented in HD TRUCS and each with a vehicle identifier, along with their corresponding regulatory subcategory, vehicle application, vehicle weight class, MOVES SourceTypeID and RegClassID, ^{586} and GEM duty cycle category. After considering comments, we revised several HD vehicles to increase the number of day cab vehicle types and sleeper cab vehicle types within the final rule version of HD TRUCS to include four day cabs vehicle types and three sleeper cabs vehicle types that are modeled in our analysis to use public charging, starting in MY 2030. In addition, of the tractors vehicle types that were designed for public charging one day cab and one sleeper cab were updated to reflect a more aerodynamic tractor design than the average tractor aerodynamics used in the technology assessment to support the Phase 2 standards. See RIA 2.2.2.1 for additional details.
^{585} California Air Resources Board, Appendix E: Zero Emission Truck Market Assessment (2019), available at
https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2019/act2019/appe.pdf (last accessed on September 26, 2022).
^{586} MOVES homepage: https://www.epa.gov/moves (last accessed October 2022).
Heavy-duty vehicles are typically powered by a diesel-fueled CI engine, though the heavy-duty market also includes vehicles powered by gasoline-fueled SI engines and alternative-fueled ICE. We selected diesel-powered ICE vehicles as the baseline vehicle for the assessment in HD TRUCS in our analysis because a diesel-fueled CI engine is broadly available for all of the 101 vehicle types and is more efficient than an SI engine. Chapter 2.2 of the RIA includes the details we developed for each of the baseline vehicles, including the size of the engine and the transmission type. This information was used to determine the weight and the cost of the ICE powertrains.
As noted, in the ZEV technologies portion of our analysis for our projected technology packages, for MYs 2027 through 2029, we primarily considered BEV technologies using depot charging. Starting in MY 2030, we also considered FCEV technologies for select applications that travel longer distances and/or carry heavier loads. This included coach buses, sleeper cab tractors, and day cab tractors that are designed to travel longer distances. For the final rule, we agree with commenters who maintained that public charging would be needed for certain BEV applications with high VMT. In our analysis, we are now projecting (and including costs for) these applications to utilize public charging, starting in MY 2030. We also updated one day cab tractor and one sleeper cab tractor that utilize public charging to reflect a more aerodynamic design than the average tractor aerodynamics used in the technology assessment to support the Phase 2 standards. This was done to reflect the reality that a newly designed HD BEV that is currently available on the market has a more aerodynamic design than tractors used in setting the Phase 2 standards. For more discussion on the specifics of the aerodynamic tractors, see RIA Chapter 2.2.2.1.

ii. Vehicle Energy Demand
Energy is necessary to perform the work required of the vehicle. This work includes driving, idling, and providing heating and cooling; in addition, some vehicles require energy to operate equipment. Vehicles with regenerative braking systems have the opportunity to recover some of the kinetic energy that would otherwise be lost during braking. There are a wide variety of energy demands across the heavy-duty sector, depending on the vehicle's application. For example, some vehicles, such as long-haul tractors, spend the vast majority of the time driving, a fraction of the time idling, and require heating and cooling of the cabin, but do not require operation of additional equipment. A transit bus typically operates at low speeds, so it requires less energy for driving than a long-haul tractor, but requires more energy for heating or cooling due to its large amount of interior cabin volume. Unlike ICE vehicles where the cabin heating is often provided by excess heat from the main ICE, BEVs do not have excess heat from an ICE to utilize in this manner and thus require more energy than ICE vehicles to heat the cabin and additional energy to manage the temperature of the batteries. As another example of the wide variety of energy demands for HD vehicles, a utility truck, also known as a bucket truck, may only drive a few miles to a worksite while idling for the majority of the day and using energy to move the bucket up and down. The power to run the separate equipment on ICE vehicles is typically provided by a PTO from the main engine.
In HD TRUCS, we determined the daily energy demand for each of the 101 vehicle types by estimating both the baseline energy demands that are similar regardless of the powertrain configuration and the energy demands that vary by powertrain. The baseline energy includes energy at the axle to move the vehicle, energy recovered from regenerative braking energy, and PTO energy. Powertrain-specific energy includes energy required to condition the battery and heat or cool the cabin using HVAC system. We discuss each of these in the following subsections.

a. Baseline Energy
For each HD TRUCS vehicle type, we determined the baseline energy consumption requirement that is needed for each of the HD TRUCS applications for ZEVs. The amount of energy needed at the axle to move the vehicle down the road is determined by a combination of the type of drive cycle (such as urban or freeway driving) and the number of miles traveled over a period of time. To do this, we used the drive cycles and cycle weightings adopted for HD GHG Phase 2 for our assessment of the energy required per mile for each vehicle type. EPA's GEM model simulates road load power requirements for various duty cycles to estimate the energy required per mile for HD vehicles. To understand the existing heavy-duty industry, we performed an analysis on current heavy-duty vehicles in the market in order to determine typical power requirements and rates of energy consumption at the axle. These values represent the energy required to propel a vehicle of a given weight, frontal area, and tire rolling resistance to complete the specified duty cycle on a per-mile basis, independent of the powertrain. In RIA Chapter 2.2.2, we describe the GEM inputs and results used to estimate the propulsion energy and power requirements at the axle for ICE vehicles on a per-mile basis. We also used these inputs, along with some simple electric vehicle assumptions, to develop a model to calculate weighted percent of energy recovery due to regenerative braking. Additional detail can be found in RIA Chapter 2.2.2.1.3.
We requested data on our propulsion and regenerative braking energy assessment in the proposal. We received comment that dump trucks, for example, haul loads greater than the payload evaluated in GEM to determine the propulsion power. It is worth noting that the payload used in GEM to determine power requirements represents an average payload with the expectation that vocational vehicles, like dump trucks, would deliver a load and then return with an empty vehicle. Therefore, the payload evaluated for Class 8 dump trucks is essentially 30,000 pounds on one leg of the trip and zero pounds for the other leg of the trip. Furthermore, as discussed in section II.F, we reduced the stringency of the final standards for heavy heavy-duty vocational vehicles from the values proposed to reflect challenging applications, such as this one.
As noted, some vocational vehicles have attachments that perform work, typically by powering a hydraulic pump, which are powered by PTOs. Information on in-use PTO energy demand cycles is limited. NREL published two papers describing investigative work into PTO usage and fuel consumption. ^{587 588} These studies, however, were limited to electric utility vehicles, such as bucket trucks and material handlers. To account for PTO usage in HD TRUCS, we chose to rely on a table described in California's Diesel Tax Fuel Regulations, specifically in Regulation 1432, “Other Nontaxable Uses of Diesel Fuel in a Motor Vehicle,” ^{589} that covers a wider range of vehicles beyond the electric utility vehicles in the referenced NREL studies. This table contains “safe-harbor” percentages that are presumed amounts of diesel fuel used for “auxiliary equipment” operated from the same fuel tank as the motor vehicle. We used this source to estimate PTO energy use as a function of total fuel consumed by vehicle type, as discussed in RIA Chapter 2.2.2.1.4. We requested data for PTO loads in the NPRM and received some comments on our approach for analyzing PTO demands. Specifically, we received data for cement mixers and cement pumpers suggesting that our PTO loads used for these vehicles in the NPRM were too low. After investigation, we agree, and have increased the PTO demand for cement mixers and pumpers.
^{587} NREL, Characterization of PTO and Idle Behavior for Utility Vehicles, Sept 2017. Available online: https://www.nrel.gov/docs/fy17osti/66747.pdf .
^{588} NREL, Fuel and Emissions Reduction in Electric Power Take-Off Equipped Utility Vehicles, June 2016. Available online: https://www.nrel.gov/docs/fy17osti/66737.pdf .
^{589} See 18 CCR section 1432, “Other Nontaxable Uses of Diesel Fuel in a Motor Vehicle,” available at
https://www.cdtfa.ca.gov/lawguides/vol3/dftr/dftr-reg1432.html .
Within HD TRUCS, we calculated the total energy needed daily based on a daily VMT for each vehicle type. We used multiple sources to develop the VMT for each vehicle including the NREL FleetDNA database, a University of California-Riverside (UCR) database, the 2002 Vehicle Inventory and Use Survey (VIUS), the CARB Large Entity Report, or an independent source specific to an application, as discussed in RIA Chapter 2.2.1.2. ^{590} EPA assigned each vehicle type a 50th percentile average daily VMT ^{591} (“operational VMT”) that was used to estimate operational costs, such as average annual fuel, hydrogen, or electricity costs, and maintenance and repair costs (see RIA Chapters 2.3.4, 2.4.4, and 2.5.3). We also account for the change in use of the vehicle over the course of its ownership and operation in HD TRUCS by applying a VMT ratio based on vehicle age to the 50th percentile VMT. The cost of fuel consumption for a particular calendar year is determined by the VMT traveled for that year and the fuel price in that year.
^{590} NREL and EPA. Heavy-Duty Vehicle Activity for EPA MOVES. Available at https://data.nrel.gov/submissions/168 , last accessed on October 15, 2022, which includes an assessment of both the NREL and UC-Riverside databases; U.S. Census Bureau. 2002 Vehicle Inventory and Use Survey. https://www.census.gov/library/publications/2002/econ/census/vehicle-inventory-and-use-survey.html , last accessed on October 15, 2022. CARB. Large Entity Reporting. Available at https://ww2.arb.ca.gov/our-work/programs/advanced-clean-trucks/large-entity-reporting .
^{591} We used the 50th percentile as a proxy for average VMT from the NREL FleetDNA database and the UC-Riverside database. The NREL and UC-Riverside databases each contained a selection of vehicles that we used to calculate 50th and 90th percentile daily VMT. When each database had a VMT value, the values were averaged to get VMT for a specific market segment. See RIA Chapter 2.2.1.2 for further details. See text addressing comments that these mileage estimates are not representative.
For the proposal, we also developed a 90th percentile daily VMT (“sizing VMT”) and used it in HD TRUCS to size ZEV components such as batteries and to estimate the size requirements for EVSE. We selected the 90th percentile daily VMT data because we project that manufacturers will design their BEVs to meet most daily VMT needs, but not to meet the most extreme operations. BEVs designed to meet the longest daily VMT of all operators would be unnecessarily heavy and expensive for most operations, which would limit their appeal.
Commenters challenged EPA's choices for both sizing and operational VMT, as well as the combination of 90th percentile sizing VMT with 50th percentile operational VMT. The first question is the mileage to which a percentile is applied. EPA based its mileage estimate on the NREL's FleetDNA and the UC Riverside's databases, which provide nationwide estimates covering the widest range of HDVs. ^{592} Two commenters recommended lower VMT using different sources of telematics data (including 2002 VIUS data, and data used by CARB in support of its ACT rule). Another commenter, on the other hand, claimed that EPA's estimate was low and supported its claim with recent (May 2023) telematics data from its own fleet operations which had a 90th percentile VMT considerably higher than that in the NREL FleetDNA data base. See RIA Chapter 2.2.1.2.2 for additional discussion.
^{592} NREL and EPA. Heavy-Duty Vehicle Activity for EPA MOVES. Available at https://data.nrel.gov/submissions/168 , last accessed on October 15, 2022, which includes an assessment of both the NREL and UC-Riverside databases.
Irrespective of mileage, one commenter maintained that the combination of a 90th percentile sizing VMT and 50th percentile operational VMT was inherently overconservative. Sizing a battery at the 90th percentile, in their view, is the equivalent of foisting unneeded capacity on a purchaser when operational VMT is at the 50th percentile. There is no reason, in that commenter's view, for the analysis to posit purchasers buying more battery capacity than they need, and for the analysis to assume that extra battery cost. In addition, the commenter asserted that 50th percentile VMT skews EPA's payback analysis toward longer payback periods, since it results in longer time in the analysis for operational and maintenance savings to be realized. In addition, some commenters were skeptical that a 90th percentile sizing VMT properly reflects the existing market where vehicles typically select different sized batteries for different range requirements.
Other commenters challenged the sizing VMT as too low. They question whether purchasers would buy a vehicle unsuitable for a portion of their operations (at least 10 percent, accepting EPA's mileage estimate). In their view, fleets would only purchase 90th percentile trucks if they had exceptionally high confidence that their vehicle will see predictable routes and weights that fall within that 90th percentile operating window. As noted, one commenter also submitted data challenging the mileage estimate itself.
Other comments were less specific, alleging more generally that heavy-duty vehicles travel more miles than reflected in EPA's analysis. These comments expressed concerns about the range of current BEVs and how the range of current BEV applications fail to match the range of corresponding ICE vehicles. For example, one commenter raised a concern that range for one EV was reported at 150 miles when compared to a comparable diesel vehicle with a range of 1,000 miles. Another commenter questioned the purchasers' willingness to accept vehicles with low range, such as the vehicles EPA included in the NPRM which had ranges with less than 100 miles. Another commenter was concerned about the availability of different models with 200 miles of range. Two other commenters were concerned about additional trips or more work required due to limited battery range and long charging times which can be affected by ambient temperature and road grade, among other factors. They also stated that these factors contribute to reduced efficiency in the trucking industry requiring additional trucks, drivers, and trips to deliver the same amount of freight.
EPA appreciates the comments that raised concern about the range of BEVs. We used 101 vehicles to represent the HD industry and our list of vehicles covers the vast majority of vehicle applications, but we recognize it is not all-encompassing. Our technology packages project that significant volumes of ICE vehicles will be sold in the timeframe of this rule and that those vehicles will be used in applications that see extremes, whether they be extreme daily VMT or extreme ambient temperatures, or niche applications. Hence the assumption of 90th percentile sizing VMT because battery sizes to meet longer daily VMTs would be unnecessarily large for most applications. For vehicles using depot charging, one of the base assumptions for the battery sizing analysis was to complete one day's worth of work on a single charge. Therefore, our basic premise was to size ZEVs and ZEV batteries so that they could perform the majority of work that ICE vehicles are capable of and to analyze the payback based on the average fleet daily VMT. This ensures that the vehicles specified in HD TRUCS are capable of doing the work performed by ICE vehicles. At the same time, an operational VMT at the 50th percentile is a conservative but reasonable means of evaluating payback. By using the 50th percentile, we are saying there will be days where the vehicle is used less and days when it's used more, but on average this value would be representative of the typical day. Consequently, we do not agree with the commenters' assertion that the combination of sizing and operational VMTs in HD TRUCS is arbitrary.
For the final rule, we are continuing to size our vehicles batteries for depot charging BEVs to the 90th percentile as this percentile would cover the majority of fleet operations. Sizing vehicle batteries to the 50th percentile, as suggested by some commenters, would decrease the number of years it would take for the BEV technology to pay back, but it would also mean that these ZEVs would be unavailable for major market segments in our analysis. EPA disagrees that such an analytic approach would be a reasoned one, given that ZEV applications are suitable (and in some instances, available now) for these broader market segments. Disallowing them analytically, i.e., a priori via a 50th percentile battery sizing assumption, consequently, is not reasonable. We take these commenters' point, however, that some HD vehicles—even tractors—do not need batteries sized as large as in the proposal's approach due to lower daily VMT. We have accordingly revised the sleeper cab and day cab tractors in HD TRUCS to account for a wide variety of operations including short- and long-range tractors. The sales distribution of these vehicles was informed by California's Large Entity Survey, which we also used in the NPRM and includes the percentage of trips by mileage for day cabs and for sleeper cabs. ^{593}
^{593} California Air Resources Board. “Large Entity Reporting.” Available at https://ww2.arb.ca.gov/our-work/programs/advanced-clean-trucks/large-entity-reporting.
In the final rule, our modeled compliance pathway includes BEVs that would utilize enroute charging, instead of depending on only charging at their depot. In the applications where enroute charging is utilized, manufacturers would not need to assume the extra battery capacity required to meet the longest VMT days, and therefore will instead match the battery size to the typical operational needs. To determine the appropriate size of the battery for these vehicles, we concluded that the vehicles would not require the same battery sizing approach we used in the NPRM for depot-charged vehicles. Instead, we sized the batteries for enroute-charged BEVs to meet the 50th percentile daily VMT needs. For the longest range day cabs and sleeper cabs, on days when these vehicles are required to travel longer distances, we find that less than 30 minutes of mid-day charging at 1 MW is sufficient to meet the HD TRUCS 90th percentile VMT assuming vehicles start the day with a full battery. Details regarding enroute charging can be found in RIA Chapters 2.2.1.2 and 2.6.3. Please see RIA Chapter 2.2.1.2 Table 2-3 for the complete list of VMT for each of the 101 vehicle types.
We continue to base the majority of our sizing VMT on the same sources we used in the NPRM. We understand that there are many different datasets available and that the 90th percentile VMT will be different in each dataset. However, the NREL FleetDNA and MOVES databases use data from many different sources across the country giving a homogenized representation of the HD fleet nationwide rather than data from a single source, even if that data was collected on a nationwide basis. Thus, after consideration of comments, our assessment is that the sources we use are better suited for the purposes of this final rule and that our use of them is reasonable.

b. Powertrain-Specific Energy
HVAC requirements vary by vehicle type, location, and duty cycle. The HVAC energy required to heat and cool interior cabins is considered separately from the baseline energy in HD TRUCS, since these energy loads are not required year-round or in all regions of the country. Nearly all commercial vehicles are equipped with heat and basic ventilation and most vehicles are equipped with air conditioning (A/C). In ICE vehicles, traditional cabin heating uses excess thermal energy produced by the main ICE. This is the only source of cabin heating for many vehicle types. Additionally, on ICE vehicles, cabin A/C uses a mechanical refrigerant compressor that is engine belt-driven.
For BEVs, the energy required for thermal management is different than for ICE vehicles. First, the loads for HVAC are different because the vehicle is not able to be heated from excess heat from the engine. In this analysis, we considered that HD BEVs may be equipped with either a positive temperature coefficient (PTC) electric resistance heater with traditional A/C, or a full heat pump system, as described in RIA Chapter 1. The vehicle's battery is used to power either system, but heat pumps are many times more efficient than PTC heaters. Given the success and increasing adoption of heat pumps in light-duty EVs, we believe that heat pumps will be the more commonly used technology and thus project the use of heat pumps in our HD TRUCS analysis.
To estimate HVAC energy consumption of BEVs in HD TRUCS, we performed a literature and market review. Even though there are limited real-world studies, we agreed with the HVAC modeling-based approach described in Basma et. al. ^{594} This physics-based cabin thermal model considers four vehicle characteristics: the cabin interior, walls, materials, and number of passengers. The authors modeled a Class 8 electric transit bus with an HVAC system consisting of two 20-kW reversible heat pumps, an air circulation system, and a battery thermal management system. We used their estimated HVAC power demand values as a function of temperature, resembling a parabolic curve, where hotter and colder temperatures require more power with the lowest power demand between 59 to 77 °F, as shown in RIA Chapter 2.4.1.1.1.
^{594} Basma, Hussein, Charbel Mansour, Marc Haddad, Maroun Nemer, Pascal Stabat. “Comprehensive energy modeling methodology for battery electric buses”. Energy: Volume 207, 15 September 2020, 118241. Available online: https://www.sciencedirect.com/science/article/pii/S0360544220313487 .
As explained in the NPRM, the power required for HVAC in HD TRUCS is based on a Basma et. al study that determined the HVAC power demand across a range of ambient temperatures. ^{595} However, for the final rule analysis, we made an adjustment to HD TRUCS to reflect a wider range of cooling temperatures (as compared to the proposed greater than 80 °F). In the final rule analysis, we created three separate ambient temperature bins: one for heating (less than 55 °F), one for cooling (greater than 75 °F), and one for a temperature range that requires only ventilation (55-75 °F). In HD TRUCS, we already accounted for the energy loads due to ventilation in the baseline energy demand, so no additional energy consumption is applied here for the ventilation-only operation. We then weighted the power demands by the percent HD VMT traveled at a specific temperature range. The results of the VMT-weighted HVAC power demand for a Class 8 Transit Bus are shown in Table II-11.
^{595} It should be noted that Basma model has discrete values in Celsius and MOVES data has discrete values in Fahrenheit. The Basma discrete values in the Basma model is fitted to a parabolic curve and converted into Fahrenheit to best fit the VMT distribution that is available in MOVES.
Lastly, HVAC load is dependent on cabin size—the larger the size of the cabin, the greater the HVAC demand. The values for HVAC power demand shown in Table II-11 represent the power demand to heat or cool the interior of a Class 8 Transit bus. However, HD vehicles have a range of cabin sizes; therefore, we developed scaling ratios relative to the cabin size of a Class 8 bus. Each vehicle's scaling factor is based on the surface area of the vehicle compared to the surface area of the Class 8 bus. Cabin sizes for most HD vehicle types have a similar cabin to a mid-size light-duty vehicle and therefore, an average scaling factor of 0.2 was applied to all of those vehicle types. ^{596} The buses and sleeper cab tractors have cabin sizes similar to the transit bus or scaled down to reflect its relative cabin size. For example, a Class 4-5 shuttle bus has a cabin size ratio of 0.6. For additional information see RIA Chapter 2.4.1.1.1. In response to our request for data on HVAC loads for BEVs, we did receive additional modeling data from one commenter that included HVAC loads for European long-haul tractors. We found the new data to be corroborative with our HVAC loads and the sleeper cab scaling factor; therefore, we did not adjust our HVAC loads from proposal in HD TRUCS.
^{596} The interior cabin where the driver and passengers sit are heated while where the cargo is stored is not heated.
Fuel cell stacks produce excess heat during the conversion of hydrogen to electricity, similar to an ICE during combustion. This excess heat can be used to heat the interior cabin of the vehicle. In HD TRUCS, we already accounted for the energy loads due to ventilation in the axle loads, so no additional energy consumption is applied to FCEV for heating operation. Therefore, for FCEV energy consumption in HD TRUCS, we only include additional energy requirements for air conditioning ( i.e., not for heating). ^{597} As described in RIA Chapter 2.4.1.1.1, we assigned a power demand of 2.01 kW for powering the air conditioner on a Class 8 bus. The A/C loads are then scaled by the cabin volume for other vehicle applications in HD TRUCS and applied to the VMT fraction that requires cooling, just as we did for BEVs.
^{597} FCEVs use waste heat from the fuel cell for heating, and that ventilation operates the same as it does for an ICE vehicle.
BEVs have thermal management systems to maintain battery core temperatures within an optimal range of approximately 68 to 95 degrees Fahrenheit (F). ^{598} In HD TRUCS, we accounted for the battery thermal management energy demands as a function of ambient temperature based on a Basma et. al study. ^{599} As described in RIA Chapter 2.4.1.1.3, we determined the amount of energy consumed to heat the battery with cabin air when it is cold outside (less than 55 °F) and energy consumed to cool the battery when it is hot outside (greater than 75 °F) with refrigerant cooling. Note, as similarly described in the HVAC discussion in this subsection and as discussed in RIA Chapter 2.4.1.1, we extended the temperature range for cooling from greater than 80 °F to greater than 75 °F for the final rule. For the ambient temperatures between these two regimes, we agreed with Basma, et. al that only ambient air cooling is required for the batteries, which requires no additional load. We first determined a single VMT-weighted power consumption value for battery heating and a value for battery cooling based on the MOVES HD VMT distribution and based on the same method used for HVAC. Then, we determined the energy required for battery conditioning required for eight hours of daily operation and expressed it in terms of percent of total battery size. Table II-12 shows the energy consumption for battery conditioning for both hot and cold ambient temperatures, expressed as a percentage of battery capacity, used in HD TRUCS. The battery cooling energy consumption percentage reflects an updated value for the final rule that includes the battery cooling loads down to 75 °F.
^{598} Basma, Hussein, Charbel Mansour, Marc Haddad, Maroun Nemer, Pascal Stabat. “Comprehensive energy modeling methodology for battery electric buses”. Energy: Volume 207, 15 September 2020, 118241. Available online: https://www.sciencedirect.com/science/article/pii/S0360544220313487 .
^{599} Basma, Hussein, Charbel Mansour, Marc Haddad, Maroun Nemer, Pascal Stabat. “Comprehensive energy modeling methodology for battery electric buses”. Energy: Volume 207, 15 September 2020, 118241. Available online: https://www.sciencedirect.com/science/article/pii/S0360544220313487 .

iii. BEV Component Sizing and Weight
We used HD TRUCS to determine the size of two of the major components in a BEV: the battery and the motor. The size of these components is determined by the energy needs of the specific vehicle to meet its daily operating requirements. In this subsection, we also discuss our method to evaluate the payload and packaging impact of the battery.

a. Battery
First, in HD TRUCS, we based the size of the battery on the daily demands on the vehicle to perform a day's work, as explained in section II.D.5.ii.a. As described in the Vehicle Energy Demand subsection, section II.D.5.ii, this daily energy consumption is a function of miles the vehicle is driven and the energy it consumes because of: (1) moving the vehicle per unit mile, including the impact of regenerative braking and PTO energy requirements, and (2) battery conditioning and HVAC energy requirements. Then we also accounted for the battery efficiency, depth of discharge, and deterioration in sizing of the batteries for BEVs.
The daily energy consumption of each BEV in HD TRUCS is determined by applying efficiency losses to energy consumption at the axle. These losses for the inverter, gearbox, and e-motor are calculated using loss maps of each component of production components for a Class 5 and a Class 8 vehicle, as described in RIA Chapter 2.4.1.1. Next, we oversized the battery to account separately for the typical usable amount of battery and, if necessary, for battery deterioration over time. For the NPRM, we sized the battery by limiting it to a maximum depth of discharge of 80 percent, recognizing that manufacturers and users likely would not allow the battery capacity to be depleted beyond 80 percent of original capacity. We also accounted for deterioration of the battery capacity over time by oversizing the battery by 20 percent, assuming only 80 percent of the battery storage is available throughout its life. We requested comment and data on heavy-duty battery depth of discharge and deterioration. 88 FR 25977.
We received numerous comments about limiting depth of discharge to 80 percent as well as 20 percent extra battery capacity to account for battery deterioration over time. Some of these commenters said we should reduce or remove the additional 20 percent of extra battery capacity for degradation and the 80 percent depth of discharge. Others pointed out that batteries degrade over time and will reduce in capacity, up to 3 percent annual capacity loss.
One commenter cited a February 2022 Roush report on the electrification of tractors where Roush had set the depth of discharge to 90 percent and a 10 percent battery degradation value and suggested using those values. They also pointed out that the decrease in VMT over time used in the proposal's version of HD TRUCS for calculating operating costs meets or exceeds the 20 percent reduction in battery capacity over that same time. They argued that the decrease in VMT already accounts for 20 percent battery deterioration and that it should not be included, or that EPA should adopt the 10 percent value that Roush used in their report. Another commenter questioned the source for a 20 percent battery capacity fade. They agreed that batteries will degrade over time but stated that data is scarce for HD applications and that recent developments in battery technology have resulted in prolonged battery life with long-distance BEVs reaching over 900,000 miles. Another commenter stated that the additional 20 percent battery sizing for deterioration was an overly conservative estimate and that fleets would adjust the mileage and routes used for a vehicle over time as they currently do with ICE vehicles from the secondary market. They stated that fleets would not pay for the additional unused battery capacity. This commenter also raised concerns about using an 80 percent depth of discharge value, saying that it would be more appropriate to model battery usage and mileage based on capacity fade and citing a demonstration by Yang et al. and Dunn et al. Another commenter stated that oversizing the battery biases downward the projected rate of BEV adoption due to increased costs attributable to the extra battery capacity. Relatedly, a few commenters raised concerns about the cost of replacing a vehicle battery. They stated that is a very large cost that should be accounted for.
After considering these comments, and further supported by the state of charge window value used in the 2022 Autonomie tool from Argonne National Laboratory, we revised the battery depth of discharge window to 90 percent in HD TRUCS. ^{600} This is further discussed in RIA Chapter 2.4.1.1.
^{600} Argonne National Laboratory. VTO HFTO Analysis Reports—2022. “ANL—ESD-2206 Report—MD HD Truck—Autonomie Assumptions.xlsx”. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/folder/242640145714 .
EPA also re-evaluated the blanket application of 20 percent deterioration value used for all vehicles in the proposal based on consideration of comments received. We agreed with certain commenters regarding existing data supports that HD VMT decreases as vehicles get older, and thus an older HD BEV would not need to have as much range as it needed when it was new to be comparable to a comparable ICE vehicle. Consequently, in the final rule, we determined the battery deterioration factor for each of the 101 vehicle applications based on the number of charging cycles the battery would require during its first ten years of operation. See RIA Chapter 2.4.1.1.3.
In the final rule, we are considering the costs of battery replacement and ICE rebuilds in our analysis of the costs to purchasers, as discussed in section IV. We are not considering battery replacement cost in our 10-year ownership calculation costs in HD TRUCS. Similarly, we do not consider engine rebuilding costs for ICE vehicles in our parallel 10-year ownership calculation of costs. The reason is the same in both instances: we do not expect failure of either the battery pack or the engine during the vehicles' first ten years of ownership, which is the period we focused on in our HD TRUCS analysis.
We have made certain conforming adjustments within HD TRUCS reflecting these considerations. In the final rule, instead of applying a constant deterioration factor, we determined the battery deterioration factor for each of the 101 vehicle applications based on the number of charging cycles the battery would require during its first ten years of operation. The ten years represents the longest payback period we consider for the technologies in our technology package. A cycle is defined as a single full charge and discharge cycle. The number of cycles is determined based on the annual operating VMT of the vehicle over the 10-year timeframe.
We selected 2,000 cycles as our number of cycles target at 10 years of age while recognizing this value depends on a number of internal and external parameters including battery chemistry, the discharge window while cycling, power output of the battery, and how the battery is managed while in and not in use. A study shows LFP batteries can maintain 80 to 95 percent state of charge after 3,000 cycles and nickel-based lithium-ion batteries are shown to retain 80 percent state of charge after 2,000 cycles under some test conditions. ^{601} Our use of a 2,000-cycle limitation is consequently conservative. We increased the battery size as necessary for vehicles such that the battery would not exceed 2,000 cycles at the end of the 10-year period—the number of cycles reflecting 10-year VMT, as just noted. We note that only eight vehicles in HD TRUCS require a 15 percent increase in battery size and meet the 2,000 cycle limit over a ten year period. Most of the 101 vehicle types would experience less than 1,500 cycles over the ten-year period. The battery sizing is described in greater detail in RIA Chapters 2.4.1.1 and 2.8.5.3.
^{601} Preger, Yuliya, et. al. “Degradation of Commercial Lithium-Ion Cells as a Function of Chemistry and Cycling Conditions.” Journal of the Electrochemical Society. September 2020. Available at: https://iopscience.iop.org/article/10.1149/1945-7111/abae37 .

b. Motor
We determined the size of the motor for each vocational and day cab tractor BEV based on the maximum power demand of the transient cycle and highway cruise cycles, the vehicle's ability to meet minimum performance targets in terms of acceleration rate of the vehicle, and the ability of the vehicle to maintain speed going up a hill. For sleeper cabs, the motor size was determined to be 400 KW based on the comparable ICE sleeper cab tractor engine power and the continuous motor power of existing HD BEV tractors. ^{602} For heavy haul tractors, the BEV motor power is set at 450 kW to reflect the maximum engine power of heavy heavy-duty engines. ^{603} As described in RIA Chapter 2.4.1.2, we estimated a BEV motor's peak power needs to size the e-motor, after considering the peak power required during the ARB transient cycle ^{604} and performance targets included in ANL's Autonomie model ^{605} and in Islam et al., ^{606} as indicated in Table II-13. We assigned the target maximum time to accelerate a vehicle from stop to 30 mph and 60 mph based on weight class of each vehicle. We also used the criteria that the vehicle must be able to maintain a specified cruise speed while traveling up a road with a 6 percent grade, as shown in Table II-13. In the case of cruising at 6 percent grade, the road load calculation is set at a constant speed for each weight class bin on a hill with a 6 percent incline. We determined the required power rating of the motor as the greatest power required to drive the vehicle over the ARB transient test cycle, at 55 mph and 65 mph constant cruise speeds, or at constant speed at 6 percent grade, and then applied losses from the e-motor. We requested comment on our approach using these performance targets in the NPRM but did not receive any comments on this issue.
^{602} Peterbilt. 579EV. Available online: https://www.peterbilt.com/trucks/electric/579EV .
^{603} Detroit Diesel Engines. Available online: https://www.demanddetroit.com/engines/dd16/ .
^{604} EPA uses three representative duty cycles for calculating CO 2 emissions in GEM: a transient cycle and two highway cruise cycles. The transient duty cycle was developed by the California Air Resources Board (CARB) and includes no grade—just stops and starts. The highway cruise duty cycles represent 55-mph and 65-mph vehicle speeds on a representative highway. They use the same road load profile but at different vehicle speeds, along with a percent grade ranging from -5 percent to 5 percent.
^{605} Islam, Ehsan Sabri. Ram Vijayagopal, Ayman Moawad, Namdoo Kim, Benjamin Dupont, Daniela Nieto Prada, Aymeric Rousseau, “A Detailed Vehicle Modeling & Simulation Study Quantifying Energy Consumption and Cost Reduction of Advanced Vehicle Technologies Through 2050,” Report to the U.S. Department of Energy, Contract ANL/ESD-21/10, October 2021. See previous reports and analysis: 2021. Available online: https://vms.taps.anl.gov/research-highlights/u-s-doe-vto-hfto-r-d-benefits/ .
^{606} Islam, Ehsan Sabri, Ram Vijayagopal, Aymeric Rousseau. “A Comprehensive Simulation Study to Evaluate Future Vehicle Energy and Cost Reduction Potential”, Report to the U.S. Department of Energy, Contract ANL/ESD-22/6, October 2022. Available online: https://vms.taps.anl.gov/research-highlights/u-s-doe-vto-hfto-r-d-benefits/ .

c. Battery Weight and Volume
Performance needs of a BEV could result in a battery that is so large or heavy that it impacts payload and, thus, potential work accomplished relative to a comparable ICE vehicle. We determined the battery weight and physical volume for each vehicle application in HD TRUCS using the specific energy and energy density of the battery for each battery capacity.
As described in RIA Chapter 2.4.2, to determine the weight impact, we used battery specific energy, which measures battery energy per unit of mass. In the NPRM, we used specific energy values for the battery pack that ranged between 199 Wh/kg in MY 2027 and 233 Wh/kg in MY 2032. 88 FR 25978. We received comments from two commenters on improvements in battery specific energy higher than the values used in the proposal. EPA recognizes there have been significant development in the areas of battery chemistry, battery cell and battery pack design. These commenters provided examples and values for battery specific energy as well as energy density. However, as explained in RIA Chapter 2.4.2, there is a difference between battery cell properties and battery pack properties. ^{607} For a complete discussion of information provided by commenters on battery specific energy, see RTC section 3.2.3.
^{607} Energy within the battery is stored in the battery cell, or more specifically in the active anode and the active cathode, or more simply referred to as the active materials (for example nickel manganese cobalt). The specific energy is a measure of how much energy can be stored per unit weight. For a given amount (weight) of active materials, it has the ability to store some amount of energy. However, active material weight within the battery is very low; instead most of the battery cell weight is comprised of housing. Since batteries typically do not exist as just active material, the specific energy is reported in terms of amount of energy (in Wh) stored in the active material and the weight of all the components that go into the battery cell. Furthermore, for transportation batteries, a battery pack consists of many (hundreds or thousands) cells, the weight of the battery is further increased from the additional mass that is added to make the pack level structure. This therefore lowers the specific energy of the battery pack (Wh remains constant since the energy is stored in the active materials and weight increases from more mass added from the pack). There is frequent reporting that conflates cell level specific energy with pack level specific energy, or the values are unspecified.
For HD TRUCS, one metric for feasibility is to determine the weight of the BEV powertrain system which includes the battery pack weight as well as the motor weight (and gear box when required). Since battery packs consist of a group of cells (or modules), additional mass from packaging, cooling system and battery management system (BMS) add additional mass without providing additional energy. For the final rule, instead of solely relying on the 2021 version of Autonomie as we did at proposal, we also analyzed the battery specific energy values provided in the comments received on the proposal, ANL BEAN values, values from DOE as provided by a 2024 ANL study, ^{608} and values in the FEV study. ^{609} For our weight assessment in the final rule, we utilized the battery pack specific energy values from the 2024 ANL study because it contains the most comprehensive and most recent assessment of the battery industry. As with battery cost, we used a 50/50 mix of NiMn and LFP batteries to determine the average specific energy for batteries. The NiMn batteries have a specific energy of 226 Wh/kg and LFP at 170 Wh/kg, the resulting value, used in our analysis, is 198 Wh/kg. For further details on battery specific energy see RIA Chapter 2.4.2.1.
^{608} Kevin Knehr, Joseph Kubal, Shabbir Ahmed, “Cost Analysis and Projections for U.S.-Manufactured Automotive Lithium-ion Batteries”, Argonne National Laboratory report ANL/CSE-24/1 for US Department of Energy. January 2024. Available online: https://www.osti.gov/biblio/2280913 .
^{609} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
We recognize that although there likely will be improvements made between 2027 and 2032, it is difficult to determine if the degree of improvements during that time frame, especially considering that manufacturers will have to balance the cost of additional weight reduction and overall costs of the BEV. Therefore, for the final rule we reasonably, and conservatively, held the battery specific energy constant for MYs 2027 through 2032.
To evaluate battery volume and determine the packaging space required for each HD vehicle type, we used battery energy density. Battery energy density (also referred to as volumetric energy density) measures battery energy per unit of volume. To calculate battery energy density, we multiplied the battery specific energy by a factor. For the NPRM, we used pack level energy densities that ranged from 496 Wh/L in MY 2027 to 557 Wh/L in MY 2032. These values corresponded to multiplying the battery pack specific energy by 2.5. We requested comment and data in the NPRM to inform these values for the final rule. 88 FR 25978.
In response to our request for data in the NPRM, one commenter provided data from a study that included battery properties of specific energy and energy density. For more details on the comment and our response, see RTC section 3.2.3. The average energy density calculated from the data provided was 2.2. For the final rule, we used a ratio of 2.0 as a conservative estimate because the properties cited by the initial commenter discussed on a cell level, not a pack level. Based on our update to battery pack specific energy, we used an energy density value of 396 Wh/L for MYs 2027 through 2032 in HD TRUCS.
Heavy-duty vehicles are used to perform work, such as moving cargo or carrying passengers. Consequently, heavy-duty vehicles are sensitive to increases in vehicle weight and carrying volume. To take this into account, we also evaluated BEVs in terms of the overall impact on payload-carrying ability and battery packaging space. The results of this analysis can be found in RIA Chapters 2.4.2 and 2.9.
At proposal, EPA included a 30 percent reduction in the payload used to evaluate compliance in GEM as a metric to determine specific vehicle applications. Specifically, EPA did not include BEVs in a projected technology package if this payload capacity was reduced by over 30 percent. 88 FR 25978. We note that the payload used to demonstrate compliance in GEM is less than the full payload capability of the vehicle. For vehicles like dump trucks and tractors, that are seen as fully loaded during delivery and empty upon return, the maximum payload was much greater than the GEM payload. Therefore, the 30 percent threshold used in the NPRM analysis did not represent a 30 percent loss in total payload and its impact on total payload is less than 30 percent. For the proposal, EPA also evaluated payload volume by calculating the width of the physical battery using the volume, wheelbase, and 110 percent of the frame rail height. If the battery width was less than 8.5 feet, we determined the battery would package on the specific vehicle.
Many commenters raised concerns about the reduction in payload due to increased curb weight of ZEVs. The principal concern raised is that battery size and weight constrain payload so much as to render BEVs uneconomic. With respect to our analysis of battery width, commenters asserted that EPA had failed to consider a number of consequential things, including space for tires and the width of each frame rail. There were also several comments on the specific value of payload loss of 30 percent used in HD TRUCS for the NPRM. Three commenters believed the payload penalty limit for BEVs is too high; for some, even a 5 to 10 percent loss is too much to perform their mission. One of these commenters claimed that approximately 20 percent of intermodal loads already max out due to weight under the current diesel truck equipment configuration. Neither of the other two commenters provided any additional information on any acceptable payload capacity loss. One commenter recommended adjustment to the payload cut off, particularly for vocational vehicles such as concrete mixers, dump trucks, and tanker trucks.
At proposal, EPA justified the cargo penalty metric based on a report of the North American Council for Freight Efficiency (NACFE) which the agency characterized as stating that vehicles weigh out before cubing out. ^{610} DRIA p. 234. Two commenters stated that EPA misunderstood the NACFE report. One commenter maintained that the NACFE report references a “per run” load instead of a “per truck” vehicle load. As load of the truck is unpredictable, any additional reduction in payload capacity reduces the flexibility and use of the vehicle. Another commenter not only concurred but also stated that the NACFE report only refers to regional trucks which makes it inappropriate to apply to all 101 vehicles in HD TRUCS. Lastly, one commenter asserted that since the NACFE report is from 2010 and the industry has gone through significant changes since then as a result of e-commerce as well as shipping practices, the assumed 30 percent weight penalty used at proposal should be included in the cost of the vehicle as fleets would account for the additional cost of making up for the lost payload through additional trips or vehicles.
^{610} EPA “Draft Regulatory Impact Analysis: Heavy-Duty Greenhouse Gas Emissions: Phase 3.” April 2023. Page 234.
After considering these comments, we are not using a 30 percent payload reduction as a metric for determining BEV suitability and are no longer estimating battery width based on frame rail height and wheelbase. Instead, for the final rule we conducted a more robust analysis where we assessed each vehicle in HD TRUCS on an individual basis and determine the suitability of each application, as described in this section and in RIA 2.9.1. EPA conducted two separate individualized types of determinations: one for battery payload weight, the other for battery volume. See RIA Chapter 2.9.1.1 and 2.9.1.2. We note further that this delineation responds to those comments relating to weighing out and cubing out, since we are conducting separate analyses for each of these situations. Furthermore, after consideration of comments, we are no longer using the NACFE report in this analysis to inform a single weight penalty cutoff for all types of vehicles.
With respect to weight, we compared the respective weights of the BEV powertrain with the comparable ICE powertrain. We determined the percentage difference in weight using the maximum payload available to each vehicle type, not the default GEM payload. For example, for the Class 8 dump trucks, the payload difference (loss) was modest: 2.6 percent; with the NiMn battery chemistry specific energy (226 Wh/kg) ^{611} the payload loss is 1.3 percent. The tanker payload loss was 2 percent of maximum payload. EPA does not view these differences as sufficient to preclude utilization of BEV technology at the rates projected in EPA's modeled compliance pathway. See RIA Chapter 2.9.1.1 for detailed weight comparisons by vehicle, and more detailed discussion of specific applications. On the other hand, for concrete mixers and pumpers, EPA determined that battery size, energy demand, and corresponding costs were all significantly higher than EPA had projected at proposal and accordingly determined that EPA's optional custom chassis standards for Concrete Mixers/Pumpers and Mixed-Use Vehicles will remain unchanged from the Phase 2 MY 2027+ CO 2 emission standards. ^{612}
^{611} Battery chemistry impacts the battery pack specific energy and battery technology continues to evolve suggesting that battery pack weight may decrease and payload increase. To assess the sensitivity of payload to higher specific energy, EPA reviewed two additional scenarios (1) use of NiMn batteries (HD TRUCS uses a value that represents a 50/50 mix of NiMn and LFP to align with battery cost assumptions) and (2) possible NiMn battery pack specific energy improvements through 2030.
^{612} See also section II.F.1 discussing optional custom chassis standards, including those for concrete mixers.
For tractors, EPA did the same type of weight comparison, and found the weight increase to be reasonable for most of the tractors in HD TRUCS. See RIA 2.9.1.1 for vehicle by vehicle difference in weight and a more detail discussion of specific applications. EPA further examined when tractors are utilized at maximum load ^{613} and found that many commodities do not require transport at maximum load, for further discussion on our analysis of tractor loading based on commodities, see Chapter 2.9.1 of the RIA. Our ultimate conclusion is that our modeled compliance pathway projects a majority of these vehicles remain ICE vehicles, that ICE vehicles therefore would be available to accommodate those commodities for which maximum loads are needed, and that BEVs remain viable for those other commodities that do not require transport at maximum load.
^{613} DOE. Vehicle Technologies Office. Fact of the Week #1293. “In 2019, More Heavy Trucks Operated at 34,000 to 36,000 Pounds than Any Other Weight Category”. Available online: https://www.energy.gov/eere/vehicles/articles/fotw-1293-june-5-2023-2019-more-heavy-trucks-operated-34000-36000-pounds-any .
Our analysis respecting volume is somewhat different. We make the reasonable assumption that if a current BEV (either tractor or vocational vehicle) exists, its volumetric capacity is suitable. Thus, if the HD TRUCS version of that BEV has the same or similar battery size as an existing BEV, we did not constrain the adoption of that BEV type due to volume loss. In some instances, we examined further whether wheelbase adjustments could accommodate larger battery sizes so as not to constrain available volume. See RIA 2.9.1.2 for a vehicle-by-vehicle discussion and more detail on specific vehicle applications.
In assessing the packaging of a FCEV powertrain, we contracted with FEV to assess how FCEVs can store and package hydrogen. The FEV study shows that six tanks could fit on a sleeper cab tractor with a wheelbase of 265”. ^{614} A vehicle class where we determined that battery size, or fuel cell and hydrogen tank size, would reduce storage volume for some applications was coach buses, and therefore we did not finalize more stringent optional custom chassis standards for coach buses, as discussed in section II.F.1. ^{615} Our individualized determinations for all of these vehicles are found in RIA 2.9.1.2.
^{614} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
^{615} See also II.F.1 discussing optional custom chassis standards, including those for coach buses.

iv. Charging Infrastructure for BEVs
Charging infrastructure represents a key element required for HD BEV operation. More charging infrastructure will be needed to support the projected growing fleet of HD BEVs. This will likely consist of a combination of (1) depot charging—with infrastructure installed in parking depots, warehouses, and other private locations where vehicles are parked off-shift (when not in use), and (2) public charging, ^{616} which provides additional electricity for vehicles during their operating hours.
^{616} En-route charging could occur at public or private charging stations though, for simplicity, we often refer to en-route charging as occurring at public stations in the preamble.
In RIA Chapters 2.6 and 2.8.7 we describe how we accounted for charging infrastructure in our analysis of HD BEV technologies for our technology packages to support the feasibility of the standards and extent of use of HD BEV technologies in the potential compliance pathway for MYs 2027-2032. We explain there in detail the updates made after consideration of comments and newly available supporting data from NREL. For the NPRM analysis, we estimated infrastructure costs exclusively associated with depot charging to fulfill each BEV's daily charging needs off-shift with the appropriately sized electrical vehicle supply equipment. This approach reflected our expectation that many heavy-duty BEV owners would opt to purchase and install EVSE at depots, and accordingly, we accounted for all of these costs upfront. We received many comments on this approach. While multiple commenters agreed that depot charging would be the primary source of charging across many vehicle applications, especially in the early years of the Phase 3 program, some commenters noted the importance of also accounting for public charging in our analysis. Commenters asserted that long-haul vehicles and other fleet vehicles that either do not regularly return to a depot, or for which installing depot charging would be difficult, may utilize public charging including during the initial model years (through 2032) covered by the Phase 3 program.
For our final rule analysis, after consideration of these comments, we have updated our HD TRUCS model to incorporate costs associated with public charging for certain vehicle types starting with MY 2030, the year when we project there will be sufficient public charging infrastructure for HD vehicles for the projected utilization of such technologies. See RIA Chapter 1.6. Specifically, in HD TRUCS we assume that all BEV sleeper cab tractors and coach buses will use public charging rather than depot charging, as will four of the ten day cab tractors—those with longer ranges—that we model. In HD TRUCS we assume public charging needs will be met with a mix of megawatt-level EVSE and 150 kW EVSE, consistent with a recent ICCT analysis. ^{617} In our analysis for the final rule, capital costs associated with public charging equipment are passed through to BEV owners through a higher charging cost. See RIA Chapter 2.4.4.2.
^{617} Hussein Basma, Claire Buysee, Yuanrong Zhou, and Felipe Rodriguez, “Total Cost of Ownership of Alternative Powertrain Technologies for Class 8 Long-haul Trucks in the United States,” April 2023. Available at: https://theicct.org/wp-content/uploads/2023/04/tco-alt-powertrain-long-haul-trucks-us-apr23.pdf .
For other day cab tractors and vocational vehicles, in HD TRUCS we continue to assume that daily charging needs can be met with appropriately sized depot EVSE. A range of depot charging equipment is available including AC or DC charging, different power levels, as well as options for different number of ports and connectors per charging unit, connector type(s), communications protocols, and additional features such as vehicle-to-grid capability (which allows the vehicle to supply energy back to the grid). Many of these selections will impact EVSE hardware and installation costs, with power level as one of the most significant drivers of cost. While specific cost estimates vary across the literature, higher-power charging equipment is typically more expensive than lower-power units. For this reason, in HD TRUCS for the final rule we continued our proposed approach to consider four different charging types—AC Level 2 (19.2 kW) and 50 kW, 150 kW, and 350 kW DC fast charging (DCFC)—though we have made updates to cost assumptions and other key inputs that impact our depot charging analysis, as described in section II.E.2 of this document.
We acknowledge that even vehicles which predominantly rely on depot charging may utilize some public charging, for example on high travel days. In addition, some fleet owners may opt not to install depot charging, and instead either rely on public charging or make alternative arrangements such as using charging-as-a-service or other business arrangements to meet charging needs. See RIA Chapter 2.6 for a more complete description of this topic.

v. FCEV Component Sizing
To compare HD FCEV technology costs and performance to a comparable ICE vehicle in HD TRUCS, this section explains how we define HD FCEVs based on the performance and use criteria in RIA Chapter 2.2 (that we also used for HD BEVs, as explained in section II.D.5.ii). We determined the e-motor, fuel cell system, and battery pack sizes to meet the power requirements for each of the FCEVs represented in HD TRUCS. We also estimated the size of the onboard fuel tank needed to store the energy, in the form of gaseous hydrogen, required to meet typical range and duty cycle needs. See RIA Chapter 2.5 for further details.

a. E-Motor
As discussed in RIA Chapter 2.4.1.2, the e-motor is part of the electric drive system that converts the electric power from the battery and/or fuel cell into mechanical power to move the wheels of the vehicle. In HD TRUCS, the e-motor was sized for a FCEV like it was sized for a BEV—to meet peak power needs of a vehicle, which is the maximum power to drive the ARB transient cycle, meet the maximum time to accelerate from 0 to 30 mph, meet the maximum time to accelerate from 0 to 60 mph, and maintain a set speed up a six-percent grade.

b. Fuel Cell System
Vehicle power in a FCEV comes from a combination of the fuel cell (FC) stack and the battery pack. The fuel cell behaves like the internal combustion engine of a hybrid vehicle, converting chemical energy stored in the hydrogen fuel into electrical energy. The battery is charged by power derived from regenerative braking, as well as excess power from the fuel cell. Some HD FCEVs are designed to rely on the fuel cell stack to produce the necessary power, with the battery primarily used to capture energy from regenerative braking. This is the type of HD FCEV that we modeled in HD TRUCS for the MY 2030 to 2032 timeframe in order to meet the longer distance requirements of select vehicle applications. 618 619 620
^{618} Islam, Ehsan Sabri, Ram Vijayagopal, Aymeric Rousseau. “A Comprehensive Simulation Study to Evaluate Future Vehicle Energy and Cost Reduction Potential”, Report to the U.S. Department of Energy, Contract ANL/ESD-22.6. October 2022. See Full report. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/file/1406494585829.
^{619} Note that ANL's analysis defines a fuel cell hybrid EV (FCHEV) as a battery-dominant vehicle with a large energy battery pack and a small fuel cell, and a fuel cell EV (FCEV) as a fuel cell-dominant vehicle with a large fuel cell and a smaller power battery. Ours is a slightly different approach because we consider a fuel cell-dominant vehicle with a battery with energy cells. The approach we took is intended to cover a wide range of vehicle application however it results in a conservative design, as it relies on a large fuel cell and a larger energy battery. As manufacturers design FCEV for specific HD applications, they will likely end up with a more optimized lower cost designs. Battery-dominant FCHEVs and fuel cell-dominant technologies with power batteries may also be feasible in this timeframe but were not evaluated for the FRM.
^{620} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
While much of FCEV design is dependent on the use case of the vehicle, manufacturers also balance the cost of components such as the fuel cell, the battery, and the hydrogen fuel storage tanks. For the purposes of this HD TRUCS analysis, we focused on PEM fuel cells that use energy battery cells, where the fuel cell and the battery were sized based on the demands of the vehicle. In HD TRUCS, the fuel cell system ( i.e., the fuel cell stacks plus balance of plant, or BOP) was sized at either the 90th percentile of power required for driving the ARB transient cycle or to maintain a constant highway speed of 75 mph with 80,000-pound gross combined vehicle weight (GCVW). The 90th percentile power requirement was used to size the fuel cells of vocational vehicles and day cab tractors, and the 75-mph power requirement was used to size the fuel cells of sleeper cab tractors. ^{621}
^{621} In the NPRM version of HD TRUCS, we inadvertently used the 90th percentile of the ARB transient cycle to size the sleeper and day cab tractors and the power required to drive at 75 mph to size the vocational vehicles. This error is corrected in the final version of HD TRUCS.
We received comments suggesting that the NPRM did not accurately reflect how a fuel cell operates because we relied on peak fuel cell efficiency rather than average operating efficiency. One commenter noted that FCEVs would benefit from BEV component efficiency gains and observed that we did not utilize the DOE targets for peak fuel cell efficiency in HD TRUCS, implying that fuel cells could be more efficient than we assumed in the NPRM because a more efficient stack would require less cooling, which could lead to compounded gains over time. Three commenters suggested that the fuel cell efficiency values used in the NPRM were too high. One commenter pointed out that we considered peak efficiency estimates rather than average operating efficiencies. The same commenter and another offered ranges for operating efficiency at power levels typical for commercial vehicles and suggested that we revise our fuel cell efficiency estimates. One of the same commenters noted that fuel cell performance degrades over time, generally due to impurities in hydrogen fuel that cause efficiencies to drop significantly from beginning of life to end of life. We evaluated these comments and find them persuasive. Accordingly, we have revised our sizing methodology for the fuel cell system (to meet power demands of a vehicle) and onboard hydrogen storage tanks (to meet energy demands of a vehicle, as described in section II.D.5.d) in the final rule version of HD TRUCS.
RIA Chapter 2.5.1.1.2 explains that to avoid undersizing the fuel cell system, we oversized the fuel cell stack by an additional 25 percent to allow for occasional scenarios where the vehicle requires more power ( e.g., to accelerate when the battery state of charge is low, to meet unusually long grade requirements, or to meet other infrequent extended high loads like a strong headwind) and so the fuel cell can operate within an efficient region. This size increase we included in the final rule version of HD TRUCS can also improve fuel cell stack durability and ensure the fuel cell stack can meet the power needs throughout the useful life. This is the systems' net peak power, or the amount available to power the wheels. ^{622} The fuel cell stack generates power, but some power is consumed to operate the fuel cell system before it gets to the e-motor. Therefore, we increased the size of the system by an additional 20 percent ^{623} to account for operation of balance of plant (BOP) components that ensure that gases entering the system are at the appropriate temperature, pressure, and humidity and remove heat generated by the stack. This is the fuel cell stack gross power.
^{622} Net system power is the gross stack power minus balance of plant losses. This value can be called the rated power.
^{623} Huya-Kouadio, Jennie and Brian D. James. “Fuel Cell Cost and Performance Analysis: Presentation for the DOE Hydrogen Program; 2023 Annual Merit Review and Peer Evaluation Meeting”. Strategic Analysis. June 6, 2023. Available online: https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/review23/fc353_james_2023_o-pdf.pdf .
The larger fuel cell can allow the system to operate more efficiently based on its daily needs, which results in less wasted energy and lower fuel consumption. This additional size also adds durability, which is important for commercial vehicles, by allowing for some degradation over time. We determined that with this upsizing, there is no need for a fuel cell system replacement within the 10-year period at issue in the HD TRUCS analysis.

c. Battery Pack
As described in RIA Chapter 2.5.1.1.3, in HD TRUCS, the battery power accounts for the difference between the peak power of the e-motor and the continuous power output of the fuel cell system. We sized the battery to meet these power needs in excess of the fuel cell's capability only when the fuel cell cannot provide sufficient power. In our analysis, the remaining power needs are sustained for a duration of 10 minutes ( e.g., to assist with a climb up a steep hill).
Since a FCEV operates like a hybrid vehicle, where power comes from a combination of the fuel cell stack and the battery, the battery is sized smaller than a battery in a BEV, which can result in more cycling of the FCEV battery. Thus, we reduced the FCEV battery's depth of discharge from 80 percent in the NPRM to 60 percent in the final rule version of HD TRUCS to reflect the usage of a hybrid battery more accurately. This means the battery is oversized in HD TRUCS to account for potential battery degradation over time.

d. Onboard Hydrogen Storage Tank
A FCEV is re-fueled like a gasoline or diesel-fueled ICE vehicle. We determined the capacity of the onboard hydrogen energy storage system using an approach like the BEV methodology for battery pack sizing in RIA Chapter 2.4.1.1, but we based the amount of hydrogen needed on the daily energy consumption needs of a FCEV.
Hydrogen fuel in the tank enters the fuel cell stack, where an electrochemical reaction converts hydrogen to electricity. During the conversion process, some energy from the hydrogen fuel is lost as heat or otherwise does not go towards producing electricity. The remaining energy is used to operate the fuel cell system. Based on consideration of comments, we agree the fuel cell system efficiency values used in the NPRM were too high and should not be based on peak performance at low power, since fuel cells typically do not operate for long in that range. We therefore reduced them by eight percent to reflect an average operating efficiency instead of peak efficiency (see RIA Chapter 2.5.1.2.1). This was based on a review of DOE's 2019 Class 8 Fuel Cell Targets. DOE has an ultimate target for peak efficiency of 72 percent, which corresponds to an ultimate fuel cell drive cycle efficiency of 66 percent. This equates to an 8 percent difference between peak efficiency and drive cycle efficiency at a more typical operating power. Therefore, to reflect system efficiency more accurately at a typical operating power, we applied the 8 percent difference to the peak efficiency estimate in the NPRM. For the final rule, the operational efficiency of the fuel cell system ( i.e., represented by drive cycle efficiency) is about 61 percent.
For the final rule, we combined the revised fuel cell system efficiency with the BEV powertrain efficiency ( i.e., the combined inverter, gearbox, and e-motor efficiencies) as a total FCEV efficiency to account for losses that take place before the remaining energy arrives at the axle. The final FCEV powertrain efficiencies, ranging from 51 percent to 57 percent, were used to size the hydrogen storage tanks and to determine the hydrogen usage and related costs.
As described in RIA Chapter 2.5.1.2.2, we included additional energy requirements for air conditioning. ^{624} For battery conditioning, since the batteries in FCEVs have the same characteristics as batteries for BEVs, we employed the same methodology used for BEVs.
^{624} FCEVs use waste heat from the fuel cell for heating, and that ventilation operates the same as it does for an ICE vehicle.
As described in RIA Chapter 2.5.1.2.1, we converted FCEV energy consumption (kWh) into hydrogen weight using an energy content of 33.33 kWh per kg of hydrogen. In our analysis, 95 percent of the hydrogen in the tank (“usable H2”) can be accessed. This is based on targets for light-duty vehicles, where a 700-bar hydrogen fuel tank with a capacity of 5.9 kg has 5.6 kg of usable hydrogen. ^{625} Furthermore, we added 10 percent to the tank size in HD TRUCS to avoid complete depletion of hydrogen from the tank.
^{625} U.S. DRIVE Partnership. “Target Explanation Document: Onboard Hydrogen Storage for Light-Duty Fuel Cell Vehicles”. U.S. Department of Energy. 2017. Available online: https://www.energy.gov/sites/prod/files/2017/05/f34/fcto_targets_onboard_hydro_storage_explanation.pdf .

E. Technology, Charging Infrastructure, and Operating Costs
As discussed in section II.D.1, we considered ICE vehicles with GHG-reducing technologies. For the modeled potential compliance pathway, we did not include additional technologies on ICE vehicles beyond those technologies we analyzed to support the Phase 2 MY 2027 standards. Therefore, there are not any incremental cost increases for the Phase 3 standards associated with the ICE vehicles in this potential compliance pathway. Thus, this subsection focuses on the costs associated with BEV and FCEV technologies and infrastructure. In the following subsections, we first discuss BEV technology (section II.E.1) and associated EVSE technology costs (section II.E.2) and FCEV technology costs (section II.E.3). RIA Chapter 2.4.3 (for BEVs) and RIA Chapter 2.5.2 (for FCEVs) includes the cost estimates for each of the 101 applications. We then discuss the IRA tax credits we quantified in our analysis for BEV and FCEV technologies in section II.E.4. Our assessment of operating costs for ICE vehicle, BEV and FCEV technologies including the fuel or electricity costs, along with the maintenance and repair costs, insurance, and taxes are presented in section II.E.5. This subsection concludes with the overall payback analysis for BEV and FCEV technologies in section II.E.6. RIA Chapter 2.8.2 includes the vehicle technologies costs, EVSE costs, operating costs, and payback results for each of the 101 HD applications for BEV and FCEV technologies. The technology costs for BEV and FCEV technologies aggregated into MOVES categories are also described in detail in RIA Chapter 3.1.
As we have noted several times throughout this preamble, there are other examples of possible compliance pathways for meeting the final standards that do not involve the widespread adoption of BEV and FCEV technologies. In section II.F.4, we provide examples of additional potential compliance pathways, including the associated technology and operating costs of those technologies.

1. BEV Technology Costs
The incremental cost of a BEV powertrain system is calculated as the cost difference from the comparable vehicle powertrain with an ICE, where the ICE vehicle powertrain cost is a sum of the costs of the engine (including the projected cost of the HD2027 standards), alternator, gearbox (transmission), starter, torque converter, and final drive system. Heavy-duty BEV powertrain costs consist of the battery, electric motor, inverter, converter, onboard charger, power electronics controller, transmission or gearbox, final drive, and electrical accessories. RIA Chapter 2.4.3 contains additional detail on our cost projections for each of these components.
Battery costs are widely discussed in the literature because they are a key driver of the cost of a HD electric vehicle. The per unit cost of the battery, in terms of $/kWh, is the most common metric in determining the cost of the battery as the final size of the battery may vary significantly between different applications. The total battery pack cost is a function of the per unit kWh cost and the size (in terms of kWh) of the pack.
There are numerous projections for battery costs and battery pricing in the literature that cover a range of estimates. Sources do not always clearly define what is included in their cost or price projections, nor whether the projections reflect direct manufacturing costs incurred by the manufacturer or the prices seen by the end-consumer. Except as noted in the NPRM, the values in the literature we used to develop the battery pack costs used in the NPRM were developed prior to enactment of the Inflation Reduction Act. In the NPRM, we requested battery cost data for heavy-duty vehicles. 88 FR 25981.
We received a significant number of comments regarding the values we used for the battery costs, as well as comments regarding application of a learning curve to battery costs. Commenters suggested values both higher and lower than the values used in the proposal. Justifications from commenters for higher than proposal values included volatility in the minerals market, adjustment to rate of learning, inability to capture some or all of BIL and IRA incentives, as well as general uncertainty within the sector. Justifications from commenters for lower than proposal values included incentives from BIL and IRA, rapid development in the EV sector including the light-duty market, cheaper chemistries including LFP and sodium ion batteries, and (more) recent stabilization within the lithium market.
One commenter recommended that EPA use a figure roughly 26 percent greater than estimated at proposal; for example, they believe the MY 2027 battery pack costs should be $183/kWh. Two other commenters echoed that commenter's recommended battery costs. Another commenter shared four CBI battery pack costs for MY 2029 under four scenarios. These scenarios included smaller and larger battery packs, and with low and high lithium raw material costs. Another commenter questioned EPA's reliance on the ICCT value for battery pack cost given ICCT's caution about uncertainty within the market for this sector. The commenter further maintained that the ICCT White Paper did not adequately explain or cite empirical support for averaging of the values, and that upper and lower bounds should be adopted instead for HD TRUCS battery cost inputs.
Although some commenters believe the battery costs used for the NPRM are too low, others believe the battery costs used were too high. One commenter referenced a Roush report of HDV battery costs of $98/kWh in MY 2030 and $88/kWh in MY 2032 without an IRA adjustment. Another commenter believes the battery used for HDVs will be less conservative than the one modeled by EPA in terms of both specific energy and energy density, and that this conservativeness is then reflected in EPA's estimates of battery costs. This commenter's cited BloombergNEF, where battery costs are projected to decline to $100/kWh by 2026 as a result of mineral price stabilization. Another commenter referenced an ICCT report where batteries would reach a cost of $120/kWh at the pack level by 2030 but did not put forward a battery pack cost estimate of their own.
Another point of disagreement from commenters is the methodology used for assessing the effects of learning by doing ^{626} on battery pack costs between 2027 and 2032. One commenter suggests that faster learning curves may be appropriate for BEVs due to novel battery chemistries that can disrupt markets and increase competition; faster-than-expected moderation of pandemic-induced supply chain disruption; battery pack economies of scale; and the tendency of battery outlooks to underestimate future learning curves. Another commenter believes learning for BEVs should start in 2022 rather than in 2027 which was used in the NPRM analysis, the logic being that learning commences as production commences. Applying EPA's learning curve starting in 2022 would have the effect of reducing cost reductions attributable to learning in the years of the Phase 3 rule. Another commenter agrees with this commenter as to when learning commences, but maintained that the learning curve for ZEVs should be less sharp than for ICE because ZEVs have fewer moving parts. The commenter also believes some components have not achieved the economies of scale that is required for the cost inputs used in HD TRUCS. Lastly, this commenter stated that the learning curve for LD was inapplicable to HD vehicles given the difference in duty cycles, durability, and the resulting difference in battery sizes. Another commenter took a different view on learning from the LD market, stating that learning should have already started in the light-duty industry and this means any further learning in HD will be smaller than what EPA estimated in the proposed rule. More detailed discussion of learning used for ZEVs can be found RIA Chapter 3.2.1 and the comments received on learning and responses can be found in RTC section 12.3.
^{626} Manufacturing learning is the process by which costs for items are reduced as manufacturing practices become more efficient through improvements in manufacturing methods. This is represented as a factor applied to a base year and applied year over year to reflect a drop in cost for year over year manufacturing improvements.
For the final rule, we re-evaluated our values used for battery cost in MY 2027 based on comments provided by stakeholders, as well as on additional studies provided by the FEV and the Department of Energy BatPaC model. ^{627 628} We considered a wide range of MY 2027 battery pack costs ranging from the $183/kWh cited by manufacturers in comments to $101/kWh projected by ANL that reflects an average of the nickel-manganese containing layered oxides (Ni/Mn) and the lithium iron phosphate (LFP) HD battery costs. ^{629} ANL conducted this study to estimate the cost of U.S-produced battery packs for light and heavy-duty vehicles using their BatPaC tool. We also contracted FEV to conduct a cost analysis to inform the final rule analysis. The FEV study projected costs for HD battery packs in MY 2027 to range from $128 to $143/kWh. As described in RIA Chapter 2.4.3, for MY 2027, we project a battery cost value of $120/kWh (2022$) based on a weighted average of the battery cost values from DOE's study, values received from commenters, and the FEV cost study.
^{627} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
^{628} DOE BatPac Study.
^{629} Argonne National Laboratory. “Cost Analysis and Projections for U.S.-Manufactured Automotive Lithium-ion Batteries.” February 2024.
We have traditionally applied learning impacts using learning factors applied to a given cost estimate as a means of reflecting learning-by-doing effects on future costs. ^{630} We are continuing to do so in this rulemaking. We agree with some parts of the comments regarding the NPRM's assessment of learning for ZEV components. In the final rule, we adjusted the learning to reflect a less steep portion of the learning curve in MY 2027 and beyond compared to the learning we used in the NPRM analysis. The learning curve we used for the final rule aligns closely with the learning applied by ANL in their BatPac modeling to develop battery costs for heavy-duty BEVs in MYs 2027 through 2032. ^{631} We calculated the MYs 2028-2032 battery costs using learning scalars as shown in RIA Chapter 3.2.1, resulting in the values shown in Table II-14 represent the direct manufacturing pack-level battery costs in HD TRUCS using 2022$. These values are used for battery costs in both BEVs and FCEVs.
^{630} See the 2010 light-duty greenhouse gas rule (75 FR 25324, May 7, 2010); the 2012 light-duty greenhouse gas rule (77 FR 62624, October 15, 2012); the 2011 heavy-duty greenhouse gas rule (76 FR 57106, September 15, 2011); the 2016 heavy-duty greenhouse gas rule (81 FR 73478, October 25, 2016); the 2014 light-duty Tier 3 rule (79 FR 23414, April 28, 2014); the heavy-duty NOx rule (88 FR 4296, January 24, 2023).
^{631} Argonne National Laboratory. “Cost Analysis and Projections for U.S.-Manufactured Automotive Lithium-ion Batteries.” Figure 4, page 16. February 2024.
As noted, batteries are the most significant cost component for BEVs, and the IRA section 13502, “Advanced Manufacturing Production Credit,” has the potential to significantly reduce the cost of BEVs whose batteries are produced in the United States. As discussed in section II.E.4, the IRA Advanced Manufacturing Production Credit provides up to $45 per kWh tax credits (with specified phase-out in CYs 2030-2033) for the production and sale of battery cells and modules, and additional tax credits for producing critical minerals such as those found in batteries, when such components or minerals are produced in the United States and other criteria are met. Our approach to accounting for the IRA Advanced Manufacturing Production Credit in our analysis is explained in section II.E.4.
An electric drive (e-drive)—another major component of an electric vehicle—includes the electric motor, an inverter, a converter, and optionally, a transmission system or gearbox. The electric energy in the form of direct current (DC) is provided from the battery; an inverter is used to change the DC into alternating current (AC) for use by the motor. The motor then converts the electric power into mechanical or motive power to move the vehicle. Conversely, the motor also receives AC from the regenerative braking, whereby the inverter changes it to DC to be stored in the battery. The transmission reduces the speed of the motor through a set of gears to an appropriate speed at the axle. An emerging trend is to replace the transmission and driveline with an e-axle, which is an electric motor integrated into the axle, e-axles are not explicitly covered in our cost analysis. ^{632}
^{632} E-axles are an emerging technology that have potential to realize efficiency gains because they have fewer moving parts. Though we did not quantify their impact explicitly due to a lack of data and information at the time of our analysis and to remain technology-neutral, the technology can be used to comply with this regulation.
A few commenters disagreed with the cost used by EPA at proposal for the electric motor, providing values that were lower and higher than the proposal. One commenter references Roush reports of $8/kW for 2030 and 2032, much lower than EPA's value. Another commenter provided CBI values of e-axle costs. Another commenter cited an ICCT report that projected cost reductions of 60 percent by 2030 and that further projected that the price of electric powertrain systems, including the transmission, motor, and inverter, would reach $23/kW. Another commenter is concerned that the market will demand different ZEV architectures depending on the application (direct drive, e-axle, and portal axle) and that each of these technologies will have a different $/kW value due to differences in component costs and their respective manufacturing process.
For the final rule, we continue to include the direct manufacturing cost for e-drive in HD TRUCS. Similar to the battery cost, there is a range of electric drive cost projections available in the literature and per stakeholder comments. One reason for the disparity across the literature is what is included in each for the “electric drive”; some cost estimates include only the electric motor and others present a more integrated model of e-motor/inverter/gearbox combination. Another reason for the disparity is described by one of the commenters: the demand for e-drive will be different for different applications. As described in detail in RIA Chapter 2.4.3.2.1, EPA's MY 2027 e-motor cost, shown in Table II-15, comes from ANL's 2022 BEAN too and is a linear interpolation of the average of the high- and low-tech scenarios for 2025 and 2030, adjusted to 2022$. ^{633} We then calculated MY 2028-2032 per-unit cost from the power of the motor (RIA Chapter 2.4.1.2) and $/kW of the e-motor shown in Table II-15, and using an EPA estimate of market learning shown in RIA Chapter 3.2.1.
^{633} Argonne National Laboratory. VTO HFTO Analysis Reports—2022. “ANL—ESD-2206 Report—BEAN Tool—MD HD Vehicle Techno-Economic Analysis.xlsm”. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/folder/242640145714 .
Gearbox and final drive units are used to reduce the speed of the motor and transmit torque to the axle of the vehicle. In HD TRUCS for the proposal, we set the MY 2027 final drive DMC at $1,500/unit, based on ANL's 2022 BEAN model for vocational vehicles. ^{634} For tractors, the final drive cost is doubled the cost of vocational vehicles because in general they have additional drive axles. We did not receive any data to support different values, therefore, we adjusted the values used in the proposal to 2022$ and applied the ICE learning effects shown in RIA Chapter 3.2.1 for MY 2028 through MY 2032. ^{635} Final drive costs for BEVs are shown in RIA Chapter 2.4.3.2.
^{634} Argonne National Laboratory. VTO HFTO Analysis Reports—2022. “ANL—ESD-2206 Report—BEAN Tool—MD HD Vehicle Techno-Economic Analysis.xlsm”. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/folder/242640145714 .
^{635} For the final rule, we updated the learning curve for BEV (and FCEV) final drive costs to be consistent with the ICE learning curve since we are basing final drive costs on a component that is similar to an ICE vehicle final drive.
The cost of the gearbox varies depends on the vehicle weight class and duty cycle. In our assessment, all light heavy-duty BEVs are direct drive and have no transmission and no cost, consistent with ANL's 2022 BEAN model. We determined the gearbox costs for medium heavy-duty and heavy heavy-duty BEVs in HD TRUCS from ANL's BEAN tool. ^{636} BEV Gearbox costs are shown are in RIA Chapter 2.4.3.2.
^{636} Argonne National Laboratory. VTO HFTO Analysis Reports—2022. “ANL—ESD-2206 Report—BEAN Tool—MD HD Vehicle Techno-Economic Analysis.xlsm”. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/folder/242640145714 .
The costs of a power converter and electric accessories in HD TRUCS for both the proposal and final rule came from ANL's 2022 BEAN tool. ^{637} For the final rulemaking version of HD TRUCS, we updated the term Power Electronics to Power Converter, which represents the cost of a DC-DC converter ($1500 in 2020$). ^{638} DC-DC converters transfer energy ( i.e., they “step up” or “step down” voltage) between higher- and lower-voltage systems, such as from a high-voltage battery to a common 12V level for auxiliary uses. ^{639} We identified an additional cost in BEAN that we added as Auxiliary Converter. ^{640} We also revised the Electric Accessories costs to include both the electric accessories costs ($4500 in 2020$) and the vehicle propulsion architecture (VPA) costs ($186 in 2020$) from ANL's 2022 BEAN. These values were converted to 2022$ and include the BEV learning effects included in RIA Chapter 3.2 and are shown in RIA Chapter 2.4.3.2.
^{637} Argonne National Laboratory. VTO HFTO Analysis Reports—2022. “ANL—ESD-2206 Report—BEAN Tool—MD HD Vehicle Techno-Economic Analysis.xlsm”. Available online: https://anl.app.box.com/s/an4nx0v2xpudxtpsnkhd5peimzu4j1hk/folder/242640145714 .
^{638} In the 2022 version of BEAN, the “BEAN results” tab, this is also represented as “pc2 DC/DC booster”.
^{639} https://info.ornl.gov/sites/publications/Files/Pub136575.pdf .
^{640} In the 2022 version of BEAN, the “Cost & LCOD & CCM” tab, this is called a “pc1 DC/DC ESS”. In the “Autonomie Out” tab, this is linked to a DC/DC buck converter cost.
When using a Level 2 charging plug, an on-board charger converts AC power from the grid to usable DC power via an AC-DC converter. When using a D fast charger (DCFC), any AC-DC converter is bypassed, and the high-voltage battery is charged directly. The costs we used in the NPRM were based on ANL's BEAN model, which was $38 in MY 2027. ^{641} In the peer review of HD TRUCS, one reviewer noted that the value used in the NPRM was unrepresentative of the actual costs and suggested a cost of $600. ^{642} In light of this critique, EPA has increased the on-board charger costs to $600 in MY 2027, as further discussed in RIA Chapter 2.4.3.3. We then calculated the MY 2028-2032 costs using the learning curve shown in RIA Chapter 3.2.1.
^{641} Argonne National Lab, Vehicle & Mobility Systems Group, TechScape, found at: https://vms.taps.anl.gov/tools/techscape/ (accessed December 2023).
^{642} U.S. EPA. EPA Responses to HD TRUCS Peer Review Comments. February 2024.
The total upfront BEV direct manufacturing cost is the summation of the per-unit cost of the battery, motor, power electronics, on-board charger, gearbox, final drive, and accessories. The total direct manufacturing technology costs for BEVs for each of the 101 vehicle types in HD TRUCS can be found in RIA Chapter 2.4.3.5 for MY 2027, MY 2030, and MY 2032.
2. EVSE Costs
As described section II.D.5.iv, we used a mix of depot and public charging in our final rule analysis of HD BEV technologies for our technology packages to support the feasibility of the standards. In that analysis, most vocational vehicles and some lower travel, return-to-base day cab tractors rely on depot charging while long-haul vehicles (sleeper cab and longer-range day cab tractors) and coach buses utilize public charging starting with MY 2030. In HD TRUCS we evaluated BEVs for 97 of the 101 vehicle types. Of those, we assign depot charging costs to 89 vehicle types starting in MY 2027 and public charging costs to eight vehicle types starting in MY 2030.
In our analysis of depot charging infrastructure costs, we account for the cost to purchasers to procure both EVSE (which we refer to as the hardware costs) as well as costs to install the equipment. These installation costs typically include labor and supplies, permitting, taxes, and any upgrades or modifications to the on-site electrical service. We developed our EVSE cost estimates for the NPRM from available literature, looking at a range of costs (low to high) for each of the four EVSE types. As discussed in RIA Chapter 1.3.2, the IRA extends and modifies a Federal tax credit under section 30C of the Internal Revenue Code that could cover up to 30 percent of the costs for businesses to procure and install EVSE on properties located in low-income or non-urban census tracts if prevailing wage and apprenticeship requirements are met. ^{643} To reflect our expectation that this tax credit—as well as grants, rebates, or other funding available through the IRA—could significantly reduce the overall infrastructure costs paid by BEV and fleet owners for depot charging, we used the low end of our EVSE cost ranges in the NPRM infrastructure cost analysis. These values are summarized in Table II-16. We requested comment, including data, on our approach and assessment of current and future costs for charging equipment and installation. 88 FR 25982.
^{643} IRA section 13404, “Alternative Fuel Refueling Property Credit” under section 26 U.S.C. 30C, referred to as 30C in this document A $100,000 per item cap applies.
We received multiple comments about these costs. One industry commenter suggested that EPA should use the midpoint rather than the low end of our EVSE cost ranges. While one manufacturer commenter suggested our assumed EVSE installation costs were too high, other manufacturer commenters said that we underestimated costs for high-power EVSE. Another commenter suggested we should directly account for the savings from the 30C tax credit.
As described in RIA Chapter 2.6.2.1, we made several changes in how we estimate the EVSE costs incurred for depot charging in the final rule analysis. For the NPRM analysis, we developed the DCFC costs from a 2021 study (Borlaug et al. 2021) specific to heavy-duty electrification at charging depots. After reviewing new information on EVSE costs provided in comments as well as literature released since the publication of the NPRM, we determined it was appropriate to increase the underlying hardware and installation cost ranges we considered for DCFC-150 kW and DCFC-350 kW based on a new NREL study issued in 2023 to reflect the most up-to-date information available. ^{644} After further consideration, including consideration of comments on this issue and availability of a new DOE analysis ^{645} of the average value of the 30C tax credit for HD charging infrastructure, we have updated the depot EVSE costs in our final rule analysis to reflect a quantitative assessment of average savings from the tax credit.
^{644} Wood, Eric et al. “The 2030 National Charging Network: Estimating U.S. Light-Duty Demand for Electric Vehicle Charging Infrastructure,” 2023. Available at: https://driveelectric.gov/files/2030-charging-network.pdf .
^{645} U.S. DOE. “Estimating Federal Tax Incentives for Heavy Duty Electric Vehicle Infrastructure and for Acquiring Electric Vehicles Weighting Less Than 14,000 Pounds.” Memorandum, March 2024.
As noted, the 30C tax credit could cover up to 30 percent of the costs for fleets or other businesses to procure and install EVSE on properties located in low-income or non-urban census tracts if prevailing wage and apprenticeship requirements are met. DOE projects that businesses will meet prevailing wage and apprenticeship requirements in order to qualify for the full 30 percent tax credit, ^{646} and estimates that 60 percent ^{647} of depots will be located in qualifying census tracts based on its assessment of where HD vehicles are currently registered, the location of warehouses and other transportation facilities that may serve as depots, and the share of the population living in eligible census tracts. ^{648} Taken together, DOE estimates an average value of this tax credit of 18 percent of the installed EVSE costs at depots. We apply this 18 percent average reduction to the EVSE costs used in HD TRUCS for the final rulemaking (FRM).
^{646} As noted in DOE's assessment, the “good faith effort” clause applicable to the apprenticeship requirement suggests that it is unlikely that businesses will not be able to meet it and take advantage of the full 30 percent tax credit (if otherwise eligible).
^{647} This estimate may be conservative as DOE notes that its analysis did not factor in that fleets may choose to site depots at charging facilities in eligible census tracts to take further advantage of the tax credit. In addition, we note that DOE estimated 68 percent of heavy-duty vehicles are registered in qualifying census tracts suggesting the share of EVSE installations at depots that are eligible for the 30C tax credit could be higher.
^{648} U.S. DOE. “Estimating Federal Tax Incentives for Heavy Duty Electric Vehicle Infrastructure and for Acquiring Electric Vehicles Weighting Less Than 14,000 Pounds.” Memorandum, March 2024.
As noted, for the NPRM, we had used the low end of our EVSE cost ranges to reflect our expectation that the tax credit would significantly reduce EVSE costs to purchasers ( i.e., we used the low end to reflect typical EVSE hardware and installation costs less savings from the tax credit). Since we explicitly model the tax credit reductions for the FRM analysis, we determined it was appropriate to switch from using the low to the midpoint of EVSE cost ranges for all EVSE types to better reflect typical hardware and installation costs before accounting for the tax credit savings. The resulting hardware and installation costs for EVSE are shown in Table II-17 before and after applying the tax credit. We use values in the right column in our depot charging analysis.
Both hardware and installation costs could vary over time. For example, hardware costs could decrease due to manufacturing learning and economies of scale. Recent studies by ICCT assumed a 3 percent reduction in hardware costs for EVSE per year to 2030. ^{649 650} By contrast, installation costs could increase due to growth in labor or material costs. Installation costs are also highly dependent on the specifics of the site including whether sufficient electric capacity exists to add charging infrastructure and how much trenching or other construction is required. If fleet owners choose to install charging stations at easier, and therefore, lower cost sites first, then installation costs could rise over time as stations are developed at more challenging sites. One of the ICCT studies found that these and other countervailing factors could result in the average cost of a 150 kW EVSE port in 2030 being similar (~3 percent lower) to that in 2021. ^{651}
^{649} Minjares, Ray, Felipe Rodriguez, Arijit Sen, and Caleb Braun. “Infrastructure to support a 100% zero-emission tractor-trailer fleet in the United States by 2040”. Working Paper 2021-33. The International Council on Clean Transportation. September 2021. Available online: https://theicct.org/sites/default/files/publications/ze-tractor-trailer-fleet-us-hdvs-sept21.pdf .
^{650} Bauer, Gordon, Chih-Wei Hsu, Mike Nicholas, and Nic Lutsey. “Charging Up America: Assessing the Growing Need for U.S. Charging Infrastructure Through 2030”. The International Council on Clean Transportation, July 2021. Available online: https://theicct.org/wp-content/uploads/2021/12/charging-up-america-jul2021.pdf .
^{651} Bauer, Gordon, Chih-Wei Hsu, Mike Nicholas, and Nic Lutsey. “Charging Up America: Assessing the Growing Need for U.S. Charging Infrastructure Through 2030”. The International Council on Clean Transportation, July 2021. Available online: https://theicct.org/wp-content/uploads/2021/12/charging-up-america-jul2021.pdf .
After considering the uncertainty on how costs may change over time, we kept the combined hardware and installation costs per EVSE port constant for the NPRM analysis. We received only a few comments on this topic. Several commenters noted that EVSE equipment costs would likely decrease over time and one suggested we incorporate reductions to account for learning rates. However, the other commenters agreed with us that while hardware costs may decline in the future, installation costs could rise, and therefore they supported our approach to keep combined hardware and installation costs constant. For the final rule analysis we continued our proposed approach of not varying costs over time on the same bases included in the NPRM and it retains a conservative approach to EVSE costs.
How long a vehicle is off-shift and parked at a depot, warehouse, or other home base each day is a key factor in determining what type of charging infrastructure could meet its needs. We refer to this as depot dwell time. This depot dwell time depends on a vehicle's duty cycle. For example, a school bus or refuse truck may be parked at a depot in the afternoon or early evening and remain there until the following morning whereas a transit bus may continue to operate throughout the evening. Even for a specific vehicle, off-shift depot dwell times may vary between weekends and weekdays, by season, or due to other factors that impact its operation.
The vehicles in our depot charging analysis span a wide range of vehicle types and duty cycles, and we expect their dwell times to vary accordingly. In the NPRM, we used a dwell time of 12 hours for every type of HD vehicle informed by our examination of start and idle activity data ^{652} for 564 commercial vehicles. ^{653} In order to better understand how depot dwell times might vary by vehicle application and class for our final rule analysis, we worked with NREL through an interagency agreement between EPA and the U.S. Department of Energy. NREL analyzed several data sets for this effort: General Transit Feed Specification (GTFS) data for about 21,700 transit buses, ^{654} operating data for nearly 300 school buses from NREL's FleetDNA database, and a set of fleet telematics data from Geotab's Altitude platform covering about 13,600 medium- and heavy-duty trucks in seven geographic zones ^{655} selected to be nationally representative. ^{656} The truck dataset includes a variety of classes and vocations. As described in Bruchon et al. 2024, ^{657} NREL separately analyzed data for four class combinations (2b-3, 4-5, 6-7, and 8) and four vocations defined by vehicles' travel patterns (door to door, hub and spoke, local, and regional). This results in sixteen unique freight vehicle categories. ^{658}
^{652} Zhang, Chen; Kotz, Andrew; Kelly, Kenneth “Heavy-Duty Vehicle Activity for EPA MOVES.” National Renewable Energy Laboratory. 2021. Available online: https://data.nrel.gov/submissions/168 .
^{653} The dataset had been analyzed as a joint effort between EPA and NREL to inform EPA's MOVES model.
^{654} Both GTFS schedule and real-time data were utilized along with information from the National Transit Database.
^{655} The seven zones are: San Jose-Sunnyvale-Santa Clara, CA; Pittsburgh, PA; Evansville, IN-KY; Lafayette, LA; Janesville-Beloit, WI; Southern ID non-Metropolitan Statistical Areas (MSA); Eastern GA non-MSAs. Data used was collected between September 7 and September 30, 2022. See Bruchon et al. 2024 for details on variables used to select the seven representative zones.
^{656} Bruchon, Matthew, Brennan Borlaug, Bo Liu, Tim Jonas, Jiayun Sun, Nhat Le, Eric Wood. “Depot-Based Vehicle Data for National Analysis of Medium- and Heavy-Duty Electric Vehicle Charging”. National Renewable Energy Laboratory. NREL/TP-5400-88241. February 2024. Available online: https://www.nrel.gov/docs/fy24osti/88241.pdf .
^{657} Bruchon, Matthew, Brennan Borlaug, Bo Liu, Tim Jonas, Jiayun Sun, Nhat Le, Eric Wood. “Depot-Based Vehicle Data for National Analysis of Medium- and Heavy-Duty Electric Vehicle Charging”. National Renewable Energy Laboratory. NREL/TP-5400-88241. February 2024. Available online: https://www.nrel.gov/docs/fy24osti/88241.pdf .
^{658} NREL's report also includes information on a long-distance vocation. However, we have excluded these from our depot charging analysis because, as noted in Bruchon et al. 2024, the long-distance trucks in the sample are less likely to meet the criteria for depot-based travel.
Across all vehicle categories, NREL provided national dwell time distributions that describe the number of hours vehicles spend at their primary domicile (or depot). For each of the sixteen freight categories as well as for school buses, these dwell durations reflect the total daily hours vehicles spent at their depots on operational weekday or weekend days regardless of whether the vehicles were parked for one continuous period or across multiple stops throughout the day. For transit buses, NREL estimated the typical time buses spent when parked at their depot overnight, i.e., the time between the end of the last shift of the day and the first shift the following service day with separate estimates for weekdays, Saturdays, and Sundays. Days on which vehicles were not operated were excluded from the samples. ^{659}
^{659} In addition, total dwell durations for school buses were only considered during the school year and stops at the depot less than one hour were excluded.
As described in RIA Chapter 2.6.2.1.4, we mapped the depot dwell durations from the 18 unique combinations of vocations and class types ( i.e., the 16 freight vehicle categories plus transit and school buses) in NREL's analysis to the applicable vehicle types in our HD TRUCS model. As shown in Table 2-78 of the RIA, dwell times in HD TRUCS range from 7.4 hours to 14.5 hours, reflecting the wide range of vehicle types considered in our analysis. (See RIA Chapter 2.6.2.1.4 for a more detailed discussion of this analysis.)
For the NPRM, we assumed that each vehicle using Level 2 charging would have its own EVSE port, while up to two vehicles could share DCFC if charging needs could be met within the assumed dwell time. While one commenter asserted that it is unreasonable to assume two vehicles could share a DCFC port, and another supported our NPRM approach, we received several other comments that the constraints on EVSE sharing in our NPRM analysis were too limiting. In our final rule analysis, we updated our approach and project that up to two vocational vehicles can share one EVSE port. For tractors, which tend to be part of larger fleets, we project that up to four vehicles can share one EVSE port. However, in both cases, we only model vehicles as sharing EVSE ports if there is sufficient dwell time for each vehicle to meet its charging needs. We note that for some of the vehicle types we evaluated, higher numbers of vehicles could share EVSE ports and still meet their daily electricity consumption needs. However, in our final rule HD TRUCS analysis we limit sharing to two vocational vehicles and four tractors per port as a conservative approach for calculating EVSE costs per vehicle.
As discussed in section II.D.2.iii.c, EPA acknowledged at proposal that there could be additional infrastructure needs beyond those associated with the charging equipment itself. 88 FR 25982. Commenters emphatically agreed and focused on three areas of concern, electrical power generation, transmission, and distribution. Our consideration of comments and final rule analysis took a close look at power generation and transmission. Our analysis shows that systems and processes exist to handle the rule's impact on power generation and transmission, including when considered in combination with projections of other impacts on power generation and transmission based on our assessments at the time of this final rule. See RTC section 7.1; see also RIA Chapter 1.6. We also considered comments and took a close look at electrical grid distribution systems. A first of its kind Multi-State Transportation Electrification Impact Study (TEIS) was conducted by DOE to evaluate the potential that some geographic areas and some users will require grid distribution buildout updates, and to assess associated time and cost in recognition that, depending on the type of buildout needed, significant implementation time and cost could exist. ^{660} In the NPRM, we assumed that utilities would cover the electrical power, transmission, and distribution upgrade costs. DRIA 2.6.5.1. For our final rule analysis, we identify distribution buildout costs with the TEIS, power generation and transmission costs with the Integrated Planning Model (IPM) and Retail Price Model (RPM) run by ICF and account for these costs within the charging costs, as discussed in section II.E.5.ii. See generally section II.D.2.iii.c and RTC section 7 (Distribution).
^{660} National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Kevala Inc., and U.S. Department of Energy. “Multi-State Transportation Electrification Impact Study: Preparing the Grid for Light-, Medium-, and Heavy-Duty Electric Vehicles”. DOE/EE-2818. U.S. Department of Energy. March 2024.

3. FCEV Technology Costs
FCEVs and BEVs include many of the same components such as a battery pack, e-motor, power electronics, gearbox unit, final drive, and electrical accessories. Therefore, we used the same costs for these components across vehicles for the same applications; for detailed descriptions of these components, see RIA Chapter 2.4.3. In this subsection and RIA Chapter 2.5.2, we present the costs for components for FCEVs that are different from a BEV. These components include the fuel cell system and onboard hydrogen fuel tank. The same energy cell battery $/kWh costs used for BEVs are used for fuel cell vehicles, but the battery size of a comparable FCEV is smaller.

i. Fuel Cell System Costs
The fuel cell stack is the most expensive component of a fuel cell system, ^{661} which is the most expensive part of a heavy-duty FCEV, primarily due to the technological requirements of manufacturing rather than material costs. ^{662} Fuel cells for the heavy-duty sector are expected to be more expensive than fuel cells for the light-duty sector because they operate at higher average continuous power over their lifespan, which requires a larger fuel cell stack size, and because they have more stringent durability requirements ( i.e., to travel more hours and go longer distances). ^{663}
^{661} Papageorgopoulos, Dimitrios. “Fuel Cell Technologies Overview”. U.S. Department of Energy. June 6, 2023. Available online: https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/review23/fc000_papageorgopoulos_2023_o.pdf .
^{662} Deloitte China and Ballard. “Fueling the Future of Mobility: Hydrogen and fuel cell solutions for transportation, Volume 1”. 2020. Available online: https://www2.deloitte.com/content/dam/Deloitte/cn/Documents/finance/deloitte-cn-fueling-the-future-of-mobility-en-200101.pdf .
^{663} Marcinkoski, Jason et. al. “Hydrogen Class 8 Long Haul Truck Targets”. U.S. Department of Energy. October 31, 2019. Available online: https://www.hydrogen.energy.gov/pdfs/19006_hydrogen_class8_long_haul_truck_targets.pdf .
Projected costs vary widely in the literature. They are expected to decrease as manufacturing matures. Larger production volumes are anticipated as global demand increases for fuel cell systems for HD vehicles, which could improve economies of scale. ^{664} Costs are also anticipated to decline as durability improves. ^{665}
^{664} Deloitte China and Ballard. “Fueling the Future of Mobility: Hydrogen and fuel cell solutions for transportation, Volume 1”. 2020. Available online: https://www2.deloitte.com/content/dam/Deloitte/cn/Documents/finance/deloitte-cn-fueling-the-future-of-mobility-en-200101.pdf .
^{665} Deloitte China and Ballard. “Fueling the Future of Mobility: Hydrogen and fuel cell solutions for transportation, Volume 1”. 2020. Available online: https://www2.deloitte.com/content/dam/Deloitte/cn/Documents/finance/deloitte-cn-fueling-the-future-of-mobility-en-200101.pdf .
For the NPRM, we relied on an average of costs from an ICCT meta-study that found a wide variation in fuel cell costs in the literature. ^{666} The costs we used in the NPRM ranged from $200 per kW in MY 2030 to $185 per kW in MY 2032. We requested comment on our cost data projections in the proposal.
^{666} Sharpe, Ben and Hussein Basma. “A meta-study of purchase costs for zero-emission trucks”. International Council on Clean Transportation, Working Paper 2022-09. February 2022. Available online: https://theicct.org/publication/purchase-cost-ze-trucks-feb22/ .
Several commenters addressed EPA's estimates for fuel cell costs. CARB agreed with EPA's estimates, noting they used similar estimated values in their Advanced Clean Fleets rule proceeding. One commenter thought the NPRM fuel cell cost estimates were too high, particularly if they represent the fuel cell stack alone, based on targets published by the European Joint Undertaking. Another commenter stated that fuel stack technology is too nascent to make any type of realistic cost estimate. They noted that existing component technologies still need to be adapted for the HD market and that fuel cell stacks are not being produced at scale now, and they stated that they do not believe accurate HD FCEV technology costs can be predicted now. Several commenters said that EPA's estimates were too low and referred to fuel cell costs from a more recent (2023) ICCT White Paper ^{667} that updated the ICCT meta-study referenced in the NPRM. ^{668} See RTC section 3.4.3 for additional details.
^{667} Xie, et. al. “Purchase costs of zero-emission trucks in the United States to meet future Phase 3 GHG standards”. International Council of Clean Transportation, Working Paper 2023-10. March 2023. Available online: https://theicct.org/wp-content/uploads/2023/03/cost-zero-emission-trucks-us-phase-3-mar23.pdf .
^{668} Sharpe, Ben and Hussein Basma. “A meta-study of purchase costs for zero-emission trucks”. International Council on Clean Transportation, Working Paper 2022-09. February 2022. Available online: https://theicct.org/publication/purchase-cost-ze-trucks-feb22/ .
We reviewed the ICCT paper that several commenters referenced. Also, due to the wide range of projected costs in the literature, EPA contracted with FEV ^{669} to independently evaluate direct manufacturing costs of heavy-duty vehicles with alternative powertrain technologies and EPA conducted an external peer review of the final FEV report. ^{670} In the report, FEV estimated costs associated with a Class 8 FCEV-dominated long-haul tractor with graphite fuel cell stacks, which are more durable than stainless steel stacks typically used in light-duty vehicle applications. FEV leveraged a benchmark study of a commercial vehicle fuel cell stack from a supplier that serves the Class 8 market. They also built prototype vehicles in-house and relied on existing expertise to validate their sizing of tanks and stacks. ^{671} Please see RTC Chapter 3.4.3 for additional detail.
^{669} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
^{670} ICF. “Peer Review of HD Vehicles, Industry Characterization, Technology Assessment and Costing Report”. September 15, 2023.
^{671} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
For the final rule, as described in RIA Chapter 2.5.2.1, we established MY 2032 fuel cell system DMCs using cost projections from FEV and ICCT. We weighted FEV's work twice as much as ICCT's because it was primary research and because some of the volumes associated with the costs in ICCT's analysis were not transparent. We note that this method of weighting primary research more heavily than secondary research is generally appropriate for assessing predictive studies of this nature; indeed, it is consistent with what ICCT itself did. For FEV's work, we selected costs that align with the HD FCEV production volume that we project in our modeled potential compliance pathway's technology packages developed for this final rule, which is roughly 10,000 units per year in MY 2032, for a DMC of $89 per kW. For ICCT's work, we used the 2030 value of $301 per kW for MY 2032, since 2030 was the latest year of values referenced by ICCT from literature. Our weighted average yielded a MY 2032 fuel cell system DMC of $160 per kW. In order to project DMCs for earlier MYs from MY 2032, we used our learning rates shown in RIA Chapter 3.2.1. This yielded the MYs 2030 and 2031 DMCs shown in Table II-18.

ii. Onboard Hydrogen Fuel Tank Costs
Onboard hydrogen storage cost projections also vary widely in the literature. For the NPRM, we relied on an average of costs from the same ICCT meta-study that we used for fuel cell costs. ^{672} The values we used in the NPRM analysis ranged between $660/kg in MY 2030 and $612/kg in MY 2032. We requested cost data projections in the proposal.
^{672} Sharpe, Ben and Hussein Basma. “A meta-study of purchase costs for zero-emission trucks”. International Council on Clean Transportation, Working Paper 2022-09. February 2022. Available online: https://theicct.org/publication/purchase-cost-ze-trucks-feb22/ .
There were few comments on hydrogen fuel tank costs. Two commenters referred to ICCT's revised meta-study. ^{673} One commenter suggested that onboard liquid hydrogen will be required for long-distance ranges of over 500 miles in the longer-term and suggested that it is too soon to offer cost estimates for liquid tanks. See RTC section 3.4.3 for details.
^{673} Xie, et. al. “Purchase costs of zero-emission trucks in the United States to meet future Phase 3 GHG standards”. International Council of Clean Transportation, Working Paper 2023-10. March 2023. Available online: https://theicct.org/wp-content/uploads/2023/03/cost-zero-emission-trucks-us-phase-3-mar23.pdf .
Given our assessment of technology readiness for the NPRM, onboard liquid hydrogen storage tanks were not included in the potential compliance pathway that supports the feasibility and appropriateness of the standards.
Like fuel cell costs, onboard gaseous hydrogen tank costs are dependent on manufacturing volume. We reviewed the ICCT paper that several commenters referenced and contracted FEV ^{674} to independently evaluate onboard hydrogen storage tank costs for MY 2027 (2022$) based on manufacturing volume, and EPA conducted an external peer review of the final FEV report. ^{675} Please see RTC Chapter 3.4.3 for additional detail.
^{674} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
^{675} ICF. “Peer Review of HD Vehicles, Industry Characterization, Technology Assessment and Costing Report”. September 15, 2023.
Using the same approach taken for fuel cell system costs, as described in RIA Chapter 2.5.2.2, we established MY 2032 onboard storage tank DMCs using cost projections from FEV and ICCT. We weighted FEV's work twice as much as ICCT's because it was primary research and because some of the volumes associated with the costs in ICCT's analysis were not transparent. We note that this method of weighting primary research more heavily than secondary research is generally appropriate for assessing predictive studies of this nature; indeed, it is consistent with what ICCT itself did. For FEV's work, we selected costs for roughly 10,000 units per year in MY 2032, for a DMC of $504 per kg. For ICCT's work, we used the 2030 value of $844 per kW for MY 2032, since 2030 was the latest year of values referenced by ICCT from literature. Our weighted average yielded a MY 2032 fuel cell system DMC of $617 per kW. In order to project DMCs from MY 2032 for earlier MYs, we used our learning rates shown in shown in RIA Chapter 3.2.1. This yielded the MYs 2030 and 2031 DMCs shown in Table II-19.

4. Inflation Reduction Act Tax Credits for HD Battery Electric Vehicles
The IRA, ^{676} which was signed into law on August 16, 2022, includes a number of provisions relevant to vehicle electrification. There are three provisions of the IRA we included within our quantitative analysis in HD TRUCS related to the manufacturing and purchase of HD BEVs and FCEVs. First, section 13502, “Advanced Manufacturing Production Credit,” provides up to $45 per kWh tax credits under section 45X of the Internal Revenue Code (“45X”) for the production and sale of battery cells and modules when the cells and modules are produced in the United States and other qualifications are met. Second, section 13403, “Qualified Commercial Clean Vehicles,” provides for a vehicle tax credit under section 45W applicable to HD vehicles if certain qualifications are met. Third, after further consideration, including consideration of comments on this issue, we have quantitatively analyzed section 13404, “Alternative Fuel Refueling Property Credit,” tax credit under 30C for EVSE costs for the final rule. See section II.E.2 of this preamble, and IRA sections 13403, 13502, and 13404. Beyond these three tax credits, there are numerous provisions in the IRA and the BIL ^{677} that may impact HD vehicles and increase adoption of HD ZEV technologies. These range from tax credits across the supply chain, to grants which may help direct ZEVs to communities most burdened by air pollution, to funding for programs to build out electric vehicle charging infrastructure, as described in section I of this preamble and RIA Chapter 1.3.2.
^{676} Inflation Reduction Act of 2022, Pub. L. 117-169, 136 Stat. 1818 (2022) (“Inflation Reduction Act” or “IRA”), available at https://www.congress.gov/117/bills/hr5376/BILLS-117hr5376enr.pdf .
^{677} United States, Congress. Public Law 117-58. Infrastructure Investment and Jobs Act of 2021. Congress.gov, www.congress.gov/bill/117th-congress/house-bill/3684/text . 117th Congress, House Resolution 3684, passed 15 November 2021.
Regarding the first of the provisions, IRA section 13502, “Advanced Manufacturing Production Credit,” provides up to $45 per kWh tax credits under 45X for the production and sale of battery cells (up to $35 per kWh) and modules or packs ^{678} (up to $10 per kWh) and 10 percent of the cost of producing critical minerals such as those found in batteries, when such components or minerals are produced in the United States and other qualifications are met as described in RIA Chapter 1.3.2.2. These credits begin in CY 2023 and phase down starting in CY 2030, ending after CY 2032. As further discussed in RIA Chapter 2.4.3.1, we recognize that there are currently few manufacturing plants specifically for HD vehicle batteries in the United States. We expect that the industry will respond to this tax credit incentive by building more domestic battery manufacturing capacity in the coming years, in part due to the BIL and IRA. For example, Daimler Trucks, Cummins, and PACCAR recently announced a new joint venture for a 21 GWh factory to be built in the U.S. to manufacture cells and packs initially focusing on LFP batteries for heavy-duty and industrial applications. ^{679} Tesla is expanding its facilities in Nevada to produce its Semi BEV tractor and battery cells ^{680} and Cummins has entered into an agreement with Arizona-based Sion Power to design and supply battery cells for commercial electric vehicle applications. ^{681} See the additional discussion in section II.D.2.ii of this preamble, and RTC section 17.2 (battery production) for further discussion and examples. Additionally, the DOE has conducted an analysis of public announcements that shows that in 2027-2032, there will be sufficient domestic battery manufacturing capacity for the HD industry to produce cells and modules that meet the requirements of the 45X tax credit and to supply the volumes we project in this final rulemaking. ^{682} Furthermore, DOE is funding through the BIL battery materials processing and manufacturing projects to “support new and expanded commercial-scale domestic facilities to process lithium, graphite and other battery materials, manufacture components, and demonstrate new approaches, including manufacturing components from recycled materials.” ^{683}
^{678} Packs would be eligible for the credit under the proposed interpretation. See 88 FR 86851.
^{679} Daimler Trucks North America. “Accelera by Cummins, Daimler Truck and PACCAR form a joint venture to advance battery cell production in the United States.” September 6, 2023. Available online: https://media.daimlertruck.com/marsMediaSite/en/instance/ko/Accelera-by-Cummins-Daimler-Truck-and-PACCAR-form-a-joint-venture-to-advance-battery-cell-production-in-the-United-States.xhtml?oid=52385590 (last accessed October 23, 2023).
^{680} Sriram, Akash, Aditya Soni, and Hyunjoo Jin. “Tesla plans $3.6 bln Nevada expansion to make Semi truck, battery cells.” Reuters. January 25, 2023. Last accessed on March 31, 2023 at https://www.reuters.com/markets/deals/tesla-invest-over-36-bln-nevada-build-two-new-factories-2023-01-24/.
^{681} Sion Power. “Cummins Invests in Sion Power to Develop Licerion® Lithium Metal Battery Technology for Commercial Electric Vehicle Applications”. November 30, 2021. Available online: https://sionpower.com/2021/cummins-invests-in-sion-power-to-develop-licerion-lithium-metal-battery-technology-for-commercial-electric-vehicle-applications/ .
^{682} Kevin Knehr, Joseph Kubal, Shabbir Ahmed, “Cost Analysis and Projections for U.S.-Manufactured Automotive Lithium-ion Batteries”, Argonne National Laboratory report ANL/CSE-24/1 for US Department of Energy. January 2024. Available online: https://www.osti.gov/biblio/2280913 .
^{683} U.S. Department of Energy. “Bipartisan Infrastructure Law: Battery Materials Processing and Battery Manufacturing & Recycling Funding Opportunity Announcement—Factsheets”. October 19, 2022. Available online: https://www.energy.gov/sites/default/files/2022-10/DOE%20BIL%20Battery%20FOA-2678%20Selectee%20Fact%20Sheets%20-%201_2.pdf .
In the NPRM, we projected that the tax credit earned by battery cell and module manufacturers is passed through to the purchaser because market competition would drive manufacturers to minimize their prices. We received comment on this projection from three commenters, questioning how much of the credit will be passed down from battery cell and module manufacturers through the supply chain to the ultimate purchaser because of the large upfront investments required to build manufacturing plants. In an interview with Axios following Daimler Trucks, Cummins, and PACCAR's recently announced battery factory, ^{684} Cummins noted that the 45X tax credit “is expected to benefit customers by lowering the price of batteries.” ^{685} After consideration of these comments and the literature and announcements described in the previous paragraph, we are continuing to include the tax credits in our assessment of purchaser costs. We maintain our modeling approach for this tax credit in HD TRUCS such that HD BEV and FCEV manufacturers fully utilize the battery module tax credit and gradually increase their utilization of the cell tax credit for MYs 2027-2029 until MY 2030 and beyond, when they earn 100 percent of the available cell and module tax credits. The battery pack costs and battery tax credits used in our analysis are shown in Table II-20. Further discussion of these assumptions can be found in RTC section 2.7.
^{684} Daimler Trucks North America. “Accelera by Cummins, Daimler Truck and PACCAR form a joint venture to advance battery cell production in the United States.” September 6, 2023. Available online: https://media.daimlertruck.com/marsMediaSite/en/instance/ko/Accelera-by-Cummins-Daimler-Truck-and-PACCAR-form-a-joint-venture-to-advance-battery-cell-production-in-the-United-States.xhtml?oid=52385590 (last accessed October 23, 2023).
^{685} Geman, Ben. “How Biden's climate law is fueling the U.S. battery boom.” Axios. September 7, 2023. Last accessed on November 2, 2023 at: https://www.axios.com/2023/09/07/battery-boom-daimler-blackrock .
Similar to our approach in using indirect cost multipliers to calculate retail price equivalents, in which we do not attempt to mirror, predict, or otherwise approximate individual companies' marketing strategies in estimating costs for the modeled potential compliance pathway (see section IV of this preamble), we do not attempt to predict specifically how manufacturers will use the 45X tax credit to alter their products' prices. Instead, we estimate the costs we expect to be incurred by manufacturers for the modeled potential compliance pathway—including direct manufacturing costs, indirect costs, and tax credits—and calculate the resulting retail price equivalents that would allow manufacturers to fully recover their costs of compliance. Regarding the second of the provisions, IRA section 13403 creates a tax credit under 45W of the Internal Revenue Code applicable to each purchase of a qualified commercial clean vehicle. These vehicles must be on-road vehicles (or mobile machinery) that are propelled to a significant extent by a battery-powered electric motor. The battery must have a capacity of at least 15 kWh (or 7 kWh if it is Class 3 or below) and must be rechargeable from an external source of electricity. This limits the qualified vehicles to BEVs and PHEVs. Additionally, FCEVs are eligible. The credit is available from CY 2023 through 2032, which overlaps with the model years for which we are finalizing standards (MYs 2027 through 2032), so we included the tax credit in our calculations for each of those years in HD TRUCS.
For BEVs and FCEVs, the tax credit is equal to the lesser of: (A) 30 percent of the BEV or FCEV cost, or (B) the incremental cost of a BEV or FCEV when compared to a comparable ICE vehicle. The limit of this tax credit is $40,000 for Class 4-8 commercial vehicles and $7,500 for commercial vehicles Class 3 and below. For example, if a BEV costs $350,000 and a comparable ICE vehicle costs $150,000, ^{686} the tax credit would be the lesser of: (A) 0.30 × $350,000 = $105,000 or (B) $350,000—$150,000 = $200,000. In this example, (A) is less than (B), but (A) exceeds the limit of $40,000, so the tax credit would be $40,000.
^{686} Sharpe, B., Basma, H. “A meta-study of purchase costs for zero-emission trucks”. International Council on Clean Transportation. February 17, 2022. Available online: https://theicct.org/wp-content/uploads/2022/02/purchase-cost-ze-trucks-feb22-1.pdf .
We received numerous comments on this 45W tax credit. Many commenters noted the potential for this tax credit to help reduce costs of ZEVs for the purchaser, with commenters differing in their assessment of how competitive the costs of ZEVs would be compared to prices of ICE vehicles after earning the tax credit. For example, one commenter stated that IRA incentives, including the 45W tax credit, would bring total cost of ownership of electric trucks lower than diesel trucks approximately five years sooner than without the law. In contrast, other commenters asserted that the tax credit could easily be offset by Federal excise and state taxes, let alone the increased cost of the ZEV without considering taxes. Additionally, one commenter questioned whether purchasers with limited tax liabilities would be able to leverage the tax credit.
Regarding this last concern that limited tax liabilities would reduce purchaser's ability to leverage the tax credit, we note that the Internal Revenue Service (IRS) has stated that a 45W credit can be carried over as a general business credit and that unused general business credits may be carried back one year and carried forward to each of the 20 tax years after the year of the credit to help offset prior and future tax liabilities. 687 688 Additionally, for applicable entities who can use elective pay, including tax-exempt organizations, States, and political subdivisions such as local governments, Indian tribal governments, Alaska Native Corporations, the Tennessee Valley Authority, rural electric co-operatives, U.S. territories and their political subdivisions, and agencies and instrumentalities of state, local, tribal, and U.S. territorial governments, the value of the credit can be paid by the IRS to the applicable entity. 689 690 Our inclusion of the Federal excise tax (which imposes a Federal tax liability associated with the purchase of a ZEV), the long credit life as a general business credit, and the elective pay provisions support our application of the credit to all eligible vehicle sales in our analysis.
^{687} Internal Revenue Service. “Commercial Clean Vehicle Credit.” February 16, 2024. Last accessed on March 18, 2024. Available at: https://www.irs.gov/credits-deductions/commercial-clean-vehicle-credit .
^{688} Internal Revenue Service. “Instructions for Form 3800 (2022).” February 8, 2024. Last accessed on March 18, 2024. Available at: https://www.irs.gov/instructions/i3800 .
^{689} Internal Revenue Service. “Elective pay and transferability.” March 5, 2024. Last accessed on March 18, 2024. Available at: https://www.irs.gov/credits-deductions/elective-pay-and-transferability.
^{690} Internal Revenue Service. “Elective Pay and Transferability Frequently Asked Questions: Elective Pay.” March 11, 2024. Last accessed on March 18, 2024. Available at: https://www.irs.gov/credits-deductions/elective-pay-and-transferability-frequently-asked-questions-elective-pay#eligibility .
We maintain our NPRM approach to modeling this tax credit. We included this tax credit in HD TRUCS by decreasing the incremental upfront cost a vehicle purchaser must pay for a ZEV compared to a comparable ICE vehicle following the process explained in the previous two paragraphs. The calculation for this tax credit was done after applying a retail price equivalent to our direct manufacturing costs. We did not calculate the full cost of vehicles in our analysis; instead, we determined that all Class 4-8 ZEVs could be eligible for the full $40,000 (or $7,500 for ZEVs Class 3 and below) if the incremental cost calculated compared to a comparable ICE vehicle was greater than that amount. In order for this determination to be true, all Class 4-8 ZEVs must cost more than $133,333 such that 30 percent of the cost is at least $40,000 (or $25,000 and $7,500, respectively, for ZEVs Class 3 and below), which seems reasonable based on our assessment of the literature. 691 692 As in the calculation described in the previous paragraph, both (A) and (B) are greater than the tax credit limit and the vehicle purchaser may receive the full tax credit. The incremental cost of a ZEV taking into account the tax credits for each vehicle segment in MY 2027 and MY 2032 are included in RIA Chapter 2.9.2.
^{691} Burnham, A., Gohlke, D., Rush, L., Stephens, T., Zhou, Y., Delucchi, M. A., Birky, A., Hunter, C., Lin, Z., Ou, S., Xie, F., Proctor, C., Wiryadinata, S., Liu, N., Boloor, M. “Comprehensive Total Cost of Ownership Quantification for Vehicles with Different Size Classes and Powertrains”. Argonne National Laboratory. April 1, 2021. Available at https://publications.anl.gov/anlpubs/2021/05/167399.pdf .
^{692} The Department of Energy published an “Incremental Purchase Cost Methodology and Results for Clean Vehicles” that estimates representative vehicle costs for broad vehicle types relevant to this rulemaking: Class 4-6, Class 7, and Class 8 ICE vehicles, BEVs, PHEVs, and FCEVs. The report indicates that Class 7 and 8 ZEVs cost more than $133,333, while Class 4-6 ZEVs cost less than $133,333. While this assessment conflicts with our simplifying assumption for Class 4-6 ZEVs, we note that our Class 4-6 ZEVs' 45W tax credits, as shown in RIA Chapter 2.9.2, are mostly projected to be limited by a wide margin by the incremental costs and not the $40,000 limit affected by this assumption. The exceptions to this are the recreational vehicles, which we do not project as having significant ZEV adoption due to their lengthy payback periods, even with the full $40,000 tax credit. Department of Energy, “Incremental Purchase Cost Methodology and Results for Clean Vehicles”. December 2023. Available online: https://www.energy.gov/sites/default/files/2023-12/2023.12.18%20Incremental%20Purchase%20Cost%20Methodology%20and%20Results%20for%20Clean%20Vehicles%20pub%2012-2022%20amd%2012-2023%20Final_2.pdf.

5. Purchaser Costs
Operating costs for HD vehicles encompass a variety of costs, such as labor, insurance, registration fees, fueling, maintenance and repair (M&R), and other costs. For this HD TRUCS analysis, we are primarily interested in costs that are different for a comparable diesel-powered ICE vehicle and for a ZEV. ^{693} These operational cost differences are used to calculate an estimated payback period in HD TRUCS. We expect fueling costs and M&R costs to be different for ZEVs than for comparable diesel-fueled ICE vehicles and included these costs in our analysis to support the NPRM. Some commenters pointed out that we should also include insurance cost. For the final rule HD TRUCS analysis, operating costs are calculated each year as a summation of the annual fuel cost, maintenance and repair costs, insurance cost, and additional ZEV registration fee. In addition, for the final rule we considered the cost impact of the Federal excise tax and state sales tax to the operator at the time of purchase after consideration of the comments we received. Each of the following subsections include the costs for ICE vehicles, BEVs, and FCEVs.
^{693} For diesel-fueled ICE vehicles, we also estimated the cost of the diesel exhaust fluid (DEF) required for the selective catalytic reduction aftertreatment system. See RIA Chapter 2.3.4.1 for DEF costs.

i. Maintenance and Repair (M&R) Costs
M&R costs contribute to the overall operating costs for HD vehicles. Data on real-world M&R costs for HD ZEVs is limited due to limited HD ZEV technology adoption today. We expect the overall maintenance costs to be lower for ZEVs compared to a comparable ICE vehicle for several reasons. First, an electric powertrain has fewer moving parts that accrue wear or need regular adjustments. Second, ZEVs do not require fluids such as engine oil or diesel exhaust fluid (DEF), nor do they require exhaust filters to reduce particulate matter or other pollutants. Third, the per-mile rate of brake wear is expected to be lower for ZEVs due to regenerative braking systems. Several literature sources propose applying a scaling factor to diesel vehicle maintenance costs to estimate ZEV maintenance costs. 694 695 696
^{694} Burnham, A., Gohlke, D., Rush, L., Stephens, T., Zhou, Y., Delucchi, M. A., Birky, A., Hunter, C., Lin, Z., Ou, S., Xie, F., Proctor, C., Wiryadinata, S., Liu, N., Boloor, M. “Comprehensive Total Cost of Ownership Quantification for Vehicles with Different Size Classes and Powertrains”. Argonne National Laboratory. April 1, 2021. Available online: https://publications.anl.gov/anlpubs/2021/05/167399.pdf .
^{695} Hunter, Chad, Michael Penev, Evan Reznicek, Jason Lustbader, Alicia Birkby, and Chen Zhang. “Spatial and Temporal Analysis of the Total Cost of Ownership for Class 8 Tractors and Class 4 Parcel Delivery Trucks”. National Renewable Energy Lab. September 2021. Available online: https://www.nrel.gov/docs/fy21osti/71796.pdf .
^{696} Burke, Andrew, Marshall Miller, Anish Sinha, et. al. “Evaluation of the Economics of Battery-Electric and Fuel Cell Trucks and Buses: Methods, Issues, and Results”. August 1, 2022. Available online: https://escholarship.org/uc/item/1g89p8dn .
EPA indicated at proposal that HD ZEVs would experience significant maintenance and repair savings vis-a-vis their ICE counterparts. This finding was based on these vehicles' simpler design, notably absence of pistons and valves, and fewer moving parts in general. ^{697} Multiple commenters agreed that ZEV purchasers would experience cost savings due to lower maintenance and repair costs. Other commenters questioned EPA's finding. These commenters maintained that it would take two technicians rather than one to service an HD BEV. In addition, they stated that mechanics will require safety training for ZEV maintenance and repair, and that EPA had failed to account for the associated costs. Another question raised in these comments is whether there are sufficient technicians qualified to service HD ZEVs. Other commenters said that maintenance facility upgrades will be needed in order to service ZEVs and that such upgrades are a cost of the rule.
^{697} 88 FR 25986-87.
Several of these commenters went on to challenge the empirical basis for EPA's estimates. In HD TRUCS, ZEV maintenance and repair costs are estimated by first calculating the baseline diesel maintenance and repair costs and then by applying BEV and FCEV downward scaling factors based on Wang, et al. ^{698} so that cost savings are the product of the diesel maintenance and repair costs times the scaling factor. Several commenters criticized EPA for (purportedly) relying on a single source for the ZEV scaling factors, and further, that the source itself quotes a large range of potential values for those factors. One commenter also noted a multi-year study of light-duty electric vehicles which showed maintenance costs averaging 2.3 times that of ICE vehicles due to the longer maintenance time and lack of qualified technicians.
^{698} Wang, Guihua et al. “Estimating Maintenance and Repair Costs for Battery Electric and Fuel Cell Heavy Duty Trucks”. Available online: https://escholarship.org/uc/item/36c08395 .
ZEV vehicles have fewer moving parts than their ICEV counterparts, which is typically indicative of fewer serviceable parts and fewer potential failures. EPA reiterates that this will result in reduced costs for maintenance and repair for their users. This conclusion has ample support. Multiple cost assessment papers and the California Advanced Clean Fleets Regulation Appendix G: Total Cost of Ownership ^{699} use cost reduction factors for ZEV maintenance compared to internal combustion engine maintenance.
^{699} https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2022/acf22/appg.pdf . See section 4, pages G-21—G-23.
However, there are considerations of when those savings will accrue. EPA agrees with commenters that there is some uncertainty in predicting cost reductions for maintenance and repair of ZEV heavy-duty vehicles before production and usage become more common. A further uncertainty involves a potential need to retrain technicians to work on ZEVs.
EPA has adjusted its cost estimates to reflect consideration of these uncertainties. We agree that there may be a transition period during which costs for maintaining and repairing ZEVs will not be at their full savings potential due to the need to train more of the workforce to maintain and repair ZEVs. To account for this period, in this final rule HD TRUCS analysis EPA has phased in the ZEV scaling factors for maintenance and repair. Specifically, instead of applying a single scaling factor for every year commencing in 2027 (for BEVs) or 2030 (for FCEVs) as at proposal, EPA is starting with a higher scaling factor and gradually decreasing it ( i.e., gradually increasing the projected cost savings) over a 5-year period. The initial higher scaling factor comes from Wang et al. and reflects estimates for 2022. EPA's approach of applying this factor commencing in 2027 or 2030 is consequently conservative given that technicians in those later years will be more experienced than they were in 2022.
The criticism that EPA used a single source to derive the scaling factors does not paint a full picture of EPA's selection of these values. EPA examined multiple papers with proposed scaling factors. ^{700} We selected the values in the Wang et al. paper because its methodology was supported by a ground-up assessment of the differences in BEV, FCEV and diesel components, and the cost reduction (scaling factor) values in the paper fall within the range of other suggested scaling factor values in the literature.
^{700} See EPA's Draft Regulatory Impact Analysis: Greenhouse Gas Emissions for Heavy-Duty Vehicles: Phase 3. EPA-420-D-23-004. April 2023. Page 265 and sources cited in endnotes 93, 94, and 95.
In this final rule HD TRUCS analysis, EPA has made a further change involving cost estimates for ICE vehicle maintenance and repair costs—the baseline to which the scaling factors are applied for cost estimation purposes—a change not requested in comments but one we think is warranted. In the NPRM analysis, we developed the ICE vehicle M&R costs based on two different equations—one for sleeper cab tractors which travel longer distances and one for vocational vehicles and day cab tractors. The value used for vocational vehicles in the NPRM includes a higher cents per mile value than the one used for sleeper cab tractors. For the final rule analysis, we used the lower cents per mile M&R value for sleeper cabs for all HD vehicles. This change reduced the overall maintenance cost estimates for diesel vehicles, which in turn reduces the overall estimated savings from ZEV M&R for users under the potential compliance pathway that supports the feasibility of the final standards, since the savings values are estimated as a cost reduction from the diesel maintenance and repair values. An explanation for the basis for this change is set out in RTC section 3.6. Lowering the diesel maintenance and repair costs, along with phasing in the ZEV scaling factors, together resulted in a substantial reduction in estimated ZEV maintenance and repair savings in the final rule compared to the NPRM.
The article cited by one commenter from Kelly Blue Book ^{701} refers to an analysis of light-duty, not heavy-duty, vehicles. ^{702} While this article says that a predictive analytics firm, We Predict, found that EVs “cost more to repair than their gasoline engine counterparts”, that article also states that that “EVs cost less in maintenance because they have fewer regular maintenance procedures.” The reason it finds that EVs are more expensive is because technicians are spending more time working on EVs than they are on gasoline cars, and that those technicians cost more per hour. As noted, EPA understands that costs for servicing ZEVs may be more expensive in the very near term than they will be once technicians are retrained and have gained some experience; EPA expects the service technician workforce to transition to a workforce that has the skills and experience needed to service ZEVs. The Kelly Blue Book article supports EPA's expectation: the article states that We Predict “believes that EVs may prove less expensive in the long run.” The article goes on to quote the We Predict CEO, James Davies, “The cost of keeping the vehicle in service for the EV, even as the EV gets older, becomes smaller and smaller and actually less than keeping an ICE [internal combustion engine] vehicle on the road. . .That's not just maintenance costs, but all service costs.” ^{703}
^{701} https://www.kbb.com/car-news/study-evs-cost-more-to-repair-less-to-maintain/.
^{702} Heavy-duty ICE vehicle maintenance and repair may have some correlation with light-duty maintenance and repair, but the comparison does not consider the maintenance and repair costs of diesel engine and exhaust aftertreatment systems which are greater than the costs associated with light-duty vehicles.
^{703} https://www.kbb.com/car-news/study-evs-cost-more-to-repair-less-to-maintain/.
The M&R BEV scaling factors used to support the final rule analysis are shown in Table II-21.
EPA agrees that when new products are introduced dealers may encounter new costs, such as technician training to repair ZEVs. EPA therefore accounts for these costs in the RPE multipliers. EPA's heavy-duty retail price equivalent (RPE) mark-up includes a 6 percent markup over manufacturing cost for Dealer new vehicle selling costs. See section IV.B.2 of this preamble for further discussion.

ii. Fuel, Charging, and Hydrogen Costs
The annual fuel cost for operating a diesel-fueled ICE vehicle is a function of its yearly fuel consumption and the cost of diesel fuel. The yearly fuel consumption is described in RIA Chapter 2.3.4.3. As we did in the NPRM, we used the DOE Energy Information Administration's (EIA) Annual Energy Outlook (AEO) transportation sector reference case projection for diesel fuel for on-road use for diesel prices. ^{704} For the final rule analysis, we updated to the latest version of AEO 2023. These fuel prices include Federal and State taxes but exclude county and local taxes.
^{704} U.S. Energy Information Administration. Annual Energy Outlook 2023. Table 57 Components of Selected Petroleum Product Prices. Diesel Fuel End User Price. Last accessed on 12/2/2023 at https://www.eia.gov/outlooks/aeo/data/browser/#/?id=70-AEO2023&cases=ref2023&sourcekey=0.
We note at the outset HD BEV related power generation and transmission actions and their costs are insignificant when compared to historical levels of total power generation. See section II.D.2.iii of this preamble and RTC section 7 (Distribution). Some commenters agreed that the projected power and transmission needs for HD BEVs is achievable, especially when the gradual increase is recognized. Some other commenters applied different analysis to generate significant power level increases. As discussed in section V, we model changes to power generation due to the increased electricity demand anticipated under the potential compliance pathway in the final rule as part of our upstream analysis. We project the additional generation needed to meet the demand of the heavy-duty BEVs in the final rule to be relatively modest (as shown in RIA Chapter 6.5); the final rule is estimated to increase electric power end use by heavy-duty electric vehicles by 0.1 percent in 2027 and increasing to 2.8 percent in 2055. This is consistent with estimates from the utility industry itself, ^{705} and from manufacturers. ^{706} As a comparison, the U.S. electricity end use between the years 1992 and 2021, a similar number of years included in our analysis, increased by around 25 percent ^{707} without any adverse effects on electric grid reliability or electricity generation capacity shortages. See also RTC section 7.1.
^{705} Comments of Edison Electric Institute, additionally summarized and discussed in RTC section 7 (Distribution) and 7.1.
^{706} See, e.g., Comments of DTNA, EPA-HQ-OAR-2022-0985, pp. 52-53.
^{707} Annual Energy Outlook 2022, U.S. Energy Information Administration, March 3, 2022 ( https://www.eia.gov/outlooks/aeo/narrative/introduction/sub-topic-01.php. )
We do agree that there can be costs associated with distribution grid buildout, and with public charging networks associated with BEV HDV charging. EPA agrees with commenters that these costs should be included in our analysis and we have done so in the final rule analysis. We agree with commenters that suggested these costs could be reflected in the cost of fuel i.e., in the charging cost—rather than as capital (upfront) costs. Although there is considerable uncertainty associated with future distribution system upgrades and costs, our final rulemaking analysis, which incorporates findings from TEIS, suggests that the cost, when spread over the appropriate timeframe and user base, is modest. ^{708} Utilities will have various mechanisms to recoup their expenditures on grid distribution infrastructure. The process chosen by any given utility may depend on the size and financial resources of the utility or it may be driven by regulatory rules and direction. For the analysis in this final rule, we are including grid infrastructure as recouped through charging costs. Details on electricity distribution system costs and resulting charging costs are provided in this section and in RIA Chapter 2.4.4.2.
^{708} National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Kevala Inc., and U.S. Department of Energy. “Multi-State Transportation Electrification Impact Study: Preparing the Grid for Light-, Medium-, and Heavy-Duty Electric Vehicles”. DOE/EE-2818. U.S. Department of Energy. March 2024.
The annual charging cost for operating a HD electric vehicle is a function of the electricity price, daily energy consumption of the vehicle, and number of operating days in a year. For the NPRM we used the DOE EIA AEO 2022 reference case commercial electricity end-use rate projection for our electricity price. ^{709} We received comments that this approach may underestimate charging costs experienced by BEV owners. One commenter noted that we should account for the impact of increased BEV demand on future electricity prices. Several commenters discussed the impact of high demand charges on electricity price. Other commenters noted that there are additional costs that could increase the effective cost to charge including EVSE maintenance costs. Some commenters noted that vehicles using public charging could likely incur higher costs to charge than those at depots.
^{709} U.S. Department of Energy, Energy Information Administration. Annual Energy Outlook 2023, Table 8: Electricity Supply, Disposition, Prices, and Emissions. Last accessed on 10/30/2023. Available online: https://www.eia.gov/outlooks/aeo/data/browser/#/?id=8-AEO2023&cases=ref2023&sourcekey=0.
EPA agrees that our approach in the NPRM underestimated charging costs and we have increased the electricity prices used in HD TRUCS for the final rule analysis. We also agree with commenters that EVSE maintenance costs and distribution upgrade costs due to increased BEV demand should be taken into account, and that incorporating these into the charging costs is a reasonable approach; we have done so in HD TRUCS for the final rule analysis.
For the final rule, in HD TRUCS we differentiate between depot charging and public charging when assigning charging costs. As explained, we have also expanded the scope of what is covered in these costs to better reflect the cost of charging. The charging costs we use for both charging types include the cost of electricity as charged by the utility ($/kWh) as well as additional costs for EVSE maintenance and distribution upgrades (expressed in $/kWh) when those upgrades are needed. Our public charging price additionally includes amortized cost of public charging equipment and land costs for the station; ^{710} and we project that third parties may install and operate these stations and pass costs onto BEV owners via charging costs.
^{710} As discussed in section II.E.2, capital costs for EVSE used in depot charging are accounted for separately. We make the simplifying assumption that fleets will utilize existing parking depots when installing EVSE and therefore will not incur additional costs for purchasing or leasing land.
To estimate charging costs, we start by modeling future electricity prices, as charged by utilities, that account for the costs of BEV charging demand and the associated distribution system upgrade costs. We do this in three steps: (1) we model future power generation using the Integrated Planning Model (IPM), (2) we estimate the cost of distribution system upgrades associated with charging demand through the DOE Multi-State Transportation Electrification Impact Study (TEIS), ^{711} and (3) we use the Retail Price Model to project electricity prices accounting for both (1) and (2).
^{711} See preamble section II.D.2.c.iii and RTC section 7 (Distribution) for a fuller description of the TEIS.
As described in RIA Chapter 4.2, IPM models the power sector, including changes to power generation based on future demand scenarios. In order to capture the potential future impacts on the power sector from zero-emission vehicles, we ran IPM for a scenario that combined electricity demand from an interim version of the final standards case and EPA's proposed rulemaking “Multi-Pollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles.” ^{712} The same demand scenario was used as the action case for the TEIS. ^{713} The TEIS research team modeled how many new or upgraded substations, feeders, and transformers would be needed to meet projected electricity demand, including demand from residential workplace, depot, and public charging to support projected light-, medium-, and heavy-duty plug-in electric vehicles. For all public and workplace charging, vehicles were assumed to charge upon arrival at full power. At homes and depot charging stations—where vehicles have longer dwell times—a managed charging scenario was developed to spread out charging and reduce peak power. (See RIA Chapter 1.6.5 and RTC section 7 (Distribution) for a discussion of the potential benefits of managed charging to fleet owners.)
^{712} Electricity demand for heavy-duty ZEVs was based on the interim control case described in RIA Chapter 4.2.4 and for light- and medium-duty vehicles was based on Alternative 3 from EPA's proposed “Multipollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles” (88 FR 29184 et seq. ). See the TEIS report for more information on the modeled (`Action') scenario with managed charging, and how demand was allocated by region and time of day.
^{713} National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, Kevala Inc., and U.S. Department of Energy. “Multi-State Transportation Electrification Impact Study: Preparing the Grid for Light-, Medium-, and Heavy-Duty Electric Vehicles”. DOE/EE-2818. U.S. Department of Energy. March 2024.
The changes to power generation in our modeled IPM scenario and the distribution cost estimates from TEIS were then input to the Retail Price Model (RPM). ^{714} The RPM developed by ICF generates estimates for average electricity prices across consumer classes accounting for the regional distribution of electricity demand. The resulting national average retail prices, which include distribution upgrade costs, were used as a basis for the charging costs in HD TRUCS. ^{715}
^{714} ICF. “Documentation of the Retail Price Model. Draft.” 2019. Available online: https://www.epa.gov/sites/default/files/2019-06/documents/rpm_documentation_june2019.pdf.
^{715} IPM and the RPM were run for select years. We used linear interpolation for electricity prices between model run years from 2028-2050. We kept electricity prices constant for 2050+ and assumed the 2027 price was the same as 2028.
For depot charging, we add 0.52 cents/kWh to the RPM results to account for EVSE maintenance costs. These values are from a recent ICCT study, ^{716} which was suggested in public comments (see RTC Chapter 6). ^{717} For public charging, we project an electricity price of 19.6 cents/kWh for 2027 and adjust it for future years according to the results of the IPM Retail Price Model discussed. The initial value from the same ICCT study ^{718} reflects costs for public charging at stations designed for long-haul vehicles. Stations are assumed to have seventeen 1 MW EVSE ports and twenty 150 kW EVSE ports for a total peak power capacity of 20 MW. The 19.6 cent/kWh price includes the amortized cost of this charging equipment, land costs, both electricity prices (cents/kWh) and demand charges (cents/kW) associated with high peak power, distribution upgrade costs for substations, feeders, and transformers associated with these public charging stations, and EVSE maintenance costs. We apply public electricity prices to long-haul vehicles, some longer-range day cab tractors and coach buses (see section II.D.5.i of this preamble). Overall, our charging costs used in the final rule analysis are higher than those used in the NPRM analysis, particularly since those costs now reflect maintenance, grid distribution upgrades, and public charging costs.
^{716} Hussein Basma, Claire Buysee, Yuanrong Zhou, and Felipe Rodriguez. “Total Cost of Ownership of Alternative Powertrain Technologies for Class 8 Long-haul Trucks in the United States.” International Council on Clean Transportation. April 2023. Available at: https://theicct.org/wp-content/uploads/2023/04/tco-alt-powertrain-long-haul-trucks-us-apr23.pdf.
^{717} See Comments of EMA at 28.
^{718} Hussein Basma, Claire Buysee, Yuanrong Zhou, and Felipe Rodriguez. “Total Cost of Ownership of Alternative Powertrain Technologies for Class 8 Long-haul Trucks in the United States.” International Council on Clean Transportation. April 2023. Available at: https://theicct.org/wp-content/uploads/2023/04/tco-alt-powertrain-long-haul-trucks-us-apr23.pdf.
For the HD TRUCS analysis, rather than focusing on depot hydrogen fueling infrastructure costs that would be incurred upfront, we included infrastructure costs in our per-kilogram retail price of hydrogen. The retail price of hydrogen is the total price of hydrogen when it becomes available to the end user, including the costs of production, distribution, storage, and dispensing at a fueling station. This price per kilogram of hydrogen includes the amortization of the station capital costs. This approach is consistent with the method we use in HD TRUCS for ICE vehicles, where the equivalent diesel fuel costs are included in the diesel fuel price instead of accounting for the costs of fuel stations separately, as well as for BEVS with public charging, as explained previously in this section.
We acknowledge that this market is still emerging and that hydrogen fuel providers will likely pursue a diverse range of business models. For example, some businesses may sell hydrogen to fleets through a negotiated contract rather than at a flat market rate on a given day. Others may offer to absorb
the infrastructure development risk for the consumer, in exchange for the ability to sell excess hydrogen to other customers and more quickly amortize the cost of building a fueling station. FCEV manufacturers may offer a “turnkey” solution to fleets, where they provide a vehicle with fuel as a package deal. This level of granularity is not reflected in our hydrogen price estimates presented in the RIA.
As discussed in section II.D.3.iv, large Federal incentives are in place that could impact the price of hydrogen. In June 2021, DOE launched a Hydrogen Shot goal to reduce the cost of clean hydrogen production by 80 percent to $1 per kilogram in one decade. ^{719} The BIL and IRA included funding for several hydrogen programs to accelerate progress towards the Hydrogen Shot and jumpstart the hydrogen market in the U.S.
^{719} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “Hydrogen Shot”. Available online: https://www.energy.gov/eere/fuelcells/hydrogen-shot .
For the NPRM analysis, we included a hydrogen price based on analysis from ANL using BEAN. 88 FR 25988. One commenter highlighted several reports that indicate large potential for the hydrogen price to rapidly drop, particularly on the production side. Several commenters expressed concern about the hydrogen price assumption in the NPRM or said that prices cannot be predicted at this time and urged that EPA's projection be regularly evaluated as the market develops. Some commenters referred to an ICCT analysis of hydrogen pricing that indicated a lack of cost-competitiveness for hydrogen-fueled trucks before 2035. Another commenter noted that the price of $4 to $5 per kg (that EPA referenced) is described by DOE as a “willingness to pay” that reflects the total price at which hydrogen must be available to the HD vehicle end user for uptake to occur, or the point at which FCEVs could reach cost parity with diesel vehicles. They stated that it cannot represent the real market and offered a bottom-up analysis to understand what fleet owners would pay at the hydrogen refueling stations. See RTC section 8.2 for the comments submitted on this issue and RIA Chapter 2.5.3.1 for a detailed response and additional discussion about hydrogen price.
For the final rule HD TRUCS analysis, in consideration of the comments, we re-evaluated our assumption about the retail price of hydrogen, in consultation with DOE. We determined the hydrogen price based on several 2030 cost scenarios for hydrogen from the Pathways to Commercial Liftoff report ^{720} that are in line with estimates from a previous DOE analysis of market uptake of FCEVs. ^{721} Several cost trajectories in the report identified paths for around $6 per kg in 2030, depending on the method of hydrogen production and cost of the station. For 2030, we looked at the average of the sums of low and high pathway estimates for hydrogen produced using steam methane reforming (SMR) with carbon capture and sequestration (CCS) and water electrolysis is just under $6 per kg in 2030, considering varying incentives from the IRA hydrogen production tax credit (PTC). Distribution, storage, and dispensing costs are based on DOE estimates if advances in distribution and storage technology are commercialized and at scale. Our scenario selections presume that in the near-term, delivery of hydrogen in liquid form is likely, due to the limited capacity of gaseous trailers and limited availability of pipelines. ^{722} Cost reductions to $4 per kg are considered feasible by 2035 with next generation fuel dispensing technologies, reductions in the cost of hydrogen production due to IRA incentives, and possibly the use of pipelines for hydrogen delivery. ^{723}
^{720} U.S. Department of Energy. “Pathways to Commercial Liftoff: Clean Hydrogen”. March 2023. Available online: https://liftoff.energy.gov/wp-content/uploads/2023/05/20230523-Pathways-to-Commercial-Liftoff-Clean-Hydrogen.pdf . See Figure 10.
^{721} Ledna, et. al. “Decarbonizing Medium- & Heavy-Duty On-Road Vehicles: Zero-Emission Vehicles Cost Analysis”. National Renewable Energy Laboratory. March 2022. Available online: https://www.nrel.gov/docs/fy22osti/82081.pdf.
^{722} U.S. Department of Energy. “Pathways to Commercial Liftoff: Clean Hydrogen”. March 2023. Available online: https://liftoff.energy.gov/wp-content/uploads/2023/05/20230523-Pathways-to-Commercial-Liftoff-Clean-Hydrogen.pdf . See Figure 10.
^{723} Ledna, et. al. “Decarbonizing Medium- & Heavy-Duty On-Road Vehicles: Zero-Emission Vehicles Cost Analysis”. National Renewable Energy Laboratory. March 2022. Available online: https://www.nrel.gov/docs/fy22osti/82081.pdf.
To evaluate these estimates further, and in response to comments, the National Renewable Energy Lab (NREL) conducted a bottom-up analysis that explores the potential range of levelized costs of dispensed hydrogen (LCOH) ^{724} from hydrogen refueling stations for HD FCEVs in 2030. Bracci et. al ^{725} evaluates breakeven costs along the full supply chain from hydrogen production to dispensing, including station costs by technology component and delivery costs by distance delivered. The authors vary hydrogen delivery distances, station sizes, station utilization rates, and economies of scale. They assume that hydrogen is dispensed in pressurized gaseous form at 700 bars of pressure and is either delivered via liquid tanker trucks or produced onsite in gaseous form. The assumed production cost of $1.50 per kg is based on costs of production today using steam methane reforming (SMR), though the paper acknowledges that many factors are at play that could impact the cost and method of hydrogen production in 2030 such as the rate of economies of scale; the impacts of policy incentives ( e.g., the 45V tax credit); ^{726} and the success of research, development, and deployment efforts. Most capital and operating costs are derived from Argonne National Laboratory's Hydrogen Delivery Scenario Analysis Model (HDSAM) Version 4.5. ^{727}
^{724} LCOH is described as the total annualized capital costs plus annual feedstock, variable, and fixed operating costs, divided by the annual hydrogen flow through the supply chain.
^{725} Bracci, Justin, Mariya Koleva, and Mark Chung. “Levelized Cost of Dispensed Hydrogen for Heavy-Duty Vehicles”. National Renewable Energy Laboratory. NREL/TP-5400-88818. March 2024. Available online: https://www.nrel.gov/docs/fy24osti/88818.pdf.
^{726} The authors indicate that relevant incentives include but are not limited to the Alternative Fuel Refueling Property Credit (30C), the Credit of Production of Clean Hydrogen (45V), the Qualified Advanced Energy Project Credit (48C), and the Credit for Qualified Commercial Clean Vehicles (45W).
^{727} Bracci, Justin, Mariya Koleva, and Mark Chung. “Levelized Cost of Dispensed Hydrogen for Heavy-Duty Vehicles”. National Renewable Energy Laboratory. NREL/TP-5400-88818. March 2024. Available online: https://www.nrel.gov/docs/fy24osti/88818.pdf.
The authors conclude that the overall system LCOH in 2030 is estimated to range from about $3.80 per kg-H 2 to $12.60 per kg-H 2 , depending on the size of stations and method of hydrogen supply. ^{728} This cost range is not the same as a retail price, but we assume that any retail markup at the station is minimal. 729 730 Importantly, it does not consider any tax incentives or other state or Federal incentive policies that may further reduce the retail price that consumers see at a fueling station in 2030. 731 732 Therefore, we conclude that our retail price of hydrogen of $6 per kg in 2030, dropping to $4 per kg by 2035, is within a reasonable range of anticipated values.
^{728} Bracci, Justin, Mariya Koleva, and Mark Chung. “Levelized Cost of Dispensed Hydrogen for Heavy-Duty Vehicles”. National Renewable Energy Laboratory. NREL/TP-5400-88818. March 2024. Available online: https://www.nrel.gov/docs/fy24osti/88818.pdf.
^{729} West Virginia Oil Marketers and Grocers Association. “How Much Money Do Businesses Make on Fuel Purchases?” Available online: https://www.omegawv.com/faq/140-how-much-money-do-businesses-make-on-fuel-purchases.html.
^{730} Kinnier, Alex. “I've analyzed the profit margins of 30,000 gas stations. Here's the proof fuel retailers are not to blame for high gas prices”. Fortune. August 9, 2022. Available online: https://fortune.com/2022/08/09/energy-profit-margins-gas-stations-proof-fuel-retailers-high-gas-prices-alex-kinnier/.
^{731} The authors indicate that relevant incentives include but are not limited to the Alternative Fuel Refueling Property Credit (30C), the Credit of Production of Clean Hydrogen (45V), the Qualified Advanced Energy Project Credit (48C), and the Credit for Qualified Commercial Clean Vehicles (45W).
^{732} U.S. Department of Energy, Hydrogen and Fuel Cell Technologies Office. “Financial Incentives for Hydrogen and Fuel Cell Projects”. Available online: https://www.energy.gov/eere/fuelcells/financial-incentives-hydrogen-and-fuel-cell-projects.
See RIA Chapter 2.5.3.1 for additional detail about our assessment. After consideration of comments and this assessment, we project the retail price of hydrogen in 2030 will be $6 per kg and fall to $4 per kg in 2035 and beyond, as shown in Table II-23.

iii. Insurance
In the NPRM analysis, we did not take into account the cost of insurance on the ZEV purchaser. A few commenters suggested we should consider the addition of insurance cost because the incremental cost of insurance for the ZEVs will be higher than for ICE vehicles. We agree that insurance costs may differ between these vehicle types and that this is a cost that will be seen by the operator. Therefore, for the final rule analysis in HD TRUCS, we included the incremental insurance costs of a ZEV relative to an ICEV by incorporating an annual insurance cost equal to 3 percent of initial upfront vehicle technology RPE cost. ^{733} This annual cost was applied for each operating year of the vehicle. For further discussion on insurance cost see RIA Chapter 2.5.3.3.
^{733} Hussein Basma, Claire Buysee, Yuanrong Zhou, and Felipe Rodriguez, “Total Cost of Ownership of Alternative Powertrain Technologies for Class 8 Long-haul Trucks in the United States,” April 2023. Page 17. Available at: https://theicct.org/wp-content/uploads/2023/04/tco-alt-powertrain-long-haul-trucks-us-apr23.pdf.

iv. Taxes
In the NPRM analysis, we did not account for the upfront taxes paid by the purchaser of the vehicle. Commenters pointed out the additional costs from the Federal excise tax and state sales tax which should be included. For the final rule, we added FET and state sales tax as a part of the upfront cost calculation for purchaser in HD TRUCS. A FET of 12 percent was applied to the upfront powertrain technology retail price equivalent of Class 8 heavy-duty vehicles and all tractors in HD TRUCS ( i.e., where the FET is applicable). Similarly, our analysis in HD TRUCS now includes a state sales tax of 5.02 percent, the average sales tax in the U.S. for heavy-duty vehicles. We applied this increase to the upfront powertrain technology retail price equivalent for all vehicles in HD TRUCS.

v. ZEV Registration Fee
In the NPRM analysis, we did not account for ZEV registration fees paid by the purchaser. Commenters have pointed out that some states have adopted state ZEV registration fees. Though 18 states do not have an additional registration fee for ZEVS, for those that do, the registration fees are generally between $50 and $225 per year. While EPA cannot predict whether and to what extent other states will enact ZEV registration fees, we have nonetheless conservatively added an annual registration fee of $100 to all ZEV vehicles in our final HD TRUCS analysis (see RIA Chapter 2.4.4).

6. Payback
After assessing the suitability of the technology and costs associated with ZEVs, EPA performed a payback calculation on each of the 101 HD TRUCS vehicles for the BEV technology and FCEV technology that we considered for the technology packages to support the feasibility of the final standards in the MY 2027-2032 timeframe. The payback period was calculated by determining the number of years that it would take for the annual operational savings of a ZEV to offset the incremental upfront purchase price of a BEV or FCEV (after accounting for the IRA section 13502 battery tax credit and IRA section 13403 vehicle tax credit as described in RIA Chapters 2.4.3.1 and 2.4.3.5, respectively, Federal excise and state sales taxes and charging infrastructure costs (for BEVs, after accounting for the IRA section 13404 Alternative Fuel Refueling Property Credit) when compared to purchasing a comparable ICE vehicle. The ICE vehicle and ZEV costs calculated include the RPE multiplier of 1.42 to include both direct and indirect manufacturing costs, as discussed further in RIA Chapter 3. The operating costs include the diesel, hydrogen or electricity costs, DEF costs, the maintenance and repair costs, insurance costs, and ZEV registration fee. The payback results for BEVs and FCEVs are shown in RIA Chapter 2.9.2.
In our payback analysis in HD TRUCS, we did not account for potential diesel engine rebuild costs for ICE vehicles, potential replacement battery costs for BEVs or EVSE replacement costs for depot-charged BEVs, or potential replacement fuel cell stack costs for FCEVs because our payback analysis covers a shorter period of time than the expected life of these components. However, we did account for these costs in our program costs, as discussed in RIA Chapter 3.4, because they will occur over the lifetime of the vehicles.
According to a 2013 study conducted by McKay and Co. the average out frame rebuilds for internal combustion engines in Class 4 through 8 vehicles range from 10 to 16 years. ^{734} In addition, in the HD2027 low NOx rule, EPA increased emissions warranties for MY 2027 and later HD engines beyond what is required today. ^{735}
^{734} MacKay & Company “Industry Characterization of Heavy-Duty Diesel Engine Rebuilds”, September 2013. EPA Contract No. EP-C-12-011 Work Assignment No. 1-06.
^{735} HD2027 rule (88 FR 4296, January 24, 2023).
Typical battery warranties being offered by HD BEV manufacturers range between 8 and 15 years today and we are finalizing an emissions warranty requirement for HD BEV (see preamble section III.B). ^{736} A BEV battery replacement may be practically necessary over the operational life of a vehicle if the battery deteriorates to a point where the vehicle range no longer meets the vehicle's operational needs. As explained in section II.D.5, we sized the battery in BEVs in HD TRUCS to meet a 10 year and 2,000 cycle threshold to better ensure a battery replacement would not be needed during the payback period assessed in HD TRUCS. Furthermore, we believe that proper vehicle and battery maintenance and management can extend battery life. For example, manufacturers will utilize battery management system to maintain the temperature of the battery ^{737} as well active battery balancing to extend the life of the battery. 738 739 Likewise, pre-conditioning has also shown to extend the life of the battery. ^{740} In addition, research suggests that battery life is expected to improve with new batteries over time as battery chemistry and battery charging strategies improve, such that newer MY BEVs will have longer battery life.
^{736} Type C BEV school bus battery warranty range five to fifteen years according to https://www.nyapt.org/resources/Documents/WRI_ESB-Buyers-Guide_US-Market_2022.pdf. The Freightliner electric walk-in van includes an eight-year battery warranty according to https://www.electricwalkinvan.com/wp-content/uploads/2022/05/MT50e-specifications-2022.pdf.
^{737} Basma, Hussein, Charbel Mansour, Marc Haddad, Maroun Nemer, Pascal Stabat. “Comprehensive energy modeling methodology for battery electric buses”. Energy: Volume 207, 15 September 2020, 118241. Available online: https://www.sciencedirect.com/science/article/pii/S0360544220313487.
^{738} Bae, SH., Park, J.W., Lee, S.H. “Optimal SOC Reference Based Active Cell Balancing on a Common Energy Bus of Battery” Available online: http://koreascience.or.kr/article/JAKO201709641401357.pdf.
^{739} Azad, F.S., Ahasan Habib, A.K.M., Rahman, A., Ahmed I. “Active cell balancing of Li-Ion batteries using single capacitor and single LC series resonant circuit.” https://beei.org/index.php/EEI/article/viewFile/1944/1491.
^{740} “How to Improve EV Battery Performance in Cold Weather” Accessed on March 31, 2023. https://www.worktruckonline.com/10176367/how-to-improve-ev-battery-performance-in-cold-weather.
Similar to the approach we took for sizing the battery in BEVs, we oversized the fuel stack system to extend the durability of the system, as discussed in section II.D.5.v.

F. Final Standards
The final standards are shown in Table II-24 and Table II-25 for vocational vehicles and in Table II-26 and Table II-27 for tractors. We are finalizing CO 2 emission standards for heavy-duty vehicles that, compared to the proposed standards, include less stringent standards for all vehicle categories in MYs 2027, 2028, 2029 and 2030. The final standards increase in stringency at a slower pace through MYs 2027 to 2030 compared to the proposal, and day cab tractor standards start in MY 2028 and heavy heavy-duty vocational vehicles start in MY 2029 (we proposed Phase 3 standards for day cabs and heavy-heavy vocational vehicles starting in MY 2027). As proposed, the final standards for sleeper cabs start in MY 2030 but are less stringent than proposed in that year and in MY 2031, and equivalent to the proposed standards in MY 2032. We are finalizing MY 2031 standards that are on par with the proposal for light- and medium-duty vocational vehicles and day cab tractors. Heavy heavy-duty vocational vehicle final standards are less stringent than proposed for all model years, including 2031 and 2032. For MY 2032, we are finalizing more stringent standards than proposed for light and medium heavy-duty vocational vehicles and day cab tractors.
As further explained in section II.G, and consistent with our HD GHG Phase 1 and Phase 2 rulemakings, in this Phase 3 final rule we considered the following factors: the impacts of potential standards on emissions reductions of GHG emissions; technical feasibility and technology effectiveness; the lead time necessary to implement the technologies; costs to manufacturers; costs to purchasers including operating savings; the impacts of standards on oil conservation and energy security; impacts of standards on the truck industry; other energy impacts; as well as other relevant factors such as impacts on safety. ^{741} In this rulemaking, EPA has accounted for a wide range of emissions control technologies, including advanced ICE engine and vehicle technologies ( e.g., engine, transmission, drivetrain, aerodynamics, tire rolling resistance improvements, the use of low carbon fuels like CNG and LNG, and H2-ICE), hybrid technologies ( e.g., HEV and PHEV), and ZEV technologies ( e.g., BEV and FCEV). These include technologies applied to motor vehicles with ICE (including hybrid powertrains) and without ICE, and a range of electrification across the technologies (from fully-electrified vehicle technologies without an ICE that achieve zero vehicle tailpipe emissions ( e.g., BEVs), fuel cell electric vehicle technologies that run on hydrogen and achieve zero tailpipe emissions ( e.g., FCEVs), as well as plug-in hybrid partially electrified technologies and ICEs with electrified accessories). As noted, under these performance-based emissions standards, manufacturers remain free to utilize any compliance choices they wish so long as they meet the CO 2 emissions standards. See section II.G.5 of this preamble for further discussion of how we balanced the factors we considered for the final Phase 3 standards.
^{741} 76 FR 57129, September 15, 2011 and 81 FR 73512, October 25, 2016.
Similar to the approach we used to support the feasibility of previous HD rulemakings, including both of the HD GHG rules, to support the feasibility of the final Phase 3 standards we developed projected technology packages for a potential compliance pathway that, on average, will meet each of the final Phase 3 standards for each regulatory subcategory of vocational vehicles and tractors after considering the various factors described in this section, including technology costs for manufacturers and costs to purchasers and operators. The final Phase 3 GHG vehicle standards apply to nationwide production volumes, which we took into account in these technology packages and the potential compliance pathway to support the feasibility of the final Phase 3 GHG vehicle standards. Consistent with EPA's prior approach for HD GHG vehicle emission standards, the technology packages utilize the averaging portion of the longstanding ABT program, ^{742} and our projected potential compliance pathway includes manufacturers producing a mix of HD vehicles that utilize ICE-powered vehicle technologies and ZEV technologies, with specific adoption rates for each regulatory subcategory of vocational vehicles and tractors for each MY based on the analyses described in this section II and RIA Chapter 2. Note that we have analyzed a modeled potential technology compliance pathway to support the feasibility and appropriateness of the level of stringency for each of the final standards and as part of the rulemaking process. EPA's analysis and modeling provides information about one potential compliance pathway manufacturers could use to comply with the standards. EPA's analysis projects that both within the product lines of individual manufacturers and for different manufacturers across the industry, manufacturers will make use of a diverse range of technologies, including a projected mix of ICE vehicle, BEV, and FCEV technologies. EPA recognizes that, although it has modeled this potential compliance pathway to support the feasibility of the final rule and as part of the rulemaking process, manufacturers will make their own assessment of the vehicle market and their own decisions about which technologies to apply to which vehicles for any given model year to comply. The standards are performance-based and while EPA finds modeling useful in evaluating the feasibility of the standards, it is manufacturers who will decide the ultimate mix of vehicle technologies to offer. Although EPA cannot analyze every possible compliance scenario, for the analysis for the final standards, we also have evaluated additional example compliance scenarios ( i.e., additional example potential compliance pathways) with only ICE and ICE vehicle technologies, as described in section II.F.3. For example, EPA finds that it would be technologically feasible in the lead time provided and taking into consideration costs to manufacturers and purchasers to meet these final standards without producing additional ZEVs to comply with this rule. The fact that such a fleet is possible underscores both the feasibility and the flexibility of the performance-based standards, and confirms that manufacturers are likely to continue to offer vehicles with a diverse range of technologies, including advanced vehicle with ICE technologies as well as ZEVs for the duration of these standards and beyond. All of these compliance pathways are technically feasible, but in our analysis, the modeled potential compliance pathway is the lowest cost one overall and is the one modeled because EPA assumes that manufacturers are commercial entities that seek to minimize costs and maximize profits.
^{742} Note that our modeled potential compliance pathway does not include direct consideration of certain additional flexibilities afforded within the ABT program generally or certain flexibilities specifically updated in this final rule, including carryover of credits generated through Phase 2 multipliers for advanced technologies (see section III.A.2 of this preamble) and an interim transitional effective expansion of averaging sets for credits generated as specified in section III.A.3 of this preamble.
We phased in the final standards gradually between MYs 2027 and 2032 to address potential lead time concerns associated with feasibility for manufacturers to deploy technologies, including ZEV technologies, to meet the standards. Concerns include consideration of time necessary to ramp up battery production, increase the availability of critical raw minerals and assure sufficiently resilient supply chains, as discussed in section II.D.2.c.ii. The concerns also include recognition that it will take time for installation of EVSE and necessary supporting electrical infrastructure by the BEV purchasers and associated electrical utility, as discussed in RTC section 7 (Distribution). They also include consideration of time to design, develop, and manufacture FCEV models and hydrogen infrastructure as discussed in RTC section 8.1, and willingness to purchase a relatively new technology. We project BEV technology adoption in the potential compliance pathway as early as MY 2027 for certain applications where we focused on depot charging, and we project adoption of BEV technology in applications that will depend on public charging and FCEV technology in the technology packages for the potential compliance pathway starting in MY 2030 for select applications that travel longer distances ( i.e., coach buses, sleeper cab tractors and day cab tractors). There has been only limited development of FCEVs for the HD market to date; therefore, our assessment is that it is appropriate to provide manufacturers with additional lead time to design, develop, and manufacture FCEV models, but that it is feasible to do so by MY 2030, as discussed in section II.D.3. With substantial Federal investment in low-GHG hydrogen production (see RIA Chapter 1.8.2), we anticipate that hydrogen supply will be sufficient and the price of hydrogen fuel will fall in the 2030 to 2035 timeframe to make HD FCEVs cost-competitive with comparable ICE vehicles for some duty cycles, as discussed in section II.E.5.ii. We also note that the hydrogen infrastructure is expected to need additional time to further develop compared to BEV depot charging infrastructure, as discussed in greater detail in RIA Chapter 1.8, but our assessment is that refueling needs can be met by MY 2030. We also recognize the positive impact regulations can have on technology and recharging/refueling infrastructure development and deployment.
EPA granted the California ACT waiver request on March 30, 2023. The approach we used to support the feasibility of the final standards, described in this section II, was to develop technology packages on a nationwide basis and including nationwide production volumes, including vehicles sold to meet the ACT requirement in California and other states that have adopted or may adopt it under CAA section 177. With the granting of the California ACT waiver, we also considered how vehicles sold to meet the ACT requirement in California and other states that have adopted or may adopt it under CAA section 177 would impact our reference case (that is, the baseline from which we model projected effects of the final rule). For the final rule, to reflect the ZEV levels projected from ACT in California and other states, we included these projected ZEV sales volumes in the reference case. ^{743}
^{743} Because it would have been improper to prejudge the outcome of EPA's disposition of California's request for a preemption waiver for its ACT program, EPA did not include the full effects of that program as an enforceable program in the reference case (baseline) used at proposal, although we did make certain estimates of ZEV sales in California and other states that had adopted ACT under CAA section 177. 88 FR 25989.
We have finalized the new Phase 3 CO 2 emission standards using the regulatory subcategories we adopted in HD GHG Phase 2, as discussed in section II.C. As we discuss later in this subsection, the technology packages vary across the 101 HD TRUCS vehicle types and thus across the regulatory subcategories. Our technology packages that support the feasibility of the final rule standards— i.e., our modeled potential compliance pathway—include a projected mix of ICE vehicle, BEV, and FCEV technologies that are discussed in section II.F.1. Sections II.F.2 and II.F.3 include the costs and lead times associated with these technologies that we considered. In addition, for the final rule, to further illustrate that there are many potential pathways to compliance for the final standards with a wide range of potential technology mixes, we evaluated additional examples of other potential compliance pathway's technology packages that also support the feasibility of the final standards, and which only include vehicles with ICE technologies (“additional example potential compliance pathways”) in section II.F.4.
We intend for the standards for each individual year are severable from standards for each of the other years, including that the earlier MYs (MY 2027 through MY 2029) are severable from the later MYs (MYs 2030 and later). More specifically, our analysis supports that the standards for each of the later years are feasible and appropriate even absent standards for each of the earlier years, and vice versa. For example, EPA's revisions to certain MY 2027 standards are severable from the new MY 2028 and later standards because our analysis supports that the standards for each of the later years are feasible and appropriate even absent the revised MY 2027 standards. Additionally, we intend that the standards for each category of vocational vehicles and tractors for each individual model year are severable, including from the standards for all other categories for that model year, and from the standards for different model years. Thus, we intend each of the Phase 3 emission standards finalized in this rule to be entirely separate from each of the other Phase 3 emission standards and other varied components of this rule, and severable from each other. EPA has considered and adopted the Phase 3 emission standards and the remaining portions of the final rule independently, and each is severable should there be judicial review. For example, EPA notes that our judgments regarding feasibility of the Phase 3 standards for earlier years largely reflect anticipated changes in the heavy-duty vehicle market (which are driven by other factors, such as the IRA and manufacturers' plans), while our judgment regarding feasibility of the standards in later years reflects those trends plus the additional lead time for further adoption of control technologies. Thus, the standards for the later years are feasible even absent standards for the earlier years, and vice versa.
Additionally, our judgments regarding the standards for each separate vehicle category are likewise independent and do not rely on one another. For another example, EPA notes that our judgments regarding feasibility of the standards for vocational vehicles reflects our judgment regarding the general availability of depot-charging infrastructure in MY 2027 and for each later model year under the modeled potential compliance pathway, and that judgment is independent of our judgment regarding standards for tractors that reflects our judgment regarding more reliance on publicly available charging infrastructure and hydrogen refueling infrastructure in the MY 2030 and for each later model year under the modeled potential compliance pathway. Similarly, within the standards for vocational vehicles, our judgments regarding the feasibility of each model year of the standards for each category of vocational vehicles (LHD, MHD, and HHD) and for tractors (day cab and sleeper cab) reflects our judgments regarding the design requirements and payback analysis for each of the individual 101 vehicle types analyzed in HD TRUCS and then aggregated to the individual vehicle category, independent of those same kinds of judgments for the other vehicle categories and independent from prior MYs standards, under the modeled potential compliance pathway. See further discussion in RTC Chapter 2.10, regarding how EPA's analysis for the modeled potential compliance pathway supports the feasibility for each MY of the Phase 3 final standards for each vehicle category, including phase-in factors up to MY 2032 and later that EPA used for a given Phase 3 MY and are independent of the prior Phase 3 MY(s) standards.
If a court were to invalidate any one of these elements of the final rule, we intend the remainder of this action to remain effective. Importantly, we have designed these different elements of the program to function sensibly and independently, the supporting basis for each of these elements of the final rule reflects that they are independently justified and appropriate, and find each portion appropriate even if one or more other parts of the rule has been set aside. For example, if a reviewing court were to invalidate the MY 2027 standards for LHD vocational vehicles, the other components of the rule, including the other Phase 3 GHG standards, remain fully operable as the remaining components for the rule would remain appropriate and feasible.

1. Technology Packages To Support the Feasibility of the Final Standards
We support the feasibility of the final standards through technology packages that include both ICE vehicle and ZEV technologies. In our analysis, the ICE vehicles include a suite of technologies that represent a vehicle that meets the existing MY 2027 Phase 2 CO 2 emission standards. These technologies exist today and continue to evolve to improve the efficiency of the engine, transmission, drivetrain, aerodynamics, and tire rolling resistance in HD vehicles and therefore reduce their CO 2 emissions. Further adoption of these Phase 2 ICE technologies beyond the adoption rates used in the HD GHG Phase 2 rule may be utilized as part of other example potential compliance pathways to meet the final standards, as discussed in section II.F.4. In addition, the heavy-duty industry continues to develop CO 2 -reducing technologies such as hybrid powertrains and H2-ICE powered vehicles, also discussed in section II.F.4 as part of other example potential compliance pathways to meet the final standards. These further technology improvements are not part of the technology packages for the modeled potential compliance pathway supporting the feasibility of the final standards but are included as specified in section II.F.4 in the additional example potential compliance pathways supporting the feasibility of the final standards. They are available to any manufacturer determining its own compliance pathway, and further support that the final Phase 3 standards are feasible and appropriate performance-based standards.
In the transportation sector, new technology adoption rates often follow an S-shape. As discussed in the preamble to the HD GHG Phase 2 final rule, the adoption rates for a specific technology are initially slow, followed by a rapid adoption period, then leveling off as the market saturates, and not always at 100 percent. ^{744} Two commenters agreed that technology adoption follows an S-shape, as we stated in the proposal.
^{744} 81 FR 73558, Oct 25, 2016.
In the proposal, we developed a method to project utilization of BEV and FCEV technologies in the HD vehicle technology packages after considering methods in the literature. There is limited existing data to support estimations of adoption rates of HD ZEV technologies. The methods considered and explored in the formulation of the method used in the proposal was developed by EPA after considering methods in the literature to estimate the relationship between payback period and technology adoption in the HD vehicle market. We noted at proposal that we had explored the following methods: (1) the methods described in ACT Research's ChargeForward report, ^{745} (2) NREL's Transportation Technology Total Cost of Ownership (T3CO) tool, ^{746} (3) Oak Ridge National Laboratory's Market Acceptance of Advanced Automotive Technologies (MA3T) model, ^{747} (4) Pacific Northwest National Laboratory's Global Change Analysis Model (GCAM), ^{748} (5) ERM's market growth analysis done on behalf of EDF, ^{749} (6) Energy Innovation's United States Energy Policy Simulator used in a January 2023 analysis by ICCT and Energy Innovation, ^{750} and (7) CALSTART's Drive to Zero Market Projection Model. ^{751} DRIA at 231. Of these methods explored for the proposal, only ACT Research's work directly related payback period to technology adoption rates. We stated in the proposal that, based on our experience, payback is the most relevant metric to the HD vehicle industry. Thus, for the proposal, we considered the ACT Research method most relevant to assess willingness to purchase and modified their method, including to account for the effects of our proposed regulation, as described in DRIA Chapter 2.7.9.
^{745} Mitchell, George. Memorandum to docket EPA-HQ-OAR-2022-0985. ACT Research Co. LLC. “Charging Forward” 2020-2040 BEV & FCEV Forecast & Analysis, updated December 2021.
^{746} National Renewable Energy Laboratory. T3CO: Transportation Technology Total Cost of Ownership. Available at: https://www.nrel.gov/transportation/t3co.html .
^{747} Oak Ridge National Laboratory. “MA3T-TruckChoice.” June 2021. Available at: https://www.energy.gov/sites/default/files/2021-07/van021_lin_2021_o_5-28_1126pm_LR_FINAL_ML.pdf.
^{748} Pacific Northwest National Laboratory. GCAM: Global Change Analysis Model. https://gcims.pnnl.gov/modeling/gcam-global-change-analysis-model.
^{749} Robo, Ellen and Dave Seamonds. Technical Memo to Environmental Defense Fund: Analysis of Alternative Medium- and Heavy-Duty Zero-Emission Vehicle Business-As-Usual Scenarios. ERM. August 19, 2022. Available online: https://www.erm.com/contentassets/154d08e0d0674752925cd82c66b3e2b1/edf-zev-baseline-technical-memo-16may2022.pdf .
^{750} ICCT and Energy Innovation. “Analyzing the Impact of the Inflation Reduction Act on Electric Vehicle Uptake in the United States”. January 2023. Available online: https://theicct.org/wp-content/uploads/2023/01/ira-impact-evs-us-jan23-2.pdf .
^{751} Al-Alawi, Baha M., Owen MacDonnell, Cristiano Facanha. “Global Sales Targets for Zero-Emission Medium- and Heavy-Duty Vehicles—Methods and Application”. February 2022. Available online: https://globaldrivetozero.org/site/wp-content/uploads/2022/02/CALSTART_Global-Sales_White-Paper.pdf .
There were many comments regarding EPA's use of a payback metric at proposal as a means of developing a potential compliance pathway that included the use of ZEVs. Two commenters said, considered alone, payback is an incomplete metric. Other factors to consider are reluctance to utilize a new technology, effects of inflation, vehicle suitability, resale value, end of the IRA and other price incentives, critical mineral availability, and availability of supportive charging infrastructure. One of these commenters cited ACT Research's own evaluation that EPA should not have increased the adoption rates for payback periods greater than four years for MY 2032 and that our analysis should not have included payback-based adoption rates for payback periods beyond ten years, because this is beyond the payback period that would be acceptable. In addition, ACT Research did not agree with EPA using two different adoption schedules corresponding to MY 2027 and MY 2032. Another commenter stated that our use of the payback period table showing fleets purchasing BEVs and FCEVs at payback periods of up to 15 years in MY 2027, and beyond 15 years in MY 2032 are “unrealistic” because fleet owners look for payback periods of two years or less. Another commenter stated that EPA should adopt a more conservative payback schedule and suggested one in their comments.
Some commenters advocated for more stringent standards (see section II.B.1.i of this preamble). One of these commenters spoke to the length of a payback period, noting that payback periods well within a vehicle's lifetime should be sufficient, noting especially that vocational vehicles have long ownership periods. They also questioned the purportedly relatively low percentages of projected ZEVs where EPA had estimated payback periods of 1-2 years. Another commenter noted that EPA's projected compliance path showed less ZEV utilization than many estimates in the literature, citing BloombergNEF, as well as various of the ICCT White Papers and the levels required in California's Advanced Clean Fleet program. Another commenter noted generally that total cost of ownership of BEVs would necessarily be less than for ICE vehicles due to their simpler drivetrains, which would occasion less maintenance costs.
As further detailed in RTC sections 2.4 and 3.12.2, some of these commenters criticized EPA's use at proposal of the data from ACT Research's payback equation. The critique from these commenters was both for lack of transparency—stating that the equation was proprietary and so did not appear in the DRIA making comment difficult without getting access—and one commenter obtained the equation and asserted that they found no substantive basis for it. As just noted, in one commenter's submitted comment, ACT Research itself reviewed the NPRM and stated that EPA had misapplied the equation by leaving out various factors, including a consideration of total cost of ownership in addition to payback period. Some commenters believed the total cost of ownership approach used in NREL's Transportation Energy & Mobility Pathway Options (TEMPO) Model (Muratori et al., 2021) was a better way to assess the shape of the payback curve. One of these commenters stated that the NREL model “overcomes key deficiencies of the ACT Research-based curve by being based on validated empirical data, subject to peer-review, and freely available to the public.” ^{752} One commenter also provided an alternate distribution of adoption rate based on payback period developed from their assessment of the inputs from a NREL study using the TEMPO Model. ^{753} This commenter also suggested standards of significantly increased stringency using the data from the TEMPO model. The other commenter provided an alternate curve based on payback period developed from their assessment of the inputs and results from a NREL study using the TEMPO Model. Another commenter preferred an alternative method for assessing a ZEV-based acceptance. Their model uses a logit function less sensitive to price, developed by the Pacific Northwest Laboratory, and also uses a 15 percent discount rate.
^{752} ICCT Comments to the HD GHG Phase 3 NPRM. EPA-HQ-OAR-2022-0985-1553-A1, p. 2.
^{753} EDF Comments to Docket. EPA-HQ-OAR-2022-0985-1644-A1, p. 58-59.
We agree with the assessment asserted in comment that the approach developed by NREL for use in the TEMPO model is more transparent. ^{754} Furthermore, for the final rule, we further evaluated and found NREL's TEMPO model and approach to be robust. The NREL TEMPO model is peer-reviewed and applicable to our use because it specifically evaluated HD ICE vehicles, BEVs, and FCEVs. We evaluated NREL's approach to determining technology choices modeled in TEMPO using a discrete choice logit formulation. ^{755} We also evaluated the work conducted by one commenter in development of their suggested alternative curve, which was derived from the TEMPO outputs. Our purpose was to assess the reasonableness of utilizing the TEMPO results for adoption rates and payback period relationships. We found the approach to be robust, and we were able to reproduce similar adoption rates for each payback period bin relative to those provided by the commenter. Therefore, based on our assessment that NREL's TEMPO model is robust and the adoption rates to payback period relationship is reproducible, for the final rule, we are continuing to use the same payback period method we used in the proposal, but have revised the adoption rates that correspond to the payback period bins based on data from NREL's TEMPO model instead of the use of the ACT Research-based model. See RIA Chapter 2.7 for additional details.
^{754} See also RIA Chapter 2.7 and RTC section 3.11.2 for additional discussion on the comments received.
^{755} NREL describes “TEMPO is a transportation demand model that covers the entire U.S. transportation sector” including the HD market. Furthermore, they express “TEMPO finds pathways to achieve energy/emissions goals and estimates implications of different scenarios and decisions.” A part of this decision process includes inputs such as vehicle cost and performance, fuel costs, charging and refueling availability, and travel behavior. The model receives this information and applies a technology adoption to various inputs and provides technology based on market segment as a part of the outputs for TEMPO. The method they used is based on a logit formulation to describe a relationship between consumer adoption and aforementioned inputs, cost coefficients and financial horizon. One commenter worked with NREL to provide the relationship between adoption rate and payback period.
In the proposal, we applied an additional constraint (which at times we refer to as a “cap”) within HD TRUCS that limited the maximum penetration ( i.e., adoption percentage) of the BEV and FCEV technologies to 80 percent for any given vehicle type. This limit was developed after consideration of the actual needs of the purchasers related to two primary areas of our analysis. Our first consideration was that this volume limit takes into account that we sized the batteries, power electronics, e-motors, and infrastructure for each vehicle type based on the 90th percentile of the average VMT. As explained in section II.D.5, we utilized this technical assessment approach because we do not expect heavy-duty OEMs to design ZEV models for the 100th percentile VMT daily use case for vehicle applications, as this could significantly increase the ZEV powertrain size, weight, and costs for a ZEV application for all users, when only a relatively small part of the market will need such specifications. Therefore, the ZEVs we analyzed and have included in the technology packages and cost projections for the proposal and this final rule in the timeframe at issue are likely not appropriate for 100 percent of the vehicle applications in the real-world. Our second consideration for including a limit for BEVs and FCEVs is that we recognize there is a wide variety of real-world operation even for the same type of vehicle. For example, some owners may not have the ability to install charging infrastructure at their facility, or some vehicles may need to be operational 24 hours a day. Under the technology pathway projected to support the feasibility for these final standards, ICE vehicle technologies continue to be included and available in volumes to address these specific vehicle applications.
The TEMPO model, as shown in RIA Chapter 2.7.1, would attribute 100 percent adoption to vehicles that have an immediate payback (payback less than or equal to 0 year). A number of commenters questioned the 80 percent limit in the HD TRUCS analysis. Two commenters found some merit to EPA's premise that a cap reflected that ZEVs would not be suitable for all applications, but both of these commenters maintained that this would be less and less over time. Consequently, these commenters thought EPA's methodology should at the least increase the cap in the standards' out years. One of these commenters also submitted an analysis without a cap ( i.e., with a 100 percent cap) where their model showed immediate payback. Under this alternative methodology, the commenter projected higher ZEV penetration for many of the vehicle Class 2-4 and 6-7 trucks, refuse trucks, and almost all bus segments. This commenter also noted these estimates did not consider the effects of the IRA. Both of these commenters also maintained that 80 percent was too conservative even for MY 2027, especially when coupled with the 90th percentile sizing VMT for the battery. Another commenter supported a cap of 90 percent.
Another commenter challenged the 80 percent cap as inconsistent with that commenter's purportedly extensive telematics data that showed the 90th percentile VMTs we used in the NPRM for day cab and sleeper cab tractors were too low, and suggested that Class 4-7 ZEVs with payback rates of <0 years would have an adoption rate of 73 percent, and Class 8 ZEVs with payback rates of <0 years would have an adoption rate of 36 percent, noting that these rates are consistent with CARB's 2019 initial market assessment for the ACT rule. This commenter also questioned why EPA's cap for those categories can be higher, that is, less restrictive, than the applicable levels considered in ACT. Another commenter stated that the results from EPA's HD TRUCS would need to be further discounted to reflect that the charging and H2 fueling infrastructure would not be in place to meet the proposed MY 2027 through 2032 standards.
After consideration of comments, including concerns raised by manufacturers, we re-evaluated the maximum penetration constraints and “caps” in HD TRUCS for the final rule. The constraints discussed in the proposal, such as the methodology to size the batteries and the recognition of the variety of real-world applications of heavy-duty trucks, still apply to the final rule analysis. Furthermore, we are taking a phased-in approach to the constraints to recognize that the development of the ZEV market will take time to develop. We broadly considered the lead time necessary to increase heavy-duty battery production (as discussed in preamble section II.D.2.ii), including growth in the planned battery production capacity from now through 2032 and other issues including availability of critical minerals and related supply chains, and time for manufacturers to design, develop, and manufacture ZEVs (as discussed in preamble section II.F.3). We also have generally accounted for the time required to deploy infrastructure (as discussed in preamble section II.F.3), including the potential need for distribution grid buildout through 2032 as informed by our analysis and by the DOE's TEIS (as discussed in preamble section II.D.2.iii). We see a similar trend in the growth of the infrastructure to support H2 refueling for FCEVs (as discussed in preamble section II.D.3.v).
In recognition of these considerations, for the final rule we applied more conservative maximum penetration constraints within HD TRUCS than were used in the proposal and which are consistent with a balanced and measured approach generally, which in our assessment are appropriate and also address concerns raised by manufacturers. We limited the maximum penetration of the ZEV technologies in HD TRUCS to 20 percent in MY 2027, 37 percent in MY 2030 and 70 percent in MY 2032 for any given vehicle type. These caps are based upon an exercise of technical judgment after reviewing the entire record and reflect consideration of and address concerns about infrastructure readiness, willingness to purchase, and critical mineral and supply chain availability, reflecting that infrastructure, technology familiarity, and material availability will have more limitations in MY 2027 (and thus taking a conservative approach to the levels of the caps in those earlier model years) but will be further developed by MY 2032, while also capping each vehicle type in HD TRUCS below the proposed value of 80 percent utilization of ZEV technologies including in MY 2032.
Put another way, depending on the MY, these caps in HD TRUCS reflect a balanced and measured approach to consideration of a combination of extreme use situations (including extremes of daily VMT), extreme usages such as continuous operation, and ensuring adequate lead time for the various considerations just explained. These real world constraints are not reflected in the TEMPO model used to develop payback; rather, the caps are part of EPA's appropriate consideration of these issues. Regarding additional responses to comments summarized here, please see RTC sections 2.4, 3.3.1 and 3.11.2, and see also RIA Chapter 2.7.
The payback schedule used in HD TRUCS for the final rule is shown in Table II-28. The schedule utilizes lower rates of technology acceptance than those used in the proposal for payback periods greater than four years. The schedule shows that when the payback is immediate, we project that up to 20 percent of that type of vehicle could use BEV technology in MY 2027 for the reasons just discussed, with diminishing adoption as the payback period increases to more than 4 years. ^{756} After consideration of comments from stakeholders, we also set the adoption rates to zero for payback bins that were greater than 10 years. The length of ownership of new tractors varies. One study found that first ownership is customarily four to seven years for For-Hire companies and seven to 12 years for private fleets. ^{757} Another survey found that the average trade-in cycle for tractors was 8.7 years. ^{758} Whereas, EMA and NADA stated that tractors typically have three to five year trade cycles. ^{759}
As we discussed in the HD GHG Phase 2 rulemaking, vocational vehicles generally accumulate far fewer annual miles than tractors and will lead owners of these vehicles to keep them for longer periods of time. ^{760} To the extent vocational vehicle owners may be similar to owners of tractors in terms of business profiles, they are more likely to resemble private fleets or owner-operators than for-hire fleets. See 81 FR 73719 (“the usual period of ownership for a vocational vehicle reflects a lengthy trade cycle that may often exceed seven years”). In addition, EMA and NADA stated that heavy-duty trucks typically have trade cycles of seven to ten years for most operations. ^{761}
^{756} See RIA Chapter 2.7.9 for additional information on the development of the adoption rate schedule for HD TRUCS for the final rule.
^{757} Roeth, Mike, et al. “Barriers to Increased Adoption of Fuel Efficiency Technologies in Freight Trucking,” Page 24. July 2013. International Council for Clean Transportation. Available at https://theicct.org/sites/default/files/publications/ICCT-NACFE-CSS_Barriers_Report_Final_20130722.pdf.
^{758} American Transportation Research Institute. “An Analysis of the Operational Costs of Trucking: 2021 Update.” November 2021. Page 14.
^{759} See NADA's comments at Docket # EPA-HQ-OAR-20220-0985-1592-A1 at pp. 7-8 and EMA's comments at Docket # EPA-HQ-OAR-20220-0985-2668-A1 at p.48.
^{760} 81 FR 73678 and 73719, October 25, 2016.
^{761} See NADA's comments at Docket # EPA-HQ-OAR-20220-0985-1592-A1 at pp. 7-8 and EMA's comments at Docket # EPA-HQ-OAR-20220-0985-2668-A1 at p.48.
The issues raised by commenters were thus considered, and issues raised by manufacturers were thus addressed, in our final rule's approach to HD TRUCS and the projected technology packages: by applying the MY 2027, MY 2030 and MY 2032 caps, as discussed, and through lower ZEV adoption in the technology packages for payback periods that are longer than 4 years (including setting adoption to zero for payback bins greater than ten years) and higher (than longer payback periods) ZEV adoption when payback is 4 years or sooner. The relationship between adoption and payback period that was created from TEMPO outputs differ from the ACT payback schedule used in the proposal and is reflective of a more typical S-curve, where adoption starts slow and then speeds up. Note, the 70 percent constraint we imposed and explained in this subsection limits the adoption of the shortest payback bins for MY 2032.
The schedule shown in Table II-28 was used in HD TRUCS to evaluate the use of BEV or FCEV technologies for each of the 101 HD TRUCS vehicle types based on its payback period for MYs 2027, 2030, and 2032.
After the technology assessment, as described in section II.D and RIA Chapter 2, and technology cost and payback analysis, as described in section II.E and RIA Chapter 2.7.2, EPA determined the technology mix of ICE vehicle and ZEV for each regulatory subcategory in the technology packages for the potential compliance pathway. We first determined the ZEVs that are appropriate based on their payback for each of the 101 vehicle types for MYs 2027, 2030, and 2032, which can be found in RIA Chapter 2.8.3.1. We then aggregated the projected ZEVs for the specific vehicle types into their respective regulatory subcategories relative to the vehicle's sales weighting, as described in RIA Chapter 2.10.1. The resulting projected ZEVs (shown in Table II-29) and projected ICE vehicles that achieve a level of CO 2 emissions performance equal to the existing MY 2027 emission standards (shown in Table II-30) were built into our technology packages for the potential compliance pathway.
As shown in Table II-30, under the modeled potential compliance pathway the majority of sales of new HD vehicles in MYs 2027 through 2032 are projected to be ICE vehicles with GHG-reducing technologies. These values represent the total national HD ZEV and ICE vehicle sales, including those accounted for in the reference case as described in section V.A. The portion of the overall HD sales in MY 2027 that are ZEVs included in the reference case is 7 percent, compared to 11 percent of sales being ZEVs across the nation due to the final rule under our modeled potential compliance pathway, as shown in Table II-31. Similarly, in the MY 2032 reference case, 20 percent of the HD sales are projected to be ZEVs, versus 45 percent ZEVs in the HD national fleet with the potential compliance pathway modeled for the final rule, respectively.
The composition of the overall HD on-road fleet in future years with the final rule under our modeled potential compliance pathway and accounting for ZEVs in the reference case, is projected to include the following:
• In 2027: 1 percent of the on-road fleet are ZEVs.
• In 2032: 7 percent of the on-road fleet are ZEVs.
• In 2040: 22 percent of the on-road fleet are ZEVs.
For the final standards, EPA did not revise ( i.e., is not finalizing the proposed revision to) the MY 2027 or 2028 CO 2 emission standards for the HHD vocational vehicles but have set new CO 2 emission standards for HHD vocational vehicles beginning in MYs 2029 through 2032. Similarly, we are not revising the MY 2027 day cab tractor standards, but have set new standards beginning in MY 2028. Our reference case modeling does include some HHD vocational and day cab tractor ZEVs in MY 2027 and HHD vocational ZEVs in MY 2028. This is our best estimate of ZEV technology penetration for the reference case. Nonetheless, we recognize the significant uncertainties associated with the commercializing of these technologies in the HHD space, which are still in their infancy today. We also recognize that vehicle manufacturers may have different technology pathway plans to demonstrate compliance with ACT, and we acknowledge that certain vehicle manufacturer comments stated that they do not expect to produce a significant number of HHD ZEVs by MY 2028 because the HHD vocational vehicles will be one of the most challenging groups in which to utilize such technologies. Our revised analysis for the final rule projects lower levels of HHD ZEVs in the compliance pathways for MYs 2027-2032 than the proposal. It also delays the start of the Phase 3 standards for day cabs by one year, beginning in MY 2028. We recognize that the manufacturers' resources will require them to make practical business decisions to first develop products that will have a better business case. Our assessment of the final program as a whole is that it takes a balanced approach while still applying meaningful requirements in MY 2027 to reducing GHG emissions from the HD sector. In light of these challenges and uncertainties, including those associated with utilizing such technologies in the nearest term for HHD vocational vehicles, the potential disparities between manufacturers in the need for lead time and their corresponding compliance strategies, and the overall strengthening of the program in MY 2027 under Phase 3, we think it is reasonable to not revise the HHD vocational vehicle emission standards for MY 2027 or 2028. In addition, we are not revising the day cab tractor emission standards for MY 2027 for similar reasons.
The HD GHG Phase 2 program includes optional custom chassis emission standards for eight specific vehicle types. Those vehicle types may either meet the primary vocational vehicle program standards or, at the vehicle manufacturer's option, may comply with these optional standards. The existing optional custom chassis standards are numerically less stringent than the primary HD GHG Phase 2 vocational vehicle standards, but the ABT program is more restrictive for vehicles certified to these optional standards. Banking and trading of credits is not permitted, with the exception that small businesses may use traded credits to comply with the optional custom-chassis standards. Averaging is only allowed within each specific custom chassis regulatory subcategory for vehicles certified to these optional standards. If a manufacturer wishes to make use of the full ABT program, from the production of some or all of their custom-chassis vehicles in a given model year, they may certify them to the primary vocational vehicle standards.
In this final action, as presented previously in this section, we are adopting more stringent standards for some, but not all, of these optional custom chassis subcategories. We are revising MY 2027 emission standards and establishing new MY 2028 through MY 2032 and later emission standards for the school bus optional custom chassis regulatory subcategory. We are also establishing new MY 2028 through MY 2032 and later emission standards for refuse hauler optional custom chassis subcategory and new MY 2029 through MY 2032 and later emission standards for the other bus optional custom chassis subcategory. ^{762}
^{762} See 40 CFR 1037.105(h)(1) for the final standards that apply for custom chassis vehicles. See existing 40 CFR 1037.105(h)(2) for restrictions on averaging, banking, and trading for vehicles optionally certified to the custom chassis standards.
We are finalizing the approach we proposed for several other optional custom chassis categories. We are finalizing our proposed approach to not set Phase 3 standards for motor homes certified to the optional custom chassis regulatory subcategory after consideration of projected technologies for motor homes, including the projected impact of the weight of batteries in BEVs in the MYs 2027-2032, as described in RIA Chapter 2.8.1. This approach was supported by two commenters. The existing Phase 2 optional custom chassis standards for this subcategory will continue to apply. Furthermore, we also are not finalizing Phase 3 standards for emergency vehicles certified to the optional custom chassis regulatory subcategory due to our assessment that these vehicles have unpredictable operational requirements and after considering suitability of projected technologies, including that emergency vehicles may have limited access to recharging facilities while handling emergency situations in the MYs 2027-2032 timeframe. Finally, we are not adopting new standards for mixed-use vehicle optional custom chassis regulatory subcategory because of our assessment that these vehicles (such as hazardous material equipment or off-road drill equipment) are designed to work inherently in an off-road environment or are designed to operate at low speeds such as to be unsuitable for normal highway operation and, after consideration of suitability of projected technologies, including that they therefore may have limited access to on-site depot or public charging facilities in the MYs 2027-2032 timeframe. ^{763} The existing Phase 2 optional custom chassis standards for this subcategory will continue to apply.
^{763} Mixed-use vehicles must meet the criteria as described in 40 CFR 1037.105(h)(1), 1037.631(a)(1), and 1037.631(a)(2).
We also are not finalizing Phase 3 standards for two other optional custom chassis categories. Several stakeholders raised significant concerns related to the ability of coach buses to perform their mission (transporting people and their cargo) using battery electric technology. Furthermore, commenters raised concerns regarding the infrastructure needs for electrified motorcoaches because these vehicles would need to rely on public enroute charging. As noted in RIA Chapter 1.5.5, there are currently two manufacturers of coach buses that produce BEV versions of the vehicles. We note that there are a variety of different applications of a coach bus. In some instances, it may be used for a day trip or for commuting and require minimal underfloor luggage space and may not require a restroom. Another common use is for trips with longer distances such that passengers travel with luggage or sports equipment that requires underfloor storage. EPA contracted FEV to conduct analysis of the packaging feasibility of a FCEV powertrain on a coach bus to inform the final rule. FEV found that a FCEV powertrain would require the loss of 2-4 seats and 30 percent of the luggage volume. ^{764} The capacity loss was driven by the space needed for the hydrogen tanks, fuel cell with BOP, and/or batteries. Our assessment is that the weight and volume required for packaging a BEV powertrain would be greater than the requirements for a FCEV powertrain, and therefore result in even greater capacity losses. After further consideration of suitability of projected technologies, including EPA re-analyzing the packaging space available for battery electric and fuel cell powertrains on coach buses, EPA now agrees with the commenters that feasibility demonstrations for new Phase 3 optional custom chassis standards for coach buses during the timeframe of the final rule should not include application of BEV or FCEV technology due to the packaging space required to meet commercial range requirements while also having adequate luggage space. Therefore, EPA's optional custom chassis standards for Coach Buses will remain unchanged from the existing Phase 2 MY 2027+ CO 2 emission standards. However, as discussed in RIA Chapter 2.9.1.2, we project that there will be some applications of coach buses that will be appropriate as ZEVs and we therefore have considered these types of vehicles in the technology package that supports the modeled potential compliance pathway for the primary vocational vehicle standards.
^{764} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
Several manufacturers and associations raised concerns regarding the ability of concrete mixers and pumpers to electrify. They point to issues related to higher PTO usage, traveling at loads higher than those used in EPA's HD TRUCS analysis, and weight sensitivity. One commenter maintains that energy used by concrete mixers is significantly higher than what is represented in GEM and suggests the underestimated load requirements (and therefore energy requirements) result in smaller battery sizes and lower costs in HD TRUCS than what that commenter expects. The commenter states that, as a result, concrete mixers should have unique standards from other vocational vehicles based on lower adoption rates. On the other hand, another commenter provided links to several electrified concrete mixer and pumpers where prototypes have been supplied to customers in Europe. Additionally, another commenter stated that EPA should set more stringent standards for concrete mixers based on their emissions impact on overburdened communities. For the final rule, EPA increased the PTO loads required for concrete mixers and pumpers in our HD TRUCS analysis based on consideration of information provided by another commenter, and therefore these vehicles have larger power demands and battery sizes in the final rule HD TRUCS analysis than the vehicles had in the NPRM analysis. In recognition of the uncertainty related to the payload weight and PTO demands of these vehicles, EPA determined that the optional custom chassis standards for Concrete Mixers/Pumpers and Mixed-Use Vehicles will remain unchanged from the existing Phase 2 custom chassis emission standards. See RIA Chapter 2.9.1.1. However, because there are prototypes for some electrified concrete mixers and pumpers, we continued to include several of these vehicle types within HD TRUCS where they are modeled as part of the compliance pathway for HHD vocational vehicles. See RIA Chapter 2.9.1.1.
We note that we do not have concerns that manufacturers of any of the custom chassis types of vehicles could inappropriately circumvent the final vocational vehicle standards or the final optional custom chassis standards. This is because vocational vehicles are built to serve a purpose which is readily identifiable. For example, a manufacturer cannot certify a box truck to the emergency vehicle custom chassis standards.

2. Summary of Costs Assessment To Meet the Final Emission Standards
We supported the feasibility of the final standards through a potential compliance pathway's projected technology packages that include both ICE vehicle and ZEV technologies. To assess the projected costs of the final Phase 3 emission standards, we thus assess the costs of the potential compliance pathway's projected technology packages. In our analysis, the ICE vehicles include a suite of technologies that represent a vehicle that meets the existing MY 2027 Phase 2 CO 2 emission standards and HD 2027 NOx emission standards. We accounted for these technology costs as part of the HD GHG Phase 2 final rule and the HD 2027 NOx rule. Therefore, our technology costs for the ICE vehicles in our analysis are considered to be $0 because we did not add additional CO 2 -reducing technologies to the ICE vehicles in the technology packages for this final rule beyond those already required under the existing regulations. The incremental cost of a heavy-duty ZEV in our analysis is the marginal cost of ZEV powertrain components compared to ICE powertrain components on a comparable ICE vehicle. This includes the removal of the associated costs of ICE-specific components from the baseline vehicle and the addition of the ZEV components and associated costs. RIA Chapter 2.3.2 and 2.4.3 includes the ICE powertrain and BEV powertrain cost estimates for each of the 101 HD vehicle types that are included in our technology packages to support the compliance pathway. RIA Chapter 2.5.2 includes the FCEV powertrain cost projections for the applicable vehicles.

i. Manufacturer Costs
Table II-32 and Table II-33 show the ZEV technology costs for manufacturers relative to the reference case described in section V.A.1, including the direct manufacturing costs that reflect learning effects, the indirect costs, and the IRA section 13502 Advanced Manufacturing Production Credit, on average aggregated by regulatory group for MYs 2027 and 2032, respectively. ^{765} The incremental ZEV adoption rate in our modeled potential compliance pathway technology package reflects the difference between the ZEV adoption rates in the technology packages that support the feasibility of our final standards and the reference case. As shown in Table II-32 through Table II-34, we project that some vocational BEVs will cost less to produce than comparable ICE vehicle types by MY 2032 or earlier. Our analysis is consistent with other studies. For example, an EDF/Roush study found that by MY 2027, BEV transit buses, school buses, delivery vans, and refuse haulers would each cost less upfront than a comparable ICE vehicle. ^{766} ICCT similarly found that “although zero-emission trucks are more expensive in the near-term than their diesel equivalents, electric trucks will be less expensive than diesel in the 2025-2030 time frame, due to declining costs of batteries and electric motors as well as increasing diesel truck costs due to emission standards compliance.” ^{767} These studies were developed prior to passage of the IRA, and therefore we would expect the cost comparisons to be even more favorable after considering the IRA provisions.
^{765} Indirect costs are described in detail in section IV.B.2.
^{766} Nair, Vishnu; Sawyer Stone; Gary Rogers; Sajit Pillai; Roush Industries, Inc. “Technical Review: Medium and Heavy Duty Electrification Costs for MY 2027-2030.” February 2022. Page 18. Last accessed on February 9, 2023 at https://blogs.edf.org/climate411/files/2022/02/EDF-MDHD-Electrification-v1.6_20220209.pd .
^{767} Hall, Dale and Nic Lutsey. “Estimating the Infrastructure Needs and Costs for the Launch of Zero-Emission Trucks.” February 2019. Page 4. Last accessed on February 9, 2023 at https://theicct.org/wp-content/uploads/2021/06/ICCT_EV_HDVs_Infrastructure_20190809.pdf .

ii. Purchaser Costs
We also evaluated the costs of the final standards for purchasers on average by regulatory group, as shown in Table II-35 through Table II-37. Our assessment of the upfront purchaser costs includes the incremental cost of a ZEV relative to a comparable ICE vehicle after accounting for the two IRA tax credits (IRA section 13502, “Advanced Manufacturing Production Credit,” and IRA section 13403, “Qualified Commercial Clean Vehicles”) including the applicable FET and sales tax, and the associated EVSE costs (including IRA section 13404, “Alternative Fuel Refueling Property Credit”), if applicable. We also assessed the incremental annual operating costs of a ZEV relative to a comparable ICE vehicle, which include the refueling/charging costs, maintenance and repair costs, and insurance costs. The operating costs for BEVs include charging costs that reflect either depot charging or public charging, depending on the vehicle type. The payback periods shown reflect the number of years it is projected to take for the annual operating savings to offset the increase in total upfront costs for the purchaser for the sales-weighted average within a regulatory group.
As shown in Table II-37, we estimate that the average upfront cost per vehicle to purchase a new MY 2032 vocational ZEV and associated EVSE compared to a comparable ICE vehicle (after accounting for two IRA tax credits, IRA section 13502, “Advanced Manufacturing Production Credit,” and IRA section 13403, “Qualified Commercial Clean Vehicles”), will be offset by operational costs ( i.e., savings that come from the lower costs to operate, maintain, and repair ZEV technologies), such that we expect the upfront cost increase will be recouped due to operating savings in two to four years on average for vocational vehicles, two years on average for day cab tractors, and five years on average for sleeper cab tractors. We discuss this in more detail and provide the payback period for each of the HD TRUCS vehicle types in RIA Chapter 2.7.
The average per-vehicle purchaser costs shown in Table II-35 for MY 2027 are higher than the MY 2032 per-vehicle costs. The reduction in costs over time are reflective of technology learning, as discussed in section IV.B. It is worth noting that though the upfront costs of a BEV MHD vocational vehicle, for example, are higher when one considers both the vehicle and the EVSE, purchasers will still recoup these upfront costs within three years of ownership on average. This is within the period of first ownership, as explained in the previous subsection. Also of note, our MY 2027 technology package for this final rule has a significantly lower adoption rate for these MHD vocational vehicles in MY 2027 than in MY 2032, reflecting the higher cost in MY 2027 than in MY 2032. Purchasers considering a ZEV also will have the option to consider alternatives to purchasing an EVSE at the time of purchasing a vehicle. For example, depending on the location of the vehicle, heavy-duty public charging may be a better solution than depot charging. Instead of spending upfront for EVSE, the purchaser could instead spread the cost over time through public charging where the EVSE costs would be built into the electricity cost or through the use of Charging as a Service. Purchasers of course could choose an ICE vehicle as well if that best suits their needs.

3. Lead Time Assessment
Two of the significant aspects of the IRA are the tax credit available for the manufacturing of batteries and the tax credit available for the purchase of HD ZEVs, where the IRA provisions' qualifications are met. The tax credits significantly reduce, and in many cases erase, the incremental cost of purchasing a HD ZEV when compared to the cost of purchasing a comparable ICE vehicle. Therefore, as explained in our payback analysis, we expect the IRA will incentivize the demand and willingness to purchase for HD ZEVs. However, demand and willingness to purchase are only two of the factors we considered when evaluating the feasibility and suitability of HD ZEV technologies in the MY 2027 through MY 2032 timeframe, for inclusion in the potential compliance pathway's technology packages to support the feasibility of the Phase 3 standards in that timeframe. We also considered the lead time required for manufacturers to design, develop, and produce the ZEV and ICE vehicle technologies in the projected technology packages, in addition to lead time considerations relating to availability of charging and hydrogen refueling infrastructure, and availability of critical minerals and resiliency of related supply chains.
As noted in the proposal for this rule, heavy-duty manufacturers have indicated it could take two to four or more years to design, develop, and prove the safety and reliability of a new HD vehicle. 88 FR 25998. A typical design process includes the design and building of prototype or demonstration vehicles that are evaluated over several months or years in real world operation. The manufacturers need to accumulate miles and experience a wide variety of environmental conditions on these prototype vehicles to demonstrate the product's durability and reliability. Then manufacturers would work to commercialize the vehicle and in turn build it in mass production. We also considered that manufacturers are likely limited in terms of the financial resources, human resources, and testing facilities to redesign all of their vehicles at the same time and, instead, focus on the applications with the best business case because these would be where the customers would be most willing to purchase. Manufacturers reiterated the need for lead time in their comments on the proposed rule. See RTC section 2.3.3.
The final Phase 3 standards phase in over time from MY 2027 through MY 2032. For HD BEVs in the potential compliance pathway, we considered that BEV technology has been demonstrated to be technically feasible in heavy-duty transportation and that manufacturers will learn from the research and development work that has gone into developing the significant number of LD and HD electric vehicle models that are on the road today, as noted in section II.D.2 and RIA Chapter 1.5.5. The feasibility of our final standards is supported by technology packages with increasing BEV adoption rates beginning in MY 2027 (see also our discussion in this section II.D.2.iii regarding our consideration of adequate time for infrastructure development for HD BEVs). For HD FCEVS, as discussed in section II.D.3 and II.D.4, along with RIA Chapter 1.7.5, fuel cell technology in other sectors has been in existence for decades, it has been demonstrated to be technically feasible in heavy-duty transportation, and there are a number of HD FCEV models that are commercially available today with more expected to become available by 2024. However, we included this technology as part of potential compliance pathway's technology packages supporting the feasibility of our final standards starting in MY 2030 in part to take into consideration lead time to allow manufacturers to design, develop, and manufacture HD FCEV models (see also our discussion in this subsection regarding our consideration of adequate time for infrastructure development for HD FCEVs).
We discuss in sections II.D.1 and II.F.1 the need for ICE vehicles to continue to install CO 2 -reducing technologies, such as advanced aerodynamics, advanced transmissions, efficient powertrains, and lower rolling resistance tires to meet the previously promulgated MY 2027 Phase 2 standards. In our technology assessment for this final rule and the potential compliance pathway's technology packages to support the feasibility of the Phase 3 standards, we included ICE vehicle technologies for a portion of each of the technology packages, and those ICE vehicle technologies mirrored the technology packages we considered in setting the previously promulgated Phase 2 MY 2027 CO 2 emission standards. Each of these technologies exists today and continues to be developed by manufacturers. As noted in 2016 when we issued the HD GHG Phase 2 final rule, at that time we provided over ten years of lead time to the manufacturers to continue the development and deployment of these technologies. Our current assessment is that these ICE vehicle technologies continue to have adequate lead time and be feasible in the MY 2027 and later timeframe, as discussed in section II.D.1.
As a new vehicle is being designed and developed, our projected technology packages include consideration that manufacturers will also need time to significantly increase HD ZEV production volumes from today's volumes. In particular, our analysis for the potential compliance pathway considers that manufacturers will need to build new powertrains or to modify existing manufacturing production lines to assemble the new products that include ZEV powertrains. Our analysis for our potential compliance pathway also considered that manufacturers will require time to source new components, such as heavy-duty battery packs, motors, fuel cell stacks, and other ZEV components, including the sourcing of the critical minerals, as discussed in section II.D.2.ii. As described in section II.D.5, our potential compliance pathway's technology packages project that manufacturers will not develop vehicles utilizing ZEV technologies to cover all types of HD vehicles at once but will focus on those with the most favorable business case first, increase the adoption of those vehicles over time, and then develop other applications. We also note that we have added temporary compliance flexibilities to the rule, including the ability to average, bank, and trade credits across averaging sets for certain HD vehicles as described in section III.A, and have done so to facilitate compliance flexibility (although, as noted in section II.G.2, these flexibilities are not necessary to EPA's determination that the final standards are feasible, provide sufficient lead time, and are appropriate within the meaning of CAA section 202(a)(1)).
Several of the Phase 3 standards commence in MY 2027, but certain standards do not; namely, the Phase 3 standards for HHD vocational vehicles commence in MY 2029, the day cab tractors commence in MY 2028, and the standards for sleeper cab tractors commence in MY 2030. We believe our approach described in section II.D.5 demonstrates the feasibility of the final standards through our potential compliance pathway's technology packages, including through the technology packages reflecting the ZEV adoption rates for the applications we have determined are achievable in the MY 2027 and later timeframe.
Purchasers of BEVs will also need to consider how they will charge their vehicles. Our assessment of EVSE technology and costs associated with charging is included in sections II.E.2, II.E.5, and II.F.4 of this preamble, RIA Chapter 1, and RIA Chapter 2. We anticipate that many first-time BEV owners may opt to purchase and install EVSE at or near the time of vehicle purchase for charging at their depot, and we therefore account for these capital costs upfront. As noted in RIA Chapter 1, we expect significant increases in HD charging infrastructure due to a combination of public and private investments. This includes Federal funding available through the BIL ^{768} and the IRA. ^{769} As discussed in section II.D.2.iii and RTC section 7 (Distribution), OEMs, utilities, EVSE providers and others are also investing in and supporting the deployment of charging infrastructure. We also there discuss demand on the grid posed by the transportation sector (both light-duty and heavy-duty) on a national level, both in the areas of the high-volume freight corridors that are the most likely targets for deployment of heavy-duty BEVs during the rule's time frame and on a parcel level in particular states and nationally. Our conclusions, as there discussed, are that there is adequate lead time for deployment of distribution grid buildout for both depot and public charging, and we include consideration of costs in our analysis.
^{768} Infrastructure Investment and Jobs Act, Pub. L. No. 117-58. 135 Stat. 429 (2021), available at https://www.congress.gov/117/plaws/publ58/PLAW-117publ58.pdf .
^{769} Inflation Reduction Act, Pub. L. 117-169, 136 Stat. 1818 (2022).
In addition to the anticipated build out of charging infrastructure and electric distribution grids which we analyzed, innovative charging solutions can further reduce lead times to deploying HD BEVs. As discussed in section II.D.2.iii of this preamble, one approach is for utilities to make non-firm capacity available immediately as they construct distribution system upgrades. In California, Southern California Edison (SCE) proposed a two-year Automated Load Control Management Systems (LCMS) Pilot. ^{770}
^{770} The program would use third-party owned LCMS equipment approved by SCE to accelerate the connection of new loads, including new EVSE, while “SCE completes necessary upgrades in areas with capacity constraints.” SCE would use the LCMS to require new customers to limit consumption during periods when the system is more constrained, while providing those customers access to the distribution system sooner than would otherwise be possible. Once SCE completes required grid upgrades, the LCMS limits will be removed, and participating customers will gain unrestricted distribution service. SCE hopes to evaluate the extent to which LCMS can be used to “support distribution reliability and safety, reduce grid upgrade costs, and reduce delays to customers obtaining interconnection and utility power service.” SCE states that prior CPUC decisions have expressed clear support for this technology and SCE is commencing the LCMS Pilot immediately Southern California Edison. “Establishment of Southern California Edison Company's Customer-Side, Third Party Owned, Automated Load Control Management Systems Pilot”. November 2023. Available online: https://edisonintl.sharepoint.com/teams/Public/TM2/Shared%20Documents/Public/Regulatory/Filings-Advice%20Letters/Pending/Electric/ELECTRIC_5138-E.pdf?CT=1704322883028&OR=ItemsView .
Plans like SCE's to use LCMS to connect new EV loads faster in constrained sections of the grid will be bolstered by standards for load control technologies. UL, an organization that develops standards for the electronics industry, drafted the UL 3141 Outline of Investigation (OOI) for Power Control Systems (PCS). Once finalized, manufacturers will be able to use this standard for developing devices that utilities can use to limit the energy consumption of BEVs. The OOI identifies five potential functions for PCS. One of these functions is to serve as a Power Import Limit (PIL) or Power Export Limit (PEL). In these use cases, the PCS controls the flow of power between a local electric power system (local EPS, most often the building wiring on a single premises) and a broader area electric power system (area EPS, most often the utility's system). Critically, the standardized PIL function will enable the interconnection of new BEV charging stations faster by leveraging the flexibility of BEVs to charge in coordination with other loads at the premise. With this standard in place and manufacturer completion of conforming products, utilities will have a clear technological framework available to use in load control programs that accelerate charging infrastructure deployment for their customers. ^{771}
^{771} UL LLC. January 11, 2024. “UL 3141: Outline for Investigation of Power Control Systems.” Available online: https://www.shopulstandards.com/ProductDetail.aspx?productId=UL3141_1_O_20240111 .
EPA notes that it regards our analysis of adequacy and timeliness of distribution grid buildout as conservative, since it (intentionally) does not account for these innovative measures undertaken by some utilities; nor does it consider other than basic mitigative measures that BEV purchasers can undertake to reduce demand. Even with this conservative approach, we found that the rule affords adequate lead time for such buildout. We note that our analysis was informed significantly by studies from, and discussions with, the Department of Energy.
We have also carefully considered the adequacy of lead time to procure minerals critical to battery production, for supply chains respecting those minerals to be resilient enough to support battery production, and for sufficiency of battery production. We have found that there is sufficient lead time within the rule's timeframe respecting all of these. See section II.D.2.c.ii of this preamble, and RTC section 17.2. Our findings here are likewise supported by DOE studies, and by our consultation with the DOE.
Purchasers of FCEVs will need to consider how they will obtain hydrogen to refuel the vehicles. Our assessment of hydrogen infrastructure and costs associated with refueling are in sections II.D.3.v, II.E.5.ii, and II.F.4 of this preamble, RIA Chapter 1, and RIA Chapter 2. We expect significant private investment as a result of public investment through BIL and IRA in the coming years. In the final rule, we project that hydrogen consumption from FCEVs would be a small proportion (less than 1 percent) of total hydrogen expected to be produced through 2030 in the United States, as discussed in RIA Chapter 1.8.3.4. After evaluating the existing and projected future hydrogen refueling infrastructure, ^{772} we considered FCEV technologies only in the MY 2030 and later timeframe to better ensure we have provided adequate time for early market infrastructure development and because we expect that projected refueling needs in the technology packages can be met by MY 2030, as discussed also in RIA Chapter 2.1.
^{772} U.S. Department of Energy. “Pathways to Commercial Liftoff: Clean Hydrogen”. March 2023. Available online: https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB.pdf .
Giving consideration to these factors, our analysis for the potential compliance pathway supports that there is sufficient lead time to meet the final standards, which manufacturers may comply with through application of BEV technologies, FCEV technologies, or further improvements to ICE vehicles (which can include additional technologies like PHEV technologies or other potential advanced technologies like H2-ICE powered vehicles) to their fleets. As just discussed, we also believe that there will be sufficient corresponding infrastructure to support technologies under our modeled potential compliance pathway, and that availability of critical minerals and supply chains will not be a constraining factor. To further demonstrate the performance-based nature of the final Phase 3 standards, we also included additional examples of compliance pathway's technology packages in section II.F.4 that support the feasibility of the final standards. In this final rule, we also considered but did not adopt alternative standards that would have been supported by technology packages with a slower phase-in of CO 2 emission-reducing technologies, including a slower phase in of HD ZEV technologies in the projected technology packages, as described and for the reasons discussed in section II.H.
Additionally, while we believe there is sufficient time for the charging and refueling infrastructure to develop for the reasons explained in this section, EPA recognizes that under the potential compliance pathway in this final rule such infrastructure for BEVs and FCEVs is important for the success of the increasing development and adoption of these technologies. EPA carefully considered that there are significant efforts already underway to develop and expand heavy-duty electric charging and hydrogen refueling infrastructure both at the local, state and Federal government level as well as from private industry, as discussed in RIA Chapters 1 and 2 and this section II. Those are important early actions that will support the increase in ZEV charging and refueling infrastructure needed for the future growth of ZEV technology of the magnitude EPA is projecting in this rule's technology packages. As discussed in section II.B.2.iii, EPA has a vested interest in monitoring industry's performance in complying with mobile source emission standards, including the highway heavy-duty industry, and is committing to do so for Phase 3. Monitoring the availability of supporting infrastructure is a critical element of that post-promulgation effort by EPA.

4. Additional Example Compliance Pathway Technology Packages To Support the Final Standards
While the potential compliance pathway's technology packages that include both vehicles with ICE and ZEV technologies discussed in section II.F.1 and RIA Chapter 2.10 support the feasibility of the final standards and was modeled for rulemaking purposes, there are many other examples of possible compliance pathways for meeting the final standards that do not involve the widespread adoption of BEV and FCEV technologies. In this section, and RIA Chapter 2.11, we provide further support for the feasibility of the final standards by describing examples of additional potential compliance pathways that are based on nationwide production volumes, including compliance pathways that involve only technologies for vehicles with ICE across a range of electrification ( i.e., without producing additional ZEVs to comply with this rule).
In this section, we discuss our analysis for the technologies included in the additional example compliance pathways of the impacts on reductions of GHG emissions; the technical feasibility and technology effectiveness; the lead time necessary to implement the technologies; costs to manufacturers; and willingness to purchase (including purchaser costs and payback). In short, EPA finds that, even without manufacturers producing additional ZEVs to comply with this rule, it would be technologically feasible to meet the final standards in the lead time provided and taking into consideration compliance costs. Regarding reductions of GHG emissions, these additional example potential compliance pathways meet the final Phase 3 MY 2027 through MY 2032 and later CO 2 emission standards, and therefore achieve the same level of vehicle CO 2 emission reductions and downstream CO 2 emission reductions as presented in preamble section V and RIA Chapter 4. Regarding technical feasibility and lead time, depending on the technology, we determined that either no further development of the technology is required (only further application) or that the technology is technically feasible and being actively developed by manufacturers to be commercially available for MY 2027 and later, and that there is sufficient lead time to deploy it. Similar to the approach we considered for BEVs and FCEVs in this preamble section II, for relevant technologies we also included a phased approach to provide lead time to meet the corresponding charging and refueling infrastructure needs under the final rule's additional example potential compliance pathways. Regarding costs of compliance, consistent with our Phase 2 assessment, we conclude that the estimated costs for all model years are reasonable for one of the additional example potential compliance pathways, for example based on our estimate that the MY 2032 fleet average per-vehicle cost to manufacturers by regulatory group will be $3,800 for LHD; $7,600 for MHD vocational vehicles; and $7,700 for HHD vocational vehicles, and range between $10,300 for day cab tractors and $10,400 for sleeper cab tractors. For another additional example potential compliance pathway, which we developed and assessed because manufacturers may choose to offer technologies (such as PHEVs) that have a higher projected upfront cost but also have a shorter payback period, we estimated higher costs of compliance ( e.g., approximately 18 percent of the price of a new tractor for MY 2032) and conclude these costs are also reasonable here given consideration of the corresponding business case for manufacturers to successfully deploy these technologies when considering willingness to purchase, including the payback period of these technologies and the IRA purchaser tax credits for PHEVs. Regarding our assessment of impacts on purchasers and willingness to purchase, the technologies we assessed generally pay back within 10 years or less. As we explain elsewhere in this preamble section II, businesses that operate HD vehicles are under competitive pressure to reduce operating costs, which should encourage purchasers to identify and adopt vehicle technologies that provide a reasonable payback period. For H2-ICE tractors, our assessment is that the operating costs exceed the operating costs of ICE tractors, but there may be other reasons that purchasers would consider this technology such as that the vehicles emit nearly zero CO 2 emissions at the tailpipe, the low engine-out exhaust emissions from H2-ICE vehicles provide the opportunity for efficient and durable after-treatment systems, and the efficiency of H2-ICE vehicles may continue to improve with time. Overall, the fact that such a fleet as the examples assessed in this section are possible underscores both the feasibility and the flexibility of the performance-based standards, and confirms that manufacturers are likely to continue to offer vehicles with a diverse range of technologies, including advanced vehicle with ICE technologies as well as ZEVs for the duration of these standards and beyond.
The vehicles considered in these additional pathways include a suite of technologies ranging from improvements in aerodynamics and tire rolling resistance in ICE tractors, to the use of lower carbon fuels like CNG and LNG, to hybrid powertrains (HEV and PHEV) and H2-ICE. As described in this section, these technologies either exist today or are actively being developed by manufacturers to be commercially available for MY 2027 and later.
This section presents our analysis of the effectiveness of reducing CO 2 emissions, the associated lead time, and the technology package costs for the technologies considered in these additional possible pathways in preamble sections II.F.4.i and II.F.4.ii (we discuss the technologies themselves in preamble section II.D.1). We then created technology packages based on adoption rates of aggregated individual technologies into three scenarios for MYs 2027, 2030, and 2032 that represent additional example potential compliance pathways that further support the feasibility of the final standards in preamble section II.F.4.iii. The technology packages and adoption rates include a mix of vehicles with ICE technologies. For example, the additional example potential compliance pathways include some vocational vehicles with the technology package that supported the Phase 2 MY 2027 CO 2 vocational vehicle emission standards (shown in Table II-4 in preamble section II.D.1, and that include technologies such as low rolling resistance tires; tire inflation systems; efficient engines, transmissions, and drivetrains; weight reduction; and idle reduction technologies) as well as additional natural gas engine, H2-ICE vehicle, hybrid powertrain, and PHEV technologies for vocational vehicles. For another example, the additional example potential compliance pathways include tractors with further aerodynamic and tire improvements in addition to the technology package that supported the Phase 2 MY 2027 CO 2 tractor emission standards (shown in Table II-3 in preamble section II.D.1, and that include technologies such as improved aerodynamics; low rolling resistance tires; tire inflation systems; efficient engines, transmissions, drivetrains, and accessories; and extended idle reduction for sleeper cabs) as well as additional natural gas engine, H2-ICE vehicle, hybrid powertrain, and PHEV technologies for tractors. The technology packages also include our projected reference case (see RIA Chapter 4) ZEV adoption rates. Scenario 1 meets the MY 2032 standards with higher adoption of vehicles with H2-ICE technology. Scenario 2 meets the MY 2032 standards with higher adoption of PHEV technology. Finally, we assessed the manufacturer costs under these additional example potential compliance pathways, in preamble section II.F.4.iv, and purchaser costs and payback in preamble section II.F.4.v. ^{773}
^{773} We also developed another set of technology packages that do not include our projected reference case ZEV adoption rates ( i.e., they are potential compliance pathways that support the feasibility of the standards with only technologies for vehicles with ICE, with zero nationwide adoption of ZEV technologies) which is presented in RIA Chapter 2.11.
The vehicle manufacturers that certified to EPA standards for MY 2022 and/or MY 2023 are those listed in Table II-38. ^{774} Manufacturers used a wide variety of technologies to meet the standards. The manufacturer names with `*' indicate that they have EPA certifications for vehicles that use natural gas. The manufacturer names with `^' indicate they have EPA certifications for vehicles with hybrid powertrains. Since the public certification data for these MYs doesn't identify which vehicles are certified with hybrid powertrains, we relied on information identified in Chapter 1.4 of the RIA. As for hydrogen-fueled internal combustion engines, no manufacturers have certified to EPA standards for MY 2022 with the technology, however a number of manufacturers have indicated that they are developing an engine that can run on hydrogen. ^{775} Finally, there are a number of manufacturers that have certified ICE vehicles that have projected CO 2 FEL that are lower than the Phase 2 MY 2027 standards. The manufacturer names with `#' indicate that they have one or more vehicles families that currently meet the Phase 2 MY 2027 standards, and which we thus project will have CO 2 FEL that are lower than the Phase 2 MY 2027 standards in MY 2027.
^{774} U.S. EPA. “Heavy-Duty Highway Gasoline and Diesel Certification Data (Model Years: 2015—Present” February 2024. Available online: www.epa.gov/compliance-and-fuel-economy-data/annual-certification-data-vehicles-engines-and-equipment .
^{775} Cummins. “Cummins to Reveal Zero-Carbon H2-ICE Concept Truck at IAA Expo Powered by the B6.7H Hydrogen Engine”. September 13, 2022. Available Online: https://www.cummins.com/news/releases/2022/09/13/cummins-reveal-zero-carbon-h2-ice-concept-truck-iaa-expo-powered-b67h .

i. Technology Effectiveness and Lead Time
We evaluated the potential for lower CO 2 emissions from further aerodynamic and tire improvements to ICE tractors as well as natural gas engine, H2-ICE vehicle, hybrid powertrain, and PHEV technologies for both vocational vehicles and tractors, as discussed in section II.D.1 of this preamble. See section II.D.1 for further discussion of EPA's assessment that these technologies are technically feasible.

a. Aerodynamic and Tire Improvements for Tractors
In these additional technology pathways, for further aerodynamic and tire improvements to the technology packages that supported the Phase 2 MY 2027 CO 2 emission standards we evaluated technologies to reduce CO 2 emissions from ICE tractors. Tractors with ICEs have the potential to have lower CO 2 emissions than required by the Phase 2 MY 2027 CO 2 emission standards by further reducing the aerodynamic drag of the tractor and by reducing the tire rolling resistance. These technologies are already being used by manufacturers to certify their tractors to the Phase 2 standards. Therefore, EPA assessed this potential technology package applicable to tractors through a combination of aerodynamic improvements and lower rolling resistant tires.
For this Phase 3 analysis, consistent with our approach in Phase 2 for evaluating technology effectiveness, we evaluated the technologies to reduce aerodynamic drag, as discussed in preamble section II.D.1.i. The aerodynamic drag performance is determined through aerodynamic testing. The results of the test determine the aerodynamic bin (Bin I through VII) and therefore input to GEM that is used to determine a vehicle's CO 2 emissions. The aerodynamic Bin I level represents tractor bodies which prioritize appearance or special duty capabilities over aerodynamics. These Bin I tractors incorporate few, if any, aerodynamic features and may have several features which detract from aerodynamics, such as bug deflectors, custom sunshades, B-pillar exhaust stacks, and others. Bin V represents the most aerodynamic MY 2022 tractors.
The aerodynamic technology already existed for the tractors to achieve Bin IV and Bin V performance in MY 2021, therefore, our assessment is that there is sufficient lead time for tractor manufacturers to increase application of these aerodynamic designs by MY 2027 and to produce more low and mid roof tractors at a Bin IV level of performance and more high roof tractors at a Bin V performance. Because no further development of aerodynamic technology is required, only further application of the technologies, under the additional example potential compliance pathways our assessment is that there is sufficient lead time to include in those technology packages the entire tractor aerodynamic performance to these levels.
For this Phase 3 analysis, we also evaluated technologies to reduce tire rolling resistance on tractors, as discussed in section II.D.1.ii of this preamble. In Phase 2, we developed four levels of tire rolling resistance. The baseline tire rolling resistance level represents the average tire rolling resistance on tractors in 2010. Levels 1, 2, and 3 are lower rolling resistance tires, with each level representing approximately 15 percent lower rolling resistance than the previous level. In the MY 2021 certification data, we found that the average rolling resistance of the steer tires installed on the day cab and sleeper cab tractors was approximately Level 2. The average rolling resistance of the drive tires installed on day cab and sleeper cab tractors was between Level 1 and Level 2 performance. The exception was for high roof sleeper cabs where the average drive tire rolling resistance was at Level 2. The lowest rolling resistance tires used on each of the day cab and sleeper cab configurations was 4.7 N/kN and 4.8 N/kN ton rolling resistance of the steer and drive tires, respectively, which is better than the Level 3 performance. Our assessment for the additional example potential compliance pathways is that tractor tire rolling resistance can shift to a 50/50 split of Level 2 and Level 3 tire rolling resistance for both the steer and drive tires in MY 2027
We used the technology effectiveness inputs and technology adoption rates discussed in this section of the preamble for aerodynamics and tire rolling resistance, along with the other vehicle technologies used in the Phase 2 MY 2027 technology package to demonstrate compliance with the Phase 2 MY 2027 tractor standards to develop the GEM inputs for each subcategory of Class 7 and 8 tractors. The set of GEM inputs are shown in Table II-39. Note that we have analyzed one technology pathway for each level of stringency, but tractor manufacturers are free to use any combination of technologies that meet the standards on average.
The results from GEM for this technology package are shown in Table II-40. As shown, this technology package within the additional example potential compliance pathway achieves 4 percent lower CO 2 emissions than the Phase 2 MY 2027 tractor standards.
In conclusion, under the additional example compliance pathways we project that improvements in ICE vehicle technologies above and beyond the improvements needed to meet the Phase 2 MY 2027 standards will be available for manufacturers to use for tractors and estimate use of those improvements would result in an additional emissions reduction of 4 percent.
We note that in these additional pathways, like in our modeled compliance pathway, the ICE vocational vehicles portion of the pathway emit at the Phase 2 MY 2027 level. Therefore, we did not add any additional technologies or costs associated with the vocational ICE vehicles with Phase 2 MY 2027 technologies. We also note that the Phase 2 standards for vocational vehicles did not include the use of aerodynamic technologies and were projected to be met with the use of improvements in tire rolling resistance and other technologies. Thus, the corresponding ICE vehicle technology package used within the additional example compliance pathway analysis for a portion of the vocational vehicles encompasses the same set of technologies used to demonstrate compliance with the Phase 2 MY 2027 standards, as described in section II.D.1.

b. Natural Gas Fueled Internal Combustion Engines
To estimate the technology effectiveness of natural gas-fueled engines compared to diesel fueled engines in the Phase 3 additional example potential compliance pathways, we used the publicly available MY 2023 heavy-duty engine certification data for CO 2 emissions. ^{776} We compared GHG certification data between three engines of similar displacement, power ratings, and intended model application fueled on CNG and conventional diesel. Family Certification CO 2 Levels for the transient Federal Test Procedure (FTP) and Supplemental Emission Test (SET) duty cycles were compared to determine the CO 2 reductions possible by applying natural gas engine technology, as shown in Table II-41. The comparison shows that natural gas engine technology could achieve CO 2 reductions up to 7 percent for vocational vehicles and 6 percent for tractors compared to a similar diesel fueled ICE.
^{776} U.S. EPA. “Annual Certification Data for Heavy-Duty Vehicles”. January 2023. Available Online: https://www.epa.gov/system/files/documents/2023-01/heavy-duty-gas-and-diesel-engines-2015-present.xlsx .
We also considered the availability of the natural gas fueling stations. According to the U.S. Department of Energy there are 1,464 compressed natural gas and liquified natural gas filling stations in the United States. ^{777} Of these stations, approximately 90 percent of them are CNG stations and 10 percent are LNG stations. These stations are a combination of publicly accessible (783) and privately operated (681). Of the publicly accessible fueling stations, all will accommodate Class 3 through 5 HD vehicles and 1,246 will accommodate HD Class 5 through 8 vehicles. After evaluating the existing, and taking into account potential future, natural gas refueling infrastructure, similar to the approach we considered for BEVs and FCEVs in this preamble section II to ensure adequate lead time for corresponding infrastructure,, we determined that there was adequate lead time for 5 percent adoption of natural gas vehicles in the additional example potential compliance pathways based on our balancing that these technologies are currently available and used as well as the additional consideration of the corresponding infrastructure needed for the level of adoption under these pathways by MY 2027.
^{777} Department of Energy, Energy Efficiency and Renewable Energy, Alternative Fuels Data Center, Alternative Fuel Station Locator. February 2024. Available online: https://afdc.energy.gov/stations/#/find/nearest?fuel=CNG&country=US .

c. Hydrogen-Fueled Internal Combustion Engines
Since neat hydrogen fuel does not contain any carbon, H2-ICE fueled with neat hydrogen produce zero HC, CH 4 , CO, and CO 2 engine-out emissions. ^{778} However, as explained in section III.C.2.xviii, we recognize that, like CI ICE, there may be negligible, but non-zero, CO 2 emissions at the tailpipe of H2-ICE that use SCR and are fueled with neat hydrogen due to contributions from the aftertreatment system from urea decomposition; thus, for purposes of 40 CFR part 1036 we are finalizing an engine testing default CO 2 emission value (3 g/hp-hr) option (though manufacturers may instead conduct testing to demonstrate that the CO 2 emissions for their engine is below 3 g/hp-hr). Under this final rule, consistent with treatments of such contributions from the aftertreatment system from urea decomposition for diesel ICE vehicles, we are not including such contributions as vehicle emissions for H2-ICE vehicles. ^{779} Thus, H2-ICE technologies that run on neat hydrogen, as defined in 40 CFR 1037.150(f) and discussed in section III.C.3.ii of the preamble, have HD vehicle CO 2 emissions that are deemed to be zero for purposes of 40 CFR part 1037. Therefore, the technology effectiveness (in other words CO 2 emission reduction) for the vehicles that are powered by this technology is 100 percent.
^{778} Note, NOx and PM emission testing is required under existing 40 CFR part 1036 for engines fueled with neat hydrogen.
^{779} The results from the fuel mapping test procedures prescribed in 40 CFR 1036.535 are fuel consumption values, therefore the CO 2 emissions from urea decomposition is not included in the results.
The lead time consideration for H2-ICE vehicles consists of two parts. The first part is the engine technology design and development, along with the integration of the engine, aftertreatment, and fuel storage integration into the vehicle. The second part is the hydrogen refueling infrastructure availability.
An H2-ICE is very similar to existing ICEs and engine manufacturers can leverage the extensive technical expertise they have developed with existing products. Many H2-ICE engine components can be produced using an engine manufacturer's existing tooling and manufacturing processes. Similarly, H2-ICE vehicles can be built on the same assembly lines as other ICE vehicles, by the same workers and with many of the same component suppliers. For example, Cummins has announced the launch of a fuel-agnostic combustion engine X10 for MY 2026 that can run on hydrogen fuel. ^{780} Many design aspects of the integration of a H2-ICE into a vehicle can be done in parallel with the H2-ICE ramp up to the production launch of an engine. However, there may be final validation vehicle development steps that will require the final H2-ICE and therefore may take an additional year after the launch of an H2-ICE. Therefore, from the technology development perspective, we project H2-ICE technology will be available in MYs 2027 and later.
^{780} Cummins. “Cummins Announces New X10 Engine, Next in The Fuel-Agnostic Series, Launching in North America in 2026.” February 2023. Available Online: https://www.cummins.com/news/releases/2023/02/13/cummins-announces-new-x10-engine-next-fuel-agnostic-series-launching-north .
The discussion in RIA Chapter 1.8.3 details our assessment of hydrogen refueling infrastructure. After evaluating the existing and projected future hydrogen refueling infrastructure and similar to the approach we considered for publicly-charged BEVs and FCEVs in this preamble section II, we considered H2-ICE vehicle technology only in the MY 2030 and later timeframe for the additional example potential compliance pathways, to better ensure that our additional example potential compliance pathways provide adequate time for early hydrogen market infrastructure development. We included the H2-ICE technology in the additional compliance pathway relative to the reference case in MY 2031 and later, which provides nearly seven years of lead time for the H2 refueling infrastructure buildout to phase in.

d. Hybrid and Plug-in Hybrid Powertrains
As discussed in section II.D.1.v, hybrid powertrains have lower CO 2 emissions than ICE powertrains due to a combination of regenerative braking and the ability to optimize the ICE operation within the hybrid powertrain system. For this Phase 3 analysis we used the approach described in Chapter 2.2.2.1.3 of the RIA to determine the effectiveness of hybrids based on the amount of braking energy recovered from regenerative braking. In summary, to calculate percent energy recovery available, we estimated the braking energy and divided by the total tractive energy ( i.e., the energy required to move the vehicle) for each drive cycle and then weighted the results using the respective GEM test cycle weighting factors. We then multiplied these values by the weighted energy consumption per mile to get energy recovered per mile from regenerative braking. The average regeneration energy as a percentage of total tractive energy was 10 percent and 5 percent, for vocational vehicles and tractors, respectively. For both tractors and vocational vehicles, we project that hybrid technology can achieve an additional 5 percent of effectiveness by optimizing how the engine is operated. For example, the engine could be operated in the minimum brake-specific fuel consumption region of the engine more often in a hybrid powertrain. In addition, the electric motor could be used to limit engine transient operation, or the engine could be downsized. This leads to an overall CO 2 emission reduction of 15 percent for vocational vehicle hybrids and 10 percent for tractor hybrids.
For hybrid electric vehicles, the projected effectiveness is further supported by powertrain testing that was conducted by Eaton at Argonne National Laboratory. The testing was performed with a Cummins X15 engine and three transmissions. The transmissions were an Eaton P2/P3 hybrid, Eaton Endurant, and an Allison 4500 RDS. For each of the three powertrain configurations, the test procedures prescribed in 40 CFR 1036.545 were followed to generate powertrain fuel maps. Each of these fuel maps were input into GEM Version 3.5.1 to determined gCO 2 /ton-mile emissions from a number of representative vehicle configurations. For the heavy heavy-duty vocational vehicles, the average CO 2 emission reductions were 22, 8, and 25 percent for multi-purpose, regional, and urban regulatory subcategories respectively. The average CO 2 reductions for day cab and sleeper cab tractors was 9 percent. The data from the powertrain tests supports the estimated CO 2 emission reduction of 15 percent for vocational vehicle hybrids, as it is expected that vocational vehicle hybrids will be certified as multi-purpose or urban. The data from the powertrain tests also supports the estimated CO 2 emission reduction of 10 percent for tractor hybrids, since many of the individual tractors had greater than 10 percent CO 2 emission reduction, with the average at 9 percent.
In addition, other studies have also shown CO 2 emission reductions from heavy-duty hybrid vehicles. For example, a New Flyer hybrid transit bus achieves 10-29 percent reduction, depending on route. ^{781} Similarly, a NovaBus hybrid transit bus found up to 30 percent reduction in CO 2 emissions at speeds ranging between 9-18 mph. ^{782} A NREL report of a reduction of 75 percent CO 2 in idle emissions during PTO use ^{783} where idle operation is over 30 percent of vehicle operating time and uses 10 percent of the fuel. ^{784} A study with a Pierce Manufacturing hybrid fire truck showed 1,500 gallons of diesel saved in one month which also leads to a reduction in CO 2 emissions. ^{785}
^{781} New Flyer. “Hybrid-electric mobility.” Available online: https://www.newflyer.com/bus/xcelsior-hybrid/.
^{782} NovaBus. “Nova LFS HEV”. Available online: https://novabus.com/blog/bus/lfs_hev/ .
^{783} Ragatz, Adam, Jonathan Burton, Eric Miller, and Matthew Thornton. “Investigation of Emissions Impacts from Hybrid Powertrains” National Renewable Energy Lab. January 2020. Available online: https://www.nrel.gov/docs/fy20osti/75782.pdf .
^{784} Konan, Arnaud, Adam Duran, Kenneth Kelly, Eric Miller, and Robert Prohaska. “Characterization of PTO and Idle Behavior for Utility Vehicles”. National Renewable Energy Lab. Available online: https://www.nrel.gov/docs/fy17osti/66747.pdf .
^{785} Pierce. “Pierce Volterra Platform of Electric Vehicles”. Available online: https://www.piercemfg.com/electric-fire-trucks/pierce-volterra .
Hybrid technology is currently being used on heavy-duty vehicles. RIA Chapter 1.4.5 details the HD truck and bus models that are currently offered as hybrid vehicles. As shown, both Allison and BAE offer heavy-duty hybrid systems for use in vehicles. Our assessment, based on currently available hybrid technology that is being produced in vehicles today, is that there is adequate lead time for manufacturers to increase the adoption of the technology for LHD and MHD vocational vehicles in MY 2027 and for HHD vocational vehicles and tractors in MY 2030 to the adoption levels included in the additional pathways.
Plug-in hybrid electric vehicles run on both electricity and fuel. The utility factor is the fraction of miles the vehicle travels in electric mode relative to the total miles traveled. The percent CO 2 emission reduction is directly related to the utility factor. The greater the utility factor, the lower the tailpipe CO 2 emissions from the vehicle. The utility factor depends on the size of the battery and the operator's driving habits. For PHEVs, we project that for MY 2027 and MY 2032 tractors, a CO 2 emission reduction (effectiveness) of 30 percent is achievable by adding a high-voltage battery that could achieve a utility factor of 22 percent. For MY 2027 vocational vehicles, we project an effectiveness of 30 percent could be achieved by adding a high-voltage battery with a utility factor of 18 percent. For MY 2030 vocational vehicles, we project an effectiveness of 50 percent could be achieved by adding a high-voltage battery with a utility factor of 41 percent. With utility factors between 18 to 41 percent, a significantly smaller battery would be needed for a PHEV in comparison to the battery needed for a corresponding battery electric vehicle.
For heavy-duty PHEVs, the projected effectiveness is further supported by powertrain testing that was conducted by Eaton at Argonne National Laboratory. To evaluate the emissions reductions of a plug-in hybrid powertrain, Eaton used a combination of GEM simulations and powertrain test results. The results of the analysis showed that a vocational vehicle with a plug-in hybrid powertrain could reduce CO 2 emission by 52 percent. ^{786}
^{786} Sanchez, James. Memorandum to Docket EPA-HQ-OAR-2022-0985. “Eaton Hybrid Powertrain Results” February 2024.
In our lead time assessment for PHEVs, we believe it will take longer for vehicle manufacturers to integrate this technology into vehicles than it will for hybrid technologies. We determined that approximately 3-4 years would be necessary to develop this technology. Therefore, we conservatively included PHEVs in limited applications (HHD vocational vehicle and day cab tractors) beginning in MY 2030 and included a scenario in MY 2032 with and without PHEVs in the technology packages that also include our projected reference case ZEV adoption rates. PHEVs, like BEVs, require an external charging source to provide electricity to the vehicle. However, the recharging demand for a PHEV is much lower than a comparable BEV. Therefore, most heavy-duty PHEVs could use Level 1 charging by plugging it into a standard 240 V outlet. Truck operators would have access to these outlets at depots and other businesses without having to require special installation of EVSE equipment. Operators would need to create access to such an outlet, but this would not be a constraining factor for lead time and such costs would be low for purchasers. Similar to the approach we considered for BEVs and FCEVs in this preamble section II, we determined there is adequate lead time to meet the projected charging infrastructure needs that correspond to the technology packages for the final rule's additional example potential compliance pathways. Furthermore, because the recharging demand for PHEVs will be lower than the levels for BEVs in our modeled potential compliance pathway, the demand on the grid would be less than assessed with our modeled potential compliance pathway discussed in preamble section II.D.2.iii.

e. Summary of the Technology Effectiveness
Table II-42 shows the summary of the technology effectiveness (percent CO 2 emission reduction) of each of the technologies discussed in this subsection relative to the Phase 2 MY 2027 standards.
Table II-42 Effectiveness of Technologies of Vehicles with ICE Relative to the MY 2027 Phase 2 Standards

ii. Technology Package Costs
In this section, we present the incremental technology package costs for each technology relative to the comparable baseline vehicles that meet the Phase 2 MY 2027 emission standards. ^{787}
^{787} The costs presented in this section do not include the learning effects after MY 2027, and therefore are higher than they would be if they included learning ( i.e., are conservative in the overestimating sense).

a. ICE Vehicle Improvements
The costs for the additional aerodynamic and low rolling resistance tire technologies were developed based on the cost assessment in the Phase 2 final rule. ^{788} These technology costs developed for the Phase 2 analysis remain appropriate because the technologies are the same and the costs including learning through MY 2027. As discussed in RIA Chapter 2.11.2.1, the incremental technology package cost of increased application of aerodynamic technologies and low rolling resistance tires is $1,978 for sleeper cab tractors and $1,715 for day cab tractors.
^{788} U.S. EPA. Regulatory Impact Analysis Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles—Phase 2. Chapter 2. EPA-420-R-16-900. August 2016.

b. Natural Gas Fueled Internal Combustion Engines
EPA contracted FEV to conduct a technology and cost study for a variety of powertrains applicable to Class 4, 5, 7, and 8 heavy-duty vehicles. ^{789} FEV also costed three (15L for Class 8, 10L for Class 7, and 6.6L for Class 4/5 ) diesel ICE powertrains that would meet the emission standards as required by the Low NOx Rule and the Phase 2 CO 2 emission standards in MY 2027. These were used to calculate the incremental cost of the alternative powertrain to the comparable diesel ICE powertrain baseline, as described in RIA Chapter 2.11.2.2.
^{789} FEV Consulting. “Heavy Duty Commercial Vehicles Class 4 to 8: Technology and Cost Evaluation for Electrified Powertrains—Final Report”. Prepared for EPA. March 2024.
The costs presented in Table II-43 include both the direct and indirect costs of compliance for manufacturers and represent a market stable scenario where the technologies are mature, which is appropriate because natural gas technologies have been used in the heavy-duty marketplace for decades. The costs represent the incremental costs of a spark-ignited (SI) CNG engine because that is the predominant technology being offered today in the heavy-duty market. ^{790}
^{790} Cummins. Natural Gas Engine Portfolio. Available online: https://mart.cummins.com/imagelibrary/data/assetfiles/0063969.pdf.
One difference in costs between a CNG powertrain and the baseline diesel powertrain is the fuel `tank.' A CNG vehicle requires pressurized fuel tanks typically made with carbon fiber in order to hold the fuel at required pressures of 250 bar. These tank types are much higher in cost than a tank to hold diesel fuel which does not require the capability to store fuel under pressure. The larger the vehicle and/or the longer the distance traveled per day dictates the number and size of the tanks required. Cost of tanks for the CNG Class 8 day cab and sleeper cab tractor powertrains were estimated to be $10,000-$16,500. ^{791}
^{791} Caffrey, Cheryl. Memorandum to the docket EPA-HQ-OAR-2022-0985. “Alternative Powertrain Costs” February 2024.
Another area of difference is in the aftertreatment required on CNG powertrains compared to a diesel. The current diesel powertrain contains a DOC, DPF, SCR and associated urea injection/mixing system. Spark-ignited CNG engines run stoichiometric combustion and therefore only require a three-way catalyst to reduce HC, CO and NOx, similar to gasoline-fueled ICE vehicles. Engine-out PM from SI-CNG fueled vehicles meet the exhaust emission standards without additional aftertreatment. Therefore, spark-ignited CNG vehicles do not require a DPF, DOC, SCR or the DEF and urea mixing system and a significant cost reduction compared to the diesel powertrain baseline is realized. Another cost reduction comes from the fuel injection system. The diesel system has a fuel injection system used to atomize the diesel fuel as it goes into the combustion chamber. These components are not needed on a gaseous fuel as it is already in combustible form.

c. Hydrogen-Fueled Internal Combustion Engines
We used the same FEV cost study to develop the incremental technology costs for H2-ICE vehicles, as shown in Table II-44. ^{792}
^{792} Caffrey, Cheryl. Memorandum to the docket EPA-HQ-OAR-2022-0985. “Alternative Powertrain Costs” February 2024.
As with CNG, a major difference between H2-ICE powertrains and the baseline diesel powertrain is the fuel `tank.' The H2-ICE requires pressurized fuel tanks typically made with carbon fiber and many other considerations in order to hold the fuel at required pressures. The H2 tanks used in the FEV cost study are designed to store H2 at 700 bar so that they can hold sufficient hydrogen. These tank types are much higher in cost than a tank to hold diesel fuel because the fuel is pressurized. The cost of the tanks on the Class 8 sleeper cab tractors can add on $30,000 in low volumes to the H2-ICE powertrain costs.
Also similar to CNG, a significant cost decrease compared to the baseline powertrain is due to the difference in the aftertreatment required on H2-ICE fueled powertrains compared to the baseline diesel powertrain. The baseline diesel powertrain contains a DOC, DPF, SCR and an associated urea mixing/dosing system. These aftertreatment components work to reduce hydrocarbons, carbon monoxide, particulate matter and NOx, respectively. Only SCR and DOC aftertreatment is required on a H2-ICE fueled with neat H2 in order to reduce NOx. In developing the aftertreatment cost for the H2-ICE, an exhaust gas heater was also included in order to reduce NOx at idle and during low power operation. Another cost decrease compared to the baseline powertrain comes from the fuel injection system. The baseline diesel system has a number of components to atomize the diesel fuel as it goes into the combustion chamber. These components are not needed on a H2-ICE because the H2 is a gaseous fuel in combustible form.

d. Hybrids and Plug-In Hybrid Powertrains
To determine the hybrid powertrain costs, we relied on the Autonomie study results published with the 2023 DOE VTO/HFTO Transportation Decarbonization Analysis. ^{793} The results include vehicle costs for conventional vehicles and parallel hybrid vehicles for each vehicle class. RIA Chapter 2.11.2.4 describes the process for determining the incremental powertrain costs for each hybrid powertrain. The summary of the hybrid vehicle costs are in Table II-45.
^{793} US Department of Energy. Available online: https://anl.box.com/s/hv4kufocq3leoijt6v0wht2uddjuiff4 and
https://anl.box.com/s/oy04bje3ltc21rz5py4bq1ed4s4bn0vo.
The PHEV technology combines an ICE powertrain with a BEV powertrain. Therefore, we calculated the incremental costs of the PHEV technology using a similar approach as we did for BEVs and ICEVs in HD TRUCS for each of the 101 vehicle types, as detailed in RIA Chapter 2.3.2 and 2.4.3. We used the same component costs for the ICE powertrain, except replaced the ICE accessory costs with the electrified accessory component costs used in BEVs. For the electrified portion of the PHEV, we also included the electric motor, onboard charger, and power converter costs for a similar BEV. The key difference between the BEV and PHEV powertrain costs is due to the size of the battery. We reduced the size of the battery for the PHEV relative to a BEV to reflect a utility factor of 41 percent for vocational vehicles and 22 percent for tractors and we conservatively estimated that the depth of discharge of a PHEV battery would be only 60 percent compared to the BEV battery depth of discharge of 90 percent. The incremental component costs for each of the HD TRUCS 101 vehicle types are shown in RIA Chapter 2.11.2.4, including direct manufacturing costs and the battery tax credit as applicable.
The individual vehicles were aggregated into the corresponding regulatory class. ^{794} We then included the indirect manufacturing costs as well; the incremental additional retail price equivalent (RPE) for PHEVs by regulatory group using the 1.42 multiplier for MY 2030 are shown in Table II-46.
^{794} The sleeper cab tractor costs were calculated using Vehicles 32, 78, and 79.

e. Summary of Technology Costs
A summary of the per vehicle incremental technology costs for each of the technologies is shown in Table II-47.

iii. Technology Adoption Rates in the Additional Potential Compliance Pathways
As we did for the modeled potential compliance pathway, for this additional example potential compliance pathway we determined the technology mix of technologies for vehicles with ICE across a range of electrification, which for this additional pathway consists of a mix of adoption of natural gas vehicles, hybrid vehicles, plug-in hybrid vehicles, H2-ICE vehicles, and aerodynamic and tire rolling resistant improvements for tractors for MYs 2027, 2030 and 2032, and including those ZEVs from our projected reference case ZEV adoption rates as described in RIA Chapter 4. These values represent the total national HD vehicle sales, including those accounted for in the reference case. However, for this additional example compliance pathway, the portion of the overall HD sales that are projected to be ZEVs in the reference case are the same portion projected to be ZEVs under the final rule ( i.e., no additional ZEVs are included to meet the final Phase 3 standards). Thus, this additional example compliance pathway supports the feasibility of the Phase 3 standards relative to the “no action” projection of ZEV adoption nationwide. We considered two scenarios for the adoption rates in MY 2032. The adoption rates for this pathway are shown in Table II-48 through Table II-50.

iv. Additional Example Potential Compliance Pathways—Manufacturer Costs To Meet the Final Standards
The fleet average per-vehicle technology costs of the additional example potential compliance pathway relative to the reference case (that includes ZEV adoption in the reference case, at the adoption rates of our “no action” reference case in RIA Chapter 4) are shown in Table II-51 for MYs 2027, 2030 and 2032.
We developed two scenarios for MY 2032. Scenario 1 includes H2-ICE vehicles without any PHEVs. Scenario 2 predominately includes PHEVs with only limited adoption of H2-ICE technology in day cab tractor applications. We estimate in Scenario 1 that the MY 2032 fleet average per-vehicle cost to manufacturers by regulatory group will be $3,800 for LHD; $7,600 for MHD vocational vehicles; and $7,700 for HHD vocational vehicles. The MY 2032 fleet average per-vehicle costs to manufacturers in Scenario 1 will range between $10,300 for day cab tractors and $10,400 per sleeper cab tractors. The Phase 2 MY 2027 tractor standard incremental fleet average per-vehicle costs were projected to be between $12,750 and $17,125 (2022$) per vehicle and the vocational vehicle standards were projected to cost between up $7,090 (2022$) per vehicle. ^{795} EPA notes the projected costs per vehicle for this final rule under Scenario 1 are similar to the fleet average per-vehicle costs projected for the HD Phase 2 rule that we considered to be reasonable. ^{796} EPA's assessment here is similarly that these estimated costs are reasonable for all model years.
^{795} The Phase 2 tractor MY 2027 standard cost increments were projected to be between $10,200 and $13,700 per vehicle in 2013$ (81 FR 73621). The Phase 2 vocational vehicle MY 2027 standards were projected to cost between $1,486 and $5,670 per vehicle in 2013$ (81 FR 73718).
^{796} 81 FR 73621-622 (tractors) and 73718-19 (vocational vehicles).
The projected manufacturer fleet average per-vehicle technology costs in Scenario 2 for MY 2032 are higher than Scenario 1. We developed this scenario because manufacturers may choose to offer technologies, such as PHEVs, that have a higher projected upfront cost, but also have a shorter payback period and therefore potentially a better business case and purchasers may demonstrate more willingness to buy. The costs to tractor manufacturers in the PHEV-focused scenario represent approximately 18 percent of the price of a new tractor (conservatively estimated to be $140,000 for day cab tractors and $190,000 for sleeper cab tractors in 2023). ^{797} We believe this is reasonable here for all model years given consideration of the corresponding business case for manufacturers to successfully deploy these technologies when considering the payback period of these technologies, including the IRA purchaser tax credits for PHEVs.
^{797} Memo to Docket. “Sample Heavy-Duty Truck Prices in 2023.” Docket EPA-HQ-OAR-2022-0945.

v. Additional Example Potential Compliance Pathways—Purchaser Cost Considerations
In this section, we discuss items associated with the purchaser costs for each of the technologies considered. Under this approach for vehicles with ICE technologies, our evaluation of payback focuses on whether the technology pays back within the period of first ownership. Consistent with our Phase 2 approach to vehicles with ICE technologies, if the vehicle with ICE technology pays back within this period, then we consider that technology within the additional example potential compliance pathways. We also evaluate payback period, consistent with our approach to consideration of payback in Phase 2 for vehicles with ICE technologies. ^{798} See also our discussion of first ownership in section II.F.1 of this preamble. We also evaluated and included vehicle with ICE technologies if we assessed there may be other reasons that purchasers would consider such technologies, such as that the vehicles emit nearly zero CO 2 emissions at the tailpipe, low engine-out exhaust emissions provide the opportunity for efficient and durable after-treatment systems, and the potential for future efficiency improvements within the lead time provided.
^{798} See 81 FR 73621-622 (tractors) and 73718-19 (vocational vehicles).

a. ICE Vehicles
Reducing the energy required to move a tractor down the road through aerodynamic improvements and reductions in tire rolling resistance will lead to reduction in operating costs. Our technology packages that include additional improvements to ICE vehicles reduced the CO 2 emissions, and therefore energy consumption, by 4 percent. The cost savings related to the reduction in fuel and DEF consumed depends on the number of miles driven, among other factors. The average DEF and diesel fuel costs for each of the baseline diesel-fueled ICE vehicle applications in HD TRUCS were developed as discussed in RIA Chapter 2.3.4. As shown in RIA Chapter 2.11.5.1, the average operating cost savings varies depending on the vehicle ID, ranging from approximately $280 to $1,800 per year. The average annual operating savings for a day cab tractor is $700 and is $1,600 for a sleeper cab tractor. Based on the technology package costs shown in section II.F.4.ii.a for additional ICE vehicle improvements, the payback period for the technology improvements would be less than three years for day cab tractors and less than two years for sleeper cab tractors.

b. Natural Gas Fueled Vehicles
The operating savings of NG vehicles come from both the elimination of the DEF costs because these vehicles use three-way catalysts and from the reduced fueling costs. When comparing fuel efficiency between diesel and SI natural gas powered HD vehicles, dependent on vehicle and duty cycle, natural gas returns 7 percent to 12 percent less fuel economy. ^{799} Therefore, we calculated the natural gas consumption using a conversion factor of 139.3 standard cubic feet (scf) to diesel gallon equivalent and applying a 10 percent fuel economy penalty to the diesel fuel consumption. ^{800} The average diesel fuel consumption, diesel fuel costs, and DEF costs for each of the baseline diesel-fueled ICE vehicle applications in HD TRUCS were developed as discussed in RIA Chapter 2.3.4. We then calculated the average annual natural gas fuel costs for each of the HD TRUCS applications by vehicle ID using $18.23/thousand cubic feet price, as shown in RIA Chapter 2.11.5.2. ^{801} The natural gas powered vehicles have immediate paybacks for some vehicle categories and payback periods of less than one year for all applications when the operating savings are compared to the upfront incremental costs of the NG vehicles, as shown in section II.F.4.ii.b.
^{799} Department of Energy, Energy Efficiency and Renewable Energy, Alternative Fuel Data Center, Vehicle and Infrastructure Cash-Flow Evaluation Tool (VICE), https://afdc.energy.gov/vice_model/ , accessed February 17, 2024.
^{800} U.S. DOE. Available online: https://afdc.energy.gov/fuels/equivalency_methodology.html .
^{801} U.S. DOE/Energy Information Administration. Annual Energy Outlook 2023. Reference Case. Table 13. Transportation Natural Gas Spot Price for 2022. Available online: https://www.eia.gov/outlooks/aeo/data/browser/#/?id=13-AEO2023&cases=ref2023&sourcekey=0 .

c. H2-ICE Vehicles
The operating costs of H2-ICE vehicles include H2 consumption to power the engine and DEF consumption to control the NOx emissions. These costs are compared to the operating DEF and diesel fuel costs for each of the baseline diesel-fueled ICE vehicle applications in HD TRUCS, as discussed in RIA Chapter 2.3.4.
H2-ICE vehicles operate on H2 gas instead of diesel fuel. We calculated the H2-ICE hydrogen fuel costs relative to our assessment of the hydrogen costs for FCEVs for each of the vehicle applications in HD TRUCS, as discussed in RIA Chapter 2.5.3.1.When comparing efficiencies between FCEV and H2-ICE vehicles, the FCEVs have an average efficiency of 53 percent, as discussed in RIA Chapter 2.5.1.2.1, while H2-ICEV has an efficiency of 42 percent. ^{802} Therefore, we calculated the H2 fueling costs for H2-ICE relative to the FCEV fueling costs by applying a ratio of 0.53/0.42.
^{802} FEV, “Hydrogen ICE”, The Aachen Colloquium Sustainable Mobility, October 5th-7th, 2020.
The H2-ICE vehicles also require a SCR system to control NOx, but the system will be smaller than a comparable diesel ICE vehicle because the engine-out NOx emissions are lower. We calculated the annual DEF costs for H2-ICE vehicles as 10 percent of the DEF costs for a comparable baseline diesel ICE vehicle. ^{803} The average DEF costs for each of the baseline diesel-fueled ICE vehicle applications in HD TRUCS were developed as discussed in RIA Chapter 2.3.4. The net annual operating savings for each of the HD TRUCS vehicle applications by vehicle ID is shown in RIA Chapter 2.11.5.3. The upfront H2-ICE powertrain technology costs, as shown in section II.F.4.ii.c, on average would pay back in 2 years for LHD vocational vehicles, 6 years for MHD vocational vehicles, 9 years for HHD vocational vehicles. The operating costs for H2-ICE tractors exceed the operating costs of ICE tractors, but there may be other reasons that purchasers would consider this technology such as the vehicles emit nearly zero CO 2 emissions at the tailpipe, the low engine-out exhaust emissions from H2-ICE vehicles provide the opportunity for efficient and durable after-treatment systems, and the efficiency of H2-ICE vehicles may continue to improve with time. ^{804}
^{803} Srna, Ales. Sandia National Laboratory. “The future of H2 internal combustion engines in California?” Slide 4. December 2023. Available online: https://ww2.arb.ca.gov/sites/default/files/2023-12/231128sandiapres.pdf .
^{804} As we explain in RTC 2.1, the statute does not require that pollution control technologies pay back in the form of operational savings, or even require EPA to consider costs to consumers. While payback is relevant to ascertaining willingness to purchase, EPA notes that many pollution control technologies do not pay back. Notwithstanding the lack of payback, such technologies have played a critical role in achieving the public health and welfare goals of section 202(a) and have been widely adopted by manufacturers and purchasers. These include technologies Congress itself contemplated in enacting the Clean Air Act section 202(a), such as catalytic converters, as well as other technologies that are the foundation for modern pollution control on HD motor vehicles, such as particulate matter filters.

d. Hybrid and Plug-In Hybrid Vehicles
Hybrid vehicles, similar to other ICE vehicle improvements, will have lower operating costs than a comparable ICE vehicle due to reduced diesel fuel consumption and DEF consumption. These HEV costs are compared to the operating DEF and diesel fuel costs for each of the baseline diesel-fueled ICE vehicle applications in HD TRUCS, as discussed in RIA Chapter 2.3.4. As discussed, we used an effectiveness level for vocational vehicle hybrid powertrains of 15 percent and for tractor hybrid powertrains of 10 percent.
The annual operating savings for HEVs was calculated for each of the HD TRUCS vehicle applications, as shown in RIA Chapter 2.11.5.4 by reducing the diesel ICE DEF and fuel costs by 15 percent for vocational vehicles and 10 percent for tractors. The annual operating savings were then compared to the upfront technology costs, as shown in section II.F.4.ii.d. The hybrid powertrain technology will pay back in 10-11 years for vocational vehicles, but in a shorter period of time for some applications such as refuse haulers, step vans, and transit buses. The average payback period for this technology in day cab tractors is 7.5 years and 4 years in sleeper cab tractors.
Similar to our discussion for ZEVs under the modeled potential compliance pathways, the IRA provides powerful incentives in reducing the cost to manufacture and purchase PHEVs, as well as reducing the cost of charging infrastructure as applicable (see further discussion in this section), that facilitates market penetration of PHEV technology in the time frame considered in this rulemaking. The upfront costs to purchasers of PHEVs would be less than the cost to manufacturers due to the IRA purchaser tax credit. IRA section 13403, “Qualified Commercial Clean Vehicles,” creates a tax credit of up to $40,000 per Class 4 through 8 HD vehicle (up to $7,500 per Class 2b or 3 vehicle) for the purchase or lease of a qualified commercial clean vehicle. This tax credit is available from CY 2023 through CY 2032 and is based on the lesser of the incremental cost of the clean vehicle over a comparable ICE vehicle or the specified percentage of the basis of the clean vehicle, up to the maximum $40,000 limitation. Among other specifications, these vehicles must be on-road vehicles (or mobile machinery) that are propelled to a significant extent by a battery-powered electric motor or are qualified fuel cell motor vehicles. For the former, the battery must have a capacity of at least 15 kWh (or 7 kWh if it has a gross vehicle weight rating of less than 14,000 pounds (Class 3 or below)) and must be rechargeable from an external source of electricity. For PHEVs, the per-vehicle tax credit cap limitation is 15 percent of the vehicle cost, which is the limiting factor for many of the applications. Since this tax credit overlaps with the model years for which we are finalizing standards (MYs 2027 through 2032), we included it in our calculations for each of those years in our analysis, as shown in Table II-52.
The purchaser of a HD PHEV would need to consider the recharging needs of the vehicle. Because the battery sizes in HD PHEVs are significantly smaller than a comparable BEV and only discharge 60 percent of their battery in-use, the recharging demand is also lower than a comparable BEV. Therefore, for this analysis, the vehicles use depot charging and recharge with a 240 V/50 amp outlet that we project are available at no additional upfront infrastructure cost. There may be situations where the operator would need to create access to such an outlet, but those costs would be low. Furthermore, as discussed in RIA Chapter 1.3.2, the IRA can also help reduce the costs for deploying EVSE infrastructure if the operator desires faster recharging times. The IRA extends the Alternative Fuel Refueling Property Tax Credit (section 13404) through 2032, with modifications. Under the new provisions, businesses would be eligible for up to 30 percent of the costs associated with purchasing and installing charging equipment in these areas (subject to a $100,000 cap per item) if prevailing wage and apprenticeship requirements are met.
Plug-in hybrid vehicle operating costs consist of a combination of ICE operation and battery electric operation. These PHEV costs are calculated relative to the operating costs for each of the baseline diesel-fueled ICE vehicle applications in HD TRUCS, as discussed in RIA Chapter 2.3.4 and the comparable BEV operating costs, as discussed in RIA Chapter 2.4.4. As discussed, we used a utility factor for vocational vehicle PHEV powertrains of 41 percent and for tractor PHEV powertrains of 22 percent in MY 2030 and later. The annual operating savings was evaluated for each of the HD TRUCS vehicle applications compared to the comparable baseline diesel ICE vehicle, as shown in RIA Chapter 2.11.5.4. The incremental cost of the PHEV powertrain technology after accounting for the IRA tax credit as shown in Table II-52 for vocational vehicles will be offset by the operating savings with a payback period of 3 years. The day cab and sleeper cab tractor upfront costs would be offset with operational savings over an 8-and 9-year period, respectively.

G. EPA's Basis for Concluding That the Final Standards Are Feasible and Appropriate Under the Clean Air Act

1. Overview
Section 202(a)(1) directs the Administrator to promulgate “standards applicable to the emission of any air pollutant from any class or classes of new motor vehicles or new motor vehicle engines, which in his judgment cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare.” See also Coalition for Responsible Regulation v. EPA, 684 F. 3d at 122 (“the job Congress gave [EPA] in § 202(a)” is “utilizing emission standards to prevent reasonably anticipated endangerment from maturing into concrete harm”). As discussed in section II.A of this preamble, there is a critical need for further GHG reductions to address the adverse impacts of air pollution from HD motor vehicles on public health and welfare. Heavy-duty vehicles are significant contributors to the U.S. GHG emissions inventories, and additional reductions in GHGs from vehicles are needed to avoid the worst consequences of climate change as discussed in section II.A. With continued advances in internal combustion engine and vehicle emissions controls and ZEV technologies coming into the mainstream as key vehicle emissions controls, EPA's assessment is that substantial further GHG emissions reductions are feasible and appropriate under Clean Air Act section 202(a)(1).
To this end, as in the HD GHG Phase 1 and Phase 2 rulemakings, in this Phase 3 final rule we considered the following factors in setting final Phase 3 GHG standards: the impacts of potential standards on reductions of GHG emissions; technical feasibility and technology effectiveness; the lead time necessary to implement the technologies; costs to manufacturers; costs to purchasers including operating savings; reduction of non-GHG emissions; the impacts of standards on oil conservation and energy security; the impacts of standards on the truck industry; other energy impacts; as well as other relevant factors such as impacts on safety. ^{805} To evaluate and balance these statutory factors and other relevant considerations, EPA must necessarily estimate a means of compliance: what technologies are projected to be available to be used, what do they cost, and what is appropriate lead time for their deployment. Thus, to support the feasibility of the final standards, EPA identified a potential compliance pathway. Having identified one means of compliance, EPA's task is to “answe[r] any theoretical objections” to that means of compliance, “identif[y] the major steps necessary,” and to “offe[r] plausible reasons for believing that each of those steps can be completed in the time available.” NRDC
v. EPA, 655 F. 2d at 332. That is what EPA has done here in this final rule, and indeed what it has done in all of the motor vehicle emission standard rules implementing section 202(a) of the Act for half a century.
^{805} 76 FR 57129, September 15, 2011, and 81 FR 73512 October 25, 2016.
In assessing the means of compliance, EPA considers updated data available at the time of this rulemaking, including real-world technological and corresponding cost developments related to emissions-reducing technologies for HD vehicles. The statute directs EPA to assess the “development and application of the requisite technology, giving appropriate consideration to the cost of compliance within” the relevant timeframe, and specifically compels EPA to consider relevant emissions-reduction technologies on vehicles and engines regardless of “whether such vehicles and engines are designed as complete systems or incorporate devices to prevent or control such pollution.” CAA section 202(a)(1), (2). The statute does not prescribe particular technologies, but rather entrusts to the EPA Administrator the authority and obligation to identify a range of available technologies that have the potential to significantly control or prevent emissions of the relevant pollutant, here GHGs, and to establish standards based on his consideration of the lead-time and costs for such technologies, along with other factors. At the same time, the statute does specifically identify criteria for technologies that cannot serve as the basis for the standards: first, technologies which cannot be developed and applied within the relevant time period, giving appropriate consideration to the cost of compliance; and second, technologies that “cause or contribute to an unreasonable risk to public health, welfare, or safety in its operation or function.” CAA section 202(a)(2), (4). The statute does not contain or imply any other exclusions. Given the statute's primary purpose and function to reduce emissions of air pollutants which are contributing to endangering air pollution, the statute therefore compels EPA to consider technologies that reduce emissions of air pollutants most effectively, including vehicle technologies that result in no vehicle tailpipe emissions and completely “prevent” GHG emissions. CAA section 202(a)(1). At minimum, the statute allows EPA to consider such technologies. Pursuant to the statutory mandate and as explained throughout this preamble, EPA has considered the full range of vehicle technologies that meet these criteria and that we anticipate will be available in the MY 2027-32 timeframe, including numerous advanced vehicles with ICE ( e.g., hybrid), BEV, and FCEV technologies which include a range of electrification (including within ICE engine and vehicle technologies).
Another part of EPA's consideration of updated data is to evaluate changes in government and regulatory incentives, which can have real and significant impacts on the development and application of vehicle technologies. Accordingly, an important element of this rule's assessment is consideration of the large potential impact that recent congressional action, including the BIL and the IRA, will have on the cost and feasibility of HD motor vehicle CO 2 emission-reducing technologies, including facilitating production and adoption of ZEV technologies for HD motor vehicles. EPA's consideration of all these factors demonstrates that very large GHG emissions reductions are feasible for HD vehicles in the MY 2027-32 timeframe and that such reductions can be achieved using a combination of advanced ICE vehicle, BEV, and FCEV technologies at reasonable cost. As noted, manufacturers remain free to choose how to comply with the final standards (and, indeed, manufacturers have at times chosen different means from those projected as a potential compliance pathway in previous rulemakings to comply with the respective standards). EPA's analysis in preamble section II.F.4 further supports the feasibility of the final standards by showing that such GHG emission reductions can be achieved using different mixes of vehicles with ICE technologies, including without producing additional ZEVs to comply with this rule as described in the additional example potential compliance pathway.
The balance of this section summarizes the key factors found in the administrative record (including the entire preamble, RIA, and RTC) that form the basis for the Administrator's determination that the final standards are feasible and appropriate under our Clean Air Act section 202(a)(1)-(2) authority. Section II.G.2 discusses the statutory factors of technological feasibility, compliance costs, and lead time, and it explains that the final standards are predicated upon technologies that are feasible and of reasonable cost during the timeframe for this rule. Section II.G.3 evaluates emissions of GHGs, and it finds that the final standards would achieve significant GHG reductions that make an important contribution to climate change mitigation. Section II.G.4 evaluates other relevant factors that are important to evaluating the real-world feasibility of the standards as well as their impact, including impacts on purchasers, non-GHG emissions, energy, safety, and other factors. It concludes that the final standards will result in considerable benefits for purchasers and operators of HD vehicles, result in public health and welfare benefits from non-GHGs, create positive energy security benefits for the United States, and not create an unreasonable risk to safety. Section II.G.5 explains how the Administrator exercised the authority Congress provided to the agency in balancing the various factors we considered. It articulates the key factors that were dispositive to the Administrator's decision in selecting the final standards, including feasibility, compliance costs, lead time, GHG emissions reductions, and cost to purchasers; as well as other factors, such as non-GHG emissions, energy, and safety, that were not used to select the standards but that nonetheless provide further support for the Administrator's decision. On balance, this section II.G, together with the rest of the administrative record, demonstrates that the final standards are supported by voluminous evidence, the product of the agency's well-considered technical judgment and the Administrator's careful weighing of the relevant factors, and that these standards faithfully implement the important directive contained in section 202(a)(1)-(2) of the Clean Air Act to reduce emissions of air pollutants from motor vehicles which cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare.

2. Consideration of Technological Feasibility, Compliance Costs and Lead Time
The technological readiness of the heavy-duty industry to meet the final standards for model years 2027-2032 and beyond is best understood in the context of over a decade of heavy-duty vehicle emissions reduction programs in which the HD industry has introduced emissions reducing technologies in a wide lineup of ever more efficient and cost-competitive vehicle applications. Electrification technologies beyond the range included in vehicles with ICE have seen particularly rapid development and an expansion in the range of electrification over the last several years, such that early HD ZEV models are in use today for some applications and are expected to expand to many more applications, as discussed in RIA Chapters 1.5 and 2. The IRA provides powerful incentives in reducing the cost to manufacture and purchase ZEVs, as well as promoting the build-out and reducing the cost of charging infrastructure, that EPA projects will facilitate increased market penetration of ZEV technology in the time frame considered in this rulemaking. As a result, the number of ZEVs projected in the potential compliance pathway's technology packages we modeled to support the feasibility of the final standards is higher than in the technology packages on which the Phase 1 and 2 HD GHG standards are predicated.
As discussed in RIA Chapter 1.5.5 and section II.D, the modeled example potential compliance pathway to support the feasibility of the final standards includes only technologies that have already been developed and deployed. Additionally, manufacturers have announced plans to rapidly increase their investments in ZEV technologies over the next decade, and have already expended billions of dollars to do so. In addition, as noted, the IRA and the BIL provide many monetary incentives for the production and purchase of ZEVs in the heavy-duty market, as well as incentives for electric vehicle charging infrastructure. Furthermore, there have been multiple actions by states to accelerate the adoption of heavy-duty ZEV technologies, such as (1) a multi-state Memorandum of Understanding for the support of heavy-duty ZEV adoption ^{806} and (2) the State of California's ACT program, which has also been adopted by other states under CAA section 177 and includes a manufacturer requirement for zero-emission truck sales. ^{807} Together with the range of ICE technologies that have been already demonstrated over the past decade, BEVs and FCEVs with no tailpipe emissions (and 0 g CO 2 /ton-mile certification values) are capable of supporting rates of annual stringency increases that are much greater than were available in earlier GHG rulemakings. Hence, EPA supports the feasibility of the final standards through a modeled potential compliance pathway reflecting the utilization of a mix of HD vehicle technologies, including the technologies most successful at reducing GHG emissions. The modeled potential compliance pathway is not a command, but one demonstration of a means of meeting the standards, not foreclosing other means. EPA's analysis of additional vehicles with ICE technology packages and the technical feasibility, technical effectiveness, lead time, and cost of compliance of corresponding additional example potential compliance pathways in preamble section II.F.4 further supports the feasibility of the final standards by showing that such GHG emission reductions can be achieved using different mixes of vehicles with ICE technologies, including without producing additional ZEVs to comply with this rule.
^{806} NESCAUM MOU, available at https://www.nescaum.org/documents/mhdv-zev-mou-20220329.pdf .
^{807} EPA granted the ACT rule waiver requested by California under CAA section 209(b) on March 30, 2023. The ACT had been adopted by seven states under CAA section 177: Oregon, Washington, New York, New Jersey, and Massachusetts adopted ACT beginning in MY 2025 while Vermont adopted ACT beginning in MY 2026 and Colorado in MY2027.
In setting GHG standards for a future model year, EPA considers the extent deployment of advanced existing and future technologies, including the technologies most effective at reducing GHG emissions, would be available and warranted in light of the benefits to public health and welfare in GHG emission reductions, and potential constraints, such as cost of compliance, lead time, raw material availability and component supplies (including availability of minerals critical to battery manufacture and resiliency of associated supply chains), redesign cycles, charging and refueling infrastructure availability and cost, and purchasers' willingness to purchase (including payback). In the modeled potential compliance pathway supporting the feasibility of the final standards, EPA assessed these considerations. The extent of these potential constraints for the potential compliance pathway has diminished significantly in light of increased and further projected investment by manufacturers, increased and further projected acceptance by purchasers, and significant support from Congress to address such areas as upfront purchase price, charging infrastructure, critical mineral supplies, and domestic supply chain manufacturing. In response to the increased stringency of the final standards, in the potential compliance pathway we project that manufacturers will adopt advanced technologies, such as increased electrification, at an increasing pace across more of their vehicles. To evaluate the feasibility of BEVs and FCEVs in our modeled potential compliance pathway's technology packages that support the feasibility of the final standards, EPA developed, and for the final rule refined, a tool called HD TRUCS, to evaluate the design features needed to meet the energy and power demands of various HD vehicle types when using BEV, FCEV, and PHEV technologies. The overarching design and functionality of HD TRUCS is premised on assessing whether, for each of the 101 vehicle types analyzed, BEV, FCEV, and PHEV technologies could perform the same work as a comparable ICE vehicle counterpart. Within the HD TRUCS modeling that EPA conducted to support this final rule, we have imposed constraints to reflect the rate at which a manufacturer can deploy BEV technologies that include consideration of time necessary to ramp up battery production, including the need to increase the availability of critical raw minerals and develop more robust supply chains, and expand battery production facilities, as discussed in section II.D.2.c.ii. Furthermore, we have also imposed constraints to reflect the development and deployment of FCEVs, as discussed in section II.D.3.
Constraints on the technology adoption limits in HD TRUCS and correspondingly our modeled potential compliance pathway, as well as other aspects of our lead time assessment, are described in section II.F. Overall, given the measured approach we have taken to phase in the rate of deployment for new HD vehicles, our assessment shows that there is sufficient lead time for the industry to more broadly deploy existing technologies and successfully comply with the final standards should they pursue this or similar compliance pathways. Should manufacturers pursue other compliance pathways like the examples outlined in section II.F.4, there also is sufficient lead time given that the technologies have already been developed, most of the technologies have already been deployed and some are already in widespread use, and there are generally fewer concerns regarding availability of supporting infrastructure and critical minerals availability.
Our modeled potential compliance pathway's technology packages to support feasibility of the final standards project that, for the industry overall, nearly 50 percent of new vocational vehicle sales and 25 to 40 percent of new tractor sales in MY 2032 will be ZEVs. As noted in section II.F.1, this represents approximately 1 percent of the HD on-road fleet in 2027 growing to 7 percent of the on-road fleet in 2032. EPA believes that this is an achievable level based on our technical assessment for this final rule that includes consideration of the feasibility and lead time required for ZEVs and appropriate consideration of the cost of compliance for manufacturers. Our assessment of the appropriateness of the level of ZEVs in our analysis is also informed by consideration of comments as well as by substantial investments by manufacturers, as described in RIA Chapter 1. More detail about our technical assessment, and our assessment of the production feasibility of ZEVs is provided in section II.D and II.E of this preamble and Chapters 1 and 2 of the RIA.
At the same time, we again note that the final standards are performance-based and do not mandate any specific technology for any manufacturer or any vehicles. The modeled potential compliance pathway is one of many possible compliance pathways that manufacturers could choose to take to meet the performance-based standards. That is, we do not expect, and the standards do not require, that all manufacturers follow a similar pathway. Instead, individual manufacturers can choose to apply a mix of technologies that best suits the company's particular product mix and market position as well as its strategies for investment and technology development. For example, manufacturers that choose to increase their sales of hybrid vehicle technologies or apply more or increase sales of advanced technologies for non-hybrid ICE vehicles would require a smaller number of ZEVs (including no ZEVs relative to the reference case) than we have projected in our assessment to support the feasibility of the final standards, as described in section II.F. In addition, while EPA has identified numerous technologies, available today, for meeting the standards, manufacturers and their suppliers are highly innovative and may develop novel technologies for achieving the requisite emissions reductions. For example, when EPA implemented certain statutory standards following the 1970 Clean Air Act Amendments, manufacturers met those standards through three-way catalysts, a theretofore unproven technology. More recently, manufacturers responded to EPA's 2001 heavy-duty rule by applying selective catalytic reduction technologies, even though EPA had not anticipated such technology would be utilized for compliance. ^{808}
^{808} 66 FR 5002, 5036 (January 18, 2001).
In considering the feasibility of the final standards, EPA also considers the available compliance flexibilities on manufacturers' compliance options and the approach EPA takes in setting HD GHG vehicle standards that consider the averaging provisions within the program's established ABT provisions. The final performance-based standards with ABT provisions give manufacturers a degree of flexibility in the design of specific vehicles and their fleet offerings, while allowing industry overall to meet the standards and thus achieve the health and environmental benefits projected for this rulemaking at a lower cost. EPA has considered ABT in the feasibility assessments for many previous rulemakings since EPA first began incorporating ABT credits provisions in mobile source rulemakings in the 1980s. In particular, consistent with our approach in Phase 2, EPA considered averaging in the standard setting process of the Phase 3 GHG standards, and our assessment is premised upon the availability of averaging in supporting the feasibility of the final standards. While we also considered the existence of other aspects of the ABT program as supportive of the feasibility of the Phase 3 GHG standards, we did not rely on those other aspects in justifying the feasibility of the standards. In other words, the existing ABT program will continue to help provide additional flexibility in compliance for manufacturers to make necessary technological improvements and reduce the overall cost of the program, without compromising overall environmental objectives; however, the other aspects of the ABT program that are not the availability of averaging, including credit carryover, deficits, banking, and trading, were not considered in setting the numeric levels of the Phase 3 standards. Likewise, the final transitional ABT provisions in this rule for credits from multipliers and credit transfers across averaging sets, described in preamble section III.A, that allow flexibility in compliance options for manufacturers were not considered in setting the numeric levels of the Phase 3 standards and we did not rely on those flexibilities in justifying the feasibility of the standards.
Manufacturers widely utilize ABT, which provide a variety of flexible paths to plan compliance. We have discussed this dynamic in past rules, and we anticipate that this same dynamic will support compliance with this rulemaking in the lead time afforded. The GHG credit program was designed to recognize that manufacturers typically have a multi-year redesign cycle and not every vehicle will be redesigned every year to add emissions-reducing technology. Moreover, when technology is added, it will generally not achieve emissions reductions corresponding exactly to a single year-over-year change in stringency of the standards. Instead, in any given model year, some vehicles will be “credit generators,” over-performing compared to their respective CO 2 emission standards in that model year, while other vehicles will be “debit generators” and under-performing against their standards. As the final standards reach increasingly lower numerical levels, some vehicle designs that had generated credits against their CO 2 emission standard in earlier model years may instead generate debits in later model years. In MY 2032 when the final standards reach the lowest level, it is possible that only BEVs, FCEVs, PHEVs, and H2-ICE vehicles are generating positive credits, and other ICE vehicles generate varying levels of deficits. A greater application of ICE vehicle technologies ( e.g., hybrids) can enable compliance with fewer ZEVs than if less ICE technology was adopted, including a compliance strategy that does not include ZEVs, and therefore enable the tailoring of a compliance strategy to the manufacturer's specific market and product offerings. Together, a manufacturer's mix of credit-generating and debit-generating vehicles contribute to its sales-weighted average performance, compared to its standard, for that year.
Just as the averaging approach in the HD vehicle GHG program allows manufacturers to design a compliance strategy relying on the sale of both credit-generating vehicles and debit-generating vehicles in a single year, the credit banking and trading provisions of the program allow manufacturers to design a compliance strategy relying on overcompliance and undercompliance in different years, or even by different manufacturers. Credit banking allows credits to carry-over for up to five years and allows manufacturers up to three years to address any credit deficits. Credit trading is a compliance flexibility provision that allows one vehicle manufacturer to purchase credits from another.
The final performance-based standards with ABT provisions give manufacturers a degree of flexibility in the design of specific vehicles and their fleet offerings, while allowing industry overall to meet the standards and thus achieve the health and environmental benefits projected for this rulemaking. EPA has considered the averaging portion of the ABT program in the feasibility assessments for previous rulemakings and continues that practice here.
We also note the other provisions in ABT that provide manufacturers additional flexibility in complying with the standards. ^{809} By averaging across vehicles in the vehicle averaging sets and by allowing for credit banking across years, manufacturers have the flexibility to adopt emissions-reducing technologies in the manner that best suits their particular market and business circumstances. We note further that we have added additional flexibilities to the ABT program as part of the Phase 3 final rule, which are aimed at providing flexibilities in the transitional MYs of the final Phase 3 standards as detailed in section III. EPA's annual Heavy-Duty Vehicle and Engine Greenhouse Gas Emissions Compliance Report illustrates how different manufacturers have chosen to make use of the GHG program's various credit features. ^{810} It is clear that manufacturers are widely utilizing several of the credit programs available, and we expect that manufacturers will continue to take advantage of the compliance flexibilities and crediting programs to their fullest extent, thereby providing them with additional tools in finding the lowest cost compliance solutions.
^{809} As noted, these additional flexibilities (other than averaging under the existing ABT program) are not necessary to EPA's determination that the final standards are feasible and appropriate. These additional flexibilities, however, do provide further support for the reasonableness of the final standards as they allow manufacturers to comply with the final standards using a greater variety of compliance pathways, including beyond those examples modeled or identified by EPA, and at lower costs, including below the costs set forth in the administrative record.
^{810} U.S. EPA. “EPA Heavy-Duty Vehicle and Engine Greenhouse Gas Emissions Compliance Report.” Available online: https://www.epa.gov/compliance-and-fuel-economy-data/epa-heavy-duty-vehicle-and-engine-greenhouse-gas-emissions .
In addition to technological feasibility and lead time, EPA has considered the cost for heavy-duty manufacturers to comply with the final standards. See section II.F.2 of this preamble and Chapter 2 of the RIA for our analysis of compliance costs for manufacturers. For some regulatory groups, we estimate that the rule will result in incremental cost savings for some vehicle types and fleet average per-vehicle costs for others. We estimate that the MY 2032 fleet average per-vehicle cost savings to manufacturers are $2,900 for LHD vocational vehicles, $1,000 for MHD vocational vehicles and $700 for HHD vocational vehicles. The MY 2032 fleet average per-vehicle costs to tractor manufacturers will range between $3,200 for day cab tractors and $10,800 per sleeper cab tractor. EPA notes the projected costs per vehicle for this final rule are lower than the fleet average per-vehicle costs projected for the HD GHG Phase 2 rule that we considered to be reasonable. 81 FR 73621 (tractors) and 73718 (vocational vehicles). The Phase 2 MY 2027 tractor standard cost increments were projected to be between $12,750 and $17,125 (2022$) per vehicle and the vocational vehicle standards were projected to cost between $1,860 and $7,090 (2022$) per vehicle. ^{811} Furthermore, the estimated MY 2032 costs to tractor manufacturers represent less than about six percent of the average price of a new heavy-duty tractor today (conservatively estimated to be $140,000 for day cab tractors and $190,000 for sleeper cab tractors in 2023). ^{812} This is likewise within the margin that EPA considered reasonable in Phase 2. ^{813}
^{811} The Phase 2 tractor MY 2027 standard cost increments were projected to be between $10,200 and $13,700 per vehicle in 2013$ (81 FR 73621). The Phase 2 vocational vehicle MY 2027 standards were projected to cost between $1,486 and $5,670 per vehicle in 2013$ (81 FR 73718).
^{812} Memo to Docket. “Sample Heavy-Duty Truck Prices in 2023.” Docket EPA-HQ-OAR-2022-0945.
^{813} 81 FR 73621 and 73719.

3. Consideration of Emissions of GHGs
An essential factor that EPA considered in determining the appropriate level of the final standards is the projected reductions in GHG emissions and associated public health and welfare impacts. ^{814}
^{814} As further explained in section II.G.4, we note that our modeled potential compliance pathway supporting the feasibility of the final standards projects increased use of ZEV technologies in the HD vehicle fleet, which would reduce not just GHG emissions but also result in reductions of vehicle emissions of non-GHG pollutants that contribute to ambient concentrations of ozone, particulate matter (PM 2.5 ), NO 2 , CO, and air toxics. EPA did not select the final GHG emission standards based on non-GHG reductions of vehicle emissions; nonetheless, the projected GHG and non-GHG reductions of vehicle emissions of the final program reinforce our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations.
The final GHG standards are projected to achieve significant reductions in GHG emissions. The final standards will achieve nearly 1 billion metric tons in net CO 2 cumulative emission reductions from calendar years 2027 through 2055 (see section V of this preamble and Chapter 4 of the RIA). As discussed in section VI of this preamble, these GHG emission reductions will make an important contribution to efforts to limit climate change and its anticipated impacts. See Coal. For Resp. Reg., 684 F. 3d at 128 (removal of 960 million metric tons of CO 2 e over the life of the GHG vehicle emission standards rule was found by EPA to be “meaningful mitigation” of GHG emissions).
The final CO 2 emission standards will reduce adverse impacts associated with climate change discussed in section II.A and will yield significant benefits, including those we can monetize and those we are unable to fully monetize due to data and modeling limitations. The GHG emission reductions resulting from compliance with this final rule will significantly reduce the volume of GHG emissions from this sector. Section VI.D.2 of this preamble discusses impacts of GHG emissions on individuals living in socially and economically vulnerable communities. The program will result in significant social benefits including $10 billion in climate benefits (with the average SC-GHGs under a 2 percent near-term Ramsey discount rate). These estimates are a partial accounting of climate change impacts and will therefore tend to be underestimates of the marginal benefits of abatement. A more detailed description and breakdown of these benefits can be found in section VII of the preamble and Chapter 7 of the RIA. As discussed in section VII, we monetize benefits of the final CO 2 standards and evaluate other costs in part to better enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are benefits we are unable to fully quantify. EPA's consistent practice has been to set standards to achieve improved air quality consistent with CAA section 202 and not to rely on cost-benefit calculations, with their uncertainties and limitations, in identifying the appropriate standards. Nonetheless, our estimated benefits, which exceed the estimated costs of the final program, reinforce our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations. More specifically, for this rule our assessment that the rule has positive net monetized benefits, regardless of the magnitude of those positive net benefits, supports our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations. Thus, regardless of the method used in quantifying the monetized benefits of GHG reductions for purposes of this rulemaking, EPA would still find the emissions reductions, in light of the cost of compliance, available lead time and other relevant factors EPA considered, would justify adoption of these standards.

4. Consideration of Impacts on Purchasers, Non-GHG Emissions, Energy, Safety, and Other Factors
As noted in section II.G.2, the IRA provides powerful incentives in reducing the cost to manufacture and purchase ZEVs, as well as reducing the cost of charging infrastructure, that we project will facilitate increased market penetration of ZEV technology in the time frame considered in this rulemaking. Businesses that operate HD vehicles are under competitive pressure to reduce operating costs, which should encourage purchasers to identify and rapidly adopt vehicle technologies that provide a reasonable payback period. Outlays for labor and fuel generally constitute the two largest shares of HD vehicle operating costs, depending on the price of fuel, distance traveled, type of HD vehicle, and commodity transported (if any), so businesses that operate HDVs face strong incentives to reduce these costs. 815 816 However, as noted in RIA Chapter 6.2, there are a number of other considerations that may impact a purchaser's willingness to adopt new technologies. Regarding payback, within HD TRUCS we considered the impact on purchasers through our evaluation of payback periods. The payback period is the number of years that it will take for the annual operational savings of a ZEV to offset the incremental upfront purchase price of a BEV or FCEV (after accounting for the IRA section 13502 battery tax credit and IRA section 13403 vehicle tax credit) and upfront charging infrastructure costs for depot-charged BEVs (including IRA section 13404, “Alternative Fuel Refueling Property Credit”) when compared to purchasing a comparable ICE vehicle. The modeled compliance pathway's average per-vehicle costs to a purchaser by regulatory group for a MY 2032 heavy-duty vehicle, including associated EVSE and after considering the IRA battery-manufacturer and vehicle-purchaser tax credits, are projected to range between $1,500 and $34,000 for vocational vehicles and $4,300 and $22,000 for tractors. As explained in section II.F.2.ii, EPA concludes that the final standards will be beneficial for purchasers because the lower operating costs during the operational life of the vehicle will offset the increase in vehicle technology costs within the usual period of first ownership of the vehicle, which can be 7 years or longer. For example, purchasers of MY 2032 vocational vehicles on average by regulatory group will recoup the upfront costs through operating savings within the first two to four years of ownership. Purchasers of MY 2032 tractors on average will recoup the upfront costs through operating savings within the first two years for day cabs and first five years for sleeper cabs. Furthermore, the purchasers will benefit from annual operating cost savings for each year after the payback occurs. EPA finds that these projected average costs to purchasers are reasonable considering the operating savings which more than offsets these costs, as was also the case with the HD GHG Phase 2 rule. See 81 FR 73482, 73621(tractors), 73719 (vocational vehicles). Regarding practicability, as discussed in detail in this section II, within HD TRUCS we also considered the impact on purchasers through our evaluation of the practicability and suitability. For example, we applied an additional constraint within HD TRUCS that limited the maximum ZEV adoption rate to 70 percent for any given vehicle type in MY 2032, 37 percent in MY 2030, and 20 percent in MY 2027. This conservative limit was developed after consideration of the needs of the purchasers, as discussed in section II.F.1.
^{815} American Transportation Research Institute, An Analysis of the Operational Costs of Trucking, September 2013. Docket ID: EPA-HQ-OAR-2014-0827-0512.
^{816} Transport Canada, Operating Cost of Trucks, 2005. Docket ID: EPA-HQ-OAR-2014-0827-0070.
For the final rule, we also conducted a complementary assessment of total cost of ownership (TCO) of BEVs and FCEVs from a purchaser's perspective, as discussed in RIA Chapter 2.12. In addition to the cost elements considered in our payback analysis, our TCO analysis also includes the costs of financing the vehicles and the impact of residual value. As the results show in RIA Chapter 2.12, we find that the costs for owning and operating a ZEV will be lower than a comparable ICE vehicle for all MY 2032 BEVs and FCEVs in our technology packages to support the modeled compliance pathway when evaluated over a five-year time horizon. In fact, all vehicles show several thousands of dollars in net TCO savings at the five-year point. We find that this TCO analysis further supports our assessment.
Within our analysis, to support the final standards we also considered the lead time necessary for the development of infrastructure associated with operating the vehicles, including consideration of the projected lead time necessary under the potential compliance pathway to install depot charging and supporting electrification infrastructure and to develop hydrogen infrastructure that will be required for the projected use of these technologies. As further explained in RIA Chapter 1.6 and sections II.E.2 and II.F.3, and RTC section 6, our assessment indicates that depot charging can be installed in time for the purchase and use of the volume of MY 2027 and later BEVs we project could be used to comply with the final standards, and we considered such purchaser costs in our analysis as previously explained. We likewise find that there is adequate lead time for the infrastructure to support depot and public charging for the use of BEVs we project could be used to comply with the final standards, and included such costs in our manufacturer or purchaser cost analyses as appropriate. Section II.D.2.iii. With respect to hydrogen infrastructure, as further explained in RIA Chapter 1.8 and section II.F.3, we recognize that this may take longer to develop, and therefore we included a constraint for FCEVs such that we did not incorporate FCEVs into technology packages to support new standards for long-haul vehicles until MY 2030, when we expect refueling needs can be met for the volume of FCEVs we project could be used to comply with the final standards. We discuss issues relating to availability of critical minerals, resiliency of associated supply chains, and critical mineral security in section II.D.2.ii and in RTC section 17.2. As there discussed, we do not consider these to be insurmountable, including for the projections to comply with the final Phase 3 standards, and we thus do not consider them to be a constraining consideration.
We also assessed the impact of future HD BEVs on the grid, as discussed in section II.D.2.iii. Our analysis for the final rule shows that systems and processes exist to handle the impact on the power generation and transmission of this final rule, including when considered in combination with projections of other impacts on power generation and transmission based on our assessments at the time of this final rule. See RTC section 7.1; see also RIA Chapter 1.6. Therefore, we found that grid reliability is not expected to be adversely affected by the modest increase in electricity demand associated with HD BEV charging and thus was not considered to be a constraining consideration.
EPA considers our analysis of the impact of the final CO 2 emission standards on vehicle and upstream emissions for non-GHG pollutants as supportive of the final standards. The final standards will decrease vehicle emissions of non-GHG pollutants, and we expect those decreased emissions will contribute to reductions in ambient concentrations of ozone, particulate matter (PM 2.5 ), NO 2 , CO, and air toxics. Similarly, we also project reductions in emissions of non-GHG pollutants from refineries ( i.e., NO X , PM 2.5 , VOC, and SO 2 ). We project that non-GHG emissions from EGUs will increase as a result of the increased demand for electricity associated with the rule, but the magnitude of emissions increases diminishes over time due to EGU regulations and changes in the future power generation mix, including impacts of the IRA. By 2055 there are net decreases in emissions from all pollutants except PM 2.5 ; when the net changes in emissions of PM 2.5 and PM 2.5 precursors ( e.g., VOC, NO X , SO 2 ) are considered together, there are positive PM 2.5 health benefits beginning in 2040 and, overall, a positive present value and annualized value of PM 2.5 health benefits when using a 2 percent and 3 percent discount rate. (See sections V and VII of this preamble and Chapters 4 and 7 of the RIA for more detail). EPA believes the non-GHG emissions reductions of this rule provide important health benefits to the 72 million people living near truck routes and even more broadly over the longer term. We note that the agency has broad authority to regulate emissions from the power sector ( e.g., the mercury and air toxics standards, and new source performance standards), as do the States and EPA through cooperative federalism programs ( e.g., in response to PM NAAQS implementation requirements, interstate transport, emission guidelines, and regional haze), ^{817} and that EPA reasonably may address air pollution incrementally across multiple rulemakings, particularly across multiple industry sectors. For example, EPA has separately proposed new source performance standards and emission guidelines for greenhouse gas emissions from fossil fuel-fired power plants, which would also reduce emissions of criteria air pollutants such as PM 2.5 and SO 2 (88 FR 33240, May 23, 2023). ^{818}
^{817} See also CAA 116.
^{818} https://www.epa.gov/stationary-sources-air-pollution/nsps-ghg-emissions-new-modified-and-reconstructed-electric-utility .
As also explained in section II.G.3, and as discussed in section VII, we monetize benefits of the final standards and evaluate other costs in part to better enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are benefits we are unable to fully quantify. As noted, EPA's consistent practice has been to set standards to achieve improved air quality consistent with CAA section 202(a), and not to rely on cost-benefit calculations, with their uncertainties and limitations, in identifying the appropriate standards. Such analysis, however, can be corroborative of a standard's reasonableness, as is the case here and as is explained further in this section.
EPA also evaluated the impacts of the final HD GHG standards on energy, in terms of oil conservation and energy security through reductions in fuel consumption. This final rule is projected to reduce U.S. oil imports by 3 billion barrels through 2055 (see RIA Chapter 6.5). EPA considered the impacts of this projected reduction in fuel consumption on energy security, specifically the avoided costs of macroeconomic disruption. Promoting energy independence and security through reducing demand for refined petroleum use by motor vehicles has long been a goal of both Congress and the Executive Branch because of both the economic and national security benefits of reduced dependence on imported oil, and was an important reason for amendments to the Clean Air Act in 1990, 2005, and 2007. ^{819} A reduction of U.S. net petroleum imports reduces both financial and strategic risks caused by potential sudden disruptions in the supply of petroleum to the U.S., thus increasing U.S. energy security. EPA finds this rule to have significant benefits from an energy security perspective. We estimate the benefits due to reductions in energy security externalities caused by U.S. petroleum consumption and imports will be approximately $0.45 billion under the final program. EPA considers this final rule to be beneficial from an energy security perspective and thus this factor was considered to be a supportive and not constraining consideration.
^{819} See e.g., 136 Cong. Rec. 11989 (May 23, 1990) (Rep. Waxman stating that clean fuel vehicles program is “tremendously significant as well for our national security. We are overly dependent on oil as a monopoly; we need to run our cars on alternative fuels.”); Remarks by President George W. Bush upon signing Energy Policy Act of 2005, 2005 U.S.C.C.A.N. S19, 2005 WL 3693179 (“It's an economic bill, but as [Sen. Pete Domenici] mentioned, it's also a national security bill.-. . . Energy conservation is more than a private virtue; it's a public virtue”); Energy Independence and Security Act, Public Law 110-140, section 806 (finding “the production of transportation fuels from renewable energy would help the United States meet rapidly growing domestic and global energy demands, reduce the dependence of the United States on energy imported from volatile regions of the world that are politically unstable, stabilize the cost and availability of energy, and safeguard the economy and security of the United States”); Statement by George W. Bush upon signing, 2007 U.S.C.C.A.N. S25, 2007 WL 4984165 (“One of the most serious long-term challenges facing our country is dependence on oil—especially oil from foreign lands. It's a serious challenge. . . . Because this dependence harms us economically through high and volatile prices at the gas pump; dependence creates pollution and contributes to greenhouse gas admissions [sic]. It threatens our national security by making us vulnerable to hostile regimes in unstable regions of the world. It makes us vulnerable to terrorists who might attack oil infrastructure.”).
EPA estimates that the annualized value of monetized net benefits to society at a 2 percent discount rate will be approximately $13 billion through the year 2055, roughly 12 times the projected cost in vehicle technology and associated electric vehicle supply equipment (EVSE) combined under the potential compliance pathway. Regarding social costs, EPA estimates that the projected cost of vehicle technology (not including the vehicle or battery tax credits) and EVSE under the potential compliance pathway will be approximately $1.1 billion, and that the HD industry will save approximately $3.5 billion in operating costs ( e.g., savings that come from less liquid fuel used, lower maintenance and repair costs for ZEV technologies as compared to ICE technologies, etc.). In other words, the social costs of the rule result in net savings to society due largely to the operating savings expected from electrification technologies. The program will result in significant social benefits including $10 billion in climate benefits (with the average SC-GHGs under a 2 percent near-term Ramsey discount rate) and $0.3 billion of the estimated total benefits through 2055 are attributable to reduced emissions of non-GHG pollutants. Finally, the benefits due to reductions in energy security externalities caused by U.S. petroleum consumption and imports will be approximately $0.45 billion under the final program. A more detailed description and breakdown of these benefits can be found in section VIII of the preamble and Chapter 7 of the RIA.
As explained in preamble sections I and II, when section 202(a) requires EPA to consider costs, it is referring to costs to manufacturers, not total social costs. The Administrator identified the standards that he finds appropriate taking into account emissions reductions, costs to manufacturers, feasibility and other required and discretionary factors. As discussed in section VII, we monetize benefits of the final CO 2 emission standards and evaluate other costs in part to better enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are benefits we are unable to fully quantify. EPA's consistent practice has been to set standards to achieve improved air quality consistent with CAA section 202 and not to rely on cost-benefit calculations, with their uncertainties and limitations, in identifying the appropriate standards. Nonetheless, our estimated benefits, which exceed the estimated costs of the final program, reinforce our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations. More specifically, for this rule our assessment that the rule has positive net monetized benefits supports our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations. Positive monetized net benefits do not depend on which of the final rule's discounted stream of PM 2.5 health benefits is used, or as explained in this preamble section II.G whether the final rule's SC-GHG estimates or the IWG SC-GHG estimates are used (see the Appendix to Chapter 8 of the RIA for the latter in the final rule); EPA finds the emissions reductions, in light of the cost of compliance, available lead time and other factors, justify adoption of these standards. Section 202(a)(4)(A) of the CAA specifically prohibits the use of an emission control device, system or element of design that will cause or contribute to an unreasonable risk to public health, welfare, or safety. EPA has a long history of considering the safety implications of its emission standards, from 1980 regulations establishing criteria pollutant standards ^{820} up to and including the HD Phase 1 and Phase 2 rules. We highlight the numerous industry standards and safety protocols that exist today for heavy-duty BEVs and FCEVs that provide guidance on the safe design of these vehicles in section II.D and RIA Chapter 1 and thus this factor was considered to be a supportive and not constraining consideration.
^{820} See, e.g., 45 FR 14503 (March 5, 1980) (“EPA would not require a particulate control technology that was known to involve serious safety problems.”).

5. Selection of Final Standards Under CAA 202(a)(1)-(2)
Under section 202(a)(1)-(2), EPA has a statutory obligation to set standards to reduce emissions of air pollutants from classes of motor vehicles that the Administrator has found contribute to air pollution that may be expected to endanger public health and welfare. In setting such standards, the Administrator must provide adequate lead time for the development and application of technology to meet the standards, taking into consideration the cost of compliance. EPA's final standards properly implement this statutory provision, as discussed in this section II.G. In setting standards for a future model year, EPA considers the extent deployment of advanced technologies, including those with the largest potential emission reductions, would be available and warranted in light of the benefits to public health and welfare in GHG emission reductions, and potential constraints, such as cost of compliance, lead time, raw material availability and component supplies (including availability of minerals critical to lithium-ion battery manufacture and resiliency of associated supply chains), redesign cycles, charging and refueling infrastructure availability and cost, and purchasers' willingness to purchase (including payback). The extent of these potential constraints for the potential compliance pathway demonstrating the feasibility of the final standards has diminished significantly in light of increased and further projected investment by manufacturers, increased and further projected acceptance by purchasers, and significant support from Congress to address such areas as upfront purchase price, charging infrastructure, critical mineral supplies, and domestic supply chain manufacturing. However, as discussed through this preamble section II and RIA Chapter 2, EPA has also given consideration to expressed concerns and uncertainties regarding several aspects of our analysis and undertaken a conservative approach in several of those specific instances, leading to a moderate, balanced approach overall. Examples include analyzing availability and timing of distribution grid buildout without considering measures by which users can mitigate the need for electrification support (see RTC section 7 (Distribution)), selecting 2,000 cycles as our maximum number of cycles for 10 years of battery age (see RIA Chapter 2.4.1.1.3), and use of maintenance and repair scaling factors commencing in MY 2027 and MY 2030 (see preamble section II.E.5). The final standards will achieve significant and important reductions in GHG emissions that endanger public health and welfare. Furthermore, as discussed throughout this preamble, the emission reduction technologies needed to meet the final standards have already been developed and are feasible and available for manufacturers to utilize in their fleets at reasonable cost in the timeframe of these final standards, even after considering key elements including battery manufacturing capacity, critical minerals availability, and timely availability of supporting infrastructure for charging and refueling.
As discussed throughout this preamble, the emission reduction technologies needed to meet the final standards are feasible and available for manufacturers to utilize in HD vehicles in the timeframe of these final standards. The final emission standards are based on one potential compliance pathway (represented in multiple projected technology packages for the various HD vehicle regulatory subcategories per MY) that includes adoption rates for both certain vehicles with ICE technologies and zero-emission vehicle technologies that EPA regards as feasible and appropriate under CAA section 202(a) for the reasons given in this section II.G, and as further discussed throughout section II and RIA Chapter 2. For the reasons described in that analysis, EPA believes these technologies can be developed and applied in HD vehicles and adopted at the projected rates for these final standards within the lead time provided, as discussed in section II.F and in RIA Chapter 2. EPA's analysis in preamble section II.F.4 further supports the feasibility of the final standards by showing that such GHG emission reductions can be achieved using different mixes of vehicles with ICE technologies, including without producing additional ZEVs to comply with this rule as described in the additional example potential compliance pathway.
EPA also gave appropriate consideration of cost of compliance in the selection of the final standards as described in this section II.G, and as further discussed in section II.F and RIA Chapter 2. The final MY 2027 through MY 2031 emission standards are less stringent than those proposed for those MYs and the final MY 2032 standards; correspondingly, the modeled potential compliance pathway supporting the feasibility of these final standards includes less aggressive application rates and, therefore, is projected to have lower technology package costs than the proposed MY 2027 through MY 2031 emissions standards and the final MY 2032 standards. Additionally, as described in this section II.G and as further discussed in section II.F and RIA Chapter 2, we considered impacts on vehicle purchasers and willingness to purchase (including payback and costs to vehicle purchasers) in applying constraints in our analysis and selecting the final standards. ^{821} For example, in MY 2032, we estimated that the incremental cost to purchase a ZEV will be recovered in the form of operational savings during the first one to four years of ownership, on average by regulatory group, for the vocational vehicles; approximately two years, on average by regulatory group, for short-haul tractors; and four years, on average by regulatory group, for long-haul tractors, as shown in the payback analysis included in section II.F.1. We find the technologies will pay for themselves on average by regulatory group within the ownership timeframe for both tractors and vocational vehicles, as described in section II.F.1.
^{821} EPA has considered purchaser response in appropriately exercising our authority under the statute, and based on the record before us, the agency views purchaser response as a material aspect of the real-world feasibility of the final standards. EPA has a vested interest in real-world feasibility of the final standards as, for example, if the vehicles with advanced technologies are not purchased, the projected emission benefits of the final standards may not occur. Although certain commenters chastised EPA for considering purchaser response, noting that it is not explicitly enumerated in the statute, EPA believes it is properly considered in this rulemaking as an aspect of both cost (including costs to manufacturers of having stranded assets) and feasibility.
Moreover, averaging and the additional flexibilities beyond averaging already available under EPA's existing regulations, including banking and trading provisions in the ABT program—which, for example, in effect enable manufacturers to spread the compliance requirement for any particular model year across multiple model years—further support EPA's conclusion that the final standards provide sufficient time for the development and application of technology, giving appropriate consideration to cost.
Congress directed the Administrator to weigh various factors under CAA section 202, and, as with the HD GHG Phase 1 and Phase 2 rules, the Administrator notes that the primary purpose of adopting standards under that provision of the Clean Air Act is to address air pollution that may reasonably be anticipated to endanger public health and welfare and that reducing air pollution has traditionally been the focus of such standards. Taking into consideration the importance of reducing GHG emissions and the primary purpose of CAA section 202 to reduce the threat posed to human health and the environment by air pollution which endangers, the Administrator finds it is appropriate to finalize standards that, when implemented, will result in meaningful reductions of HD vehicle GHG emissions both near term and over the longer term, and to select such standards taking into consideration the enumerated statutory factors of technological feasibility and cost of compliance within the available lead time, as well as the relevant discretionary factor of impacts on purchasers and willingness to purchase. In identifying the final standards, EPA's goal was to balance the emissions reductions given our assessment of technological feasibility and accounting for cost of compliance, lead time, and purchaser costs and willingness to purchase, and the constraining uncertainties related to each of these elements.
There have been very significant developments in the utilization of ZEV technologies since EPA promulgated the HD GHG Phase 2 rule. One of the most significant developments for U.S. heavy-duty manufacturers and purchasers is the adoption of the IRA, which takes a comprehensive approach to addressing many of the potential barriers to wider adoption of heavy-duty ZEVs in the United States. As noted in RIA Chapter 2, the IRA provides tens of billions of dollars in tax credits and direct Federal funding to reduce the upfront cost of purchasing ZEVs, to increase the number of charging stations across the country, to reduce the cost of manufacturing batteries, and to promote domestic source of critical minerals and other important elements of the ZEV supply chain. By addressing all of these potential obstacles to wider ZEV adoption in a coordinated, well-financed, strategy, Congress significantly advanced the potential for ZEV adoption in the near term, thus supporting standards supported by a potential compliance pathway which includes ZEV technologies.
In developing the modeled potential compliance pathway, EPA considered a variety of constraints which have to date limited utilization of ZEV technologies and/or could limit it in the future, including the following: cost to manufacturers and purchasers; availability of critical minerals; adequacy of battery production and necessary supply chain elements; adequate electricity supply and distribution infrastructure in support of depot and public charging; and availability of hydrogen and supporting infrastructure for its deployment in FCEVs. While EPA acknowledges that there are some factual uncertainties regarding future projections on these constraints, as detailed through the preamble and the accompanying RIA, our analysis recognizes these uncertainties and identifies the considerations the agency found persuasive. Our analysis was informed by extensive consultation with analysts from other agencies, including the Federal Energy Regulatory Commission, DOE, DOT, and the Joint Office of Energy and Transportation. We have extensively reviewed published literature and other data. As discussed in this preamble and the accompanying RIA, we have incorporated limitations into our modeling to address these potential constraints, as we have assessed are appropriate.
As discussed in section II.G.4, there are additional considerations that support, but were not used to select, the final standards. These include the non-GHG emission and energy impacts, energy security, safety, and net benefits. EPA estimates that the annualized value of monetized net benefits to society at a 2 percent discount rate will be approximately $13 billion through the year 2055, more than 11 times the cost in vehicle technology and associated electric vehicle supply equipment (EVSE) combined (see preamble section VII and Chapter 8 of the RIA). We recognize these estimates do not reflect unquantified benefits, which would be greater still, and the Administrator has not relied on these estimates in identifying the appropriate standards under CAA section 202(a)(1)-(2). Nonetheless, our conclusion that the estimated benefits exceed the estimated costs of the final program reinforces our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations.
As we explained in the HD Phase 3 NPRM, we also considered, but did not analyze, and requested comment on a more stringent alternative with emission standards similar to those required by the CA ACT program. We received a number of comments supporting more stringent standards, as discussed in section II.B. We are not adopting such standards. First, at this time and for similar reasons to those explained in this section II regarding changes made in the final standards from the proposed standards' level of stringency, we consider the final standards' stringency as the appropriate balancing of the factors. Second, the Phase 3 standards demonstrably achieve reductions of GHG emissions beyond those attributable to a “no action” scenario (including the ACT standards), and include significant reductions in non-ACT states. See preamble section V and RTC section 2.4 and sources there cited. We thus do not accept the comment that standards more stringent than those proposed are necessary to achieve reductions beyond those which would occur in the absence of Federal standards. Third, our modeled potential compliance pathway supporting feasibility of the final standards appropriately reflects that ICE vehicles will continue to be needed for certain applications, and for certain usage and weather conditions. The caps on ZEV adoption in our HD TRUCS analysis for the modeled potential compliance pathway properly reflect these considerations. We do not agree with commenters advocating for more stringent standards reflecting further improvements to ICE vehicles and engines beyond the Phase 2 MY 2027 improvements in our modeled compliance pathway, as our assessment is that manufacturers do not have the resources to use all the different technology improvement strategies together within the lead time provided by the Phase 3 program ( e.g., the modeled potential compliance pathway technologies plus technologies in an additional example potential compliance pathway discussed in preamble section II.F.4). See RTC section 2.4.
Fourth, consideration of availability and timing of distribution grid buildout infrastructure, availability of critical minerals and associated issues, and willingness to purchase all warrant a balanced and measured approach in determining the stringency of these standards. Thus, the standards are carefully phased in so that the standards for the initial years of the Phase 3 standards are less stringent, Phase 3 standards for certain vocational vehicles and tractors commence in post-2027 model years, and the standards provide longer lead time where public charging is part of the modeled potential compliance pathway. We believe that these decisions reflect reasoned consideration of feasibility and lead time, appropriately giving these considerations more weight than these commenters would. See RTC section 2.4 for additional responses. In addition to our final standards, we also considered an alternative less stringent than our final standards, as specified and discussed in sections II.H and IX. We considered an alternative with a slower phase-in and with less stringent CO 2 emission standards; however, we did not select this level for the final standards because our assessment in this final rule is that feasible and appropriate standards are available that provide for greater GHG emission reductions than would be provided by this slower phase-in alternative.
We acknowledge that both those stakeholders pressing for more and less rapid increases in stringency have submitted considerable technical studies in support of their positions, including analyses purportedly demonstrating that a more or less rapid adoption of emissions reduction technologies, including zero-emissions technologies, is feasible. These studies account for the vast range of economic, technology, regulatory, and other factors described throughout this preamble; draw different assumptions about key variables; and reach very different conclusions. We have carefully reviewed all these studies and further discuss them in the RIA and the RTC. The agency's final standards are premised upon our own extensive technical assessment, which in turn is based on a wide review of the literature and test data, extensive expertise with the industry and with implementation of past standards, peer review, and our modeling analyses. The data and resulting modeling demonstrate a balanced and measured rate of adoption of emission reduction technologies, at rates bounded between the higher and lower rates in studies provided by commenters.
On balance, we think the various comments and studies pressing for faster or slower increases in stringency than the final rule each have their strengths and weaknesses, and we recognize the inherent uncertainties associated with predicting the future of the highly dynamic vehicle and related industries up to eight years from today through MY 2032. This uncertainty pervades both scenarios with lesser and greater increases in stringency than the final standards. For example, slower increases in stringency would be more certainly feasible and less costly for manufacturers, but they would also risk giving up emissions reductions and consequent benefits to public health and welfare that are actually achievable. By contrast, faster increases in stringency would aim to achieve greater emissions reductions and consequent benefits for public health and welfare, but they would also run the risk of incurring greater costs of compliance and potentially being infeasible in light of the lead time provided. The final standards reflect our technical expertise in discerning a reasoned path among the varying sources of data, analyses, and other evidence we have considered, as well as the Administrator's policy judgment as to the appropriate level of emissions reductions that can be achieved at a reasonable cost in the available lead time.
While the final standards are more stringent than the Phase 2 standards, EPA applied numerous conservative approaches throughout our analysis (as identified throughout this section II and in RIA Chapter 2) and the final standards additionally are less stringent than those proposed for the first several years of implementation leading to MY 2032. As explained throughout this document, EPA has assessed the appropriateness and feasibility of these standards taking into consideration the potential benefits to public health and welfare, existing market trends and financial incentives for ZEV adoption, and constraints which could shape technology adoption in the future, including: cost to manufacturers and purchasers; lead time for manufacturers to develop new products to meet a diverse set of HD applications; availability of raw materials, batteries, and other necessary supply chain elements; and adequate charging and refueling infrastructure, electricity supply and distribution. As a result of re-evaluating data and analyses in light of public comments, we have revised both our cost estimates and our assessment of the feasibility of more stringent standards, particularly for the early years of the program. For the years the agency is setting standards, we find it is important for the standards to provide a degree of certainty and send appropriate market signals to facilitate the anticipated investments, not only in technology adoption but also in complementary areas such as supply chains and charging and refueling infrastructure. The Administrator concludes that this balanced and measured approach is within the authority Congress provided under and is consistent with the text and purpose of CAA section 202(a)(1)-(2).
In summary, after consideration of the very significant reductions in GHG emissions, given the technical feasibility of the final standards and the moderate costs per vehicle in the available lead time, and taking into account a number of other factors such as the savings to purchasers in operating costs over the lifetime of the vehicle, safety, the benefits for energy security, and the significantly greater quantified benefits compared to quantified costs, EPA believes that the final standards are appropriate under EPA's section 202(a)(1)-(2) authority.

H. Alternatives Considered
Our analysis for the final rule of relevant existing information, public comments, and new information that became available between the proposal and final rule supports a slower implementation than included in the proposed standards; our assessment in this final rule, as described in this section II, is that the final standards provide the appropriate speed of implementation, including adequate lead time. In developing this final rule, we also developed and considered an alternative set of less stringent standards and a more gradual phase-in than the final standards in section II.F. The results of the analysis of this alternative are included in section IX of the preamble. In addition, we considered a set of more stringent standards reflecting levels of stringency that would be achieved from extrapolating the California ACT rule to the national level.
As discussed in section II.F, we considered while developing the final standards that manufacturers choosing a compliance strategy that utilizes ZEV technologies will need time to ramp up ZEV production from the numbers of ZEVs produced today to the higher adoption rates we project may be used to comply with the final standards that begin between three and eight model years from now. Manufacturers will need to conduct research and develop electrified configurations for a diverse set of applications. They will also need time to conduct durability assessments because downtime is very critical in the heavy-duty market. Furthermore, manufacturers will require time to make new capital investments for the manufacturing of heavy-duty battery cells and packs, motors, and other EV components, along with changing over the vehicle assembly lines to incorporate an electrified powertrain. In addition, the purchasers of HD BEVs will need time to design and install charging infrastructure at their facilities or determine their hydrogen refueling logistics for FCEVs. Therefore, we developed and considered an alternative that reflects a more gradual phase-in of utilization of such technologies to provide even longer lead time to address such considerations. The alternative CO 2 emission standards shown in Table II-53 and Table II-54. We are not adopting this alternative set of standards in this final rule because, as already described, our assessment is that feasible and appropriate standards are available that provide for greater emission reductions than provided under this alternative, do so at reasonable cost, and provide sufficient lead time.
In the final rule analysis, we also considered standards consistent with levels of stringency that would be achieved from the California ACT rule extrapolated to the national level. The more stringent alternative standards considered are shown in Table II-55 and Table II-56. We are not adopting standards consistent with this more stringent alternative because we consider the final standards' stringency as the appropriate balancing of the factors, as discussed in section II.G.

I. Small Businesses
As proposed, qualifying small manufacturers will remain subject to the previously promulgated Phase 2 MY 2027 and later GHG vehicle emission standards, and are not subject to the Phase 3 standards unless they voluntarily decide to opt into the Phase 3 program, as discussed in this section (see 40 CFR 1037.105(b) and (h) and 1037.106(b)). ^{822} We note that this approach avoids any potential undue burden on these small entities. See 88 FR 26008. EPA may consider new GHG emission standards to apply for vehicles produced by small business vehicle manufacturers as part of a future regulatory action.
^{822} See section III.C of this preamble for a description of the final revisions to the provisions for small manufacturers in 40 CFR 1037.105(b) and (h), 1037.106(b), and 1037.150(c) and (w).
As described in RIA Chapter 9, we have identified a small number of heavy-duty vehicle manufacturers that would qualify as small manufacturers under the heavy-duty vehicle manufacturer category. Most of these small businesses currently only produce ZEVs, while one company currently produces ICE vehicles. ^{823} We thus estimate that there would only be a small emissions benefit from applying the final standards to the relatively low production volume of ICE vehicles produced by small businesses and maintaining the previously promulgated HD vehicle CO 2 standards for these companies at this time would have a negligible impact on the overall GHG emission reductions that the program would otherwise achieve. We received no comments on our proposal to retain the MY 2027 and later standards for qualifying manufacturers or revise the definition of small manufacturer. The Phase 2 standards will continue to apply and any applicable small manufacturer flexibilities established under the Phase 2 program will continue to be available to small manufacturers for MY 2027 and later.
^{823} See section XI.C of this preamble for our regulatory flexibility assessment of the potential burden on small businesses.
Since the Phase 2 standards are also based on a fleet average, small manufacturers can continue to average within their averaging sets to achieve the applicable standards. However, we proposed to restrict banking, trading, and the use of advanced technology credit multipliers for credits generated against the Phase 2 standards for qualifying manufacturers that utilize this small business interim provision. Under this final rule, and as explained in the proposal, qualifying small manufacturers may voluntarily certify their vehicles to the Phase 3 standards without ABT participation restrictions if they certify all their vehicle families within a given averaging set to the Phase 3 standards for the given MY. In other words, small manufacturers that opt into the Phase 3 program for a given MY for all their vehicle families within a given averaging set would be eligible for the full ABT program, including the expanded flexibilities finalized in this rule as described in section III.A.
While the new Phase 3 standards do not apply for vehicles produced by qualifying small manufacturers, we proposed and are finalizing that small manufacturers that are certifying BEVs or FCEVs would be subject to the battery durability monitor and warranty provisions described in section III.B.

III. Compliance Provisions, Flexibilities, and Test Procedures
In this rule, we are retaining the general compliance structure of existing 40 CFR part 1037 with some revisions described in this section. Vehicle manufacturers will continue to demonstrate that they meet emission standards using emission modeling and EPA's Greenhouse gas Emissions Model (GEM) and will use fuel-mapping or powertrain test information from procedures established and revised in previous rulemakings. ^{824}
^{824} See the HD GHG Phase 2 rule (81 FR 73478, October 25, 2016), the Heavy-Duty Engine and Vehicle Technical Amendment rule (86 FR 34308, June 29, 2021), and the HD2027 rule (88 FR 4296, January 24, 2023). As also explained in the proposal for this rulemaking, in this rulemaking EPA did not reopen any portion of our heavy-duty compliance provisions, flexibilities, and testing procedures, including those in 40 CFR parts 1037, 1036, and 1065, other than those specifically identified in the proposal as the subject of our proposal or a solicitation for comment. For example, while EPA is finalizing revisions to discrete elements of the HD ABT program, EPA did not reopen the general availability of ABT.
In section III.A, we describe the general ABT program, discrete revisions to it which we are finalizing, and how we expect manufacturers to utilize ABT to meet the final standards. In section III.A.1, we describe a revision to the definition of “U.S.-directed production volume” that clarifies consideration in this rulemaking of nationwide production volumes, including those that may be certified to different state emission standards. ^{825} This revised definition addresses the interaction that would otherwise result between the previous definition of U.S.-directed production volume and the California Advanced Clean Truck (ACT) regulation for HD vehicles. ^{826} Section III.A.2 includes updates to advanced technology credit provisions after considering comments received on the HD2027 NPRM (87 FR 17592, March 28, 2022) and the proposal for this rulemaking (88 FR 25926, April 27, 2023). In section III.A.3, we describe other revised flexibilities available to heavy-duty vehicle manufacturers, including an interim transitional flexibility regarding how credits could be used across averaging sets. In section III.B, we describe new durability monitoring requirements for BEVs and PHEVs, clarify existing warranty requirements for PHEVs, and describe new warranty requirements for BEVs and FCEVs. Finally, section III.C includes additional clarifying and editorial amendments we are finalizing related to the HD highway engine provisions of 40 CFR part 1036, the HD vehicle provisions of 40 CFR part 1037, the test procedures for HD engines in 40 CFR part 1065, and provisions that span multiple sectors.
^{825} The definition update includes conforming amendments throughout the HD engine and vehicle regulations of 40 CFR parts 1036 and 1037, respectively.
^{826} EPA granted the ACT rule waiver requested by California under CAA section 209(b) on March 30, 2023.

A. Revisions to the ABT Program
The existing HD GHG Phase 2 program provides flexibilities, primarily through the HD GHG ABT program, that facilitate compliance with the emission standards. In the HD space, our use of averaging dates back to our 1985 emissions standards for highway HD engines. 50 FR 10606 (March 15, 1985) (“Emissions averaging, of both particulate and oxides of nitrogen emissions from heavy-duty engines, is allowed beginning with the 1991 model year. Averaging of NO, emissions from light-duty trucks is allowed beginning in 1988.”). Similarly, we have included banking and trading for highway HD engines in our rules dating back to 1990. 55 FR 30584 (July 26, 1990) (“This final rule announces new programs for banking and trading of particulate matter and oxides of nitrogen emission credits for gasoline-, diesel- and methanol-powered heavy-duty engines.”). See section I of this preamble for a summary of EPA's authority and implementation of ABT in previous rulemakings, and a more detailed description in response to comments on our authority in RTC section 10.2.1.
EPA considered averaging and the existence of the general ABT program as part of the Phase 2 standard setting process (see, e.g., 81 FR 73495 (October 25, 2016)). As explained in section II, we likewise considered averaging in the standard setting process of the Phase 3 GHG standards, and our assessment is premised upon the availability of averaging in supporting the feasibility of the final standards. While we also considered the existence of other aspects of the ABT program as supportive of the feasibility of the Phase 3 GHG standards, we did not rely on those other aspects in justifying the feasibility of the standards. In other words, the existing ABT program will continue to help provide additional flexibility in compliance for manufacturers to make necessary technological improvements and reduce the overall cost of the program, without compromising overall environmental objectives; however, the other aspects of the ABT program that are not the availability of averaging, including credit carryover, deficits, banking, and trading, were not considered in setting the numeric levels of the Phase 3 standards. Accordingly, these other aspects of ABT are severable from the Phase 3 standards.
The current HD GHG Phase 2 program also includes specific credit provisions for “advanced technologies” as identified in the Phase 2 rule ( i.e., PHEVs, BEVs, and FCEVs) and separate provisions for other innovative technologies that are not reflected in GEM. As described in section II of this preamble, the revisions to the existing MY 2027 Phase 2 GHG emission standards and new standards for MYs 2028 through 2032 are supported by a modeled potential compliance pathway premised on utilization of a variety of technologies, including technologies that are considered advanced technologies in the existing HD GHG Phase 2 ABT program. ^{827}
^{827} As stated in the proposal, we are retaining and did not reopen the existing off-cycle provisions of 40 CFR 1037.610 that allow manufacturers to request approval for other “innovative” technologies. 88 FR 26013.
We are generally retaining and did not reopen the existing HD GHG Phase 2 ABT program that allows for emission credits to be averaged, banked, or traded within each of the averaging sets specified in existing 40 CFR 1037.740(a). We provide the following description of the existing ABT program for background and informational purposes only. ^{828} In brief, under the existing program, manufacturers may choose to demonstrate compliance with the applicable emission standard by using the regulatory provisions for averaging, banking, and trading. ^{829} They do so by dividing their vehicles into “families” or “subfamilies”. For each family or subfamily, the manufacturer must designate a “Family Emission Limit”, which is an “emission level . . . to serve in place of the otherwise applicable emission standard” for each family or subfamily. ^{830} The designated FEL applies to every vehicle within a family or sub-family and must be complied with throughout the vehicle's useful life. Manufacturers choosing to demonstrate compliance with the applicable emission standards using the ABT program must show compliance based on (among other things) production levels and emissions level of FELs. See 40 CFR 1037.705(b). Each family or subfamily has a designated FEL, and credits are generated if the FEL is lower than the applicable standard, and debits are generated if the FEL is higher than the applicable standard. ^{831} The manufacturer can use those credits to offset higher emission levels from vehicles in the same averaging set such that the averaging set meets the standards on “average”, “bank” the credits for later use, or “trade” the credits to another manufacturer. In other words, under the existing ABT program, a manufacturer has two obligations—(1) all vehicles are certified to and must comply throughout their useful life with the FEL applicable to that vehicle's family or subfamily, and (2) the manufacturer's vehicles must comply with the applicable emission standard as a group, e.g., using a production-weighted average of the various FELs across the applicable averaging set. All vehicle families across an averaging set must show a net zero or positive credit balance as detailed in the existing regulation. ^{832} To incentivize the research and development of new technologies with great emission reduction potential, the existing HD vehicle ABT program also includes credit multipliers for certain advanced technologies, which we discuss further in III.A.2.
^{828} See also an expanded description of EPA's ABT program provided as background in the HD GHG Phase 1 rule (76 FR 57238-57243).
^{829} 40 CFR 1037.241(a)(2).
^{830} 40 CFR 1037.801 (definition of “Family emission limit”).
^{831} “[F]or each family or subfamily . . . positive credits [are generated] for a family or subfamily that has an FEL below the standard.” 40 CFR 1037.705(b).
^{832} Manufacturers must show “that [the manufacturer's] net balance of emission credits from all [the manufacturer's] participating vehicle families in each averaging set is not negative”. 40 CFR 1037.730(c)(1), and 40 CFR 1037.241(a)(2) (“vehicle families within an averaging set are considered in compliance with the CO 2 emissions standards, if the sum of positive and negative credits for all vehicle configurations in those vehicles lead to a zero balance or a positive balance of credits”).
In this section III.A, we describe changes we are finalizing for three aspects of the ABT program: the applicable production volume for use in calculating ABT credits, how manufacturers can use credit multipliers for advanced technologies, and credit transfers across averaging sets. We intend for the limitations placed on credits generated from Phase 2 advanced technology credit multipliers and the transitional allowance of credit transfers across averaging sets that are finalized in this rule to be entirely separate from the Phase 3 emissions standards and other varied components of this rule, and severable from each other. Each of these two issues has been considered and adopted independently of the level of the standards, and indeed of each other. EPA's overall vehicle program continues to be fully implementable even in the absence of any one or both of these elements. All the emissions standards in the rule are feasible even without these specific flexibilities. While credits from multipliers and credit transfers across averaging sets allow flexibility in compliance options for manufacturers, they are not necessary for manufacturers to meet the emissions standards and we did not rely on them in justifying the feasibility of the standards. See preamble sections II.F and II.G and RIA Chapter 2. EPA has also considered and adopted these transitional ABT flexibilities and requirements and the remaining portions of the final rule independently, and each is severable should there be judicial review. If a court were to invalidate any one of these elements of the final rule, we intend the remainder of this action to remain effective, as we have designed the program to function even if one part of the rule is set aside. For example, if a reviewing court were to invalidate the transitional allowance of credit transfers across averaging sets, the other components of the rule, including the Phase 3 GHG standards (which are not predicated on these transitional flexibilities), remain fully operable. We did not propose or otherwise reopen, and we are not adopting any revisions to the allowance that provides manufacturers three years to resolve credit deficits, as detailed in 40 CFR 1037.745. We did not reopen and are generally retaining the existing credit life of five years, as described in 40 CFR 1037.740(c), with discrete revisions beginning in MY 2027 to the availability of credits earned from advanced technology multipliers as described in section III.A.2. Similarly, we are retaining the existing ABT restrictions for vehicles certified to the custom chassis standards in 40 CFR 1037.105(h)(2). Manufacturers of custom chassis vehicles that wish to make use of the expanded flexibilities we are finalizing in this rule and describing in this section III.A, must certify the vehicles under the main program in the applicable regulatory subcategory.

1. U.S.-Directed Production Volume
As described in section II.D and II.F, the Phase 3 GHG vehicle standards include consideration of nationwide production volumes. Correspondingly, we proposed and are finalizing that the GHG ABT program for compliance with those standards be applicable to the same production volumes considered in setting the standards. 88 FR 26009. The existing HD GHG Phase 2 vehicle program has certain provisions (based off the regulatory definition of “U.S.-directed production volume”) that would exclude production volumes that are certified to different state emission standards, including exclusion from participation in ABT. To address the interaction between the existing definition of U.S.-directed production volume and the California Advanced Clean Truck (ACT) regulation for HD vehicles, we proposed and are finalizing a revision to the definition of “U.S.-directed production volume” in 40 CFR 1037.801. The revision removes the final sentence of that definition, which presently states that the definition “does not include vehicles certified to state emission standards that are different than the emissions standards in this part”, and thereby amends it to remove any exclusions from the definition. In this section III.A.1, we summarize the approach used to setting the Phase 3 standards and the uncertainties that led us to revise the definition such that, within the Phase 3 standards and within the ABT GHG vehicle program, we consider nationwide production volumes that include vehicles that may be certified to state emission standards that are different than the emission standards in 40 CFR part 1037, including vehicles subject to the ACT standards.
The term U.S.-directed production volume is key in how the regulations direct manufacturers to calculate credits in the HD vehicle ABT GHG program in 40 CFR part 1037, subpart H. As noted, prior to this final rule, the existing definition of “U.S.-directed production volume” for HD vehicles explicitly excludes vehicles certified to state emission standards that differed from Federal standards. ^{833} Consequently, vehicle production volumes excluded from that term's definition could not generate credits or deficits for purposes of the Federal program. As described in the proposal (88 FR 26009), the previous exclusion of engines and vehicles certified to different state standards did not impact the HD GHG program under parts 1036 and 1037 to-date because California adopted GHG emission standards for HD engines and vehicles that aligned with the Federal HD GHG Phase 1 and Phase 2 standards. 834 835 As also noted in the proposal, the revised definition would align with the approach in the LD GHG program (88 FR 26010).
^{833} Previously, 40 CFR 1037.801 defined U.S.-directed production volume as meaning “the number of vehicle units, subject to the requirements of this part, produced by a manufacturer for which the manufacturer has a reasonable assurance that sale was or will be made to ultimate purchasers in the United States. This does not include vehicles certified to state emission standards that are different than the emission standards in this part.” An equivalent definition of U.S-directed production volume previously applied for HD engines under 40 CFR 1036.801.
^{834} California Air Resources Board. “Final Regulation Order for Phase 1 Greenhouse Gas Regulations.” December 5, 2014, available at https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2013/hdghg2013/hdghgfrot13.pdf.
^{835} California Air Resources Board. “Final Regulation Order for Phase 2 Greenhouse Gas Regulations and Tractor-Trailer GHG Regulations.” April 1, 2019, available at https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2018/phase2/finalatta.pdf?_ga=2.122416523.1825165293.1663635303-1124543041.1635770745 .
As discussed in Chapter 1 of the RIA, the ACT regulation requires manufacturers to produce and sell increasing numbers of zero-emission medium- and heavy-duty highway vehicles. Given the distinct difference between what would be required under the ACT regulation compared to the existing Phase 2 and proposed Phase 3 vehicle standards, we proposed that the new definition would start with MY 2024 to provide consistent treatment of any production volumes certified to ACT. We requested comment on whether we should consider other options to transition to the new definition.
In comments, vehicle manufacturers generally supported the proposed revision to the definition and the effective date of MY 2024, with some indicating that manufacturers would need to include vehicles intended for ACT states in order to meet the Phase 3 standards and that some manufacturers have adopted ZEV technologies as a Phase 2 compliance strategy. Environmental and health NGOs generally opposed the proposed revision noting that, combined with the multipliers available for advanced technology credits in that period, the new definition would erode the Phase 3 standard stringency and result in no improvements beyond what would occur in the absence of the rule. Some of the commenters further suggested that these credits could even dilute the stringency of the Phase 2 standards, without justification, by making the revised definition effective in MY 2024. Consequently, the commenters urged that if EPA amends the definition as proposed, it either commence the change in MY 2027 rather than MY 2024 or that EPA make a corresponding adjustment in stringency of the Phase 3 national standard to include nationwide adoption rates similar to ACT.
We are adopting an amended definition of the term U.S.-directed production volume. We disagree with commenters maintaining that EPA should not change the definition because any credits generated by vehicles in ACT states would be windfalls for the Phase 3 program. First, it is not clear that ZEV sales in ACT states are automatically attributable to the ACT requirements. Manufacturers have already introduced ZEVs into the market and, given that EPA granted the waiver for ACT earlier this year, some may have done so as a Phase 2 compliance strategy. ^{836} Additionally, it is currently unclear if manufacturers' existing compliance plans to meet the Phase 2 standards in a given model year include use of all or a portion of their advanced technology credits (and associated credit multipliers) generated from nationwide production volumes. Credits generated as a result of legitimate Phase 2 compliance strategies are not windfalls and we do not have a way to accurately project or account for the balance of credits that may be available for use in MYs 2027 and later.
^{836} See, e.g., comments of DTNA (EPA-HQ-OAR-2022-0985-1555) and Volvo (EPA-HQ-OAR-0985-1606) asserting that OEMs have not been adopting certain technologies on which EPA predicated the Phase 2 rule and consequently have looked to other means of compliance, including utilizing ZEV technologies.
Furthermore, the final standards reflect nationwide production volumes. As explained in section II.F of this preamble, for the modeled potential compliance pathway supporting the feasibility of the final standards, HD TRUCS uses nationwide production volumes to project the utilization of the ZEV technologies portion of the technology packages. ^{837} So commenters were mistaken in maintaining that the change in the definition would necessarily dilute the Phase 3 standard stringency, as the final Phase 3 standards' stringency are premised upon nationwide production volumes, consistent with the amended definition.
^{837} Specifically, the projected ZEV adoption rates in our modeled potential compliance pathway are sales-weighted by subcategory. See RIA Chapter 2 for a more detailed description of HD TRUCS and its use of MOVES 4.0 data, as well as the potential compliance pathway's technology packages.
In response to commenters suggesting EPA adjust the stringency of Phase 3 to include nationwide adoption rates similar to ACT, we note that we developed the final rule stringency through a balanced and measured approach, based on consideration and balancing of the statutory and other relevant factors, including technical feasibility, costs, and lead time, as described in section II.G of this preamble and RTC section 2.4.
We note an additional concern with EPA adopting suggestions from commenters asking EPA to take a different Phase 3 standard setting approach and implement the Federal program with the previous definition. Even under the previous definition, manufacturers should be eligible to generate credits under the Federal program for production and sales in excess of those required by ACT in states where ACT is applicable, as otherwise our Federal program could unintentionally create a disincentive for such excess production and sales in states where ACT applies. 838 839 If the ACT program simply mandated “each manufacturer shall produce x number of vehicles of each type”, it would be straightforward to segregate production volumes and sales destined for ACT states and exclude such volumes from standard setting and compliance. But the ACT program is not structured that simply and also provides various compliance flexibilities for manufacturers. For example, it uses a credit generating approach with similarities to the Federal ABT program, but with consequential differences as well, including weighted amounts of credits per vehicle class, banking and trading across all vehicle classes, the ability to generate partial credits for certain vehicles, and the potential for carrying deficits into future model years. See RIA Chapter 1.3.3 for further detail on the California ACT regulation. Thus, there would be meaningful uncertainties related to segregating manufacturers' production volumes and credit balances to comply with the ACT regulation. While we project a reference case (as explained in section V of this preamble and RIA chapter 4.3.1) that includes an increase in the production of ZEVs in part reflecting compliance with ACT in states where applicable, given the flexibilities in ACT, the production volumes projected in the reference case may not match what manufacturers actually do. It is also unclear how EPA could appropriately distinguish which credits should be treated as excess and part of compliance with the Phase 3 program, and the complexity involved in such a scheme raises verification concerns.
^{838} See comments from Navistar, Inc. (EPA-HQ-OAR-2019-0055-1318, p. 6) submitted to EPA for the HD2027 NPRM (87 FR 17592).
^{839} We also considered that exclusion of production volumes and sales of states that adopted ACT from the Federal ABT program could unintentionally complicate or even disincentivize other state's decision making in whether to adopt ACT under CAA section 177.
Finally, we do not think it would be appropriate under CAA section 202(a)(1) to support the standards through a feasibility demonstration under the modeled potential compliance pathway projecting that manufacturers will sell volumes of ZEVs nationally (including in ACT states), but then prohibit manufacturers from generating and using credits based on such sales for compliance purposes. This would result in a disconnect between how EPA developed and implemented the standards, as the standard stringency reflects nationwide production volumes but implementation would exclude portions of nationwide sales. In addition, we want to minimize the impact of the uncertainty surrounding the number of states that may adopt the ACT program on manufacturer compliance planning both in the years leading up to MY 2027 and during the years of the Phase 3 program. That is, we think it is important to provide manufacturers with regulatory certainty on the impact of their products on their compliance with the Phase 3 program, and believe that it would be inappropriate for such impacts to change significantly every time a new State decided to adopt (or withdraw from) the ACT program. Furthermore, manufacturers may be motivated to produce vehicles with advanced CO 2 control or prevention technologies by Phase 3 and in response to other initiatives, and we want to support any U.S. adoption of these technologies by allowing manufacturers to account for their nationwide production volumes to comply with the standards of this rule. For these reasons, EPA believes the change to the definition is warranted.
In response to commenters urging that any change not occur until MY 2027, we disagree that this new definition would dilute the Phase 2 program. The Phase 2 standards were promulgated as a national program and we expect manufacturers developed their Phase 2 compliance strategies relying on the availability of credits, and in some case credit multipliers, from nationwide production. As noted, there are comments to this effect from manufacturers. While there are now new state standards and the previous definition would exclude production intended for sale in states adopting those standards, the timing of the ACT waiver approval relative to the manufacturer compliance plans would cause timing concerns in the near term if those production volumes were excluded from Phase 2 compliance.
Also, as just noted, uncertainties relating to other states adopting the ACT regulation and the timing of such adoption can cut across manufacturers' compliance plans, and this concern is especially sensitive in the near term, when manufacturers are least able to alter compliance strategies. For example, with respect to MY 2024, EPA expects that manufacturers have been planning and developing a compliant fleet for years based on the nationwide applicability of the Phase 2 program, including ABT provisions, and the lead time necessary to develop and produce heavy-duty vehicles. EPA granted the CAA section 209 waiver of preemption for the California ACT program on March 30, 2023, which is during MY 2024, and which under the prior definition of U.S.-Directed Production Volume would have caused manufacturers to not be able to generate credits for vehicles sold in states that had adopted ACT. ^{840} To suddenly deprive manufacturers of the ability to generate credits for vehicles sold in ACT states for MY 2024 during that model year would likely undermine manufacturers' long-extant compliance strategies, and given the lead time necessary for developing and producing vehicles, would not likely cause manufacturers to significantly change their product line in MY 2024.
^{840} We note again that prior to the adoption of ACT and EPA granting the waiver for ACT, the EPA and California programs were aligned. Thus, as a practical matter, manufacturers could generate credits based on nationwide production volumes, notwithstanding the then-existing definition of “U.S.-directed production volume.” From this perspective, EPA's amendment of the definition appropriately preserves the status quo whereby credits may be generated nationwide for compliance through the EPA ABT program. See Response to Comments section 10.2.
Thus, we are finalizing a revision to the definition of “U.S.-directed production volume” in 40 CFR 1037.801 such that it represents the total nationwide production volumes, and we are making that change effective in MY 2024 to minimize the uncertainties related to how ACT will be implemented. We explain in the following section III.A.2 that the final rule includes provisions aimed at minimizing emissions impacts of credits from PHEV, BEV, and FCEV production volumes.
Finally, we note that in addition to this revision to the definition of “U.S.-directed production volume”, we are finalizing additional conforming amendments throughout 40 CFR part 1037 to streamline references to the revised definition; see section III.C.3 of this preamble for further discussion on one of those revisions. ^{841}
^{841} As discussed in section III.C.3, we are also finalizing a similar update to the heavy-duty highway engine definition of “U.S.-directed production volume” in 40 CFR 1036.801, with additional updates where it is necessary to continue to exclude production volumes intended for sale in states with different emission standards.

2. Advanced Technology Credit Multipliers for CO 2 Emissions
For the HD GHG Phase 2 rule, EPA adopted credit multipliers through MY 2027 for vehicles that qualified as “advanced technology” based on the administrative record at that time ( i.e., PHEV, BEV, and FCEV). In the proposal for this rule (88 FR 26010), we described the HD GHG Phase 2 advanced technology credit multipliers as representing a tradeoff between incentivizing new advanced technologies that could have significant emissions benefits and providing credits that could allow higher emissions from credit-using engines and vehicles. At the time we finalized the HD GHG Phase 2 program in 2016, we estimated that there would be very little market penetration of PHEV, BEV, and FCEV in the heavy-duty market in the MY 2021 to MY 2027 timeframe when the advanced technology credit multipliers would be in effect. Additionally, the technology packages in our technical basis of the feasibility of the HD GHG Phase 2 standards did not include any of these advanced technologies.
In our assessment conducted during the development of HD GHG Phase 2, we found only one manufacturer had certified HD BEVs through MY 2016, and we projected “limited adoption of all-electric vehicles into the market” for MYs 2021 through 2027. ^{842} At low adoption levels, the benefits of encouraging additional utilization of these technologies outweighed negative emissions impacts of multipliers. However, as discussed in section II, manufacturers are now actively increasing their use of PHEV, BEV, and FCEV HD technologies with further support through the IRA and other actions, and we expect this growth to continue through the remaining timeframe for the HD GHG Phase 2 program and into the timeframe for this Phase 3 program.
^{842} 81 FR 73818 (October 25, 2016).
While we did anticipate that some growth in development of these technologies would occur due to the credit incentives in the HD GHG Phase 2 final rule, we did not expect the level of innovation observed since we finalized the rule, the IRA or BIL incentives, or that California would adopt the ACT rule at the same time these advanced technology multipliers were in effect. We therefore proposed phasing out multipliers for PHEV and BEV technologies one year earlier than provided in the Phase 2 rule. After considering comments and the potential disruption to manufacturers' compliance plans for Phase 2, we are retaining the existing Phase 2 flexibility that allows manufacturers to continue to earn advanced technology credit multipliers for PHEV and BEV technologies through model year 2027. To address the concern of reduced Phase 3 stringency raised in comments, we are finalizing a provision that places certain restrictions on and specifies the circumstances when credits from multipliers may be used in model years 2027 through 2029 and eliminates the availability of credit multipliers for use in model years 2030 and later. In this section III.A.2, we present background on advanced technologies, summarize the comments that informed our final approach for credit multipliers, and describe the revisions we are finalizing related to advanced technology credits.

i. Background on Phase 1 and Phase 2 GHG Advanced Technology Credits
In the prior HD GHG Phase 1 and Phase 2 rules, EPA adopted advanced technology credits to incentivize the long-term development of technologies that had the potential to achieve very large GHG reductions. Specifically, in HD GHG Phase 1, we provided advanced technology credits for hybrid powertrains, Rankine cycle waste heat recovery systems on engines, all-electric vehicles, and fuel cell electric vehicles to promote the implementation of advanced technologies that were not included in our technical basis of the feasibility of the Phase 1 emission standards (see 40 CFR 86.1819-14(k)(7), 1036.150(h), and 1037.150(p)). The HD GHG Phase 2 CO 2 emission standards that followed Phase 1 were premised on the use of mild hybrid powertrains in vocational vehicles and waste heat recovery systems in a subset of the engines and tractors, and we removed mild hybrid powertrains and waste heat recovery systems as options for advanced technology credits. At the time of the HD GHG Phase 2 final rule in 2016, we believed the HD GHG Phase 2 standards themselves provided sufficient incentive to develop those specific technologies. However, none of the HD GHG Phase 2 standards were based on projected utilization of the other, even more-advanced Phase 1 advanced credit technologies ( e.g., plug-in hybrid electric vehicles, all-electric vehicles, and fuel cell electric vehicles). For HD GHG Phase 2, EPA promulgated advanced technology credit multipliers through MY 2027, as shown in Table III-1 (see also 40 CFR 1037.150(p)).
As stated in the HD GHG Phase 2 rulemaking, our intention with these multipliers was to create a meaningful incentive for those manufacturers considering developing and applying these qualifying advanced technologies into their vehicles. The multipliers under the existing program are consistent with values recommended by CARB in their HD GHG Phase 2 comments. ^{843} CARB's values were based on a cost analysis that compared the costs of these advanced technologies to costs of other GHG-reducing technologies. CARB's cost analysis showed that multipliers in the range we ultimately promulgated as part of the HD GHG Phase 2 final rule would make these advanced technologies more competitive with the other GHG-reducing technologies and could allow manufacturers to more easily generate a viable business case to develop these advanced technologies for HD vehicles and bring them to market at a competitive price.
^{843} Letter from Michael Carter, CARB, to Gina McCarthy, Administrator, EPA and Mark Rosekind, Administrator, NHTSA, June 16, 2016. EPA Docket ID EPA-HQ-OAR-2014-0827_attachment 2.
In establishing the multipliers in the HD GHG Phase 2 final rule, we also considered the tendency of the HD sector to lag behind the light-duty sector in the adoption of several advanced technologies. There are many possible reasons for this, such as:
• HD vehicles are more expensive than light-duty vehicles, which makes it a greater monetary risk for purchasers to invest in new technologies.
• These vehicles are primarily work vehicles, which makes predictable functionality and versatility important.
• Sales volumes are much lower for HD vehicles, especially for specialized vehicles.
At the time of the HD GHG Phase 2 rulemaking, after considering these factors, combined with virtually non-existent adoption of the aforementioned advanced technologies in HD vehicles as of 2016, we concluded that it was unlikely that market adoption of these low GHG advanced technologies would grow significantly within the next decade without additional incentives.
As we stated in the HD GHG Phase 2 final rule preamble, our determination that it was appropriate to provide large multipliers for these advanced technologies, at least in the short term, was because these advanced technologies have the potential to lead to very large reductions in GHG emissions and fuel consumption and promote technology development substantially in the long term. 81 FR 73818. However, because the credit multipliers are so large, we also stated that they should not necessarily be made available indefinitely. Therefore, they were included in the HD GHG Phase 2 final rule as an interim program continuing only through MY 2027. 40 CFR 1037.615(a).
The HD GHG Phase 2 CO 2 emission credits for HD vehicles are calculated according to the existing regulations at 40 CFR 1037.705(b). For BEVs and FCEVs, the family emission level (FEL) value for CO 2 emissions is deemed to be 0 grams per ton-mile. ^{844} Under those existing regulations, the CO 2 emission credits for HD BEVs built between MY 2021 and MY 2027 would be multiplied by 4.5 (or the values shown in Table III-1 for the other technologies) and, for discussion purposes, can be visualized as split into two shares. ^{845} The first share of credits would come from the reduction in CO 2 emissions realized by the environment from a BEV that is not emitting from the tailpipe, represented by the first 1.0 portion of the multiplier. Therefore, each BEV or FCEV produced receives base emission credits equivalent to the level of the standard, even before considering the effect of a multiplier. The second share of credits does not represent CO 2 emission reductions realized in the real world but rather, as just explained, was established by EPA to help incentivize a nascent market: in this example, the emission credits for BEVs built between MY 2021 and 2027 receive an advanced technology credit multiplier of 4.5, i.e., an additional 3.5 multiple of the standard.
^{844} 40 CFR 1037.150(f).
^{845} See 40 CFR 1037.150(p) and 1037.705(b).

ii. Revisions to the Advanced Technology Credit Multipliers
We proposed to amend the existing Phase 2 rule to provide for an earlier phase out of multipliers for PHEVs and BEVs. In general, commenters' support for the proposed approach for phasing out advanced technology credit multipliers varied (see section 10.3.1 of the RTC document for this rulemaking). Some commenters supported the proposal. Others commented that EPA should retain the multipliers through MY 2027 as finalized in the Phase 2 program, noting that manufacturers are relying on the availability of the multipliers for their compliance plans and so would need more lead time to revise their plans. Some commenters suggested that our statements in the proposal that there is sufficient incentive available for advanced technologies indicated that EPA should eliminate some or all multipliers before MY 2026. Others noted the need for continued support for manufacturers to develop these technologies, and recommended EPA extend the availability of some or all multipliers beyond MY 2027.
At proposal (88 FR 26010), we noted that revisions to credit multipliers should carefully balance several considerations. In terms of potential emissions impact, we acknowledged that a portion of the credits that result from an advanced technology multiplier do not represent CO 2 emission reductions realized in the real world and those excess credits could allow for backsliding of emission reductions expected from ICE vehicles. Relating to the need for continued incentives, we noted that increasing manufacturer production levels, the availability of IRA or BIL incentives, and targets set as part of California's ACT rule all indicate PHEV and BEV HD vehicles will be utilized increasingly in the near-term, reducing the need for the extra incentives provided by the advanced technology multipliers.
In the proposal, we also recognized, however, that some manufacturers' long-term product plans for PHEV or BEV technologies may have extended to model years closer to MY 2027, and we did not propose to immediately eliminate PHEV and BEV credit multipliers. 88 FR 26012. Instead, we proposed a MY 2026 phase-out for PHEV and BEV credit multipliers, one year earlier than adopted in Phase 2, in part, to limit the impact on current manufacturer product plans for the HD GHG Phase 2 standards and to provide some flexibility as manufacturers plan for the more stringent Phase 3 standards. We did not propose any changes to the advanced technology multiplier for fuel cell electric vehicles, which applies through MY 2027, noting that it was still appropriate to incentivize the development of fuel cell technology, because it has been slower to develop in the HD market, as discussed in section II (88 FR 26012). We note that the proposal regarding Phase 2's credit multipliers was limited to evaluating approaches to phase out their availability for use and we did not propose or request comment on extending credit multipliers to apply for other technologies.
In this final rule, commenters expanded on the proposed considerations. Some commenters noted that we are amending the definition of U.S. Directed Production Volume, as discussed in the section III.A.1, such that vehicle production volumes sold in California or section 177 states that adopt ACT would be included in the ABT credit calculations. These commenters indicated that continuing to allow multipliers for PHEVs and BEVs could expand banks of credits well past the point EPA contemplated when adopting the Phase 2 rule. Some of these commenters asserted that, given the Phase 2 flexibilities and the ACT requirements, manufacturers will necessarily comply with the Phase 3 standards by virtue of complying with ACT. In contrast, several manufacturers commented that both their near-term Phase 2 and long-term compliance plans relied on the availability of credit multipliers (including use of credits generated from credit multipliers for Phase 2 compliance) and some even requested EPA extend the availability through MY 2030 to continue to incentivize the technologies. One manufacturer indicated that California's ACT program targets manufacturer sales, but that those sales only occur if customers purchase the products. This commenter noted that, while supporting regulations exist in some states, there are no nationwide initiatives to ensure sales, so it is unclear how many ZEVs will be sold as a result of ACT.
After considering the comments received on the proposal for this rule, we are not taking final action on the proposal to revise the Phase 2 rule to provide for an earlier phase out (one year early) of multipliers for PHEVs and BEVs. As such, manufacturers may continue to generate credits that include credit multipliers for PHEV, BEV, and FCEV technologies through MY 2027 as was adopted in Phase 2. ^{846} We note that our analysis of the feasibility of the Phase 3 standards did not rely on the availability of carried over credits from Phase 2 or Phase 2 credit multipliers; our assessment is that such credits will provide appropriate flexibilities for manufacturers in the transition into the early years of the Phase 3 program, as manufacturers make practical business decisions on where to apply their resources to first develop products. We also note that retaining the existing Phase 2 ABT provisions on credit multipliers should address potential concerns or uncertainties raised by manufacturers regarding their compliance plans relying on the credits generated under the existing Phase 2 credit multiplier provisions. However, as explained in the remainder of this preamble section, we are finalizing provisions to limit the potential use of credits generated from this flexibility.
^{846} We are revising 40 CFR 1037.150(p) to clarify the applicable standards for calculating credits. We are finalizing parallel edits to existing 40 CFR 1037.615(a) and 1037.740(b) to clarify when the advanced technology credit calculations would apply.
We disagree with those commenters that assert manufacturers will necessarily comply with the Phase 3 standards by virtue of complying with ACT. These comments assume a given volume of Phase 2 credits will be generated and carried over into Phase 3, and thus presuppose manufacturers' compliance strategies with both the Federal performance-based Phase 2 and 3 standards and the California ACT program. Our final rule reference case modeling is our best estimate of ZEV technology production volumes in the absence of the Phase 3 rulemaking, as supported by our analysis in preamble section V. Sales volumes could prove to be lower, however. ^{847} We also recognize that manufacturers may have different approaches and technology pathway plans to demonstrate compliance with Phase 2 as well as with ACT, as asserted by certain commenters and summarized previously in this section, and thus manufacturers may undertake different approaches than those asserted as the basis of commenters' concerns with multiplier credit volumes. EPA considered all of these comments in weighing potential limitations on ABT flexibilities for credits generated by the existing Phase 2 credit multipliers.
^{847} We also note that, in RIA Chapter 4.10, we conducted a reference case sensitivity analysis with lower ZEV adoption than we project will occur through compliance with CARB's ACT.
After balancing consideration of the concerns of disrupting on-going Phase 2 compliance strategies and the potential for multiplier credits to erode the emission benefits of the Phase 3 program, we are placing restrictions on how credits from multipliers can be used to meet the Phase 3 standards, and are additionally limiting their use to the initial model years of the Phase 3 program. As described in the remainder of this section III.A.2.ii, we are finalizing provisions that will limit when manufacturers can use credits generated from credit multipliers in MY 2027 through 2029 and eliminate the availability of those credits for use in MY 2030 and later.
As noted previously, advanced technology credits can be thought of as two portions: a base credit calculated using the equation in 40 CFR 1037.705(b) and a multiplier portion calculated using multipliers specified in 40 CFR 1037.150(p) for a given advanced technology. Our final provisions will continue to allow manufacturers to apply the base credits from advanced technologies through the 5-year credit life; however, to ensure meaningful vehicle GHG emission reductions under the Phase 3 program, we are finalizing restrictions for how manufacturers can use the multiplier portion of advanced technology credits toward Phase 3 compliance.
In MYs 2027 through 2029, manufacturers can continue to use multiplier credits to meet the Phase 3 standards; however, multiplier credits can only be applied toward Phase 3 compliance after available base credits are used. In a given model year within the timeframe this limitation applies, manufacturers quantify the credits available from advanced technologies, including from credits that were banked in previous years, and account for the base and multiplier portions of the credits. Then, for each family, they would calculate credits without consideration of credit multipliers ( i.e., credits and deficits from ICE vehicles, and base credits from vehicles with advanced technologies) and sum the credit quantities over all vehicle families in the averaging set. ^{848} If the credit quantity is positive, any surplus credits, including the multiplier credits, can be banked for future use. If the credit quantity for the given averaging set is negative, manufacturers must use available base credits before applying multiplier credits. Specifically, a manufacturer would apply credits in the following order of priority, while the credit quantity for the averaging set is negative:
^{848} This first step is generally consistent with our historical approach to credits, which allows use of credits generated within the same model year but also first applies all such available credits through averaging to resolve credit balances for that model year before applying banked or traded credits. This approach prevents potential gaming of credit life and trading limitations. To further clarify this in the regulations, we are also adding an amendment in 40 CFR 1037.701(f) consistent with this description.
1. Base credits banked or traded within the same averaging set.
2. Base credits earned in the same model year from other averaging sets (see section III.A.3 of this preamble).
3. Base credits banked or traded in other averaging sets and used across averaging sets as described in section III.A.3.
4. Multiplier credits within the same averaging set for the same model year.
5. Multiplier credits banked or traded within the same averaging set.
6. Multiplier credits earned in the same model year from other averaging sets.
7. Multiplier credits banked or traded in other averaging sets.
This limitation to using credits from multipliers for MYs 2027 through 2029 is intended to balance the competing concerns discussed in this section. Manufacturers would continue to have access to the full amount of credits from multipliers if needed in the early years of the Phase 3 program. ^{849} By prioritizing the use of base credits, we are reducing the potential for multiplier credits to erode the emission benefits of the Phase 3 program, in particular in MYs beyond 2029.
^{849} See Brakora, Jessica. Memorandum to docket EPA-HQ-OAR-2022-0985. “Additional Considerations of ABT Provisions for HD GHG Phase 3 Final Rule”. March 2024 for examples of how these provisions could apply.
We emphasize that this limitation to using credits from multipliers for MYs 2027 through 2029 is intended to apply for Phase 3 compliance. We want to preserve manufacturers' ability to implement their existing plans for complying with the Phase 2 program. Some manufacturers stated in their comments that they have included PHEV and BEV technologies in their plans to comply with Phase 2 standards and that those plans also rely on the credit multipliers for the remaining model years of the Phase 2 program. Others have indicated that credit multipliers are a critical incentive for FCEV development in the near term. To minimize the impact on manufacturers' Phase 2 compliance plans, we continue to allow full advanced technology credits, including any multiplier credits, to be used for Phase 2 compliance as currently allowed in the Phase 2 ABT program. That is, in MYs 2026 and earlier, averaged, banked, and traded Phase 2 advanced technology credits, including applicable multipliers, can be used to comply with the CO 2 standards in those years. In MY 2027, manufacturers will continue to have the option to earn advanced technology credits with multipliers relative to the Phase 3 standards. All multiplier credits can be used in full toward any Phase 2 deficits through MY 2029 ( i.e., the end of the 3-year window when manufacturers must remedy any MY 2026 Phase 2 deficits).
In MY 2030, we are phasing out the multiplier portion of any remaining advanced technology credits. Credits from Phase 2 advanced technologies will continue to be available, including those credits generated from their applicable multiplier, through MY 2029 as described previously in this section. In MY 2030 and later, manufacturers would retain any base credits previously earned from PHEV, BEV, or FCEV advanced technologies that are still within their credit life of 5 years, but manufacturers could no longer use multiplier credits for certifying model year 2030 and later vehicles. Any unused multiplier credits would expire in MY 2030.
Since some portion of the advanced technology credits have restricted or expiring use, we expect to track base credits separate from multiplier credits in evaluating compliance and will work with manufacturers to prioritize which credits are applied for a given model year consistent with the final restrictions and provisions. Finally, we note that in section II.B of this preamble we describe part of EPA's commitment to monitor the on-going implementation of the HD vehicle GHG programs as assessing manufacturers' use of the CO 2 emissions ABT program. This will include evaluating manufacturers' use of advanced technology multipliers, quantifying any banked credits generated from the use of multipliers, and considering the potential for those credits to undermine the overall goals of the Phase 3 program in the MY 2027 and later time frame. If we identify a significant volume of banked credits from credit multipliers that we determine is undermining the goals of the Phase 3 program, we may consider further restrictions in a future action.

3. Transitional Flexibility Allowing Credit Exchange Across Averaging Sets
In recognition that the final HD GHG Phase 3 standards will require meaningful investments from manufacturers to reduce GHG emissions from HD vehicles, we are finalizing additional flexibilities to assist manufacturers in the implementation of Phase 3. Specifically, we requested comment on and are finalizing an interim ( i.e., temporary) flexibility for manufacturers to use certain credits across averaging sets, with limitations outlined in this section. We are retaining our current averaging set definitions and our approach that limits averaging, banking, or trading within an averaging set for credits or deficits generated from heavy-duty vehicles outside the range of model years over which this transitional allowance applies. ^{850}
^{850} 40 CFR 1037.140(g) and 1037.740(a).
In HD GHG Phase 1, we adopted an approach to allow advanced technology credits to earn a multiplier of 1.5 and be applied to any heavy-duty engine or vehicle averaging set, subject to a cap. ^{851} In HD GHG Phase 2, we discontinued the allowance to reduce the risk of market distortions if we allowed the use of the credits across averaging sets combined with the larger credit multipliers. ^{852} As discussed in section III.A.2, manufacturers will continue to have the flexibility to generate advanced technology credit multipliers through model year 2027 but those credits generated from multipliers would only be available for use through model year 2029.
^{851} 40 CFR 1036.740(c) and 1037.740(b).
^{852} 81 FR 73498, October 25, 2016.
We requested comment on the flexibility for credits generated from PHEV, BEV, and FCEV to be used across certain averaging sets, including for HD vehicles subject to 40 CFR part 1037, HD engines subject to 40 CFR part 1036, or heavy-duty vehicles subject to 40 CFR part 86, subpart S, and any limitations we should consider. 88 FR 26013. In comments, many vehicle manufacturers expressed concern over the level of the proposed standards and, for those considering a compliance pathway similar to the potential pathway EPA modeled, the uncertainties in their ability to produce enough BEV or FCEV or otherwise to meet the standards. Commenters expressing support for using credits across averaging sets generally noted that the flexibility would help manufacturers implement advanced technologies in the vehicle segments with the greatest demand or cost effectiveness. Some of these supportive commenters suggested EPA expand the flexibility beyond the examples provided in the requests for comment. Commenters opposed to allowing credit transfers across averaging sets generally expressed concern over market distortions and reduced effectiveness of the rule.
After considering comments and further evaluation of the example flexibilities included as requests for comment in the proposal, the final provision, available as an interim, transitional flexibility during model years 2027 through 2032, will allow manufacturers some flexibility to use credits generated from heavy-duty vehicles across averaging sets. In this section III.A.3, we describe how the allowance applies for heavy-duty vehicles under 40 CFR part 1037 and heavy-duty vehicles under 40 CFR part 86, subpart S. We also explain our decision not to extend this flexibility to allow heavy-duty vehicle credits for use in the heavy-duty engine averaging sets under 40 CFR part 1036. See also section 10.3.2 of the response to comments document for this rule.

i. Applicability of the Transitional Flexibility Allowing Credit Exchange Across Averaging Sets
The current rules provide three averaging sets for HD vehicles: Light HDV, Medium HDV, and Heavy HDV (see 40 CFR 1037.740(a)). Credits generated by vehicles may only be averaged, banked, or traded within each averaging set. Id. EPA sought comment on revising this limitation during the initial phase-in years of the Phase 3 program for credits generated from Phase 2's designated advanced technologies. 88 FR 26013. EPA's request for comment also included the possibility of credits generated by chassis-certified Class 2b/3 vehicles certified under 40 CFR part 86, subpart S, being allowed to be used within the HD vehicle ABT program and credits from HD vehicles being allowed to be used within the HD engine ABT program. Id.
The provision that limits credit exchanges to within averaging sets is unique to the heavy-duty rules—on the light-duty vehicle side, credits can flow freely among all vehicle types. EPA implemented the limitation because heavy-duty vehicles comprise so many applications that calculations across averaging sets of, for example, operating life and load cycles could prove problematic. 76 FR 57240 (September 11, 2011). EPA has also noted manufacturer equity concerns (see, e.g., 55 FR 30586 (July 26, 1990)), whereby manufacturers with broader product lines might have an unfair advantage because of greater opportunities to average. EPA further indicated, however, that we could reassess these limitations after gaining experience administering the program. 76 FR 57240. In this rulemaking, commenters did not voice these concerns, and HD manufacturers commented that averaging across the HDV averaging sets would no longer afford competitors an unfair advantage. ^{853}
^{853} See, for example, comments from Volvo Group (EPA-HQ-OAR-2022-0985-1606, p 20-21).
After considering comments, we are finalizing an interim provision allowing credits to be used across HD vehicle averaging sets during the MY 2027 through MY 2032 period. More specifically, during model years 2027 through 2032, manufacturers can transfer credits generated from heavy-duty vehicles in MYs 2027-2032 between all heavy-duty vehicle averaging sets in 40 CFR part 1037. Thus, credits can transfer from Light HDV to Medium HDV or Heavy HDV, from Medium HDV to Light HDV or Heavy HDV, and from Heavy HDV to Light HDV or Medium HDV. We note that we are finalizing this interim provision to include credits generated by all heavy-duty vehicles, including those using ICE-based vehicle technologies and not limited to Phase 2 advanced technologies. The broad applicability of this interim provision ensures that we continue to incentivize future vehicle technology that may generate credits against the Phase 3 standards by including it within this interim flexibility.
We also requested comment on the possibility of allowing manufacturers certifying under 40 CFR part 1037 to access credits generated by Class 2b and 3 pickup trucks and vans ^{854} (see 88 FR 26013). One manufacturer of medium-duty vehicles commented in support of that potential allowance, indicating that there is a two-year delay in adapting light-duty vehicle technology for the heavy-duty vehicle market. No other affected manufacturers commented on the issue. After considering comments, we are finalizing provisions allowing manufacturers to access credits generated by model year 2027 through 2032 medium-duty vehicles to certify heavy-duty vehicles, with some limitations as described in the following section III.A.3.ii. Specifically, we are finalizing an interim allowance for one-way credit transfers from averaging sets for medium-duty vehicles certified to 40 CFR part 86, subpart S, to averaging sets for heavy-duty vehicles certified to 40 CFR part 1037. ^{855}
^{854} The recent Light- and Medium-duty final rule now classifies these vehicles as “Medium Duty Vehicles”. See Final Rule: Multi-Pollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles. Docket number EPA-HQ-OAR-2022-0829. Available online: https://www.epa.gov/regulations-emissions-vehicles-and-engines/final-rule-multi-pollutant-emissions-standards-model.
^{855} See 40 CFR 86.1819-14 and 40 CFR 1037.150(z).
As previously explained, Phase 2 credits may be banked for use in the Phase 3 program and manufacturers can continue to apply all available Phase 2 credits within the applicable averaging sets consistent with the existing ABT program. In section III.A.3.ii, we describe some limitations on the use of banked credits under this transitional flexibility.
We have calculated the range of credits that would be eligible for transfer across averaging sets and estimated the relative impact of these newly available credits, and project that use of this flexibility will have a limited impact on the stringency of the Phase 3 standards. ^{856} While we anticipate no significant negative emissions impact, we are finalizing the transitional flexibility as an interim provision, available until model year 2032, because we do not expect a continued need for such a flexibility once the Phase 3 program is fully implemented. We may consider extending the flexibility in a future rule.
^{856} See Brakora, Jessica. Memorandum to docket EPA-HQ-OAR-2022-0985. “Additional Considerations of ABT Provisions for HD GHG Phase 3 Final Rule”. March 2024 for illustrations of how these provisions could operate in tandem.

ii. Limitations of the Transitional Flexibility Allowing Credit Exchange Across Averaging Sets
As noted in section III.A.2, we have taken steps to reduce the potential for Phase 2 advance technology multiplier credits to dilute the effective stringency of the Phase 3 standards by restricting the use of credits generated from multipliers to MYs 2027 through 2029 and phasing out their availability in MY 2030. These multiplier credit restrictions also limit potential impacts from allowing credits to exchange across averaging sets as the restrictions apply within the range of model years over which this transitional flexibility applies. In this section III.A.3.ii, we describe other specific limitations we are adopting for heavy-duty vehicles under 40 CFR part 1037 and heavy-duty vehicles under 40 CFR part 86, subpart S, to further reduce potential impacts of credit exchanges across the applicable averaging sets.
As noted previously, manufacturers may bank credits generated before MY 2027 for use in Phase 3. However, for this transitional flexibility allowing credits to exchange across averaging sets, a manufacturer may only use credits from MY 2026 and earlier vehicles if the credits were generated from vehicles certified as advanced technologies under 40 CFR part 1037. ^{857} We are extending the interim cross-averaging set flexibility to include these credits given that increased utilization of advanced technologies prior to the commencement of the Phase 3 program has the potential to lead to very large reductions in GHG emissions (as we recognized in the Phase 2 rulemaking).
^{857} This allowance includes any credits generated from multipliers under 40 CFR part 1037 that are available for use in MYs 2027-2029.
The final rule includes several limitations on the flexibility to use credits to demonstrate compliance with Phase 3 standards. First, we are not extending the interim flexibility to include credits generated from MY 2026 and earlier vehicles certified to 40 CFR part 86, subpart S. Those earlier vehicles are subject to less stringent standards, which also include the allowance to generate multiplier credits for advanced technologies. Allowing heavy-duty vehicle manufacturers to access credits from these earlier medium-duty vehicles would risk substantially delaying the benefits of the Phase 3 standards. Second, we are limiting the use of credits from 40 CFR part 86, subpart S, to a one-way transfer to 40 CFR part 1037 in recognition that there is greater availability of advanced technologies in pickup trucks and vans and less need to offer a flexibility for vehicles in that market relative to the larger vehicle classes. Third, medium-duty credits may be used for demonstrating compliance only for Light HDV or Medium HDV averaging sets; this is consistent with the request for comment in the proposed rule.
Regarding credits from vehicles certified to 40 CFR part 86, subpart S, we make two additional clarifications. First, any credits transferred under this flexibility would no longer be available for the part 86 ABT program to aid in manufacturers meeting the requirements for medium-duty vehicles. Second, vehicles defined as Medium-duty Passenger Vehicles in 40 CFR part 86, subpart S, are over 8,500 pounds GVWR but are subject to the standards that apply for light trucks and are therefore not eligible to generate credits for this transitional flexibility.
Some commenters expressed concern with the Phase 2 ABT provisions allowing credits from vocational vehicles to be used for tractors in the same weight class. They argued that a manufacturer may use vocational vehicle ZEV credits to offset tractors, thereby limiting adoption of ZEV technology in tractors. Were manufacturers to do so, this would be consistent with the original intent of the ABT program, which is to provide manufacturers the flexibility to identify which vehicle categories to apply new technologies for their specific product line to meet the standards, generally allowing them to meet standards at lower cost. As we describe later in this response, we project a limited impact on emissions from this new (and temporary) flexibility.
We also requested comment on the possibility of allowing a one-way transfer of CO 2 credits from heavy-duty vehicle averaging sets to heavy-duty engine averaging sets (see 88 FR 26013 seeking comment on this potential flexibility). While some commenters expressed general support for this allowance, we expect we would need to apply restrictions on the engine averaging sets where vehicle credits can be applied to limit potential disproportionate adverse emission impact on certain engine categories and FEL caps to avoid backsliding on the engine standards. At this time, we are not finalizing such a flexibility as we believe the complexity would limit the use of this flexibility relative to the other flexibilities we are finalizing in this rule.
Finally, we requested comment on capping the volume of credits that can be transferred across the HD vehicle averaging sets. 88 FR 26013. We are not including a cap on credits transferred between averaging sets in the final interim flexibility. A cap would be justified in cases where vehicles with zero or near-zero tailpipe CO 2 emissions are able to offset a significant number of vehicles in any given averaging set under this flexibility. Our assessment of the effect of those vehicles does not indicate a such an offset. Furthermore, we do not want manufacturers to limit production of technologies with the potential for very large GHG emission reductions in order to be within a cap; in particular we do not want to disincentivize manufacturers from producing additional vehicles with technologies that can achieve very large GHG emissions reductions.

B. Battery Durability Monitoring and Warranty Requirements
This section describes the battery durability monitoring requirements that we are finalizing for BEVs and PHEVs and how warranty applies for several advanced technologies. As we explained in the proposal, BEVs, PHEVs, and FCEVs are playing an increasing role in vehicle manufacturers' compliance strategies to control GHG emissions from HD vehicles. The battery durability and warranty requirements support BEV, PHEV, and FCEV battery durability and thus support achieving the GHG emissions reductions projected by this program. Further, these requirements support the integrity of the GHG emissions credit calculations under the ABT program as these calculations are based on mileage over a vehicle's full useful life. ^{858}
^{858} These two rationales are separate and independent justifications for the requirements.
At the outset we note that, in comments, the Engine Manufacturers Association (EMA) challenged EPA's authority to adopt durability and warranty requirements for these powertrains and their components. Before describing the final rule provisions relating to durability and warranty, we first address this threshold issue. EMA agrees that EPA has authority “to set lower emission standards as advancements in technology allow, even down to zero,” but maintains that authority to establish useful life, durability, and warranty requirements related to such standards differs because these provisions are applicable only to “emission related” components, and BEV and FCEV powertrain components do not emit: “EPA's authority to prescribe useful life requirements under CAA section 202(d) is directly tied to the purpose of extending the time span of emission standards that limit the rate, quantity or concentration of emissions of air pollutants from new motor vehicles . . . . Since ZEV powertrains, including ZEV batteries, do not and cannot emit any air pollutants in any quantity into the ambient air . . ., EPA does not have the authority to set emissions-related useful life requirements for BEV and FCEV powertrains or their various non-emitting components.” With regard to warranty and durability, EMA further states that “CAA section 207(a)(1) makes it clear that the scope of authorized warranties is to ensure that vehicles and engines `are designed, built and equipped so as to conform at the time of sale with the applicable regulations [ i.e., emission standards] established under section . . . [section 202(a)(1)].' ” ^{859}
^{859} The comment did not address durability requirements related to PHEV components (see RTC section 11.1).
EPA's authority to set and enforce durability requirements for emission-related components like batteries is an integral part of its title II authority. Durability requirements ensure that vehicle manufacturers and the vehicles they produce will continue to comply with emissions standards set under 202(a) over the course of those vehicles' useful lives. Such authority arises both out of section 202(a)(1) and 202(d) (relating to a vehicle's useful life) and section 206(a)(1) and 206(b)(1) (relating to certification requirements for compliance).
EPA accounts for durability at certification by requiring, as part of the compliance demonstration for meeting GHG emission standards, a demonstration that emission controls will not deteriorate during useful life, such as for a battery in a hybrid or plug-in hybrid electric vehicle. 40 CFR 1036.241(c) and 1037.241(c). Durability of a ZEV battery is covered by this same provision and principle. EPA has exercised its authority to set emission durability requirements across a variety of emission-related components for decades, including electrified technology like electronic control modules (ECM). See, e.g., 40 CFR 1065.915(d) (permitting ECM signals in place of Portable Emissions Measurement System (PEMS) instrument measurements); 40 CFR 1037.605 (requiring ECM programming where vehicle is speed limited to 45 mph as part of alternate standards certification).
EPA has separate authority to set warranty requirements for batteries in ZEVs and PHEVs. CAA section 207(a)(1). Providing a warranty for emission-related components like batteries precisely accomplishes the congressional purpose of assuring purchasers that vehicles will conform to applicable emission standards at time of sale and in use. Previously, EPA has already set warranty requirements for batteries in hybrids and PHEVs. See 88 FR 4363 (discussing 40 CFR 1036.120). EPA has also previously provided warranties for other electrified technologies, such as ECMs. Indeed, Congress explicitly provided that ECMs are “specified major emissions control component[s]” for warranty purposes per section 207(i)(2).
In general, ZEV batteries, just like batteries in PHEVs and other hybrid vehicles, are emission-related components for two reasons, thus providing EPA authority to set durability and warranty requirements applicable to them. First, they are emission-related by their nature. Durability and warranty requirements for batteries are not like requiring durability and warranty for a vehicle component like a vehicle's “windshield” or “brake pedals” that have no relevance to a vehicle's emissions. Integrity of a battery in a vehicle with these powertrains is vital to the vehicle's emission performance; integrity of its “brake pedals” ” is not. It is wrong to say that a component that allows a vehicle to operate entirely without emissions is not emission-related. See 40 CFR 1037.120(c) (“The emission-related warranty also covers other added emission-related components to the extent they are included in your application for certification, and any other components whose failure would increase a vehicle's CO 2 emissions.”). ^{860}
^{860} The listed components in 40 CFR 1037.120(c)—” tires, automatic tire inflation systems, tire pressure monitoring systems, vehicle speed limiters, idle reduction systems, devices added to improve aerodynamic performance (not including standard components such as hoods or mirrors), fuel cell stacks, and RESS with hybrid systems, battery electric vehicles, and fuel cell electric vehicles “—are evidently all related to vehicular emissions.
Second, for warranty and durability purposes, EPA has consistently considered a component to be “emission related” if it relates to a manufacturer's ability to comply with emissions standards, regardless of the form of those standards. ^{861} For standards to be meaningfully applicable across a vehicle's useful life, EPA's assessment of compliance with such standards necessarily includes an evaluation of the performance of the emissions control systems, which for BEVs, FCEVs, and PHEVs includes the battery system both when the vehicle is new and across its useful life. This is particularly true given the averaging form of standards that EPA uses for GHG emissions (and which EMA continues to support) and which most manufacturers choose for demonstrating compliance. Given the fleet average nature of the standards, the Agency needs to have confidence that the emissions reductions—and thus credits generated—by each BEV, FCEV, and PHEV introduced into the fleet are reflective of the real world. This is particularly important because one of the elements of the credit generating formula is useful life of the vehicle in miles travelled, see 40 CFR 1037.705(a).
^{861} See 88 FR 4296, January 24, 2023.
Ensuring that ZEVs and PHEVs contain durable batteries is thus essential to assuring the integrity of the averaging process: assuring that vehicles will need to perform in fact for the useful life mileage reflected in any credits they may generate. Put another way, durable batteries are a significant factor in vindicating the averaging form of the standard: that the standard is met per vehicle, and on average per fleet, throughout the vehicles' useful life. The battery durability and warranty provisions finalized in this rulemaking allow for greater confidence that the batteries installed by vehicle manufacturers are durable and thus support the standards. Specifically, the durability regulatory provisions for batteries work to assure the integrity of the standards throughout a vehicle's useful life, precisely in accord with the requirements of section 202(a)(1) and 202(d), and batteries are clearly emissions-related components for which warranty requirements may be set under 207(a)(1). EPA therefore disagrees with EMA that it lacks authority to adopt such standards. EMA's assertion that these provisions are unrelated to the emission standards is consequently completely misplaced.
In addition to EPA's general authority to promulgate durability requirements under sections 202 and 206, EPA has additional separate and specific authority to require on-board monitoring systems capable of “accurately identifying for the vehicle's useful life as established under [section 202], emission-related systems deterioration or malfunction.” Section 202(m)(1)(A). ^{862} As we discuss at length in this section, EV batteries are “emission-related systems,” and thus EPA has the authority to set durability monitoring requirements for such systems over the course of a vehicle's useful life.
^{862} Section 202(m)(1)(A) specifically applies to light duty vehicles and light duty trucks, but section 202(m)(1) allows EPA to “promulgate regulations requiring manufacturers to install such onboard diagnostic systems on heavy-duty vehicles and engines,” which provides concurrent authority for the battery monitoring requirements discussed in this section.
EMA suggests that EPA does not have authority to set durability or warranty requirements because ZEV batteries are not emission-related for several reasons. First, EMA argues that because ZEVs do not themselves emit, they and their powertrain components are “not within the scope of any specific emission standards,” and therefore they cannot be subject to “emissions-related” durability and warranty requirements. But EPA does have the authority to set standards for ZEVs as they are part of the “class” of regulated vehicles. In addition, all vehicles, including ZEVs, are subject to an applicable Family Emission Limit (FEL) throughout their useful life to demonstrate compliance with EPA's GHG emissions standards. ^{863}
^{863} See preamble section I.C and Response to Comments section 10.2.1 for further description of EPA's authority to set standards under section 202(a) using an averaging form, and to include ZEVs and PHEVs within a fleet average-based standard. For a more detailed description of the ABT process for HDVs, see section III.A of this preamble and section 10.2.1.d of the RTC document. EPA replies to the commenter's assertions regarding authority to establish standards for a vehicle's useful life as part of that same response to comments.
EMA argues secondly that a component only counts as emission-related if its failure would allow the vehicle to continue operating, but with higher emissions. But nothing in the statute imposes such a limitation. Moreover, while it is true that the failure of a battery would cause the vehicle to stop operating, the same is true for some other vehicle components that have also historically been subject to durability requirements. For instance, EPA has set durability requirements for diesel engines (see 40 CFR 86.1823-08(c)), failure of which could cause the vehicle to stop operating. Similarly, Congress explicitly provided that electronic control modules (ECMs) (described in the statute as “electronic emissions control units”) are “specified major emissions control component[s]” for warranty purposes per section 207(i)(2); failure of ECMs can also cause the vehicle to stop operating, and not necessarily increase the emissions of the vehicle.
EMA is also mistaken in suggesting that there is no way to warrant at time of sale that a vehicle that lacks tailpipe emissions is “designed, built, and equipped so as to conform, at time of sale with applicable regulations under [section 202(a)(1). . . . and . . . for its useful life, as determined by [section 202(d)].” Section 207(a)(1). In fact, automakers warrant at the time of sale that each new vehicle is designed to comply with all applicable emission standards and will be free from defects that may cause noncompliance. They do so with respect to all emission-related components in the manufacturer's application for certification, as noted, and which explicitly include batteries (also known as Rechargeable Energy Storage System (RESS)). See 40 CFR 1037.120(c). These provisions are readily implementable at time of sale and thereafter by reference to the applicable certified FEL and comport entirely with section 207 of the Act.
We intend for the battery durability and warranty requirements finalized in this rule to be entirely separate and severable from the revised emissions standards and other varied components of this rule, and also severable from each other. EPA has considered and adopted battery durability requirements, battery warranty requirements, and the remaining portions of the final rule independently, and each is severable should there be judicial review. If a court were to invalidate any one of these elements of the final rule, we intend the remainder of this action to remain effective, as we have designed the program to function even if one part of the rule is set aside. For example, if a reviewing court were to invalidate the battery durability requirements, we intend the other components of the rule, including the GHG standards, to remain effective.
As we explain previously in this section, for manufacturers who choose to produce BEVs, FCEVs, or PHEVs, durable batteries are important to ensuring that the manufacturer's overall compliance with fleet emissions standards would continue throughout the useful life of the vehicle. The battery durability and warranty provisions EPA is finalizing help assure this outcome. At the same time, we expect that, even if not strictly required, the majority of vehicle manufacturers would still produce vehicles containing durable batteries given their effect on vehicle performance and the competitive nature of the industry. Available data indicates that manufacturers are already providing warranty coverage similar to what is required by the final durability and warranty requirements for ZEVs and PHEVs of various sizes. 864 865 866 867 868 Given the competitive nature of the ZEV and PHEV market, we anticipate that manufacturers will continue to do so, regardless of EPA's final rule.
^{864} United Nations Economic Commission for Europe Informal Working Group on Electric Vehicles and the Environment (UN ECE EVE), “Battery Durability: Review of EVE 34 discussion,” May 19, 2020, p. 12. Available at https://wiki.unece.org/download/attachments/101555222/EVE-35-03e.pdf?api=v2 .
^{865} UK Department of Transport, “Commercial electric vehicle battery warranty analysis,” April 25, 2023. Available at https://wiki.unece.org/download/attachments/192840855/EVE-61-08e%20-%20UK%20warranty%20analysis.pdf?api=v2 .
^{866} CarEdge.com, “The Best Electric Vehicle Battery Warranties in 2024,” January 9, 2024. Accessed on February 16, 2024 at https://caredge.com/guides/ev-battery-warranties .
^{867} California Air Resources Board, “Cars and Light-Trucks are Going Zero—Frequently Asked Questions.” Accessed on February 16, 2024 at https://ww2.arb.ca.gov/resources/documents/cars-and-light-trucks-are-going-zero-frequently-asked-questions .
^{868} Forbes, “By The Numbers: Comparing Electric Car Warranties,” October 31, 2022. Accessed on February 16, 2024 at https://www.forbes.com/sites/jimgorzelany/2022/10/31/by-the-numbers-comparing-electric-car-warranties/?sh=2ed7a5243fd7 .
Moreover generally, the battery durability and warranty requirements resemble many other compliance provisions that facilitate manufacturers' ability to comply with the standards, as well as EPA's ability to assure and enforce that compliance. Were a reviewing court to invalidate any compliance provision, that would preclude the agency from applying that particular provision to assure compliance, but it would not mean that the entire regulatory framework should fall with it. Specifically, were a reviewing court to invalidate the final durability and warranty requirements, EPA would continue to have numerous tools at its disposal to assure and enforce compliance of the final standards, including the entire panoply of certification requirements, in-use testing requirements, administrative and judicial enforcement, and so forth, so as to achieve significant emissions reductions. Therefore, EPA is adopting and is capable of implementing final standards entirely separate from the battery durability and warranty requirements. The contrapositive is also true: EPA is adopting and capable of implementing the battery durability and warranty requirements entirely separate from the standards. For example, even without the final standards, we believe the enhanced battery durability and warranty requirements would serve to facilitate compliance with the existing GHG standards.

1. BEV and PHEV Durability Monitoring Requirements
EPA's HD vehicle GHG emission standards apply for the regulatory useful life of the HD vehicle, consistent with CAA section 202(a)(1) (“Such standards shall be applicable to such vehicles and engines for their useful life”). Section 202(d) commands EPA to prescribe regulations establishing useful life for purposes of section 202(a)(1) standards. Accordingly, EPA has historically required manufacturers to demonstrate the durability of their emission control systems on vehicles, implementing these authorities as well as EPA's authority to prescribe “appropriate testing” for purposes of vehicle certification under section 206(a). See, e.g., 40 CFR 1037.205(l) (requiring applicants for certification to identify the vehicle family's deterioration factors and how the manufacturer derived those factors) and 1037.241(b) ^{869} (EPA may require engineering analysis showing that performance of emission controls will not deteriorate in use as part of certification process). Without durability demonstration requirements, EPA would not be able to assess whether vehicles originally manufactured in compliance with relevant emissions standards (including the subfamily specific Family Emission Limit (FEL) to which each vehicle is certified, for manufacturers complying using the ABT compliance alternative; see section III.A of this preamble and RTC chapter 10.2.1, section d) would remain compliant over the course of their useful life. Recognizing that BEV, PHEV, and FCEV are playing an increasing role in manufacturers' compliance strategies, and that emission credit calculations are based in part on mileage over a vehicle's useful life, the same logic applies to BEV, PHEV, and FCEV battery and powertrain durability. Under 40 CFR part 1037, subpart H, credits are calculated by determining the FEL each vehicle subfamily achieves beyond the standard and multiplying that by the production volume and a useful life mileage attributed to each vehicle subfamily. ^{870} Having a useful life mileage value for each vehicle subfamily is integral to calculating the credits attributable to that vehicle, whether those credits are used for calculating compliance through averaging, or for banking or trading.
^{869} In this final action we are moving 40 CFR 1037.241(c) to 40 CFR 1037.241(b).
^{870} More specifically, vehicle families and subfamilies are certified to the applicable standard and FEL. Conditions are placed on the certificates to ensure compliance with the fleet average after the year's production is completed. The production-weighted sum of the families and their FELs within each averaging set must be equal to or less than the applicable emission standard. The useful life values for the HD vehicle standards are located in 40 CFR 1037.105(e) and 1037.106(e). 40 CFR 1037.705(b) specifies that useful life of the vehicle, in miles, is part of the formula used to determine credit generation.
Because vehicle manufacturers can use such emissions control technologies to comply with EPA standards, we proposed and are finalizing requirements to ensure that such vehicles certifying to EPA standards are durable and capable of providing the anticipated emissions reductions to which they are certified. Specifically, we are finalizing a requirement that manufacturers provide a customer-facing battery state-of-health (SOH) monitor for all heavy-duty BEVs and PHEVs. The new 40 CFR 1037.115(f) requires manufacturers to install a customer-accessible SOH monitor which estimates, monitors, and communicates the vehicle's state of certified energy (SOCE) as it is defined in 40 CFR 1037.115(f). Specifically, manufacturers would implement onboard algorithms to estimate the current state of health of the battery, in terms of the state of its usable battery energy (UBE) expressed as a percentage of the original UBE when the vehicle was new.
EPA may perform in-use testing “of any vehicle subject to the standards.” 40 CFR 1037.401(a). This in-use testing is compared to the FEL to which the vehicle is certified. See 40 CFR 1037.241(a)(2) (“Note that the FEL is considered to be the applicable emissions standard for an individual configuration”). If manufacturers are complying with the standard by averaging credits, emission credits would be calculated assuming the battery sufficiently maintains its performance for the full useful life of the vehicle. Without battery-specific durability requirements applicable to such vehicles, we are mindful that there would not be a guarantee that a manufacturer's overall compliance with emission standards would continue throughout that useful life. We are finalizing new battery durability monitoring to apply for MY 2030 and later HD BEVs and PHEVs as a key step in assuring the emission reductions projected for this program will be achieved in use.
As implemented by light-duty vehicle manufacturers in current BEVs and PHEVs, lithium-ion battery technology has been shown to be effective and durable for use and we expect that this will also be the case for heavy-duty vehicles. ^{871} We recognize that the energy capacity of a battery will naturally degrade to some degree with time and usage, which can result in a reduction in driving range as the vehicle ages. See RIA Chapter 2.4.1.1.3. Excessive battery degradation in a PHEV could lead to higher fuel consumption and increased criteria pollutant tailpipe emissions, while a degraded battery in a BEV could impact its ability to deliver the lifetime mileage expected. This effectively becomes an issue of durability if it reduces the utility of the vehicle or its useful life, and EPA will closely track developments in this area and propose modifications as they become necessary.
^{871} See RIA Chapter 2.4.1.1.4, for how we accounted for battery deterioration in our analysis.
Vehicle and engine manufacturers are currently required to account for potential battery degradation that could result in an increase in CO 2 and criteria pollutant emissions when certifying hybrid or plug-in hybrid vehicles (see, e.g., existing 40 CFR 1037.241(b) and 1036.241(c)). ^{872} In addition, engine manufacturers are required to demonstrate compliance with criteria pollutant standards using fully aged emission control components that represent expected degradation during useful life (see, e.g., 40 CFR 1036.235(a)(2) and 1036.240). We considered these well-established approaches, as well as comments received, for the final battery durability monitoring requirements for HD BEVs and PHEVs.
^{872} We are removing current 40 CFR 1037.241(b) and redesignating 40 CFR 1037.241(c) to 40 CFR 1037.241(b).
The importance of battery durability in the context of zero- and near-zero emission vehicles, such as BEVs and PHEVs, has been cited by several authorities in recent years. In their 2021 Phase 3 report, ^{873} the National Academies of Science (NAS) identified battery durability as an important issue with the rise of electrification. ^{874} Several rulemaking bodies have also recognized the importance of battery durability in a world with rapidly increasing numbers of zero-emission vehicles. In 2015 the United Nations Economic Commission for Europe (UN ECE) began studying the need for a Global Technical Regulation (GTR) governing battery durability. In April 2022 it published United Nations Global Technical Regulation No. 22, “In- Vehicle Battery Durability for Electrified Vehicles,” ^{875} or GTR No. 22, which provides a regulatory structure for contracting parties to set standards for battery durability in BEVs and PHEVs. ^{876} The European Commission and other contracting parties have also recognized the importance of durability provisions and are working to adopt the GTR standards in their local regulatory structures.
^{873} National Academies of Sciences, Engineering, and Medicine 2021. “Assessment of Technologies for Improving Light-Duty Vehicle Fuel Economy 2025-2035”. Washington, DC: The National Academies Press. https://doi.org/10.17226/26092 .
^{874} Among the findings outlined in that report, NAS noted that: “battery capacity degradation is considered a barrier for market penetration of BEVs,” (p. 5-114), and that “[knowledge of] real-world battery lifetime could have implications on R&D priorities, warranty provision, consumer confidence and acceptance, and role of electrification in fuel economy policy.” (p. 5-115). NAS also noted that “life prediction guides battery sizing, warranty, and resale value [and repurposing and recycling]” (p. 5-115), and discussed at length the complexities of SOH estimation, life-cycle prediction, and testing for battery degradation (p. 5-113 to 5-115).
^{875} United Nations Economic Commission for Europe, Addendum 22: United Nations Global Technical Regulation No. 22, United Nations Global Technical Regulation on In-vehicle Battery Durability for Electrified Vehicles, April 14, 2022. Available at: https://unece.org/sites/default/files/2022-04/ECE_TRANS_180a22e.pdf .
^{876} EPA representatives chaired the informal working group that developed this GTR and worked closely with global regulatory agencies and industry partners to complete its development in a form that could be adopted in various regions of the world, including potentially the United States.
EPA concurs with the emerging consensus that battery durability is an important issue. The ability of a zero-emission vehicle to achieve the expected emission reductions during its lifetime depends in part on the ability of the battery to maintain sufficient driving range, capacity, power, and general operability for a period of use comparable to that expected of a conventional vehicle. Durable and reliable electrified vehicles are therefore critical to ensuring that projected emissions reductions are achieved by this program. The durability monitoring regulations will require manufacturers of BEVs and PHEVs to develop and implement an on-board state-of-certified-energy (SOCE) monitor that can be read by the vehicle user. These requirements are similar to the battery durability monitor regulation framework developed by the UN ECE and adopted in 2022 as GTR No. 22. We did not propose and are not finalizing durability monitoring requirements for FCEV manufacturers at this time because the technology is currently still emerging in heavy-duty vehicle applications, and we are still learning what the appropriate metric might be for quantifying FCEV performance.
The Administrator has determined that GTR No. 22, which was developed with extensive input from EPA, provides an appropriate framework and set of requirements for ensuring battery durability and should be integrated into the context of this rulemaking for this purpose. The requirements and general framework of the battery durability program under this rule are therefore largely identical to those outlined in GTR No. 22 and broadly parallel the GTR in terms of the hardware, monitoring and compliance requirements, the associated statistical methods and metrics that apply to determination of compliance, and criteria for establishing battery durability and monitor families.
For BEV, we requested comment as to the desirability of EPA defining a standard procedure for determining UBE. 88 FR 26015. We received comments both supporting and objecting to EPA defining such a standard test procedure. We are not finalizing a specific procedure at this time due to the range of HD BEV architectures and the limited test facilities for conducting powertrain testing of BEV with e-axles. In addition, we are not requiring pack level testing for the determination of UBE, as allowing for vehicle level testing would enable easier verification of UBE with in-use vehicles. The final rule instead requires manufacturers to develop and get EPA approval of their own test procedure for determining UBE that meets the criteria that is described in this section. With the SOCE being a relative measure of battery health and not absolute UBE, we believe that leaving the test procedure up to the manufacturer will still provide a meaningful measure of the health of the battery. We also believe that requiring the SOH to be customer-accessible will provide assurance that the SOH monitor is relatively accurate.
For PHEV, manufacturers will use the existing powertrain test procedures defined in 40 CFR 1036.545 to determine UBE, or a manufacturer-specific alternative test procedure. ^{877} The regulatory powertrain test procedures require that PHEVs be tested in charge depleting and charge sustaining modes using a range of vehicle configurations. Under the final procedure, PHEV manufacturers would select the most representative vehicle configuration to determine UBE for the powertrain family. In addition to this test procedure, the final rule allows manufacturers to develop and get EPA approval of their own test procedures for determining UBE for PHEV. We are finalizing this option since some manufacturers may use the same battery pack for their BEV and PHEV products, and using the same procedure will reduce testing burden and variability in the determination of UBE. ^{878}
^{877} We are moving the existing powertrain procedure from its current location in 40 CFR 1037.550 to the heavy-duty highway engine provisions as a new 40 CFR 1036.545. See section III.C.3 of this preamble for more information.
^{878} This flexibility is in response to a comment that we received from Cummins, that is summarized in RTC section 11.
Along with these provisions allowing manufacturers to develop their own test procedure for determining UBE for BEV or for PHEV, we are finalizing specific criteria for such a test procedure to ensure it produces accurate results that are representative of in-use operation. These provisions bound the parameters of each manufacturer-specific test procedure. The first requirement is that the test procedure must measure UBE by discharging the battery at a constant power that is representative of the vehicle cruising on the highway. For many HD vehicles the power to cruise on the highway would result in a C-rate between C/6 and C/2. ^{879} The second requirement is that the test is complete when the battery is not able to maintain the target power. The third requirement is that the battery energy measurements must meet the requirements defined in 40 CFR 1036.545(a)(10). The final requirement is that the SOH monitor must be able to determine the UBE within +/− 5 percent of the result of the test procedure. The finalized accuracy requirement for the SOH monitor is supported by GTR No. 22 and by comments to the proposal.
^{879} C-rate is a measure of the rate at which a battery is discharged or charged relative to its maximum capacity and has units of inverse hours. At a 2C discharge rate, it would take 0.5 hours to fully discharge a battery.
We requested comment on finalizing a state-of-certified-range (SOCR) monitor. 88 FR 26015. In response, we received one comment supporting EPA finalizing an SOCR monitor and many comments in opposition. As stated by some commenters, the range of a HD BEV is highly dependent on the duty cycle and payload of the vehicle. Since an SOCR monitor is not likely to provide useful information to the driver, we are not finalizing a requirement for an SOCR monitor at this time. A complete list of the comments and our response can be found in section 11 of the response to comments document.
We believe that the new requirement to have an SOH monitor, buttressed by the manufacturer-specific test for determining UBE, will assure that these vehicles meet standards throughout their useful life, per sections 202(a)(1) and 202(d) of the CAA. In addition, the SOH monitor should provide consumers with assurance of durability, and an ability to monitor it.
In addition, under the EPA GHG program, BEV and PHEV generate credits that can be traded among manufacturers and used to offset deficits generated by vehicles using other technologies that do not themselves meet the standards, as well as used to offset debits generated by the manufacturer's own fleet ( i.e., vehicle families across each averaging set). Part of the credit-generating calculation is the useful life of the vehicle, as specified in 40 CFR 1037.105(e) and 1037.106(e). See 40 CFR 1037.705(b) (formula). If credits generated by vehicles using these powertrains are used to offset debits created by other vehicles on an equivalent basis, it is important that the vehicles achieve this specified useful life mileage—mileage equivalent to what is expected for an ICE vehicle. For BEV and PHEV, this depends, in substantial part, on the life of the battery. The durability provisions in this final rule, plus the warranty provisions described in the following preamble section, provide additional assurance that the battery will perform over this useful life mileage. Again, the durability provisions in this rule help provide a safeguard.

2. Battery and Fuel Cell Electric Vehicle Component Warranty
Recognizing that BEV, PHEV, and FCEV are playing an increasing role in manufacturers' compliance strategies we proposed new warranty requirements for BEV and FCEV batteries and associated emission-related components ( e.g., fuel-cell stack, electric motors, and inverters) and proposed to clarify how existing warranty requirements apply for PHEVs. In response to this proposal, we received many comments supporting the proposed warranty requirements. We also received comments encouraging EPA to define which components are covered and what failures are covered under the warranty. A complete list of the comments and our responses is included in section 11.2 of the response to comments document.
In consideration of the comments and that BEV, PHEV, and FCEV are playing an increasing role in manufacturers' compliance strategies, we are identifying the high-voltage battery, and the powertrain components that depend on it (including fuel-cell stack, electric motors, and inverters), as “emission-related components” in HD vehicles under 40 CFR 1037.120(c) (components covered by warranty), as they play a critical role in reducing the vehicles' emissions and allowing BEV and FCEV to have zero tailpipe emissions in-use, see section I.B of this preamble. As EMA notes in its comments, “[t]raditional emission-related warranty requirements serve the useful purpose of motivating a trucking company to keep the emissions control systems functioning properly throughout each vehicle's useful life.”
As such, we are finalizing new warranty requirements for MY 2027 and later BEV and FCEV batteries and associated emission-related electric powertrain components ( e.g., fuel-cell stack, electric motors, and inverters) under the authority of CAA section 207(a)(1) and clarifying how existing warranty requirements apply for PHEVs. ^{880} The battery warranty requirements we describe in this section build on existing emissions warranty provisions for other emission-related components by establishing specific new requirements tailored to the emission control-related role of the high-voltage battery and fuel-cell stack in durability and performance of BEVs and FCEV.
^{880} See section I.D. of this preamble and in this section III.B for further discussion of EPA's authority under CAA section 207(a)(1).
EPA believes that this practice of ensuring a minimum level of warranty protection for emissions-related components on ICE vehicles, including hybrid vehicles, should be extended to the high-voltage battery and other electric powertrain components of BEVs and FCEVs for multiple reasons. Recognizing that BEVs and FCEVs are playing an increasing role in manufacturers' compliance strategies, the high-voltage battery and the powertrain components that depend on it are emission control devices critical to the operation and emission performance of BEVs and FCEVs, as they play a critical role in allowing BEVs and FCEVs to operate with zero tailpipe emissions. Further, EPA anticipates that compliance with the program is likely to be achieved with larger penetrations of BEVs and FCEVs than under the previous program. Although the projected emissions reductions are based on a spectrum of control technologies, in light of the cost-effective reductions achieved, especially by BEV and FCEVs s, EPA anticipates most if not all manufacturers will include credits generated by BEVs and FCEVs as part of their compliance strategies, even if those credits are obtained from other manufacturers; thus this is a particular concern given that the calculation of credits for averaging (as well as banking and trading) depend on the battery and emission performance being maintained for the full useful life of the vehicle. Additionally, warranty provisions are a strong complement to the battery durability requirements described in the previous section. We believe that a component under warranty is more likely to be properly maintained and repaired or replaced if it fails, which would help ensure that credits granted for BEV and FCEVs sales represent real emission reductions achieved over the life of the vehicle.
We did not propose new battery warranty requirements for PHEVs. As “hybrid system components” they already have warranty requirements under the existing regulations in 40 CFR parts 1036 and 1037. In the HD2027 low NO X rule, we finalized a provision stating that when a manufacturer's certified configuration includes hybrid system components ( e.g., batteries, electric motors, and inverters), those components are considered emission-related components, which would be covered under the warranty requirements (see, e.g., 88 FR 4363, January 24, 2023, and 40 CFR 1036.120).
We are revising 40 CFR 1036.120(c) to clarify that the warranty requirements of 40 CFR part 1036 apply to hybrid system components for any hybrid manufacturers certifying to the part 1036 engine standards. In 40 CFR 1037.120(c), we are also finalizing our proposal to remove the sentence stating that the emission-related warranty does not need to cover components whose failure would not increase a vehicle's emissions of any regulated pollutant, and replacing this sentence with “and any other components whose failure would increase a vehicle's CO 2 emissions” to the existing sentence that states the emission-related warranty covers components included in the application for certification.
In response to the comments stating that EPA should define which components are covered and what failures are covered under the emissions warranty, we have made the following changes. First, we are clarifying that the RESS (also known as the high-voltage battery) and associated electric powertrain components in the vehicle's application for certification are covered under the emission-related warranty. Second, we are finalizing text in 40 CFR 1037.205(b) stating that “For any vehicle using RESS (such as hybrid vehicles, FCEV, and BEV), describe in detail all components needed to charge the system, store energy, and transmit power to move the vehicle.” ^{881} By making these two changes we believe that we have defined which components are covered, while leaving the requirements general enough to cover technologies that are not currently in the market. As for the comments on defining what failures are covered under the emissions warranty, we are not finalizing any changes, as the current warranty requirements already provide the framework for manufacturers to define the specific failures that are covered under warranty, as they have done for many years. We also received comment that only the high-voltage battery and fuel cell should be covered by the emissions warranty. Although we agree that the high-voltage battery and fuel cell should be covered, these are not the only components that enable ZEV to have a zero CO 2 grams per mile from the tailpipe. These reductions are also dependent on the components that allow charging the system, storing energy, and transmitting power to move the vehicle, and as such we are requiring manufacturers to include these components in the vehicle's application for certification and cover them with the emissions warranty. We are finalizing as proposed that those components be covered by the existing regulations' emissions warranty periods of 5 years or 50,000 miles for Light HDV and 5 years or 100,000 miles for Medium HDV and Heavy HDV (see revisions to 40 CFR 1037.120).
^{881} Rechargeable Energy Storage System (RESS) means engine or equipment components that store recovered energy for later use to propel the vehicle or accomplish a different primary function. Examples of RESS include the battery system or a hydraulic accumulator in a hybrid vehicle.
The warranty provisions are a strong complement to the proposed battery durability monitoring requirements. As explained, EPA anticipates that most if not all manufacturers would include the averaging of credits generated by BEVs and FCEVs as part of their compliance strategies for the final standards. Thus, as noted in the previous section on durability, emission credits would be calculated assuming the battery sufficiently maintains its performance for the full useful life of the vehicle. 40 CFR 1037.705(b) (formula). We believe a component under warranty is more likely to be properly maintained and repaired or replaced if it fails, which could help ensure that credits granted for BEV and FCEV production volumes represent real emission reductions achieved over the life of the vehicle. Finally, we expect many manufacturers will provide warranties beyond the existing 40 CFR 1037.120 levels for the BEV and FCEV they produce, and the new requirements to require those warranty periods and document them in the owner's manual would provide additional assurance for owners that all BEV and FCEV have the same minimum warranty period. ^{882}
^{882} For example, the Freightliner eCascadia includes a powertrain warranty of 5 year/150,000 or 300,000 miles (depending on battery pack size). Available at: https://dtnacontent-dtna.prd.freightliner.com/content/dam/enterprise/documents/DDCTEC%2016046%20-%20eCascadia%20Spec%20Sheet_6.0.pdf (last accessed October 30, 2023). In addition, Type C BEV school bus battery warranty range five to fifteen years according to https://www.nyapt.org/resources/Documents/WRI_ESB-Buyers-Guide_US-Market_2022.pdf . Lastly, the Freightliner electric walk-in van includes an eight-year battery warranty according to https://www.electricwalkinvan.com/wp-content/uploads/2022/05/MT50e-specifications-2022.pdf .

C. Additional Revisions to the Regulations
In this subsection, we discuss revisions to 40 CFR parts 1036, 1037, and 1065. After consideration of comments, ^{883} many of the updates described in this section I.C.5 we are finalizing as proposed, however in some cases we have updated the final revisions from those proposed and are finalizing additional clarifications and editorial corrections. We intend for the changes to testing and other certification procedures finalized in this rule to be entirely separate from the Phase 3 emissions standards and other varied components of this rule, and severable from each other. These are changes EPA is making related to implementation of standards generally ( i.e., independent of the numeric stringency of the standards set in this final rule). EPA has considered and adopted changes to testing and other certification procedures and the remaining portions of the final rule independently, and each is severable should there be judicial review. If a court were to invalidate any one of these elements of the final rule, the remainder of this action remains fully operable, as we have designed the program to function even if one part of the rule is set aside.
^{883} EPA participates in on-going Emissions Measurement & Testing Committee meetings and notes that certain clarifying and editorial revisions included in the final rule described in this section III.C were supported by the engine and vehicle manufacturers and other industry stakeholders participating in those meetings. See memo to docket EPA-HQ-OAR-2022-0985: Laroo, Christopher. “Test Procedure Meetings with the Engine Manufacturers Association”.

1. Updates for Cross-Sector Issues
This section includes updates that make the same or similar changes in related portions of the CFR or across multiple standard-setting parts for individual industry sectors.

i. LLC Cycle Smoothing and Accessory Load
We finalized a new LLC duty-cycle in the HD2027 rule that included a test procedure for smoothing the nonidle nonmotoring points immediately before and after idle segments within the duty-cycle. ^{884} It was brought to our attention that the smoothing procedure in 40 CFR 1036.514(c)(3) allows smoothing based on the idle accessory torque but says nothing about how to address the contribution of curb idle transmission torque (CITT), while 40 CFR 1065.610(d)(3)(v) through (viii) requires smoothing based on CITT and says nothing about how to address idle accessory torque. This could create confusion and difficulties for common cases where CITT is required in addition to the 40 CFR 1036.514 idle accessory torques. 40 CFR 1036.514(c)(3), as currently written, would only apply if the transmission was in neutral, because it only allows you to account for the accessory load and not CITT, which was not EPA's intent. To illustrate the concern, for example, a MHD engine could have an LLC idle accessory load of 23.5 foot-pounds, which is 19 percent of a typical automatic transmission CITT of 124 foot-pounds. To resolve this potential issue, we are removing the smoothing instructions in 40 CFR 1036.514 and incorporating them into 40 CFR 1065.610.
^{884} 88 FR 4296 (January 24, 2023).
The original intent of the 40 CFR 1065.610 duty-cycle generation procedure was to avoid discontinuities in the reference torque values. It was written with the assumption that idle load in neutral was zero, meaning the vehicle or machine idle accessory load was zero. When we introduced the required LLC idle accessory load in 40 CFR 1036.514, we failed to realize that amendments would be needed to 40 CFR 1065.610(d)(3) to clarify how to handle the accessory load in the denormalization process. The engine mapping section 40 CFR 1065.510 is another area of concern as it does not address the possibility of droop in the idle governor, which would result in different idle speeds when the transmission is in drive versus neutral. This results in an additional complication as the required idle accessory torque will be different in drive versus neutral to keep the accessory power at the level specified in table 1 to 40 CFR 1036.514(c)(4).
Paragraph (d)(4) of 40 CFR 1065.610 is a related paragraph that allows a different deviation for an optional declared minimum torque that applies to variable- and constant-speed engines and both idle and nonidle nonmotoring points in the duty-cycle. Its scope of application is wider than 40 CFR 1065.610(d)(3). Paragraph (d)(4) of 40 CFR 1065.610 applies to all nonidle nonmotoring points in the duty-cycle, not just the ones immediately preceding or following an idle segment and using it instead of paragraph (d)(3) would not get the intended constant idle accessory power loads or the intended smoothing.
There is also an existing historical conflict between 40 CFR 1065.510(f)(4) and 1065.610(d)(4). Paragraph (f)(4) of 40 CFR 1065.510 requires that manufacturers declare non-zero idle, or minimum torques, but 40 CFR 1065.610(d)(4), permissible deviations, make their use within the duty-cycle generation optional. This results in an inconsistency between the two sections as 40 CFR 1065.510(f)(4) requires these parameters to be declared, but 40 CFR 1065.610(d)(4) does not require them to be used.
Additionally, there is a historical conflict in 40 CFR 1065.610(d)(3)(v). This paragraph, as written, includes zero percent speed and, if the paragraph is executed in the order listed, it would include idle points that were changed to neutral in the previous step for neutral while stationary transmissions. This conflict would change the torque values of those idle-in-neutral points back to the warm-idle-in-drive torque and the speed would be left unaltered at the idle-in-neutral speed. This was clearly not the intent of this paragraph, yet we note that this conflict existed already for regulations that applied to model year 1990 engines.
The smoothing of idle points also raises the need for smoothing of the few occurances of non-idle points in the duty cycle where the vehicle may be moving, the torque converter may not be stalled, and the warm-idle-in-drive torque may not be appropriate. This would result in the smoothing of consecutive points around nonidle nonmotoring points with normalized speed at or below zero percent and reference torque from zero to the warm-idle-in-drive torque value where the reference torque is set to the warm-idle-in-drive torque value.
To address these concerns, we are revising 40 CFR 1065.510, 1065.512, and 1065.610. Note, other changes to these subsections not specifically mentioned here are edits to fix citations to relocated or new paragraphs and to improve the clarity of the test procedures. The changes to 40 CFR 1065.610 include basing the smoothing of points preceding an idle segment and following an idle segment on the warm-idle-in-drive torque value (sum of CITT and idle accessory torque). Exceptions to this are for manual transmissions and for the first 24 seconds of initial idle segments for automatic transmissions. Here the warm-idle-in-neutral torque value (idle accessory torque) is used. We are including manual transmissions in the required deviations for reference torque determination for variable-speed engines in 40 CFR 1065.610(d)(3) for completeness. The amendments to 40 CFR 1065.610(d)(3) include the option to skip these deviations for a manual transmission where optional declared idle torque and the optional declared power are not declared (idle torque is zero). This provides labs that have not yet implemented these required deviations the option to not implement them if they only need to run tests with manual transmissions with zero idle torque. We also add manual transmissions to 40 CFR 1065.512(b)(2) where these required deviations in 40 CFR 1065.610 are cited.
We are also revising 40 CFR 1065.510(b) and (f) to address the effect of droop in the idle governor and how to determine idle speed when idle torque is a function of idle speed (where a component is specified as power or CITT is specified as a function of speed and the idle speeds need to be determined for each setpoint of the idle governor). We are also adding an option to declare the warm idle speed(s) equal to the idle speed setpoint for electronically governed variable-speed engines with an isochronous low-speed governor. Recent updates to the mapping test procedure in 40 CFR 1065.510 assumed that one could declare the warm idle speed(s) equal to the idle speed setpoint for electronically governed variable-speed engines when running the map at the minimum user-adjustable idle speed setpoint and using the map for any test. ^{885} We are finalizing the proposed changes to make it clear that this option is allowed, which would help simplify the mapping process.
^{885} 88 FR 4296 (January 24, 2023).
To resolve the conflict between 40 CFR 1065.510(f)(4) and 1065.610(d)(4), we are moving the requirement to declare torques to 40 CFR 1065.510(f)(5), which would clarify it is optional and consistent with 40 CFR 1065.610(d)(4).
To resolve the conflict in 40 CFR 1065.610(c)(3)(v), which we are redesignating as 40 CFR 1065.610(c)(3)(vii), we are revising the applicability of the paragraph from “all points” to limit it to apply to “all nonidle nonmotoring points.” To address the smoothing of consecutive nonidle nonmotoring points that immediately follow and precede any smoothed idle points we are changing the reference torques to the warm-idle-in-drive torque value by adding a new 40 CFR 1065.610(c)(3)(xi).
We are also reorganizing 40 CFR 1036.514 and revising the section to clarify the process for cycle denormalization of speed and torque where accessory load is included and to add more specific transmission shift points for greater than 200 seconds idle segments for LLC engine and hybrid powertrain testing. Shifting the transmission to neutral during very long idle segments is more representative of in-use operation than leaving it in drive, so we proposed and are finalizing more specific shift points instead of a range to reduce lab-to-lab variability. The new shift points include setting the reference speed and torque values to the warm-idle-in-drive values for the first three seconds and the last three seconds of the idle segment for an engine test, keeping the transmission in drive for the first 3 seconds of the idle segment, shifting the transmission from drive to park or neutral immediately after the third second in the idle segment, and shifting the transmission into drive again three seconds before the end of the idle segment.

ii. Calculating Greenhouse Gas Emission Rates
We are revising 40 CFR 1036.550(b)(2) and 1054.501(b)(7) to clarify that when determining the test fuel's carbon mass fraction, W C, the fuel properties that must be measured are α (hydrogen) and b (oxygen). These paragraphs, as currently written, imply that you cannot use the default fuel properties in 40 CFR 1065.655 for a , b , g (sulfur), and d (nitrogen). The fuel property determination in 40 CFR 1065.655(e) makes it clear that if manufacturers measure fuel properties and the default g and d values for their fuel type are zero in Table 2 to 40 CFR 1065.655, manufacturers do not need to measure those properties. The sulfur ( g ) and nitrogen ( d ) content of these highly refined gasoline and diesel fuels are not enough to affect the W C determination and the original intent was to not require their measurement. We expect the revisions to reduce confusion on the fuel properties requirement. We are also adding a reference to 40 CFR 1065.655(e) in 40 CFR 1036.550(b)(2) and 1054.501(b)(7) so that they point to the default fuel property table whose number had been previously changed and we did not make the corresponding update in 40 CFR 1036.550(b)(2) and 1054.501(b)(7).

iii. ABT Reporting
We are finalizing a proposed allowance for manufacturers to correct previously submitted vehicle and engine GHG ABT reports, where a mathematical or other error in the GEM-based or fleet calculations used for compliance was discovered after the September 30 deadline for submitting the final report. In the Phase 1 program, EPA chose the deadline for submitting a final GHG ABT report to coincide with existing criteria pollutant report requirements that manufacturers follow for heavy-duty engines. ^{886} The deadline was based on our interest in manufacturers maintaining good quality assurance/quality control (QA/QC) processes in generating ABT reports. We continue to believe that aligning the ABT report deadlines for criteria and GHG pollutants can provide consistency within a manufacturer's certification and compliance processes, but further consideration of the inherent differences and complexities in how credits are calculated and accounted for in the two programs led us to consider a time window beyond 270 days for allowing corrections to the GHG report. Certifying an engine or vehicle fleet with attribute-based features (Phase 1) or GEM (Phase 2) involves a greater risk of error compared to EPA's engine or vehicle test-based programs for criteria pollutants, where direct measurement of criteria pollutant emissions at time of certification is well established. Whether an indirect, physics-based model for quantifying GHG emissions such as GEM, or a unique technology-, attribute-, or engine production volume-based credit accounting system, unintentional errors, if not detected prior to submitting the final GHG ABT report and not realized until the accounting process for the following model year was initiated, could negatively affect a manufacturer's credit balance. For example, the loss of these credits could result in a manufacturer purchasing credits or making unplanned investments in additional technologies to make up for the credits lost due to the report error.
^{886} See the HD GHG Phase 1 rule (76 FR 57284, September 15, 2011).
Under the revisions to 40 CFR 1036.730(f) and 1037.730(f), EPA would consider requests to correct previously submitted MY 2021 or later ABT reports only when notified of the error within 24 months from the September 30 final report deadline. For requests to correct reports for MY 2020 or earlier, we have set an interim deadline of October 1, 2024 (see new 40 CFR 1036.150(aa) and 1037.150(y)). We believe that corrections to ABT reports, where justified, will have no impact on emissions compliance as the actual performance of a manufacturer's fleet was better than what was reported in error, and correcting the report simply adjusts the credit balance for the model year in question to the appropriate value, such that those credits can then be used in future model years.
This narrowly focused allowance for correcting accounting, typographical, or GEM-based errors after a manufacturer submits the 270-day final report (see revisions in 40 CFR 1037.730) is intended to address the disproportionate and adverse financial impact of an unintentional error in the complex modeling and accounting processes that manufacturers use to determine compliance and credit balances for a given model year. We proposed and are finalizing a 10 percent discount to these credit corrections to the final report, which will reduce the value of the credits that are restored upon approval of the request. The 10 percent discount is intended to balance the goal of encouraging accuracy in ABT reports and use of robust QA/QC processes against the considerations for allowing manufacturers the ability to correct unforeseen errors.

iv. Migration of 40 CFR 1037.550 to 40 CFR 1036.545
We are migrating the powertrain test procedure from the heavy-duty motor vehicle regulations in 40 CFR part 1037 to the heavy-duty highway engine regulations in 40 CFR part 1036. Specifically, we are migrating the procedure from 40 CFR 1037.550 to 40 CFR 1036.545. Over the course of the development of this test procedure, its use expanded to include certification of engines to the criteria pollutant standards in 40 CFR part 1036 (including test procedures in 40 CFR 1036.510, 1036.512, and 1036.514) and the procedure can be used in place of the engine GHG testing procedures (40 CFR 1036.535 and 1036.540) for hybrid engines and hybrid powertrains. We are migrating the test procedure to 40 CFR 1036.545 as-is, with the following exceptions:
We are adding a new figure that provides an overview of the steps involved in carrying out testing under this section.
We are clarifying the use of the GEM HIL model contained within GEM Phase 2, Version 4.0 if it is used to simulate a vehicle's automatic transmission. If the engine is intended for vehicles with automatic transmissions, the manufacturer must use the cycle configuration file in GEM to change the transmission state (either in-gear or idle) as a function of time as defined by the duty cycles in 40 CFR part 1036.
We are clarifying the recommended means to control and apply the electrical accessory loads for powertrains tested over the LLC duty cycle.
We are clarifying that if the test setup has multiple locations where torque is measured and speed is controlled, the manufacturer is required to sum the measured torque and validate that the speed control meets the requirements defined in 40 CFR 1036.545(m). Positive cycle work, W [cycle], would then be determined by integrating the sum of the power measured at each location in 40 CFR 1036.545(o)(7).
We are also clarifying that manufacturers may test the powertrain with a chassis dynamometer as long as they measure speed and torque at the powertrain's output shaft or wheel hubs.
We are replacing all references to 40 CFR 1037.550 throughout 40 CFR parts 1036 and 1037 with new references to 40 CFR 1036.545. We are clarifying that when creating GEM inputs, if speed and torque are measured at more than one location, determine W [cycle] by integrating the sum of the power calculated from speed and torque measurements at each location.
Finally, we received comment from multiple stakeholders that improvements are needed to reduce the test burden of the hybrid powertrain test procedure. As discussed in RTC section 24.1.4, many of these suggested changes are out of scope for this rule. However, EPA is constantly reviewing its test procedures and in the future EPA intends to work with manufacturers and stakeholders to further streamline hybrid certification.

v. Median Calculation for Test Fuel Properties in 40 CFR 1036.550
The regulation at 40 CFR 1036.550 currently requires the use of the median value of measurements from multiple labs for the emission test fuel's carbon-mass-specific net energy content and carbon mass fraction for manufacturers to determine the corrected CO 2 emission rate using equation 1036.550-1 in 40 CFR 1036.550. The current procedure does not provide a method for determining the median value. We proposed to add a new calculation for the median value in the statistics calculation procedures of 40 CFR 1065.602 as a new paragraph (m) to ensure that labs are using the same method to calculate the median value. We also proposed to reference the new paragraph (m) in 40 CFR 1036.550(a)(1)(i) and (a)(2)(i) for carbon-mass-specific net energy content and carbon mass fraction, respectively. We are finalizing the new median calculation procedure as proposed.

2. Updates to 40 CFR Part 1036 Heavy-Duty Highway Engine Provisions

i. Manufacturer Run Heavy-Duty In-Use Testing
We are adding a clarification to 40 CFR 1036.405(d) regarding the starting point for the 18-month window manufacturers have to complete an in-use test order. Under the current provision, the clock for the 18-month window starts after EPA has received the manufacturer's proposed plan for recruiting, screening, and selecting vehicles. There is concern that manufacturers could delay testing by unnecessarily prolonging the selection process. To alleviate this concern and keep the testing timeline within the originally intended 18-month window, we are revising the 18-month window to start when EPA issues the order for the manufacturer to test a particular engine family.
In the HD2027 final rule, we adopted a new 40 CFR 1036.420 that includes the pass criteria for individual engines tested under the manufacturer run in-use testing program. Table 1 to 40 CFR 1036.420 contains the accuracy margins for each criteria pollutant. We are correcting an inadvertent error in the final rule's amendatory text for the regulations that effects the accuracy margin for carbon monoxide (CO), which is listed in Table 1 as 0.025 g/hp-hr. The HD2027 preamble is clear that the CO accuracy margin that we finalized was intended to be 0.25 g/hp-hr and we are correcting Table 1 to reflect the value in that rule's preamble. ^{887}
^{887} See HD2027 final rule preamble (88 FR 4353, January 24, 2023) (“PEMS measurement allowance values in 40 CFR 86.1912 are 0.01 g/hp-hr for HC, 0.25 g/hp-hr for CO, 0.15 g/hp-hr for NO X , and 0.006 g/hp-hr for PM. We are maintaining the same values for HC, CO, and PM in this rulemaking.”).

ii. Low Load Cycle (LLC)—Cycle Statistics
We are updating 40 CFR 1036.514 to address the ability of gaseous fueled non-hybrid engines with single point fuel injection to pass cycle statistics to validate the LLC duty cycle. In 40 CFR 1036.514(e), we referenced, in error, the alternate cycle statistics for gaseous fueled engines with single point fuel injection in the cycle average fuel map section in 40 CFR 1036.540(d)(3) instead of adding LLC specific cycle statistics in 40 CFR 1036.514(e). We are adding a new table 2 in 40 CFR 1036.514(b) to provide cycle statistics that are identical to those used by the California Air Resources Board for the LLC and to remove the reference to 40 CFR 1036.540(d)(3) in 40 CFR 1036.514(e).

iii. Low Load Cycle (LLC)—Background Sampling
We are removing the provision in 40 CFR 1036.514(d) that allows periodic background sampling into the bag over the course of multiple test intervals during the LLC because the allowance to do this is convered in 40 CFR 1065.140(b)(2). The LLC consists of a very long test interval and the intent of the provision was to address emission bag sampling systems that do not have enough dynamic range to sample background constantly over the entire duration of the LLC. Paragraph (b)(2) of 40 CFR 1065.140 affords many flexibilities regarding the measurement of background concentrations, including sampling over multiple test intervals as long as it does not affect manufacturers' ability to demonstrate compliance with the applicable emission standards. The final revisions to 40 CFR 1036.514(d) include additional edits for clarification and consistency with other final revisions.

iv. Determining Vehicle C Speed Values for Powertrain Testing
We are finalizing changes to 40 CFR 1036.520 to make the procedure more robust at determining a representative vehicle C speed. For powertrains where there is no power interrupt as the transmission shifts through gears, the test procedure can result in an unrepresentatively high vehicle C speed. This is because the test procedure assumes maximum powertrain power as a function of speed for each gear will start low, and then reach the peak power before dropping again. If the powertrain does not have multiple speeds where the power is equal to 98 percent of peak power, the vehicle C speed is the highest speed in top gear. The finalized changes to the procedure in 40 CFR 1036.520(j)(1) address this by using the lowest vehicle speed in top gear in place of the minimum vehicle speed where power is greater than 98 percent of peak power. We are also adding a new 40 CFR 1036.520(j)(3) to allow manufacturers to use a declared vehicle C speed instead of the measured value if the declared value is within (97.5 to 102.5) percent of the corresponding measured value.
For series hybrids the powertrain may have only one, two or three gears in the transmission or e-axle so the average of the minimum and maximum speeds where power is greater than 98 percent of peak power in top gear, may result in an unrepresentatively low vehicle C speed. To address this issue, we are finalizing a new 40 CFR 1036.520(j)(4), which directs a manufacturer to request EPA approval for a representative vehicle C speed if the procedure results in a vehicle C speed that is lower than the cruise speed of the powertrain.

v. U.S.-Directed Production Volume
In the recent HD2027 rule, we amended the heavy-duty highway engine provision in 40 CFR 1036.205 and several other sections to replace “U.S.-directed production volume” with the more general term “nationwide” where we intended manufacturers report total nationwide production volumes, including production volumes that meet different state standards.
In this rule, for the reasons explained in section I.A.1, we are finalizing a broader change to the definition in 40 CFR 1037.801 such that the phrase “U.S.-directed production volume” no longer excludes production volumes for vehicles certified to different state standards. We are similarly updating the definition of “U.S.-directed production volume” for engines in 40 CFR 1036.801 to maintain consistency between the engine and vehicle regulatory definitions. We are also reinstating, as proposed, the term “U.S.-directed production volume” where we previously used “nationwide” in 40 CFR part 1036 to avoid having two terms with the same meaning. ^{888}
^{888} We proposed and are finalizing revisions in 40 CFR 1036.205(v), 1036.250(a), 1036.405(a), 1036.605(e), 1036.725(b), and 1036.730(b).
As noted in the proposal, the NO X ABT program for HD engines in part 1036 excludes production volumes certified to different state standards in its credit calculations, and we proposed clarifying updates throughout 40 CFR part 1036 to ensure no change to those existing exclusions in tandem with the proposed change to the definition of the term “U.S.-directed production volume.” Most notably, we proposed a new 40 CFR 1036.705(c)(4) as the location where we exclude engines certified to different state emission standards from being used to calculate emission credits in the HD engine program. ^{889} Two commenters suggested revisions to the proposed 40 CFR 1036.705(c)(4), indicating manufacturers may certify their engines to both California and Federal standards to ensure that engines can be sold nationwide. Under the proposed definition, manufacturers would not be allowed to include engines certified to the California standards in their credit calculations, even if the engine was never sold in California (or in a state that adopted California standards). After considering these comments and noting that we never intended to discourage manufacturers from certifying a complete engine family to California-level standards, we are further revising the proposed provision to exclude engines if they are certified to different state standards and intended for sale in a state that adopted those different emission standards. ^{890}
^{889} We are finalizing as proposed the revision to move the statement to keep records relating to those production volumes from its current location in 40 CFR 1036.705(c) to 40 CFR 1036.735 with the other ABT recordkeeping requirements.
^{890} We are finalizing as proposed revisions that replace several instances of “U.S.-directed production volume” with a more general “production volume” where the text clearly is connected to ABT or add a more specific reference to the production volume specified in 40 CFR 1036.705(c). See revisions in 40 CFR 1036.150(d) and (k), 1036.725(b), and 1036.730(b).

vi. Correction to NO X ABT FEL Cap
We are finalizing an amendment to 40 CFR 1036.104 to remove paragraph (c)(2)(iii) which corresponds to a FEL cap of 70 mg/hp-hr for MY 2031 and later Heavy HDE that we proposed in HD2027 but did not intend to include in the final amendatory text. In the final rule for the HD2027 rule, we did not intend to include in the final amendatory text paragraph (c)(2)(iii) alongside the final FEL cap of 50 mg/hp-hr for MY 2031 and later which applies to all HD engine service classes including Heavy HDE in paragraph (c)(2)(ii) described by EPA in the preamble and supporting rule record. We are finalizing the correction of this error and removing paragraph (c)(2)(iii). This correction will not impact the stringency of the final NO X standards because even without correction paragraph (c)(2)(ii) controls. ^{891}
^{891} As EPA explained in the NPRM and elsewhere in this final rule, EPA did not reopen the final HD2027 standards, or any other portion of that rule besides those specifically identified in the NPRM as subject to new revisions.

vii. Rated Power and Continuous Rated Power Coefficient of Variance in 40 CFR 1036.520
We are finalizing the correction of an error and a revision to a provision we intended to include in HD2027, regarding determining power and vehicle speed values for powertrain testing. In 40 CFR 1036.520, paragraphs (h) and (i) describe how to determine rated power and continuous rated power, respectively, from the 5 Hz data in paragraph (g) averaged from the 100 Hz data collected during the test. We inadvertently left out the coefficient of variance (COV) limits of 2 percent that are needed for making the rated and continuous rated power determinations in the HD2027 final 40 CFR 1036.520(h) and (i), which were intended to be based on the COVs calculated in 40 CFR 1036.520(g) and we correctly included in the HD2027 final 40 CFR 1036.520(g). We are adding the 2 percent COV limit in 40 CFR 1036.520(h) and (i). We are also finalizing the correction of a paragraph reference error in 40 CFR 1036.520(h). The paragraph references the data collected in paragraph (f)(2) of the section. The data collection takes place in paragraph (d)(2) of the section.

viii. Selection of Drive Axle Ratio and Tire Radius for Hybrid Engine and Hybrid Powertrain Testing
We are finalizing changes to the drive axle ratio and tire radius selection paragraphs in 40 CFR 1036.510(b)(2)(vii) and (viii), that includes combining the selection process into a single paragraph (b)(2)(vii). When testing hybrid engines and hybrid powertrains a series of vehicle parameters must be selected. The paragraphs for selecting drive axle ratio and tire radius are separate from each other, however the selection of the drive axle ratio must be done in conjunction with the tire radius as not all tire sizes are offered with a given drive axle ratio. We are finalizing the combination of these paragraphs into one to eliminate any possible confusion on the selection of these two parameters.
The maximum vehicle speed for SET testing of hybrid engines and powertrains is determined based on the vehicle parameters and maximum achievable speed for the configuration in 40 CFR 1036.510. This is not the case for the FTP vehicle speed which reaches a maximum of 60 miles per hour. It has been brought to our attention that there are some vehicle configurations that cannot achieve the FTP maximum speed of 60 mile per hour. To resolve this, we are finalizing changes to 40 CFR 1036.510(b)(2)(vii) that instruct the manufacturer to select a representative combination of drive axle ratio and tire size that ensure a vehicle speed of no less than 60 miles per hour. We are also finalizing the inclusion, as a reminder, that manufacturers may request approval for selected drive axle ratio and tire radius consistent with the provisions of 40 CFR 1036.210. We are also finalizing the addition of a provision for manufacturers to follow 40 CFR 1066.425(b)(5) if the hybrid powertrain or hybrid engine is used exclusively in vehicles which are not capable of reaching 60 mi/hr. This allows the manufacturer to seek approval of an alternate test cycle and cycle-validation criteria for powertrains where the representative tire radius and axle ratio do not allow the vehicle to achieve the maximum speeds of the specified test cycle.

ix. Determining Power and Vehicle Speed Values for Powertrain Testing
We are finalizing revisions to 40 CFR 1036.520(d)(2) to address the possibility of clutch slip when performing the full load acceleration with maximum driver demand at 6.0 percent road grade where the initial vehicle speed is 0 mi/hr. The revision allows hybrid engines and hybrid powertrains to increase the initial speed from 0 miles per hour to 5 miles per hour to mitigate clutch slip. This change in initial speed will reduce the extreme force on the clutch when accelerating at 6.0 percent grade. We are not finalizing the second option proposed that allowed modification of the road grade during the first 30 seconds of the full load acceleration, as the option to start at a higher initial speed will do a better job at reducing the effects of the low-end torque, which is the cause of clutch slip.
We are finalizing a revision to 40 CFR 1036.520(d)(3) to address situations where the powertrain does not reach maximum power in the highest gear 30 seconds after the grade setpoint has reached 0.0 percent. To address this we are replacing the 30 second time limit with a speed change stability limit of 0.02 m/s ^2 which will trigger the end of the test.

x. Determining Vehicle Mass in 40 CFR 1036.510
We requested comment on updating equation 1036.510-1 of 40 CFR 1036.510 to better reflect the relationship of vehicle mass and rated power. It was brought to EPA's attention that with the increase in rated power of heavy-duty engines, equation 1036.510-1 of 40 CFR 1036.510 might need updating to better reflect the relationship of vehicle mass and rated power. We are not making any changes to equation 1036.510-1 of 40 CFR 1036.510 at this time because we still consider it to be representative. Further, we requested comment on this issue and received no comments suggesting changes.

xi. Test Procedure for Engines Recovering Kinetic Energy for Electric Heaters
We are finalizing a clarification in the existing definition for hybrid in 40 CFR 1036.801 to add a sentence stating that systems recovering kinetic energy to power an electric heater for the aftertreatment do not qualify as a hybrid engine or hybrid powertrain. Under the existing hybrid definition, systems that recover kinetic energy, such as regenerative braking, are be considered “hybrid components” and manufacturers were required to use the powertrain test procedures to account for the electric heater or use the engine test procedures and forfeit the emission reductions from heating the aftertreatment system. With this clarification to the hybrid definition, engines that use regenerative braking only to power an electric heater for aftertreatment devices are not considered hybrid engines and, therefore, are not required to use the powertrain test procedures; instead, those engines can use the test procedures for engines without hybrid components.
We are finalizing a supplement to the new definitions with direction for testing these systems in 40 CFR 1036.501. In the new 40 CFR 1036.501(g), we are clarifying that an electric heater for aftertreatment can be installed and functioning when creating fuel maps using 40 CFR 1036.505(b) and measuring emissions over the duty cycles specified in 40 CFR 1036.510(b), 1036.512(b), and 1036.514(b). This allowance is limited to hybrid engines where the system recovers less than 10 percent of the total positive work over each applicable transient cycle and the recovered energy is exclusively used to power an electric heater in the aftertreatment. Since the small amount of recovered energy is stored thermally and can't be used to move the vehicle, we believe that the engine test procedures are just as representative of real-world operation as the powertrain test procedures. The limit of 10 percent is based on the amount of negative work versus positive work typical of conventional engines over the transient cycle. After evaluating a range of HDE, we have observed that the negative work from the transient FTP cycle during engine motoring is less than 10 percent of the positive work of the transient FTP cycle. ^{892} In the same paragraph (g), we are finalizing an option for manufacturers to use the powertrain test procedures for these systems, which does not have the same restrictions we are finalizing for the amount of recovered energy.
^{892} Memorandum to Docket EPA-HQ-OAR-2022-0985: “Analysis of Motoring and Positive Cycle Work for Current Heavy-Duty Engines”. James Sanchez. April 4, 2023.
We are finalizing changes to the proposed 40 CFR 1036.501(g), to clarify that for these hybrid engines, the choice to run the powertrain test procedure or the engine test procedure can be made separately for measuring emissions and fuel mapping. The allowance to choose which test procedure to use doesn't allow for a unique decision to be made for each of the applicable duty cycles in 40 CFR part 1036. For example, you cannot run the powertrain test procedure for the FTP and run the engine test procedure for the SET. In addition, the same test procedure must be used for all pollutants. For example, you may not run the powertrain test procedure for CO 2 and the engine test procedure for NO X .

xii. Updates to 40 CFR Part 1036 Definitions
We are finalizing new and updated definitions in 40 CFR 1036.801 in support of several requirements we are finalizing in section II or this section III. We added a reference to two new definitions we are finalizing in 40 CFR part 1065: “Carbon-containing fuel” and “neat”. The definition of carbon-containing fuel will help identify the applicable test procedures for engines using fuels that do not contain carbon and would not produce CO 2 . The definition of “neat” indicates that a fuel is not mixed or diluted with other fuels, which helps distinguish between fuels that contain no carbon, such as hydrogen, and fuels that contain carbon through mixing, such as hydrogen where a diesel pilot is used for combustion. We are also updating the definition for “U.S.-directed production volume” of engines to be equivalent to nationwide production, consistent with the updated definition for vehicles in part 1037.
We are consolidating the definitions of hybrid, hybrid engine, and hybrid powertrain into a single definition of “hybrid” with subparagraphs distinguishing hybrid engines and powertrains. The definition of hybrid retains most of the existing definition, except that we have removed the unnecessary “electrical” qualifier from batteries and added a statement relating to recovering energy to power an electric heater in the aftertreatment (see section I.C.2.xi of this preamble). The revised definitions for hybrid engines and powertrains, which are being finalized as subparagraphs under “hybrid”, are more complementary of each other with less redundancy. As noted in section I.C.2.xi, we are finalizing updated definitions of hybrid engine and hybrid powertrain to exclude systems recovering kinetic energy for electric heaters.
We are finalizing several editorial revisions to definitions as well. We are updating the definition of mild hybrid such that it is relating to a hybrid engine or hybrid powertrain. We are revising the existing definition of small manufacturer to clarify that the employee and revenue limits include the totals from all affiliated companies and added a reference to the definition of affiliated companies in 40 CFR 1068.30.

xiii. Miscellaneous Corrections and Clarifications in 40 CFR Part 1036
We are finalizing as proposed an update to 40 CFR 1036.150(j) to clarify that the alternate standards apply for model year 2023 and earlier loose engines, which is consistent with existing 40 CFR 86.1819-14(k)(8).
We are finalizing an update to the provision describing how to determine deterioration factors for exhaust emission standards in 40 CFR 1036.245 to clarify that it also applies for hybrid powertrains.

xiv. Off-Cycle Test Procedure for Engines That Use Fuels Other Than Carbon-Containing Fuel
We are finalizing a new 40 CFR 1036.530(j) for engines that use fuels other than carbon-containing fuel. The off-cycle test procedures in 40 CFR 1036.530 use CO 2 as a surrogate for engine power. This approach works for engines that are fueled with carbon-containing fuel, since power correlates to fuel mass rate and for carbon-containing fuels, fuel mass rate is proportional to the CO 2 mass rate of the exhaust. For fuels other than carbon-containing fuels, the fuel mass rate is not proportional to the CO 2 mass rate of the exhaust. To address this issue, we are finalizing that for fuels other than carbon-containing fuels, to use engine power directly instead of relying on CO 2 mass rate to determine engine power. For field testing where engine torque and speed are not directly measured, engine broadcasted speed and torque can be used as described in 40 CFR 1065.915(d)(5).

xv. Onboard Diagnostic and Inducement Amendments
EPA is amending specific aspects of 40 CFR 1036.110 and 1036.111 to add clarifications and correct minor errors in the OBD and inducement provisions adopted in the HD2027 final rule. ^{893} Specifically, EPA is adopting the following amendments, without change from the proposed rule except as noted.
^{893} As EPA explained in the NPRM and elsewhere in this final rule, EPA did not reopen any aspect of our OBD and inducement provisions other than those clarifications and corrections specifically identified in the NPRM for this section.
• 40 CFR 1036.110(b)(6): Correcting a reference to the CARB regulation to be consistent with our intent as described in the preamble of the final rule (see 88 FR 4372) to not require under our regulations manufacturer self-testing and reporting requirements as referenced in 13 CCR 1971.1(l)(4).
• 40 CFR 1036.110(b)(9): Clarifying that the list of data parameters readable by a generic scan tool is limited to components that are subject to existing OBD monitoring requirements ( e.g., through comprehensive component requirements in 13 CCR 1971.1(g)(3)). For example, if parking brake status was not included in an engine's OBD certificate, it would not be a required data parameter. The RTC describes a minor change from the proposed rule to clarify that OBD monitoring is relevant both for monitoring specific components, and for monitoring parameters related to those components.
• 40 CFR 1036.110(b)(11): Adding a reference to 13 CCR 1971.5. The final rule referenced 13 CCR 1971.1 to point to OBD testing deadlines; however, there are additional OBD testing deadlines specified in 1971.5.
• 40 CFR 1036.110(c)(1) and 1036.125(h)(8)(iii): Correcting terminology within these provisions by referring to inducements related to “DEF level” instead of “DEF quantity,” to make the intent clearer that the system must use the level of DEF in the DEF tank for purposes of evaluating the specified inducement triggering condition. We separately refer to the quantity of DEF injection for managing the functioning of the SCR catalyst, which is unrelated to the level of DEF in the DEF tank.
• 40 CFR 1036.111: Editing for clarity to eliminate confusion with onboard diagnostic terminology. More specifically, the final rule includes edits to adjust inducement-related terminology to refer to “inducement triggering conditions” instead of “fault conditions.” Inducement algorithms are executed through OBD algorithms, but the inducement triggers are separate from OBD fault conditions related to the malfunction indicator light.
• 40 CFR 1036.111(a)(2): Clarifying how to determine the inducement speed category when the vehicle has less than 30 hours of accumulated data. The regulation as adopted sets the inducement schedule based on average vehicle speed over the preceding 30 hours of non-idle operation. That instruction will cover most circumstances; however, there is no specific instruction for an inducement triggering condition that occurs before the vehicle accumulates 30 hours of non-idle operation. As described in the final rule, we depend on 30 hours of non-idle operation to establish which inducement schedule is appropriate for a vehicle. We are also aware that a newly purchased vehicle would have accumulated several hours of very low-speed operation before being placed into service. We are therefore amending the regulation to specify that engines should not be designed to assess the speed category for inducement triggering conditions until the vehicle has accumulated 30 hours of non-idle operation. Manufacturers should instead program engines with a setting categorizing them as high-speed vehicles until they accumulate 30 hours of non-idle operation to avoid applying an inappropriate speed schedule.
• 40 CFR 1036.111(d)(1), table 2: Correcting a typographical error for the middle set of columns to read “Medium-speed” instead of repeating “Low-speed.” The table was correctly published in the preamble to the final rule but was incorrectly transcribed in the Code of Federal Regulations (see 88 FR 4378). We are also adding an inadvertently omitted notation in the table to identify the placement of a footnote to the table.
• 40 CFR 1036.111(a)(1): After consideration of a comment received, we are correcting the omission of an alternative DEF level triggering condition. More specifically, this final rule includes a provision allowing for DEF supply falling to 2.5 percent of DEF tank capacity as an acceptable triggering condition for a DEF level inducement. EPA SCR certification guidance documents included a DEF level triggering condition of 2.5 percent DEF tank capacity in 2009, and manufacturers have used this strategy since that time. ^{894} In the HD2027 NPRM and final rule, we described our intention to finalize an inducement program similar to the approach described in our existing guidance. Some manufacturers may prefer to rely on percent of DEF tank capacity instead of estimating a fill level that corresponds to the time remaining before the tank is empty because there is less need to make assumptions about the vehicle's operating characteristics.
^{894} “Inducement-Related Guidance Documents, and Workshop Presentation,” EPA docket memo number EPA-HQ-OAR-2019-0055-0778, October 2021. See Docket Entry EPA-HQ-OAR-2022-0985-78383.”

xvi. Engine Data and Information To Support Vehicle Certification
We are finalizing an update 40 CFR 1036.505 to clarify that when certifying vehicles with GEM, for any fuel type not identified in table 1 to paragraph (b)(4) of 40 CFR 1036.550, the manufacturer identifies the fuel type as diesel fuel for engines subject to compression-ignition standards, and identifies the fuel type as gasoline for engines subject to spark-ignition standards. This change to 40 CFR 1036.505, is intended to clarify what was originally intended for fuels that are not specified in table 1 to paragraph (b)(4) of 40 CFR 1036.550. This clarification addresses the potential situation where, if a fuel is input into GEM other than the fuel types identified in table 1 to paragraph (b)(4) of 40 CFR 1036.550, GEM will output an error.

xvii. Charge-Depleting Criteria Pollutant Test Sequence—40 CFR 1065.510 Figure 1 and 40 CFR 1065.512 Figure 1
We are finalizing updates to the charge-depleting criteria pollutant test sequence figures in 40 CFR 1065.510 for the SET duty-cycle and 40 CFR 1065.512 for the FTP duty-cycle. These updates are not substantive and are intended to provide better visualization of the charge-depleting and charge-sustaining portions of the test sequences as well as which test intervals are relevant for criteria pollutant determination.

xviii. Testing Exemption for Engines Fueled With Hydrogen
As discussed in section II.D.1, hydrogen-fueled internal combustion engines (ICE) are a newer technology under development, and since neat hydrogen fuel does not contain any carbon, H2 ICE fueled with neat hydrogen produce zero HC, CH 4 , CO, and CO 2 engine-out emissions. We recognize that there may be negligible, but non-zero, CO 2 emissions at the tailpipe of H2 ICE that use SCR and are fueled with neat hydrogen due to contributions from the aftertreatment system from urea decomposition. Similarly, CO 2 emissions are attributable to the aftertreatment systems in compression-ignition ICEs. However, the contribution of CO 2 emission due to decomposition of the urea portion of DEF used in the aftertreatment system of diesel fueled ICE is less than 1 percent of the total. ^{895} Since hydrogen-fueled internal combustion engines must meet the same tailpipe NO X standards in 40 CFR 1036.104 as diesel fueled engines, we expect that engine out NO X will be at the same level or lower than diesel fueled engines, which would result in the same or lower DEF usage and tailpipe CO 2 emissions. We are therefore finalizing that tailpipe CO 2 emissions from engines fueled with neat hydrogen are deemed to be 3 g/hp-hr, and tailpipe CH 4 , HC, and CO emissions are deemed to comply with the applicable standards. ^{896} We are finalizing 3 g/hp-hr as the default CO 2 emission value, since 0.5 percent of the CO 2 emissions of a Phase 2 compliant compression-ignition engine is less than 3 g/hp-hr. The use of the default CO 2 emission value of 3 g/hp-hr is optional and manufacturers may instead conduct testing to demonstrate that the CO 2 emissions for their engine is below 3 g/hp-hr. Note, NOx and PM emission testing is required under existing 40 CFR part 1036 for engines fueled with neat hydrogen.
^{895} See 81 FR 73553. “. . . urea typically contributes 0.2 to 0.5 percent of the total CO 2 emissions measured from the engine, and up to 1 percent at certain map points.”.
^{896} See 40 CFR 1036.150(f).

xix. Emergency Vehicle Provisions
We are adding several provisions to 40 CFR part 1036 to restore what was originally adopted in 40 CFR part 86. The effort to migrate emission standards and certification requirements improperly omitted several provisions related to the allowance for manufacturers to design their engines with AECDs that override a derate condition for qualifying emergency vehicles. Specifically, we are revising 40 CFR 1036.115(h)(4) to clarify that emissions standards do not apply when AECDs for emergency vehicles are active. We are adding text to 40 CFR 1036.501(e) to allow manufacturers to disable such approved AECDs for emergency vehicles during testing. We are also adding text to 40 CFR 1036.580(d) to instruct manufacturers to disregard approved AECDs for emergency vehicles when they determine Infrequent Regeneration Adjustment Factors. Finally, we are revising the definition of “emergency vehicle” in 40 CFR 1036.801 to allow for qualifying as an emergency vehicle if it has characteristics that support an expectation that it will be used in emergency situations such that malfunctions would cause a significant risk to human life.
We are also amending 40 CFR 1036.601 to clarify that engines for emergency vehicles may need to include design features that don't full comply with the OBD requirements in 40 CFR 1036.110. For example, the regulation requires in-cab displays with derate information for the driver, but the cab display should not include information about the schedule for pending derates an approved AECD will prevent that derate from occurring.

3. Updates to 40 CFR Part 1037 Heavy-Duty Motor Vehicle Provisions

i. Standards for Qualifying Small Businesses
As noted in section II.I, we are finalizing that qualifying small manufacturers will continue to be subject to the existing MY 2027 and later standards. We proposed revisions to 40 CFR 1037.150(c) that clarified the standards and proposed restrictions on participation in the ABT program for MYs 2027 and later for qualifying small manufacturers that utilize the interim provision. In the final rule, we have revised 40 CFR 1037.105(b) and (h) and 1037.106(b) to include the MY 2027 and later standards that apply for small manufacturers. The interim provisions of 40 CFR 1037.150(c) and (w) specify the flexibilities that continue to be available for small manufacturers. We are also finalizing as proposed the revised definition for “small manufacturer” in 40 CFR 1037.801. ^{897}
^{897} The revision removes criteria for trailers and revenue that do not apply for the heavy-duty truck manufacturing category covered by this rule and adds a clarifying reference to what qualifies as an affiliated company for applying the specified number of employee limits.

ii. Vehicles With Engines Using Fuels Other Than Carbon-Containing Fuels
In the HD2027 final rule, we adopted revisions to 40 CFR 1037.150(f) to include fuel cell electric vehicles, in addition to battery electric vehicles, in the provision that deems tailpipe emissions of regulated GHG pollutants as zero and as such does not require CO 2 -related emission testing. As discussed in section II.D.1, hydrogen-fueled internal combustion engines are a newer technology under development, and since hydrogen has no carbon, H2 ICEs fueled with neat hydrogen produce zero HC, CH 4 , CO, and CO 2 engine-out emissions. We recognize that there may be negligible, but non-zero, CO 2 emissions at the tailpipe of H2 ICE vehicles fueled with neat hydrogen that utilize SCR due to the aftertreatment system contribution from urea decomposition. Similarly, CO 2 emissions are attributable to the aftertreatment systems in ICE. These aftertreatment-based CO 2 emissions from HD CI engines today are treated differently in the engine and vehicle compliance programs. In the engine program, the CO 2 emissions from the aftertreatment are included in the measurements to demonstrate compliance with the engine CO 2 standards in 40 CFR part 1036. In the vehicle program, the CO 2 emissions from the aftertreatment are excluded from the fuel maps developed to demonstrate compliance with the vehicle CO 2 emission standards in 40 CFR part 1037. We are finalizing an approach to maintain common measurement of emissions from ICE regardless of the fuel used to power them. Therefore, we are finalizing as proposed to include vehicles using engines fueled with neat hydrogen in 40 CFR 1037.150(f) so that their CO 2 tailpipe emissions are deemed to be zero and manufacturers are not required to perform any engine testing for demonstrating compliance with the vehicle CO 2 emission standards. This final revision does not change the requirements for H2 ICE engines, including those fueled with neat hydrogen, to meet the N 2 O GHG standards and the criteria pollutant emission standards in 40 CFR part 1036. Additionally, we are revising as proposed 40 CFR 1037.150(f) to replace “electric vehicles” with “battery electric vehicles”, and “hydrogen fuel cell vehicles” with “fuel cell electric vehicles”, consistent with final revisions to those definitions (see section I.C.3.xiii of this preamble).

iii. ABT Calculations
We proposed revisions to the definitions of two variables of the emission credit calculation for ABT in 40 CFR 1037.705. As noted in section II.C, we are not finalizing the proposed update to the emission standard variable (variable “Std”) to establish a common reference emission standard when calculating ABT emission credits for vocational vehicles with tailpipe CO 2 emissions deemed to be. However, we are finalizing as proposed a revision to the “Volume” variable. With the final revision to paragraph (c), we intend for 40 CFR 1037.705(c) to replace “U.S.-directed production volume” as the primary reference for the appropriate production volume to apply with respect to the ABT program and propose to generally replace throughout part 1037.

iv. U.S.-Directed Production Volume
The existing 40 CFR 1037.205, which describes requirements for the application for certification, uses the term U.S.-directed production volume. As described in section I.A.1, we are finalizing a change to the definition of “U.S.-directed production volume”, such that the term equates to nationwide production volumes that include any production volumes certified to different state standards. The revised definition does not require a change to 40 CFR 1037.205 to ensure manufacturers report nationwide production volumes.
We are finalizing as proposed revisions to the introductory paragraph of 40 CFR 1037.705(c), consistent with the final revisions to the corresponding HD engine provisions, to establish this paragraph as the reference for which engines are excluded from the production volume used to calculate emission credits for HD highway (see section I.C.2.v of this preamble). Similarly, final revisions include replacing several instances of “U.S.-directed production volume” with a more general “production volume” where the text clearly is connected to ABT or a more specific reference to the production volume specified in 40 CFR 1037.705(c). ^{898}
^{898} See revisions in 40 CFR 1037.150(c) and 1037.730(b).

v. Revisions to Hybrid Powertrain Testing and Axle Efficiency Testing
We are finalizing the addition of a new figure to 40 CFR 1036.545 to give an overview on how to carry out hybrid powertrain testing in that section. We are finalizing in the axle efficiency test in 40 CFR 1037.560(e)(2) the use of an alternate lower gear oil temperature range on a test point by test point basis in addition to the current alternate that requires the use of the same lower temperature range for all test points within the test matrix. This provides more representative test results as not all test points within a matrix for a given axle test will result in gear oil temperatures within the same range. We are also finalizing a change to 40 CFR 1037.560(h)(1) to require that testing must be done using the same temperature range for each setpoint for all axle assemblies when developing analytically derive axle power loss maps for untested configurations within an axle family.

vi. Removal of Trailer Provisions
As part of the HD GHG Phase 2 rulemaking, we set standards for certain types of trailers used in combination with tractors (see 81 FR 73639, October 25, 2016). We are finalizing the removal of the regulatory provisions related to trailers in 40 CFR part 1037 to carry out a decision by the U.S. Court of Appeals for the D.C. Circuit, which vacated the portions of the HD GHG Phase 2 final rule that apply to trailers. ^{899} These revisions include removal of specific sections and paragraphs describing trailer provisions and related references throughout the part. Additionally, we are finalizing new regulatory text for an existing test procedure that currently refers to a trailer test procedure. The existing 40 CFR 1037.527 describes a procedure for manufacturers to measure aerodynamic performance of their vocational vehicles by referring to the A to B testing methodology for trailers in 40 CFR 1037.525. We have removed the regulatory text describing A to B testing from the trailer procedure and moved it into 40 CFR 1037.527 (such that it replaces the cross-referencing regulatory text).
^{899} Truck Trailer Manufacturers Association v. EPA, 17 F.4th 1198 (D.C. Cir. 2021).

vii. Removal of 40 CFR 1037.205(q)
We have corrected an inadvertent error and have removed the existing 40 CFR 1037.205(q). This paragraph contained requirements we proposed in HD2027 but did not finalize and thus did not intend to include in the final rule's amendatory instructions, regarding information for battery electric vehicles and fuel cell electric vehicles to show they meet the standards of 40 CFR part 1037.

viii. Adding Full Cylinder Deactivation to 40 CFR 1037.520(j)(1)
We are finalizing as proposed to credit vehicles with engines that include full cylinder deactivation during coasting at 1.5 percent. We believe this is appropriate since the same 1.5 percent credit is currently provided for tractors and vocational vehicles with neutral coasting, and both technologies reduce CO 2 emissions by reducing the engine braking during vehicle coasting. ^{900} Cylinder deactivation can reduce engine braking by closing both the intake and exhaust valves when there is no operator demand to reduce the pumping losses of the engine when motoring. Because of this, only vehicles with engines where both exhaust and intake valves are closed when the vehicle is coasting qualify for the 1.5 percent credit.
^{900} See the HD GHG Phase 2 rule (81 FR 73598, October 25, 2016), for more information on how 1.5 percent was determined for neutral coasting.

ix. Removal of Chassis Testing Option Under 40 CFR 1037.510 and Reference Update
We are removing the chassis dynamometer testing option for testing over the duty cycles as described in 40 CFR 1037.510(a). The chassis dynamometer test was available as an option for Phase 1 testing in 40 CFR 1037.615. We are removing it to avoid confusion as the chassis dynamometer testing option is only allowed when performing off-cycle testing following 40 CFR 1037.610 and is not allowed for creating the cycle average fuel map for input into GEM. Note that manufacturers may continue to test vehicles on a chassis dynamometer to quantify off-cycle credits under 40 CFR 1037.610.
We are also correcting paragraph reference errors in 40 CFR 1037.510(a)(2)(iii) and (iv). These paragraphs reference the warmup procedure in 40 CFR 1036.520(c)(1). The warmup procedure is located in 40 CFR 1036.520(d).

x. Utility Factor Clarification for Testing Engines With a Hybrid Power Takeoff Shaft
We are clarifying the variable description for the utility factor fraction UF RCD in 40 CFR 1037.540(f)(3)(ii). The current description references the use of an “approved utility factor curve”. The original intent was to use the power take off utility factors that reside in Appendix E to 40 CFR part 1036 to generate a utility factor curve to determine UF RCD. We are clarifying this by replacing “approved utility factor curve” with a reference to the utility factors in Appendix E.

xi. Heavy-Duty Vehicles at or Below 14,000 Pounds GVWR
The final standards in this rule apply for all heavy-duty vehicles above 14,000 pounds GVWR, except as noted in existing 40 CFR 1037.150(l). We are not changing the option for manufacturers to voluntarily certify incomplete vehicles at or below 14,000 pounds GVWR to 40 CFR part 1037 instead of certifying under 40 CFR part 86, subpart S; the final standards in this rule would also apply for those incomplete heavy-duty vehicles. We are removing 40 CFR 1037.104 as proposed and refer manufacturers to 40 CFR 1037.5 for excluded vehicles. ^{901}
^{901} This change includes removing the reference to 40 CFR 1037.104 in 40 CFR 1037.1.
In a parallel rulemaking to set new emission standards for light-duty and medium-duty vehicles under 40 CFR part 86, subpart S, we proposed a requirement for complete and incomplete vehicles at or below 14,000 pounds GVWR with Gross Combined Weight Rating above 22,000 pounds to have installed engines that have been certified to the engine-based criteria emission standards in 40 CFR part 1036. Those vehicles would continue to meet GHG standards under 40 CFR 86.1819 instead of meeting the engine-based GHG standards in 40 CFR part 1036 and the vehicle-based GHG standards in 40 CFR part 1037, with one exception. The exception would be to allow an option for manufacturers of such incomplete vehicles to meet the greenhouse gas standards under 40 CFR parts 1036 and 1037 instead of meeting the chassis-based greenhouse gas standards under 40 CFR part 86, subpart S. In that parallel rulemaking, the final rule allows manufacturers the option to certify those engines to the engine-based criteria emission standards under 40 CFR part 1036 instead of certifying to chassis-based standards under 40 CFR part 86, subpart S. For manufacturers that select that option, the greenhouse gas standards apply as we just described for the proposed rule.

xii. Updates to Optional Standards for Tractors at or Above 120,000 Pounds
In HD GHG Phase 2 and in a subsequent rulemaking, we adopted optional heavy Class 8 tractor CO 2 emission standards for tractors with a GCWR above 120,000 pounds (see 40 CFR 1037.670). ^{902} We did this because most manufacturers tend to rely on U.S. certificates as their evidence of conformity for products sold into Canada to reduce compliance burden. Therefore, in Phase 2 we adopted provisions that allow the manufacturers the option to meet standards that reflect the appropriate technology improvements, along with the powertrain requirements that go along with higher GCWR. While these heavy Class 8 tractor standards are optional for tractors sold into the U.S. market, Canada adopted these as mandatory requirements as part of their regulatory development and consultation process. As proposed, we are adopting provisions to sunset the optional standards after MY 2026. ^{903}
^{902} 81 FR 73582 (October 25, 2016) and 86 FR 34338 (June 29, 2021).
^{903} We removed the standards listed in the rightmost column of existing table 1 of paragraph (a) of § 1037.670; we note that the column was intended for model years 2027 and later standards but was mistakenly labeled “Model years 2026 and later”.

xiii. Updates to 40 CFR Part 1037 Definitions
We are finalizing several updates to the definitions in 40 CFR 1037.801. As noted in section I.C.3.vi, we are removing the trailer provisions, which include removing the following definitions: Box van, container chassis, flatbed trailer, standard tractor, and tank trailer. We also are revising several definitions to remove references to trailers or trailer-specific sections, including definitions for: Class, heavy-duty vehicle, low rolling resistance tire, manufacturer, model year, Phase 1, Phase 2, preliminary approval, small manufacturer, standard payload, tire rolling resistance, trailer, and vehicle.
We are finalizing new and updated definitions in support of several requirements in section II or this section III. We are finalizing replacement of the existing definition of “electric vehicle” with more specific definitions for the different vehicle technologies and energy sources that could be used to power these vehicles. Specifically, we are finalizing new definitions for battery electric vehicle, fuel cell electric vehicle, and plug-in hybrid electric vehicle. We are also finalizing the replacement of the existing definition of “hybrid engine or hybrid powertrain” with a definition of “hybrid” that refers to a revised definition in 40 CFR part 1036. ^{904} We are also updating the definition of U.S.-directed production volume to be equivalent to nationwide production as described section III.A.1.
^{904} See section I.C.2.xiii of this preamble for a description of the updated definition of hybrid.
We are finalizing several editorial revisions to definitions as well. We are finalizing a revision to the definition of vehicle to remove the text of existing paragraph (2)(iii) and move the main phrase of that removed paragraph ( i.e., “when it is first sold as a vehicle”) to the description of “complete vehicle” to further clarify that aspect of the existing definition. We are finalizing as proposed a revision to the existing definition of small manufacturer, in addition to the revisions removing reference to trailers, to clarify that the employee and revenue limits include the totals from all affiliated companies and added a reference to the definition of affiliated companies in 40 CFR 1068.30.
We are finalizing revisions to the definitions of “light-duty truck” and “light-duty vehicle”, by having the definitions reference the definitions in 40 CFR 86.1803-1.

xiv. Miscellaneous Corrections and Clarifications in 40 CFR Part 1037
We are finalizing revisions to several references to 40 CFR part 86 revisions. Throughout 40 CFR part 1037, we are replacing references to 40 CFR 86.1816 or 86.1819 with a more general reference to the standards of part 86, subpart S. These revisions reduce the need to update references to specific part 86 sections if new standards are added to a different section in a future rule. We are not revising any references to specific part 86 paragraphs ( e.g., 40 CFR 86.1819-14(j)).
We are removing the duplicative statements in 40 CFR 1037.105(c) and 1037.106(c) regarding CH 4 and N 2 O standards from their current locations and moving it to 40 CFR 1037.101(a)(2)(i) where we currently describe the standards that apply in part 1037. We are also updating 40 CFR 1037.101(a)(2)(i) to more accurately state that only CO 2 standards are described in 40 CFR 1037.105 and 1037.106, by removing reference to CH 4 and N 2 O in that sentence. We are updating the section title for 40 CFR 1037.102 to include the term “Criteria” and the list of components ( i.e., NO X , HC, PM, and CO) covered by the section to be consistent with the naming convention used in 40 CFR part 1036.

xv. Finalized Changes for In-Use Tractor Testing in 40 CFR 1037.665
The in-use tractor testing requirements were adopted to apply only to Phase 1 and Phase 2 tractors. We proposed to extend that to Phase 3 tractors as well, but received comments describing the significant test burden and limited value in performing this testing. Based on those comments and our own evaluation of the merits of further testing, we are not taking final action on the proposed change to extend testing requirements to Phase 3 tractors.

xvi. Finalized Changes to Constraints for Vocational Regulatory Subcategories in 40 CFR 1037.150(v)
In this action we are finalizing clarifications to 40 CFR 1037.150(z). ^{905} As pointed out in comments to this rule, 40 CFR 1037.150(z) included provisions that were duplicative, potentially confusing, or not needed. To address these concerns, we are deleting the former paragraph (z)(1), which contains a requirement to select the Regional regulatory subcategory if the engine is only tested with the Supplemental Emission Test. This scenario, however, is not allowed, as 40 CFR 1036.108(a)(1) requires that vocational engines measure CO 2 emissions over the FTP duty cycle. We are also deleting the reference to former paragraphs (z)(1) and (3) in the former paragraph (z)(5), as we are removing paragraphs (z)(1) and the former paragraph (z)(3) provides restrictions for defining vehicles as Urban and is not applicable to defining vehicles to the Multi-purpose regulatory subcategory. Finally, we are deleting former paragraph (z)(6), as it is identical to former paragraph (z)(5).
^{905} Note that 40 CFR 1037.150(z) is being moved to 40 CFR 1037.150(v).

4. Updates to 40 CFR Part 1039 Nonroad Compression-Ignition Engines
The final rule includes an amendment to 40 CFR 1039.705(b) to correct a publishing error in the equation to calculate emission credits for nonroad compression-ignition engines.

5. Updates to 40 CFR Part 1065 Engine Testing Procedures

i. Engine Testing and Certification With Fuels Other Than Carbon-Containing Fuels
Alternative fuels and fuels other than carbon-containing fuels are part of the fuel pathway for sustainable biofuel, e-fuel, and clean hydrogen development under the U.S. National Blueprint for Transportation Decarbonization. ^{906} This blueprint anticipates a mix of battery electric, sustainable fuel, and hydrogen use to achieve a net zero carbon emissions level by 2050 for the heavy-duty sector. EPA is updating 40 CFR part 1065 to facilitate certification of engines using fuels other than carbon-containing fuels for all sectors that use engine testing to show compliance with the standards. This includes a new definition of “carbon-containing fuel” in 40 CFR 1065.1001, the addition of a new paragraph (f) in 40 CFR 1065.520 that requires the selection of the chemical balance method prior to emission testing, and the addition of a new chemical balance procedure in section 40 CFR 1065.656 that is used in place of the carbon-based chemical balance procedure in 40 CFR 1065.655 when an engine is certified for operation using fuels other than carbon-containing fuels ( e.g., hydrogen or ammonia). ^{907} Since these fuels do not contain carbon, the current carbon-based chemical balance cannot be used as it is designed based on comparisons of the amount of carbon in the fuel to the amount measured post combustion in the exhaust. The chemical balance for fuels other than carbon-containing fuels looks at the amount of hydrogen in the fuel versus what is measured in the exhaust. The amendments also facilitate certification of an engine on a mix of carbon-containing fuels and fuels other than carbon-containing fuels. The update to 40 CFR 1065.520(f) also requires the decision on which chemical balance to use to be based on the hydrogen-to-carbon ratio of the fuel mixture. If it is less or equal to 6, the chemical balance in 40 CFR 1065.655 must be used. The regulation at 40 CFR 1065.695, Data Requirements, was also updated with the addition of a new paragraph (c)(9)(v) to add a requirement to in the section that describes the emission calculations used, including listing the chemical balance method used.
^{906} The U.S. National Blueprint for Transportation Decarbonization: A Joint Strategy to Transform Transportation. DOE/EE-2674. January 2023. Available at: https://www.energy.gov/sites/default/files/2023-01/the-us-national-blueprint-for-transportation-decarbonization.pdf.
^{907} We are also finalizing a definition for “carbon-containing fuel” in 40 CFR 1036.801 that references the proposed new 40 CFR part 1065 definition.
The addition of the certification option for fuels other than carbon-containing fuels relies on inputs requiring hydrogen, ammonia, and water concentration measurement from the exhaust. We are finalizing the addition of new sections in 40 CFR part 1065 and revisions to some existing sections to support the procedure in 40 CFR 1065.656. We are finalizing a new 40 CFR 1065.255 to provide specifications for hydrogen measurement devices, a new 40 CFR 1065.257 to provide specifications for water measurement using a Fourier Transform Infrared (FTIR) analyzer, and a new 40 CFR 1065.277 to provide specifications for ammonia measurement devices. These additions also require a new 40 CFR 1065.357 to address CO 2 interference when measuring water using an FTIR analyzer, a new 40 CFR 1065.377 to address H 2 O interference and any other interference species as deemed by the instrument manufacturer or using good engineering judgment when measuring NH 3 using an FTIR or laser infrared analyzers, and the addition of calibration gases for these new analyzer types to 40 CFR 1065.750. We are also adding drift check requirements to 40 CFR 1065.550(b) to address drift correction of the H 2 , O 2 , H 2 O, and NH 3 measurements needed in the 40 CFR 1065.656 procedure. We are not finalizing the addition of drift check requirements for H 2 , O 2 , H 2 O, and NH 3 measurements in 40 CFR 1065.935(g)(5)(ii) for testing with PEMS. These exhaust gas constituents are not regulated and are used in the chemical balance to facilitate dilution ratio determination for background correction and dry to wet correction. If there is any significant drift with these species, the impact will be included in the drift check verification of the regulated pollutants. We are also adding a new 40 CFR 1065.750(a)(6) to address the uncertainty of the water concentrations generated to perform the linearity verification of the water FTIR analyzer in 40 CFR 1065.257. We are finalizing two options to generate a humid gas stream. The first is via a heated bubbler where dry gas is passed through the bubbler at a controlled water temperature to generate a gas with the desired water content. The second is a device that injects heated liquid water into a gas stream. The linearity verification requirement for the humidity generator is once a year to an uncertainty of ±3 percent; ^{908} however, we are not requiring that the calibration of the humidity generator be NIST traceable. We are finalizing a leak check requirement after the humidity generator is assembled, as these devices are typically disassembled and stored when not in use and subsequent assembly prior to use could lead to leaks in the system. We are including calculations to determine the uncertainty of the humidity generator from measurements of dewpoint and absolute pressure. We are finalizing a new definition for “carbon-containing fuel” and “lean-burn” in 40 CFR 1065.1001 to further support the addition of the certification option for engines using fuels other than carbon-containing fuels.
^{908} The verification schedule in 40 CFR 1065.750(a)(6) says: “Calibrate the humidity generator upon initial installation, within 370 days before verifying the H 2 O measurement of the FTIR, and after major maintenance.”.
We are not adding any specifications for alternative test fuels, like methanol, and fuels other than carbon-containing fuels like hydrogen and ammonia, to 40 CFR part 1065, subpart H. Manufacturers certifying engines with alternative test fuels must use the provision in 40 CFR 1065.701(c) which allows the use of test fuels that we do not specify in 40 CFR part 1065, subpart H, with our approval.

ii. Engine Speed Derate for Exhaust Flow Limitation
We are finalizing a change to 40 CFR 1065.512(b)(1) to address the appearance of three options for generating new reference duty-cycle points for the engine to follow. The option in the existing 40 CFR 1065.512(b)(1)(i) is not an actual option; instead, it gives direction on how to operate the dynamometer (torque control mode). This sentence has been moved into 40 CFR 1065.512(b)(1). The two remaining options in the current 40 CFR 1065.512(b)(1)(ii) and (iii) have been redesignated as 40 CFR 1065.512(b)(1)(i) and (ii).
We are not finalizing the change we proposed to 40 CFR 1065.512(b)(1) to address cycle validation issues where an engine with power derate intended to limit exhaust mass flowrate might include controls that reduce engine speed under cold-start conditions, resulting in reduced exhaust flow that assists other aftertreatment thermal management technologies ( e.g., electric heater). Upon further investigation of the test procedure, we determined that 40 CFR part 1065 already contains options to address this. If the engine has the power derate feature described previously in this section, when this feature is active, the following scenarios would be applicable to enable engine testing:
1. For idle points:
a. For engines with an idle governor, have the dynamometer control torque and set the operator demand to minimum (same as what is currently done for most engine tests).
b. For engines without an idle governor ( i.e., no possibility of and enhanced or decreased idle governor speed), the test lab can decide whether to control speed or torque with the dyno and operator demand.
2. For non-idle-non-motoring points, have the dynamometer control torque and the operator demand control speed.
3. For motoring points, have the dynamometer control speed and set operator demand to minimum (same as what is currently done for most engine tests).
If a test lab tested an engine with power derate and took this approach and the power derate feature activates, we would expect the following to occur:
• For idle points under option 1a of the list, this feature could lower the idle governor setpoint and the dynamometer would continue to apply the reference idle torque. Presumably, any fueling limit at idle would be sufficient to keep the engine from stalling in-use and it would not stall in the test cell under this idle condition.
• For idle points under option 1b of the list, on engines without and idle governor (if this case is even practical for this technology), the fueling limit still cannot be set so low as to cause the engine to stall under idle load conditions.
• For non-idle-non-motoring points (option 2 of the list), the throttle is expected to saturate at maximum and the dynamometer will continue to try to apply the reference torque. This operation has the possibility of stalling the engine if the fueling limit is insufficient to produce the reference torque at a reduced speed and might require a stall countermeasure in the test cell controls.
• For motoring points (option 3 of the list), it is assumed the engine is already at minimum fueling (because the operator demand is at minimum) and power derate feature will have no impact on these points.

iii. Accelerated Aftertreatment Aging
We recently finalized a new accelerated aftertreatment aging procedure for use in deterioration factor determination in 40 CFR 1065.1131 through 1065.1145. We requested comment on the need for potential changes to the procedure based on experience that manufacturers and test labs have gained since the procedure was finalized.
We are finalizing changes to 40 CFR 1065.1135, 1065.1137, 1065.1139, 1065.1141, and 1065.1145. These changes are based on EPA's consideration of comments submitted to EMA's Emission Measurement and Testing Committee (EMTC). The comments consisted of a series of updates to the affected sections listed. These updates were based on additional testing and accelerated aging model validation performed by Southwest Research Institute as part of the Diesel Aftertreatment Accelerated Aging Cycle (DAAAC) Validation Steering Committee that consists of government (EPA) and industry (EMA) representatives who were part of the original DAAAC validation study that procedures in 40 CFR 1065.1131 through 1065.1145 were based on.
Explanation of the changes to the sections listed are as follows:
• We are finalizing an editorial change to 40 CFR 1065.1135 that is the simple insertion of a comma.
• We are finalizing non-substantive wording changes to 40 CFR 1065.1137.
• We are finalizing a change to 40 CFR 1065.1137(b)(1) where we are adding “storage capacity of the more active site” as an additional recommended metric for determining the thermal reactivity coefficient for use in the Arrhenius rate law function to model cumulative thermal degradation due to catalyst heat exposure for copper-based zeolite SCR catalysts. This metric has been shown to be an effective metric for tracking thermal aging in addition to the already allowed ratio between the storage capacity of the two different storage sites.
• We are finalizing a change to 40 CFR 1065.1137(b)(2) where we are removing the 250 °C temperature target for the single storage site thermal aging metric for iron-based zeolite SCR catalysts. Advancements in this catalyst technology have led to the need for a technology formulation specific temperature as opposed to the use of a prescribed default temperature, which we are adding as part of this change.
• We are finalizing a change to 40 CFR 1065.1137(b)(3) where we are removing the use of NO X conversion at 250 °C temperature target for the single storage site thermal aging metric for vanadium SCR catalysts. Advancements in this catalyst technology have led to the need for a different approach for tracking aging to achieve sufficient resolution. We are updating the key aging metric to Brunauer-Emmett-Teller (BET) theory for determination of surface area. We are also allowing the use of total ammonia storage capacity as a surrogate for BET measurements of surface area as the key aging metric, using a single storage site model.
• We are finalizing the addition of a new 40 CFR 1065.1137(b)(4) to add total ammonia storage capacity as a recommended key aging metric for zone-coated copper- and iron-based zeolite SCR, similar to paragraphs (b)(1) and (2) of the section. There was no option given previously for determining the key aging metric for this technology and the new addition remedies this.
• We are finalizing a change to the redesignated 40 CFR 1065.1137(b)(5) to the key aging metric NO to NO 2 conversion rate and HC reduction efficiency temperatures to a value less than or equal to 200 °C determined using good engineering judgement. This change resolves the inconsistencies throughout 40 CFR part 1037 regarding the temperature rate at which the conversion rate should be determined.
• We are finalizing an update to 40 CFR 1065.1137(c)(1) to change the recommended maximum time to observe changes in the aging metric from 50 hours to 64 hours as 64 hours is more in line with the pattern of increasing evenly spaced time intervals (2, 4, 8, 16, and 32 hours) given in 40 CFR 1065.1137(c)(2).
• We are finalizing the addition of new paragraphs (c)(2)(i) and (ii) to 40 CFR 1065.1137 to add processes for determining ammonia storage capacity for SCR catalysts as well as for determining oxidation conversion efficiency of NO to NO 2 for diesel oxidation catalysts (DOC) to assess the aging metric. These are the standard methodologies for assessing the aging metric and will provide a level playing field for test facilities carrying out accelerated aging testing.
• We are finalizing updates to 40 CFR 1065.1137, specifically new paragraphs (d)(1) through (4) to replace the use of a generalized deactivation equation for determination of catalyst deactivation rate constant, k D , and thermal reactivity coefficient, E a,D . The generalized equation was replaced with more specific processes for copper-based zeolite SCR (40 CFR 1065.1137(d)(1)), iron-based zeolite and vanadium SCR (40 CFR 1065.1137(d)(2)), zone-coated zeolite SCR (40 CFR 1065.1137(d)(3)), and diesel oxidation catalysts (40 CFR 1065.1137(d)(4)). These updates stem from the need for more detail and specificity on how to model the thermal reactivity coefficient to provide consistency and a level playing field. For example, it provides a means to use the temperature programmed desorption (TPD) data used to generate the ammonia storage capacity values to model catalyst deactivation.
• 40 CFR 1065.1137(d)(1) for copper-based zeolite SCR requires the processing of all ammonia TPD data for each aging condition using an algorithm to fit the ammonia desorption data. We recommend using a Temkin adsorption model to quantify the ammonia TPD at each site to determine the desorption peaks of individual storage sites. We allow either the general power law expression (GPLE) or Arrhenius modeling approaches to derive the thermal reactivity coefficient, E a,D . We recommend that both models are used to fit the data and that the resulting E a,D values for the two methods are within 3 percent of each other as a quality assurance check. These updates stem from the need for more detail and specificity on how to model the thermal reactivity coefficient to provide consistency and a level playing field.
• 40 CFR 1065.1137(d)(2) for iron-based zeolite of vanadium SCR requires the processing of all ammonia TPD data (or BET surface area data) for each aging condition using GLPE to fit the ammonia desorption data. Global fitting is used to solve for E a,D and the pre-exponential factor, A D , by applying a generalized reduced gradient (GRG) nonlinear minimization algorithm. These updates stem from the need for more detail and specificity on how to model the thermal reactivity coefficient to provide consistency and a level playing field.
• 40 CFR 1065.1137(d)(3) for zone-coated zeolite SCR requires derivation of the thermal reactivity coefficient, E a,D , for each zone of the SCR, based on 40 CFR 1065.1137(d)(1) and (2). The zone that yields the lowest E a,D is used for calculating the target cumulative thermal load, as outlined in 40 CFR 1065.1139. These updates stem from the need for more detail and specificity on how to model the thermal reactivity coefficient to provide consistency and a level playing field.
• 40 CFR 1065.1137(d)(4) for diesel oxidation catalysts models the catalyst monolith as a plug flow reactor with first order reaction rate. The pre-exponential term, A, in the Arrhenius rate law function is proportional to the number of active sites and is the desired aging metric. The NO to NO 2 oxidation reverse light off data for each aging condition is processed by determining the average oxidation conversion efficiency at a temperature of less than or equal to 200 °C determined using good engineering judgement and this is used to calculate the aging metric. This temperature limit change resolves the inconsistencies throughout 40 CFR part 1037 regarding the temperature rate at which the conversion rate should be determined. GPLE is used to fit the NO to NO 2 conversion data at each aging temperature. Global fitting is used to solve for E a,D and the pre-exponential factor, A D, by applying a generalized reduced gradient (GRG) nonlinear minimization algorithm. These updates stem from the need for more detail and specificity on how to model the thermal reactivity coefficient to provide consistency and a level playing field.
• We are finalizing the addition of new paragraphs 40 CFR 1065.1139(e)(6)(v) for heat load calculation and tuning for systems that have regeneration events and 40 CFR 1065.1139(f)(3) for heat load calculation and tuning for systems that do not have regeneration events. These additions allows a reduction in the acceleration factor from 10 to a lower number if the target cumulative deactivation for the field data, D t,field , is not achievable without exceeding the catalyst temperature limits. This would be applicable, for example, for a vanadium catalyst where you might not be able to age at the target temperature because it might cause vanadium sublimation, thus you would use a lower target temperature and then increase the test time to arrive at equivalent aging. The same lower acceleration factor for thermal aging must also then be used in the chemical exposure calculations, instead of 10.
• We are finalizing the addition of a new 40 CFR 1065.1141(b)(2) to add an additional method recommendation on modification of the engine to increase oil consumption to levels required for accelerated aging in a manner such that the oil consumption is still generally representative of oil passing the piston rings into the cylinder. This method uses iterative modification of the oil control rings in one or more cylinders to reduce the spring tension on the oil control ring and provides a robust means to increase engine oil consumption.
• We are finalizing an update to 40 CFR 1065.1141(f) to recommend incorporation of a method of continuous oil consumption monitoring during accelerated aging, including validation of the monitoring method with periodic draining and weighing of the engine oil. This is to ensure that oil consumption rates are representative over the course of the accelerated aging test.
• We are finalizing an update to 40 CFR 1065.1145(d) to recommended that if the aging cycle is paused for any reason, you resume testing at the same point in the cycle where it stopped to ensure consistent thermal and chemical exposure of the aftertreatment system.
• We are finalizing an update to 40 CFR 1065.1145(e)(2)(i) to remove the requirement to operate the engine for at least 4 hours after an oil change with the exhaust bypassing the aftertreatment system to stabilize the new oil. The Southwest Research Institute Diesel Aftertreatment Accelerated Aging Cycle (DAAAC) Validation test program did not stabilize new oil after an oil change and the validation program results to date indicate that there is no adverse effect on accelerated aging. Therefore we are removing the break in requirement to reduce test burden.

iv. Nonmethane Cutter Water Interference Correction
We recently finalized options and requirements for gaseous fueled engines to allow a correction for the effect of water on the nonmethane cutter (NMC) performance, as gaseous fueled engines produce much higher water content in the exhaust than gasoline or diesel fuels, impacting the final measured emission result. ^{909} The correction is done by adjusting the methane and ethane response factors used for the Total Hydrocarbon (THC) Flame Ionization Detector (FID) and the combine methane response factor and penetration fraction and combined ethane response factor and penetration fraction of the NMC FID. These response factors and penetration fractions are then used to determine NMHC and methane concentrations based on the molar water concentration in the raw or diluted exhaust. EPA is aware that test labs that have attempted to implement this correction have reported that this new option is lacking clarity with respect to the implementation of these corrections from both a procedural and emission calculation perspective. Test labs and manufacturers have also requested the option to use the water correction for all fuels, not just gaseous fuels. Test labs and manufacturers have also stated that in their view, as written, 40 CFR 1065.360(d)(12) indicates that the water correction for the methane response factor on the THC FID is required; we note that was not our intent and are finalizing updates to this section to clarify that provision.
^{909} 86 FR 34543, June 29, 2021.
In addition to general edits that improve the consistency of terminology and the rearrangement of some paragraphs to improve the flow of the procedure, we are making the following changes to 40 CFR 1065.360, 1065.365, and 1065.660 to address the concerns raised regarding implementation and use of the NMC performance corrections. In 40 CFR 1065.360 and 1065.365, we are allowing the optional use of the water correction for the applicable response factors and penetration fractions for engines operated on any fuel, as the use of the correction improves the quality of the emission measurement even though the effect is less pronounced for liquid fuels. In 40 CFR 1065.360, we are finalizing revisions to clarify that determination of the FID methane response factor as a function of molar water concentration is optional for all fuels. In 40 CFR 1065.365, we are removing the recommendation of a methane penetration fraction of greater than 0.85 for the NMC FID because the procedure will account for the effect of the penetration fraction regardless of the level of NMC methane penetration. We are also finalizing a corresponding change in relation to another change in this rule, such that the requirements for linearity performance of the humidity generator must meet the uncertainty requirements in 40 CFR 1065.750(a)(6) that we have added to address the accuracy of humidity generators used in the calibration of the FTIRs used for water measurement. In 40 CFR 1065.660, we are modifying equations 1065.660-2 and 1065.660-9 by adding the variable for the methane response factor and penetration fraction for the NMC FID back into the equations, which we previously removed for simplification because the value was set to a constant of one. This modification has no effect on the outcome of the calculations if the effect of water on the NMC performance is not being accounted for because the procedure directs that the methane response factor and penetration fraction for the NMC FID are set to one. If the effect of water is being accounted for, these modified equations make it easier to understand the requirements of the procedure.

v. ISO 8178 Exceptions in 40 CFR 1065.601
Paragraph (c)(1) of 40 CFR 1065.601 allows the use of ISO 8178 mass-based emission calculations instead of the calculations specified in 40 CFR part 1065, subpart G, with two exceptions. We are updating the section reference to the exception in 40 CFR 1065.601(c)(1)(i) for NO X humidity and temperature correction from ISO 8178-1 Section 14.4 to ISO 8178-4 Section 9.1.6 to address updates made to ISO 8178 over the last 20 years that changed the location of this correction. We are also removing the exception for the use of the particulate correction factor for humidity in ISO 8178-1 Section 15.1 because this correction factor no longer exists in ISO 8178.

vi. Work System Boundary in 40 CFR 1065.210
Figure 1 to paragraph (a) of 40 CFR 1065.210 provides diagrams for the work inputs, outputs, and system boundaries for engines. We are updating the diagram for liquid cooled engines in figure 1 to paragraph (a) of 40 CFR 1065.210 to include electric heaters that use work from an external power source. We are also updating 40 CFR 1065.210(a) to include an example of an engine exhaust electrical heater and direction on how to simulate the efficiency of the electrical generator, to account for the work of the electrical heater. We are finalizing an efficiency of 67 percent, as this is the value used in 40 CFR 86.1869-12(b)(4)(xiii) as the baseline alternator efficiency when determining off-cycle improvements of high efficiency alternators.

vii. Fuel and Diesel Exhaust Fluid Composition in 40 CFR 1065.655
We are finalizing updates to the elemental mass fraction variables in 40 CFR 1065.655(e) to clarify that these are measured values that are used to calculate the elemental ratios in the fuel mixture. Not the default values from table 2 of 40 CFR 1065.655. We are also finalizing updates to the variable description for carbon mass fraction for equation 1065.655-25 in 40 CFR 1065.655(f)(3). This update clarifies that the carbon mass fraction used in the equation is the one determined in 40 CFR 1065.655(d).

viii. NO 2 -to-NO Converter Conversion Verification in 40 CFR 1065.378
We are finalizing an update to the NO X converter efficiency check in 40 CFR 1065.378, adding an exception as a new paragraph (e)(3) to address instances where the peak total NO 2 concentration expected during the emission test will be high and the ozonator used in the converter efficiency check cannot generate enough NO 2 to approximate this level. With this change, a lab may request EPA approval to use an NO 2 gas in lieu of generating NO 2 from NO gas using an ozonator.
High peak total NO 2 emission concentrations could occur when performing OBD system certification where, for example, a manufacturer could be testing failed components that result in high NO 2 to NO X ratio with high total NO X (around 2000 ppm) or when measuring NO X from raw exhaust where a high NO 2 spike might occur. Ozonators in chemiluminescent analyzers are generally not designed to generate that high of an NO 2 concentration during the NO X efficiency test (the step in § 1065.378(d)(3)(iv)). The update to 40 CFR part 1065 to allow the use of a high concentration NO 2 gas will alleviate these concerns.

ix. Formaldehyde Gas Blend Accuracy in 40 CFR 1065.750
We are finalizing the removal of formaldehyde from the gas mixture in 40 CFR 1065.750(a)(3)(xiii). There is no standard for formaldehyde from NIST and the preference is to gravimetrically blend it under the “other similar standards” provision in 40 CFR 1065.750(a)(4). Removing formaldehyde here increases the allowable blend tolerance from ±1 percent to ±3 percent of the NIST accepted value in addition to allowing the use of “other similar standards”, as this gas standard now must meet the requirements of 40 CFR 1065.750(a)(4). Formaldehyde did not appear on its own in 40 CFR 1065.750(a)(3), but rather as part of a gas mixture of 11 gasses in 40 CFR 1065.750(a)(3)(xiii). The gas blend in 40 CFR 1065.750(a)(3)(xiii) is for calibration of an FTIR when the FTIR additive method is used for determination of NMHC from gaseous fueled engines. Formaldehyde in an individual gas blend is already covered by 40 CFR 1065.750(a)(4). The removal of formaldehyde from the gas blend in 40 CFR 1065.750(a)(3)(xiii) now allows it to be blended based on the provisions in 40 CFR 1065.750(a)(4) and it can still be included in the gas mixture in 40 CFR 1065.750(a)(3)(xiii) for calibration of the FTIR.

x. Drift Validation of Emissions in 40 CFR 1065.672
We are finalizing an update to 40 CFR 1065.672(c) to delete occurances of “brake-specific” as it relates to emission calculations for drift validation. Paragraph (c) currently references brake-specific emission calculations in 40 CFR 1065.650. 40 CFR 1065.650 includes calculations of mass emissions in addition to brake-specific emissions. Off-cycle emission testing requires calculation Bin 1 emissions rates that are in mass per unit time. This change will make the use of 40 CFR 1065.672 more universal and apply to mass emission rates and not just brake-specific emission rates.

IV. Program Costs
In this section, we present the costs we estimate will be incurred by manufacturers and purchasers of HD vehicles impacted by the final standards. We also present the social costs of the final standards. Our analyses characterize the costs of the potential compliance pathway's technology packages described in section II.F of the preamble; however, as we note there, manufacturers may elect to comply using a different combination of HD vehicle and engine technologies than what we have modeled. We present these costs not only in terms of the upfront incremental technology cost differences between an HD BEV or FCEV powertrain and a comparable HD ICE powertrain, ^{910} but also how those costs will change in years following implementation due to learning-by-doing effects. These technology costs are presented in terms of direct manufacturing costs (DMC) and associated indirect costs. These direct and indirect costs when summed and multiplied by vehicle sales are referred to as “technology package costs” in this section, and when estimated relative to the reference case ^{911} represent the estimated costs incurred by manufacturers ( i.e., regulated entities) to comply with the final standards should a manufacturer choose to comply using the compliance pathway EPA modeled as one means of showing the standards' feasibility.
^{910} Baseline vehicles are ICE vehicles meeting the previous MY 2027 Phase 2 standards discussed in RIA Chapter 2.2.2 and the HD2027 Low NO X standards discussed in RIA Chapter 2.3.2.
^{911} As discussed in RIA Chapter 4.2.2, the reference case or scenario is a no-action scenario that represents emissions in the U.S. without the final rulemaking. Note, reference case cost estimates also include costs associated with replacing a comparable ICE powertrain baseline vehicle with a BEV or FCEV powertrain for ZEV adoption rates in the reference case.
More specifically, we break the costs into the following categories and subcategories:
1. Technology Package Costs, which are the sum of DMC and indirect costs. This may also be called the package retail price equivalent (package RPE). This includes:
a. DMC, which include the costs of materials and labor to produce a product or piece of technology.
b. Indirect costs, which include research and development (R&D), warranty, corporate operations (such as salaries, pensions, health care costs, dealer support, and marketing), and profits. ^{912} We estimate indirect costs using RPE markups.
^{912} Technology costs represent costs that manufacturers are expected to attempt to recapture via new vehicle sales. As such, profits are included in the indirect cost calculation. Clearly, profits are not a “cost” of compliance—EPA is not imposing new regulations to force manufacturers to make a profit. However, profits are necessary for manufacturers in the heavy-duty industry, a competitive for-profit industry, to sustain their operations. As such, manufacturers are expected to make a profit on the compliant vehicles they sell, and we therefore include those profits in estimating technology costs.
2. Manufacturer Costs, or “manufacturer RPE,” which is the package RPE less any applicable battery tax credits. This includes:
a. Package RPE. Traditionally, the package RPE is the manufacturer RPE in EPA cost analyses for HD standards.
b. Battery tax credit from IRA section 13502, “Advanced Manufacturing Production Credit,” which serves to reduce manufacturer costs. The battery tax credit is described further in sections ES and II of this preamble and Chapters 1 and 2 of the RIA.
3. Purchaser Costs, which are the sum of purchaser (1) upfront costs (which include the upfront vehicle costs (manufacturer (also referred to as purchaser) RPE plus applicable Federal excise and state sales taxes less any applicable vehicle tax credit) plus applicable EVSE costs), and (2) operating costs. This includes:
a. Manufacturer RPE. In other words, the purchaser incurs the manufacturer's package costs less any applicable battery tax credits. We refer to this as the “manufacturer RPE” in relation to the manufacturer and, at times, the “purchaser RPE” in relation to the purchaser. These two terms are equivalent in this analysis.
b. Vehicle tax credit from IRA section 13403, “Qualified Commercial Clean Vehicles,” which serve to reduce purchaser costs. The vehicle tax credit is described further in sections I and II of this preamble and Chapters 1 and 2 of the RIA.
c. Electric Vehicle Supply Equipment (EVSE) costs, which are the costs associated with charging equipment installed at depots. Our EVSE cost estimates include indirect costs so are sometimes referred to as “EVSE RPE.”
d. EVSE tax credit from IRA section 13404, “Alternative Fuel Refueling Property Credit,” which serve to reduce purchaser costs. The EVSE tax credit is described further in sections I and II of this preamble and Chapters 1 and 2 of the RIA.
e. Federal excise tax and state sales tax, which are upfront costs incurred for select vehicles for excise tax and for all heavy-duty vehicles for sales tax.
f. Purchaser upfront vehicle costs, which include the manufacturer (also referred to as purchaser) RPE plus EVSE costs plus applicable Federal excise and state sales taxes less any applicable vehicle tax credits.
g. Operating costs, which include fuel costs (including costs for diesel, gasoline, CNG, electricity [which varies depending on whether the vehicle is charged at a depot or at a public charging facility], and hydrogen), costs for diesel exhaust fluid (DEF), maintenance and repair costs, insurance, battery replacement costs, ICE vehicle engine rebuild costs, and EVSE replacement costs.
4. Social Costs, which are the sum of package RPE, EVSE RPE, and operating costs and computed on at a fleet level on an annual basis. Note that fuel taxes, Federal excise tax, state sales tax and battery, vehicle and EVSE tax credits are not included in the social costs. Taxes, registration fees, and tax credits are transfers as opposed to social costs. Social costs includes:
a. Package RPE (which excludes applicable tax credits).
b. EVSE RPE (which excludes applicable tax credits).
c. Operating costs which include pre-tax fuel costs, electricity costs (including those associated with electrification infrastructure and a public charging network), DEF costs, insurance, maintenance and repair costs, battery replacement costs, ICE vehicle engine rebuild costs, and EVSE replacement costs.
We describe these costs and present our cost estimates in the text that follows, after we discuss the relevant IRA tax credits and how we have considered them in our estimates. All costs are presented in 2022 dollars (2022$), unless noted otherwise. For both the reference and final standards scenarios, we used the MOVES outputs discussed in RIA Chapter 4 ^{913} to compute technology costs and operating costs as well as social costs on an annual basis. The costs and tax credits are estimated on a per vehicle basis and do not change between the reference and final standards cases, but the estimated vehicle populations of the ICE vehicles, BEVs or FCEVs do change between the reference and final standards cases. The modeled potential compliance pathway's technology packages project an increase in BEV and FCEV sales and a decrease in ICE vehicle sales in the final standards case compared to the reference case and these changes in vehicle populations are the determining factor for total cost differences between the reference and final standards cases.
^{913} As discussed in RIA Chapter 4.2.2, the final standards scenario or case represents emissions in the U.S. with the final HD GHG Phase 3 standards.
In general, the final rule cost analysis methodology mirrors the approach we took for the proposal, with some updates to our modeling. Our final rule analysis was conducted using the latest dollar value, 2022$, which represents an update from the 2021$ used in the NPRM analysis. Many of our direct manufacturing costs of technologies have been revised based on consideration of comments and data received, as discussed in more detail in preamble section II. Similarly, the operating costs including fuel prices, electricity prices (now for both depot and public charging), and hydrogen prices have been updated, including to reflect the latest projections, as described in RIA Chapter 2. The purchaser costs for the final rule reflect the Move to first inclusion of insurance costs, sales tax, and the Federal excise tax as applicable, also described in that Chapter 2. The maintenance and repair costs for vocational ICE vehicles have been reduced, after consideration of comments. This change led to a decrease in the M&R costs of the BEVs and FCEVs accordingly, ^{914} but in addition we applied higher M&R costs for BEVs and FCEVs in the early years of the Phase 3 program. These changes are explained in more detail in RIA Chapter 2. Finally, battery replacement, ICE vehicle engine rebuilds, and EVSE replacements are additional operating costs in the final rule that were not included in the NPRM. It is worth noting that, as described in preamble section V, the overall cost savings of the final program are lower than the proposal due to the increased number of ZEVs considered in the reference case (reflecting manufacturers' compliance with the ACT program in California and in the seven other states and a lower, non-zero level of ZEV adoption in the other 42 states as discussed in preamble section V.A) and a slower phase in of final standards.
^{914} As described in the NPRM and in this section IV, our methodology to estimate BEV and FCEV maintenance costs involves multiplying diesel vehicle maintenance costs by a factor based on cited research.
Note that the analysis that follows sometimes presents undiscounted costs and sometimes presents discounted costs. We discount future costs and benefits to properly characterize their value in the present or, as directed by the Office of Management and Budget in the currently applicable Circular A-4 (2003), in the year costs and benefits begin. Also, in that same guidance, OMB directs use of both 3 and 7 percent discount rates as we have done with some exceptions. ^{915} While we were conducting the analysis for this rule, OMB finalized an update to Circular A-4 (2023), ^{916} in which it recommended the general application of a 2-percent discount rate to costs and benefits. The January 1, 2025, effective date of the updated Circular A-4 means that the updated Circular A-4 does not apply to this rulemaking, we have also included 2 percent discount rates in our analysis. Present and annualized values are abbreviated as PV and AV throughout the document tables in this section.
^{915} See Advisory Circular A-4, Office of Management and Budget, September 17, 2003.
^{916} See updated Advisory Circular A-4, Office of Management and Budget, November 9, 2023. The effective date of the updated Circular is March 1, 2024, for regulatory analyses received by OMB in support of proposed rules, interim final rules, and direct final rules, and January 1, 2025, for regulatory analyses received by OMB in support of other final rules. In other words, the updated Circular applies to the regulatory analyses for draft proposed rules that are formally submitted to OIRA after February 29, 2024, and for draft final rules that are formally submitted to OIRA after December 31, 2024.
We received various costs-related comments for vehicle costs, EVSE costs, state sales tax, Federal excise tax, maintenance and repair, insurance, fuel and charging costs, as well as comments regarding the implications of the IRA and BIL. Many of these comments are summarized and responded to in preamble section II, and the detailed comments and our responses are in RTC sections 2 and 3. Any applicable changes to costs discussed in those sections and RIA Chapter 2 are reflected in the rest of this preamble section and in RIA Chapter 3.
In addition, we received comments on learning and RPE, and those comments are addressed in this section and in RTC section 12. Briefly, for RPE, commenters argued that EPA used too low of a factor and based the RPE on dated information, but commenters did not provide better, more recent, or additional data. We therefore continue to consider our NPRM approach to be appropriate and provide more recent supporting data in section 14.2 of the RTC. For the learning curve used in the NPRM, there was generally agreement across commenters on this issue that some accounting for savings reflecting learning was appropriate. However, some commenters acknowledged savings over time attributed to learning by doing but maintained that the learning process has commenced already since heavy-duty BEVs are already being produced and sold. After consideration of comments that BEV learning has begun, for the final rule, we shifted the battery learning onto the flatter portion of the learning curve used in the proposal as shown in Figure IV-1. Details of this adjustment are in Chapter 2.4 of the RIA.
We also received comment about inclusion of dealer costs and we estimate them as a portion of RPE in the indirect manufacturing costs of technology package costs in the final rule, as discussed in section IV.B.2 and in Chapter 3 of the RIA.

A. IRA Tax Credits
Our cost analysis quantitatively includes consideration of three IRA tax credits, specifically the “Advanced Manufacturing Production Credit,”, “Qualified Commercial Clean Vehicles,”, and “Alternative Fuel Refueling Property Credit” applied to battery cost, vehicle purchase cost, and EVSE purchase cost respectively (sections II.E.1, II.E.2, II.E.3, and II.E.4 of the preamble and Chapters 1.3.2 and 2.4.3 of the RIA). We note that a detailed discussion of how these tax credits were considered in our analysis of costs in our technology packages may be found in section II.E of the preamble and Chapter 2.4.3 of the RIA. The battery tax credit is expected to reduce manufacturer costs, and in turn purchaser costs, as discussed in section IV.C. The vehicle tax credit and EVSE tax credit are also expected to reduce purchaser costs, as discussed in section IV.D.2. For the cost analysis discussed in this section IV, the battery tax credit, vehicle tax credit and EVSE tax credit were estimated for MYs 2027 through 2032 and then aggregated for each MOVES source type and regulatory class.

B. Technology Package Costs
Technology package costs include estimated technology costs associated with compliance with the final MY 2027 and later CO 2 emission standards (see Chapter 3 of the RIA) based on the projected technology packages modeled for the potential compliance pathway. Individual technology piece costs are presented in Chapters 2 of the RIA. In general, for the first MY of each final emission standard, the per vehicle individual technology piece costs consist of the DMC estimated for each vehicle in the model year of the final standards and are used as a starting point in estimating both the technology package costs and the total incremental costs. Following each year of when costs are first incurred, we have applied a learning effect to represent the cost reductions expected to occur via the “learning by doing” phenomenon. ^{917} However, for the final rule, we started the BEV learning scale in MY 2026, rather than MY 2027 after consideration of comments received that BEV learning may begin before MY 2027. This was implemented by recalculating the BEV learning scalars, such that MY 2027 is equal to a learning value of 1 but retaining the growth rate as if the scalar started in MY 2026. See RIA Chapter 3.2.1 for a more detailed description of how this was implemented. The “learning by doing” phenomenon is the process by which doing something over and over results in learning how to do that thing more efficiently which, in turn, leads to reduced resource usage, i.e., cost savings. The DMC as modified year-by-year by a learning factor provides a year-over-year cost for each technology as applied to new vehicle production, which EPA then used to calculate total technology package costs of the final standards.
^{917} “Cost Reduction through Learning in Manufacturing Industries and in the Manufacture of Mobile Sources, Final Report and Peer Review Report,” EPA-420-R-16-018, November 2016.
This technology package cost calculation approach presumes that the projected technologies ( i.e., those in the particular technology package developed by EPA as a potential compliance pathway to support the feasibility of the final standards) will be purchased by the vehicle original equipment manufacturers (OEMs) from their suppliers. So, while the DMC estimates for the OEM in section IV.B.1 include the indirect costs and profits incurred by the supplier, the indirect cost markups we apply in section IV.B.2 cover the indirect costs incurred by OEMs to incorporate the new technologies into their vehicles and the profit margins for the OEM typical of the heavy-duty vehicle industry. To address these OEM indirect costs, we then applied industry standard RPE markup factors to the DMC to estimate indirect costs associated with the new technology. These factors represent an average price, or RPE, for products assuming all products recapture costs in the same way. We recognize that this is rarely the actual case since manufacturers typically have different pricing strategies for different products. For that reason, the RPE should not be considered the price for each individual technology package but instead should be considered more like the average price needed to recapture both costs and profits to support ongoing business operations. Both the learning effects applied to direct costs and the application of markup factors to estimate indirect costs are consistent with the cost estimation approaches used in EPA's past HD GHG regulatory programs. ^{918} The sum of the DMC and indirect costs represents our estimate of technology “package costs” or “package RPE” per vehicle year-over-year. These per vehicle technology package costs are multiplied by estimated sales for the final standards and reference scenarios. Then the total technology package-related costs for manufacturers (total package costs or total package RPE) associated with the final HD GHG Phase 3 standards is the difference between the final standards and reference scenarios.
^{918} See the Phase 1 heavy-duty greenhouse gas rule (76 FR beginning at 57319, September 15, 2011); the Phase 2 heavy-duty greenhouse gas rule (81 FR 73863, October 25, 2016).

1. Direct Manufacturing Costs
To produce a unit of output, manufacturers incur direct and indirect manufacturing costs. DMC include cost of materials and labor costs. Indirect manufacturing costs are discussed in the following section, IV.B.2. The DMCs presented here include the incremental technology piece costs associated with compliance with the final standards as compared to the technology piece costs associated with the comparable baseline vehicle. ^{919} Our modeled potential compliance pathway to meet the final standards are technology packages that include both ICE vehicle and ZEV technologies. In our analysis, the ICE vehicles include a suite of technologies that represent a vehicle that meets the previous MY 2027 Phase 2 CO 2 emission standards. Therefore, our direct manufacturing costs for the ICE vehicles are considered to be $0 because our projected technology package did not add additional CO 2 -reducing technologies to the ICE vehicles beyond those in the baseline vehicle (we note that even though such improvements were not included in the modeled potential compliance pathway, additional improvements and technologies for vehicles with ICE are feasible and manufacturers could utilize such technologies to meet the final standards; see preamble section II.F for examples of additional potential compliance pathways that include technologies for vehicles with ICE with such improvements). The DMC of the BEVs or FCEVs could be thought of as the technology piece costs of replacing a comparable ICE powertrain baseline vehicle with a BEV or FCEV powertrain. Note, reference case costs estimates also include costs associated with replacing a comparable ICE powertrain baseline vehicle with a BEV or FCEV powertrain for ZEV adoption rates in the reference case.
^{919} Baseline vehicles are ICE vehicles meeting the previous MY 2027 Phase 2 standards discussed in RIA Chapter 2.2.2 and the HD2027 Low NO X standards discussed in RIA Chapter 2.3.2.
We have estimated the DMC by estimating the cost of removing the cost of the ICE powertrain, and adding the cost of a BEV or FCEV powertrain, as presented in Chapter 2 and 3 of the RIA. In other words, net incremental costs reflect adding the total costs of components added to the powertrain to make it a BEV or FCEV, as well as removing the total costs of components removed from a comparable ICE baseline vehicle to make it a BEV or FCEV.
Chapter 4 of the RIA contains a description of the MOVES vehicle source types and regulatory classes. In short, we estimate costs in MOVES for vehicle source types that have both regulatory class populations and associated emission inventories. Also, throughout this section, LHD refers to light heavy-duty vehicles, MHD refers to medium heavy-duty vehicles, and HHD refers to heavy heavy-duty vehicles. ^{920}
^{920} As explained in preamble section V, MOVES vehicle definitions encompass the regulatory subcategories of the final standards but are not identical to them.
The direct costs are then adjusted to account for learning effects on BEV, FCEV and ICE vehicle powertrains on an annual basis going forward beginning with the first year of the analysis, e.g., MY 2027, for the final standards and reference scenarios. Overall, under the modeled potential compliance pathway we anticipate the number of ICE powertrains (including engines and transmissions) manufactured each year will decrease as more ZEVs enter the market. Due to decreasing production of ICE powertrains, this scenario may lead to slower cost reductions going forward than would typically occur from learning-by-doing in the context of component costs for ICE powertrains. On the other hand, with the inclusion of new hardware costs projected in our HD2027 final rule's modeled potential compliance pathway to meet the HD2027 emission standards, we expect learning effects will reduce the incremental cost of these technologies. Chapter 2 and 3 of the RIA includes a detailed description of the approach used to apply learning effects in this analysis and reflects consideration of the comments received on our approach to learning. The resultant DMC per vehicle and how those costs decrease over time on a fleet level are presented in section IV.E.1 of this preamble.

2. Indirect Manufacturing Costs
Indirect manufacturing costs are all the costs associated with producing the unit of output that are not direct manufacturing costs—for example, they may be related to research and development (R&D), warranty, corporate operations (such as salaries, pensions, health care costs, dealer support, and marketing) and profits. An example of a R&D cost for these final standards includes the engineering resources required to develop a battery state of health monitor as described in preamble section III.B.1. An example of a warranty cost is the future cost covered by the manufacturer to repair defective BEV or FCEV components and meet the warranty requirements discussed in section III.B.2. Indirect costs are generally recovered by allocating a share of the indirect costs to each unit of goods sold. Although direct costs can be allocated to each unit of goods sold, it is more challenging to account for indirect costs allocated to a unit of goods sold. To ensure that regulatory analyses capture the changes in indirect costs, markup factors (which relate total indirect costs to total direct costs) have been developed and used by EPA and other stakeholders. These factors are often referred to as RPE multipliers and are typically applied to direct costs to estimate indirect costs. RPE multipliers provide, at an aggregate level, the proportionate share of revenues relative shares of revenue where:
Revenue = Direct Costs + Indirect Costs
Revenue/Direct Costs = 1 + Indirect Costs/Direct Costs = RPE multiplier
Resulting in:
Indirect Costs = Direct Costs × (RPE−1)
If the relationship between revenues and direct costs ( i.e., RPE multiplier) can be shown to equal an average value over time, then an estimate of direct costs can be multiplied by that average value to estimate revenues, or total costs. Further, that difference between estimated revenues, or total costs, and estimated direct costs can be taken as the indirect costs. Cost analysts and regulatory agencies have frequently used these multipliers to predict the resultant impact on costs associated with manufacturers' responses to regulatory requirements and we are using that approach in this analysis.
The final cost analysis estimates indirect costs by applying the RPE markup factor used in past EPA rulemakings (such as those setting GHG standards for heavy-duty vehicles and engines). ^{921} The markup factors are based on company filings with the Securities and Exchange Commission for several engine and engine/vehicle manufacturers in the heavy-duty industry. ^{922} The RPE factors for the HD vehicle industry as a whole are shown in Table IV-1. Also shown in Table IV-1 are the RPE factors for light-duty vehicle manufacturers. ^{923}
^{921} 76 FR 57322; 81 FR 73863.
^{922} Heavy Duty Truck Retail Price Equivalent and Indirect Cost Multipliers, Draft Report, July 2010.
^{923} Rogozhin,A., et al., Using indirect cost multipliers to estimate the total cost of adding new technology in the automobile industry. International Journal of Production Economics (2009), doi:10.1016/j.ijpe.2009.11.031.
For this analysis, EPA based indirect cost estimates for diesel and compressed natural gas (CNG) regulatory classes on the HD Truck Industry RPE value shown in Table IV-1. We are using an RPE of 1.42 to compute the indirect costs associated with the replacement of a diesel-fueled or CNG-fueled powertrain with a BEV or FCEV powertrain. For this analysis, EPA based indirect cost estimates for gasoline regulatory classes on the LD Vehicle RPE value shown in Table IV-1 because the engines and vehicles more closely match those built by LD vehicle manufacturers. We are using an RPE of 1.5 to compute the indirect costs associated with the replacement of a gasoline-fueled powertrain with a BEV or FCEV powertrain. The heavy-duty vehicle industry is becoming more vertically integrated and the direct and indirect manufacturing costs we are analyzing are those that reflect the technology packages costs OEMs would try to recover at the end purchaser, or retail, level. For that reason, we believe the two respective vehicle industry RPE values represent the most appropriate factors for this analysis. EPA received comments on RPE and commenters argued that EPA used too low of a factor and based the RPE on dated information. After consideration of the comment, EPA has clarified that the RPE accounts for dealer costs, as described in this section. Including this clarification, EPA finds that the multiplier we used is appropriate and based on robust data and analysis. Moreover, commenters did not provide better, more recent, or additional data to update values for RPE, and EPA is not aware of any such data. Therefore, we continue with the approach used in the NPRM.
EPA received comment that dealers may encounter new costs when new products are introduced (which we refer to in this rulemaking as “dealer new vehicle selling costs”), such as technician training to repair ZEVs. After consideration of comment, EPA is clarifying that we accounted for these costs in the RPE multipliers. ^{924} The heavy-duty RPE in Table IV-1 is based on values from the report, “Heavy Duty Truck Retail Price Equivalent and Indirect Cost Multipliers,” ^{925} which contains detailed cost contributor subcategories, including costs associated with dealer support. Within the dealer support costs, the contribution of new dealer selling costs in the RPE mark-up includes a 6 percent markup over manufacturing cost for dealer new vehicle selling costs, from the “Other” cost contributor shown in Table IV-1.
^{924} See also preamble section II.E.5 explaining that our cost savings estimates for maintenance and repair reflect a later start date for BEVs and FCEVs to account for the need for initial technician training.
^{925} Heavy Duty Truck Retail Price Equivalent and Indirect Cost Multipliers, Draft Report, July 2010.
Dealer new vehicle selling costs for CY 2027 through 2032 are shown in Table IV-2. We calculated the dealer new vehicle selling costs as 6 percent of the total direct cost calculated for the final standards. Table IV-2 also shows the undiscounted sum of dealer new vehicle selling costs from CY 2027 to 2032.

3. Vehicle Technology Package RPE
Table IV-3 presents the total fleet-wide incremental technology costs estimated for the final standards relative to the reference case for the projected adoption of ZEVs in our technology package on an annual basis. As previously explained in this section, the costs shown in Table IV-3 reflect marginal direct and indirect manufacturing costs of the technology package for the final standards as compared to the baseline vehicle.
It is important to note that these are costs and not prices. As we explained previously in this section, we do not attempt to estimate how manufacturers will price their products in the technology package costs. Manufacturers may pass costs along to purchasers via price increases that reflect actual incremental costs to manufacture a ZEV when compared to a comparable ICE vehicle. However, manufacturers may also price products higher or lower than what would be necessary to account for the incremental cost difference. EPA is not attempting to mirror, predict, or otherwise approximate individual companies' marketing strategies in estimating costs for the modeled potential compliance pathway. ^{926}
^{926} We have likewise noted that our modeled potential compliance pathway is just one potential means manufacturers may use to meet the final standards. By law, EPA must consider the compliance costs of standards, and to do so, must develop a potential compliance pathway for such standards in order to estimate those costs.

C. Manufacturer Costs

1. Relationship to Technology Package RPE
The manufacturer costs in EPA's past HD GHG rulemaking cost analyses on an average-per-vehicle basis was only the average-per-vehicle technology package RPE described in section II.F. However, in the cost analysis for this final rule, we are also taking into account the IRA battery tax credit in our estimates of manufacturer costs (also referred to in this section as manufacturer's RPE), as we expect the battery tax credit to reduce manufacturer costs, and in turn purchaser costs. The DMCs without the battery tax credit are included in section IV.E.1.

2. Battery Tax Credit
Table IV-4 shows the annual estimated fleet-wide battery tax credits from IRA section 13502, “Advanced Manufacturing Production Credit,” for the final standards relative to the reference case in 2022$ under the potential compliance pathway. These estimates were based on the detailed discussion in RIA Chapter 2 of how we considered battery tax credits. Both BEVs and FCEVs include a battery in the powertrain system that may meet the IRA battery tax credit requirements if the applicable criteria are met. The battery tax credits begin to phase down starting in CY 2030 and expire after CY 2032.

3. Manufacturer RPE
The manufacturer RPE for BEVs is calculated by subtracting the battery tax credit in Table IV-4 from the corresponding technology package RPE from Table IV-3 and the resultant manufacturer RPE is shown in Table IV-5. Table IV-5 reflects learning effects on vehicle package RPE and battery tax credits from CY 2027 through 2055. The sum of the vehicle package RPE and battery tax credits for each year is shown in the manufacturer RPE column. The difference in manufacturer RPE under the potential compliance pathway between the final standards and reference case is presented in Table IV-5.

D. Purchaser Costs

1. Purchaser RPE
The purchaser RPE is the estimated upfront vehicle cost paid by the purchaser prior to considering the IRA vehicle tax credits. Note, as explained in section IV.C, we do consider the IRA battery tax credit in estimating the manufacturer RPE, which in this analysis we then consider to be equivalent to the purchaser RPE because we assume full pass-through of the IRA battery tax credit from the manufacturer to the purchaser. In other words, in this analysis, the manufacturer RPE and purchaser RPE are equivalent terms. The purchaser RPEs reflect the same values as the corresponding manufacturer RPEs presented in section IV.C.3.

2. Vehicle Purchase Tax Credit
Table IV-6 shows the annual estimated vehicle tax credit for BEVs and FCEVs from IRA section 13403, “Qualified Commercial Clean Vehicles,” for the final standards relative to the reference case, in 2022$ under the potential compliance pathway. These estimates were based on the detailed discussion in RIA Chapter 2 of how we considered vehicle tax credits. The vehicle tax credits carry through to MY 2032 with the value diminishing over time as vehicle costs decrease due to the learning effect as shown in RIA Chapter 2. Beginning in CY 2033, the tax credit program expires.

3. Electric Vehicle Supply Equipment Costs
As we included in the analysis for the NPRM, we accounted for the EVSE hardware and associated installation costs for equipment installed at depots, as described in Chapter 2.6 of the RIA. For the final rule, we have also included BEVs that would solely depend on public charging in the technology package to support the final standards. The purchasers of these vehicles would not incur an upfront cost to purchase and install EVSE. As discussed in RIA Chapter 2.4.4.2 for public charging and in Chapter 2.5.3 for FCEVs, we included the respective infrastructure cost in our retail electricity prices per kwh and retail prices per kg of hydrogen in our operating costs. These end user costs include the production, distribution, storage, and dispensing at a public charging or fueling station. This approach is consistent with the method we use in HD TRUCS for comparable ICE vehicles, where the equivalent diesel fuel costs are included in the diesel fuel price instead of accounting for the costs of fuel stations separately.
The depot EVSE cost estimates include both direct and indirect costs and are sometimes referred to in these final standards as EVSE RPE costs. As discussed in RIA Chapter 2.6.2, we increased the depot EVSE costs for the final rule to reflect consideration of the cost data we received in comments. For these EVSE cost estimates, we project that up to two vehicles can share one DCFC port if there is sufficient dwell time for both vehicles to meet their daily charging needs for vocational vehicles and up to four for tractors. ^{927} While fleet owners may also choose to share Level 2 chargers across vehicles, we are conservatively assigning one Level 2 charger per vehicle. As discussed in the RIA, we assume that EVSE costs are incurred by purchasers, i.e., heavy-duty vehicle purchasers/owners. We analyzed EVSE costs in 2022$ on a fleet-wide basis under the potential compliance pathway for this analysis. The annual costs associated with EVSE in the final standards relative to the reference case are shown in Table IV-7.
^{927} We note that for some of the vehicle types we evaluated, more than two vehicles could share a DCFC port and still meet their daily electricity consumption needs.

4. EVSE Tax Credit
Table IV-8 shows the annual estimated EVSE tax credit from IRA section 13404, “Alternative Fuel Refueling Property Credit,” for the final standards relative to the reference case, in 2022$ under the potential compliance pathway. These estimates were based on the detailed discussion in RIA Chapter 2 of how we considered EVSE tax credits. The EVSE tax credits carry through to MY 2032. Beginning in CY 2033, the tax credit program expires.

5. Federal Excise Tax, State Sales Tax
As discussed in preamble section II.E.5, in the NPRM we did not account for the upfront taxes paid by the purchaser of the vehicle. Several commenters raised concerns about additional costs that were not included in HD TRUCS for the proposal. The concern raised by the greatest number of commenters was the additional cost from Federal excise tax and state sales tax because of higher BEV and FCEV upfront vehicle cost under the potential compliance pathway. We agree with the commenters that the cost analysis should include the impact of the FET and State Sales Tax on purchasers. For the final rule, we added FET and state sale tax as a part of the purchaser upfront vehicle cost calculation. A FET of 12 percent was applied to the upfront powertrain technology retail price equivalent for Class 8 heavy-duty vehicles and all tractors, as discussed in RIA Chapter 2.4.3.2. Similarly, a state tax of 5.02 percent, the average sales tax in the U.S. for heavy-duty vehicles discussed in RIA Chapter 2.4.3.1, was applied to the upfront powertrain technology retail price equivalent and was added to all vehicles for the final rule analysis. Table IV-9 shows the estimated state sales tax and Federal excise tax by calendar year for the final standards relative to the reference case.

6. Purchaser Upfront Costs
The expected upfront incremental costs to the purchaser include the purchaser upfront vehicle costs plus the purchaser upfront EVSE costs as applicable, after tax credits and including FET and sales state tax, under the potential compliance pathway. In other words, the estimated purchaser upfront incremental costs include the purchaser RPE discussed in section IV.D.1 less the vehicle tax credit discussed in section IV.D.2 plus the EVSE RPE in IV.D.3 less the EVSE tax credit in section IV.D.4 and plus the Federal excise tax and state sales tax in section IV.D.5. Table IV-10 shows the estimated incremental upfront purchaser costs for BEVs and FCEVs by calendar year for the final standards relative to the reference case. Note that EVSE costs are associated only with BEVs using depot charging; FCEVs and BEVs solely using public charging do not have any associated upfront EVSE costs because those costs are reflected in the public hydrogen refueling and charging electricity costs.

7. Operating Costs
We have estimated six types of operating costs associated with the final HD GHG Phase 3 emission standards and our potential compliance pathway's projected technology packages that includes ICE, BEV and FCEV powertrains. These six types of operating costs include changes in fuel costs of BEVs and FCEVs compared to comparable ICE vehicles, avoided diesel exhaust fluid (DEF) consumption by BEVs and FCEVs compared to comparable diesel-fueled ICE vehicles, reduced maintenance and repair costs of BEVs and FCEVs as compared to comparable ICE vehicles, changes to insurance costs of BEVs and FCEVs as compared to comparable ICE vehicles, battery replacement and ICE engine rebuild costs and EVSE replacement costs. To estimate fuel, DEF and maintenance and repair costs of ICE vehicles, EPA used the results of MOVES runs, as discussed in RIA Chapter 4, to estimate costs associated with fuel consumption, DEF consumption, and VMT. Similarly, the electricity, hydrogen fuel, and maintenance and repair costs of BEVs and FCEVs were calculated based on the MOVES outputs for fuel/electricity consumption and VMT. EPA added insurance costs for all vehicle types for the final rule analysis based on the incremental upfront cost (purchaser RPE) of the vehicle and calculated for each year a vehicle is operating. For the final rule cost analysis in this section of the preamble, we also accounted for the costs to rebuild diesel engines and battery replacement costs and EVSE replacement costs. We have estimated the net effect on fuel costs, DEF costs, maintenance and repair costs, insurance, battery replacements, engine rebuilds, and EVSE replacements. We describe our approach in this section (IV.D.7).
Additional details on our methodology and estimates of operating costs per mile impacts are included in RIA Chapter 3.4 as well as insurance, ICE engine rebuilds, BEV battery replacement, and EVSE replacement costs. Chapter 4 of the RIA contains a description of the MOVES vehicle source types and regulatory classes. In short, we estimate costs based on MOVES vehicle source types that have both regulatory class populations and associated emission inventories.

i. Costs Associated With Fuel Usage
Costs associated with fuel usage are presented in two ways: on an annual basis for aggregate costs of all vehicles and on a per mile basis for a specific model year in each MOVES source type and regulatory class. The annual costs are presented in section IV.E.3 to show the overall fuel costs of the policy case compared to the reference case for pre-tax fuel. The costs on a per mile basis are given as an example what a specific MY vehicle in a given MOVES source type and regulatory class could estimate to pay on a per mile basis based on the VMT and total cost of all fuel at retail prices used from the first year the vehicle is in operation until CY 2055.
To determine the total costs associated with fuel usage for MY 2032 vehicles, the fuel usage for each MOVES source type and regulatory class was multiplied by the fuel price from the AEO 2023 reference case for diesel, gasoline, and CNG prices over from CY 2032 to CY 2055. ^{928} Fuel costs per gallon and kWh are discussed in RIA Chapter 2. We used retail fuel prices since we expect that retail fuel prices are the prices paid by owners of these ICE vehicles. For electric vehicle costs, the electricity prices used estimates of the cost per kWh of charging at depot and public charge points along with estimates of the share of charging by each source type at those respective charge points. The development of the costs per kWh is presented in RIA Chapter 2.4.4.2 and the values used to estimate program costs are shown in Table IV-11. For hydrogen vehicle fuel costs, we used the hydrogen prices presented in RIA Chapter 2.5.3.1 and presented in RIA Chapter 3 and shown in Table IV-12. To calculate the average cost per mile of fuel usage for each scenario, MOVES source type and regulatory class, EPA divided the fuel cost by the VMT for each of the MY 2032 vehicles starting in CY 2032 until CY 2055. The estimates of fuel cost per mile for MY 2032 vehicles under the final rule are shown in Table IV-13, Table IV-14, and Table IV-15 for 2 percent, 3 percent and 7 percent discounting, respectively. Values shown as a dash (“-”) in Table IV-13, Table IV-14, and Table IV-15 represent cases where a given MOVES source type and regulatory class did not use a specific fuel type for MY 2032 vehicles. ^{929}
^{928} Reference Case Projection Tables, U.S. Energy Information Administration. Annual Energy Outlook 2023.
^{929} For example, there were no vehicles in our MOVES runs for the transit bus source type in the LHD45 regulatory class that were diesel-fueled, so the value in the table is represented as a dash (“-”).
The number of ICE vehicles decrease and ZEV increase in the final standards case compared to the reference case therefore the fuel costs for all vehicles are less in final standards case when computed on an annual basis as shown in section IV.E.3 for pre-tax fuel.

ii. Costs Associated With Diesel Exhaust Fluid
DEF consumption costs in heavy-duty vehicles were estimated in the HD2027 final rule. ^{930} We are applying the same methodology in this analysis to estimate the total costs of DEF under the final HD GHG Phase 3 standards. Costs associated with DEF are presented in two ways in a similar manner for fuel costs: on an annual basis for aggregate costs of all vehicles and on a per mile basis for a specific model year in each MOVES source type and regulatory class. The annual costs are presented in section IV.E.3 to show the overall DEF costs of the policy case compared to the reference case. The costs on a per mile basis presented here are given as an example what a specific MY vehicle in a given MOVES source type and regulatory class could estimate to pay on a per mile basis based on the VMT and total cost of all DEF used from the first year the vehicle is in operation until CY 2055. Note that the DEF consumption rates do not change between the policy and reference scenarios, but the total number of miles traveled by vehicles consuming DEF does change between scenarios. Therefore, the DEF costs per mile are intended to allow a vehicle user an estimate typical costs related to DEF usage and the aggregate annual costs show the impacts of the final standards compared and reference case.
^{930} 88 FR 4296, January 24, 2023.
An example of cost estimates of DEF on a per mile basis for MY 2032 vehicles is provided in Table IV-16, Table IV-17, and Table IV-18 for 2 percent, 3 percent, and 7 percent discounting, respectively. DEF costs per mile were estimated by first the totaling DEF costs for MY 2032 vehicles by taking the DEF usage for each MOVES source type and regulatory class and multiplying by the DEF price from CY 2032 to CY 2055. ^{931} Then to calculate the average cost of DEF per mile, the total DEF cost was divided by the total VMT for each MOVES Source Type and regulatory class of MY 2032 vehicles from CY 2032 to CY 2055. The DEF cost was computed for the final standards case under the potential compliance pathway for each fuel type. Several source types and regulatory classes contain no diesel-fueled ICE vehicles and therefore no DEF consumption costs. Values shown as a dash “-” in Table IV-16, Table IV-17, and Table IV-18 represent cases where a given MOVES source type and regulatory class did not use a specific fuel type. Table IV-16, Table IV-17, and Table IV-18 have values of 0 for gasoline, electricity, CNG and hydrogen as those vehicles do not consume any DEF and therefore do not incur any cost per mile.
^{931} This analysis uses the DEF prices presented in the NCP Technical Support Document (see “Nonconformance Penalties for On-highway Heavy-duty Diesel Engines: Technical Support Document,” EPA-420-R-12-014) with growth beyond 2042 projected at the same 1.3 percent rate as noted in the NCP TSD. Note that the DEF prices used update the NCP TSD's 2011 prices to 2022$.
The number of diesel vehicles decrease in the final standards case compared to the reference case therefore the total DEF costs for all vehicles are less in final standards case when computed on an annual basis as shown in section IV.E.3.

iii. Costs Associated With Maintenance and Repair
We assessed the estimated maintenance and repair costs of HD ICE vehicles, BEVs and FCEVs for the reference case and the final standards case under the potential compliance pathway. After consideration of comments, we have reduced the maintenance and repair costs for vocational ICE vehicles in the final rule. This change led to a decrease in the M&R costs of the BEVs and FCEVs accordingly. We made further changes to M&R costs for BEVs and FCEVs in the early years of the Phase 3 program such that the M&R savings do not accrue as quickly as they did in our NPRM analysis. The results of our analysis show that maintenance and repair costs associated with HD BEVs and FCEVs are estimated to be lower than maintenance and repair costs associated with comparable ICE vehicles. The methodology for how we calculated maintenance and repair costs were estimated is discussed in RIA Chapter 2.3.4.2, 2.4.4.1, 2.5.3.2 and Chapter 3 of the RIA.
Maintenance and repair cost in cents per mile were computed in a similar manner as fuel and DEF costs. The cost of maintenance and repairs in cents per mile for MY 2032 vehicles in each MOVES source type and regulatory class by fuel type for the final standards are shown in Table IV-19, Table IV-20, and Table IV-21 for 2-percent, 3-percent and 7-percent discount rates, respectively. Table IV-19, Table IV-20, and Table IV-21 demonstrate higher costs per mile of ICE vehicles compared to ZEV. The number of ICE vehicles decrease and ZEV increase in the final standards case compared to the reference case therefore the total maintenance and repair costs for all vehicles are less in final standards case when computed on an annual basis as shown in section IV.E.3.

iv. Costs Associated With Insurance
As discussed in preamble section II.E.5, we did not take into account the cost of insurance on the user in the NPRM. A few commenters suggested we should consider the addition of insurance cost because the incremental cost of insurance for the ZEVs will be higher than for ICE vehicles. We agree that insurance costs may differ between vehicles, and this is a cost that will be seen by the operator. Therefore, for the final rule analysis, we included the incremental insurance costs of a ZEV relative to a comparable ICE vehicle under the potential compliance pathway by incorporating an annual insurance cost equal to 3 percent of initial upfront vehicle technology RPE cost, as described in section II.E.5 of the preamble. This annual cost was applied for each operating year of the vehicle.
To calculate the year over year insurance costs, 3 percent of the initial vehicle technology package RPE was multiplied by estimated sales for the final standards and reference case and were computed each year a vehicle was operational. Then the difference between the final standards case and reference case insurance costs are shown on an annual basis in Table IV-22.

v. Costs Associated With State Registration Fees on ZEVs
As discussed in preamble section II.E.5, we did not take into account the cost of state registration fees on ZEVs in the NPRM. Commenters suggested we should consider the addition of state registration fees on ZEVs because some states have adopted state ZEV registration fees in some cases to replace gasoline and diesel road tax revenue. Currently, many states do not have any additional registration fee for EVs. For the states that do, the registration fees are generally between $50 and $225 per year. While EPA cannot predict whether and to what extent other states will enact EV registration fees, we have nonetheless conservatively added an annual additional registration fee to all ZEV vehicles of $100 in our cost analysis. This annual cost was applied for each operating year of the vehicle. Then the difference between the final standards case and reference case for state registration fees on BEVs costs are shown on an annual basis in Table IV-23.

vi. Costs Associated With Battery Replacement and Engine Rebuild
As discussed in preamble section II.E.6, we did not take into account the cost of battery replacement and engine rebuild on the user in the NPRM. In the final rule, after consideration of comment, we added battery replacement and engine rebuild costs. Table IV-24 shows the annual estimated battery replacement and engine rebuild costs on an annual basis relative to the reference case under the potential compliance pathway. Battery replacement and engine rebuild frequency and costs depend on MOVES vehicle source type and regulatory class. Details about the year of replacement or rebuild and associated costs are discussed in RIA 3. ^{932}
^{932} Sanchez, James. Memorandum to docket EPA-HQ-OAR-2022-0985. “Estimating Battery Replacement and Engine Rebuild Costs”. February 23, 2023.

vii. Costs Associated With EVSE Replacement
As discussed in preamble section II.E.6, we did not take into account the cost of EVSE replacement on the user in the NPRM. In the final rule, after consideration of comment, we added EVSE replacement. There is limited data on the expected lifespan of charging infrastructure. We make the simplifying assumption that all depot EVSE ports have a 15-year equipment lifetime. ^{933} After that, we assume they must be replaced at full cost. This assumption likely overestimates costs as some EVSE providers may opt to upgrade existing equipment rather than incur the cost of a full replacement. Some installation costs such as trenching or electrical upgrades may also not be needed for the replacement. Table IV-25 shows the annual estimated EVSE replacement costs on annual basis relative to the reference case under the potential compliance pathway.
^{933} Borlaug, B., Salisbury, S., Gerdes, M., and Muratori, M. “Levelized Cost of Charging Electric Vehicles in the United States,” 2020. Available online: https://www.sciencedirect.com/science/article/pii/S2542435120302312?via%3Dihub .

E. Social Costs
To compute the social costs of the final rulemaking, we added the estimated total vehicle technology package RPE from section IV.B.3, total operating costs from section IV.D.7, and total EVSE RPE from section IV.D.3. We note that the fuel costs in this subsection's social cost analysis are estimated pre-tax rather than what the purchaser will pay ( i.e., the retail fuel price). All of the costs are computed for the MOVES reference and final standards cases and cost impacts are presented as the difference between the final standards and reference case. Additionally, the battery tax credit, vehicle tax credit, EVSE tax credit, excise taxes, sales taxes, and state registration fees on ZEVs are not included in the social costs analysis discussed in this subsection.

1. Total Vehicle Technology Package RPE
Table IV-26 reflects learning effects on DMC and indirect costs from 2027 through 2055. The sum of the DMC and indirect manufacturing cost for each year is shown in the “Total Technology Package Costs” column and reflects the difference in total cost between the final standards and reference case in the specific calendar year.

2. Total EVSE RPE
Building on the analysis presented in section IV.D.3 that discusses EVSE RPE cost per vehicle for depot charging, the annual EVSE RPE was estimated by multiplying EVSE RPE on a per vehicle basis by the modeled number of BEV sales in MOVES. Table IV-27 shows the undiscounted annual EVSE RPE cost for the final standards relative to the reference case. The number of EVSE are expected to increase over time for the final standards relative to the reference case. This is due to the expected increase in BEVs requiring EVSE in our modeled potential compliance pathway's technology packages. Thus, our modeled compliance pathway for the final standards shows increased EVSE cost over time.

3. Total Operating Costs
EPA computed annual fuel costs across the national fleet for each fuel type for the final standards and reference cases by multiplying the amount of fuel consumed for each vehicle modeled in MOVES by the cost of each fuel type. Table IV-28 shows the undiscounted annual fuel savings for the final standards relative to the reference case for each fuel type. Using projected fuel prices from AEO 2023 and the estimated electricity and hydrogen prices as discussed in section IV.D.7.i, the total, national fleet-wide costs of electricity and hydrogen consumption increase over time while the costs for diesel, gasoline, and CNG consumption decrease over time, as shown on an annual basis in Table IV-28. This is due to the expected increase in BEVs and FCEVs in our modeled potential compliance pathway resulting in fewer diesel, gasoline, and CNG vehicles in the final standards case compared to the reference case. The net effect of the final standards shows increased operating cost savings over time.
Annual DEF costs for diesel vehicles were computed for the final standards and reference cases by multiplying the modeled amount of DEF consumed by the cost DEF. Table IV-29 shows the annual savings associated with less DEF consumption in the final standards relative to the reference case; note that non-diesel vehicles are shown for completeness with no savings since those vehicles do not consume DEF.
EPA computed annual maintenance and repair costs on an annual basis for all vehicles modeled in MOVES based on the total annual VMT, vehicle type and vehicle age as discussed in preamble section V and RIA Chapters 2 and 3. Table IV-30 presents the maintenance and repair costs associated with the final rulemaking. The maintenance and repair costs are attributable to changes in new BEV, FCEV, and ICE vehicle sales and populations. EPA has not projected any changes to the maintenance and repair costs on a per mile basis for each vehicle powertrain type between the final standards and reference case, but as more HD ZEVs enter the HD fleet in our modeled potential compliance pathway, the total maintenance and repair costs for the fleet of those vehicles correspondingly increases. The opposite is true for diesel, gasoline, and CNG vehicles in that potential compliance pathway as there become fewer of these vehicles in the fleet, such that their total maintenance and repair costs decrease.
Annual insurance costs were computed by EPA on an annual basis for all vehicles modeled in MOVES based on the purchaser RPE, as discussed RIA Chapter 2 and 3. Table IV-31 presents the insurance costs associated with the final rulemaking. The insurance costs are attributable to changes in new BEV, FCEV, and ICE vehicle sales and populations in our modeled potential compliance pathway. EPA has not projected any changes to the insurance for each vehicle powertrain type between the final standards and reference case, but as more HD ZEVs enter the HD fleet, the total insurance costs for the fleet of those vehicles correspondingly increases. The opposite is true for diesel, gasoline, and CNG vehicles in our modeled potential compliance pathway as there become fewer of these vehicles in the fleet, such that the total insurance costs for the fleet of those vehicles decreases.
Battery replacement and engine rebuild costs were computed on an annual basis for select BEV vehicles modeled in MOVES in the year a BEV/FCEV reaches its replacement age, as discussed in RIA Chapter 2 and 3. The battery replacement costs are attributable to changes in BEV age and populations under the modeled potential compliance pathway. EPA has not projected any changes to the battery replacement costs for each vehicle powertrain type between the final standards and reference case, but as more HD ZEVs enter the HD fleet, the total battery replacement costs for the fleet of those vehicles correspondingly increases. Similarly, ICE engine rebuild costs are applied to ICE vehicles once the vehicle reaches its replacement age. Table IV-32 presents the battery replacement and engine rebuild costs associated with the final rulemaking.
EVSE replacement costs were computed on an annual basis for all BEV modeled in MOVES in the year an EVSE reaches its replacement age, as discussed in RIA Chapter 2 and 3. The EVSE replacement costs are attributable to changes in BEV populations under the modeled potential compliance pathway. EPA has not projected any changes to a single EVSE replacement cost between the final standards and reference case, but as more HD ZEVs enter the HD fleet, the total number of EVSE increases. For this reason, there will be more EVSE to replace in the final standards compared to the reference case. Table IV-33 presents the EVSE replacement costs associated with the final rulemaking.

4. Total Social Costs
Adding together the cost elements outlined in sections IV.E.1, IV.E.2, and IV.E.3, we estimated the total social costs associated with the final CO 2 standards which reflect our modeled potential compliance pathway; these total social costs associated with the final standards relative to the reference case are shown in Table IV-34. Table IV-34 presents costs in 2022$ in undiscounted annual values along with net present values at 2-percent, 3-percent and 7-percent discount rates with values discounted to the 2027 calendar year. In addition, the battery tax credit, vehicle tax credit, EVSE tax credit, sales taxes, Federal excise tax and state registration fees for ZEVs are not included in the social costs analysis discussed in this subsection because taxes, registration fees, and tax credits are transfers and not social costs.
As shown in Table IV-34, starting in 2035, our analysis demonstrates that total program costs under the final standards scenario are lower than the total program costs under the reference case.

V. Estimated Emission Impacts From the Final Standards
We project that the final CO 2 standards will result in downstream emission reductions of GHGs ^{934} from heavy-duty vehicles. Downstream emission processes are those that come directly from a vehicle, such as tailpipe exhaust, crankcase exhaust, evaporative emissions, and refueling emissions. While the final standards do not directly address criteria pollutants or air toxics, we project that they will also result in reductions of downstream emissions of both criteria pollutants and air toxics. We project that these anticipated emission reductions will be achieved through increased adoption of HD vehicle and engine technologies to reduce GHG emissions. Examples of these GHG-reducing technologies that manufacturers may choose to adopt include ICE vehicle technologies, heavy-duty battery electric vehicle (BEV) technologies and fuel cell vehicle (FCEV) technologies. We projected the emission reductions from the modeled potential compliance pathway's technology packages described in section II. As we note there, manufacturers may elect to comply using a different combination of HD vehicle and engine technologies than we modeled. In fact, we developed additional example potential compliance pathways that meet the final Phase 3 MY 2027 through MY 2032 and later CO 2 emission standards (see preamble section II.F.3). These pathways would achieve the same level of vehicle CO 2 emission reductions and downstream CO 2 emission reductions discussed in this section.
^{934} Although the final standards do not directly address non-CO 2 GHGs, we anticipate that the final standards will result in reductions of downstream emissions of non-CO 2 GHGs.
With the modeled increase in adoption of GHG reducing technologies, including heavy-duty BEVs and FCEVs (together referred to as ZEVs), the final standards will also impact upstream emissions of GHGs and other pollutants. Upstream emissions sources are those that do not come from the vehicle itself but are attributable to a vehicle, such as from electricity generation for charging BEVs, the production of hydrogen used to fuel FCEVs, and emissions generated during petroleum-based fuel production and distribution. We estimated the impacts of the final standards on emissions from electricity generation units (EGUs) and on emissions from fuel refineries.
In general, the final rule emissions inventory analysis methodology mirrors the approach we took for the proposal, with some updates to our modeling and assumptions. First, we utilized the most recent version of EPA's Motor Vehicle Emission Simulator (MOVES) model. Second, we updated the reference case ^{935} in several ways, including accounting for EPA granting California the preemption waiver for its ACT rule under CAA section 209(b). ^{936} Third, we performed new Integrated Planning Model (IPM) runs to evaluate power sector emission impacts. Fourth, we changed our assumptions about refinery throughput to better account for U.S. exports of gasoline and diesel. These changes are explained in more detail in section V.A and RIA Chapter 4.
^{935} The reference case is a baseline scenario that represents the U.S. without the final rule.
^{936} 88 FR 20688, April 6, 2023.
To estimate the downstream emission reductions from the final standards, we used MOVES4.R3, which was created based on the latest major public version of MOVES, MOVES4.0.0, and contains various updates including updates to the adoption rate and energy consumption of heavy-duty electric vehicles. These model updates are summarized in Chapter 4.2 of the RIA, and MOVES4.0.0 data and algorithms are described in detail in the technical reports that are available online and in the docket for this rulemaking. 937 938
^{937} See https://www.epa.gov/moves/moves-onroad-technical-reports#moves4 .
^{938} Murray, Evan. Memorandum to Docket EPA-HQ-OAR-2022-0985. “MOVES4.0.0 Technical Reports”. February 2024.
To estimate upstream EGU emission impacts from the final standards, we used the 2022 post-IRA version of the Integrated Planning Model (IPM), which is a linear programming model that forecasts EGU operation and emissions by calculating the most cost-effective way for the electricity generation and transmission system to meet its total demand. IPM accounts for many variables that impact the operation and emissions of EGUs, including total energy demand (including reserve requirements and peak load demand), planned EGU retirements, final rules that impact EGU operation, fuel prices, and infrastructure buildout costs, and congressional action like the Inflation Reduction Act. More details on IPM and the inputs and post-processing used to evaluate the impact of the final standards on EGU emissions can be found in the Chapter 4.2.4 of the RIA.
To estimate upstream refinery impacts from the final standards, we adjusted an existing refinery inventory from the emissions modeling platform ^{939} to reflect updated onroad fuel demand from heavy-duty vehicles. The refinery inventory adjustments were developed using MOVES projections of liquid fuel demand for both the reference case and the final standards. More details on the refinery impacts methodology can be found in Chapter 4.2.5 of the RIA.
^{939} The emissions modeling platform is a product of the National Emissions Inventory Collaborative consistent of more than 245 employees of state and regional air agencies, EPA, and Federal Land Management agencies. It includes a full suite of base year (2016) and projection year (2023 and 2028) emission inventories modeled using EPA's full suite of emissions modeling tools, including MOVES, SMOKE, and CMAQ. https://www.epa.gov/air-emissions-modeling/2016v3-platform .
We received several comments on the scope of upstream emissions to be considered and estimated by EPA. The modeling for the final rule includes the three most significant sectors in terms of understanding the impact of the standards on overall emissions (downstream, EGUs and refineries). We did not estimate impacts on emissions from other sectors with comparatively smaller potential impacts, like those related to the extraction or transportation of fuels for either EGUs or refineries. ^{940} Detailed discussion of the comments we received on upstream modeling and our responses can be found in Chapter 13 of the RTC.
^{940} We included upstream emissions from FCEVs in our EGU emissions modeling, as is discussed in Chapter 4 of the RIA and later in section V.A.2.

A. Model Inputs

1. MOVES Inputs
We used MOVES to evaluate the downstream emissions impact of the final standards relative to a reference case. MOVES defines vehicles using a combination of source type and regulatory class, where source type roughly defines a vehicle's vocation or usage pattern, and regulatory class roughly defines a vehicle's gross vehicle weight rating (GVWR) or weight class. Table V-1 defines MOVES heavy-duty source types and Table V-2 defines MOVES heavy-duty regulatory classes. 941 942 943
^{941} MOVES vehicle definitions encompass the regulatory subcategories of the final standards but are not identical to them. The technology evaluation in HD TRUCS uses 101 vehicle types which can be mapped to MOVES source types and regulatory classes, but no single vehicle type in HD TRUCS corresponds to any single source type or regulatory class. In relation to the final standards, we synonymize combination short-haul tractors (MOVES source type 61) with day cabs and combination long-haul tractors (MOVES source type 62) with sleeper cabs.
^{942} 40 CFR 86.091-2. Available online: https://www.govinfo.gov/content/pkg/CFR-1998-title40-vol12/pdf/CFR-1998-title40-vol12-sec86-091-2.pdf .
^{943} U.S. EPA. “Frequently Asked Questions about Heavy-Duty `Glider Vehicles' and `Glider Kits'. July 2015. Available online: https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P100MUVI.PDF .
In modeling heavy-duty ZEV populations in the reference case, a scenario that represents the United States without the final standards, we considered several different factors related to purchaser acceptance of new technologies as discussed in RIA Chapter 2, along with three factors described in this section and in greater detail in RIA Chapter 1.
First, the market has evolved such that early HD ZEV models are in use today for some applications and HD ZEVs are expected to expand to many more applications, as discussed in RIA Chapters 1.1, 1.5, and 1.7. Additionally, manufacturers have already made substantial investments in ZEV technologies and have announced plans to rapidly increase those investments over the next decade. Second, the IRA and the BIL provide many monetary incentives for the production and purchase of ZEVs in the heavy-duty market, as well as incentives for electric vehicle charging infrastructure. Third, there have been actions by states to accelerate the adoption of heavy-duty ZEVs. Notably, absent the final standards, the State of California's Advanced Clean Trucks (ACT) program imposes minimum ZEV sales requirements beginning in model year 2024 in California and states that have adopted the program under CAA section 177. EPA granted the waiver of preemption for California's ACT rule waiver under CAA section 209(b) on March 30, 2023. ^{944}
^{944} 88 FR 20688, April 6, 2023.
Our reference case for this final rulemaking shows increased ZEV adoption for all heavy-duty vehicle types compared to our reference case for the NPRM. First, the reference case includes the ACT program, as suggested by many commenters and as EPA indicated would be likely at proposal. ^{945} The reference case for this final rule thus reflects manufacturers' compliance with the ACT program in California and in the seven other states that have finalized adoption of ACT. ^{946} As explained further in this section, it also includes a lower, non-zero level of ZEV adoption in the other 42 states. The national reference case HD ZEV adoption rates, based on a sales-weighting of state-specific adoption rates, are presented in Table V-3. Further discussion of the reference case ZEV adoption we modeled in MOVES can be found in RIA Chapter 4.2.21 and breakdowns of ZEV adoption rates by model year, source type, regulatory class, and location can be found in RIA Appendix B.
^{945} EPA granted California's waiver request on March 30, 2023, which left EPA insufficient time to develop an updated reference case for inclusion in the proposal. See 88 FR 25989.
^{946} At the time we performed the inventory modeling analysis, seven states had adopted ACT in addition to California. Oregon, Washington, New York, New Jersey, and Massachusetts adopted ACT beginning in MY 2025 while Vermont adopted ACT beginning in MY 2026 and Colorado in MY 2027. Three other states, New Mexico, Maryland, and Rhode Island adopted ACT (beginning in MY 2027) in November and December of 2023, but there was not sufficient time for us to incorporate them as ACT states in our modeling.
Several commenters noted that our reference case should quantitatively reflect not only the anticipated ZEV sales from the ACT rule in California and other states which have adopted it, but also ZEV adoption resulting from numerous other factors. The commenters specifically suggested to include (1) state policies such as California's Advanced Clean Fleets ^{947} and Innovative Clean Transit rules and the NESCAUM MHD ZEV MOU; ^{948} (2) manufacturer, fleet, and government commitments for producing and procuring ZEVs; (3) adoption for vehicles that reach cost parity with conventional vehicles; and (4) the billions of dollars of programs to support HD ZEV deployment in the BIL and the IRA. Our revised reference case for this final rulemaking includes greater HD ZEV adoption than the reference case in the NPRM for the reasons cited in the preceding paragraphs.
^{947} EPA received a waiver request under CAA section 209(b) and 209(e) from California for the ACF rule on November 15, 2023 (see https://www.epa.gov/state-and-local-transportation/vehicle-emissions-california-waivers-and-authorizations#current ). EPA is currently reviewing the waiver request for the CA ACF rule. Because EPA action on California's waiver request is pending, we did not include the full effects of ACF in the reference case.
^{948} NESCAUM MOU, available at https://www.nescaum.org/documents/mhdv-zev-mou-20220329.pdf .
We reviewed the literature to evaluate future HD ZEV projections in the absence of a Phase 3 regulation. We found that the literature had varied projections. For instance, the National Renewable Energy Laboratory (NREL) conducted an analysis in early 2022, prior to the IRA, that projected 42 percent HD ZEV sales by 2030 and 98 percent sales by 2040, along with 100 percent of bus sales being ZEVs by 2030. ^{949} This analysis assumed economics alone drive adoption ( i.e., total cost of ownership), and therefore they did not consider non-financial factors such ZEV product research and development timelines, ZEV manufacturing timelines, the availability of ZEV models, manufacturing or infrastructure constraints, driver preferences, and other factors. ACT Research also conducted an analysis prior to IRA and projected HD ZEV sales of 24 percent in 2024, 26 percent in 2030, and 34 percent in 2031. ^{950} The International Council for Clean Transportation (ICCT) published a pair of analyses in early 2023 and projected a variety of scenarios. 951 952 Specifically, they projected that in 2030, HD ZEV sales would reach 10 to 51 percent for Class 4-8 trucks, 2 to 34 percent for buses, 16 to 44 percent for short-haul tractors, and 0 to 16 percent for long-haul tractors, with adoption rates generally increasing in future years. The range in their values results from two scenarios. The lower adoption rates represent inclusion of only the regulatory baseline, including the ACT rule and Innovative Clean Transit rule. The higher adoption rates represent their aforementioned regulatory baseline as well as additional market growth driven primarily by the market's response to incentives in the IRA. EDF and ERM conducted a follow-up analysis of their HD ZEV sales projections after the IRA passed in 2022. ^{953} They project several scenarios which range between 11 and 42 percent HD ZEV sales in 2029 when including long-haul tractors. The EDF/ERM analysis found that IRA will help accelerate ZEV adoption due to the purchasing incentives, which drives HD ZEVs to reach upfront vehicle cost parity at least five years sooner than without the IRA incentives. The ACT Research, ICCT, and EDF/ERM projections, similar to the 2022 NREL study, also did not consider several important real-world factors noted, which would in general be expected to slow down or reduce ZEV sales.
^{949} Ledna, Catherine, et.al. “Decarbonizing Medium- & Heavy-Duty On-Road Vehicles: Zero-Emission Vehicles Cost Analysis.” March 2022. Slide 25. Available online: https://www.nrel.gov/docs/fy22osti/82081.pdf .
^{950} Lockridge, Deborah. “ACT: Third of Class 4-8 Vehicles to be Battery-Electric in 10 Years.” June 2021. Available online: https://www.truckinginfo.com/10144947/act-third-of-class-4-8-vehicles-to-be-battery-electric-in-10-years .
^{951} Ragon, Pierre-Louis, Buysse, Claire, Sen, Arijit, Meyer, Michelle, Benoit, Jonathan, Miller, Josh, Rodriguez, Felipe. “Potential Benefits of the U.S. Phase 3 Greenhouse Gas Emissions Regulation for Heavy-Duty Vehicles.” International Council on Clean Transportation. April 2023. Available online: https://theicct.org/wp-content/uploads/2023/04/hdv-phase3-ghg-standards-benefits-apr23.pdf .
^{952} Slowik, Peter et al. “Analyzing the Impact of the Inflation Reduction Act on Electric Vehicle Uptake in the United States.” International Council on Clean Transportation and Energy Innovation Policy & Technology LLC. January 2023. Available online: https://theicct.org/wp-content/uploads/2023/01/ira-impact-evs-us-jan23.pdf .
^{953} Robo, Ellen and Dave Seamonds. Technical Memo to Environmental Defense Fund: Investment Reduction Act Supplemental Assessment: Analysis of Alternative Medium- and Heavy-Duty Zero-Emission Vehicle Business-As-Usual Scenarios. ERM. August 19, 2022. Page 9. Available online: https://www.erm.com/contentassets/154d08e0d0674752925cd82c66b3e2b1/edf-zev-baseline-technical-memo-addendum.pdf .
We note that our reference case projection of ZEV adoption in this final rulemaking includes less aggressive ZEV adoption than urged by a number of commenters or when compared to the studies from NREL, ACT Research, ICCT, and EDF/ERM because we consider real-world factors submitted to the record by other commenters, such as the considerations we described that NREL did not consider in their projections. Therefore, while we think our reference case projection appropriately weighs the relevant real-world factors compared to the more limited set of factors considered in these studies and comments, we may be projecting emission reductions due to the final standards that are greater than could be expected using a reference case that reflects higher levels of ZEV adoption in the HD market absent our rule. At the same time, our use of this reference case would also overestimate the costs of compliance of this final rule if the market would achieve higher levels of ZEV adoption than we project in the absence of our final standards. ^{954}
^{954} We also received comment questioning how many ZEVs will be sold nationwide as a result of ACT (see RTC section 2.4). Given the comments on variability in HD ZEV adoption projections absent the final standards, and the corresponding potential uncertainty in the reference case, we also performed a sensitivity analysis using a reference case that has lower HD ZEV adoption compared to the final rule reference case presented here, as we expected such a scenario may result in a greater magnitude of costs. We present this sensitivity analysis in RIA Chapter 4.10, where we demonstrate that program costs are reasonable when compared to a reference case that has lower HD ZEV adoption than presented here.
In modeling the control case ( i.e., the effect of the final standards), we analyze the impact of the final CO 2 emission standards on a heavy-duty fleet that is projected in our potential compliance pathway to include both ICE vehicles and an increase in ZEV adoption consistent with our technology packages described in preamble section II. Our modeling of the ICE vehicle portions of the technology packages reflect CO 2 emission improvements projected in previously promulgated standards, notably HD GHG Phase 2; thus, we do not model an increase in ICE vehicle efficiency resulting from the final standards. Future HD ZEV populations in MOVES for the final standards scenario were estimated at the national level using HD TRUCS based on the technology assessment for BEVs and FCEVs discussed in section II of this preamble and in RIA Chapter 2. We calculated ZEV adoption by assuming that a) in no combination of MY, source type, regulatory class, and location ( i.e., states that have or have not adopted ACT) would ZEV adoption in the control case be lower than in the reference case, and b) HD ZEV sales would first meet the requirements of the ACT rule in California and the states which have adopted the ACT rule under CAA section 177, and then sales would increase further in all other states consistent with our projections of national ZEV adoption in our principal modelled compliance pathway (described in section II and RIA Chapter 2).
Table V-4 shows the ZEV adoption rates used in modeling the final standards in MOVES from 2027 through 2032. We calculated ZEV adoption rates for the alternative using a similar methodology and those rates are discussed in section IX. Further discussion of the ZEV adoption rates we modeled can be found in RIA Chapter 4.2.3 and breakdowns of ZEV adoption rates by technology, model year, source type, regulatory class, and location can be found in RIA Appendix B.

2. Upstream Modeling
We used the 2022 post-IRA version of IPM to estimate the EGU emissions associated with the additional energy demand from increased HD ZEV adoption. Relative to the NPRM, we performed new IPM runs for updated reference and control cases that all account for the IRA. Because of the lead times necessary to complete our IPM modeling for the final rulemaking analysis, we developed IPM inputs for draft interim reference and control scenarios which do not directly correspond to the ZEV adoption rates and energy demand for the reference and control cases described in section V.A.1.
The differences between the draft interim and final scenarios are small compared to the difference between IPM defaults and the final scenarios. Therefore, we evaluated that we could use the draft interim IPM results to calculate adjusted inventories that provide a good approximation of the EGU emissions impact of the final standards. The details of this methodology can be found in Chapter 4.2.4 of the RIA.
To account for upstream emissions from the production of hydrogen used to fuel FCEVs, we made a simplifying assumption in modeling the final standards that all hydrogen used for FCEVs would be produced via electrolysis of water using electricity from the grid and can therefore be entirely represented as additional demand to EGUs and modeled using IPM. We developed a scaling factor to account for the mass of hydrogen that would need to be produced to meet the FCEV energy demand calculated by MOVES.
We received comments noting that hydrogen in the U.S. today is primarily produced via steam methane reforming (SMR), largely as part of petroleum refining and ammonia production. Given the BIL and IRA provisions that meaningfully incentivize reducing the emissions and carbon intensity of hydrogen production, as well as new transportation and other demand drivers and potential future regulation, we anticipate more hydrogen will be produced by electrolysis in the future. However, to evaluate the upstream impacts of FCEVs more fully under different scenarios, for the final rule analysis, we also performed a comparative analysis of upstream emissions under different hydrogen production pathways. The comparative analysis offers a qualitative range for the upstream emissions that are projected from increased FCEV adoption in the potential compliance pathway's technology package demonstrating the feasibility of the final standards. More details on our upstream analysis of emissions from FCEVs, including the derivation of the scaling factors for hydrogen produced by electrolysis and the emission factors for hydrogen produced via SMR, are documented in Chapter 4.2.4 of the RIA.
The emission impacts presented in this section are based on the electrolysis scenario, but emission comparisons between the electrolysis and SMR scenarios can be found in Chapter 4.8 of the RIA. The comparative analysis shows that the relative emissions of producing hydrogen via SMR versus electrolysis change over time. Compared to grid-based electrolysis, we estimate SMR to have lower emissions in earlier years and higher emissions in later years.
To estimate refinery emission impacts from the final standards, we adjusted an existing refinery inventory from the emissions modeling platform to reflect updated onroad fuel demand from heavy-duty vehicles. The refinery inventory adjustments were developed using MOVES projections of liquid fuel demand for both the reference case and the final standards. Our refinery emission methodology is discussed in detail in Chapter 4.2.5 of the RIA.
In the NPRM analysis we assumed that 93 percent of the drop in domestic demand would be reflected in reduced refinery activity. We received several comments noting that, in response to lower domestic demand, U.S. refineries would increase exports and continue refining similar volumes of liquid fuels. After consideration of these comments, for the final rule, we projected that 50 percent of the drop in domestic demand would be reflected in reduced refinery activity. There remains large uncertainty about how the U.S. refining sector will respond to greater electrification in the onroad sector, and Chapter 4.9 of the RIA includes a sensitivity analysis that assumes that 20 percent of the drop in domestic demand would be reflected in reduced refinery activity.

B. Estimated Emission Impacts From the Final Standards
This final rule includes CO 2 emission standards for MYs 2027 through 2032 and beyond. Our modeled potential compliance pathway to demonstrate the feasibility of these final standards includes both ICE vehicles and an increase in ZEV adoption consistent with our technology packages described in preamble section II. Because ZEVs do not produce any tailpipe emissions, we expect reductions in downstream GHG emissions as well as reductions in downstream emissions of criteria pollutants and air toxics. In our analysis, operation of HD ZEVs increases emissions from EGUs but leads to reduced emissions from refineries.
We present downstream emission reductions in section V.B.1 and upstream emission impacts in section V.B.2. Section V.B.3 presents the net emission impacts of the final standards. The impact of the final standards on cumulative GHG emissions are presented in section V.B.4. The downstream and upstream impacts of the alternative are discussed in section IX.
Because all our modeling is done for a full national domain, emissions impacts cover the full national inventory. Emissions impacts in other domains, such as particular regions or localities in the United States, are likely to differ from the impacts presented here.

1. Estimated Impacts on Downstream Emissions
Our estimates of the downstream emission reductions of GHGs that will result from the final standards relative to the reference case are presented in Table V-5 for calendar years 2035, 2045, and 2055. Total GHG emissions, or CO 2 equivalent (CO 2 e), are calculated by summing all GHG emissions multiplied by their 100-year global warming potentials (GWP). The GWP values used in Table V-5 are consistent with the 2014 IPCC Fifth Assessment Report (AR5). ^{955}
^{955} IPCC, 2014: Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Core Writing Team, R.K. Pachauri and L.A. Meyer (eds.)]. Available online: https://www.ipcc.ch/site/assets/uploads/2018/02/SYR_AR5_FINAL_full.pdf.
In 2055, we estimate that the final standards will reduce downstream emissions of CO 2 from heavy-duty vehicles by 20 percent, methane by 12 percent, and nitrous oxide by 20 percent, resulting in a reduction of 20 percent for total CO 2 equivalent emissions from heavy-duty vehicles. Table V-5 also shows that most of the GHG emission reductions are from CO 2 , which represents approximately 96 percent of all heavy-duty GHG emission reductions from the final standards.
We note that these reductions are lower in the final rule than the proposal. We modeled the proposed standards with our updated FRM methodologies and reference case. The results are presented in RIA Chapter 4.11 and demonstrate that the emission impact differences are primarily due to the increased number of ZEVs considered in the reference case (as discussed earlier in this preamble section V.A) and do not indicate that the final standards are meaningfully less stringent than the proposed standards.
We expect the final CO 2 emission standards will also result in reductions of non-GHG pollutants. Table V-6 presents our estimates of the downstream emission reductions of criteria pollutants and air toxics from heavy-duty vehicles that will result from the final standards in calendar years 2035, 2045, and 2055 relative to the reference case.
In 2055, we estimate the final standards will reduce heavy-duty vehicle emissions of NO X by 20 percent, ^{956} PM 2.5 by 5 percent, VOC by 20 percent, and SO 2 by 20 percent. Reductions in air toxics in 2055 range from 15 percent for formaldehyde to 27 percent for 1,3-butadiene. Again, it is worth noting that these reductions are similarly lower in the final rule than the proposal primarily due to the increased number of ZEVs considered in the reference case. Our increased reference case ZEV adoption is greatest for light and medium heavy-duty vehicles, which means LHD and MHD gasoline vehicles make up a much smaller portion of the HD fleet in the final reference case than in our NPRM reference case. Therefore, emissions reductions for pollutants which are driven by emissions from gasoline vehicles, most notably PM 2.5 and VOCs, are much smaller in our final analysis than our NPRM analysis. This is discussed in more detail in RIA Chapter 4.
^{956} The version of MOVES used to model the final standards includes the HD2027 Low NO X standards (88 FR 4296, March 27, 2023), so it is accounted for in the reference case. NO X reductions presented here are incremental to the impacts from that final rule.
Chapter 4.3 of the RIA contains more details on downstream emission reductions by vehicle type, fuel type, and emission process, as well as year-over-year impacts from 2027 through 2055.

2. Estimated Impacts on Upstream Emissions
The final standards are projected to increase emissions from EGUs. Our estimates of the additional GHG emissions from EGUs due to the final standards, relative to the reference case, are presented in Table V-7 for calendar years 2035, 2045, and 2055, in million metric tons (MMT). Our estimates for additional criteria pollutant emissions are presented in Table V-8.
In 2055, we estimate the final standards will increase EGU emissions of CO 2 by 12.9 million metric tons, compared to 29.3 million metric tons in 2035. There are similar trends for all other pollutants. EGU impacts decrease over time because of changes in the projected power generation mix as electricity generation uses less fossil fuels. Chapter 4.4 of the RIA contains more details and discussion of the impacts of the final CO 2 emission standards on EGU emissions, including year-over-year impacts from 2027 through 2055.
We expect the final standards to lead to a decrease in refinery emissions. Table V-9 presents the estimated impact of the final standards on GHG emissions from refineries (in metric tons) and Table V-10 presents the estimated impact on criteria pollutant emissions (in U.S. tons) from refineries, both relative to the reference case.
Like downstream emissions, we expect refinery emission reductions to increase over time as HD ZEV adoption increases, thus reducing demand for refined fossil fuels and the crude oil from which they are produced. For example, we expect refinery emissions of carbon dioxide to decrease by 331 thousand metric tons in 2035 and 690 thousand metric tons in 2055.

3. Estimated Impacts on Combined Downstream and Upstream Emissions
While we present a net emissions impact of the final CO 2 emission standards, it is important to note that some upstream emission sources are not included in the estimates. This is discussed in detail in Chapter 4 of the RIA.
Table V-11 shows a summary of our modeled downstream, upstream, and net GHG emission impacts of the final standards relative to the reference case ( i.e., the emissions inventory in the absence of the final standards), in million metric tons, for calendar years 2035, 2045, and 2055. Table V-12contains a summary of the modeled net impacts of the final standards on criteria pollutant emissions. As discussed in section II.G, EPA's assessment is that these net impacts are supportive of the final standards.
In 2055, we estimate the final standards will result in a net decrease of 61 million metric tons of GHG emissions. We also estimate net decreases in emissions of NO x , VOC, and SO 2 in 2055. However, we estimate a net increase in PM 2.5 emissions.
In general, net emission impacts are determined by the interaction of two effects. First, HD ZEV adoption increases over time, thus reducing downstream and refinery emissions. Second, the increase in EGU emissions declines over time as the electricity grid becomes cleaner due to EGU regulations and the future power generation mix changes, in part driven by the IRA. These effects can balance differently for different pollutants.
Downstream emissions are a more significant source of GHG, NO X , and VOC emissions, so net reductions grow over time. However, EGUs are a more significant source of SO 2 emissions (largely driven by coal combustion) and PM 2.5 emissions (largely driven by coal and natural gas combustion). We estimate a net increase in SO 2 emissions in 2035 and 2045 but a net decrease in 2055 as coal is phased out of the electricity sector. Natural gas remains an important fuel for electricity generation, which is why we estimate a net increase in PM 2.5 in all years. However, consistent with the trends for other pollutants, the magnitude of the PM 2.5 emission increases diminish over time.

4. Cumulative GHG Emission Impacts
The warming impacts of GHGs are cumulative. Table V-13, Table V-14, and Table V-15 present the cumulative GHG impacts that we model will result from the final standards between 2027 through 2055 for downstream emissions, EGU emissions, and refinery emissions, respectively, relative to the reference case.
Overall, we estimate the final standards will reduce net GHG emissions by just over 1 billion metric tons between 2027 and 2055, relative to the reference case, as is presented in Table V-16.

VI. Climate, Health, Air Quality, Environmental Justice, and Economic Impacts
In this section, we discuss the impacts of the final rule on climate change, health and environmental effects, environmental justice, and oil and electricity and hydrogen consumption. We also discuss our approaches to analyzing the impact of this rule on the heavy-duty vehicle market and employment.

A. Climate Change Impacts
Elevated concentrations of greenhouse gases (GHGs) have been warming the planet, leading to changes in the Earth's climate that are occurring at a pace and in a way that threatens human health, society, and the natural environment. While EPA is not making any new scientific or factual findings with regard to the well-documented impact of GHG emissions on public health and welfare in support of this rule, EPA is providing in this section a brief scientific background on climate change to offer additional context for this rulemaking and to help the public understand the environmental impacts of GHGs.
Extensive information on climate change is available in the scientific assessments and the EPA documents that are briefly described in this section, as well as in the technical and scientific information supporting them. One of those documents is EPA's 2009 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under section 202(a) of the CAA (74 FR 66496, December 15, 2009) (“2009 Endangerment Finding”). In the 2009 Endangerment Finding, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs—CO 2 , methane (CH 4 ), nitrous oxide (N 2 O), HFCs, perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 )—“may reasonably be anticipated to endanger the public health and welfare of current and future generations” (74 FR 66523). The 2009 Endangerment Finding, together with the extensive scientific and technical evidence in the supporting record, documented that climate change caused by human emissions of GHGs threatens the public health of the U.S. population. It explained that by raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses (74 FR 66497). While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S. (74 FR 66525). The 2009 Endangerment Finding further explained that compared with a future without climate change, climate change is expected to increase tropospheric ozone pollution over broad areas of the U.S., including in the largest metropolitan areas with the worst tropospheric ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525). Climate change is also expected to cause more intense hurricanes and more frequent and intense storms of other types and heavy precipitation, with impacts on other areas of public health, such as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-related disorders (74 FR 66525). Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498).
The 2009 Endangerment Finding also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare ^{957} in the U.S., including: Changes in water supply and quality due to changes in drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530).
^{957} The CAA states in section 302(h) that “[a]ll language referring to effects on welfare includes, but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.” 42 U.S.C. 7602(h).
In 2016, the Administrator issued a similar finding for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA. ^{958} In the 2016 Endangerment Finding, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Finding compellingly supported a similar endangerment finding under CAA section 231(a)(2)(A), and also found that the science assessments released between the 2009 and the 2016 Findings “strengthen and further support the judgment that GHGs in the atmosphere may reasonably be anticipated to endanger the public health and welfare of current and future generations” (81 FR 54424).
^{958} “Finding that Greenhouse Gas Emissions From Aircraft Cause or Contribute to Air Pollution That May Reasonably Be Anticipated To Endanger Public Health and Welfare.” 81 FR 54422, August 15, 2016. (“2016 Endangerment Finding”).
Since the 2016 Endangerment Finding, the climate has continued to change, with new observational records being set for several climate indicators such as global average surface temperatures, GHG concentrations, and sea level rise. Additionally, major scientific assessments continue to be released that further advance our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both globally and in the U.S. ^{959}
^{960}
^{961}
^{962}
^{963}
^{964}
^{965}
^{966}
^{967}
^{968}
^{969}
^{970}
^{971}
^{959} USGCRP, 2017: Climate Science Special Report: Fourth National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 470 pp, doi: 10.7930/J0J964J6.
^{960} USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C.
^{961} USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
^{962} IPCC, 2018: Global Warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Pörtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)].
^{963} IPCC, 2019: Climate Change and Land: an IPCC special report on climate change, desertification, land degradation, sustainable land management, food security, and greenhouse gas fluxes in terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. Masson-Delmotte, H.-O. Pörtner, D. C. Roberts, P. Zhai, R. Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)].
^{964} IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere in a Changing Climate [H.-O. Pörtner, DC Roberts, V. Masson-Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A. Alegria, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer (eds.)].
^{965} IPCC, 2023: Summary for Policymakers. In: Climate Change 2023: Synthesis Report. Contribution of Working Groups I, II and III to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Core Writing Team, H. Lee and J. Romero (eds.)]. IPCC, Geneva, Switzerland, pp. 1-34, doi:10.59327/IPCC/AR6-9789291691647.001.
^{966} National Academies of Sciences, Engineering, and Medicine. 2016. Attribution of Extreme Weather Events in the Context of Climate Change. Washington, DC: The National Academies Press. https://dio.org/10.17226/21852.
^{967} National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National Academies Press. https://doi.org/10.17226/24651.
^{968} National Academies of Sciences, Engineering, and Medicine. 2019. Climate Change and Ecosystems. Washington, DC: The National Academies Press. https://doi.org/10.17226/25504.
^{969} Blunden, J., T. Boyer, and E. Bartow-Gillies, Eds., 2023: “State of the Climate in 2022”. Bull. Amer. Meteor. Soc., 104 (9), Si-S501 https://doi.org/10.1175/2023BAMSStateoftheClimate.
^{970} EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.
^{971} Jay, A.K., A.R. Crimmins, C.W. Avery, T.A. Dahl, R.S. Dodder, B.D. Hamlington, A. Lustig, K. Marvel, P.A. Méndez-Lazaro, M.S. Osler, A. Terando, E.S. Weeks, and A. Zycherman, 2023: Ch. 1. Overview: Understanding risks, impacts, and responses. In: Fifth National Climate Assessment. Crimmins, A.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S. Global Change Research Program, Washington, DC, USA. https://doi.org/10.7930/NCA5.2023.CH1.
The most recent information demonstrates that the climate is continuing to change in response to the human-induced buildup of GHGs in the atmosphere. These recent assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in human history and that they continue to climb, primarily because of both historical and current anthropogenic emissions, and that these elevated concentrations endanger our health by affecting our food and water sources, the air we breathe, the weather we experience, and our interactions with the natural and built environments. For example, atmospheric concentrations of one of these GHGs, CO 2 , measured at Mauna Loa in Hawaii and at other sites around the world reached 419 parts per million (ppm) in 2022 (nearly 50 percent higher than preindustrial levels) ^{972} and have continued to rise at a rapid rate. Global average temperature has increased by about 1.1 °C (2.0 °F) in the 2011-2020 decade relative to 1850-1900. ^{973} The years 2015-2022 were the warmest 8 years in the 1880-2022 record. ^{974} The IPCC determined (with medium confidence) that this past decade was warmer than any multi-century period in at least the past 100,000 years. ^{975} Global average sea level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate over the 1971 to 2006 period, and three times the rate of the 1901 to 2018 period. ^{976} The rate of sea level rise over the 20th century was higher than in any other century in at least the last 2,800 years. ^{977} Higher CO 2 concentrations have led to acidification of the surface ocean in recent decades to an extent unusual in the past 65 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons. ^{978} Arctic sea ice extent continues to decline in all months of the year; the most rapid reductions occur in September (very likely almost a 13 percent decrease per decade between 1979 and 2018) and are unprecedented in at least 1,000 years. ^{979} Human-induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts ^{980} in many regions. ^{981}
^{972} https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt.
^{973} IPCC, 2021: Summary for Policymakers. In: Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Péan, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekçi, R. Yu, and B. Zhou (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 3-32, doi:10.1017/9781009157896.001.
^{974} Blunden, et al. 2023.
^{975} IPCC, 2021.
^{976} IPCC, 2021.
^{977} USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
^{978} IPCC, 2018.
^{979} IPCC, 2021.
^{980} These are drought measures based on soil moisture.
^{981} IPCC, 2021.
The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The 2022 CO 2 concentration of 419 ppm is already higher than at any time in the last 2 million years. ^{982} If concentrations exceed 450 ppm, they would likely be higher than any time in the past 23 million years: ^{983} at the current rate of increase of more than 2 ppm a year, this would occur in about 15 years. While GHGs are not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO 2 concentrations were above 400 ppm) Greenland was not yet completely covered by ice and still supported forests, while 23 million years ago (the last time concentrations were above 450 ppm) the West Antarctic ice sheet was not yet developed, indicating the possibility that high GHG concentrations could lead to a world that looks very different from today and from the conditions in which human civilization has developed. If the Greenland and Antarctic ice sheets were to melt substantially, sea levels would rise dramatically—the IPCC estimated that over the next 2,000 years, sea level will rise by 7 to 10 feet even if warming is limited to 1.5 °C (2.7 °F), from 7 to 20 feet if limited to 2 °C (3.6 °F), and by 60 to 70 feet if warming is allowed to reach 5 °C (9 °F) above preindustrial levels. ^{984} For context, almost all of the city of Miami is less than 25 feet above sea level, and the 4th National Climate Assessment (NCA4) stated that 13 million Americans would be at risk of migration due to 6 feet of sea level rise.
^{982} Annual Mauna Loa CO 2 concentration data from https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt , accessed September 9, 2023.
^{983} IPCC, 2013.
^{984} IPCC, 2021.
The NCA4 found that it is very likely (greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years. ^{985} Coral reefs will be at risk for almost complete (99 percent) losses with 1 °C (1.8 °F) of additional warming from today (2 °C or 3.6 °F since preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over half of the geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland livestock would be projected to be lost. ^{986} The IPCC similarly found that climate change has caused substantial damages and increasingly irreversible losses in terrestrial, freshwater, and coastal and open ocean marine ecosystems.
^{985} USGCRP, 2018.
^{986} IPCC, 2018.
Every additional increment of temperature comes with consequences. For example, the half degree of warming from 1.5 to 2 °C (0.9 °F of warming from 2.7 °F to 3.6 °F) above preindustrial temperatures is projected on a global scale to expose 420 million more people to extreme heatwaves at least once every five years, and 62 million more people to exceptional heatwaves at least once every five years (where heatwaves are defined based on a heat wave magnitude index which takes into account duration and intensity—using this index, the 2003 French heat wave that led to almost 15,000 deaths would be classified as an “extreme heatwave” and the 2010 Russian heatwave which led to thousands of deaths and extensive wildfires would be classified as “exceptional”). It would increase the frequency of sea-ice-free Arctic summers from once in 100 years to once in a decade. It could lead to 4 inches of additional sea level rise by the end of the century, exposing an additional 10 million people to risks of inundation as well as increasing the probability of triggering instabilities in either the Greenland or Antarctic ice sheets. Between half a million and a million additional square miles of permafrost would thaw over several centuries. Risks to food security would increase from medium to high for several lower-income regions in the Sahel, southern Africa, the Mediterranean, central Europe, and the Amazon. In addition to food security issues, this temperature increase would have implications for human health in terms of increasing ozone concentrations, heatwaves, and vector-borne diseases (for example, expanding the range of the mosquitoes which carry dengue fever, chikungunya, yellow fever, and the Zika virus, or the ticks which carry Lyme, babesiosis, or Rocky Mountain Spotted Fever). ^{987} Moreover, every additional increment in warming leads to larger changes in extremes, including the potential for events unprecedented in the observational record. Every additional degree will intensify extreme precipitation events by about 7 percent. The peak winds of the most intense tropical cyclones (hurricanes) are projected to increase with warming. In addition to a higher intensity, the IPCC found that precipitation and frequency of rapid intensification of these storms has already increased, the movement speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging. ^{988}
^{987} IPCC, 2018.
^{988} IPCC, 2021.
The NCA4 also evaluated a number of impacts specific to the U.S. Severe drought and outbreaks of insects like the mountain pine beetle have killed hundreds of millions of trees in the western U.S. Wildfires have burned more than 3.7 million acres in 14 of the 17 years between 2000 and 2016, and Federal wildfire suppression costs were about a billion dollars annually. ^{989} The National Interagency Fire Center has documented U.S. wildfires since 1983, and the 10 years with the largest acreage burned have all occurred since 2004. ^{990} Wildfire smoke degrades air quality, increasing health risks, and more frequent and severe wildfires due to climate change would further diminish air quality, increase incidences of respiratory illness, impair visibility, and disrupt outdoor activities, sometimes thousands of miles from the location of the fire. Meanwhile, sea level rise has amplified coastal flooding and erosion impacts, requiring the installation of costly pump stations, flooding streets, and increasing storm surge damages. Tens of billions of dollars of U.S. real estate could be below sea level by 2050 under some scenarios. Increased frequency and duration of drought will reduce agricultural productivity in some regions, accelerate depletion of water supplies for irrigation, and expand the distribution and incidence of pests and diseases for crops and livestock. The NCA4 also recognized that climate change can increase risks to national security, both through direct impacts on military infrastructure and by affecting factors such as food and water availability that can exacerbate conflict outside U.S. borders. Droughts, floods, storm surges, wildfires, and other extreme events stress nations and people through loss of life, displacement of populations, and impacts on livelihoods. ^{991}
^{989} USGCRP, 2018.
^{990} NIFC (National Interagency Fire Center). 2021. Total wildland fires and acres (1983-2020). Accessed August 2021. www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.
^{991} USGCRP, 2018.
EPA modeling efforts can further illustrate how these impacts from climate change may be experienced across the U.S. EPA's Framework for Evaluating Damages and Impacts (FrEDI) ^{992} uses information from over 30 peer-reviewed climate change impact studies to project the physical and economic impacts of climate change to the U.S. resulting from future temperature changes. These impacts are projected for specific regions within the U.S. and for more than 20 impact categories, which span a large number of sectors of the U.S. economy. ^{993} Using this framework, the EPA estimates that global emission projections, with no additional mitigation, will result in significant climate-related damages to the U.S. ^{994} These damages to the U.S. would mainly be from increases in lives lost due to increases in temperatures, as well as impacts to human health from increases in climate-driven changes in air quality, dust and wildfire smoke exposure, and incidence of suicide. Additional major climate-related damages would occur to U.S. infrastructure such as roads and rail, as well as transportation impacts and coastal flooding from sea level rise, increases in property damage from tropical cyclones, and reductions in labor hours worked in outdoor settings and buildings without air conditioning. These impacts are also projected to vary from region to region with the Southeast, for example, projected to see some of the largest damages from sea level rise, the West Coast projected to experience damages from wildfire smoke more than other parts of the country, and the Northern Plains states projected to see a higher proportion of damages to rail and road infrastructure. While information on the distribution of climate impacts helps to better understand the ways in which climate change may impact the U.S., recent analyses are still only a partial assessment of climate impacts relevant to U.S. interests and do not reflect increased damages that occur due to interactions between different sectors impacted by climate change or all the ways in which physical impacts of climate change occurring abroad have spillover effects in different regions of the U.S.
^{992} (1) Hartin, C., et al. (2023). Advancing the estimation of future climate impacts within the United States. Earth Syst. Dynam., 14, 1015-1037, https://dio.org/10.5194/esd-14-1015-2023. (2) Supplementary Material for the Regulatory Impact Analysis for the Supplemental Proposed Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,” Docket ID No. EPA-HQ-OAR-2021-0317, September 2022, (3) The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050. Published by the U.S. Department of State and the U.S. Executive Office of the President, Washington, DC. November 2021, (4) Climate Risk Exposure: An Assessment of the Federal Government's Financial Risks to Climate Change, White Paper, Office of Management and Budget, April 2022.
^{993} EPA (2021). Technical Documentation on the Framework for Evaluating Damages and Impacts (FrEDI). U.S. Environmental Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi. Documentation has been subject to both a public review comment period and an independent expert peer review, following EPA peer-review guidelines.
^{994} Compared to a world with no additional warming after the model baseline (1986-2005).
Some GHGs also have impacts beyond those mediated through climate change. For example, elevated concentrations of CO 2 stimulate plant growth (which can be positive in the case of beneficial species, but negative in terms of weeds and invasive species, and can also lead to a reduction in plant micronutrients ^{995} ) and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone. ^{996}
^{995} Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Pérez de León, A. Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, Nutrition, and Distribution. The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. U.S. Global Change Research Program, Washington, DC, 189-216. https://health2016.globalchange.gov/low/ClimateHealth2016_07_Food_small.pdf.
^{996} WMO (World Meteorological Organization), Scientific Assessment of Ozone Depletion: 2018, Global Ozone Research and Monitoring Project —Report No. 58, 588 pp., Geneva, Switzerland, 2018.
Transportation is the largest U.S. source of GHG emissions, representing 29 percent of total GHG emissions. ^{997} Within the transportation sector, heavy-duty vehicles are the second largest contributor to GHG emissions and are responsible for 25 percent of GHG emissions in the sector. ^{998} The GHG emission reductions resulting from compliance with this final rule will significantly reduce the volume of GHG emissions from this sector. Section VI.D.2 of this preamble discusses impacts of GHG emissions on individuals living in socially and economically vulnerable communities. While EPA did not conduct modeling to specifically quantify changes in climate impacts resulting from this rule in terms of avoided temperature change or sea-level rise, we did quantify climate benefits by monetizing the emission reductions through the application of estimates of the social cost of greenhouse gases (SC-GHGs), as described in section VII.A of this preamble.
^{997} EPA (2023). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 (EPA-430-R-23-002, published April 2023).
^{998} EPA (2023). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2021 (EPA-430-R-23-002, published April 2023).
These scientific assessments, the EPA analyses, and documented observed changes in the climate of the planet and of the U.S. present clear support regarding the current and future dangers of climate change and the importance of GHG emissions mitigation.

B. Health and Environmental Effects Associated With Exposure to Non-GHG Pollutants
The non-GHG emissions that will be impacted by this rule contribute, directly or via secondary formation, to concentrations of pollutants in the air which affect human and environmental health. These pollutants include particulate matter, ozone,, sulfur oxides, carbon monoxide and air toxics.

1. Background on Criteria and Air Toxics Pollutants Impacted by This Rule

i. Particulate Matter
Particulate matter (PM) is a complex mixture of solid particles and liquid droplets distributed among numerous atmospheric gases which interact with solid and liquid phases. Particles in the atmosphere range in size from less than 0.01 to more than 10 micrometers (µm) in diameter. ^{999} Atmospheric particles can be grouped into several classes according to their aerodynamic diameter and physical sizes. Generally, the three broad classes of particles include ultrafine particles (UFPs, generally considered as particles with a diameter less than or equal to 0.1 µm [typically based on physical size, thermal diffusivity, or electrical mobility]), “fine” particles (PM 2.5 ; particles with a nominal mean aerodynamic diameter less than or equal to 2.5 µm), and “thoracic” particles (PM 10 ; particles with a nominal mean aerodynamic diameter less than or equal to 10 µm). Particles that fall within the size range between PM 2.5 and PM 10 , are referred to as “thoracic coarse particles” (PM 10−2.5 , particles with a nominal mean aerodynamic diameter greater than 2.5 µm and less than or equal to 10 µm). EPA currently has NAAQS for PM 2.5 and PM 10 . ^{1000}
^{999} U.S. EPA. Policy Assessment (PA) for the Review of the National Ambient Air Quality Standards for Particulate Matter (Final Report, 2020). U.S. Environmental Protection Agency, Washington, DC, EPA/452/R-20/002, 2020.
^{1000} Regulatory definitions of PM size fractions, and information on reference and equivalent methods for measuring PM in ambient air, are provided in 40 CFR parts 50, 53, and 58. With regard to NAAQS which provide protection against health and welfare effects, the 24-hour PM 10 standard provides protection against effects associated with short-term exposure to thoracic coarse particles ( i.e., PM 10-2.5 ).
Most particles are found in the lower troposphere, where they can have residence times ranging from a few hours to weeks. Particles are removed from the atmosphere by wet deposition, such as when they are carried by rain or snow, or by dry deposition, when particles settle out of suspension due to gravity. Atmospheric lifetimes are generally longest for PM 2.5 , which often remains in the atmosphere for days to weeks before being removed by wet or dry deposition. ^{1001} In contrast, atmospheric lifetimes for UFP and PM 10-2.5 are shorter. Within hours, UFP can undergo coagulation and condensation that lead to formation of larger particles in the accumulation mode or can be removed from the atmosphere by evaporation, deposition, or reactions with other atmospheric components. PM 10-2.5 are also generally removed from the atmosphere within hours through wet or dry deposition. ^{1002}
^{1001} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019. Table 2-1.
^{1002} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019. Table 2-1.
Particulate matter consists of both primary and secondary particles. Primary particles are emitted directly from sources, such as combustion-related activities ( e.g., industrial activities, motor vehicle operation, biomass burning), while secondary particles are formed through atmospheric chemical reactions of gaseous precursors ( e.g., sulfur oxides (SO X ), oxides of nitrogen (NO X ) and volatile organic compounds (VOCs)).

ii. Ozone
Ground-level ozone pollution forms in areas with high concentrations of ambient NO X and VOCs when solar radiation is strong. Major U.S. sources of NO X are highway and nonroad motor vehicles, engines, power plants and other industrial sources; natural sources, such as soil, vegetation, and lightning, are smaller sources. Vegetation is the dominant source of VOCs in the United States. Volatile consumer and commercial products, such as propellants and solvents, highway and nonroad vehicles, engines, fires, and industrial sources also contribute to the atmospheric burden of VOCs at ground-level.
The processes underlying ozone formation, transport, and accumulation are complex. Ground-level ozone is produced and destroyed by an interwoven network of free radical reactions involving the hydroxyl radical (OH), NO, NO 2 , and complex reaction intermediates derived from VOCs. Many of these reactions are sensitive to temperature and available sunlight. High ozone events most often occur when ambient temperatures and sunlight intensities remain high for several days under stagnant conditions. Ozone and its precursors can also be transported hundreds of miles downwind, which can lead to elevated ozone levels in areas with otherwise low VOC or NO X emissions. As an air mass moves and is exposed to changing ambient concentrations of NO X and VOCs, the ozone photochemical regime (relative sensitivity of ozone formation to NO X and VOC emissions) can change.
When ambient VOC concentrations are high, comparatively small amounts of NO X catalyze rapid ozone formation. Without available NO X , ground-level ozone production is severely limited, and VOC reductions would have little impact on ozone concentrations. Photochemistry under these conditions is said to be “NO X -limited.” When NO X levels are sufficiently high, faster NO 2 oxidation consumes more radicals, dampening ozone production. Under these “VOC-limited” conditions (also referred to as “NO X -saturated” conditions), VOC reductions are effective in reducing ozone, and NO X can react directly with ozone, resulting in suppressed ozone concentrations near NO X emission sources. Under these NO X -saturated conditions, NO X reductions can increase local ozone under certain circumstances, but overall ozone production (considering downwind formation) decreases and, even in VOC-limited areas, NO X reductions are not expected to increase ozone levels if the NO X reductions are sufficiently large—large enough for photochemistry to become NO X -limited.

iii.
Oxides of nitrogen (NO X ) refers to nitric oxide (NO) and nitrogen dioxide (NO 2 ). Most NO 2 is formed in the air through the oxidation of NO emitted when fuel is burned at a high temperature. NO 2 is a criteria pollutant, regulated for its adverse effects on public health and the environment, and highway vehicles are an important contributor to NO 2 emissions. NO X , along with VOCs, are the two major precursors of ozone, and NO X is also a major contributor to secondary PM 2.5 formation.

iv. Sulfur Oxides
Sulfur dioxide (SO 2 ), a member of the sulfur oxide (SO X ) family of gases, is formed from burning fuels containing sulfur ( e.g., coal or oil), extracting gasoline from oil, or extracting metals from ore. SO 2 and its gas phase oxidation products can dissolve in water droplets and further oxidize to form sulfuric acid which reacts with ammonia to form sulfates, which are important components of ambient PM.

v. Carbon Monoxide
Carbon monoxide (CO) is a colorless, odorless gas formed by incomplete combustion of carbon-containing fuels and by photochemical reactions in the atmosphere. Nationally, particularly in urban areas, the majority of CO emissions to ambient air come from mobile sources. ^{1003}
^{1003} U.S. EPA, (2010). Integrated Science Assessment for Carbon Monoxide (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/019F, 2010.
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=218686. See section 2.1.

vi. Diesel Exhaust
Diesel exhaust is a complex mixture composed of particulate matter, carbon dioxide, oxygen, nitrogen, water vapor, carbon monoxide, nitrogen compounds, sulfur compounds and numerous low-molecular-weight hydrocarbons. A number of these gaseous hydrocarbon components are individually known to be toxic, including aldehydes, benzene and 1,3-butadiene. The diesel particulate matter present in diesel exhaust consists mostly of fine particles (less than 2.5 µm), of which a significant fraction is ultrafine particles (less than 0.1 µm). These particles have a large surface area which makes them an excellent medium for adsorbing organics, and their small size makes them highly respirable. Many of the organic compounds present in the gases and on the particles, such as polycyclic organic matter, are individually known to have mutagenic and carcinogenic properties.
Diesel exhaust varies significantly in chemical composition and particle sizes between different engine types (heavy-duty, light-duty), engine operating conditions (idle, acceleration, deceleration), and fuel formulations (high/low sulfur fuel). Also, there are emissions differences between on-road and nonroad engines because the nonroad engines are generally of older technology. After being emitted in the engine exhaust, diesel exhaust undergoes dilution as well as chemical and physical changes in the atmosphere. The lifetimes of the components present in diesel exhaust range from seconds to months.

vii. Air Toxics
The most recent available data indicate that millions of Americans live in areas where air toxics pose potential health concerns. 1004 1005 The levels of air toxics to which people are exposed vary depending on where people live and work and the kinds of activities in which they engage, as discussed in detail in EPA's 2007 Mobile Source Air Toxics Rule. ^{1006} According to EPA's 2017 National Emissions Inventory (NEI), mobile sources were responsible for 39 percent of outdoor anthropogenic toxic emissions. Further, mobile sources were the largest contributor to national average risk of cancer and immunological and respiratory health effects from directly emitted pollutants, according to EPA's Air Toxics Screening Assessment (AirToxScreen) for 2019. 1007 1008 Mobile sources are also significant contributors to precursor emissions which react to form air toxics. ^{1009} Formaldehyde is the largest contributor to cancer risk of all 72 pollutants quantitatively assessed in the 2019 AirToxScreen. Mobile sources were responsible for 26 percent of primary anthropogenic emissions of this pollutant in the 2017 NEI and are significant contributors to formaldehyde precursor emissions. Benzene is also a large contributor to cancer risk, and mobile sources account for about 60 percent of average exposure to ambient concentrations.
^{1004} Air toxics are pollutants known to cause or suspected of causing cancer or other serious health effects. Air toxics are also known as toxic air pollutants or hazardous air pollutants. https://www.epa.gov/AirToxScreen/airtoxscreen-glossary-terms#air-toxics.
^{1005} U.S. EPA (2022) Technical Support Document EPA Air Toxics Screening Assessment. 2018 AirToxScreen TSD. https://www.epa.gov/system/files/documents/2023-02/AirToxScreen_2018%20TSD.pdf.
^{1006} U.S. Environmental Protection Agency (2007). Control of Hazardous Air Pollutants from Mobile Sources; Final Rule. 72 FR 8434, February 26, 2007.
^{1007} U.S. EPA. (2022) 2019 AirToxScreen: Assessment Results. https://www.epa.gov/AirToxScreen/2019-airtoxscreen-assessment-results.
^{1008} AirToxScreen also includes estimates of risk attributable to background concentrations, which includes contributions from long-range transport, persistent air toxics, and natural sources; as well as secondary concentrations, where toxics are formed via secondary formation. Mobile sources substantially contribute to long-range transport and secondarily formed air toxics.
^{1009} Rich Cook, Sharon Phillips, Madeleine Strum, Alison Eyth & James Thurman (2020): Contribution of mobile sources to secondary formation of carbonyl compounds, Journal of the Air & Waste Management Association, DOI: 10.1080/10962247.2020.1813839.

2. Health Effects Associated With Exposure to Non-GHG Pollutants
Heavy-duty vehicles emit non-GHG pollutants that contribute to ambient concentrations of ozone, PM, NO 2 , SO 2 , CO, and air toxics. This section of the preamble discusses the health effects associated with exposure to these pollutants. Although the discussion which follows largely deals with the effects of these pollutants on the general population, we note at the outset that certain populations are especially vulnerable and susceptible to effects from exposure to these pollutants. Children are one such population, and they are especially vulnerable because they generally breathe more relative to their size than adults; consequently, they may be exposed to relatively higher amounts of air pollution. ^{1010} Children also tend to breathe through their mouths more than adults, and their nasal passages are less effective at removing pollutants, which leads to greater lung deposition of some pollutants such as PM. 1011 1012 Furthermore, air pollutants may pose health risks specific to children because children's bodies are still developing. ^{1013} For example, during periods of rapid growth such as fetal development, infancy and puberty, their developing systems and organs may be more easily harmed. 1014 1015 See EPA's Report “America's Children and the Environment,” which presents national trends on air pollution and other contaminants and environmental health of children. ^{1016}
^{1010} EPA (2009) Metabolically-derived ventilation rates: A revised approach based upon oxygen consumption rates. Washington, DC: Office of Research and Development. EPA/600/R-06/129F. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=202543.
^{1011} U.S. EPA Integrated Science Assessment for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019. Chapter 4 “Overall Conclusions” p. 4-1.
^{1012} Foos, B.; Marty, M.; Schwartz, J.; Bennet, W.; Moya, J.; Jarabek, A.M.; Salmon, A.G. (2008) Focusing on children's inhalation dosimetry and health effects for risk assessment: An introduction. J Toxicol Environ Health 71A: 149-165.
^{1013} Children's environmental health includes conception, infancy, early childhood and through adolescence until 21 years of age as described in the EPA Memorandum: Issuance of EPA's 2021 Policy on Children's Health. October 5, 2021. Available at https://www.epa.gov/system/files/documents/2021-10/2021-policy-on-childrens-health.pdf .
^{1014} EPA (2006) A Framework for Assessing Health Risks of Environmental Exposures to Children. EPA, Washington, DC, EPA/600/R-05/093F, 2006.
^{1015} U.S. Environmental Protection Agency. (2005). Supplemental guidance for assessing susceptibility from early-life exposure to carcinogens. Washington, DC: Risk Assessment Forum. EPA/630/R-03/003F. https://www3.epa.gov/airtoxics/childrens_supplement_final.pdf.
^{1016} U.S. EPA. America's Children and the Environment. Available at: https://www.epa.gov/americaschildrenenvironment.

i. Particulate Matter
Scientific evidence spanning animal toxicological, controlled human exposure, and epidemiologic studies shows that exposure to ambient PM is associated with a broad range of health effects. These health effects are discussed in detail in the Integrated Science Assessment for Particulate Matter, which was finalized in December 2019 (2019 p.m. ISA), with a more targeted evaluation of studies published since the literature cutoff date of the 2019 p.m. ISA in the Supplement to the Integrated Science Assessment for PM (Supplement). 1017 1018 The PM ISA characterizes the causal nature of relationships between PM exposure and broad health categories ( e.g., cardiovascular effects, respiratory effects, etc.) using a weight-of-evidence approach. ^{1019} Within this characterization, the PM ISA summarizes the health effects evidence for short-term ( i.e., hours up to one month) and long-term ( i.e., one month to years) exposures to PM 2.5 , PM 10-2.5 , and ultrafine particles and concludes that exposures to ambient PM 2.5 are associated with a number of adverse health effects. The discussion in this section VI.B.2.i highlights the PM ISA's conclusions and summarizes additional information from the Supplement where appropriate, pertaining to the health effects evidence for both short- and long-term PM exposures. Further discussion of PM-related health effects can also be found in the 2022 Policy Assessment for the review of the PM NAAQS. ^{1020}
^{1017} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
^{1018} U.S. EPA. Supplement to the 2019 Integrated Science Assessment for Particulate Matter (Final Report, 2022). U.S. Environmental Protection Agency, Washington, DC, EPA/635/R-22/028, 2022.
^{1019} The causal framework draws upon the assessment and integration of evidence from across scientific disciplines, spanning atmospheric chemistry, exposure, dosimetry and health effects studies ( i.e., epidemiologic, controlled human exposure, and animal toxicological studies), and assess the related uncertainties and limitations that ultimately influence our understanding of the evidence. This framework employs a five-level hierarchy that classifies the overall weight-of-evidence with respect to the causal nature of relationships between criteria pollutant exposures and health and welfare effects using the following categorizations: causal relationship; likely to be causal relationship; suggestive of, but not sufficient to infer, a causal relationship; inadequate to infer the presence or absence of a causal relationship; and not likely to be a causal relationship (U.S. EPA) (2019). Integrated Science Assessment for Particulate Matter (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, Section P. 3.2.3).
^{1020} U.S. EPA. Policy Assessment (PA) for the Reconsideration of the National Ambient Air Quality Standards for Particulate Matter (Final Report, 2022). U.S. Environmental Protection Agency, Washington, DC, EPA-452/R-22-004, 2022.
EPA has concluded that recent evidence in combination with evidence evaluated in the 2009 p.m. ISA supports a “causal relationship” between both long- and short-term exposures to PM 2.5 and premature mortality and cardiovascular effects and a “likely to be causal relationship” between long- and short-term PM 2.5 exposures and respiratory effects. ^{1021} Additionally, recent experimental and epidemiologic studies provide evidence supporting a “likely to be causal relationship” between long-term PM 2.5 exposure and nervous system effects and between long-term PM 2.5 exposure and cancer. Because of remaining uncertainties and limitations in the evidence base, EPA determined a “suggestive of, but not sufficient to infer, a causal relationship” for long-term PM 2.5 exposure and reproductive and developmental effects ( i.e., male/female reproduction and fertility; pregnancy and birth outcomes), long- and short-term exposures and metabolic effects, and short-term exposure and nervous system effects.
^{1021} U.S. EPA (2009). Integrated Science Assessment for Particulate Matter (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-08/139F.
As discussed extensively in the 2019 p.m. ISA and the Supplement, recent studies continue to support a “causal relationship” between short- and long-term PM 2.5 exposures and mortality. 1022 1023 For short-term PM 2.5 exposure, multi-city studies, in combination with single- and multi-city studies evaluated in the 2009 p.m. ISA, provide evidence of consistent, positive associations across studies conducted in different geographic locations, populations with different demographic characteristics, and studies using different exposure assignment techniques. Additionally, the consistent and coherent evidence across scientific disciplines for cardiovascular morbidity, including exacerbations of chronic obstructive pulmonary disease (COPD) and asthma, provide biological plausibility for cause-specific mortality and ultimately total mortality. Recent epidemiologic studies evaluated in the Supplement, including studies that employed alternative methods for confounder control, provide additional support to the evidence base that contributed to the 2019 p.m. ISA conclusion for short-term PM 2.5 exposure and mortality.
^{1022} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
^{1023} U.S. EPA. Supplement to the 2019 Integrated Science Assessment for Particulate Matter (Final Report, 2022). U.S. Environmental Protection Agency, Washington, DC, EPA/635/R-22/028, 2022.
The 2019 p.m. ISA concluded a “causal relationship” between long-term PM 2.5 exposure and mortality. In addition to reanalyzes and extensions of the American Cancer Society (ACS) and Harvard Six Cities (HSC) cohorts, multiple new cohort studies conducted in the United States and Canada consisting of people employed in a specific job ( e.g., teacher, nurse), and that apply different exposure assignment techniques, provide evidence of positive associations between long-term PM 2.5 exposure and mortality. Biological plausibility for mortality due to long-term PM 2.5 exposure is provided by the coherence of effects across scientific disciplines for cardiovascular morbidity, particularly for coronary heart disease, stroke, and atherosclerosis, and for respiratory morbidity, particularly for the development of COPD. Additionally, recent studies provide evidence indicating that as long-term PM 2.5 concentrations decrease there is an increase in life expectancy. Recent cohort studies evaluated in the Supplement, as well as epidemiologic studies that conducted accountability analyses or employed alternative methods for confounder controls, support and extend the evidence base that contributed to the 2019 p.m. ISA conclusion for long-term PM 2.5 exposure and mortality.
A large body of studies examining both short- and long-term PM 2.5 exposure and cardiovascular effects supports and extends the evidence base evaluated in the 2009 p.m. ISA. The strongest evidence for cardiovascular effects in response to short-term PM 2.5 exposures is for ischemic heart disease and heart failure. The evidence for short-term PM 2.5 exposure and cardiovascular effects is coherent across scientific disciplines and supports a continuum of effects ranging from subtle changes in indicators of cardiovascular health to serious clinical events, such as increased emergency department visits and hospital admissions due to cardiovascular disease and cardiovascular mortality. For long-term PM 2.5 exposure, there is strong and consistent epidemiologic evidence of a relationship with cardiovascular mortality. This evidence is supported by epidemiologic and animal toxicological studies demonstrating a range of cardiovascular effects including coronary heart disease, stroke, impaired heart function, and subclinical markers ( e.g., coronary artery calcification, atherosclerotic plaque progression), which collectively provide coherence and biological plausibility. Recent epidemiologic studies evaluated in the Supplement, as well as studies that conducted accountability analyses or employed alternative methods for confounder control, support and extend the evidence base that contributed to the 2019 p.m. ISA conclusion for both short- and long-term PM 2.5 exposure and cardiovascular effects.
Studies evaluated in the 2019 PM ISA continue to provide evidence of a “likely to be causal relationship” between both short- and long-term PM 2.5 exposure and respiratory effects. Epidemiologic studies provide consistent evidence of a relationship between short-term PM 2.5 exposure and asthma exacerbation in children and COPD exacerbation in adults as indicated by increases in emergency department visits and hospital admissions, which is supported by animal toxicological studies indicating worsening allergic airways disease and subclinical effects related to COPD. Epidemiologic studies also provide evidence of a relationship between short-term PM 2.5 exposure and respiratory mortality. However, there is inconsistent evidence of respiratory effects, specifically lung function declines and pulmonary inflammation, in controlled human exposure studies. With respect to long term PM 2.5 exposure, epidemiologic studies conducted in the United States and abroad provide evidence of a relationship with respiratory effects, including consistent changes in lung function and lung function growth rate, increased asthma incidence, asthma prevalence, and wheeze in children; acceleration of lung function decline in adults; and respiratory mortality. The epidemiologic evidence is supported by animal toxicological studies, which provide coherence and biological plausibility for a range of effects including impaired lung development, decrements in lung function growth, and asthma development.
Since the 2009 PM ISA, a growing body of scientific evidence examined the relationship between long-term PM 2.5 exposure and nervous system effects, resulting for the first time in a causality determination for this health effects category of a “likely to be causal relationship.” The strongest evidence for effects on the nervous system comes from epidemiologic studies that consistently report cognitive decrements and reductions in brain volume in adults. The effects observed in epidemiologic studies in adults are supported by animal toxicological studies demonstrating effects on the brain of adult animals including inflammation, morphologic changes, and neurodegeneration of specific regions of the brain. There is more limited evidence for neurodevelopmental effects in children, with some studies reporting positive associations with autism spectrum disorder and others providing limited evidence of an association with cognitive function. While there is some evidence from animal toxicological studies indicating effects on the brain ( i.e., inflammatory and morphological changes) to support a biologically plausible pathway for neurodevelopmental effects, epidemiologic studies are limited due to their lack of control for potential confounding by copollutants, the small number of studies conducted, and uncertainty regarding critical exposure windows.
Building off the decades of research demonstrating mutagenicity, DNA damage, and other endpoints related to genotoxicity due to whole PM exposures, recent experimental and epidemiologic studies focusing specifically on PM 2.5 provide evidence of a relationship between long-term PM 2.5 exposure and cancer. Epidemiologic studies examining long-term PM 2.5 exposure and lung cancer incidence and mortality provide evidence of generally positive associations in cohort studies spanning different populations, locations, and exposure assignment techniques. Additionally, there is evidence of positive associations with lung cancer incidence and mortality in analyses limited to never smokers. The epidemiologic evidence is supported by both experimental and epidemiologic evidence of genotoxicity, epigenetic effects, carcinogenic potential, and that PM 2.5 exhibits several characteristics of carcinogens, which collectively provides biological plausibility for cancer development and resulted in the conclusion of a “likely to be causal relationship.”
For the additional health effects categories evaluated for PM 2.5 in the 2019 PM ISA, experimental and epidemiologic studies provide limited and/or inconsistent evidence of a relationship with PM 2.5 exposure. As a result, the 2019 PM ISA concluded that the evidence is “suggestive of, but not sufficient to infer a causal relationship” for short-term PM 2.5 exposure and metabolic effects and nervous system effects and for long-term PM 2.5 exposures and metabolic effects as well as reproductive and developmental effects.
In addition to evaluating the health effects attributed to short- and long-term exposure to PM 2.5 , the 2019 PM ISA also conducted an extensive evaluation as to whether specific components or sources of PM 2.5 are more strongly related with health effects than PM 2.5 mass. An evaluation of those studies resulted in the 2019 PM ISA concluding that “many PM 2.5 components and sources are associated with many health effects, and the evidence does not indicate that any one source or component is consistently more strongly related to health effects than PM 2.5 mass.” ^{1024}
^{1024} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
For both PM 10-2.5 and UFPs, for all health effects categories evaluated, the 2019 PM ISA concluded that the evidence was “suggestive of, but not sufficient to infer, a causal relationship” or “inadequate to determine the presence or absence of a causal relationship.” For PM 10-2.5 , although a Federal Reference Method was instituted in 2011 to measure PM 10-2.5 concentrations nationally, the causality determinations reflect that the same uncertainty identified in the 2009 PM ISA with respect to the method used to estimate PM 10-2.5 concentrations in epidemiologic studies persists. Specifically, across epidemiologic studies, different approaches are used to estimate PM 10-2.5 concentrations ( e.g., direct measurement of PM 10-2.5 , difference between PM 10 and PM 2.5 concentrations), and it remains unclear how well correlated PM 10-2.5 concentrations are both spatially and temporally across the different methods used.
For UFPs, which have often been defined as particles less than 0.1 µm, the uncertainty in the evidence for the health effect categories evaluated across experimental and epidemiologic studies reflects the inconsistency in the exposure metric used ( i.e., particle number concentration, surface area concentration, mass concentration) as well as the size fractions examined. In epidemiologic studies the size fraction examined can vary depending on the monitor used and exposure metric, with some studies examining number count over the entire particle size range, while experimental studies that use a particle concentrator often examine particles up to 0.3 µm. Additionally, due to the lack of a monitoring network, there is limited information on the spatial and temporal variability of UFPs within the U.S., as well as population exposures to UFPs, which adds uncertainty to epidemiologic study results.
The 2019 PM ISA cites extensive evidence indicating that “both the general population as well as specific populations and life stages are at risk for PM 2.5 -related health effects.” ^{1025} For example, in support of its “causal” and “likely to be causal” determinations, the ISA cites substantial evidence for (1) PM-related mortality and cardiovascular effects in older adults; (2) PM-related cardiovascular effects in people with pre-existing cardiovascular disease; (3) PM-related respiratory effects in people with pre-existing respiratory disease, particularly asthma exacerbations in children; and (4) PM-related impairments in lung function growth and asthma development in children. The ISA additionally notes that stratified analyses ( i.e., analyses that directly compare PM-related health effects across groups) provide strong evidence for racial and ethnic differences in PM 2.5 exposures and in the risk of PM 2.5 -related health effects, specifically within Hispanic and non- Hispanic Black populations, with some evidence of increased risk for populations of low socioeconomic status. Recent studies evaluated in the Supplement support the conclusion of the 2019 PM ISA with respect to disparities in both PM 2.5 exposure and health risk by race and ethnicity and provide additional support for disparities for populations of lower socioeconomic status. ^{1026} Additionally, evidence spanning epidemiologic studies that conducted stratified analyses, experimental studies focusing on animal models of disease or individuals with pre-existing disease, dosimetry studies, as well as studies focusing on differential exposure suggest that populations with pre-existing cardiovascular or respiratory disease, populations that are overweight or obese, populations that have particular genetic variants, and current/former smokers could be at increased risk for adverse PM 2.5 -related health effects. The 2022 Policy Assessment for the review of the PM NAAQS also highlights that factors that may contribute to increased risk of PM 2.5 -related health effects include life stage (children and older adults), pre-existing diseases (cardiovascular disease and respiratory disease), race/ethnicity, and socioeconomic status. ^{1027}
^{1025} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
^{1026} U.S. EPA. Supplement to the 2019 Integrated Science Assessment for Particulate Matter (Final Report, 2022). U.S. Environmental Protection Agency, Washington, DC, EPA/635/R-22/028, 2022.
^{1027} U.S. EPA. Policy Assessment (PA) for the Reconsideration of the National Ambient Air Quality Standards for Particulate Matter (Final Report, 2022). U.S. Environmental Protection Agency, Washington, DC, EPA-452/R-22-004, 2022, p. 3-53.

ii. Ozone
This section provides a summary of the health effects associated with exposure to ambient concentrations of ozone. ^{1028} The information in this section is based on the information and conclusions in the April 2020 Integrated Science Assessment for Ozone (Ozone ISA). ^{1029} The Ozone ISA concludes that human exposures to ambient concentrations of ozone are associated with a number of adverse health effects and characterizes the weight of evidence for these health effects. ^{1030} The discussion in this section VI.B.2.ii highlights the Ozone ISA's conclusions pertaining to health effects associated with both short-term and long-term periods of exposure to ozone.
^{1028} Human exposure to ozone varies over time due to changes in ambient ozone concentration and because people move between locations which have notably different ozone concentrations. Also, the amount of ozone delivered to the lung is influenced not only by the ambient concentrations but also by the breathing route and rate.
^{1029} U.S. EPA. Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-20/012, 2020.
^{1030} The ISA evaluates evidence and draws conclusions on the causal relationship between relevant pollutant exposures and health effects, assigning one of five “weight of evidence” determinations: causal relationship, likely to be a causal relationship, suggestive of a causal relationship, inadequate to infer a causal relationship, and not likely to be a causal relationship. For more information on these levels of evidence, please refer to Table II in the Preamble of the ISA.
For short-term exposure to ozone, the Ozone ISA concludes that respiratory effects, including lung function decrements, pulmonary inflammation, exacerbation of asthma, respiratory-related hospital admissions, and mortality, are causally associated with ozone exposure. It also concludes that metabolic effects, including metabolic syndrome ( i.e., changes in insulin or glucose levels, cholesterol levels, obesity, and blood pressure) and complications due to diabetes are likely to be causally associated with short-term exposure to ozone and that evidence is suggestive of a causal relationship between cardiovascular effects, central nervous system effects and total mortality and short-term exposure to ozone.
For long-term exposure to ozone, the Ozone ISA concludes that respiratory effects, including new onset asthma, pulmonary inflammation, and injury, are likely to be causally related with ozone exposure. The Ozone ISA characterizes the evidence as suggestive of a causal relationship for associations between long-term ozone exposure and cardiovascular effects, metabolic effects, reproductive and developmental effects, central nervous system effects and total mortality. The evidence is inadequate to infer a causal relationship between chronic ozone exposure and increased risk of cancer.
Finally, interindividual variation in human responses to ozone exposure can result in some groups being at increased risk for detrimental effects in response to exposure. In addition, some groups are at increased risk of exposure due to their activities, such as outdoor workers and children. The Ozone ISA identified several groups that are at increased risk for ozone-related health effects. These groups are people with asthma, children and older adults, individuals with reduced intake of certain nutrients ( i.e., Vitamins C and E), outdoor workers, and individuals having certain genetic variants related to oxidative metabolism or inflammation. Ozone exposure during childhood can have lasting effects through adulthood. Such effects include altered function of the respiratory and immune systems. Children absorb higher doses (normalized to lung surface area) of ambient ozone, compared to adults, due to their increased time spent outdoors, higher ventilation rates relative to body size, and a tendency to breathe a greater fraction of air through the mouth. ^{1031} Children also have a higher asthma prevalence compared to adults. Recent epidemiologic studies provide generally consistent evidence that long-term ozone exposure is associated with the development of asthma in children. Studies comparing age groups reported higher magnitude associations for short-term ozone exposure and respiratory hospital admissions and emergency room visits among children than among adults. Panel studies also provide support for experimental studies with consistent associations between short-term ozone exposure and lung function and pulmonary inflammation in healthy children. Additional children's vulnerability and susceptibility factors are listed in section XI.B.2 of the preamble.
^{1031} Children are more susceptible than adults to many air pollutants because of differences in physiology, higher per body weight breathing rates and consumption, rapid development of the brain and bodily systems, and behaviors that increase chances for exposure. Even before birth, the developing fetus may be exposed to air pollutants through the mother that affect development and permanently harm the individual. Infants and children breathe at much higher rates per body weight than adults, with infants under one year of age having a breathing rate up to five times that of adults. In addition, children breathe through their mouths more than adults and their nasal passages are less effective at removing pollutants, which leads to a higher deposition fraction in their lungs.

iii.
The most recent review of the health effects of oxides of nitrogen completed by EPA can be found in the 2016 Integrated Science Assessment for Oxides of Nitrogen—Health Criteria (Oxides of Nitrogen ISA). ^{1032} The primary source of NO 2 is motor vehicle emissions, and ambient NO 2 concentrations tend to be highly correlated with other traffic-related pollutants. Thus, a key issue in characterizing the causality of NO 2 -health effect relationships was evaluating the extent to which studies supported an effect of NO 2 that is independent of other traffic-related pollutants. EPA concluded that the findings for asthma exacerbation integrated from epidemiologic and controlled human exposure studies provided evidence that is sufficient to infer a causal relationship between respiratory effects and short-term NO 2 exposure. The strongest evidence supporting an independent effect of NO 2 exposure comes from controlled human exposure studies demonstrating increased airway responsiveness in individuals with asthma following ambient-relevant NO 2 exposures. The coherence of this evidence with epidemiologic findings for asthma hospital admissions and emergency department visits as well as lung function decrements and increased pulmonary inflammation in children with asthma describe a plausible pathway by which NO 2 exposure can cause an asthma exacerbation. The 2016 ISA for Oxides of Nitrogen also concluded that there is likely to be a causal relationship between long-term NO 2 exposure and respiratory effects. This conclusion is based on new epidemiologic evidence for associations of NO 2 with asthma development in children combined with biological plausibility from experimental studies.
^{1032} U.S. EPA. Integrated Science Assessment for Oxides of Nitrogen—Health Criteria (2016 Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-15/068, 2016.
In evaluating a broader range of health effects, the 2016 ISA for Oxides of Nitrogen concluded that evidence is “suggestive of, but not sufficient to infer, a causal relationship” between short-term NO 2 exposure and cardiovascular effects and mortality and between long-term NO 2 exposure and cardiovascular effects and diabetes, birth outcomes, and cancer. In addition, the scientific evidence is inadequate (insufficient consistency of epidemiologic and toxicological evidence) to infer a causal relationship for long-term NO 2 exposure with fertility, reproduction, and pregnancy, as well as with postnatal development. A key uncertainty in understanding the relationship between these non-respiratory health effects and short- or long-term exposure to NO 2 is co-pollutant confounding, particularly by other roadway pollutants. The available evidence for non-respiratory health effects does not adequately address whether NO 2 has an independent effect or whether it primarily represents effects related to other or a mixture of traffic-related pollutants.
The 2016 ISA for Oxides of Nitrogen concluded that people with asthma, children, and older adults are at increased risk for NO 2 -related health effects. In these groups and lifestages, NO 2 is consistently related to larger effects on outcomes related to asthma exacerbation, for which there is confidence in the relationship with NO 2 exposure.

iv. Sulfur Oxides
This section provides an overview of the health effects associated with SO 2 . Additional information on the health effects of SO 2 can be found in the 2017 Integrated Science Assessment for Sulfur Oxides—Health Criteria (SO X ISA). ^{1033} Following an extensive evaluation of health evidence from animal toxicological, controlled human exposure, and epidemiologic studies, the EPA has concluded that there is a causal relationship between respiratory health effects and short-term exposure to SO 2 . The immediate effect of SO 2 on the respiratory system in humans is bronchoconstriction. People with asthma are more sensitive to the effects of SO 2 , likely resulting from preexisting inflammation associated with this disease. In addition to those with asthma (both children and adults), there is suggestive evidence that all children and older adults may be at increased risk of SO 2 -related health effects. In free-breathing laboratory studies involving controlled human exposures to SO 2 , respiratory effects have consistently been observed following 5-10 min exposures at SO 2 concentrations ≥400 ppb in people with asthma engaged in moderate to heavy levels of exercise, with respiratory effects occurring at concentrations as low as 200 ppb in some individuals with asthma. A clear concentration-response relationship has been demonstrated in these studies following exposures to SO 2 at concentrations between 200 and 1000 ppb, both in terms of increasing severity of respiratory symptoms and decrements in lung function, as well as the percentage of individuals with asthma adversely affected. Epidemiologic studies have reported positive associations between short-term ambient SO 2 concentrations and hospital admissions and emergency department visits for asthma and for all respiratory causes, particularly among children and older adults (≥65 years). The studies provide supportive evidence for the causal relationship.
^{1033} U.S. EPA. Integrated Science Assessment (ISA) for Sulfur Oxides—Health Criteria (Final Report, Dec 2017). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-17/451, 2017.
For long-term SO 2 exposure and respiratory effects, the EPA has concluded that the evidence is suggestive of a causal relationship. This conclusion is based on new epidemiologic evidence for positive associations between long-term SO 2 exposure and increases in asthma incidence among children, together with animal toxicological evidence that provides a pathophysiologic basis for the development of asthma. However, uncertainty remains regarding the influence of other pollutants on the observed associations with SO 2 because these epidemiologic studies have not examined the potential for co-pollutant confounding.
Consistent associations between short-term exposure to SO 2 and mortality have been observed in epidemiologic studies with larger effect estimates reported for respiratory mortality than for cardiovascular mortality. While this finding is consistent with the demonstrated effects of SO 2 on respiratory morbidity, uncertainty remains with respect to the interpretation of these observed mortality associations due to potential confounding by various copollutants. Therefore, the EPA has concluded that the overall evidence is suggestive of a causal relationship between short-term exposure to SO 2 and mortality.

v. Carbon Monoxide
Information on the health effects of carbon monoxide (CO) can be found in the January 2010 Integrated Science Assessment for Carbon Monoxide (CO ISA). ^{1034} The CO ISA presents conclusions regarding the presence of causal relationships between CO exposure and categories of adverse health effects. ^{1035} This section provides a summary of the health effects associated with exposure to ambient concentrations of CO, along with the CO ISA conclusions. ^{1036}
^{1034} U.S. EPA (2010). Integrated Science Assessment for Carbon Monoxide (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/019F, 2010.
^{1035} The ISA evaluates the health evidence associated with different health effects, assigning one of five “weight of evidence” determinations: causal relationship, likely to be a causal relationship, suggestive of a causal relationship, inadequate to infer a causal relationship, and not likely to be a causal relationship. For definitions of these levels of evidence, please refer to section 1.6 of the ISA.
^{1036} Personal exposure includes contributions from many sources, and in many different environments. Total personal exposure to CO includes both ambient and non-ambient components; and both components may contribute to adverse health effects.
Controlled human exposure studies of subjects with coronary artery disease show a decrease in the time to onset of exercise-induced angina (chest pain) and electrocardiogram changes following CO exposure. In addition, epidemiologic studies presented in the CO ISA observed associations between short-term CO exposure and cardiovascular morbidity, particularly increased emergency room visits and hospital admissions for coronary heart disease (including ischemic heart disease, myocardial infarction, and angina). Some epidemiologic evidence is also available for increased hospital admissions and emergency room visits for congestive heart failure and cardiovascular diseases as a whole. The CO ISA concludes that a causal relationship is likely to exist between short-term exposures to CO and cardiovascular morbidity. It also concludes that available data are inadequate to conclude that a causal relationship exists between long-term exposures to CO and cardiovascular morbidity.
Animal studies show various neurological effects with in-utero CO exposure. Controlled human exposure studies report central nervous system and behavioral effects following low-level CO exposures, although the findings have not been consistent across all studies. The CO ISA concludes that the evidence is suggestive of a causal relationship with both short- and long-term exposure to CO and central nervous system effects.
A number of studies cited in the CO ISA have evaluated the role of CO exposure in birth outcomes such as preterm birth or cardiac birth defects. There is limited epidemiologic evidence of a CO-induced effect on preterm births and birth defects, with weak evidence for a decrease in birth weight. Animal toxicological studies have found perinatal CO exposure to affect birth weight, as well as other developmental outcomes. The CO ISA concludes that the evidence is suggestive of a causal relationship between long-term exposures to CO and developmental effects and birth outcomes.
Epidemiologic studies provide evidence of associations between short-term CO concentrations and respiratory morbidity such as changes in pulmonary function, respiratory symptoms, and hospital admissions. A limited number of epidemiologic studies considered copollutants such as ozone, SO 2 , and PM in two-pollutant models and found that CO risk estimates were generally robust, although this limited evidence makes it difficult to disentangle effects attributed to CO itself from those of the larger complex air pollution mixture. Controlled human exposure studies have not extensively evaluated the effect of CO on respiratory morbidity. Animal studies at levels of 50-100 ppm CO show preliminary evidence of altered pulmonary vascular remodeling and oxidative injury. The CO ISA concludes that the evidence is suggestive of a causal relationship between short-term CO exposure and respiratory morbidity, and inadequate to conclude that a causal relationship exists between long-term exposure and respiratory morbidity.
Finally, the CO ISA concludes that the epidemiologic evidence is suggestive of a causal relationship between short-term concentrations of CO and mortality. Epidemiologic evidence suggests an association exists between short-term exposure to CO and mortality, but limited evidence is available to evaluate cause-specific mortality outcomes associated with CO exposure. In addition, the attenuation of CO risk estimates which was often observed in co-pollutant models contributes to the uncertainty as to whether CO is acting alone or as an indicator for other combustion-related pollutants. The CO ISA also concludes that there is not likely to be a causal relationship between relevant long-term exposures to CO and mortality.

vi. Diesel Exhaust
In EPA's 2002 Diesel Health Assessment Document (Diesel HAD), exposure to diesel exhaust was classified as likely to be carcinogenic to humans by inhalation from environmental exposures, in accordance with the revised draft 1996/1999 EPA cancer guidelines. 1037 1038 A number of other agencies (National Institute for Occupational Safety and Health, the International Agency for Research on Cancer, the World Health Organization, California EPA, and the U.S. Department of Health and Human Services) made similar hazard classifications prior to 2002. EPA also concluded in the 2002 Diesel HAD that it was not possible to calculate a cancer unit risk for diesel exhaust due to limitations in the exposure data for the occupational groups or the absence of a dose-response relationship.
^{1037} U.S. EPA. (1999). Guidelines for Carcinogen Risk Assessment. Review Draft. NCEA-F-0644, July. Washington, DC: U.S. EPA. Retrieved on March 19, 2009 from http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=54932 .
^{1038} U.S. EPA (2002). Health Assessment Document for Diesel Engine Exhaust. EPA/600/8-90/057F Office of research and Development, Washington DC. Retrieved on March 17, 2009, from http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=29060 . pp. 1-1 1-2.
In the absence of a cancer unit risk, the Diesel HAD sought to provide additional insight into the significance of the diesel exhaust cancer hazard by estimating possible ranges of risk that might be present in the population. An exploratory analysis was used to characterize a range of possible lung cancer risk. The outcome was that environmental risks of cancer from long-term diesel exhaust exposures could plausibly range from as low as 10 −5 to as high as 10 −3 . Because of uncertainties, the analysis acknowledged that the risks could be lower than 10 −5 , and a zero risk from diesel exhaust exposure could not be ruled out.
Noncancer health effects of acute and chronic exposure to diesel exhaust emissions are also of concern to EPA. EPA derived a diesel exhaust reference concentration (RfC) from consideration of four well-conducted chronic rat inhalation studies showing adverse pulmonary effects. The RfC is 5 µg/m ^3 for diesel exhaust measured as diesel particulate matter. This RfC does not consider allergenic effects such as those associated with asthma or immunologic or the potential for cardiac effects. There was emerging evidence in 2002, discussed in the Diesel HAD, that exposure to diesel exhaust can exacerbate these effects, but the exposure-response data were lacking at that time to derive an RfC based on these then-emerging considerations. The Diesel HAD states, “With [diesel particulate matter] being a ubiquitous component of ambient PM, there is an uncertainty about the adequacy of the existing [diesel exhaust] noncancer database to identify all of the pertinent [diesel exhaust]-caused noncancer health hazards.” The Diesel HAD also notes “that acute exposure to [diesel exhaust] has been associated with irritation of the eye, nose, and throat, respiratory symptoms (cough and phlegm), and neurophysiological symptoms such as headache, lightheadedness, nausea, vomiting, and numbness or tingling of the extremities.” The Diesel HAD notes that the cancer and noncancer hazard conclusions applied to the general use of diesel engines then on the market and as cleaner engines replace a substantial number of existing ones, the applicability of the conclusions would need to be reevaluated.
It is important to note that the Diesel HAD also briefly summarizes health effects associated with ambient PM and discusses EPA's then-annual PM 2.5 NAAQS of 15 µg/m ^3 . In 2012, EPA revised the level of the annual PM 2.5 NAAQS to 12 µg/m ^3 and in 2024 EPA revised the level of the annual PM 2.5 NAAQS to 9.0 µg/m ^3 . ^{1039} There is a large and extensive body of human data showing a wide spectrum of adverse health effects associated with exposure to ambient PM, of which diesel exhaust is an important component. The PM 2.5 NAAQS provides protection from the health effects attributed to exposure to PM 2.5 . The contribution of diesel PM to total ambient PM varies in different regions of the country and also within a region from one area to another. The contribution can be high in near-roadway environments, for example, or in other locations where diesel engine use is concentrated.
^{1039} https://www.epa.gov/pm-pollution/national-ambient-air-quality-standards-naaqs-pm.
Since 2002, several new studies have been published which continue to report increased lung cancer risk associated with occupational exposure to diesel exhaust from older engines. Of particular note since 2011 are three new epidemiology studies which have examined lung cancer in occupational populations, including truck drivers, underground nonmetal miners, and other diesel motor-related occupations. These studies reported increased risk of lung cancer related to exposure to diesel exhaust, with evidence of positive exposure-response relationships to varying degrees. 1040 1041 1042 These newer studies (along with others that have appeared in the scientific literature) add to the evidence EPA evaluated in the 2002 Diesel HAD and further reinforce the concern that diesel exhaust exposure likely poses a lung cancer hazard. The findings from these newer studies do not necessarily apply to newer technology diesel engines ( i.e., heavy-duty highway engines from 2007 and later model years) since the newer engines have large reductions in the emission constituents compared to older technology diesel engines.
^{1040} Garshick, Eric, Francine Laden, Jaime E. Hart, Mary E. Davis, Ellen A. Eisen, and Thomas J. Smith. 2012. Lung cancer and elemental carbon exposure in trucking industry workers. Environmental Health Perspectives 120(9): 1301-1306.
^{1041} Silverman, D.T., Samanic, C.M., Lubin, J.H., Blair, A.E., Stewart, P.A., Vermeulen, R., & Attfield, M.D. (2012). The diesel exhaust in miners study: a nested case-control study of lung cancer and diesel exhaust. Journal of the National Cancer Institute.
^{1042} Olsson, Ann C., et al. “Exposure to diesel motor exhaust and lung cancer risk in a pooled analysis from case-control studies in Europe and Canada.” American journal of respiratory and critical care medicine 183.7 (2011): 941-948.
In light of the growing body of scientific literature evaluating the health effects of exposure to diesel exhaust, in June 2012 the World Health Organization's International Agency for Research on Cancer (IARC), a recognized international authority on the carcinogenic potential of chemicals and other agents, evaluated the full range of cancer-related health effects data for diesel engine exhaust. IARC concluded that diesel exhaust should be regarded as “carcinogenic to humans.” ^{1043} This designation was an update from its 1988 evaluation that considered the evidence to be indicative of a “probable human carcinogen.”
^{1043} IARC [International Agency for Research on Cancer]. (2013). Diesel and gasoline engine exhausts and some nitroarenes. IARC Monographs Volume 105. Online at http://monographs.iarc.fr/ENG/Monographs/vol105/index.php.

vii. Air Toxics
Heavy-duty engine emissions contribute to ambient levels of air toxics that are known or suspected human or animal carcinogens or that have noncancer health effects. These compounds include, but are not limited to, acetaldehyde, benzene, 1,3-butadiene, formaldehyde, and naphthalene. These compounds were all identified as national cancer risk drivers or contributors in the 2019 Air Toxics Screening Assessment (AirToxScreen). 1044 1045
^{1044} U.S. EPA (2022) Technical Support Document EPA's Air Toxics Screening Assessment. 2018 AirToxScreen TSD. https://www.epa.gov/system/files/documents/2023-02/AirToxScreen_2018%20TSD.pdf.
^{1045} U.S. EPA (2023) 2019 AirToxScreen Risk Drivers. https://www.epa.gov/AirToxScreen/airtoxscreen-risk-drivers.

a. Acetaldehyde
Acetaldehyde is classified in EPA's IRIS database as a probable human carcinogen, based on nasal tumors in rats, and is considered toxic by the inhalation, oral, and intravenous routes. ^{1046} The inhalation unit risk estimate (URE) in IRIS for acetaldehyde is 2.2 × 10 −6 per µg/m ^3 . ^{1047} Acetaldehyde is reasonably anticipated to be a human carcinogen by the NTP in the 14th Report on Carcinogens and is classified as possibly carcinogenic to humans (Group 2B) by the IARC. 1048 1049
^{1046} U.S. EPA (1991). Integrated Risk Information System File of Acetaldehyde. Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=290.
^{1047} U.S. EPA (1991). Integrated Risk Information System File of Acetaldehyde. This material is available electronically at https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=290.
^{1048} NTP (National Toxicology Program). 2016. Report on Carcinogens, Fourteenth Edition.; Research Triangle Park, NC: U.S. Department of Health and Human Services, Public Health Service. https://ntp.niehs.nih.gov/go/roc14.
^{1049} International Agency for Research on Cancer (IARC). (1999). Re-evaluation of some organic chemicals, hydrazine, and hydrogen peroxide. IARC Monographs on the Evaluation of Carcinogenic Risk of Chemical to Humans, Vol 71. Lyon, France.
The primary noncancer effects of exposure to acetaldehyde vapors include irritation of the eyes, skin, and respiratory tract. ^{1050} In short-term (4 week) rat studies, degeneration of olfactory epithelium was observed at various concentration levels of acetaldehyde exposure. ^{1051} Data from these studies were used by EPA to develop an inhalation reference concentration of 9 µg/m ^3 . Some asthmatics have been shown to be a sensitive subpopulation to decrements in functional expiratory volume (FEV1 test) and bronchoconstriction upon acetaldehyde inhalation. ^{1052} Children, especially those with diagnosed asthma, may be more likely to show impaired pulmonary function and symptoms of asthma than are adults following exposure to acetaldehyde. ^{1053}
^{1050} U.S. EPA (1991). Integrated Risk Information System File of Acetaldehyde. This material is available electronically at https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=290.
^{1051} Appleman, L.M., R.A. Woutersen, and V.J. Feron. (1982). Inhalation toxicity of acetaldehyde in rats. I. Acute and subacute studies. Toxicology. 23: 293-297.
^{1052} Myou, S.; Fujimura, M.; Nishi K.; Ohka, T.; and Matsuda, T. (1993). Aerosolized acetaldehyde induces histamine-mediated bronchoconstriction in asthmatics. Am. Rev. Respir.Dis.148(4 Pt 1): 940-943.
^{1053} California OEHHA, 2014. TSD for Noncancer RELs: Appendix D. Individual, Acute, 8-Hour, and Chronic Reference Exposure Level Summaries. December 2008 (updated July 2014). https://oehha.ca.gov/media/downloads/crnr/appendixd1final.pdf.

b. Benzene
EPA's Integrated Risk Information System (IRIS) database lists benzene as a known human carcinogen (causing leukemia) by all routes of exposure and concludes that exposure is associated with additional health effects, including genetic changes in both humans and animals and increased proliferation of bone marrow cells in mice. 1054 1055 1056 EPA states in its IRIS database that data indicate a causal relationship between benzene exposure and acute lymphocytic leukemia and suggest a relationship between benzene exposure and chronic non-lymphocytic leukemia and chronic lymphocytic leukemia. EPA's IRIS documentation for benzene also lists a range of 2.2 × 10 −6 to 7.8 × 10 −6 per µg/m ^3 as the unit risk estimate (URE) for benzene. 1057 1058 The International Agency for Research on Cancer (IARC) has determined that benzene is a human carcinogen, and the U.S. Department of Health and Human Services (DHHS) has characterized benzene as a known human carcinogen. 1059 1060
^{1054} U.S. EPA. (2000). Integrated Risk Information System File for Benzene. This material is available electronically at: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
^{1055} International Agency for Research on Cancer. (1982). IARC monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Some industrial chemicals and dyestuffs, International Agency for Research on Cancer, World Health Organization, Lyon, France 1982.
^{1056} Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992). Synergistic action of the benzene metabolite hydroquinone on myelopoietic stimulating activity of granulocyte/macrophage colony-stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691-3695.
^{1057} A unit risk estimate is defined as the increase in the lifetime risk of cancer of an individual who is exposed for a lifetime to 1 µg/m3 benzene in air.
^{1058} U.S. EPA. (2000). Integrated Risk Information System File for Benzene. This material is available electronically at: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
^{1059} International Agency for Research on Cancer (IARC, 2018. Monographs on the evaluation of carcinogenic risks to humans, volume 120. World Health Organization—Lyon, France. http://publications.iarc.fr/Book-And-Report-Series/Iarc-Monographs-On-The-Identification-Of-Carcinogenic-Hazards-To-Humans/Benzene-2018.
^{1060} NTP (National Toxicology Program). 2016. Report on Carcinogens, Fourteenth Edition.; Research Triangle Park, NC: U.S. Department of Health and Human Services, Public Health Service. https://ntp.niehs.nih.gov/go/roc14.
A number of adverse noncancer health effects, including blood disorders such as preleukemia and aplastic anemia, have also been associated with long-term exposure to benzene. 1061 1062 The most sensitive noncancer effect observed in humans, based on current data, is the depression of the absolute lymphocyte count in blood. 1063 1064 EPA's inhalation reference concentration (RfC) for benzene is 30 µg/m ^3 . The RfC is based on suppressed absolute lymphocyte counts seen in humans under occupational exposure conditions. In addition, studies sponsored by the Health Effects Institute (HEI) provide evidence that biochemical responses occur at lower levels of benzene exposure than previously known. 1065 1066 1067 1068 EPA's IRIS program has not yet evaluated these new data. EPA does not currently have an acute reference concentration for benzene. The Agency for Toxic Substances and Disease Registry (ATSDR) Minimal Risk Level (MRL) for acute inhalation exposure to benzene is 29 µg/m ^3 for 1-14 days exposure. 1069 1070
^{1061} Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197. EPA-HQ-OAR-2011-0135.
^{1062} Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554.
^{1063} Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T. Smith, N. Titenko-Holland, L.P. Zhang, W. Blot, S.N. Yin, and R.B. Hayes. (1996). Hematotoxicity among Chinese workers heavily exposed to benzene. Am. J. Ind. Med. 29: 236-246.
^{1064} U.S. EPA (2002). Toxicological Review of Benzene (Noncancer Effects). Environmental Protection Agency, Integrated Risk Information System (IRIS), Research and Development, National Center for Environmental Assessment, Washington DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris/iris_documents/documents/toxreviews/0276tr.pdf.
^{1065} Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003). HEI Report 115, Validation & Evaluation of Biomarkers in Workers Exposed to Benzene in China.
^{1066} Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et al. (2002). Hematological changes among Chinese workers with a broad range of benzene exposures. Am. J. Industr. Med. 42: 275-285.
^{1067} Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 306: 1774-1776.
^{1068} Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from Urban Air. Research Reports Health Effect Inst. Report No.113.
^{1069} U.S. Agency for Toxic Substances and Disease Registry (ATSDR). (2007). Toxicological profile for benzene. Atlanta, GA: U.S. Department of Health and Human Services, Public Health Service. http://www.atsdr.cdc.gov/ToxProfiles/tp3.pdf.
^{1070} A minimal risk level (MRL) is defined as an estimate of the daily human exposure to a hazardous substance that is likely to be without appreciable risk of adverse noncancer health effects over a specified duration of exposure.
There is limited information from two studies regarding an increased risk of adverse effects to children whose parents have been occupationally more e to benzene. 1071 1072 Data from animal studies have shown benzene exposures result in damage to the hematopoietic (blood cell formation) system during development. 1073 1074 1075 Also, key changes related to the development of childhood leukemia occur in the developing fetus. ^{1076} Several studies have reported that genetic changes related to eventual leukemia development occur before birth. For example, there is one study of genetic changes in twins who developed T cell leukemia at nine years of age. ^{1077}
^{1071} Corti, M; Snyder, CA. (1996) Influences of gender, development, pregnancy and ethanol consumption on the hematotoxicity of inhaled 10 ppm benzene. Arch Toxicol 70:209-217.
^{1072} McKinney P.A.; Alexander, F.E.; Cartwright, R.A.; et al. (1991) Parental occupations of children with leukemia in west Cumbria, north Humberside, and Gateshead, Br Med J 302:681-686.
^{1073} Keller, KA; Snyder, CA. (1986) Mice exposed in utero to low concentrations of benzene exhibit enduring changes in their colony forming hematopoietic cells. Toxicology 42:171-181.
^{1074} Keller, KA; Snyder, CA. (1988) Mice exposed in utero to 20 ppm benzene exhibit altered numbers of recognizable hematopoietic cells up to seven weeks after exposure. Fundam Appl Toxicol 10:224-232.
^{1075} Corti, M; Snyder, CA. (1996) Influences of gender, development, pregnancy and ethanol consumption on the hematotoxicity of inhaled 10 ppm benzene. Arch Toxicol 70:209-217.
^{1076} U. S. EPA. (2002). Toxicological Review of Benzene (Noncancer Effects). National Center for Environmental Assessment, Washington, DC. Report No. EPA/635/R-02/001F. https://cfpub.epa.gov/ncea/iris/iris_documents/documents/toxreviews/0276tr.pdf.
^{1077} Ford, AM; Pombo-de-Oliveira, MS; McCarthy, KP; MacLean, JM; Carrico, KC; Vincent, RF; Greaves, M. (1997) Monoclonal origin of concordant T-cell malignancy in identical twins. Blood 89:281-285.

c. 1,3-Butadiene
EPA has characterized 1,3-butadiene as carcinogenic to humans by inhalation. 1078 1079 The IARC has determined that 1,3-butadiene is a human carcinogen, and the U.S. DHHS has characterized 1,3-butadiene as a known human carcinogen. 1080 1081 1082 1083 There are numerous studies consistently demonstrating that 1,3-butadiene is metabolized into genotoxic metabolites by experimental animals and humans. The specific mechanisms of 1,3-butadiene-induced carcinogenesis are unknown; however, the scientific evidence strongly suggests that the carcinogenic effects are mediated by genotoxic metabolites. Animal data suggest that females may be more sensitive than males for cancer effects associated with 1,3-butadiene exposure; there are insufficient data in humans from which to draw conclusions about sensitive subpopulations. The URE for 1,3-butadiene is 3 × 10 −5 per µg/m ^3 . ^{1084} 1,3-butadiene also causes a variety of reproductive and developmental effects in mice; no human data on these effects are available. The most sensitive effect was ovarian atrophy observed in a lifetime bioassay of female mice. ^{1085}
Based on this critical effect and the benchmark concentration methodology, an RfC for chronic health effects was calculated at 0.9 ppb (approximately 2 µg/m ^3 ).
^{1078} U.S. EPA. (2002). Health Assessment of 1,3-Butadiene. Office of Research and Development, National Center for Environmental Assessment, Washington Office, Washington, DC. Report No. EPA600-P-98-001F. This document is available electronically at https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=54499 .
^{1079} U.S. EPA. (2002) “Full IRIS Summary for 1,3-butadiene (CASRN 106-99-0)” Environmental Protection Agency, Integrated Risk Information System (IRIS), Research and Development, National Center for Environmental Assessment, Washington, DC https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=139.
^{1080} International Agency for Research on Cancer (IARC). (1999). Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 71, Re-evaluation of some organic chemicals, hydrazine and hydrogen peroxide, World Health Organization, Lyon, France.
^{1081} International Agency for Research on Cancer (IARC). (2008). Monographs on the evaluation of carcinogenic risk of chemicals to humans, 1,3-Butadiene, Ethylene Oxide and Vinyl Halides (Vinyl Fluoride, Vinyl Chloride and Vinyl Bromide) Volume 97, World Health Organization, Lyon, France.
^{1082} NTP (National Toxicology Program). 2016. Report on Carcinogens, Fourteenth Edition.; Research Triangle Park, NC: U.S. Department of Health and Human Services, Public Health Service. https://ntp.niehs.nih.gov/go/roc14.
^{1083} International Agency for Research on Cancer (IARC). (2012). Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 100F chemical agents and related occupations, World Health Organization, Lyon, France.
^{1084} U.S. EPA. (2002). “Full IRIS Summary for 1,3-butadiene (CASRN 106-99-0)” Environmental Protection Agency, Integrated Risk Information System (IRIS), Research and Development, National Center for Environmental Assessment, Washington, DC https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=139 .
^{1085} Bevan, C.; Stadler, J.C.; Elliot, G.S.; et al. (1996). Subchronic toxicity of 4-vinylcyclohexene in rats and mice by inhalation. Fundam. Appl. Toxicol. 32:1-10.

d. Formaldehyde
In 1991, EPA concluded that formaldehyde is a Class B1 probable human carcinogen based on limited evidence in humans and sufficient evidence in animals. ^{1086} An inhalation URE for cancer and a reference dose for oral noncancer effects were developed by EPA and posted on the IRIS database. Since that time, the NTP and IARC have concluded that formaldehyde is a known human carcinogen. 1087 1088 1089
^{1086} EPA. Integrated Risk Information System. Formaldehyde (CASRN 50-00-0) https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=419.
^{1087} NTP (National Toxicology Program). 2016. Report on Carcinogens, Fourteenth Edition.; Research Triangle Park, NC: U.S. Department of Health and Human Services, Public Health Service. https://ntp.niehs.nih.gov/go/roc14.
^{1088} IARC Monographs on the Evaluation of Carcinogenic Risks to Humans Volume 88 (2006): Formaldehyde, 2-Butoxyethanol and 1-tert-Butoxypropan-2-ol.
^{1089} IARC Monographs on the Evaluation of Carcinogenic Risks to Humans Volume 100F (2012): Formaldehyde.
The conclusions by IARC and NTP reflect the results of epidemiologic research published since 1991 in combination with previous and more recent animal, human and mechanistic evidence. Research conducted by the National Cancer Institute reported an increased risk of nasopharyngeal cancer and specific lymphohematopoietic malignancies among workers exposed to formaldehyde. 1090 1091 1092 A National Institute of Occupational Safety and Health study of garment workers also reported increased risk of death due to leukemia among workers exposed to formaldehyde. ^{1093} Extended follow-up of a cohort of British chemical workers did not report evidence of an increase in nasopharyngeal or lymphohematopoietic cancers, but a continuing statistically significant excess in lung cancers was reported. ^{1094} Finally, a study of embalmers reported formaldehyde exposures to be associated with an increased risk of myeloid leukemia but not brain cancer. ^{1095}
^{1090} Hauptmann, M.; Lubin, J.H.; Stewart, P.A.; Hayes, R.B.; Blair, A. 2003. Mortality from lymphohematopoetic malignancies among workers in formaldehyde industries. Journal of the National Cancer Institute 95: 1615-1623.
^{1091} Hauptmann, M.; Lubin, J.H.; Stewart, P.A.; Hayes, R.B.; Blair, A. 2004. Mortality from solid cancers among workers in formaldehyde industries. American Journal of Epidemiology 159: 1117-1130.
^{1092} Beane Freeman, L.E.; Blair, A.; Lubin, J.H.; Stewart, P.A.; Hayes, R.B.; Hoover, R.N.; Hauptmann, M. 2009. Mortality from lymphohematopoietic malignancies among workers in formaldehyde industries: The National Cancer Institute cohort. J. National Cancer Inst. 101: 751-761.
^{1093} Pinkerton, L.E. 2004. Mortality among a cohort of garment workers exposed to formaldehyde: an update. Occup. Environ. Med. 61: 193-200.
^{1094} Coggon, D, EC Harris, J Poole, KT Palmer. 2003. Extended follow-up of a cohort of British chemical workers exposed to formaldehyde. J National Cancer Inst. 95:1608-1615.
^{1095} Hauptmann, M.; Stewart P.A.; Lubin J.H.; Beane Freeman, L.E.; Hornung, R.W.; Herrick, R.F.; Hoover, R.N.; Fraumeni, J.F.; Hayes, R.B. 2009. Mortality from lymphohematopoietic malignancies and brain cancer among embalmers exposed to formaldehyde. Journal of the National Cancer Institute 101:1696-1708.
Health effects of formaldehyde in addition to cancer were reviewed by the Agency for Toxics Substances and Disease Registry in 1999, supplemented in 2010, and by the World Health Organization. 1096 1097 1098 These organizations reviewed the scientific literature concerning health effects linked to formaldehyde exposure to evaluate hazards and dose response relationships and defined exposure concentrations for minimal risk levels (MRLs). The health endpoints reviewed included sensory irritation of eyes and respiratory tract, reduced pulmonary function, nasal histopathology, and immune system effects. In addition, research on reproductive and developmental effects and neurological effects was discussed along with several studies that suggest that formaldehyde may increase the risk of asthma—particularly in the young.
^{1096} ATSDR. 1999. Toxicological Profile for Formaldehyde, U.S. Department of Health and Human Services (HHS), July 1999.
^{1097} ATSDR. 2010. Addendum to the Toxicological Profile for Formaldehyde. U.S. Department of Health and Human Services (HHS), October 2010.
^{1098} IPCS. 2002. Concise International Chemical Assessment Document 40. Formaldehyde. World Health Organization.
In June 2010, EPA released a draft Toxicological Review of Formaldehyde—Inhalation Assessment through the IRIS program for peer review by the National Research Council (NRC) and public comment. ^{1099} That draft assessment reviewed more recent research from animal and human studies on cancer and other health effects. The NRC released their review report in April 2011. ^{1100} EPA addressed the NRC (2011) recommendations and applied systematic review methods to the evaluation of the available noncancer and cancer health effects evidence and released a new draft IRIS Toxicological Review of Formaldehyde—Inhalation in April 2022. ^{1101} In this draft, updates to the 1991 IRIS finding include a stronger determination of the carcinogenicity of formaldehyde inhalation to humans, as well as characterization of its noncancer effects to propose an overall reference concentration for inhalation exposure. The National Academies of Sciences, Engineering, and Medicine released their review of EPA's 2022 Draft Formaldehyde Assessment in August 2023, concluding that EPA's “findings on formaldehyde hazard and quantitative risk are supported by the evidence identified.” ^{1102} EPA is currently revising the draft IRIS assessment in response to comments received. ^{1103}
^{1099} EPA (U.S. Environmental Protection Agency). 2010. Toxicological Review of Formaldehyde (CAS No. 50-00-0)—Inhalation Assessment: In Support of Summary Information on the Integrated Risk Information System (IRIS). External Review Draft. EPA/635/R-10/002A. U.S. Environmental Protection Agency, Washington DC [online]. Available: http://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=223614 .
^{1100} NRC (National Research Council). 2011. Review of the Environmental Protection Agency's Draft IRIS Assessment of Formaldehyde. Washington DC: National Academies Press. http://books.nap.edu/openbook.php?record_id=13142 .
^{1101} U.S. EPA. 2022. IRIS Toxicological Review of Formaldehyde-Inhalation (External Review Draft, 2022). U.S. Environmental Protection Agency, Washington, DC, EPA/635/R-22/039.
^{1102} National Academies of Sciences, Engineering, and Medicine. 2023. Review of EPA's 2022 Draft Formaldehyde Assessment. Washington, DC: The National Academies Press. https://doi.org/10.17226/27153 .
^{1103} For more information, see https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=248150# .

e. Naphthalene
Naphthalene is found in small quantities in gasoline and diesel fuels. Naphthalene emissions have been measured in larger quantities in both gasoline and diesel exhaust compared with evaporative emissions from mobile sources, indicating it is primarily a product of combustion.
Acute (short-term) exposure of humans to naphthalene by inhalation, ingestion, or dermal contact is associated with hemolytic anemia and damage to the liver and the nervous system. ^{1104} Chronic (long term) exposure of workers and rodents to naphthalene has been reported to cause cataracts and retinal damage. ^{1105}
Children, especially neonates, appear to be more susceptible to acute naphthalene poisoning based on the number of reports of lethal cases in children and infants (hypothesized to be due to immature naphthalene detoxification pathways). ^{1106} EPA released an external review draft of a reassessment of the inhalation carcinogenicity of naphthalene based on a number of recent animal carcinogenicity studies. ^{1107} The draft reassessment completed external peer review. ^{1108} Based on external peer review comments received, EPA is developing a revised draft assessment that considers inhalation and oral routes of exposure, as well as cancer and noncancer effects. ^{1109} The external review draft does not represent official agency opinion and was released solely for the purposes of external peer review and public comment. The NTP listed naphthalene as “reasonably anticipated to be a human carcinogen” in 2004 on the basis of bioassays reporting clear evidence of carcinogenicity in rats and some evidence of carcinogenicity in mice. ^{1110} California EPA has released a new risk assessment for naphthalene, and the IARC has reevaluated naphthalene and re-classified it as Group 2B: possibly carcinogenic to humans. ^{1111}
^{1104} U.S. EPA. 1998. Toxicological Review of Naphthalene (Reassessment of the Inhalation Cancer Risk), Environmental Protection Agency, Integrated Risk Information System, Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=56434 .
^{1105} U.S. EPA. 1998. Toxicological Review of Naphthalene (Reassessment of the Inhalation Cancer Risk), Environmental Protection Agency, Integrated Risk Information System, Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=56434 .
^{1106} U.S. EPA. (1998). Toxicological Review of Naphthalene (Reassessment of the Inhalation Cancer Risk), Environmental Protection Agency, Integrated Risk Information System, Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=56434.
^{1107} U.S. EPA. (1998). Toxicological Review of Naphthalene (Reassessment of the Inhalation Cancer Risk), Environmental Protection Agency, Integrated Risk Information System, Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=56434.
^{1108} Oak Ridge Institute for Science and Education. (2004). External Peer Review for the IRIS Reassessment of the Inhalation Carcinogenicity of Naphthalene. August 2004. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=84403.
^{1109} U.S. EPA. (2018) See: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=436.
^{1110} NTP (National Toxicology Program). 2016. Report on Carcinogens, Fourteenth Edition.; Research Triangle Park, NC: U.S. Department of Health and Human Services, Public Health Service. https://ntp.niehs.nih.gov/go/roc14 .
^{1111} International Agency for Research on Cancer (IARC). (2002). Monographs on the Evaluation of the Carcinogenic Risk of Chemicals for Humans. Vol. 82. Lyon, France.
Naphthalene also causes a number of non-cancer effects in animals following chronic and less-than-chronic exposure, including abnormal cell changes and growth in respiratory and nasal tissues. ^{1112} The current EPA IRIS assessment includes noncancer data on hyperplasia and metaplasia in nasal tissue that form the basis of the inhalation RfC of 3 μg/m ^3 . ^{1113} The ATSDR MRL for acute and intermediate duration oral exposure to naphthalene is 0.6 mg/kg/day based on maternal toxicity in a developmental toxicology study in rats. ^{1114} ATSDR also derived an ad hoc reference value of 6 × 10 − ^2 mg/m ^3 for acute (≤24-hour) inhalation exposure to naphthalene in a Letter Health Consultation dated March 24, 2014 to address a potential exposure concern in Illinois. ^{1115} The ATSDR acute inhalation reference value was based on a qualitative identification of an exposure level interpreted not to cause pulmonary lesions in mice. More recently, EPA developed acute RfCs for 1-, 8-, and 24-hour exposure scenarios; the ≤24-hour reference value is 2 × 10 − ^2 mg/m ^3 . ^{1116} EPA's acute RfCs are based on a systematic review of the literature, benchmark dose modeling of naphthalene-induced nasal lesions in rats, and application of a PBPK (physiologically based pharmacokinetic) model.
^{1112} U. S. EPA. (1998). Toxicological Review of Naphthalene, Environmental Protection Agency, Integrated Risk Information System, Research and Development, National Center for Environmental Assessment, Washington, DC. This material is available electronically at https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=56434 .
^{1113} U.S. EPA. (1998). Toxicological Review of Naphthalene. Environmental Protection Agency, Integrated Risk Information System (IRIS), Research and Development, National Center for Environmental Assessment, Washington, DC https://cfpub.epa.gov/ncea/iris_drafts/recordisplay.cfm?deid=56434 .
^{1114} ATSDR. Toxicological Profile for Naphthalene, 1-Methylnaphthalene, and 2-Methylnaphthalene (2005). https://www.atsdr.cdc.gov/ToxProfiles/tp67-p.pdf .
^{1115} ATSDR. Letter Health Consultation, Radiac Abrasives, Inc., Chicago, Illinois (2014). https://www.atsdr.cdc.gov/HAC/pha/RadiacAbrasives/Radiac%20Abrasives,%20Inc.%20_%20LHC%20(Final)%20_%2003-24-2014%20(2)_508.pdf.
^{1116} U. S. EPA. Derivation of an acute reference concentration for inhalation exposure to naphthalene. Report No. EPA/600/R-21/292. https://cfpub.epa.gov/ncea/risk/recordisplay.cfm?deid=355035.

viii. Exposure and Health Effects Associated With Traffic
Locations near major roadways generally have elevated concentrations of many air pollutants emitted from motor vehicles. Hundreds of studies have been published in peer-reviewed journals, concluding that concentrations of CO, CO 2 , NO, NO 2 , benzene, aldehydes, particulate matter, black carbon, and many other compounds are elevated in ambient air within approximately 300-600 meters (about 1,000-2,000 feet) of major roadways. The highest concentrations of most pollutants emitted directly by motor vehicles are found within 50 meters (about 165 feet) of the edge of a roadway's traffic lanes.
A large-scale review of air quality measurements in the vicinity of major roadways between 1978 and 2008 concluded that the pollutants with the steepest concentration gradients in vicinities of roadways were CO, ultrafine particles, metals, elemental carbon (EC), NO, NO X , and several VOCs. ^{1117} These pollutants showed a large reduction in concentrations within 100 meters downwind of the roadway. Pollutants that showed more gradual reductions with distance from roadways included benzene, NO 2 , PM 2.5 , and PM 10 . In reviewing the literature, Karner et al. (2010) reported that results varied based on the method of statistical analysis used to determine the gradient in pollutant concentration. More recent studies of traffic-related air pollutants continue to report sharp gradients around roadways, particularly within several hundred meters. ^{1118}
^{1119}
^{1120}
^{1121}
^{1122}
^{1123}
^{1124}
^{1125} There is evidence that EPA's regulations for vehicles have lowered the near-road concentrations and gradients. ^{1126} Starting in 2010, EPA required through the NAAQS process that air quality monitors be placed near high-traffic roadways for determining concentrations of CO, NO 2 , and PM 2.5 . The monitoring data for NO 2 and CO indicate that in urban areas, monitors near roadways often report the highest concentrations. 1127 1128
^{1117} Karner, A.A.; Eisinger, D.S.; Niemeier, D.A. (2010). Near-roadway air quality: synthesizing the findings from real-world data. Environ Sci Technol 44: 5334-5344.
^{1118} McDonald, B.C.; McBride, Z.C.; Martin, E.W.; Harley, R.A. (2014) High-resolution mapping of motor vehicle carbon dioxide emissions. J. Geophys. Res.Atmos.,119, 5283-5298, doi:10.1002/2013JD021219.
^{1119} Kimbrough, S.; Baldauf, R.W.; Hagler, G.S.W.; Shores, R.C.; Mitchell, W.; Whitaker, D.A.; Croghan, C.W.; Vallero, D.A. (2013) Long-term continuous measurement of near-road air pollution in Las Vegas: seasonal variability in traffic emissions impact on air quality. Air Qual Atmos Health 6: 295-305. DOI 10.1007/s11869-012-0171-x.
^{1120} Kimbrough, S.; Palma, T.; Baldauf, R.W. (2014) Analysis of mobile source air toxics (MSATs)—Near-road VOC and carbonyl concentrations. Journal of the Air &Waste Management Association, 64:3, 349-359, DOI: 10.1080/10962247.2013.863814.
^{1121} Kimbrough, S.; Owen, R.C.; Snyder, M.; Richmond-Bryant, J. (2017) NO to NO 2 Conversion Rate Analysis and Implications for Dispersion Model Chemistry Methods using Las Vegas, Nevada Near-Road Field Measurements. Atmos Environ 165: 23-24.
^{1122} Apte, J.S.; Messier, K.P.; Gani, S.; Brauer, M.; Kirchstetter, T.W.; Lunden, M.M.; Marshall, J.D.; Portier, C.J.; Vermeulen, R.C.H.; Hamburg, S.P. (2017) High-Resolution Air Pollution Mapping with Google Street View Cars: Exploiting Big Data. Environ Sci Technol 51: 6999-7008. https://doi.org/10.1021/acs.est.7b00891 .
^{1123} Gu, P.; Li, H.Z.; Ye, Q.; et al. (2018) Intercity variability of particulate matter is driven by carbonaceous sources and correlated with land-use variables. Environ Sci Technol 52: 52: 11545-11554. [Online at http://dx.doi.org/10.1021/acs.est.8b03833 ].
^{1124} Hilker, N.; Wang, J.W.; Jong, C-H.; Healy, R.M.; Sofowote, U.; Debosz, J.; Su, Y.; Noble, M.; Munoz, A.; Doerkson, G.; White, L.; Audette, C.; Herod, D.; Brook, J.R.; Evans, G.J. (2019) Traffic-related air pollution near roadways: discerning local impacts from background. Atmos. Meas. Tech., 12, 5247-5261. https://doi.org/10.5194/amt-12-5247-2019 .
^{1125} Dabek-Zlotorzynska, E., V. Celo, L. Ding, D. Herod, C-H. Jeong, G. Evans, and N. Hilker. 2019. “Characteristics and sources of PM 2.5 and reactive gases near roadways in two metropolitan areas in Canada.” Atmos Environ 218: 116980.
^{1126} Sarnat, J.A.; Russell, A.; Liang, D.; Moutinho, J.L; Golan, R.; Weber, R.; Gao, D.; Sarnat, S.; Chang, H.H.; Greenwald, R.; Yu, T. (2018) Developing Multipollutant Exposure Indicators of Traffic Pollution: The Dorm Room Inhalation to Vehicle Emissions (DRIVE) Study. Health Effects Institute Research Report Number 196. [Online at: https://www.healtheffects.org/publication/developing-multipollutant-exposure-indicators-traffic-pollution-dorm-room-inhalation ].
^{1127} Gantt, B; Owen, R.C.; Watkins, N. (2021) Characterizing nitrogen oxides and fine particulate matter near major highways in the United States using the National Near-road Monitoring Network. Environ Sci Technol 55: 2831-2838. [Online at https://doi.org/10.1021/acs.est.0c05851 ].
^{1128} Lal, R.M.; Ramaswani, A.; Russell, A.G. (2020) Assessment of the near-road (monitoring) network including comparison with nearby monitors within U.S. cities. Environ Res Letters 15: 114026. [Online at https://doi.org/10.1088/1748-9326/ab8156 ].
For pollutants with relatively high background concentrations relative to near-road concentrations, detecting concentration gradients can be difficult. For example, many carbonyls have high background concentrations because of photochemical breakdown of precursors from many different organic compounds. However, several studies have measured carbonyls in multiple weather conditions and found higher concentrations of many carbonyls downwind of roadways. 1129 1130 These findings suggest a substantial roadway source of these carbonyls.
^{1129} Liu, W.; Zhang, J.; Kwon, J.l; et l. (2006). Concentrations and source characteristics of airborne carbonyl compounds measured outside urban residences. J Air Waste Manage Assoc 56: 1196-1204.
^{1130} Cahill, T.M.; Charles, M.J.; Seaman, V.Y. (2010). Development and application of a sensitive method to determine concentrations of acrolein and other carbonyls in ambient air. Health Effects Institute Research Report 149. Available at https://www.healtheffects.org/system/files/Cahill149.pdf .
In the past 30 years, many studies have been published with results reporting that populations who live, work, or go to school near high-traffic roadways experience higher rates of numerous adverse health effects, compared to populations far away from major roads. ^{1131} In addition, numerous studies have found adverse health effects associated with spending time in traffic, such as commuting or walking along high-traffic roadways, including studies among children. 1132 1133 1134 1135
^{1131} In the widely used PubMed database of health publications, between January 1, 1990 and December 31, 2021, 1,979 publications contained the keywords “traffic, pollution, epidemiology,” with approximately half the studies published after 2015.
^{1132} Laden, F.; Hart, J.E.; Smith, T.J.; Davis, M.E.; Garshick, E. (2007) Cause-specific mortality in the unionized U.S. trucking industry. Environmental Health Perspect 115:1192-1196.
^{1133} Peters, A.; von Klot, S.; Heier, M.; Trentinaglia, I.; Hörmann, A.; Wichmann, H.E.; Löwel, H. (2004) Exposure to traffic and the onset of myocardial infarction. New England J Med 351: 1721-1730.
^{1134} Zanobetti, A.; Stone, P.H.; Spelzer, F.E.; Schwartz, J.D.; Coull, B.A.; Suh, H.H.; Nearling, B.D.; Mittleman, M.A.; Verrier, R.L.; Gold, D.R. (2009) T-wave alternans, air pollution and traffic in high-risk subjects. Am J Cardiol 104: 665-670.
^{1135} Adar, S.; Adamkiewicz, G.; Gold, D.R.; Schwartz, J.; Coull, B.A.; Suh, H. (2007) Ambient and microenvironmental particles and exhaled nitric oxide before and after a group bus trip. Environ Health Perspect 115: 507-512.
Numerous reviews of this body of health literature have been published. In a 2022 final report, an expert panel of the Health Effects Institute (HEI) employed a systematic review focusing on selected health endpoints related to exposure to traffic-related air pollution. ^{1136} The HEI panel concluded that there was a high level of confidence in evidence between long-term exposure to traffic-related air pollution and health effects in adults, including all-cause, circulatory, and ischemic heart disease mortality. ^{1137} The panel also found that there is a moderate-to-high level of confidence in evidence of associations with asthma onset and acute respiratory infections in children and lung cancer and asthma onset in adults. The panel concluded that there was a moderate level of evidence of associations with small for gestational age births, but low-to-moderate confidence for other birth outcomes (term birth weight and preterm birth). This report follows on an earlier expert review published by HEI in 2010, where it found strongest evidence for asthma-related traffic impacts. Other literature reviews have been published with conclusions generally similar to the HEI panels'. 1138 1139 1140 1141 Additionally, in 2014, researchers from the U.S. Centers for Disease Control and Prevention (CDC) published a systematic review and meta-analysis of studies evaluating the risk of childhood leukemia associated with traffic exposure and reported positive associations between postnatal proximity to traffic and leukemia risks, but no such association for prenatal exposures. ^{1142} The U.S. Department of Health and Human Services' National Toxicology Program published a monograph including a systematic review of traffic-related air pollution and its impacts on hypertensive disorders of pregnancy. The National Toxicology Program concluded that exposure to traffic-related air pollution is “presumed to be a hazard to pregnant women” for developing hypertensive disorders of pregnancy. ^{1143}
^{1136} HEI Panel on the Health Effects of Long-Term Exposure to Traffic-Related Air Pollution (2022) Systematic review and meta-analysis of selected health effects of long-term exposure to traffic-related air pollution. Health Effects Institute Special Report 23. [Online at https://www.healtheffects.org/publication/systematic-review-and-meta-analysis-selected-health-effects-long-term-exposure-traffic ] This more recent review focused on health outcomes related to birth effects, respiratory effects, cardiometabolic effects, and mortality.
^{1137} Boogaard, H.; Patton, A.P.; Atkinson, R.W.; Brook, J.R.; Chang, H.H.; Crouse, D.L.; Fussell, J.C.; Hoek, G.; Hoffmann, B.; Kappeler, R.; Kutlar Joss, M.; Ondras, M.; Sagiv, S.K.; Samoli, E.; Shaikh, R.; Smargiassi, A.; Szpiro, A.A.; Van Vliet, E.D.S.; Vienneau, D.; Weuve, J.; Lurmann, F.W.; Forastiere, F. (2022) Long-term exposure to traffic-related air pollution and selected health outcomes: A systematic review and meta-analysis. Environ Internatl 164: 107262. [Online at https://doi.org/10.1016/j.envint.2022.107262 ].
^{1138} Boothe, V.L.; Shendell, D.G. (2008). Potential health effects associated with residential proximity to freeways and primary roads: review of scientific literature, 1999-2006. J Environ Health 70: 33-41.
^{1139} Salam, M.T.; Islam, T.; Gilliland, F.D. (2008). Recent evidence for adverse effects of residential proximity to traffic sources on asthma. Curr Opin Pulm Med 14: 3-8.
^{1140} Sun, X.; Zhang, S.; Ma, X. (2014) No association between traffic density and risk of childhood leukemia: a meta-analysis. Asia Pac J Cancer Prev 15: 5229-5232.
^{1141} Raaschou-Nielsen, O.; Reynolds, P. (2006). Air pollution and childhood cancer: a review of the epidemiological literature. Int J Cancer 118: 2920-9.
^{1142} Boothe, VL.; Boehmer, T.K.; Wendel, A.M.; Yip, F.Y. (2014) Residential traffic exposure and childhood leukemia: a systematic review and meta-analysis. Am J Prev Med 46: 413-422.
^{1143} National Toxicology Program (2019) NTP Monograph on the Systematic Review of Traffic-related Air Pollution and Hypertensive Disorders of Pregnancy. NTP Monograph 7. https://ntp.niehs.nih.gov/ntp/ohat/trap/mgraph/trap_final_508.pdf .
For several other health outcomes there are publications to suggest the possibility of an association with traffic-related air pollution, but insufficient evidence to draw definitive conclusions. Among these outcomes are neurological and cognitive impacts ( e.g., autism and reduced cognitive function, academic performance, and executive function) and reproductive outcomes ( e.g., preterm birth, low birth weight). 1144 1145 1146 1147 1148 1149
^{1144} Volk, H.E.; Hertz-Picciotto, I.; Delwiche, L.; et al. (2011). Residential proximity to freeways and autism in the CHARGE study. Environ Health Perspect 119: 873-877.
^{1145} Franco-Suglia, S.; Gryparis, A.; Wright, R.O.; et al. (2007). Association of black carbon with cognition among children in a prospective birth cohort study. Am J Epidemiol. doi: 10.1093/aje/kwm308. [Online at http://dx.doi.org ].
^{1146} Power, M.C.; Weisskopf, M.G.; Alexeef, SE; et al. (2011). Traffic-related air pollution and cognitive function in a cohort of older men. Environ Health Perspect 2011: 682-687.
^{1147} Wu, J.; Wilhelm, M.; Chung, J.; Ritz, B. (2011). Comparing exposure assessment methods for traffic-related air pollution in an adverse pregnancy outcome study. Environ Res 111: 685-692. https://doi.org/10.1016/j.envres.2011.03.008 .
^{1148} Stenson, C.; Wheeler, A.J.; Carver, A.; et al. (2021) The impact of traffic-related air pollution on child and adolescent academic performance: a systematic review. Environ Intl 155: 106696 [Online at https://doi.org/10.1016/j.envint.2021.106696 ].
^{1149} Gartland, N.; Aljofi, H.E.; Dienes, K.; et al. (2022) The effects of traffic air pollution in and around schools on executive function and academic performance in children: a rapid review. Int J Environ Res Public Health 19: 749. https://doi.org/10.3390/ijerph19020749.
Numerous studies have also investigated potential mechanisms by which traffic-related air pollution affects health, particularly for cardiopulmonary outcomes. For example, some research indicates that near-roadway exposures may increase systemic inflammation, affecting organ systems, including blood vessels and lungs. 1150 1151 1152 1153 Additionally, long-term exposures in near-road environments have been associated with inflammation-associated conditions, such as atherosclerosis and asthma. 1154 1155 1156
^{1150} Riediker, M. (2007). Cardiovascular effects of fine particulate matter components in highway patrol officers. Inhal Toxicol 19: 99-105. doi: 10.1080/08958370701495238.
^{1151} Alexeef, SE; Coull, B.A.; Gryparis, A.; et al. (2011). Medium-term exposure to traffic-related air pollution and markers of inflammation and endothelial function. Environ Health Perspect 119: 481-486. doi:10.1289/ehp.1002560.
^{1152} Eckel. S.P.; Berhane, K.; Salam, M.T.; et al. (2011). Residential Traffic-related pollution exposure and exhaled nitric oxide in the Children's Health Study. Environ Health Perspect. doi:10.1289/ehp.1103516.
^{1153} Zhang, J.; McCreanor, J.E.; Cullinan, P.; et al. (2009). Health effects of real-world exposure diesel exhaust in persons with asthma. Res Rep Health Effects Inst 138. [Online at http://www.healtheffects.org ].
^{1154} Adar, S.D.; Klein, R.; Klein, E.K.; et al. (2010). Air pollution and the microvasculature: a cross-sectional assessment of in vivo retinal images in the population-based Multi-Ethnic Study of Atherosclerosis. PLoS Med 7(11): E1000372. doi:10.1371/journal.pmed.1000372.
^{1155} Kan, H.; Heiss, G.; Rose, K.M.; et al. (2008). Prospective analysis of traffic exposure as a risk factor for incident coronary heart disease: The Atherosclerosis Risk in Communities (ARIC) study. Environ Health Perspect 116: 1463-1468. doi:10.1289/ehp.11290.
^{1156} McConnell, R.; Islam, T.; Shankardass, K.; et al. (2010). Childhood incident asthma and traffic-related air pollution at home and school. Environ Health Perspect 1021-1026.
As described in section VI.D.3, people who live or attend school near major roadways are more likely to be people of color and/or have a low SES. Additionally, people with low SES often live in neighborhoods with multiple stressors and health risk factors, including reduced health insurance coverage rates, higher smoking and drug use rates, limited access to fresh food, visible neighborhood violence, and elevated rates of obesity and some diseases such as asthma, diabetes, and ischemic heart disease. Although questions remain, several studies find stronger associations between air pollution and health in locations with such chronic neighborhood stress, suggesting that populations in these areas may be more susceptible to the effects of air pollution. 1157 1158 1159 1160 1161 1162 1163 1164
^{1157} Islam, T.; Urban, R.; Gauderman, W.J.; et al. (2011). Parental stress increases the detrimental effect of traffic exposure on children's lung function. Am J Respir Crit Care Med.
^{1158} Clougherty, J.E.; Kubzansky, L.D. (2009) A framework for examining social stress and susceptibility to air pollution in respiratory health. Environ Health Perspect 117: 1351-1358. Doi:10.1289/ehp.0900612.
^{1159} Clougherty, J.E.; Levy, J.I.; Kubzansky, L.D.; Ryan, P.B.; Franco Suglia, S.; Jacobson Canner, M.; Wright, R.J. (2007) Synergistic effects of traffic-related air pollution and exposure to violence on urban asthma etiology. Environ Health Perspect 115: 1140-1146. doi:10.1289/ehp.9863.
^{1160} Finkelstein, M.M.; Jerrett, M.; DeLuca, P.; Finkelstein, N.; Verma, D.K.; Chapman, K.; Sears, M.R. (2003) Relation between income, air pollution and mortality: a cohort study. Canadian Med Assn J 169: 397-402.
^{1161} Shankardass, K.; McConnell, R.; Jerrett, M.; Milam, J.; Richardson, J.; Berhane, K. (2009) Parental stress increases the effect of traffic-related air pollution on childhood asthma incidence. Proc Natl Acad Sci 106: 12406-12411. doi:10.1073/pnas.0812910106.
^{1162} Chen, E.; Schrier, H.M.; Strunk, R.C.; et al. (2008). Chronic traffic-related air pollution and stress interact to predict biologic and clinical outcomes in asthma. Environ Health Perspect 116: 970-5.
^{1163} Currie, J. and R. Walker (2011) Traffic Congestion and Infant Health: Evidence from E-ZPass. American Economic Journal: Applied Economics, 3 (1): 65-90. https://doi.org/10.1257/app.3.1.65.
^{1164} Knittel, C.R.; Miller, D.L.; Sanders N.J. (2016) Caution, Drivers! Children Present: Traffic, Pollution, and Infant Health. The Review of Economics and Statistics, 98 (2): 350-366. https://doi.org/10.1162/REST_a_00548.
The risks associated with residence, workplace, or school near major roads are of potentially high public health significance due to the large population in such locations. We analyzed several data sets to estimate the size of populations living or attending school near major roads. Our evaluation of environmental justice concerns in these studies is presented in section VI.D.3 of this preamble.
Every two years from 1997 to 2009 and in 2011 and 2013, the U.S. Census Bureau's American Housing Survey (AHS) conducted a survey that includes whether housing units are within 300 feet of an “airport, railroad, or highway with four or more lanes.” ^{1165} The 2013 AHS reports that 17.3 million housing units, or 13 percent of all housing units in the United States, were in such areas. Assuming that populations and housing units are in the same locations, this corresponds to a population of more than 41 million U.S. residents near high-traffic roadways or other transportation sources. ^{1166} According to the Central Intelligence Agency's World Factbook, based on data collected between 2012-2022, the United States had 6,586,610 km of roadways, 293,564 km of railways, and 13,513 airports. ^{1167} As such, highways represent the overwhelming majority of transportation facilities described by this factor in the AHS.
^{1165} The variable was known as “ETRANS” in the questions about the neighborhood.
^{1166} The analysis of population living near major roads based on the Freight Analysis Framework, version 4 is intended to provide comparable estimates as the AHS analyses for the conterminous United States ( i.e., “the lower 48”). Population estimates for the two methods result in very good agreement—41 million people living within 300 feet/100 meters using the AHS 2009 dataset, and 41 million people living within 100 meters of a road in the FAF4 network using the data in that analysis.
^{1167} Central Intelligence Agenda. World Factbook: United States. [Online at https://www.cia.gov/the-world-factbook/countries/united-states/#transportation ].
In examining schools near major roadways, we used the Common Core of Data from the U.S. Department of Education, which includes information on all public elementary and secondary schools and school districts nationwide. ^{1168} To determine school proximities to major roadways, we used a geographic information system (GIS) to map each school and roadway based on the U.S. Census's TIGER roadway file. ^{1169} We estimated that about 10 million students attend public schools within 200 meters of major roads, about 20 percent of the total number of public school students in the U.S. 1170 1171 1172
About 800,000 students attend public schools within 200 meters of primary roads, or about 2 percent of the total.
^{1168} http://nces.ed.gov/ccd/ .
^{1169} Pedde, M.; Bailey, C. (2011) Identification of Schools within 200 Meters of U.S. Primary and Secondary Roads. Memorandum to the docket.
^{1170} Pedde, M.; Bailey, C. (2011) Identification of Schools within 200 Meters of U.S. Primary and Secondary Roads. Memorandum to the docket.
^{1171} Here, “major roads” refer to those TIGER classifies as either “Primary” or “Secondary”. The Census Bureau describes primary roads as “generally divided limited-access highways within the Federal interstate system or under state management”. Secondary roads are “main arteries, usually in the U.S. highway, state highway, or county highway system”.
^{1172} For this analysis we analyzed a 200-meter distance based on the understanding that roadways generally influence air quality within a few hundred meters from the vicinity of heavily traveled roadways or along corridors with significant trucking traffic. See U.S. EPA, 2014. Near Roadway Air Pollution and Health: Frequently Asked Questions. EPA-420-F-14-044.
EPA also conducted a study to estimate the number of people living near truck freight routes in the United States, which includes many large highways and other routes where light- and medium-duty vehicles operate. ^{1173} Based on a population analysis using the U.S. Department of Transportation's (USDOT) Freight Analysis Framework 4 (FAF4) and population data from the 2010 decennial census, an estimated 72 million people live within 200 meters of these FAF4 roads, which are used by all types of vehicles. ^{1174} The FAF4 analysis includes the population living within 200 meters of major roads, while the AHS uses a 100-meter distance; the larger distance and other methodological differences explain the difference in the two estimates for populations living near major roads. ^{1175}
^{1173} U.S. EPA (2021). Estimation of Population Size and Demographic Characteristics among People Living Near Truck Routes in the Conterminous United States. Memorandum to the Docket.
^{1174} FAF4 is a model from the USDOT's Bureau of Transportation Statistics (BTS) and Federal Highway Administration (FHWA), which provides data associated with freight movement in the U.S. It includes data from the 2012 Commodity Flow Survey (CFS), the Census Bureau on international trade, as well as data associated with construction, agriculture, utilities, warehouses, and other industries. FAF4 estimates the modal choices for moving goods by trucks, trains, boats, and other types of freight modes. It includes traffic assignments, including truck flows on a network of truck routes. https://ops.fhwa.dot.gov/freight/freight_analysis/faf/ .
^{1175} The same analysis estimated the population living within 100 meters of a FAF4 truck route is 41 million.
The EPA's Exposure Factor Handbook also indicates that, on average, Americans spend more than an hour traveling each day, bringing nearly all residents into a high-exposure microenvironment for part of the day. 1176 1177 While near-roadway studies focus on residents near roads or others spending considerable time near major roads, the duration of commuting results in another important contributor to overall exposure to traffic-related air pollution. Studies of health that address time spent in transit have found evidence of elevated risk of cardiac impacts. 1178 1179 1180 Studies have also found that school bus emissions can increase student exposures to diesel-related air pollutants, and that programs that reduce school bus emissions may improve health and reduce school absenteeism. 1181 1182 1183 1184
^{1176} EPA. (2011) Exposure Factors Handbook: 2011 Edition. Chapter 16. Online at https://www.epa.gov/expobox/about-exposure-factors-handbook .
^{1177} It is not yet possible to estimate the long-term impact of growth in telework associated with the COVID-19 pandemic on travel behavior. There were notable changes during the pandemic. For example, according to the 2021 American Time Use Survey, a greater fraction of workers did at least part of their work at home (38%) as compared with the 2019 survey (24%). [Online at https://www.bls.gov/news.release/atus.nr0.htm ].
^{1178} Riediker, M.; Cascio, W.E.; Griggs, T.R.; et al. (2004) Particulate matter exposure in cars is associated with cardiovascular effects in healthy young men. Am J Respir Crit Care Med 169. [Online at https://doi.org/10.1164/rccm.200310-1463OC ].
^{1179} Peters, A.; von Klot, S.; Heier, M.; et al. (2004) Exposure to traffic and the onset of myocardial infarction. New Engl J Med 1721-1730. [ Online athttps://doi.org/10.1056/NEJMoa040203 ].
^{1180} Adar, S.D.; Gold, D.R.; Coull, B.A.; (2007) Focused exposure to airborne traffic particles and heart rate variability in the elderly. Epidemiology 18: 95-103 [Online at 351: https://doi.org/10.1097/01.ede.0000249409.81050.46 ].
^{1181} Sabin, L.; Behrentz, E.; Winer, A.M.; et al. Characterizing the range of children's air pollutant exposure during school bus commutes. J Expo Anal Environ Epidemiol 15: 377-387. [Online at https://doi.org/10.1038/sj.jea.7500414 ].
^{1182} Li, C.; N, Q.; Ryan, P.H.; School bus pollution and changes in the air quality at schools: a case study. J Environ Monit 11: 1037-1042. [ https://doi.org/10.1039/b819458k ].
^{1183} Austin, W.; Heutel, G.; Kreisman, D. (2019) School bus emissions, student health and academic performance. Econ Edu Rev 70: 108-12.
^{1184} Adar, S.D.; D.Souza, J.; Sheppard, L.; et al. (2015) Adopting clean fuels and technologies on school buses. Pollution and health impacts in children. Am J Respir Crit Care Med 191. [Online at http://doi.org/10.1164/rccm.201410-1924OC ].

3. Welfare Effects Associated With Exposure to Non-GHG Pollutants
This section discusses the environmental effects associated with non-GHG pollutants affected by this rule, specifically particulate matter, ozone, NO X, SO X , and air toxics.

i. Visibility
Visibility can be defined as the degree to which the atmosphere is transparent to visible light. ^{1185} Visibility impairment is caused by light scattering and absorption by suspended particles and gases. It is dominated by contributions from suspended particles except under pristine conditions. Visibility is important because it has direct significance to people's enjoyment of daily activities in all parts of the country. Individuals value good visibility for the well-being it provides them directly, where they live and work, and in places where they enjoy recreational opportunities. Visibility is also highly valued in significant natural areas, such as national parks and wilderness areas, and special emphasis is given to protecting visibility in these areas. For more information on visibility see the final 2019 PM ISA. ^{1186}
^{1185} National Research Council, (1993). Protecting Visibility in National Parks and Wilderness Areas. National Academy of Sciences Committee on Haze in National Parks and Wilderness Areas. National Academy Press, Washington, DC. This book can be viewed on the National Academy Press website at https://www.nap.edu/catalog/2097/protecting-visibility-in-national-parks-and-wilderness-areas .
^{1186} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
EPA is working to address visibility impairment. Reductions in air pollution from implementation of various programs associated with the Clean Air Act Amendments of 1990 provisions have resulted in substantial improvements in visibility and will continue to do so in the future. Nationally, because trends in haze are closely associated with trends in particulate sulfate and nitrate due to the relationship between their concentration and light extinction, visibility trends have improved as emissions of SO 2 and NO X have decreased over time due to air pollution regulations such as the Acid Rain Program. ^{1187} However, in the western part of the country, changes in total light extinction were smaller, and the contribution of particulate organic matter to atmospheric light extinction was increasing due to increasing wildfire emissions. ^{1188}
^{1187} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
^{1188} Hand, JL; Prenni, AJ; Copeland, S; Schichtel, BA; Malm, WC. (2020). Thirty years of the Clean Air Act Amendments: Impacts on haze in remote regions of the United States (1990-2018). Atmos Environ 243: 117865.
In the Clean Air Act Amendments of 1977, Congress recognized visibility's value to society by establishing a national goal to protect national parks and wilderness areas from visibility impairment caused by manmade pollution. ^{1189} In 1999, EPA finalized the regional haze program to protect the visibility in Mandatory Class I Federal areas. ^{1190} There are 156 national parks, forests and wilderness areas categorized as Mandatory Class I Federal areas. ^{1191} These areas are defined in CAA section 162 as those national parks exceeding 6,000 acres, wilderness areas and memorial parks exceeding 5,000 acres, and all international parks which were in existence on August 7, 1977.
^{1189} See CAA section 169(a).
^{1190} 64 FR 35714, July 1, 1999.
^{1191} 62 FR 38680-38681, July 18, 1997.
EPA has also concluded that PM 2.5 causes adverse effects on visibility in other areas that are not targeted by the Regional Haze Rule, such as urban areas, depending on PM 2.5 concentrations and other factors such as dry chemical composition and relative humidity ( i.e., an indicator of the water composition of the particles). The secondary (welfare-based) PM NAAQS provide protection against visibility effects. In recent PM NAAQS reviews, EPA evaluated a target level of protection for visibility impairment that is expected to be met through attainment of the existing secondary PM standards.

ii. Ozone Effects on Ecosystems
The welfare effects of ozone include effects on ecosystems, which can be observed across a variety of scales, i.e., subcellular, cellular, leaf, whole plant, population and ecosystem. Ozone effects that begin at small spatial scales, such as the leaf of an individual plant, when they occur at sufficient magnitudes (or to a sufficient degree) can result in effects being propagated to higher and higher levels of biological organization. For example, effects at the individual plant level, such as altered rates of leaf gas exchange, growth and reproduction, can, when widespread, result in broad changes in ecosystems, such as productivity, carbon storage, water cycling, nutrient cycling, and community composition.
Ozone can produce both acute and chronic injury in sensitive plant species depending on the concentration level and the duration of the exposure. ^{1192} In those sensitive species, ^{1193} effects from repeated exposure to ozone throughout the growing season of the plant can tend to accumulate, so even relatively low concentrations experienced for a longer duration have the potential to create chronic stress on vegetation. 1194 1195 Ozone damage to sensitive plant species includes impaired photosynthesis and visible injury to leaves. The impairment of photosynthesis, the process by which the plant makes carbohydrates (its source of energy and food), can lead to reduced crop yields, timber production, and plant productivity and growth. Impaired photosynthesis can also lead to a reduction in root growth and carbohydrate storage below ground, resulting in other, more subtle plant and ecosystems impacts. ^{1196} These latter impacts include increased susceptibility of plants to insect attack, disease, harsh weather, interspecies competition and overall decreased plant vigor. The adverse effects of ozone on areas with sensitive species could potentially lead to species shifts and loss from the affected ecosystems, ^{1197} resulting in a loss or reduction in associated ecosystem goods and services. Additionally, visible ozone injury to leaves can result in a loss of aesthetic value in areas of special scenic significance like national parks and wilderness areas and reduced use of sensitive ornamentals in landscaping. ^{1198} In addition to ozone effects on vegetation, newer evidence suggests that ozone affects interactions between plants and insects by altering chemical signals ( e.g., floral scents) that plants use to communicate to other community members, such as attraction of pollinators.
^{1192} 73 FR 16486, March 27, 2008.
^{1193} Only a small percentage of all the plant species growing within the U.S. (over 43,000 species have been catalogued in the USDA PLANTS database) have been studied with respect to ozone sensitivity.
^{1194} U.S. EPA. Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-20/012, 2020.
^{1195} The concentration at which ozone levels overwhelm a plant's ability to detoxify or compensate for oxidant exposure varies. Thus, whether a plant is classified as sensitive or tolerant depends in part on the exposure levels being considered.
^{1196} 73 FR 16492, March 27, 2008.
^{1197} 73 FR 16493-16494, March 27, 2008. Ozone impacts could be occurring in areas where plant species sensitive to ozone have not yet been studied or identified.
^{1198} 73 FR 16490-16497, March 27, 2008.
The Ozone ISA presents more detailed information on how ozone affects vegetation and ecosystems. ^{1199} The Ozone ISA reports causal and likely causal relationships between ozone exposure and a number of welfare effects and characterizes the weight of evidence for different effects associated with ozone. ^{1200} The Ozone ISA concludes that visible foliar injury effects on vegetation, reduced vegetation growth, reduced plant reproduction, reduced productivity in terrestrial ecosystems, reduced yield and quality of agricultural crops, alteration of below-ground biogeochemical cycles, and altered terrestrial community composition are causally associated with exposure to ozone. It also concludes that increased tree mortality, altered herbivore growth and reproduction, altered plant-insect signaling, reduced carbon sequestration in terrestrial ecosystems, and alteration of terrestrial ecosystem water cycling are likely to be causally associated with exposure to ozone.
^{1199} U.S. EPA. Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-20/012, 2020.
^{1200} The Ozone ISA evaluates the evidence associated with different ozone related health and welfare effects, assigning one of five “weight of evidence” determinations: causal relationship, likely to be a causal relationship, suggestive of a causal relationship, inadequate to infer a causal relationship, and not likely to be a causal relationship. For more information on these levels of evidence, please refer to Table II of the ISA.

iii. Deposition
The Integrated Science Assessment for Oxides of Nitrogen, Oxides of Sulfur, and Particulate Matter—Ecological Criteria documents the ecological effects of the deposition of these criteria air pollutants. ^{1201} It is clear from the body of evidence that oxides of nitrogen, oxides of sulfur, and particulate matter contribute to total nitrogen (N) and sulfur (S) deposition. In turn, N and S deposition cause either nutrient enrichment or acidification depending on the sensitivity of the landscape or the species in question. Both enrichment and acidification are characterized by an alteration of the biogeochemistry and the physiology of organisms, resulting in ecologically harmful declines in biodiversity in terrestrial, freshwater, wetland, and estuarine ecosystems in the U.S. Decreases in biodiversity mean that some species become relatively less abundant and may be locally extirpated. In addition to the potential loss of unique living species, the decline in total biodiversity can be harmful because biodiversity is an important determinant of the stability of ecosystems and their ability to provide socially valuable ecosystem services.
^{1201} U.S. EPA. Integrated Science Assessment (ISA) for Oxides of Nitrogen, Oxides of Sulfur and Particulate Matter Ecological Criteria (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-20/278, 2020.
Terrestrial, wetland, freshwater, and estuarine ecosystems in the U.S. are affected by nitrogen enrichment/eutrophication caused by nitrogen deposition. These effects, though improving recently as emissions and deposition decline, have been consistently documented across the United States for hundreds of species and have likely been occurring for decades. In terrestrial systems nitrogen loading can lead to loss of nitrogen-sensitive plant and lichen species, decreased biodiversity of grasslands, meadows and other sensitive habitats, and increased potential for invasive species and potentially for wildfire. In aquatic systems nitrogen loading can alter species assemblages and cause eutrophication.
The sensitivity of terrestrial and aquatic ecosystems to acidification from nitrogen and sulfur deposition is predominantly governed by the intersection of geology and deposition. Prolonged exposure to excess nitrogen and sulfur deposition in sensitive areas acidifies lakes, rivers, and soils. Increased acidity in surface waters creates inhospitable conditions for biota and affects the abundance and biodiversity of fishes, zooplankton and macroinvertebrates and ecosystem function. Over time, acidifying deposition also removes essential nutrients from forest soils, depleting the capacity of soils to neutralize future acid loadings and negatively affecting forest sustainability. Major effects in forests include a decline in sensitive tree species, such as red spruce (Picea rubens) and sugar maple (Acer saccharum).
Building materials including metals, stones, cements, and paints undergo natural weathering processes from exposure to environmental elements ( e.g., wind, moisture, temperature fluctuations, sunlight, etc.). Pollution can worsen and accelerate these effects. Deposition of PM is associated with both physical damage (materials damage effects) and impaired aesthetic qualities (soiling effects). Wet and dry deposition of PM can physically affect materials, adding to the effects of natural weathering processes, by potentially promoting or accelerating the corrosion of metals, by degrading paints and by deteriorating building materials such as stone, concrete and marble. ^{1202} The effects of PM are exacerbated by the presence of acidic gases and can be additive or synergistic due to the complex mixture of pollutants in the air and surface characteristics of the material. Acidic deposition has been shown to have an effect on materials including zinc/galvanized steel and other metal, carbonate stone (as monuments and building facings), and surface coatings (paints). ^{1203} The effects on historic buildings and outdoor works of art are of particular concern because of the uniqueness and irreplaceability of many of these objects. In addition to aesthetic and functional effects on metals, stone and glass, altered energy efficiency of photovoltaic panels by PM deposition is also an emerging consideration for impacts of air pollutants on materials.
^{1202} U.S. EPA. Integrated Science Assessment (ISA) for Particulate Matter (Final Report, 2019). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-19/188, 2019.
^{1203} Irving, P.M., e.d. 1991. Acid Deposition: State of Science and Technology, Volume III, Terrestrial, Materials, Health, and Visibility Effects, The U.S. National Acid Precipitation Assessment Program, Chapter 24, page 24-76.

iv. Welfare Effects Associated With Air Toxics
Emissions from producing, transporting, and combusting fuel contribute to ambient levels of pollutants that contribute to adverse effects on vegetation. Volatile organic compounds (VOCs), some of which are considered air toxics, have long been suspected to play a role in vegetation damage. ^{1204} In laboratory experiments, a wide range of tolerance to VOCs has been observed. ^{1205} Decreases in harvested seed pod weight have been reported for the more sensitive plants, and some studies have reported effects on seed germination, flowering, and fruit ripening. Effects of individual VOCs or their role in conjunction with other stressors ( e.g., acidification, drought, temperature extremes) have not been well studied. In a recent study of a mixture of VOCs including ethanol and toluene on herbaceous plants, significant effects on seed production, leaf water content, and photosynthetic efficiency were reported for some plant species. ^{1206}
^{1204} U.S. EPA. (1991). Effects of organic chemicals in the atmosphere on terrestrial plants. EPA/600/3-91/001.
^{1205} Cape JN, ID Leith, J Binnie, J Content, M Donkin, M Skewes, DN Price AR Brown, AD Sharpe. (2003). Effects of VOCs on herbaceous plants in an open-top chamber experiment. Environ. Pollut. 124:341-343.
^{1206} Cape JN, ID Leith, J Binnie, J Content, M Donkin, M Skewes, DN Price AR Brown, AD Sharpe. (2003). Effects of VOCs on herbaceous plants in an open-top chamber experiment. Environ. Pollut. 124:341-343.
Research suggests an adverse impact of vehicle exhaust on plants, which has in some cases been attributed to aromatic compounds and in other cases to. 1207 1208 1209 The impacts of VOCs on plant reproduction may have long-term implications for biodiversity and survival of native species near major roadways. Most of the studies of the impacts of VOCs on vegetation have focused on short-term exposure, and few studies have focused on long-term effects of VOCs on vegetation and the potential for metabolites of these compounds to affect herbivores or insects.
^{1207} Viskari E-L. (2000). Epicuticular wax of Norway spruce needles as indicator of traffic pollutant deposition. Water, Air, and Soil Pollut. 121:327-337.
^{1208} Ugrekhelidze D, F Korte, G Kvesitadze. (1997). Uptake and transformation of benzene and toluene by plant leaves. Ecotox. Environ. Safety 37:24-29.
^{1209} Kammerbauer H, H Selinger, R Rommelt, A Ziegler-Jons, D Knoppik, B Hock. (1987). Toxic components of motor vehicle emissions for the spruce Picea abies. Environ. Pollut. 48:235-243.

C. Air Quality Impacts of Non-GHG Pollutants
Section V of this preamble presents projections of the changes in criteria pollutant and air toxics emissions due to the final rule. We did not conduct air quality modeling for this rule, and making predictions based solely on emissions changes is extremely difficult; the atmospheric chemistry related to ambient concentrations of PM 2.5 , ozone and air toxics is very complex, and the emissions changes are spatially variable. Nevertheless, we do expect that in areas in close proximity to roadways ( i.e., within 300-600 meters of the roadway), the reductions in vehicle emissions will decrease ambient levels of PM 2.5 , NO 2 , and other traffic-related pollutants described in section VI.B. Across broader geographic areas, we also expect the decrease in vehicle emissions to contribute to lower ambient concentrations of ozone and PM 2.5 , which are secondarily formed in the atmosphere. Section V of this preamble also describes projected potential emission reductions downwind from refineries, which would improve air quality in those locations. Increased emissions from EGUs may increase ambient concentrations of some pollutants in downwind areas, although those impacts will lessen over time as the power sector becomes cleaner.

D. Environmental Justice

1. Overview
Communities with environmental justice concerns, which can include a range of communities and populations, face relatively greater cumulative impacts associated with environmental exposures of multiple types, as well as impacts from non-chemical stressors. 1210 1211 1212 1213 As described in section VI.B.2, there is some literature to suggest that different sociodemographic factors may increase susceptibility to the effects of traffic-associated air pollution. In addition, compared to non-Hispanic Whites, some other racial groups experience greater levels of health problems during some life stages. For example, in 2018-2020, about 12 percent of non-Hispanic Black; 9 percent of non-Hispanic American Indian/Alaska Native; and 7 percent of Hispanic children were estimated to currently have asthma, compared with 6 percent of non-Hispanic White children. ^{1214} Nationally, on average, non-Hispanic Black and non-Hispanic American Indian or Alaska Native people also have lower than average life expectancy based on 2019 data. ^{1215}
^{1210} Rowangould, G.M. (2013) A census of the near-roadway population: public health and environmental justice considerations. Trans Res D 25: 59-67. http://dx.doi.org/10.1016/j.trd.2013.08.003 .
^{1211} Marshall, J.D. (2000) Environmental inequality: Air pollution exposures in California's South Coast Air Basin. Atmos Environ 21: 5499-5503. https://doi.org/10.1016/j.atmosenv.2008.02.005.
^{1212} Marshall, J.D. (2008) Environmental inequality: air pollution exposures in California's South Coast Air Basin. Atmos Environ 21: 5499-5503. https://doi.org/10.1016/j.atmosenv.2008.02.005 .
^{1213} Mohai, P.; Pellow, D.; Roberts Timmons, J. (2009) Environmental justice. Annual Reviews 34: 405-430. https://doi.org/10.1146/annurev-environ082508-094348 .
^{1214} Current Asthma Prevalence by Race and Ethnicity (2018-2020). [Online at https://www.cdc.gov/asthma/most_recent_national_asthma_data.htm ].
^{1215} Arias, E. Xu, J. (2022) United States Life Tables, 2019. National Vital Statistics Report, Volume 70, Number 19. [Online at https://www.cdc.gov/nchs/data/nvsr/nvsr70/nvsr70-19.pdf ].
EPA's 2016 “Technical Guidance for Assessing Environmental Justice in Regulatory Analysis” provides recommendations on conducting the highest quality analysis feasible of environmental justice (EJ) issues associated with a given regulatory decision, though it is not prescriptive, recognizing that data limitations, time and resource constraints, and analytic challenges will vary by media and regulatory context. ^{1216} Where applicable and practicable, the Agency endeavors to conduct such an EJ analysis. There is evidence that communities with EJ concerns are disproportionately and adversely impacted by heavy-duty vehicle emissions. ^{1217}
^{1216} USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
^{1217} Demetillo, M.A.; Harkins, C.; McDonald, B.C.; et al. (2021) Space-based observational constraints on NO 2 air pollution inequality from diesel traffic in major US cities. Geophys Res Lett 48, e2021GL094333.
In section VI.D.2, we discuss the EJ impacts of this final rule's GHG emission standards from the anticipated reduction of GHGs. We also discuss in section VI.D.3 the potential additional EJ impacts from the non-GHG (criteria pollutant and air toxic) emissions changes we estimate would result from compliance with the CO 2 emission standards, including impacts near roadways and from upstream sources. EPA did not consider potential adverse disproportionate impacts of vehicle emissions in selecting the CO 2 emission standards, but we provide information about adverse impacts of vehicle emissions for the public's understanding of this rulemaking, which addresses the need to protect public health consistent with CAA section 202(a)(1)-(2). When assessing the potential for disproportionate and adverse health or environmental impacts of regulatory actions on populations with potential EJ concerns, EPA strives to answer the following three broad questions, for purposes of the EJ analysis: (1) Is there evidence of potential EJ concerns in the baseline (the state of the world absent the regulatory action)? Assessing the baseline will allow EPA to determine whether pre-existing disparities are associated with the pollutant(s) under consideration ( e.g., if the effects of the pollutant(s) are more concentrated in some population groups); (2) Is there evidence of potential EJ concerns for the regulatory option(s) under consideration? Specifically, how are the pollutant(s) and its effects distributed for the regulatory options under consideration?; and (3) Do the regulatory option(s) under consideration exacerbate or mitigate EJ concerns relative to the baseline? It is not always possible to provide quantitative answers to these questions.
EPA received several comments related to the environmental justice impacts of heavy-duty vehicles in general and the impacts of the proposal specifically. We summarize and respond to those comments in section 18 of the Response to Comments document that accompanies this rulemaking. After consideration of comments, EPA updated our review of the literature, while maintaining our general approach to the environmental justice analysis. We note that analyses in this section are based on data that was the most appropriate recent data at the time we undertook the analyses. We intend to continue analyzing data concerning disproportionate impacts of pollution in the future, using the latest available data.

2. GHG Impacts on Environmental Justice and Vulnerable or Overburdened Populations
In the 2009 Endangerment Finding, the Administrator considered how climate change threatens the health and welfare of the U.S. population. As part of that consideration, she also considered risks to people of color and low-income individuals and communities, finding that certain parts of the U.S. population may be especially vulnerable based on their characteristics or circumstances. These groups include economically and socially disadvantaged communities; individuals at vulnerable life stages, such as the elderly, the very young, and pregnant or nursing women; those already in poor health or with comorbidities; the disabled; those experiencing homelessness, mental illness, or substance abuse; and Indigenous or other populations dependent on one or limited resources for subsistence due to factors including but not limited to geography, access, and mobility.
Scientific assessment reports produced over the past decade by the USGCRP, 1218,1219 the IPCC, 1220 1221 1222 1223 the National Academies of Science, Engineering, and Medicine, 1224 1225 and the EPA ^{1226} add more evidence that the impacts of climate change raise potential EJ concerns. These reports conclude that less-affluent, traditionally marginalized and predominantly non-White communities can be especially vulnerable to climate change impacts because they tend to have limited resources for adaptation, are more dependent on climate-sensitive resources such as local water and food supplies or have less access to social and information resources. Some communities of color, specifically populations defined jointly by ethnic/racial characteristics and geographic location (e.g ., African-American, Black, and Hispanic/Latino communities; Native Americans, particularly those living on tribal lands and Alaska Natives), may be uniquely vulnerable to climate change health impacts in the U.S., as discussed in this section. In particular, the 2016 scientific assessment on the Impacts of Climate Change on Human Health ^{1227} found with high confidence that vulnerabilities are place- and time-specific, lifestages and ages are linked to immediate and future health impacts, and social determinants of health are linked to greater extent and severity of climate change-related health impacts. The GHG emission reductions from this final rule would contribute to efforts to reduce the probability of severe impacts related to climate change.
^{1218} USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
^{1219} USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp. https://health2016.globalchange.gov/ .
^{1220} Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G. Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 1039-1099.
^{1221} Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M. Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food security and food production systems. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 485-533.
^{1222} Smith, K.R., A. Woodward, D. Campbell-Lendrum, D.D. Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn, 2014: Human health: impacts, adaptation, and co-benefits. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 709-754.
^{1223} IPCC, 2018: Global Warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Pörtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. In Press.
^{1224} National Research Council. 2011. America's Climate Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781 .
^{1225} National Academies of Sciences, Engineering, and Medicine. 2017. Communities in Action: Pathways to Health Equity. Washington, DC: The National Academies Press. https://doi.org/10.17226/24624 .
^{1226} EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.
^{1227} USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment.

i. Effects on Specific Communities and Populations
Per the Fourth National Climate Assessment (NCA4), “Climate change affects human health by altering exposures to heat waves, floods, droughts, and other extreme events; vector-, food- and waterborne infectious diseases; changes in the quality and safety of air, food, and water; and stresses to mental health and well-being.” ^{1228} Many health conditions such as cardiopulmonary or respiratory illness and other health impacts are associated with and exacerbated by an increase in GHGs and climate change outcomes, which is problematic as these diseases occur at higher rates within vulnerable communities. Importantly, negative public health outcomes include those that are physical in nature, as well as mental, emotional, social, and economic.
^{1228} Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 2018: Human Health. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/NCA4.2018.CH14.
The scientific assessment literature, including the aforementioned reports, demonstrates that there are myriad ways in which particular communities and populations may be affected at the individual and community levels. Individuals face differential exposure to criteria pollutants, in part due to the proximities of highways, trains, factories, and other major sources of pollutant-emitting sources to less-affluent residential areas. Outdoor workers, such as construction or utility crews and agricultural laborers, who frequently are comprised of already at-risk groups, are exposed to poor air quality and extreme temperatures without relief. Furthermore, people in communities with EJ concerns face greater housing, clean water, and food insecurity and bear disproportionate and adverse economic impacts and health burdens associated with climate change effects. They have less or limited access to healthcare and affordable, adequate health or homeowner insurance. ^{1229} Finally, resiliency and adaptation are more difficult for economically vulnerable communities; these communities have less liquidity, individually and collectively, to move or to make the types of infrastructure or policy changes to limit or reduce the hazards they face. They frequently are less able to self-advocate for resources that would otherwise aid in building resilience and hazard reduction and mitigation.
^{1229} USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment.
The assessment literature cited in EPA's 2009 and 2016 Endangerment and Cause or Contribute Findings, as well as Impacts of Climate Change on Human Health, also concluded that certain populations and life stages, including children, are most vulnerable to climate-related health effects. ^{1230} The assessment literature produced from 2016 to the present strengthens these conclusions by providing more detailed findings regarding related vulnerabilities and the projected impacts youth may experience. These assessments—including the NCA4 and The Impacts of Climate Change on Human Health in the United States (2016)—describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to allergens, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low-income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households. More generally, these reports note that extreme weather and flooding can cause or exacerbate poor health outcomes by affecting mental health because of stress; contributing to or worsening existing conditions, again due to stress or also as a consequence of exposures to water and air pollutants; or by impacting hospital and emergency services operations. ^{1231} Further, in urban areas in particular, flooding can have significant economic consequences due to effects on infrastructure, pollutant exposures, and drowning dangers. The ability to withstand and recover from flooding is dependent in part on the social vulnerability of the affected population and individuals experiencing an event. ^{1232} In addition, children are among those especially susceptible to allergens, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low-income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
^{1230} 74 FR 66496, December 15, 2009; 81 FR 54422, August 15, 2016.
^{1231} Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 2018: Human Health. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 539-571. doi:10.7930/NCA4.2018.CH14.
^{1232} National Academies of Sciences, Engineering, and Medicine 2019. Framing the Challenge of Urban Flooding in the United States. Washington, DC: The National Academies Press. https://doi.org/10.17226/25381 .
The Impacts of Climate Change on Human Health ^{1233} also found that some communities of color, low-income groups, people with limited English proficiency, and certain immigrant groups (especially those who are undocumented) are subject to many factors that contribute to vulnerability to the health impacts of climate change. While difficult to isolate from related socioeconomic factors, race appears to be an important factor in vulnerability to climate-related stress, with elevated risks for mortality from high temperatures reported for Black or African American individuals compared to White individuals after controlling for factors such as air conditioning use. Moreover, people of color are disproportionately more exposed to air pollution based on where they live, and disproportionately vulnerable due to higher baseline prevalence of underlying diseases such as asthma. As explained earlier, climate change can exacerbate local air pollution conditions so this increase in air pollution is expected to have disproportionate and adverse effects on these communities. Locations with greater health threats include urban areas (due to, among other factors, the “heat island” effect where built infrastructure and lack of green spaces increases local temperatures), areas where airborne allergens and other air pollutants already occur at higher levels, and communities experienced depleted water supplies or vulnerable energy and transportation infrastructure.
^{1233} USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp. http://dx.doi.org/10.7930/J0R49NQX .
The recent EPA report on climate change and social vulnerability ^{1234} examined four socially vulnerable groups (individuals who are low income, minority, without high school diplomas, and/or 65 years and older) and their exposure to several different climate impacts (air quality, coastal flooding, extreme temperatures, and inland flooding). This report found that Black and African-American individuals were 40 percent more likely to currently live in areas with the highest projected increases in mortality rates due to climate-driven changes in extreme temperatures, and 34 percent more likely to live in areas with the highest projected increases in childhood asthma diagnoses due to climate-driven changes in particulate air pollution. The report found that Hispanic and Latino individuals are 43 percent more likely to live in areas with the highest projected labor hour losses in weather-exposed industries due to climate-driven warming, and 50 percent more likely to live in coastal areas with the highest projected increases in traffic delays due to increases in high-tide flooding. The report found that American Indian and Alaska Native individuals are 48 percent more likely to live in areas where the highest percentage of land is projected to be inundated due to sea level rise, and 37 percent more likely to live in areas with high projected labor hour losses. Asian individuals were found to be 23 percent more likely to live in coastal areas with projected increases in traffic delays from high-tide flooding. Persons with low income or no high school diploma are about 25 percent more likely to live in areas with high projected losses of labor hours, and 15 percent more likely to live in areas with the highest projected increases in asthma due to climate-driven increases in particulate air pollution, and in areas with high projected inundation due to sea level rise.
^{1234} EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.
In a more recent 2023 report, Climate Change Impacts on Children's Health and Well-Being in the U.S., the EPA considered the degree to which children's health and well-being may be impacted by five climate-related environmental hazards—extreme heat, poor air quality, changes in seasonality, flooding, and different types of infectious diseases. ^{1235} The report found that children's academic achievement is projected to be reduced by 4-7 percent per child, as a result of moderate and higher levels of warming, impacting future income levels. The report also projects increases in the numbers of annual emergency department visits associated with asthma, and that the number of new asthma diagnoses increases by 4-11 percent due to climate-driven increases in air pollution relative to current levels. In addition, more than 1 million children in coastal regions are projected to be temporarily displaced from their homes annually due to climate-driven flooding, and infectious disease rates are similarly anticipated to rise, with the number of new Lyme disease cases in children living in 22 states in the eastern and midwestern U.S. increasing by approximately 3,000-23,000 per year compared to current levels. Overall, the report confirmed findings of broader climate science assessments that children are uniquely vulnerable to climate-related impacts and that in many situations, children in the U.S. who identify as Black, Indigenous, and People of Color, are limited English-speaking, do not have health insurance, or live in low-income communities may be disproportionately more exposed to the most severe adverse impacts of climate change.
^{1235} EPA. 2023. Climate Change Impacts on Children's Health and Well-Being in the U.S., EPA-430-R-23-001.
Tribes and Indigenous communities face disproportionate and adverse risks from the impacts of climate change, particularly those communities impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Indigenous communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The IPCC indicates that losses of customs and historical knowledge may cause communities to be less resilient or adaptable. ^{1236} The NCA4 noted that while Tribes and Indigenous Peoples are diverse and will be impacted by the climate changes universal to all Americans, there are several ways in which climate change uniquely threatens Tribes and Indigenous Peoples' livelihoods and economies. ^{1237} In addition, as noted in the following paragraph, there can be institutional barriers (including policy-based limitations and restrictions) to their management of water, land, and other natural resources that could impede adaptive measures.
^{1236} Porter, et al., 2014: Food security and food production systems.
^{1237} Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S. McNeeley, C. Narducci, J. Raymond-Yakoubian, L. Singletary, and K. Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 572-603. doi:10.7930/NCA4. 2018. CH15.
For example, Indigenous agriculture in the Southwest is already being adversely affected by changing patterns of flooding, drought, dust storms, and rising temperatures leading to increased soil erosion, irrigation water demand, and decreased crop quality and herd sizes. The Confederated Tribes of the Umatilla Indian Reservation in the Northwest have identified climate risks to salmon, elk, deer, roots, and huckleberry habitat. Housing and sanitary water supply infrastructure are vulnerable to disruption from extreme precipitation events. Additionally, NCA4 noted that Tribes and Indigenous Peoples generally experience poor infrastructure, diminished access to quality healthcare, and greater risk of exposure to pollutants. Consequently, Native Americans often have disproportionately higher rates of asthma, cardiovascular disease, Alzheimer's disease, diabetes, and obesity. These health conditions and related effects (disorientation, heightened exposure to PM 2.5 , etc. ) can all contribute to increased vulnerability to climate-driven extreme heat and air pollution events, which also may be exacerbated by stressful situations, such as extreme weather events, wildfires, and other circumstances.
NCA4 and IPCC's Fifth Assessment Report ^{1238} also highlighted several impacts specific to Alaskan Indigenous Peoples. Coastal erosion and permafrost thaw will lead to more coastal erosion, rendering winter travel riskier and exacerbating damage to buildings, roads, and other infrastructure—impacts on archaeological sites, structures, and objects that will lead to a loss of cultural heritage for Alaska's Indigenous people. In terms of food security, the NCA4 discussed reductions in suitable ice conditions for hunting, warmer temperatures impairing the use of traditional ice cellars for food storage, and declining shellfish populations due to warming and acidification. While the NCA4 also noted that climate change provided more opportunity to hunt from boats later in the fall season or earlier in the spring, the assessment found that the net impact was an overall decrease in food security. In addition, the U.S. Pacific Islands and the Indigenous communities that live there are also uniquely vulnerable to the effects of climate change due to their remote location and geographic isolation. They rely on the land, ocean, and natural resources for their livelihoods, but they face challenges in obtaining energy and food supplies that need to be shipped in at high costs. As a result, they face higher energy costs than the rest of the nation and depend on imported fossil fuels for electricity generation and diesel. These challenges exacerbate the climate impacts that the Pacific Islands are experiencing. NCA4 notes that Tribes and Indigenous Peoples of the Pacific are threatened by rising sea levels, diminishing freshwater availability, and negative effects to ecosystem services that threaten these individuals' health and well-being.
^{1238} Porter, et al., 2014: Food security and food production systems.

3. Non-GHG Impacts
In section V.B., in addition to GHG emissions impacts, we also discuss potential additional emission changes of non-GHGs ( i.e., criteria and air toxic pollutants) that we project from compliance with the final GHG emission standards. This section VI.D.3 describes evidence that communities with EJ concerns are disproportionately and adversely impacted by relevant non-GHG emissions. We discuss the potential impact of non-GHG emissions for two specific contexts: near-roadway (section VI.D.3.i) and upstream sources (section VI.D.3.ii).

i. Near-Roadway Analysis
As described in section VI.B.2.viii of this preamble, concentrations of many air pollutants are elevated near high-traffic roadways. We recently conducted an analysis of the populations within the CONUS living in close proximity to truck freight routes as identified in USDOT's FAF4. ^{1239} FAF4 is a model from the USDOT's Bureau of Transportation Statistics and Federal Highway Administration, which provides data associated with freight movement in the United States. ^{1240} Relative to the rest of the population, people living near FAF4 truck routes are more likely to be people of color and have lower incomes than the general population. People living near FAF4 truck routes are also more likely to live in metropolitan areas. Even controlling for region of the country, county characteristics, population density, and household structure, race, ethnicity, and income are significant determinants of whether someone lives near a FAF4 truck route.
^{1239} U.S. EPA (2021). Estimation of Population Size and Demographic Characteristics among People Living Near Truck Routes in the Conterminous United States. Memorandum to the Docket.
^{1240} FAF4 includes data from the 2012 Commodity Flow Survey (CFS), the Census Bureau on international trade, as well as data associated with construction, agriculture, utilities, warehouses, and other industries. FAF4 estimates the modal choices for moving goods by trucks, trains, boats, and other types of freight modes. It includes traffic assignments, including truck flows on a network of truck routes. https://ops.fhwa.dot.gov/freight/freight_analysis/faf/.
We additionally analyzed other national databases that allowed us to evaluate whether homes and schools were located near a major road and whether disparities in exposure may be occurring in these environments. Until 2009, the U.S. Census Bureau's American Housing Survey (AHS) included descriptive statistics of over 70,000 housing units across the nation and asked about transportation infrastructure near respondents' homes every two years. 1241 1242 We also analyzed the U.S. Department of Education's Common Core of Data, which includes enrollment and location information for schools across the United States. ^{1243}
^{1241} U.S. Department of Housing and Urban Development, & U.S. Census Bureau. (n.d.). Age of other residential buildings within 300 feet. In American Housing Survey for the United States: 2009 (pp. A-1). Retrieved from https://www.census.gov/programs-surveys/ahs/data/2009/ahs-2009-summary-tables0/h150-09.html.
^{1242} The 2013 AHS again included the “etrans” question about highways, airports, and railroads within half a block of the housing unit but has not maintained the question since then.
^{1243} http://nces.ed.gov/ccd/.
In analyzing the 2009 AHS, we focused on whether a housing unit was located within 300 feet of a “4-or-more lane highway, railroad, or airport” (this distance was used in the AHS analysis). ^{1244} We analyzed whether there were differences between households in such locations compared with those in locations farther from these transportation facilities. ^{1245} We included other variables, such as land use category, region of country, and housing type. We found that homes with a non-White householder were 22-34 percent more likely to be located within 300 feet of these large transportation facilities than homes with White householders. Homes with a Hispanic householder were 17-33 percent more likely to be located within 300 feet of these large transportation facilities than homes with non-Hispanic householders. Households near large transportation facilities were, on average, lower in income and educational attainment and more likely to be a rental property and located in an urban area compared with households more distant from transportation facilities.
^{1244} This variable primarily represents roadway proximity. According to the Central Intelligence Agency's World Factbook, in 2010, the United States had 6,506,204 km of roadways, 224,792 km of railways, and 15,079 airports. Highways thus represent the overwhelming majority of transportation facilities described by this factor in the AHS.
^{1245} Bailey, C. (2011) Demographic and Social Patterns in Housing Units Near Large Highways and other Transportation Sources. Memorandum to docket.
In examining schools near major roadways, we used the Common Core of Data from the U.S. Department of Education, which includes information on all public elementary and secondary schools and school districts nationwide. ^{1246} To determine school proximities to major roadways, we used a geographic information system to map each school and roadways based on the U.S. Census's TIGER roadway file. ^{1247} We estimated that about 10 million students attend schools within 200 meters of major roads, about 20 percent of the total number of public school students in the United States. ^{1248} About 800,000 students attend public schools within 200 meters of primary roads, or about 2 percent of the total. We found that students of color were overrepresented at schools within 200 meters of primary roadways, and schools within 200 meters of primary roadways had a disproportionately greater population of students eligible for free or reduced-price lunches. ^{1249} Black students represent 22 percent of students at schools located within 200 meters of a primary road, compared to 17 percent of students in all U.S. schools. Hispanic students represent 30 percent of students at schools located within 200 meters of a primary road, compared to 22 percent of students in all U.S. schools.
^{1246} http://nces.ed.gov/ccd/.
^{1247} Pedde, M.; Bailey, C. (2011) Identification of Schools within 200 Meters of U.S. Primary and Secondary Roads. Memorandum to the docket.
^{1248} Here, “major roads” refer to those TIGER classifies as either “Primary” or “Secondary”. The Census Bureau describes primary roads as “generally divided limited-access highways within the Federal interstate system or under state management”. Secondary roads are “main arteries, usually in the U.S. highway, state highway, or county highway system”.
^{1249} For this analysis we analyzed a 200-meter distance based on the understanding that roadways generally influence air quality within a few hundred meters from the vicinity of heavily traveled roadways or along corridors with significant trucking traffic. See U.S. EPA, 2014. Near Roadway Air Pollution and Health: Frequently Asked Questions. EPA-420-F-14-044.
We also reviewed existing scholarly literature examining the potential for disproportionately high exposure to these pollutants among people of color and people with low socioeconomic status (SES). Numerous studies evaluating the demographics and socioeconomic status of populations or schools near roadways have found that they include a greater percentage of residents of color, as well as lower SES populations (as indicated by variables such as median household income). Locations in these studies include Los Angeles, CA; Seattle, WA; Wayne County, MI; Orange County, FL; Tampa, FL; the State of California; the State of Texas; and nationally. ^{1250}
^{1251}
^{1252}
^{1253}
^{1254}
^{1255}
^{1256}
^{1257}
^{1258}
^{1259}
^{1260}
^{1261} . Such disparities may be due to multiple factors, such as historic segregation, redlining, residential mobility, and daily mobility. ^{1262}
^{1263}
^{1264}
^{1265}
^{1266}
^{1267}
^{1250} Marshall, J.D. (2008) Environmental inequality: air pollution exposures in California's South Coast Air Basin. Atmos Environ 42: 5499-5503. doi:10.1016/j.atmosenv.2008.02.00.
^{1251} Su, J.G.; Larson, T.; Gould, T.; Cohen, M.; Buzzelli, M. (2010) Transboundary air pollution and environmental justice: Vancouver and Seattle compared. GeoJournal 57: 595-608. doi:10.1007/s10708-009-9269-6.
^{1252} Chakraborty, J.; Zandbergen, P.A. (2007) Children at risk: measuring racial/ethnic disparities in potential exposure to air pollution at school and home. J Epidemiol Community Health 61: 1074-1079. doi:10.1136/jech.2006.054130.
^{1253} Green, R.S.; Smorodinsky, S.; Kim, J.J.; McLaughlin, R.; Ostro, B. (2004) Proximity of California public schools to busy roads. Environ Health Perspect 112: 61-66. doi:10.1289/ehp.6566.
^{1254} Wu, Y; Batterman, S.A. (2006) Proximity of schools in Detroit, Michigan to automobile and truck traffic. J Exposure Sci & Environ Epidemiol. doi:10.1038/sj.jes.7500484.
^{1255} Su, J.G.; Jerrett, M.; de Nazelle, A.; Wolch, J. (2011) Does exposure to air pollution in urban parks have socioeconomic, racial, or ethnic gradients? Environ Res 111: 319-328.
^{1256} Jones, M.R.; Diez-Roux, A.; Hajat, A.; et al. (2014) Race/ethnicity, residential segregation, and exposure to ambient air pollution: The Multi-Ethnic Study of Atherosclerosis (MESA). Am J Public Health 104: 2130-2137. [Online at: https://doi.org/10.2105/AJPH.2014.302135 .].
^{1257} Stuart A.L., Zeager M. (2011) An inequality study of ambient nitrogen dioxide and traffic levels near elementary schools in the Tampa area. Journal of Environmental Management. 92(8): 1923-1930. https://doi.org/10.1016/j.jenvman.2011.03.003.
^{1258} Stuart A.L., Mudhasakul S., Sriwatanapongse W. (2009) The Social Distribution of Neighborhood-Scale Air Pollution and Monitoring Protection. Journal of the Air & Waste Management Association. 59(5): 591-602. https://doi.org/10.3155/1047-3289.59.5.591.
^{1259} Willis M.D., Hill E.L., Kile M.L., Carozza S., Hystad P. (2020) Assessing the effectiveness of vehicle emission regulations on improving perinatal health: a population-based accountability study. International Journal of Epidemiology. 49(6): 1781-1791. https://doi.org/10.1093/ije/dyaa137.
^{1260} Collins, T.W., Grineski, SE, Nadybal, S. (2019) Social disparities in exposure to noise at public schools in the contiguous United States. Environ. Res. 175, 257-265. https://doi.org/10.1016/j.envres.2019.05.024.
^{1261} Kingsley S., Eliot M., Carlson L., Finn J., MacIntosh D.L., Suh H.H., Wellenius G.A. (2014) Proximity of US schools to major roadways: a nationwide assessment. J Expo Sci Environ Epidemiol. 24: 253-259. https://doi.org/10.1038/jes.2014.5.
^{1262} Depro, B.; Timmins, C. (2008) Mobility and environmental equity: do housing choices determine exposure to air pollution? Duke University Working Paper.
^{1263} Rothstein, R. The Color of Law: A Forgotten History of How Our Government Segregated America. New York: Liveright, 2018.
^{1264} Lane, H.J.; Morello-Frosch, R.; Marshall, J.D.; Apte, J.S. (2022) Historical redlining is associated with present-day air pollution disparities in US Cities. Environ Sci & Technol Letters 9: 345-350. DOI: [Online at: https://doi.org/10.1021/acs.estlett.1c01012 ].
^{1265} Ware, L. (2021) Plessy's legacy: the government's role in the development and perpetuation of segregated neighborhoods. RSF: The Russel Sage Foundation Journal of the Social Sciences, 7:92-109. DOI: 10.7758/RSF.2021.7.1.06.
^{1266} Archer, D.N. (2020) “White Men's Roads through Black Men's Homes”: advancing racial equity through highway reconstruction. Vanderbilt Law Rev 73: 1259.
^{1267} Park, Y.M.; Kwan, M.P. (2020) Understanding Racial Disparities in Exposure to Traffic-Related Air Pollution: Considering the Spatiotemporal Dynamics of Population Distribution. Int. J. Environ. Res. Public Health. 17 (3): 908. https://doi.org/10.3390/ijerph17030908.
Several publications report nationwide analyses that compare the demographic patterns of people who do or do not live near major roadways. ^{1268}
^{1269}
^{1270}
^{1271}
^{1272}
^{1273} Three of these studies found that people living near major roadways are more likely to be people of color or of low SES. 1274 1275 1276 They also found that the outcomes of their analyses varied between regions within the United States. However, only one such study looked at whether such conclusions were confounded by living in a location with higher population density and looked at how demographics differ between locations nationwide. ^{1277} That study generally found that higher density areas have higher proportions of low-income residents and people of color. In other publications assessing a city, county, or state, the results are similar. 1278 1279 1280
Furthermore, students of lower-income families and students with disabilities are more likely to travel to school by bus or public transit than are other students. 1281 1282 1283
^{1268} Rowangould, G.M. (2013) A census of the U.S. near-roadway population: public health and environmental justice considerations. Transportation Research Part D; 59-67.
^{1269} Tian, N.; Xue, J.; Barzyk. T.M. (2013) Evaluating socioeconomic and racial differences in traffic-related metrics in the United States using a GIS approach. J Exposure Sci Environ Epidemiol 23: 215-222.
^{1270} CDC (2013) Residential proximity to major highways—United States, 2010. Morbidity and Mortality Weekly Report 62(3): 46-50.
^{1271} Clark, L.P.; Millet, D.B., Marshall, J.D. (2017) Changes in transportation-related air pollution exposures by race-ethnicity and socioeconomic status: outdoor nitrogen dioxide in the United States in 2000 and 2010. Environ Health Perspect https://doi.org/10.1289/EHP959.
^{1272} Mikati, I.; Benson, A.F.; Luben, T.J.; Sacks, J.D.; Richmond-Bryant, J. (2018) Disparities in distribution of particulate matter emission sources by race and poverty status. Am J Pub Health https://ajph.aphapublications.org/doi/abs/10.2105/AJPH.2017.304297?journalCode=ajph.
^{1273} Alotaibi, R.; Bechle, M.; Marshall, J.D.; Ramani, T.; Zietsman, J.; Nieuwenhuijsen, M.J.; Khreis, H. (2019) Traffic related air pollution and the burden of childhood asthma in the continuous United States in 2000 and 2010. Environ International 127: 858-867. https://www.sciencedirect.com/science/article/pii/S0160412018325388.
^{1274} Tian, N.; Xue, J.; Barzyk. T.M. (2013) Evaluating socioeconomic and racial differences in traffic-related metrics in the United States using a GIS approach. J Exposure Sci Environ Epidemiol 23: 215-222.
^{1275} Rowangould, G.M. (2013) A census of the U.S. near-roadway population: public health and environmental justice considerations. Transportation Research Part D; 59-67.
^{1276} CDC (2013) Residential proximity to major highways—United States, 2010. Morbidity and Mortality Weekly Report 62(3): 46-50.
^{1277} Rowangould, G.M. (2013) A census of the U.S. near-roadway population: public health and environmental justice considerations. Transportation Research Part D; 59-67.
^{1278} Pratt, G.C.; Vadali, M.L.; Kvale, D.L.; Ellickson, K.M. (2015) Traffic, air pollution, minority, and socio-economic status: addressing inequities in exposure and risk. Int J Environ Res Public Health 12: 5355-5372. http://dx.doi.org/10.3390/ijerph120505355.
^{1279} Sohrabi, S.; Zietsman, J.; Khreis, H. (2020) Burden of disease assessment of ambient air pollution and premature mortality in urban areas: the role of socioeconomic status and transportation. Int J Env Res Public Health doi:10.3390/ijerph17041166.
^{1280} Aizer A., Currie J. (2019) Lead and Juvenile Delinquency: New Evidence from Linked Birth, School, and Juvenile Detention Records. The Review of Economics and Statistics. 101 (4): 575-587. https://doi.org/10.1162/rest_a_00814.
^{1281} Bureau of Transportation Statistics (2021) The Longer Route to School. [Online at https://www.bts.gov/topics/passenger-travel/back-school-2019 ].
^{1282} Wheeler, K.; Yang, Y.; Xiang, H. (2009) Transportation use patterns of U.S. children and teenagers with disabilities. Disability and Health J 2: 158-164. https://doi.org/10.1016/j.dhjo.2009.03.003.
^{1283} Park, K.; Esfahani, H.N.; Novack, V.L.; et al. (2022) Impacts of disability on daily travel behaviour: A systematic review. Transport Reviews 43: 178-203. https://doi.org/10.1080/01441647.2022.2060371.
Two recent studies provide strong evidence that reducing emissions from heavy-duty vehicles is likely to reduce the disparity in exposures to traffic-related air pollutants. Both use NO 2 observations from the recently launched TROPospheric Ozone Monitoring Instrument satellite sensor as a measure of air quality, which provides high-resolution observations that heretofore were unavailable from any satellite. ^{1284}
^{1284} TROPospheric Ozone Monitoring Instrument (TROPOMI) is part of the Copernicus Sentinel-5 Precursor satellite.
One study evaluated NO 2 concentrations during the COVID-19 lockdowns in 2020 and compared them to NO 2 concentrations from the same dates in 2019. ^{1285} That study found that average NO 2 concentrations were highest in areas with the lowest percentage of White populations, and that the areas with the greatest percentages of non-White or Hispanic populations experienced the greatest declines in NO 2 concentrations during the lockdown. These NO 2 reductions were associated with the density of highways in the local area.
^{1285} Kerr, G.H.; Goldberg, D.L.; Anenberg, S.C. (2021) COVID-19 pandemic reveals persistent disparities in nitrogen dioxide pollution. PNAS 118. https://doi.org/10.1073/pnas.2022409118.
In the second study, NO 2 measured from 2018-2020 was averaged by racial groups and income levels in 52 large U.S. cities. Using census tract-level NO 2 , the study reported average population-weighted NO 2 levels to be 28 percent higher for low-income non-White people compared with high-income White people. The study also used weekday-weekend differences and bottom-up emission estimates to estimate that diesel traffic is the dominant source of NO 2 disparities in the studied cities.
Overall, there is substantial evidence that people who live or attend school near major roadways are more likely to be of a non-White race, Hispanic, and/or have a low SES. As described in section VI.B.2.viii, traffic-related air pollution may have disproportionate and adverse impacts on health across racial and sociodemographic groups. We expect communities near roads will benefit from the reduced vehicle emissions of PM, NO X , SO 2 , VOC, CO, and mobile source air toxics projected to result from this final rule. Although we were not able to conduct air quality modeling of the estimated emission reductions, we believe it a fair inference that because vehicular emissions affect communities with environmental justice concerns disproportionately and adversely due to roadway proximity, and because we project this rule will result in significant reductions in vehicular emissions, these communities' exposures to non-GHG air pollutants will be reduced. EPA is considering how to better estimate the near-roadway air quality impacts of its regulatory actions and how those impacts are distributed across populations.

ii. Upstream Source Impacts
As described in Chapter 4.5, we expect some non-GHG emissions reductions from sources related to refining petroleum fuels and increases in emissions from EGUs, both of which would lead to changes in exposure for people living in communities near these facilities. The EGU emissions increases become smaller over time because of changes in the projected power generation mix as electricity generation uses less fossil fuels.
Analyses of communities in close proximity to EGUs have found that a higher percentage of communities of color and low-income communities live near these sources when compared to national averages. ^{1286} EPA compared the percentages of people of color and low-income populations living within three miles of fossil fuel-fired power plants regulated under EPA's Acid Rain Program and/or EPA's Cross-State Air Pollution Rule to the national average and found that there is a greater percentage of people of color and low-income individuals living near these power plants than in the rest of the country on average. ^{1287} According to 2020 Census data, on average, the U.S. population is comprised of 40 percent people of color and 30 percent low-income individuals. In contrast, the population living near fossil fuel-fired power plants is comprised of 53 percent people of color and 34 percent low-income individuals. ^{1288} Historically redlined neighborhoods are more likely to be downwind of fossil fuel power plants and to experience higher levels of exposure to relevant emissions than non-redlined neighborhoods. ^{1289} Analysis of populations near refineries and oil and gas wells indicates there may be potential disparities in pollution-related health risk from these sources. 1290 1291 1292 1293 See also section V.B of this preamble, discussing issues pertaining to lifecycle emissions more generally.
^{1286} See 80 FR 64662, 64915-64916 (October 23, 2015).
^{1287} U.S. EPA (2023) 2021 Power Sector Programs—Progress Report. https://www3.epa.gov/airmarkets/progress/reports/.
^{1288} U.S. EPA (2023) 2021 Power Sector Programs—Progress Report. https://www3.epa.gov/airmarkets/progress/reports/ .
^{1289} Cushing L.J., Li S., Steiger B.B., Casey J.A. (2023) Historical red-lining is associated with fossil fuel power plant siting and present-day inequalities in air pollutant emissions. Nature Energy. 8: 52-61. https://doi.org/10.1038/s41560-022-01162-y .
^{1290} U.S. EPA (2014). Risk and Technology Review—Analysis of Socio-Economic Factors for Populations Living Near Petroleum Refineries. Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. January.
^{1291} Carpenter, A., and M. Wagner. Environmental justice in the oil refinery industry: A panel analysis across United States counties. J. Ecol. Econ. V. 159 (2019).
^{1292} Gonzalez, J.X., et al. Historic redlining and the siting of oil and gas wells in the United States. J. Exp. Sci. & Env. Epi. V. 33. (2023). p. 76-83.
^{1293} In comparison to the national population, the EPA publication reports higher proportions of the following population groups in block groups with higher cancer risk associated with emissions from refineries: “minority”, “African American”, “Other and Multiracial”, “Hispanic or Latino”, “Ages 0-17”, “Ages 18-64”, “Below the Poverty Level”, “Over 25 years old without a HS diploma”, and “Linguistic isolations”.

E. Economic Impacts

1. Impacts on Vehicle Sales, Fleet Turnover, Mode Shift, Class Shift and Domestic Production
In this section, we discuss the impacts this regulation may have on HD vehicle sales, including the potential for pre-buy and low-buy decisions, decisions regarding the mode of transportation used to move goods, shifting of purchases between HD vehicle classes, and effects on domestic production of HD vehicles, under the modeled potential compliance pathway. Pre-buy occurs when a purchaser pulls ahead a planned future purchase to make the purchase before implementation of an EPA regulation in anticipation that a future vehicle may have a higher upfront or operational cost, or have reduced reliability. Low-buy occurs when a vehicle that would have been purchased after the implementation of a regulation is either not purchased at all, or the purchase is delayed. Low-buy may occur directly as a function of pre-buy (where a vehicle was instead purchased prior to implementation of the new regulation), or due to a vehicle purchaser delaying the purchase of a vehicle due to cost or uncertainty. Pre- and low-buy are short-term effects, with research indicating that effects are seen for one year or less before and after a regulation is implemented. ^{1294} Pre-buy and low-buy impact fleet turnover, which can result in a level of emission reduction attributable to the new emission standards that is different from the level of emission reduction EPA estimated. Mode shift occurs if goods that would normally be shipped by HD vehicle are instead shipped by another method ( e.g., rail, boat, air) as a result of this action. Class shift occurs when a vehicle purchaser decides to purchase a different class of vehicle than originally intended due to the new regulation. For example, a purchaser may buy a Class 8 vehicle instead of the Class 7 vehicle they may have purchased in the absence of a regulation. Domestic production could be affected if the regulation creates incentives for manufacturers to shift between domestic and foreign production.
^{1294} See the EPA report “Analysis of Heavy-Duty Vehicle Sales Impacts Due to New Regulation” at https://cfpub.epa.gov/si/si_public_pra_view.cfm?dirEntryID=349838&Lab=OTAQ for a literature review and EPA analysis of pre-buy and low-buy due to HD regulations.
Based on our analysis of the comments and available data, as well as our technical expertise in implementing the HD GHG and other vehicle emissions programs, EPA finds that the above-described impacts are unlikely to occur in a significant manner. Specifically, we expect that they will either not occur at all, or if they do, occur in a limited way that will not significantly affect the GHG emissions reductions projected by this rule or that would unduly disrupt the HD vehicle market. Notably, while some commenters speculated about the possibility of these impacts, no commenter presented, and EPA is not aware of, actual data and analysis demonstrating that these impacts would occur in a significant way in response to this regulation. While there is some analysis on these phenomena more generally—for example on low-buy and pre-buy in response to earlier HD regulations or in the light-duty (LD) sector—EPA finds that such analyses are not directly relevant to this regulation given relevant differences between the economic impacts of HD GHG and earlier HD criteria pollutant regulation, HD ICE and HD ZEV vehicles, and the HD and LD sectors. As such, extrapolation of these studies to this HD GHG regulation would not be technically sound. Moreover, as we explain in this section, salient features of our analysis of the modeled potential compliance pathway for this regulation—including the significant expected operating savings as well as the continuing availability of ICE vehicles in all HD vehicle segments—provide strong, qualitative evidence that these impacts are unlikely to be significant as a result of the final standards.

i. Vehicle Sales and Fleet Turnover
The final emission standards may lead to a change in the timing of planned vehicle purchases, phenomena known as “pre-buy” and “low-buy.” Pre-buy occurs when purchasers of HD vehicles pull their planned future vehicle purchase forward to the months before a regulation is implemented compared to when they otherwise would have purchased a new vehicle in the absence of the regulation. Pre-buy may occur due to expected cost increases of post-regulation vehicles, or in order to avoid perceived cost, quality, or other changes associated with new emission standards. Another reason pre-buy might occur is due to purchaser beliefs about the availability of their vehicle type of choice in the post-regulation market. For example, if purchasers think that they might not be able to get the HD ICE vehicle they want after the regulation is promulgated, they may pre-buy an ICE vehicle. ^{1295}
^{1295} We note that the HD TRUCS model used in this rulemaking to analyze ZEV technologies matched performance capabilities of ZEVs to an existing ICE vehicle for each use case where the ZEV vehicle technologies are technologically feasible.
Our assessment, with respect to ZEV technologies included in our potential compliance pathway, is that the Federal vehicle and battery tax credits, and EVSE tax credits for those purchasers eligible for them, will mitigate possible pre-buy by reducing the perceived purchase price or lifetime operational cost difference of a new, post-rule ZEV compared to a new pre- or post-rule comparable ICE vehicle. We also expect that the final rule's more gradual phase-in of more stringent standards compared to the proposal will mitigate possible pre-buy. In addition, as noted in section D of the Executive Summary, the estimated fleet-average costs to manufacturers per-vehicle for this rule are less than those estimated for the HD GHG Phase 2 rule, which EPA found to be reasonable, and we do not have data (and no commenter presented data) showing a significant level of pre-buy in anticipation of Phase 2. As also noted in section D of the Executive Summary, HD ZEV purchasers' incremental upfront costs (after the tax credits) are recovered through operational savings such that payback occurs between two and four years on average for vocational vehicles, after two years for short-haul tractors, and after five years on average for long-haul tractors. These operational cost savings, and therefore the payback of the higher upfront costs, will also mitigate pre-buy to the extent they are considered in the purchase decision. With respect to possible purchaser anxiety over being unable to purchase an ICE vehicle after promulgation of the regulation, we note that these final standards do not mandate the production or purchase of any particular vehicle, or the use of any particular technology in such vehicles. As described in section C of the Executive Summary and preamble section II, we model a potential compliance pathway to meet the standards with a diverse mix of ICE vehicle and ZEV technologies, as well as additional example potential compliance pathways to meet the standards that do not include increasing utilization of ZEV technologies. In addition, the phasing-in of the standards will allow ample time for purchasers to make decisions about their vehicle of choice, and the potential compliance pathway modeled for this rule reflects that the majority of vehicles will remain ICE vehicles, even in MY 2032.
While uncertainty about a new technology may trigger pre-buy as well, this could be mitigated by purchasers being educated on the new technology or increasing exposure to the new technology. For example, education on the benefits of ZEV ownership and operational characteristics (for example, reduced operational costs, decreased exposure to exhaust emissions and engine noise and smoother acceleration) and on charging and hydrogen refueling infrastructure technology and availability may lead to less uncertainty about each of these technologies. ^{1296} Our final standards may increase purchaser exposure to ZEV technologies, as well as incentivize manufacturers and dealers to educate HD vehicle purchasers on ZEVs, including the benefits of ZEVs, thus accelerating the reduction of purchaser risk aversion. We also expect recent congressional actions to support ZEV infrastructure and supply chain, including the CHIPS Act, BIL and IRA, will reduce uncertainty surrounding ZEV ownership. ^{1297} We note again that the standards do not mandate the use of a specific technology.
^{1296} For more information on purchaser acceptance of HD ZEVs, see RIA Chapter 6.2. For more information on the charging and hydrogen refueling infrastructure analysis in this rule, see RIA Chapter 2.6.
^{1297} The CHIPS Act is the Creating Helpful Incentives to Produce Semiconductors and Science Act and was signed into law on August 9, 2022. It is designed to strengthen supply chains, domestic manufacturing and national security. More information on how all of these Acts are expected to support opportunities for growth along the supply chain can be found in the January 2023 White House publication “Building a Clean Energy Economy: A Guidebook to the Inflation Reduction Act's Investments in Clean Energy and Climate Action.” found online at https://www.whitehouse.gov/wp-content/uploads/2022/12/Inflation-Reduction-Act-Guidebook.pdf.
In addition to pre-buy, there is the possibility of “low-buy” occurring in response to new regulation. ^{1298} In a low-buy scenario, sales of HD vehicles decrease in the months after a regulation becomes effective, compared to what would have happened in the absence of a regulation, due to purchasers either pre-buying or delaying a planned purchase. Low-buy may be directly attributable to pre-buy, where purchases originally planned for the months following the effective date of new emission standards are instead purchased in the months preceding the effective date of the new emission standards. Low-buy may also be attributable to purchasers delaying the planned purchase of a new vehicle due to the new emission standards, and may occur for reasons such as increased costs or uncertainty about the new vehicles. We expect low-buy, to the extent that it might occur, to be mitigated under the same circumstances described in this section for pre-buy.
^{1298} In comments, commenters referred to “no-buy” as opposed to low-buy, however the concept is the same: the potential that vehicles that would have been purchased after the new rule becomes effective will not be purchased for a length of time.
As noted in section 19.4 of the RTC for this rule, some commenters on the proposed rule highlight the potential for this rule to lead to pre-buy, with one commenter asserting that EPA should finalize more incremental measures than those proposed in order to avoid dramatic increases in up-front vehicle costs and associated pre-buy. Another commenter stated that the cost of complying with the proposal will lead to a pre-buy, and an increase in demand for the previous model year, leading to an increase in the cost of that earlier model year. Some commenters also stated that EPA's approach of not estimating sales effects is inconsistent with both EPA's light-duty rules, and the recently finalized HD2027 rule.
In response to the comment regarding more incremental measures than those proposed, we point to preamble section II.F, where we explain that the standards for MYs 2027-2031 in the final rule are not as stringent as those proposed as they include a slower phase-in. While we made this change for the reasons stated in section II of the preamble and not due to any concerns with pre-buy or low-buy, this nonetheless is responsive to the commenters' request for a slower phase-in. In addition, in response to this commenter and the commenter on costs, the costs of complying with the rule are lower on average than those estimated in the proposed rule. Also, the estimated pathways of compliance with the rule are associated with reduced fueling costs for both the vehicles with ICE technologies, and with ZEVs. ZEVs are also expected to have lower maintenance and repair costs than comparable ICE vehicles. These cost savings will reduce the payback period of such technologies that may be used by manufacturers to comply with the rule. We expect that these cost savings will work toward mitigating possible pre-buy and increased demand for previous model year vehicles.
In response to commenters stating that the qualitative discussion in the proposed rule is inconsistent with our approach to sales effects in light-duty rules, as well as with the recently finalized HD2027 Low NOx final rule ^{1299} (HD2027 rule), we believe this rule is significantly different from those rules such that we cannot apply the same kinds of quantitative analyses. First, with respect to light-duty, the light-duty market is a very different market than the HD vehicle market, and purchase decisions are made differently. LD consumer behavior includes different considerations than a HD vehicle owner who purchases a vehicle to perform work (such as transport passengers, deliver concrete, or move freight). Therefore, the method of analyses for estimating sales effects in the LD market are not the same as those that should be used for effects in the HD market. Second, the costs of GHG-reducing technologies are more than offset through operating savings, unlike the technologies associated with the HD2027 rule. Thus, we would expect sales effects of this rule to be significantly different from those associated with the HD2027 rule or other rules establishing standards to reduce criteria pollutants.
^{1299} “Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards” 88 FR 4296, January 24, 2023.
At proposal, we discussed the analysis of EPA regulations on four recent HD regulations, which suggested that the range of possible pre-buy and low-buy due to those rules includes no pre-buy or low-buy due to EPA rules. ^{1300} We also made it clear that, while it is instructive that the ERG report found little to no pre-buy or low-buy effects due to our HD rules, the approach to estimate a change in the sales of HD vehicles before and after the promulgation of a rule due to the cost of that rule (as was done in the ERG report) should not be used to estimate sales effects from this final rule because: (1) most of the statistically significant sales effects in the report were estimated using data from criteria pollutant rules, which are not appropriate for use in estimating effects from HD GHG rules because differences in how costs are incurred and benefits are accrued as a result of HD vehicle criteria pollutant regulations versus HD GHG regulations may lead to differences in how HD vehicle buyers react to a particular regulation; ^{1301} (2) there was relatively more uncertainty in the net estimated price change from the 2014 GHG rule than in the criteria pollutant rules because the performance-based GHG standards had many different compliance pathways which led to both capital cost increases as well as reductions in operating costs through fuel savings. As such, the cost of the regulation could vary greatly across firms and may have led to net cost savings. This likely variation in net costs of the rule led to greater uncertainty in the results of the report; (3) the approach outlined in the report was estimated only using HD ICE vehicle data ( e.g., cost of compliance due to adding HD ICE engine technologies to a HD ICE engine) because that was all that was available at the time of promulgation of the rules. The modeled potential compliance pathway for this rule includes ZEV technologies, which associated EVSE infrastructure, and the possible impacts of such are not represented in the results of the report. For these reasons, we are not using the method in the ERG report to estimate sales effects due to this rule. For more discussion on comments, and our response to comments, related to sales effect of this rule, see RTC section 19.4.
^{1300} “Analysis of Heavy-Duty Vehicle Sales Impacts Due to New Regulation.” At https://cfpub.epa.gov/si/si_public_pra_view.cfm?dirEntryID=349838&Lab=OTAQ .
^{1301} For example, the 2014 rule (`Final Rule for Phase 1 Greenhouse House Emissions Standards and Fuel Efficiency Standards for Medium- and Heavy-Duty Engines and Vehicles' found at https://www.epa.gov/regulations-emissions-vehicles-and-engines/final-rule-phase-1-greenhouse-gas-emissions-standards ) led to reductions in GHG emissions and had lower associated technology costs compared to the criteria pollutant rules, and compliance with the GHG regulation was associated with fuel savings.
This rulemaking is expected to lead to reductions in emissions across the HD vehicle fleet (see section V of this preamble), though such reductions are expected to happen gradually as the HD fleet turns over. This is because the fraction of the total HD vehicle fleet that are new, compliant vehicles will initially be a small portion of the entire HD market. As more vehicles compliant with this rule are sold, and as older HD vehicles are retired, greater emission reductions are expected to accumulate. The emission reductions attributable to each HD segment that will be affected by this rule will depend on many factors, including the rate of purchase of compliant vehicles in each market segment over time and the proportion of those vehicles that utilize each of the mix of technologies under the compliance pathways manufacturers choose. In addition, if pre-buy or low-buy occurs as a result of this rulemaking, emission reductions will be smaller than anticipated. Under pre-buy conditions, fleets would, on average, be comprised of newer model year vehicles. Though these new vehicles are expected to have lower emissions than the vehicles they are replacing, emission reductions could still be lower than we estimate will be achieved as a result of the final emission standards. Under low-buy, we expect older, more polluting, HD vehicles to remain in use longer than they otherwise would in the absence of new regulation. If pre-buy is smaller than low-buy, to the extent both might occur, this would lead to a slower fleet turnover, at least in the short term. ^{1302} Conversely, if pre-buy is larger than low-buy, short-term fleet turnover would increase and fleets would, on average, be comprised of newer model year vehicles, and though emission reductions would be expected to be larger than under a scenario where low-buy exceeds pre-buy, emission reductions would still be lower than we estimate will be achieved as a result of the final emission standards. Under a situation where low-buy matches pre-buy, we would also expect lower emission reductions than estimated, and emission reductions would likely be somewhere between the two relative pre-buy/low-buy scenarios discussed in this paragraph. For more information on sales impacts, see Chapter 6.1.1 of the RIA.
^{1302} Fleet turnover refers to the pace at which new vehicles are purchased and older vehicles are retired. A slower fleet turnover means older vehicles are kept on the road longer, and the fleet is older on average. A faster fleet turnover means that the fleet is younger, on average.
Although, as commenters mentioned, the increased purchase price due to this rule could potentially lead to pre-buy and/or low-buy, pre- or low-buy is unlikely to occur in a significant manner. Specifically, we expect that they will either not occur at all, or if they do, occur in a limited way that will not significantly affect the GHG emissions reductions projected by this rule or that would unduly disrupt the HD vehicle market. This is due, in part, to the operating cost savings we estimate will be achieved in complying with this rule. For the modeled compliance pathway for this rule, that cost savings are expected to wholly offset the increased upfront purchase cost for ZEVs, which leads to payback periods of between two and five years. This is also supported by the analyses of previously promulgated EPA HD emission standards, which indicate that where pre-buy or low-buy has been seen, the magnitude of these phenomena has been small. ^{1303} Lastly, it should be noted that many studies estimating how large or expensive purchases are made, including that of HD vehicles, indicate purchase decisions are heavily influenced by macroeconomic factors unrelated to regulations, such as interest rates, economic activity, and the general state of the economy. ^{1304} For example, according to the Economic Research Division of the Federal Reserve, retail sales of heavy weight trucks sales fell dramatically between September of 2019 and May of 2020 (about 46 percent fewer sales), likely in great part due to the COVID-19 pandemic, and they rebounded through May of 2021 to be only about 13 percent lower than in September of the previous year. ^{1305}
^{1303} For example, Lam and Bausell (2007), Rittenhouse and Zaragoza-Watkins (2018), and an unpublished report by Harrison and LeBel (2008). For EPA's summary on these studies, see the EPA peer review report “Analysis of Heavy-Duty Vehicle Sales Impacts Due to New Regulation.” at https://cfpub.epa.gov/si/si_public_pra_view.cfm?dirEntryID=349838&Lab=OTAQ , in the docket for this rule.
^{1304} See the literature review found in the ERG report mentioned earlier in this section, “Analysis of Heavy-Duty Vehicle Sales Impacts Due to New Regulation.” Found at https://cfpub.epa.gov/si/si_public_pra_view.cfm?dirEntryID=349838&Lab=OTAQ for more information.
^{1305} The graph of monthly, seasonally adjusted heavy weight truck sales from the Bureau of Economic Analysis can be found at: https://fred.stlouisfed.org/series/HTRUCKSSAAR.

ii. Mode Shift
Mode shift would occur if goods normally shipped by HD vehicle are instead shipped by another method ( e.g., rail, boat, air) as a result of this action. Whether shippers switch to a different mode of transportation for freight depends not only on the cost per mile of the shipment ( i.e., freight rate), but also the value of the shipment, the speed of transport needed for shipment (for example, for non-durable goods), and the availability of supporting infrastructure ( e.g., rail lines, highways, waterways). Shifting from HD vehicles to other modes of transportation may occur if the cost of shipping goods by HD vehicles increases relative to other modes of transport in cases where there is another mode of transport available that can meet the required timing. Though we are unable to estimate what effect this rule might have on shipping costs, in part because we are not able to estimate how a change in upfront vehicle costs affects shipping rates, or how much of a change in operational costs is passed through to the shipping rates, we do estimate that, under the potential compliance pathway projected for this rule, average net upfront costs are paid back in five years or less for the vehicle groups affected by this rule, and these vehicles are expected to experience reduced operational costs. Chapter 3.3 of the RIA and section IV.D of this preamble discuss the estimated decrease in operational costs of this rule, mainly due to the increase in the share of ZEVs in the on-road HD fleet under the modeled potential compliance pathway. But the same is true for ICE vehicles that meet the Phase 3 emission standards, using other potential compliance pathways. The vehicles that comply with this rule are expected to have positive total costs of ownership over both five- and ten-year time horizons and thus we do not expect a significant increase in shipping rates and therefore we do not project mode shifts as a likely outcome of this regulation. ^{1306} Furthermore, no commenter suggested that mode shift was a reasonable outcome of our proposed standards. ^{1307} For more information on mode shift, see Chapter 6.1.2 of the RIA.
^{1306} If manufacturers comply by adding technology to ICE vehicles, we also expect to see reduced operational costs through reduced fuel consumption.
^{1307} We note that a study published by Argonne National Laboratory in 2017 indicates that if mode shift were to occur as a result of this rule, it would likely result in further decreasing transportation GHG emissions and upstream energy usage. https://publications.anl.gov/anlpubs/2017/08/137467.pdf.

iii. Class Shift
Class shift would occur if purchasers shift their vehicle purchase from one class of vehicle to another class of vehicle due to impacts of the rule on vehicle attributes, including performance and relative costs, among vehicle types that could practically be switched. Heavy-duty vehicles are typically configured and purchased to perform a function. For example, a concrete mixer truck is purchased to transport concrete, a combination tractor is purchased to move freight with the use of a trailer, and a Class 4 box truck could be purchased to make deliveries. The purchaser makes decisions based on many attributes of the vehicle, including the gross vehicle weight rating, which in part determines the amount of freight or equipment that can be carried. If the Phase 3 standards impact either the performance or cost of a vehicle relative to the other vehicle classes, then purchasers may choose to purchase a different vehicle, resulting in the unintended consequence of increased fuel consumption or GHG emissions in-use.
A purchaser in need of a specific vocational vehicle, such as a bus, box truck or street sweeper, would not be able to shift the purchase to a vehicle with a less stringent emission standard (such as the optional custom chassis standards for emergency vehicles, recreational vehicles, or mixed use (nonroad) type vehicles) and still meet their needs. The purchaser makes decisions based on many attributes of the vehicle, including the gross vehicle weight rating or gross combined weight rating of the vehicle, which in part determines the amount of freight or equipment that can be carried. Due to this, it is not likely feasible for purchasers to switch to other vehicle classes simply due to the emission standards.
In the proposed rule, we requested comment on data or methods to estimate the effect the emission standards might have on class shifting. Though we did not receive comment on data or methods, we did receive comment on possible class shifting, due to the differences between an ICE vehicle and its corresponding ZEV counterpart. EMA commented that ZEVs will require increased axle-capacity directly due to increased vehicle weight, or to ensure consistent payload under increased vehicle weight due to the weight of a battery. EMA commented that this may lead to driver shortages if vehicles shifted from Class 6 to Class 7, for example due to increased driver requirements, and will lead to increased costs, for example due to increased driver pay or the need to pay excise taxes if a vehicle shifts from Class 7 to Class 8.
As described in section II.D.3 of the preamble, we account for differences in vehicle uses and payload capacity in HD TRUCS, a tool we developed to for this rule to evaluate ZEV technologies. Our HD TRUCS analysis was then incorporated in in our consideration of possible compliance pathways to support the feasibility of the final standards. In the modeled potential compliance pathway, we estimate the new vehicles produced and sold compliant with the rule, including ZEVs, are able to perform the same function as vehicles produced without the rule in place. For example, BEV technologies were not included within the potential compliance pathway in situations where the performance needs of a BEV would result in a battery that was too large or heavy due to the impact on payload and potential work accomplished relative to a comparable ICE vehicle. We assess the incremental weight increase or decrease of ZEVs compared to ICE vehicles in RIA Chapter 2.9.1. Also, it should be noted that for this final rule, we projected multiple pathways to compliance, including pathways that did not project an increase in ZEV penetration. Furthermore, although there are possible pathways that include reduced ZEV penetration compared to the modeled potential compliance pathway estimated in the analysis for this rule, there may also be greater ZEV penetration in one or more vehicle classes than we estimate in the modeled potential compliance pathway.
Class shift could also occur if one class of vehicle becomes significantly more expensive relative to another class of vehicle due to the technology and operating costs associated with the new emission standards. We expect class shifting, if it does occur, to be very limited because this rule applies new emission standards to all HD vehicle classes, as described in preamble section II. Furthermore, typically the purchase cost of heavy-duty vehicles increases with the class of the vehicle. In other words, a light heavy-duty box truck typically costs less to purchase and operate than a heavy heavy-duty box truck. The projected incremental upfront and operating costs to purchasers in the modeled compliance pathway for this final rule do not lead to situations where the cost to purchase a heavier class of vehicle becomes lower than the cost to purchase a lighter class. ^{1308} In addition, the average payback period for the technologies in the modeled potential compliance pathway for all of the classes of vehicles are within the first ownership period, and our analysis shows a positive total cost of ownership over a five year time horizon.
^{1308} See preamble section II.F.2.ii.
In summary, we expect very little class shifting, if any, to occur. However, if a limited amount of shifting were to occur, we expect negligible emission impacts (compared to those emission reductions estimated to occur as a result of the emission standards).

iv. Domestic Production
These emission standards are not expected to provide incentives for manufacturers to shift between domestic and foreign production. This is because the emission standards apply to vehicles sold in the United States regardless of where such vehicles are produced. If foreign manufacturers already have increased expertise in satisfying the requirements of the emission standards, there may be some initial incentive for foreign production. However, given increasing global interest in reducing vehicle emissions, specifically through the use of ZEV technologies, as domestic manufacturers produce vehicles with reduced emissions, including ZEVs, the opportunity for domestic manufacturers to sell in other markets might increase. To the extent that the emission standards might lead to application and use of technologies that other countries may seek now or in the future, developing this capacity for domestic producers now may provide some additional ability to serve those markets. In addition, this rule and Federal actions including the IRA and BIL support the U.S. in our efforts to remain competitive on a global scale by encouraging and supporting the expansion of and investment in domestic manufacturing of ZEV technologies, supply chains, charging infrastructure and other industries related to green transportation technology.
As discussed in section B of the Executive Summary and RIA Chapter 1, the IRA contains tax credit incentives. The tax credit for the production and sale of battery cells and modules ^{1309} is conditioned on such components or minerals being produced in the United States and, thus, is designed to encourage such domestic production. ^{1310} Our cost analysis reflects that in our modeled potential compliance pathway we project an increasing percentage of the batteries used in HD BEVs will be eligible for the up to $45/kwh tax credit beginning in MY 2027 through MY 2032, in addition to consideration of the other tax incentives that apply to vehicle and EVSE purchasers, as described in section IV and RIA Chapter 3. For more information on comments received on possible impacts to domestic production of HD vehicles or components, and our responses, see the RTC section 19.
^{1309} The tax credit (45X) is for up to $45 per kilowatt-hour (kWh), and for 10 percent of the cost of producing applicable critical minerals (including those found in batteries and fuel cells, provided that the minerals meet certain specifications).
^{1310} Note that the 30C charger credit has a requirement that eligible chargers must be installed in certain census tracts.

2. Purchaser Acceptance
In the modeled potential compliance pathway for the final rule, we project an increase in the adoption of HD BEVs and FCEVs for most of the HD vehicle types for MYs 2027 and beyond (see preamble section II or the RIA Chapter 2 for details). ^{1311} As explained in section IV and Chapter 3 of the RIA, though we estimate this rule will be associated with higher upfront vehicle costs for some vehicles, these costs are expected to be mitigated by operating costs savings. As explained in preamble section II and RIA Chapter 2, under the modeled potential compliance pathway, although some HD ZEVs produced and sold in response to this rule have higher incremental upfront purchaser vehicle cost difference between a ZEV and a comparable ICE vehicle (or higher incremental upfront purchaser cost difference when including consideration of EVSE, as applicable), our cost analysis shows that this incremental upfront purchaser cost difference will be partially or fully offset by a combination of the Federal vehicle tax credit and battery tax credit (and EVSE tax credit, as applicable) for HD ZEVs that are available through MY 2032, and further offset over time through operational savings. ^{1312} Our analysis shows that, in our modeled compliance pathway, the vehicle types for which we project ZEV adoption for MY 2032 have an average payback period of between two and five years, depending on the regulatory group, when compared to a comparable ICE vehicle, even after considering the upfront purchaser and operating costs of the associated EVSE. See sections II and IV of this preamble and Chapters 2 and 3 of the RIA for more information on the estimated costs of this rule.
^{1311} We again note that manufacturers may choose any compliance pathway that meets the final standards, including pathways that do not use ZEV technologies, and thus we note that ZEVs may not be purchased at the rates estimated in the modeled potential compliance pathway analyzed for this rule.
^{1312} For more information on the Federal tax credits, see section ES.B of this preamble.
Businesses that operate HD vehicles are under competitive pressure to reduce operating costs, which should encourage purchasers to identify and rapidly adopt new vehicle technologies that reduce operating costs. As outlays for labor and fuel generally constitute the two largest shares of HD vehicle operating costs, depending on the price of fuel, distance traveled, type of HD vehicle, and commodity transported (if any), businesses that operate HD vehicles face strong incentives to reduce these costs. 1313 1314 Potential savings in operating costs appear to offer strong incentives for HD vehicle buyers to pay higher upfront costs for vehicles that reduce operating costs, such as HD ZEVs. Economic theory suggests that a normally functioning competitive market would lead HD vehicle buyers to want to purchase, and HD vehicle manufacturers to incorporate, technologies that contribute to lower net costs.
^{1313} American Transportation Research Institute, An Analysis of the Operational Costs of Trucking, September 2013. Docket ID: EPA-HQ-OAR-2014-0827-0512.
^{1314} Transport Canada, Operating Cost of Trucks, 2005. Docket ID: EPA-HQ-OAR-2014-0827-0070.
In RIA Chapter 6.2, we discuss the possibility that an “energy efficiency gap” or “energy paradox” has existed, where available technologies that would reduce the total cost of ownership for the vehicle (when evaluated over their expected lifetimes using conventional discount rates) have not been widely adopted, or the adoption is relatively slow, despite their potential to repay buyers' initial investments rapidly. The energy efficiency gap may exist due to constraints on access to capital for investment, imperfect or asymmetrical information about the new technology, uncertainty about supporting infrastructure, uncertainty about the resale market, and first-mover disadvantages for manufacturers. For example, purchasers may not consider the full, or even a portion of, the value of operational cost savings, due to uncertainty, such as uncertainty about future fuel prices, or purchaser uncertainty about the technology itself. Another example of when this may occur is if a principal-agent problem exists, causing split incentives. ^{1315} In this section we discuss these potential issues that may impact the adoption of technologies like HD ZEVs, as well as factors (like this final rule) that may mitigate them. We expect these final Phase 3 standards as well as other factors we discuss will help overcome such barriers by incentivizing the development of technologies and supporting infrastructure that reduce operating costs and total cost of ownership, like ZEV technologies, and reduce uncertainties for HD vehicle purchasers on such technologies' benefits and other potential concerns. Additionally, the final rule also sends a signal to electric utilities of demand under the potential compliance pathway, and thus provides support justifying buildout of electrification infrastructure.
^{1315} A principal-agent problem happens when there is a conflict in priorities (split incentives) between a “principal,” or the owner of an asset, and an “agent,” or the person to whom control of the asset has been delegated, such as a manager or HD vehicle operator.
The availability of existing incentives, including the Federal purchaser (vehicle and EVSE) and battery manufacturing tax credits in the IRA, is expected to lead to lower upfront costs for purchasers of HD ZEVs than would otherwise occur. ^{1316} We expect this will impact ZEV adoption rates by purchasers taking advantage of existing incentives to lower the upfront costs of purchasing HD ZEVs (including depot EVSE), which would result in higher ZEV adoption rates than would otherwise exist absent such incentives, and so counteract the energy efficiency gap for purchasers under the modeled potential compliance pathway for manufacturers.
^{1316} Note that the incentives exist in the reference scenario and under the scenario analyzed with our final standards.
In addition, as purchasers consider more of the operational cost savings of, for example, a ZEV over a comparable ICE vehicle in their purchase decision, the smaller the impact the higher upfront costs for purchasers have on that decision, and purchasers are more likely to purchase (in this example, a ZEV). However, for this example, uncertainty about ZEV technology, charging infrastructure technology and availability for BEVs, hydrogen refueling infrastructure for FCEVs, or uncertainty about future fuel and electricity prices may affect purchaser consideration of operational cost savings of ZEVs. ^{1317} Other areas of uncertainty include purchasers' impressions of BEV charging and FCEV fueling infrastructure support and availability, perceptions of the comparisons of quality and durability of different BEV powertrains, and resale value of the vehicle. We acknowledge that uncertainties, including those regarding infrastructure, could affect manufacturer compliance strategies, and could lead to compliance strategy decisions involving fewer ZEVs than we project in our modeled potential compliance pathway.
^{1317} We provide an assessment of charging infrastructure and the electric generation, transmission and distribution in preamble section II.
As discussed in detail in RIA Chapter 2.6 and 2.10.3, EPA has carefully analyzed the infrastructure needs and costs to support the modeled potential compliance pathway's technology packages that support the MY 2027-2032 standards. Additionally, as purchasers learn more about ZEV technologies, and as the penetration of the technologies and supporting infrastructure in the market increases, the exposure to ZEV technologies in the real world will reduce uncertainty related to viability or durability of the vehicles and the availability of supporting infrastructure. And though increasing penetration of HD ZEVs is projected to continue to happen regardless of the standards, as explained in our reference case, these standards are expected to help accelerate the process, incentivizing manufacturers to educate purchasers on the benefits of their compliance strategy technologies, like HD ZEVs. We note that, as explained in preamble section II.B.2.iii, EPA, in consultation with other agencies, has committed to engage with stakeholders to monitor compliance and major elements related to HD ZEV infrastructure, and to issue periodic reports reflecting this collected information in the lead up to these standards. These actions will also increase purchaser awareness and reduce uncertainty.
A principal-agent problem could exist if truck operators (agents) and truck purchasers who are not also operators (principals) value characteristics of the trucks under purchase consideration differently (split incentives) which could lead to differences in purchase decisions between truck operators and truck purchasers. Characteristics may include physical characteristics (for example noise, vibration or acceleration), cost characteristics (for example operational costs, purchase prices, or cost of EVSE installation), or other characteristics (for example availability of EVSE infrastructure). Such potential split incentives, or market failures, could, for example, impact HD ZEV adoption rates if agents weigh characteristics more associated with ICE vehicles greater than those associated with ZEV vehicles in a manner different than represented in the analysis of the modeled compliance pathway for this rule. The possibility of a principal-agent problem could be mitigated through measures that cause an alignment of interests between the principal and the agent, for example, measures that lead to sharing of the benefits and/or costs that may cause the issue. While this is a theoretical issue, EPA is not aware of any data or analysis persuasively demonstrating if the principal-agent problem significantly affects HD vehicle purchases generally, or specifically with respect to HD ZEV purchases. However, we note that, given the commercial nature of how HD vehicles are used and the need to minimize costs in competitive business environments, we think it is reasonable, absent empirical evidence to the contrary, to conclude that truck purchasers are very unlikely to ignore the significant operational cost savings associated with HD ZEVs.
EPA recognizes that there is uncertainty related to technologies that manufacturers may adopt in their compliance strategies for this final rule, like ZEVs, that may impact the adoption of new technology even though it reduces operating costs. Markets for both new and used HD vehicles may face these problems, although it is difficult to assess empirically the degree to which they do. We expect these final Phase 3 standards will help overcome such barriers by incentivizing the development and deployment of technologies that reduced HD vehicle emissions, including ZEV technologies, and the development of supporting infrastructure, as well as the education of HD vehicle purchasers on the benefits of reduced emission technology and about ZEV infrastructure.
In the proposed rule, we requested comment and data on acceptance of HD ZEVs. Though we did not receive any data, we did receive many comments on ZEV acceptance and adoption, including assertions that the proposed rule would lead to reduced choice at the dealership because there will be fewer ICE vehicle models available to choose from, and that total ownership cost and return on investment for HD ZEVs is difficult to predict, in part because ZEVs are so new. Other commenters were in support of greater ZEV adoption, stating that the benefits of ZEVs, including their overall cost, driver appreciation, and sustainability, are drivers for adoption. Further detail regarding these comments and our responses is in RTC section 19.5.
In our modeled potential compliance pathway that supports the feasibility of the standards, we account for and consider willingness to purchase considerations in several ways (and, correspondingly, impacts on HD ZEV adoption included in the modeled potential compliance pathway). This includes considering uncertainty about vehicle weight, component ( e.g., battery) sizing, infrastructure availability, upfront purchaser costs, and payback for purchasers, as well as including limitations in our analysis to phase in the final standards to provide additional time and a slower pace of adjustment in early model years. For example, our HD TRUCS analysis applies oversize factors for batteries to account for temperature effects, potential battery degradation and more; we sized most batteries for the 90th percentile of estimated VMT; ^{1318} and we sized EVSE such that vehicles' batteries could be fully recharged during the dwell time available to specific vehicle applications. In addition, in our HD TRUCS analysis we cap the ZEV adoption rate for each vehicle type to be no more than 70 percent for MY 2032 and no more than 20 percent in MY 2027. For more detail on the constraints we considered and included, see preamble sections II.D, II.E, and II.F. In the HD TRUCS analysis, we developed a method to include consideration of payback in assessing adoption rates of BEVs and FCEVs for the modeled potential compliance pathway after considering methods in the literature. ^{1319} Our payback curve, and methods considered and explored in the formulation of the method used in this rule, are described in RIA Chapter 2.7. As stated there, given information currently available, and our experience with the HD vehicle industry, payback period is the most relevant metric to the HD vehicle industry. ^{1320} The payback schedule caps used in our model are lower in MY 2027 compared to MY 2032 to recognize additional time for the ZEV technology and infrastructure to mature. Fleet owners and drivers will have had more exposure to ZEV technology in 2032 compared to 2027, which may work to alleviate concerns related to ZEVs (for example, concerns of reliability) and result in a lower impression of risk of these newer technologies. In addition, infrastructure to support ZEV technologies will have had more time to expand and mature, further supporting increased HD ZEV adoption rates.
^{1318} For the final rule, we sized batteries in BEVs that we expect to be charged en-route using public charging starting in MY 2030 at the 50th percentile daily VMT. For the longest range day cabs and sleeper cabs, on days when these vehicles are required to travel longer distances, we find that less than 30 minutes of mid-day charging at 1 MW is sufficient to meet the HD TRUCS 90th percentile VMT assuming vehicles start the day with a full battery.
^{1319} Adoption rates estimated in HD TRUCS are one of several factors considered in determining the appropriate level of the standards. These estimated adoption rates in HD TRUCS demonstrate that the adoption rates in our modeled potential compliance pathway are all feasible.
^{1320} Our assessment of total cost of ownership, shown in RIA Chapter 2.12, further supports our assessment of payback periods.
In summary, EPA recognizes that businesses that operate HD vehicles are under competitive pressure to reduce operating costs, which should encourage HD vehicle buyers to identify and rapidly adopt cost-effective technologies that reduce operating costs and the total cost of ownership. Outlays for labor and fuel generally constitute the two largest shares of HD vehicle operating costs, depending on the price of fuel, distance traveled, type of HD vehicle, and commodity transported (if any), so businesses that operate HD vehicles face strong incentives to reduce these costs. However, EPA also recognizes that there is uncertainty related to technologies that manufacturers may adopt in their compliance strategies for this final rule, like ZEVs, that may impact the adoption of these technologies even though they reduce operating costs. Markets for both new and used HD vehicles may face these problems, although it is difficult to assess empirically the degree to which they do. As explained in this section and RIA Chapter 6.2, we expect these final Phase 3 standards as well as other factors we discussed will help overcome such barriers by incentivizing the development of technologies and supporting infrastructure that reduce operating costs and total cost of ownership, like ZEV technologies, and reduce uncertainties for HD vehicle purchasers on such technologies' benefits and other potential concerns.
As explained in section II of the preamble, under the modeled potential compliance pathway the majority of new vehicles are projected to be ICE vehicles. Additionally, in this final rule, we emphasize that manufacturers have flexibility to choose among various compliance pathways to meet the standards that can include a mix of HD vehicle technologies; we analyzed a modeled potential compliance pathway to support the feasibility of the final standards, and we also provided additional example potential compliance pathways that utilizes only vehicles with ICE technologies relative to the reference case. Because there are multiple ways to comply with this rule, and even under the modeled potential compliance pathway the majority of new vehicles are projected to be ICE vehicles, we expect that fleets and purchasers will be able to purchase the vehicle that works best for them given their circumstances. For fleets and purchasers, purchase decisions may include choosing a vehicle to comply with state or local policies as well as this rule, or choosing a vehicle that improves driver retention due to its characteristics. As noted, the final rule also sends a signal to electric utilities of demand under the modeled potential compliance pathway, and thus provides support justifying buildout of electrification infrastructure. As explained in section VI.E.1, the ability for manufacturers to comply through various compliance pathways is also expected to reduce the likelihood of pre- or low-buy that could potentially be associated with this rule.

3. VMT Rebound
Historically, the “rebound effect” has been interpreted as more intensive vehicle use, resulting in an increase in liquid fuel in response to increased ICE vehicle fuel efficiency. Although much of this possible vehicle use increase is likely to take the form of an increase in the number of miles vehicles are driven, it can also take the form of an increase in the loaded operating weight of a vehicle or altering routes and schedules in response to improved fuel efficiency. More intensive use of those HD ICE vehicles consumes fuel and generates emissions, which reduces the fuel savings and avoided emissions that would otherwise be expected to result from increasing fuel efficiency of HD ICE vehicles.
Unlike the LD vehicle rebound effect, there is little published literature on the HD vehicle rebound effect, and all of it focuses on the rebound effect due to increased ICE fuel efficiency. Winebrake et al. (2012) suggest that vocational trucks and tractor trailers have a rebound effect of essentially zero. ^{1321} Leard et al. (2015) estimate that tractor trailers have a rebound effect of 30 percent, while vocational vehicles have a 10 percent rebound rate. ^{1322} Patwary et al. (2021) estimated that the average rebound effect of the U.S. road freight sector is between about 7 to 9 percent, although their study indicated that rebound has increased over time. ^{1323} This is slightly smaller than the value found by Leard et al. (2015) for the similar sector of tractors.
^{1321} Winebrake, J.J., Green, E.H., Comer, B., Corbett, J.J., Froman, S., 2012. Estimating the direct rebound effect for on-road freight transportation. Energy Policy 48, 252-259.
^{1322} Leard, B., Linn, J., McConnell, V., and Raich, W. (2015). Fuel Costs, Economic Activity, and the Rebound Effect for Heavy-Duty Trucks. Resources For the Future Discussion Paper, 14-43.
^{1323} Patwary, A.L., Yu, T.E., English, B.C., Hughes, D.W., and Cho, S.H. (2021). Estimating the rebound effect of the US road freight transport. Transportation Research Record, 2675(6), 165-174.
With respect to ZEVs specifically, we do not have data that operational cost savings of switching from an ICE vehicle to a ZEV will affect the VMT driven of that vehicle, nor do we have data on how changing fuel prices might affect VMT of ZEVs over time. Given the increasing penetration of ZEVs in the HD fleet even in the reference case, as explained in preamble section V, as well as the wide range of effects discussed in the literature, we do not believe the rebound estimates in literature cited here are appropriate for use in our analysis. In addition, the majority of research on VMT rebound has been performed in the light-duty vehicle context. The factors influencing light-duty and heavy-duty VMT are generally different. For example, light-duty VMT is generally related to personal considerations, including costs and benefits associated with driving, while HD VMT is more a function of profits or impacts on labor. It is also important to note that even if there is an increase in VMT in new vehicles, this may be offset by a decrease in VMT on older vehicles. This may occur if operational cost savings on newer vehicles due to this rule lead operators to shift VMT to these newer, more efficient vehicles.
If rebound rates are positive, we would assume that higher rebound rates are associated with larger responses to a change in the cost per mile of travel, which could result in some increase in non-GHG emissions and in brake and tire wear, but also an increase in benefits associated with increased vehicle use (for example, increased economic activity associated with the services provided by those vehicles), as well as positive impacts on employment. However, lower rebound rates may happen if owner/operators use those cost savings in other ways, for example, to reduce their payback period. Also, as noted in the Winebrake at al. (2012) study, possible rebound impacts are likely reduced by adjustments in other operational costs such as labor, and the nature of the freight industry as an input to a larger supply chain system. As in the proposal, we are not estimating any VMT rebound due to this rule (88 FR 26072). Comments received on this issue, and our response to them, can be found in RTC section 19.2.

4. Employment Impacts
Economic theories of labor demand indicate that employers affected by environmental regulation may change their demand for different types of labor in different ways, increasing demand for some types, decreasing demand for other types, or not changing it at all for still other types. A variety of conditions can affect employment impacts of environmental regulation, including baseline labor market conditions and employer and worker characteristics such as industry and region. A growing body of literature has examined employment effects of environmental regulation. Morgenstern et al. decompose the labor consequences in a regulated industry facing increased abatement costs. ^{1324} This study identifies three separate components of labor demand effects. First, there is a demand effect caused by higher production costs, which in turn, results in increased market prices. Increased market prices reduce consumption (and production), thereby reducing demand for labor within the regulated industry. Second, there is a cost effect. As production costs increase, manufacturing plants use more of all inputs, including labor, to produce the same level of output. Third, there is a factor-shift effect, which occurs when post-regulation production technologies may have different labor intensities than pre-regulation production technologies. ^{1325}
^{1324} Morgenstern, R.D.; Pizer, W.A.; and Shih, J.-S. “Jobs Versus the Environment: An Industry-Level Perspective.” Journal of Environmental Economics and Management 43: 412-436. 2002.
^{1325} Additional literature using similar frameworks include Berman and Bui (2001) and Deschênes (2018). For more information on this literature, see the Chapter 10 of the RIA for the HD2027 rule, found at Docket ID EPA-HQ-OAR-2019-0055.
Due to a lack of data, we are not able to estimate employment effects from this rule. The overall effect of the rule on employment in the heavy-duty vehicle manufacturing sector depends on the relative magnitude of factor-shift, cost, and demand effects, as well as possible differences in employment related to HD ICE and ZEV manufacturing under the potential compliance pathway. A market shift to HD ZEVs will lead to a shift in employment needs as well. In Chapter 6.4.2 of the RIA, we show that the amount of labor per million dollars in sales in motor vehicle manufacturing sectors has generally declined over the last fifteen years, indicating that fewer people have been needed to produce the same value of goods. For example, in 2008, motor vehicle body and trailer manufacturing employed about 4.8 employees per million dollars in sales, falling to just under 3.7 employees per million dollars in sales in 2022. In the electrical equipment manufacturing sector, which is involved in the production of components that go in to BEVs and the battery electric portion of PHEVS, employment has increased over the last fifteen years, rising from about 3.3 employees per million dollars in sales in 2007 to about 4.1 employees per million dollars in sales in 2022.
The International Union, United Automobile, Aerospace and Agricultural Implement Workers of America (UAW) has stated that re-training programs will be needed to support auto workers in a market with an increasing share of electric vehicles in order to prepare workers that might be displaced by the shift to the new technology. ^{1326} In comments on the proposed rule, the UAW stated support for emission reductions, though they also indicated a slower phase in of ZEVs into the market than that projected in the proposal would better support employees in auto manufacturing and supporting industries. Volkswagen has stated that labor requirements for ICE vehicles are about 70 percent higher than their electric counterpart, but these changes in employment intensities in the manufacturing of the vehicles can be offset by shifting to the production of new components, for example batteries or battery cells. ^{1327} Climate Nexus has indicated that increasing penetrations of electric vehicles will lead to a net increase in jobs, a claim that is partially supported by the rising investment in batteries, vehicle manufacturing and charging stations. ^{1328} Though most of these statements are specifically referring to light-duty vehicles, they hold true for the HD market as well.
^{1326} More information on UAW's comments can be found in the white paper “Making EVs work for American workers” found at https://uaw.org/wp-content/uploads/2019/07/190416-EV-White-Paper-REVISED-January-2020-Final.pdf .
^{1327} Herrmann, F., Beinhauer, W., Borrmann, D., Hertwig, M., Mack, J., Potinecke, T., Praeg, C., Rally, P. 2020. Effects of Electric Mobility and Digitalisation on the Quality and Quantity of Employment at Volkswagen. Fraunhofer Institute for Industrial Engineering IAO. Study on behalf of the Sustainability Council of the Volkswagen Group. https://www.volkswagenag.com/presence/stories/2020/12/frauenhofer-studie/6095_EMDI_VW_Summary_um.pdf .
^{1328} See the report from Climate Nexus at https://climatenexus.org/climate-issues/energy/ev-job-impacts/ .
The expected investment mentioned by Climate Nexus is also supported by recent Federal investment which will allow for increased investment along the vehicle supply chain, including domestic battery manufacturing, charging infrastructure, and vehicle manufacturing, both in the LD and HD markets. ^{1329} This investment includes the BIL, the CHIPS Act, ^{1330} and the IRA, which are expected to create domestic employment opportunities along the full automotive sector supply chain, from components and equipment manufacturing and processing to final assembly, as well as incentivize the development of reliable EV battery supply chains, both for BEVs and PHEVs. ^{1331} For example, the IRA is expected to impact domestic employment through conditions on eligibility for purchase incentives and battery manufacturing incentives. These conditions include contingencies for domestic assembly, domestic critical minerals production, and domestic battery manufacturing. As an example, a new joint venture between Daimler Trucks, Cummins, and PACCAR recently announced a new battery factory to be built in the U.S. to manufacture cells and packs initially focusing on heavy-duty and industrial applications was announced in September 2023. ^{1332} The BlueGreen Alliance and the Political Economy Research Institute estimate that IRA will create over 9 million jobs over the next decade, with about 400,000 of those jobs being attributed directly to the battery and fuel cell vehicle provisions in the act. ^{1333} As discussed in RTC section 19.6, there are many existing and planned projects focused on training new and existing employees in fields related to green jobs, and specifically green jobs associated with electric vehicle production, maintenance and repair and the associated charging infrastructure. This includes work by the Joint Office of Energy and Transportation, created by the BIL, which supports efforts related to deploying infrastructure, chargers and zero emission transit and school buses. In addition, the IRA is expected to lead to increased demand in ZEVs through tax credits for purchasers of ZEVs.
^{1329} See preamble section I for information on the BIL and IRA provisions relevant to vehicle electrification, and the associated infrastructure.
^{1330} The CHIPS Act is the Creating Helpful Incentives to Produce Semiconductors and Science Act and was signed into lay on August 9, 2022. It is designed to strengthen supply chains, domestic manufacturing and national security. More information can be found at https://www.whitehouse.gov/briefing-room/statements-releases/2022/08/09/fact-sheet-chips-and-science-act-will-lower-costs-create-jobs-strengthen-supply-chains-and-counter-china/ .
^{1331} More information on how these acts are expected to aid employment growth and create opportunities for growth along the supply chain can be found in the January, 2023 White House publication “Building a Clean Energy Economy: A Guidebook to the Inflation Reduction Act's Investments in Clean Energy and Climate Action.” found online at https://www.whitehouse.gov/wp-content/uploads/2022/12/Inflation-Reduction-Act-Guidebook.pdf .
^{1332} Daimler Trucks North America. “Accelera by Cummins, Daimler Truck and PACCAR form a joint venture to advance battery cell production in the United States.” September 6, 2023. Available online: https://media.daimlertruck.com/marsMediaSite/en/instance/ko/Accelera-by-Cummins-Daimler-Truck-and-PACCAR-form-a-joint-venture-to-advance-battery-cell-production-in-the-United-States.xhtml?oid=52385590 (last accessed October 23, 2023).
^{1333} Note that these are not all net new employment and reflects where workers may be hired away from other jobs. As the labor market gets tighter and the economy is closer to full employment, there will be a greater number of employees shifting from one job to another. More information can be found in: Political Economy Research Institute. (2022). Job Creation Estimates Through Proposed Inflation Reduction Act. University of Massachusetts Amherst. Retrieved from https://www.bluegreenalliance.org/site/9-million-good-jobs-from-climate-action-the-inflation-reduction-act .
The factor-shift effect on employment reflects potential employment changes due to changes in labor intensity of production resulting from compliance activities. The final standards do not mandate the use of a specific technology, and EPA anticipates that a compliant fleet under the standards will include a diverse range of technologies including ICE vehicle and ZEV technologies. ZEVs and ICE vehicles require different inputs and have different costs of powertrain production, though there are many common parts as well. There is little research on the relative labor intensity needs of producing a HD ICE vehicle versus producing a comparable HD ZEV. Though there are some news articles and research from the light-duty motor vehicle market, they do not provide a clear indication of the relationship between employment needs for ZEVs and ICE vehicles. Some studies find that LD BEVs are less complex, requiring fewer person-hours to assemble than a comparable ICE vehicle. ^{1334} Others find that there is not a significant difference in the employment needed to produce ICE vehicles when compared to ZEVs. ^{1335}
^{1334} Barret, J. and Bivens, J. (2021). The stakes for workers in how policymakers manage the coming shift to all-electric vehicles. Economic Policy Institute. https://www.epi.org/publication/ev-policy-workers .
^{1335} Kupper, D., Kuhlmann, K., Tominaga, K., Arora, A., Schlageter, J. (2020). Shifting Gears in Auto Manufacturing. https://www.bcg.com/publications/2020/transformative-impact-of-electric-vehicles-on-auto-manufacturing .
EPA worked with a research group to produce a peer-reviewed tear-down study of a light-duty BEV (Volkswagen ID.4) to its comparable ICE vehicle counterpart (Volkswagen Tiguan). ^{1336} Included in this study are estimates of labor intensity needed to produce each vehicle under three different assumptions of vertical integration of manufacturing scenarios ranging from a scenario where most of the assemblies and components are sourced from outside suppliers to a scenario where most of the assemblies and components are assembled in house. Under the low and moderate levels of vertical integration, results indicate that assembly of the BEV at the plant is reduced compared to assembly of the ICE vehicle. Under a scenario of high vertical integration, which includes the BEV battery assembly, results show an increase in time needed to assemble the BEV. When powertrain systems are ignored (battery, drive units, transmission and engine assembly), the BEV requires more time to assemble under all three vertical integration scenarios. The results indicate that the largest difference in assembly comes from the building of the battery pack assembly. When the battery cells are built in-house, the BEV will require more hours to build. What is not discussed in this research is that battery cells must be built, regardless of where that occurs. Battery plants are being built and announced in the US, with support from the IRA, BIL and CHIPs, as discussed in section II.D.
^{1336} FEV Consulting Inc., “Cost and Technology Evaluation, Conventional Powertrain Vehicle Compared to an Electrified Powertrain Vehicle, Same Vehicle Class and OEM,” prepared for Environmental Protection Agency, EPA Contract No. 68HERC19D00008, February 2023.
Though we have more information today on differences in the time it takes to build an ICE vehicle and a comparable BEV or PHEV, we do not have enough information to estimate an effect of our rule based on this information. We do not know how OEMs will be (and are) manufacturing their vehicles, nor do we know what this will look like in several years as the MY 2027 and later standards become effective and there is projected to be an increase in the share of BEVs being produced and sold. We can say, generally, that this study indicates that if production of EVs and their power supplies are done in the US at the same rates as ICE vehicles, we do not expect employment to fall, and it may likely increase. In addition, data on the labor intensity of PHEV production compared to ICE vehicle production is also very sparse. PHEVs share features with both ICE vehicles (including engines and exhaust assemblies) and BEVs (including motors and batteries). If labor is a factor of the number of components, PHEVs might have a higher labor intensity of production compared to both BEV and ICE vehicles. We do not have data on employment differences in traditional ICE vehicle manufacturing sectors and ZEV manufacturing sectors, especially for expected effects in the future, nor do we have data on the employment needed for the level of battery production we anticipate will be required to meet future HD ZEV demand projected in our potential compliance pathway.
The demand effect reflects potential employment changes due to changes in new HD vehicle sales. If HD ICE vehicle sales decrease, fewer people would be needed to assemble trucks and the components used to manufacture them. On the other hand, if HD ZEV sales increase, more people would be needed to assemble HD ZEVs and their components, including batteries. If HD ICE vehicle sales decrease while HD ZEV sales increase, the net change in employment will depend on the relative employment needs for each vehicle type. Additional, short-term, effects might be seen if pre-buy or low-buy were to occur. If pre-buy occurs, HD vehicle sales may increase temporarily, leading to temporary increases in employment in the related manufacturing sectors. If low-buy occurs, there may be temporary decreases in employment in the manufacturing sectors related to HD vehicles. However, as noted, EPA does not expect significant pre-buy or low-buy resulting from this rule. In addition, as noted in preamble section E.1, we do not anticipate much mode or class shift in HD market affected by this rule, which also supports a minimal demand effect on employment.
The cost effect reflects the potential impact on employment due to increased costs from adopting technologies needed for vehicles to meet the new emission standards. In the HD ICE vehicle manufacturing sector, if firms invest in lower emitting HD ICE vehicles, we would expect labor to be used to implement those technologies. For firms producing ZEVs, we do not expect the rule to require additional compliance activities, as ZEVs, by definition, emit zero tailpipe emissions. ^{1337} In addition, the standards do not mandate the use of a specific technology, and EPA anticipates that a compliant fleet under the standards will include a diverse range of technologies including ICE and ZEV technologies. Under the additional compliance pathways projected for this final rule that include only technology adoption in ICE vehicles, we expect there could be some increase in employment related to implementing these ICE technologies. However, the level of employment due to implementing new ICE technology as result of this rule will depend on the relative rate of the adoption of the technology.
^{1337} We note that there may be indirect impacts, for example through battery durability monitoring or warranty requirements. See preamble section III.B for more information on these requirements.
In the proposed rule, we requested comment on data and methods that could be used to estimate the potential effects of this action on employment in HD vehicle manufacturing sectors, and on how increasing electrification in the HD market in general might impact employment in HD manufacturing sectors, both for ICE powertrains as well as electrified powertrains. We also requested comment on data and methods to estimate possible effects of the emission standards on employment in the HD ICE and ZEVs manufacturing markets. ^{1338} Comments received mainly stated that the regulation might negatively impact job quality, as well as that there will be geographically localized effects, even if national level net impacts are minimal. We acknowledge the possibility of geographically localized effects, and that there may be job quality impacts associated with this rule, especially in the short term. We do not, however, have data to estimate current or future job quality. As described throughout section 19.6 of the RTC, we note that there are ongoing actions by the Departments of Energy (DOE) and Labor (DOL), as well as others, supporting green jobs, including the Office of Energy Jobs, which is particularly focused on jobs with high standards and the right to collective bargaining. In addition, we are unable to determine the future location of vehicle manufacturing and supporting industries beyond the public announcements made as of the publication of this rule. Also, we point out that even though vehicle manufacturing and battery manufacturing may create more localized employment effects, infrastructure work is, and will continue to be, a nation-wide effort. For more on the comments we received on the labor impacts of the proposed rule, and our responses, see section 19.6 of the RTC document.
^{1338} 88 FR 26074.
As the share of ZEVs in the HD market increases, there may also be effects on employment in associated ZEV industries, including battery production and BEV charging infrastructure industries as well as hydrogen refueling infrastructure industries. These impacts may occur in several ways, including through greater demand for batteries and therefore increased employment needs. In addition, increased demand for charging and hydrogen fueling infrastructure to support more ZEVs may lead to more private and public charging and fueling facilities being constructed, or to greater use of existing facilities, which can lead to increased maintenance needs for those facilities. For example, as described in RIA Chapter 2.10.3, we estimated the total number of EVSE ports that will be required to support the depot-charged BEVs in the technology packages developed to support the MY 2027-2032 standards. We find just under 500,000 EVSE ports will be needed across all six model years. This increased demand in EVSE will increase employment in this sector.
In the proposed rule, we requested comment on data and methods that could be used to estimate the effect of this action on the HD BEV vehicle charging infrastructure industry. We received comments stating that there will be shortage of qualified BEV technicians, as well as technicians qualified to repair and maintain infrastructure. We also received comments stating that there has already been significant job creation in response to demand for battery production, with the expectation that battery and charging infrastructure will create many more jobs. We note first that the vehicle market is moving toward increasing ZEV market share, with or without this rule. We also note that there are many potential pathways to comply with this rule, and regardless of the outcome, we project that ICE vehicles will remain a significant share of new vehicle sales through MY 2032, as well as remain the majority share of the fleet for many years after. The pace of ZEV uptake should provide ample opportunity for training programs to be implemented, especially if there is demand, or lack of supply, for qualified technicians. In addition, there are many labor and employment initiatives happening related to electric vehicles, including those related to battery production and supply chain, vehicle manufacturing and deployment, refueling infrastructure, maintenance and repair of electric vehicles and more. ^{1339} These programs include initiatives to promote production and availability and also to train, and retrain, workers in support of increasing high quality employment related to green energy.
^{1339} See the memo from the U.S. Department of Labor to Elizabeth Miller on Labor/Employment Initiatives in the Battery/Vehicle Electrification Space, located in the docket.
Because of the diversity of the HD vehicle market, we expect that entities from a wide range of transportation sectors will purchase vehicles subject to the emission standards. HD vehicles are typically commercial in nature, and typically provide an “intermediate good,” meaning that such vehicles are used to provide a commercial service (transporting goods, municipal service vehicles, etc.), rather than serving as final consumer goods themselves (as most light-duty vehicles do). As a result, the purchase price of a new HD vehicle likely impacts the price of the services provided by that vehicle. Operating costs and purchase incentives may also impact the price of services provided. If a change in upfront cost and/or operating costs, including purchase incentives (as might be available for a new ZEV), results in higher prices for the services provided by these vehicles compared to the same services provided by a pre-regulation vehicle, it may reduce demand for the services such vehicles provide. In turn, there may be less employment in the sectors providing such services. On the other hand, if there are savings that are passed on to consumers through lower prices for services provided, it may lead to an increase in demand for those services, and therefore may lead to an increase in employment in those sectors providing those services. We estimate that there are savings over the life of operating a ZEV relative to an ICE vehicle that may decrease downstream prices. We expect that the actual effects on demand for the services provided by these vehicles and related employment will depend on cost pass-through, as well as responsiveness of demand to changes in transportation cost, should such changes occur. ^{1340}
^{1340} Cost pass-through refers to the amount of increase in up-front cost incurred by the HD vehicle owner that is then passed on to their customers in the form of higher prices for services provided by the HD vehicle owner.
This action may also produce employment effects in other sectors, for example, in firms providing liquid fuel. While reduced liquid fuel consumption represents cost savings for purchasers of liquid fuel, it could also represent a loss in value of output for the petroleum refining industry, which could result in reduced employment in that sector. These impacts may also pass up the supply chain to, for example, pipeline construction, operation and maintenance, and domestic oil production. In this final rule, we estimate that the reduction in fuel consumption will be met by increasing net exports by half of the amount of reduced domestic demand for refined product, with the other half being met by reductions in U.S. refinery output. Though the reduced domestic output may lead to future closures or conversions of individual refineries, we are unable to estimate the future decisions of refineries to keep operating, shut down or convert away from fossil fuels because they depend on the economics of individual refineries, economic conditions of parent companies, long-term strategies for each company, and on the larger macro-economic conditions of both the U.S. and the global refinery market, and therefore we are unable to estimate the possible effect this rule will have on employment in the petroleum refining sector. However, because the petroleum refining industry is material-intensive and not labor intensive, and we estimate that only part of the reduction in liquid fuel consumption will be met by reduced refinery production in the U.S., see RIA Chapter 6.5, we expect that any employment effect due to reduced petroleum demand will be small. Commenters stated concerns that employment in the petroleum refining industry will fall because plants will close, while others more generally stated that oil worker jobs will be devastated. For our response to these comments, see section 19.6 of the RTC document.
This action could also provide some positive impacts on driver employment in the heavy-duty trucking industry. As discussed in section IV of this preamble, the reduction in fuel costs from purchasing a ZEV instead of an ICE vehicle will be expected to not only reduce operational costs for ZEV owners and operators compared to an ICE vehicle, but may also provide additional incentives to purchase a HD ZEV over a HD ICE vehicle. For example, the Clean Air Task Force and ZETA submitted comments stating the HD ZEVs are associated with increased driver satisfaction due to quieter operations, better visibility, a smoother ride, faster acceleration, less odor, and a smoother and safer experience when driving in high traffic or urban environments. The commenters state that these positive attributes have the possibility of decreasing truck driver shortages and increasing driver retention.
An additional factor to consider for employment impacts across all industries that might be affected by this rule under the potential compliance pathway, or by the increase in the share of HD ZEVs in the market, is that though more ZEVs are being introduced to the market regardless of this rule, the vehicles on the road will still continue to be dominated by HD ICE vehicles, and many HD ICE vehicles will continue to be sold. This gradual shift avoids abrupt changes and will reduce impacts in acceptance, infrastructure availability, employment, supply chain, and more.

F. Oil Imports and Electricity and Hydrogen Consumption
We project that the final standards will reduce not only GHG emissions but also liquid fuel consumption ( i.e., oil consumption) while simultaneously increasing electricity and hydrogen consumption. Reducing liquid fuel consumption is a significant means of reducing GHG emissions from the transportation sector. As discussed in section V and RIA Chapter 4, we used an updated version of EPA's MOVES model to estimate the impact of the final standards on heavy-duty vehicle emissions, fuel consumption, electricity consumption, and hydrogen consumption. In Chapter 6.5 of the RIA, we present fossil fuel—diesel, gasoline, CNG—consumption impacts. Table 6-1 in Chapter 6 of the RIA shows the estimated reduction in U.S. oil imports under the final standards relative to the reference case scenario. This final rule is projected to reduce U.S. oil imports by 3 billion barrels through 2055 (see Table 6-2 of the RIA). The oil import reductions are the result of reduced consumption ( i.e., reduced liquid fuel demand) of both diesel fuel and gasoline and our estimate that 94.8 percent of reduced liquid fuel demand results in reduced imports. ^{1341} RIA Table 6-2 also includes the projected increase in electricity and hydrogen consumption due to the final rule.
^{1341} The 94.8 percent import reduction factor is based upon revised throughput assumptions for U.S. refineries in response to a decline in product demand as a result of this final rule. See Chapter 7.3.4 of the RIA for how the 94.8 percent is calculated assuming the refiners maintain refinery throughput at 50 percent of the decline in product demand as a result of this rule by exporting refined products.

VII. Benefits of the Program
In this section, we describe three sets of monetized benefits for the program and the methodology we use to calculate those benefits: climate benefits related to GHG emissions reductions calculated using the social cost of GHGs, the health benefits related to reductions in non-GHG pollutant emissions, and energy security benefits.
EPA monetizes the benefits of the standards in part to better enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are benefits that we are currently unable to fully quantify. EPA's consistent practice has been to set standards to achieve improved air quality consistent with Clean Air Act (CAA) section 202 and not to rely on cost-benefit calculations, with their uncertainties and limitations, in identifying the appropriate standards. Nonetheless, as explained in section VIII of this preamble, our conclusion that the estimated benefits exceed the estimated costs of the program reinforces our view that the final standards represent an appropriate weighing of the statutory factors and other relevant considerations.

A. Climate Benefits
EPA estimates the climate benefits of GHG emissions reductions expected from the final rule using estimates of the social cost of greenhouse gases (SC-GHG) that reflect recent advances in the scientific literature on climate change and its economic impacts and incorporate recommendations made by the National Academies of Science, Engineering, and Medicine. ^{1342} EPA published and used these estimates in the RIA for Final Oil and Gas NSPS/EG Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review”, which was signed by the EPA Administrator on December 2, 2023. ^{1343} EPA solicited public comment on the methodology and use of these estimates in the RIA for the agency's December 2022 Oil and Gas NSPS/EG Supplemental Proposal and has conducted an external peer review of these estimates, as described further in this section. Section 7.1 of the RIA lays out the details of the updated SC-GHG used within this final rule.
^{1342} National Academies of Sciences, Engineering, and Medicine (National Academies). 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. National Academies Press.
^{1343} U.S. EPA. (2023f). Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review”: EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances. Washington, DC: U.S. EPA.
The SC-GHG is the monetary value of the net harm to society associated with a marginal increase in GHG emissions in a given year, or the net benefit of avoiding that increase. In principle, SC-GHG includes the value of all climate change impacts (both negative and positive), including (but not limited to) changes in net agricultural productivity, human health effects, property damage from increased flood risk and natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. The SC-GHG, therefore, reflects the societal value of reducing emissions of the gas in question by one metric ton and is the theoretically appropriate value to use in conducting benefit-cost analyses of policies that affect GHG emissions. In practice, data and modeling limitations restrain the ability of SC-GHG estimates to include all physical, ecological, and economic impacts of climate change, implicitly assigning a value of zero to the omitted climate damages. The estimates are, therefore, a partial accounting of climate change impacts and likely underestimate the marginal benefits of abatement.
Since 2008, the EPA has used estimates of the social cost of various greenhouse gases ( i.e., SC-CO 2 , SC-CH 4 , and SC-N 2 O), collectively referred to as the “social cost of greenhouse gases” (SC-GHG), in analyses of actions that affect GHG emissions. The values used by the EPA from 2009 to 2016, and since 2021—including in the proposal for this rulemaking—have been consistent with those developed and recommended by the IWG on the SC-GHG; and the values used from 2017 to 2020 were consistent with those required by Executive Order (E.O.) 13783, which disbanded the IWG. During 2015-2017, the National Academies conducted a comprehensive review of the SC-CO 2 and issued a final report in 2017 recommending specific criteria for future updates to the SC-CO 2 estimates, a modeling framework to satisfy the specified criteria, and both near-term updates and longer-term research needs pertaining to various components of the estimation process. ^{1344} The IWG was reconstituted in 2021 and E.O. 13990 directed it to develop a comprehensive update of its SC-GHG estimates, recommendations regarding areas of decision-making to which SC-GHG should be applied, and a standardized review and updating process to ensure that the recommended estimates continue to be based on the best available economics and science going forward.
^{1344} U.S. EPA. (2023f).
EPA is a member of the IWG and is participating in the IWG's work under E.O. 13990. As noted in previous EPA RIAs—including in the proposal RIA for this rulemaking, while that process continues, the EPA is continuously reviewing developments in the scientific literature on the SC-GHG, including more robust methodologies for estimating damages from emissions, and looking for opportunities to further improve SC-GHG estimation. ^{1345} In the December 2022 Oil and Gas Supplemental Proposal RIA, ^{1346} the Agency included a sensitivity analysis of the climate benefits of that rule using a new set of SC-GHG estimates that incorporates recent research addressing recommendations of the National Academies ^{1347} in addition to using the interim SC-GHG estimates presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990 ^{1348} that the IWG recommended for use until updated estimates that address the National Academies' recommendations are available. The EPA solicited public comment on the sensitivity analysis and the accompanying draft technical report, External Review Draft of Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances, which explains the methodology underlying the new set of estimates and was included as supplementary material to the RIA for the December 2022 Supplemental Oil and Gas Proposal. ^{1349} The response to comments document can be found in the docket for that action. ^{1350}
^{1345} EPA strives to base its analyses on the best available science and economics, consistent with its responsibilities, for example, under the Information Quality Act.
^{1346} U.S. EPA. (2023). Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review”: EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances. Washington, DC: U.S. EPA.
^{1347} U.S. EPA. (2023).
^{1348} Interagency Working Group on Social Cost of Carbon (IWG). 2021 (February). Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide: Interim Estimates under Executive Order 13990. United States Government.
^{1349} https://www.epa.gov/environmental-economics/scghg-tsd-peer-review .
^{1350} Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review”, EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances, Docket ID No. EPA-HQ-OAR-2021-0317, November 2023.
To ensure that the methodological updates adopted in the technical report are consistent with economic theory and reflect the latest science, the EPA also initiated an external peer review panel to conduct a high-quality review of the technical report (see 88 FR 29372 noting this peer review process was ongoing at the time of our proposal), completed in May 2023. The peer reviewers commended the agency on its development of the draft update, calling it a much-needed improvement in estimating the SC-GHG and a significant step towards addressing the National Academies' recommendations with defensible modeling choices based on current science. The peer reviewers provided numerous recommendations for refining the presentation and for future modeling improvements, especially with respect to climate change impacts and associated damages that are not currently included in the analysis. Additional discussion of omitted impacts and other updates were incorporated in the technical report to address peer reviewer recommendations. Complete information about the external peer review, including the peer reviewer selection process, the final report with individual recommendations from peer reviewers, and the EPA's response to each recommendation is available on EPA's website. ^{1351}
^{1351} https://www.epa.gov/environmental-economics/scghg-tsd-peer-review .
Section 7.1 within the RIA provides an overview of the methodological updates incorporated into the SC-GHG estimates used in this final rule. A more detailed explanation of each input and the modeling process is provided in the final technical report, EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances. ^{1352}
^{1352} Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review”, EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances, Docket ID No. EPA-HQ-OAR-2021-0317, November 2023.
Commenters on our HD GHG Phase 3 NPRM brought up issues regarding baseline scenarios, climate modeling ( e.g., equilibrium climate sensitivity) and IAMS, claiming that they all used outdated assumptions. Other commenters suggested that EPA use lower discount rates as well as utilize the latest research and values from the December 2022 Supplemental Oil and Gas Proposal. EPA's decision to use the updated SC-GHG values from U.S. EPA (2023f) ^{1353} addresses several of the concerns voiced within the comments. See RTC section 20 for further detail on the comments received and EPA's responses. For a detailed description of the updated modeling, please see RIA section 7 for our final rule as well as the U.S. EPA (2023f). An appendix to Chapter 7 provides the climate benefits of the rule using the interim SC-GHG estimates.
^{1353} EPA. 2023f. “Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking: Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review.” EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances, Washington, DC. doi: Docket ID No. EPA-HQ-OAR-2021-0317.
Table VII-1 presents the annual, undiscounted monetized climate benefits of the net GHG emissions reductions (comprised of GHG emissions reductions from vehicles and refineries, and increased GHG emissions from EGUs; see preamble section V) associated with the final rule using the SC-GHG estimates presented in EPA (2023f) for the stream of years beginning with the first year of rule implementation, 2027, through 2055. Also shown are the present values (PV) and equivalent annualized values (AV) associated with each of the three SC-GHG values. For a thorough discussion of the SC-GHG methodology, limitations and uncertainties, see Chapter 7 of the RIA.

B. Non-GHG Health Benefits
This section discusses the economic benefits from reductions in adverse health impacts resulting from non-GHG emission reductions that can be expected to occur as a result of the final CO 2 emission standards. GHG emissions are predominantly the byproduct of fossil fuel combustion processes that also produce criteria and hazardous air pollutant emissions. The heavy-duty vehicles that are subject to the final CO 2 emission standards are also significant sources of mobile source air pollution such as directly-emitted PM, NO X , VOCs, CO, SO 2 and air toxics. Our projected emission reductions, monetized here, reflect the projected potential compliance pathway presented in preamble section II. However, as noted elsewhere, there are other means of achieving the standards, including pathways not utilizing ZEV technologies. Resulting emission reductions would differ from those presented here in such cases (EPA expects that different manufacturers will choose different compliance pathways). Under the modeled potential compliance pathway, zero-emission technologies will also affect emissions from upstream sources that occur during, for example, electricity generation and from the refining and distribution of liquid fuel (see section V of this preamble). This final rule's benefits analysis includes added emissions due to increased electricity generation and emissions reductions from reduced petroleum refining.
Changes in ambient concentrations of ozone, PM 2.5 , and air toxics that will result from the final CO 2 emission standards under the modeled pathway are expected to affect human health by reducing premature deaths and other serious human health effects, and they are also expected to result in other important improvements in public health and welfare (see section VI of this preamble). Children, especially, benefit from reduced exposures to criteria and toxic pollutants because they tend to be more sensitive to the effects of these respiratory pollutants. Ozone and particulate matter have been associated with increased incidence of asthma and other respiratory effects in children, and particulate matter has been associated with a decrease in lung maturation.
When feasible, EPA conducts full-scale photochemical air quality modeling to demonstrate how its national mobile source regulatory actions affect ambient concentrations of regional pollutants throughout the United States. The estimation of the human health impacts of a regulatory action requires national-scale photochemical air quality modeling to conduct a full-scale assessment of PM 2.5- and ozone-related health benefits. Air quality modeling and associated analyses are not available for this rule.
For the analysis of the final CO 2 emission standards (and the analysis of the alternative in section IX), we instead use a reduced-form “benefit-per-ton” (BPT) approach to estimate the monetized PM 2.5 -related health benefits of this final rule. The BPT approach estimates the monetized economic value of PM 2.5 -related emission impacts (such as direct PM, NO X , and SO 2 ) due to implementation of the final program. Similar to the SC-GHG approach for monetizing reductions in GHGs, the BPT approach estimates monetized health benefits of avoiding one ton of PM 2.5 -related emissions from a particular source sector. The value of health benefits from reductions or increases in PM 2.5 emissions associated with this final rule was estimated by multiplying PM 2.5 -related BPT values by the corresponding annual reduction in tons of directly-emitted PM 2.5 and PM 2.5 precursor emissions (NO X and SO 2 ). As explained in Chapter 7.2 in the RIA, the PM 2.5 BPT values represent the monetized value of human health benefits, including reductions in both premature mortality and nonfatal illnesses.
The mobile sector BPT estimates used in this final rule were published in 2019 but have been updated to be consistent with the health benefits Technical Support Document (Benefits TSD) that accompanied the 2023 p.m. NAAQS Proposal. 1354 1355 1356 1357 The Benefits TSD details the approach used to estimate the PM 2.5 -related benefits reflected in these BPTs. The EGU and Refinery BPT estimates used in this final rule were also recently updated to be consistent with the Benefits TSD. ^{1358} For more detailed information about the benefits analysis conducted for this final rule, including the BPT unit values used in this analysis, please refer to Chapter 7 of the RIA.
^{1354} Wolfe, P.; Davidson, K.; Fulcher, C.; Fann, N.; Zawacki, M.; Baker, K. R. 2019. Monetized Health Benefits Attributable to Mobile Source Emission Reductions across the United States in 2025. Sci. Total Environ. 650, 2490-2498. Available at: https://doi.org/10.1016/J.SCITOTENV.2018.09.273 .
^{1355} U.S. Environmental Protection Agency (U.S. EPA). 2023. PM NAAQS Reconsideration Proposal RIA. EPA-HQ-OAR-2019-0587.
^{1356} U.S. Environmental Protection Agency (U.S. EPA). 2023. Estimating PM 2.5 - and Ozone-Attributable Health Benefits. Technical Support Document (TSD) for the PM NAAQS Reconsideration Proposal RIA. EPA-HQ-OAR-2019-0587.
^{1357} Note that the Final PM NAAQS Reconsideration RIA, released in February 2024, based its benefits analysis on the same Benefits TSD that accompanied the PM NAAQS Reconsideration proposal.
^{1358} U.S. Environmental Protection Agency (U.S. EPA). 2023. Technical Support Document: Estimating the Benefit per Ton of Reducing Directly-Emitted PM 2.5 , PM 2.5 Precursors and Ozone Precursors from 21 Sectors.
A chief limitation to using PM 2.5 -related BPT values is that they do not reflect the health benefits associated with reducing ambient concentrations of ozone. The PM 2.5 -related BPT values also do not capture the health benefits associated with reductions in direct exposure to NO 2 and mobile source air toxics, nor do they account for improved ecosystem effects or visibility. The estimated benefits of this final rule would be larger if we were able to monetize these unquantified benefits at this time.
Table VII-2 presents the annual, undiscounted PM 2.5 -related health benefits estimated for the stream of years beginning with the first year of rule implementation, 2027, through calendar year 2055 for the final standards. Benefits are presented by source: Onroad heavy-duty vehicles and upstream sources (EGUs and refineries combined). Because premature mortality typically constitutes the vast majority of monetized benefits in a PM 2.5 benefits assessment, we present benefits based on risk estimates reported from two different long-term exposure studies using different cohorts to account for uncertainty in the benefits associated with avoiding PM-related premature deaths. 1359 1360 Although annual benefits presented in the table are not discounted for the purposes of present value or annualized value calculations, annual benefits do reflect the use of 3-percent and 7-percent discount rates to account for avoided health outcomes that are expected to accrue over more than a single year (the “cessation lag” between the change in PM exposures and the total realization of changes in health effects). Table VII-2 also displays the present and annualized values of estimated benefits that occur from 2027 to 2055, discounted using both 3-percent and 7-percent discount rates and reported in 2022$. We estimate that the annualized value of the benefits of the final program is $120 to $220 million at a 3-percent discount rate and −$9.1 to −$32 million at a 7-percent discount rate (2022$). Depending on the discount rate used, the annualized value of the stream of PM 2.5 health benefits may either be positive or negative.
^{1359} Wu, X, Braun, D, Schwartz, J, Kioumourtzoglou, M and Dominici, F (2020). Evaluating the impact of long-term exposure to fine particulate matter on mortality among the elderly. Science advances 6(29): eaba5692.
^{1360} Pope III, CA, Lefler, JS, Ezzati, M, Higbee, JD, Marshall, JD, Kim, S-Y, Bechle, M, Gilliat, KS, Vernon, SE and Robinson, AL (2019). Mortality risk and fine particulate air pollution in a large, representative cohort of US adults. Environmental health perspectives 127(7): 077007.
We use a constant 3-percent and 7-percent discount rate to calculate present and annualized values in Table VII-2, consistent with current applicable OMB Circular No. A-4 guidance. For the purposes of presenting total net benefits (see preamble section VIII), we also use a constant 2-percent discount rate to calculate present and annualized values. We note that we do not currently have BPT estimates that use a 2-percent discount rate to account for cessation lag. If we apply a constant 2-percent discount rate to the stream of annual benefits based on the 3-percent cessation lag BPT, the annualized value of total PM 2.5 -related benefits would be $160 to $300 million.
We believe the non-GHG pollutant benefits presented here are our best estimate of benefits absent air quality modeling, and we have confidence that the BPT approach provides a reasonable estimate of the monetized PM 2.5 -related health benefits associated with this rulemaking. Please refer to RIA Chapter 7 for more information on the uncertainty associated with the benefits presented here.

C. Energy Security
The final CO 2 emission standards are designed to require reductions in GHG emissions from HD vehicles in the MYs 2027-2032 and beyond timeframe and, thereby, are expected to reduce oil consumption. Our modeled potential compliance pathway projects a mix of ZEV technologies and ICE vehicle technologies in compliant fleets. Our analysis is based on this modeled potential compliance pathway but, as noted, many other potential pathways to compliance exist, and analytic results would differ from those presented here in such cases. Under our modeled compliance pathway, the standards will be met through a combination of zero-emission and ICE vehicle technologies, which will, in turn, reduce the demand for oil and enable the U.S. to reduce its petroleum imports. A reduction of U.S. petroleum imports reduces both financial and strategic risks caused by potential sudden disruptions in the supply of imported petroleum to the United States, thus increasing U.S. energy security.
Energy security is broadly defined as the uninterrupted availability of energy sources at affordable prices. ^{1361} Energy independence and energy security are distinct but related concepts. The goal of U.S. energy independence is the elimination of all U.S. imports of petroleum and other foreign sources of energy, but more broadly, it is the elimination of the U.S.'s sensitivity to variations in the price and supply of foreign sources of energy. ^{1362} See Chapter 7 of the RIA for a more detailed assessment of energy security and energy independence impacts of this final rule and section II.D.2 for a discussion on battery critical minerals and supply.
^{1361} International Energy Agency. “Energy security: Ensuring the uninterrupted availability of energy sources at an affordable price”. Last updated December 2, 2019.
^{1362} Greene, D. 2010. Measuring energy security: Can the United States achieve oil independence? Energy Policy 38, pp. 1614-1621.
In order to understand the energy security implications of reducing U.S. net oil imports, EPA has worked with Oak Ridge National Laboratory (ORNL), which has developed approaches for evaluating the social costs and energy security implications of oil use. When conducting this analysis, ORNL estimates the risk of reductions in U.S. economic output and disruption to the U.S. economy caused by sudden disruptions in world oil supply and associated price shocks ( i.e., labeled the avoided macroeconomic disruption/adjustment costs). These risks are quantified as “macroeconomic oil security premiums,” i.e., the extra costs of oil use besides its market price.
Two commenters claimed that the proposed rule would improve the U.S.'s energy security position by increasing the wider use of electric HD vehicles. We agree with these commenters that the final rule will lower the risks to the U.S. economy of oil supply disruptions; our projected potential compliance pathway for the final standards supports that U.S. oil consumption and U.S. oil imports are reduced ( e.g., with the utilization of HD vehicle technologies including ZEV technologies) as a result of this final rule. On the other hand, several commenters suggested that EPA is undermining U.S. energy security by promoting electric HD vehicles in this proposed rule. Mandating a specific technology such as electric vehicles stifles innovation and progress, according to these commenters. We respond to these comments in detail in section 22 of the RTC but note here that the commenters' characterization of the rule as mandating ZEV technology is not correct. While the potential compliance pathway that supports the feasibility of the final standards includes ZEV technologies in its mix of HD vehicle technologies, manufacturers can choose any compliance pathway most suitable to them and alternative compliance pathways exist, including those not involving ZEV technologies (see section II.F.6 of this preamble for one example). EPA thus believes that the final rule maintains the flexible structure created and followed in the previous HD vehicle GHG emission standards rules, which is effectively designed to reflect the diverse nature of the heavy-duty vehicle industry.
One commenter asserted that the proposed rule does not address the U.S. energy security impacts of the greater use of natural gas in the U.S. electricity sector stemming from the wider use of electric HD vehicles as a result of this rule. We do not agree that this final rule will result in energy security issues stemming from the wider use of natural gas. We respond to this comment in section 22 of the RTC document.
One commenter suggested that the energy security methodology developed by ORNL used in the proposed rule is outdated and no longer applicable to the current structure of global oil markets. EPA and ORNL have worked together to revise the macroeconomic oil security premiums based upon the recent energy security literature. Also, for this final rule, EPA is using macroeconomic oil security premiums estimated using ORNL's methodology which incorporates updated oil price projections and energy market and economic trends from the U.S. Department of Energy's Energy Information Administration's (EIA) most recent Annual Energy Outlook (AEO) 2023. Therefore, EPA believes that the macroeconomic oil security premiums used in this final rulemaking are reasonable. See section 22 of the RTC document for more discussion on this topic. We do not consider military cost impacts as a result of reductions in U.S. oil imports from this final rule due to methodological issues in quantifying these impacts.
To calculate the oil security benefits of this final rule, EPA is using the ORNL macroeconomic oil security premium methodology with (1) estimated oil savings calculated by EPA, and (2) an oil import reduction factor of 94.8 percent, which estimates how much U.S. oil net imports are reduced from projected changes in U.S. oil consumption. Estimated oil savings are discussed in detail in RIA Chapter 6.5. The oil import reduction factor is based on AEO data and is discussed in detail in RIA Chapter 7.3. Based upon consideration of comments EPA received on the proposal, EPA is updating the oil import reduction factor to be consistent with revised estimates that U.S. refineries will operate at higher production levels than EPA estimated in the proposed rule. See Chapter 4 of the RIA and section 13 of the RTC document for more discussion of how EPA is updating its refinery throughput assumptions and, in turn, air quality impacts from refinery emissions, as a result of this rule. See Chapter 7 of the RIA and section 22 of the RTC document for EPA's discussion of how EPA is updating the oil import reduction factor to be consistent with new estimates of refinery throughput for this final rule. In Table VII-3, EPA presents the macroeconomic oil security premiums and the energy security benefits for the final HD GHG Phase 3 vehicle standards for the years from 2027-2055.
Two commenters claimed that since the proposed rule promotes the wider use of electric vehicles, it limits the potential for renewable fuels ( i.e., biofuels) to create energy security benefits. One commenter suggested that proposed rule would make it more difficult to meet the renewable fuel mandates of EPA's Renewable Fuel Standard (RFS) program. EPA agrees with the commenters that the increased use of renewable fuels in the U.S. transportation sector will improve the U.S.'s energy security and energy independence position but disagrees that this rule is at odds with the RFS program. On June 21st, 2023, EPA announced a final rule (RFS Set Rule) to establish renewable fuel volume requirements and associated percentage standards for cellulosic biofuel, biomass-based diesel, advanced biofuels, and total renewable fuel for the 2023-2025 timeframe. ^{1363} The recently finalized RFS Set Rule and this final rule are complementary in achieving GHG reductions in the U.S. transportation sector. We respond to these comments in more detail in section 22 of the RTC document.
^{1363} Renewable Fuel Standard (RFS) Program: Standards for 2023-2025 and Other Changes. 88 FR 44468, July 12, 2023.
Numerous commenters suggested that EPA ignored the impacts on U.S.'s energy and national security in the proposed rule of an unfavorable transition from reliable, abundant, domestically-sourced fuels to a complex supply chain reliant on foreign-sourced critical minerals. For this final rule, EPA distinguishes between energy security, mineral/metal security and security issues associated with the importation of critical minerals, ZEV batteries and component parts ( i.e., ZEV supply chain issues). We address energy security issues involving U.S. oil consumption and oil imports associated with this final rule in Chapter 7 of the RIA and section 22 of the RTC. Comments associated with projected wider use of HD ZEV technologies' impacts on the U.S.'s mineral/metal security and security issues associated with the importation of HD ZEV batteries and their component parts ( i.e., ZEV technologies supply chain issues) are addressed in section II.D.2 of this preamble and in section 17 of the RTC document.

VIII. Comparison of Benefits and Costs
This section compares the estimated range of benefits associated with reductions of GHGs, monetized health benefits from reductions in PM 2.5 , energy security benefits, fuel savings, and vehicle-related operating savings to total costs associated with the modeled compliance pathway for the final rule and for the alternative. Estimated costs are detailed and presented in section IV of this preamble. Those costs include costs for both the new technology in our modeled potential compliance pathway's technology packages and the operating costs associated with that new technology. Importantly, as detailed in section IV of this preamble, the vehicle costs presented here exclude the IRA battery tax credit, the vehicle tax credit and the EVSE tax credit while the fuel savings exclude fuel taxes. As such, as presented in this section, these costs, along with other operating costs, represent the social costs and/or savings associated with the final standards. Benefits from the reduction of GHG emissions and criteria pollutant emissions, and energy security benefits associated with reductions of imported oil, are presented in section VII.

A. Methods
EPA presents three different benefit-cost comparisons for the final rule and for the alternative:
1. A future-year snapshot comparison of annual benefits and costs in the year 2055, chosen to approximate the annual costs and benefits that will occur in a year when most of the regulated fleet will consist of HD vehicles subject to the HD GHG Phase 3 standards due to fleet turnover. Benefits, costs, and net benefits are presented in year 2022 dollars and are not discounted.
2. The present value (PV) of the stream of benefits, costs, and net benefits calculated for the analytical time horizon of 2027 through 2055, discounted back to the first year of implementation of the final rule (2027) using 2-percent, 3-percent and 7-percent discount rates, and presented in year 2022 dollars. ^{1364} Note that year-over-year costs are presented in preamble section IV and year-over-year benefits may be found in preamble section VII.
^{1364} Monetized climate benefits are presented under a 2 percent near-term Ramsey discount rate, consistent with EPA's updated estimates of the SC-GHG. The 2003 version of OMB's Circular A-4 had generally recommended 3 percent and 7 percent as default discount rates for costs and benefits, though as part of the Interagency Working Group on the Social Cost of Greenhouse Gases, OMB had also long recognized that climate effects should be discounted only at appropriate consumption-based discount rates. While we were conducting the analysis for this rule, OMB finalized an update to Circular A-4, in which it recommended the general application of a 2 percent discount rate to costs and benefits (subject to regular updates), as well as the consideration of the shadow price of capital when costs or benefits are likely to accrue to capital (OMB 2023). Because the SC-GHG estimates reflect net climate change damages in terms of reduced consumption (or monetary consumption equivalents), the use of the social rate of return on capital (7 percent under OMB Circular A-4 (2003)) to discount damages estimated in terms of reduced consumption would inappropriately underestimate the impacts of climate change for the purposes of estimating the SC-GHG.
3. The equivalent annualized value (AV) of benefits, costs, and net benefits representing a flow of constant annual values that, had they occurred in each year from 2027 through 2055, will yield an equivalent present value to those estimated in method 2 (using a 2-percent, 3-percent or 7-percent discount rate). Each AV represents a typical benefit, cost, or net benefit for each year of the analysis and is presented in year 2022 dollars.

B. Results
Table VIII-1 shows the undiscounted annual monetized vehicle-related projected technology packages RPE costs of the final rule and the alternative in calendar year 2055. The table also shows the PV and AV of those costs for the calendar years 2027 through 2055 using 2-percent, 3-percent and 7-percent discount rates. The table includes an estimate of the projected vehicle technology packages RPE costs and corresponding costs associated with EVSE.
Note that all costs, savings, and benefits estimates presented in the tables that follow are rounded to two significant figures; numbers may not sum due to independent rounding.
Table VIII-2 and Table VIII-3 show the undiscounted annual monetized vehicle-related operating savings of the final rule and the alternative, respectively, in calendar year 2055. The table also shows the PV and AV of those savings for calendar years 2027 through 2055 using 2-percent, 3-percent and 7-percent discount rates. The savings in diesel exhaust fluid (DEF) consumption arise in the modeled potential compliance pathway's technology packages from the decrease in diesel engine-equipped vehicles which require DEF to maintain compliance with NOx emission standards. The maintenance and repair savings are due again to the HD vehicle technologies utilized in the modeled potential compliance pathway; BEVs and FCEVs are projected to ultimately require 71 percent and 75 percent, respectively, of the maintenance and repair costs required of HD vehicles equipped with internal combustion engines, as discussed in section II.
Table VIII-4 shows the undiscounted annual monetized energy security benefits of the final rule and the alternative in calendar year 2055. The table also shows the PV and AV of those benefits for calendar years 2027 through 2055 using 2-percent, 3-percent and 7-percent discount rates.
Table VIII-5 shows the climate benefits of reduced GHG emissions, using the SC-GHG estimates presented in the EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances (EPA 2023). ^{1365} The details are discussed in RIA Chapter 7. These climate benefits include benefits associated with changes to HD vehicle GHGs and both EGU and refinery GHG emissions, but do not include any impacts associated with the extraction or transportation of fuels for either EGUs or refineries.
^{1365} For more information about the development of these estimates, see www.epa.gov/environmental-economics/scghg .
Table VIII-6 shows the undiscounted annual monetized PM 2.5 -related health benefits of the final rule and the alternative in calendar year 2055. The table also shows the PV and AV of those benefits for calendar years 2027 through 2055 using a 2-percent, 3-percent and 7-percent discount rate. The benefits in
Table VIII-6 reflect the two premature mortality estimates derived from the Medicare study (Wu et al., 2020) and the NHIS study (Pope et al., 2019). 1366 1367 The monetized criteria pollutant health benefits include reductions in PM 2.5 -related emissions from HD vehicles. Monetized upstream health impacts associated with the standards also include benefits associated with reduced PM 2.5 -related emissions from refineries and health disbenefits associated with increased PM 2.5 -related emissions from EGUs. Negative monetized values are associated with health disbenefits related to increases in estimated emissions from EGUs. Depending on the discount rate used, the present and annualized value of the stream of PM 2.5 -related benefits may either be positive or negative.
^{1366} Wu, X, Braun, D, Schwartz, J, Kioumourtzoglou, M and Dominici, F (2020). Evaluating the impact of long-term exposure to fine particulate matter on mortality among the elderly. Science advances 6(29): eaba5692.
^{1367} Pope III, CA, Lefler, JS, Ezzati, M, Higbee, JD, Marshall, JD, Kim, S-Y, Bechle, M, Gilliat, KS, Vernon, SE and Robinson, AL (2019). Mortality risk and fine particulate air pollution in a large, representative cohort of US adults. Environmental health perspectives 127(7): 077007.
Table VIII-7 shows the undiscounted annual total benefits of the final rule and the alternative in calendar year 2055, as well as the PV and AV of the total benefits for calendar years 2027 through 2055. Total benefits are the sum of climate benefits, criteria pollutant benefits and energy security benefits. The present and annualized values of energy security benefits and PM 2.5 health impacts are discounted using either a 2-percent, 3-percent, or 7-percent constant discount rate (see Table VIII-4 and Table VIII-6, respectively). Climate benefits are based on reductions in GHG emissions and are calculated using three different SC-GHG estimates that assume either a 1.5-percent, 2.0-percent, or 2.5-percent near-term Ramsey discount rate (see Table VIII-5). For presentational purposes in Table VIII-7, we use the climate benefits associated with the SC-GHG estimates at the 2-percent near-term Ramsey discount rate for the total benefits calculation. The benefits include those associated with changes to HD vehicle GHGs and both EGU and refinery GHG emissions, but do not include any impacts associated with the extraction or transportation of fuels for either EGUs or refineries. This likely underestimates the refinery-related emission reductions projected in the rule but likely also underestimates EGU-related emission increases in the rule.
We summarize the vehicle costs, operational savings, and benefits of the final rule, as shown in Table VIII-8. Table VIII-8 presents the final rule's costs from Table VIII-1, operating savings from Table VIII-2, and total benefits from Table VIII-7 (comprised of benefits presented in Tables VIII-4 through VIII-6) in a single table. We summarize the vehicle costs, operational savings, and benefits of the alternative in Table VIII-9. We remind readers that, in the NPRM, we used the interim SC-GHG values, while in this final rule we are using the updated SC-GHG values (see section VII.A of this preamble and Chapter 7.1 of the final RIA). We include the 2 percent discount rate here for consistency with the 2 percent near-term Ramsey discount rate used in the updated SC-GHG values.
We have also estimated the total transfers associated with the final standards and the alternative, as shown in Table VIII-10 and Table VIII-11, respectively. The transfers consist of the IRA battery tax credit, vehicle tax credit, EVSE tax credit, fuel taxes, Federal excise taxes and state sales taxes, and annual vehicle registration fees on all ZEVs. None of these are included in the prior tables ( i.e., Table VIII-1 through Table VIII-9) in this section's comparison of benefits and costs. Note that the transfers are presented from the perspective of purchasers, so positive values represent transfers to purchasers.

IX. Analysis of Alternative CO2 Emission Standards
As discussed throughout this preamble, in developing this final rule, EPA considered a regulatory alternative that would establish less stringent CO 2 emission standards and, thus, would result in fewer GHG emission reductions than the CO 2 emission standards we are finalizing. This section presents estimates of technology costs, CO 2 emission reductions, fuel savings, and other impacts associated with the alternative.

A. Comparison of Final Standards and Alternative
The alternative represents a slower phase-in option for program implementation, which represents differences in timing, costs, and benefits of a HD vehicle CO 2 emissions program. Specifically, the alternative has both a less aggressive phase-in of CO 2 emissions standards from MYs 2027 through 2031 and a less stringent standard for MYs 2032 and beyond. The alternative was modeled using the same methodologies used to model the final rule, as described in Chapters 2 and 4 of the RIA.
EPA developed and considered an alternative with a more gradual phase-in of CO 2 emission standards for MYs 2027 through MY 2031 and a less stringent final standard in MY 2032, as discussed in section II.H. The slower phase-in alternative standards, presented in Table IX-1 and Table IX-2, are calculated using the same method as the final standards, as described in preamble section II.F. The ZEV technologies adoption rates in the potential technology packages that would comply with these levels of stringency for MYs 2027 through 2032 under the slower phase-in alternative are shown in Table IX-1. The ZEV technologies adoption rates in the potential technology packages that would comply with the slower phase-in alternative standards by regulatory subcategory and by MY are shown in RIA Chapter 2.9.5.
Based on our current analysis for each of the vocational vehicle and tractor subcategories, our assessment is that feasible and appropriate emission standards that provide for greater CO 2 emission reductions than through the slower phase-in alternative and at reasonable cost are available. As explained in preamble section II.H, we are not adopting this alternative set of standards in this final rule because, as already described, our assessment is that feasible and appropriate standards are available that provide for greater emission reductions than provided under this alternative, do so at reasonable cost, and provide sufficient lead time.

B. Emission Inventory Comparison of Final Rule and Slower Phase-In Alternative
Both the final standards and the alternative were modeled by EPA in an updated version of EPA's Motor Vehicle Emission Simulator (MOVES) model, MOVES4.R3 by increasing ZEV adoption in HD vehicles, which means we model the alternative's possible compliance pathway as utilizing more HD ICE vehicles ^{1368} than those modeled for the final standards' potential compliance pathway. In general, this means the alternative has both lower downstream emission reductions, lower refinery emissions reductions, and lower upstream EGU emission increases when compared to the final standards. Chapter 4.7 of the RIA contains more discussion on the emission impacts of the alternative.
^{1368} In this scenario, HD ICE emission rates reflect CO 2 emission improvements projected in previously promulgated standards, notably HD GHG Phase 2.

1. Downstream Emission Comparison
Our estimates of the downstream emission reductions of GHGs that would result from the alternative relative to the reference case are presented in Table IX-3 for calendar years 2035, 2045, and 2055. Total GHG emissions, or CO 2 equivalent (CO 2 e), are calculated by summing all GHG emissions multiplied by their 100-year Global Warming Potentials (GWP). ^{1369}
^{1369} IPCC, 2014: Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Core Writing Team, R.K. Pachauri and L.A. Meyer (eds.)]. Available online: https://www.ipcc.ch/site/assets/uploads/2018/02/SYR_AR5_FINAL_full.pdf .
Our estimated GHG emission reductions for the alternative are lower than for the final standards (see section V of this preamble). In 2055, we estimate that the alternative would reduce emissions of CO 2 by 6 percent (the final standards estimate is 20 percent), methane by 3 percent (the final standards estimate is 12 percent), and N 2 O by 6 percent (the final standards estimate is 20 percent). The resulting total GHG reduction, in CO 2 e, is 6 percent for the alternative versus 20 percent for the final standards.
For both the final standards and the alternative, we modeled potential compliance pathways based on an increase in the use of zero-emission vehicle technologies. Therefore, we also project that downstream emission reductions of criteria pollutants and air toxics would result from the alternative, relative to the reference case, as presented in Table IX-4.
Once again, the emission reductions in criteria pollutants and air toxics that would result from the alternative are smaller than those estimated to result from the final standards. For example, in 2055, we estimate the alternative would reduce NO X emissions by 7 percent, PM 2.5 emissions by 1 percent, and VOC emissions by 4 percent. This is compared to the final standards reductions of NO X by 20 percent, PM 2.5 by 5 percent, and VOC by 20 percent for the final standards. Reductions in emissions for air toxics from the alternative range from 1 percent for benzene (the final standards estimate is 25 percent) to 3 percent for formaldehyde (the final standards estimate is 15 percent).

2. Upstream Emission Comparison
Our estimates of the additional GHG emissions from EGUs due to the alternative, relative to the reference case, are presented in Table IX-5 for calendar years 2035, 2045, and 2055, in million metric tons (MMT). Our estimates for additional criteria pollutant emissions are presented in Table IX-6.
Because the potential compliance pathway for the alternative assumes lower ZEV adoption rates, we project smaller increases in emissions from EGUs than the final standards. In 2055, we estimate the alternative would increase EGU emissions of CO 2 by 4.4 million metric tons (compared to 12.9 million metric tons from the final standards), with similar trends for all other pollutants. The EGU impacts for all pollutants decrease over time because of projected changes in the power generation mix.
Table IX-7 presents the estimated impact of the alternative on GHG emissions from refineries and Table IX-8 presents the estimated impact of the alternative on criteria pollutant emissions from refineries, both relative to the reference case.
We project smaller reductions in refinery emissions for the alternative than for the final standards (see section V of this preamble), consistent with our projected impacts for downstream emissions. We project a reduction of 147,787 metric tons of CO 2 for the alternative versus 690,477 metric tons for the final standards.

3. Comparison of Net Emissions Impacts
Table IX-9 shows a summary of our modeled downstream, upstream, and net GHG emission impacts of the alternative relative to the reference case ( i.e., the emissions inventory without the final standards), in million metric tons, for calendar years 2035, 2045, and 2055. Table IX-10 contains a summary of the modeled net impacts of the alternative on criteria pollutant emissions.
In 2055, we estimate the alternative would result in a net decrease of 17 million metric tons of GHG emissions, compared to 61 million metric tons for the final standards. Like the final standards, we project net decreases in emissions of NOx, VOC, and SO 2 in 2055 but a net increase in PM 2.5 emissions. Consistent with other emissions impacts trends discussed for the alternative, the magnitude of these net impacts is smaller for the alternative than for the final standards.

4. Comparison of Cumulative GHG Impacts
The warming impacts of GHGs are cumulative. Table V-13, Table V-14, and Table V-15 present the cumulative GHG impacts that we model would result from both the final standards and the alternative from 2027 through 2055 for downstream emissions, EGU emissions, and refinery emissions, respectively, relative to the reference case.
Overall, we estimate the alternative would reduce net GHG emissions by 321 million metric tons between 2027 and 2055, relative to the reference case, as is presented in Table V-16. This is less than one third the total reduction from the final standards, which is more than 1 billion metric tons.

C. Program Costs Comparison of the Final Rule and Alternative
Using the cost elements outlined in sections IV.B, IV.C, and IV.D, we have estimated the costs associated with the final rule and alternative relative to the reference case, as shown in Table IX-15. Costs are presented in more detail in Chapter 3 of the RIA. As noted earlier, costs are presented in 2022$ in undiscounted annual values along with net present values and annualized values at 2, 3, and 7 percent discount rates with values discounted to the 2027 calendar year.
As shown in Table IX-15, our analysis demonstrates that the final standards will have the lowest cost compared to the alternative and reference cases for all net present and annualized values at all three discount rates.

D. Benefits

1. Climate Benefits
Our estimates of the climate benefits from the GHG emissions reductions associated with the alternative are similar to those discussed for the final rule in section VII of this preamble. Table IX-16 presents the annual, undiscounted monetized climate benefits of reduced GHG emissions using social cost of GHG (SC-GHG) values presented in the EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances ^{1370} for the years beginning with the first year of rule implementation, 2027, through 2055 for the alternative and final standards. Also shown are the present values and equivalent annualized values associated with each of the SC-GHG values. For more detailed information about the climate benefits analysis conducted for the final standards and alternative, please refer to section 7.1 of the RIA. See sections V and IX.B of this preamble for our analysis of GHG emission impacts of the final standards and alternative, respectively.
^{1370} EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances.

2. Criteria Pollutant Reductions
Table IX-17 presents the total annual, undiscounted PM 2.5 -related health benefits estimated for the stream of years beginning with the first year of rule implementation, 2027, through calendar year 2055 for the final CO 2 emission standards and alternative. The range of benefits in Table IX-17 reflects the range of premature mortality estimates based on risk estimates reported from two different long-term exposure studies using different cohorts to account for uncertainty in the benefits associated with avoiding PM-related premature deaths. 1371 1372 Although annual benefits presented in the table are not discounted for the purposes of present value or annualized value calculations, annual benefits do reflect the use of 3 percent and 7 percent discount rates to account for avoided health outcomes that are expected to accrue over more than a single year (the “cessation lag” between the change in PM exposures and the total realization of changes in health effects). The table also displays the present and annualized value of estimated benefits that occur from 2027 to 2055, discounted using both 3 percent and 7 percent discount rates and reported in 2022$.
^{1371} Wu, X, Braun, D, Schwartz, J, Kioumourtzoglou, M and Dominici, F (2020). Evaluating the impact of long-term exposure to fine particulate matter on mortality among the elderly. Science advances 6(29): eaba5692.
^{1372} Pope III, CA, Lefler, JS, Ezzati, M, Higbee, JD, Marshall, JD, Kim, S-Y, Bechle, M, Gilliat, KS, Vernon, SE and Robinson, AL (2019). Mortality risk and fine particulate air pollution in a large, representative cohort of US adults. Environmental health perspectives 127(7): 077007.
The PM 2.5 -related health benefits of a less stringent alternative program are −$3.0 to $2.1 million assuming a 3 percent discount rate and −$77 to −$36 million assuming a 7 percent discount rate (2022$). We use a constant 3 percent and 7-pecent discount rate to calculate present and annualized values in Table IX-17, consistent with current applicable OMB Circular No. A-4 guidance (2003). For the purposes of presenting total net benefits (see preamble section VIII), we also use a constant 2 percent discount rate to calculate present and annualized values. We note that we do not currently have BPT estimates that use a 2-percent discount rate to account for cessation lag. If we apply a constant 2 percent discount rate to the stream of annual benefits based on the 3 percent cessation lag BPT, annualized benefits would be $15 to $22 million. Depending on the discount rate used, the present and annualized value of the stream of PM 2.5 health benefits may either be positive or negative.
For more detailed information about the benefits analysis conducted for the final standards and alternative, please refer to Chapter 7 of the RIA.

3. Energy Security
In Table IX-18, EPA presents the macroeconomic oil security premiums and the energy security benefits for the final standards and alternative for the years 2027 through 2055. The oil security premiums and the energy security benefits for the final CO 2 emission standards are further discussed in section VII.

E. How do the final standards and alternative compare in overall benefits and costs?
Table IX-19 shows the estimated net benefits for the final standards and alternative relative to the reference case, at 2, 3 and 7 percent discount rates, respectively. Preamble section VIII and Chapter 8 of the RIA presents more detailed results. These estimated net benefits are the sum of benefits and operating savings minus vehicle costs.
As noted in preamble section VIII's discussion of costs and benefits for the final standards, EPA's consistent practice has been to set standards to achieve improved air quality consistent with CAA section 202 and not to rely on cost-benefit calculations, with their uncertainties and limitations, in identifying the appropriate standards. Nonetheless, the significantly greater benefits for the final standards relative to the alternative provide reinforcing support for EPA's decision to adopt the final standards in lieu of the alternative. For example, in 2055, the final rule would result in net benefits of $32 billion dollars (2022$), which is significantly greater than the alternative's net benefits of $8.3 billion.

X. Statutory and Executive Order Reviews
Additional information about these statutes and Executive orders can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders .

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 14094: Modernizing Regulatory Review
This action is a “significant regulatory action,” as defined under section 3(f)(1) of Executive Order 12866, as amended by Executive Order 14094. Accordingly, EPA submitted this action to the Office of Management and Budget (OMB) for Executive Order 12866 review. Documentation of any changes made in response to the Executive Order 12866 review is available in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, the “Regulatory Impact Analysis—Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles: Phase 3—Final Rulemaking,” is available in the docket. ^{1373} The analyses contained in the RIA document are also summarized in sections II, IV, V, VI, VII, VIII, and IX of this preamble.
^{1373} U.S. EPA. Regulatory Impact Analysis—Greenhouse Gas Emissions Standards for Heavy-Duty Vehicles: Phase 3. EPA-420-R-24-006. March 2024.

B. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) that EPA prepared has been assigned EPA ICR Number 2734.02. You can find a copy of the Supporting Statement in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.
This rulemaking consists of targeted updates and new GHG emission standards for heavy-duty vehicles beginning with MY 2027. While there will be changes to the EV-CIS data system to reflect new standards, this will not affect manufacturer reporting. In addition, While EPA has committed to post-rule monitoring of the implementation of the heavy-duty vehicle GHG programs, that monitoring is expected to rely on manufacturer-submitted certification data and will not impose additional reporting requirements. As part of this monitoring program, EPA will continue to evaluate the data collection needs and will create a new ICR if we determine additional data is needed. Finally, the information collection activities for EPA's Phase 2 GHG program do not change as a result of this rule. While manufacturers are expected to experience a cost associated with reviewing the new requirements, they already submit the data that would be required for certification to the standards to EPA's certification system (under programmatic ICRs). There would be a change only to the specific data reported, not its reporting.
• Respondents/affected entities: Manufacturers of heavy-duty onroad vehicles.
• Respondent's obligation to respond: Regulated entities must respond to this collection if they wish to sell their products in the United States, as prescribed by CAA section 203(a). Participation in some programs is voluntary; but once a manufacturer has elected to participate, it must submit the required information.
• Estimated number of respondents: Approximately 77 heavy-duty vehicle manufacturers.
• Frequency of response: One-time burden associated with reviewing the new requirements for all manufacturers; for EV manufacturers, one-time burden associated with new battery health monitor provisions, warranty reporting requirements, and associated revisions to owners' manuals.
• Total estimated burden: 7,411 hours. Burden is defined at 5 CFR 1320.03(b).
• Total estimated cost: $1.622 million; includes an estimated $936,500 in maintenance and operational costs.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in Title 40 of the Code of Federal Regulations are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. As explained in this preamble, EPA is exempting small entities from the revisions to EPA's Phase 2 GHG standards for MY 2027 and the new GHG standards for MYs 2028 through 2032 and later. Small EV manufacturers are subject to new battery health monitor provisions and warranty provisions, which include making associated revisions to owners' manuals. There are 10 small companies that are affected by the requirements. The estimated burden is not expected to exceed 3 percent of annual revenue for any small entity, and is expected to be between 1 and 3 percent of annual revenue for only one company. We therefore conclude that this action will not have a significant economic impact on a substantial number of small entities within the regulated industries. More information concerning the small entities and our conclusion is presented in Chapter 9 of the RIA.

D. Unfunded Mandates Reform Act (UMRA)
This action contains no unfunded Federal mandate for State, local, or Tribal governments as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. This action imposes no enforceable duty on any State, local, or Tribal government. This action contains Federal mandates under UMRA that may result in annual expenditures of $100 million or more for the private sector. Accordingly, the costs and benefits associated with this action are discussed in sections IV, VII, and VIII of this preamble and in the RIA, which is in the docket for this rule.
This action is not subject to the requirements of UMRA section 203 because it contains no regulatory requirements that might significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism
The action we are finalizing for HD Phase 3 CO 2 emission standards and related regulations does not have federalism implications. The final HD Phase 3 CO 2 emission standards and related regulations will not have substantial direct effects on the states, on the relationship between the National Government and the states, or on the distribution of power and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments
This action does not have Tribal implications as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to this action. This action does not have substantial direct effects on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. However, EPA has engaged with Tribal stakeholders in the development of this rulemaking by holding a Tribal workshop, offering information sessions to Tribal organizations, and offering government-to-government consultation upon request.

G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks
This action is subject to Executive Order 13045 because it is a significant regulatory action under section 3(f)(1) of Executive Order 12866, and EPA believes that the environmental health risks or safety risks of the pollutants addressed by this action may have a disproportionate effect on children. The 2021 Policy on Children's Health also applies to this action. ^{1374} Accordingly, we have evaluated the environmental health or safety effects of air pollutants affected by the final rule on children. The results of this evaluation are described in section VI of the preamble and Chapter 5 of the RIA. The protection offered by these standards may be especially important for children because childhood represents a life stage associated with increased susceptibility to air pollutant-related health effects.
^{1374} U.S. Environmental Protection Agency (2021). 2021 Policy on Children's Health. Washington, DC. https://www.epa.gov/system/files/documents/2021-10/2021-policy-on-childrens-health.pdf .
GHG emissions contribute to climate change and the GHG emissions reductions described in section V of this preamble resulting from this rule will contribute to mitigation of climate change. The assessment literature cited in EPA's 2009 and 2016 Endangerment Findings concluded that certain populations and life stages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2016 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience. These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low-income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households. More detailed information on the impacts of climate change to human health and welfare is provided in section VI.A of this preamble.
Children make up a substantial fraction of the U.S. population, and often have unique factors that contribute to their increased risk of experiencing a health effect from exposures to ambient air pollutants because of their continuous growth and development. Children are more susceptible than adults to many air pollutants because they have (1) a developing respiratory system, (2) increased ventilation rates relative to body mass compared with adults, (3) an increased proportion of oral breathing, particularly in boys, relative to adults, and (4) behaviors that increase chances for exposure. Even before birth, the developing fetus may be exposed to air pollutants through the mother that affect development and permanently harm the individual when the mother is exposed.
In addition to reducing GHGs, this final rule will also reduce onroad emissions of criteria pollutants and air toxics. Section V of this preamble presents the estimated onroad emissions reductions from the rule. Certain motor vehicle emissions present greater risks to children. Early lifestages ( e.g., children) are thought to be more susceptible to tumor development than adults when exposed to carcinogenic chemicals that act through a mutagenic mode of action. ^{1375} Exposure at a young age to these carcinogens could lead to a higher risk of developing cancer later in life. Chapter 5.2.8 of the RIA describes a systematic review and meta-analysis conducted by the U.S. Centers for Disease Control and Prevention that reported a positive association between proximity to traffic and the risk of leukemia in children. Also, section VI.B of this preamble and Chapter 5 of the RIA discuss a number of childhood health outcomes associated with proximity to roadways, including evidence for exacerbation of asthma symptoms and suggestive evidence for new onset asthma.
^{1375} U.S. Environmental Protection Agency (2005). Supplemental guidance for assessing susceptibility from early-life exposure to carcinogens. Washington, DC: Risk Assessment Forum. EPA/630/R-03/003F. https://www3.epa.gov/airtoxics/childrens_supplement_final.pdf .
In addition to reduced onroad emissions of criteria pollutants and air toxics, we expect the rule will also lead to reductions in refinery emissions and increases in pollutant emissions from EGUs (see preamble section V). As described in section VI.B of this preamble and Chapter 5 of the RIA, the Integrated Science Assessments for a number of pollutants affected by this rule, including those for SO 2 , NO 2 , PM, ozone, and CO, describe children as a group with greater susceptibility.
There is substantial evidence that people who live or attend school near major roadways are more likely to be people of color, Hispanic ethnicity, and/or low socioeconomic status. Analyses of communities in close proximity to sources such as EGUs and refineries have also found that a higher percentage of communities of color and low-income communities live near these sources when compared to national averages. Within these highly exposed groups, children's exposure and susceptibility to health effects is greater than adults due to school-related and seasonal activities, behavior, and physiological factors.
Children are not expected to experience greater ambient concentrations of air pollutants compared to the general population. However, because of their greater susceptibility to air pollution, including the impacts of a changing climate, and their increased time spent outdoors, it is likely that the GHG emissions reductions associated with the standards will have particular benefits for children's health.

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
This action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. EPA has outlined the energy effects in section VI of this preamble and Chapter 5 of the RIA, which is available in the docket for this action and is briefly summarized here.
This action will reduce CO 2 emissions from heavy-duty vehicles under revised GHG standards, which will result in significant reductions in the consumption of petroleum, increase electricity consumption, achieve energy security benefits (described in section VII.C of this preamble), and have no adverse energy effects. As shown in Table 6-1 in the RIA, EPA projects that through 2055 these standards will result in a reduction of 135 billion gallons of diesel and gasoline consumption and an increase of 2,300 TWh of electricity consumption (RIA 6.5). As discussed in preamble section II.D.2.iii.d, we do not expect the increased electricity consumption under this rule to have significant adverse impacts on the electric grid.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR part 51
This action involves technical standards. Except for the standards discussed in this section, the standards included in the regulatory text as incorporated by reference were all previously approved for IBR and no change is included in this action.
In accordance with the requirements of 1 CFR 51.5, we are incorporating by reference the use of test methods and standards from ASTM International (ASTM). The referenced standards and test methods may be obtained through the ASTM website ( www.astm.org ) or by calling (610) 832-9585. We are incorporating by reference the following ASTM standards:
In accordance with the requirements of 1 CFR 51.5, we are incorporating by reference the use of test methods and standards from National Institute of Standards and Technology (NIST). The referenced standards and test methods may be obtained through the NIST website ( www.nist.gov ) or by calling (301) 975-6478. We are incorporating by reference the following NIST standards:
In accordance with the requirements of 1 CFR 51.5, we are incorporating by reference the use of EPA's Greenhouse gas Emissions Model (GEM) Phase 2, Version 4.0. The referenced model may be obtained through the EPA website ( www.epa.gov ) or by emailing complianceinfo@epa.gov . As described in section III.C.1.iv of this preamble, we are moving the powertrain testing provisions of 40 CFR 1037.550 to 40 CFR 1036.545, including references to U.S. EPA's Greenhouse gas Emissions Model (GEM). We are therefore removing GEM references in 40 CFR 1037.550, with the change noted in 40 CFR 1037.810(d)(4). We are accordingly incorporating by reference GEM as follows:

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: Revitalizing Our Nation's Commitment to Environmental Justice for All
EPA believes that the human health or environmental conditions that exist prior to this action result in or have the potential to result in disproportionate and adverse human health or environmental effects on communities with environmental justice concerns. EPA provides a summary of the evidence for potentially disproportionate and adverse effects among people of color and low-income populations in section VI.D of the preamble for this rule.
EPA believes that this action is likely to reduce existing disproportionate and adverse effects on many communities with environmental justice concerns.
Section VI.D.1 discusses the environmental justice issues associated with climate change. People of color, low-income populations and/or indigenous peoples may be especially vulnerable to the impacts of climate change. The GHG emission reductions from this action will contribute to efforts to reduce the probability of severe impacts related to climate change.
In addition to reducing GHGs, we project that this action will also reduce onroad emissions of criteria pollutants and air toxics. Section V of this preamble presents the estimated impacts from this action on onroad, refinery and EGU emissions. These non-GHG emission reductions from vehicles will improve air quality for the people who reside in close proximity to major roadways and who are disproportionately represented by people of color and people with low income, as described in section VI.D.3 of this preamble. We expect that localized increases in criteria and toxic pollutant emissions from EGUs and reductions in petroleum-sector emissions could lead to changes in exposure to these pollutants for people living in the communities near these facilities. Analyses of communities in close proximity to these sources (such as EGUs and refineries) have found that a higher percentage of communities of color and low-income communities live near these sources when compared to national averages.
EPA is additionally identifying and addressing environmental justice concerns by providing just treatment and meaningful involvement with environment justice groups in soliciting input, considering comments, and developing this final rulemaking.
The information supporting this impacts review is contained in section VI.D of the preamble for this rule, and all supporting documents have been placed in the public docket for this action.

K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action meets the criteria set forth in 5 U.S.C. 804(2).

L. Judicial Review
This final action is “nationally applicable” within the meaning of CAA section 307(b)(1) because it is expressly listed in the section ( i.e., “any standard under section [202] of this title”). Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the U.S. Court of Appeals for the District of Columbia Circuit within 60 days from the date this final action is published in the Federal Register . Filing a petition for reconsideration by the Administrator of this final action does not affect the finality of the action for the purposes of judicial review, nor does it extend the time within which a petition for judicial review must be filed and shall not postpone the effectiveness of such rule or action.

M. Severability
This final rule includes new and revised requirements for numerous provisions under various aspects of the highway on-road emission control program, including certain revised GHG standards for MY 2027 and new GHG standards for MYs 2028 through 2032 and later for HD vehicles, updates to discrete elements of the ABT program, emission-related warranty, and other requirements. Therefore, this final rule is a multifaceted rule that addresses many separate things for independent reasons, as detailed in each respective portion of this preamble. We intend each portion of this rule to be severable from each other, though we took the approach of including all the parts in one rulemaking rather than promulgating multiple rules to ensure the changes are consistently implemented, even though the changes are not inter-dependent. We have noted the independence of various pieces of this package both in the proposal and in earlier sections of the preamble but we reiterate it here for clarity.
For example, EPA notes that our judgments regarding feasibility of the Phase 3 standards for earlier years largely reflect anticipated changes in the heavy-duty vehicle market (which are driven by other factors, such as the IRA and manufacturers' plans), while our judgments regarding feasibility of the standards in later years reflect those trends plus the additional lead time for further adoption of control technologies. Thus, the standards for the later years are feasible and appropriate even absent standards for the earlier years, and vice versa. Accordingly, EPA finds that the standards for each individual year are severable from standards for each of the other years, and that at minimum the earlier MYs (MY 2027 through MY 2029) are severable from the later MYs (MYs 2030 and later). Furthermore, EPA's revisions to certain MY 2027 standards are severable from the new MY 2028 and later standards because our analysis supports that the standards for each of the later years are feasible and appropriate even absent the revised MY 2027 standards.
Additionally, our judgments regarding the standards for each separate vehicle category are likewise independent and do not rely on one another. For example, EPA notes that our judgments regarding feasibility of the standards for vocational vehicles reflect our judgment regarding the general availability of depot-charging infrastructure in MY 2027 and for each later model year under the modeled potential compliance pathway, and that judgment is independent of our judgment regarding standards for tractors that reflects our judgment regarding more reliance on publicly available charging infrastructure and hydrogen refueling infrastructure in MY 2030 and for each later model year under the modeled potential compliance pathway. Similarly, within the standards for vocational vehicles, our judgments regarding the feasibility of each model year of the standards for each category of vocational vehicles (LHD, MHD, and HHD) and for tractors (day cab and sleeper cab) reflect our judgments regarding the design requirements and payback analysis for each of the individual 101 vehicle types analyzed in HD TRUCS and then aggregated to the individual vehicle category, independent of those same kinds of judgments for the other vehicle categories and independent from prior MYs standards, under the modeled potential compliance pathway. Accordingly, EPA finds that the standards for each category of vocational vehicles and tractors for each individual model year are severable, including from the standards for all other categories for that model year, and from the standards for different model years.
Finally, EPA notes that there are changes EPA is making related to implementation of standards generally ( i.e., independent of the numeric stringency of the standards set in this final rule). For example, EPA is making changes to testing and other certification procedures, as well as establishing battery durability and battery warranty provisions. For another example, EPA is making changes to discrete elements of the existing ABT program, including to use of credits generated from Phase 2 credit multipliers for advanced technologies and credit transfers across averaging sets. Each of these issues has been considered and adopted independently of the level of the standards, and indeed of each other. EPA's overall vehicle program continues to be fully implementable even in the absence of any one or more of these elements. For instance, while the battery durability and warranty provisions support the implementation of the standards, EPA adopted the standards independent of those provisions, and the standards can function absent them. Likewise, while credits from multipliers and credit transfers across averaging sets allow flexibility in compliance options for manufacturers, they are not necessary for manufacturers to meet the emissions standards and we did not rely on them in justifying the feasibility of the standards.
Thus, EPA has independently considered and adopted each of these portions of the final rule (including but not limited to the Phase 3 GHG standards for HD vehicles; updates to discrete elements of the ABT program, including temporary transitional flexibilities; compliance testing and certification procedures; battery durability monitoring; and battery warranty) and each is severable should there be judicial review. If a court were to invalidate any one of these elements of the final rule, we intend the remainder of this action to remain effective. Importantly, we have designed these different elements of the program to function sensibly and independently, the supporting basis for each of these elements of the final rule reflects that they are independently justified and appropriate, and find each portion appropriate even if one or more other parts of the rule has been set aside. For example, if a reviewing court were to invalidate any of the Phase 3 GHG standards, the other regulatory amendments, including not only the other Phase 3 GHG standards but also the changes to discrete elements of the ABT program, certification procedures, and battery durability and warranty, remain fully operable. Moreover, this list is not intended to be exhaustive, and should not be viewed as an intention by EPA to consider other parts of the rule not explicitly listed here as not severable from other parts of the rule.

XI. Statutory Authority and Legal Provisions
Statutory authority for this action is found in the Clean Air Act at 42 U.S.C. 7401-7675, including Clean Air Act sections 202-208, 213, 216, and 301 (42 U.S.C. 7521-7542, 7547, 7550, and 7601). Statutory authority for the GHG standards is found in CAA section 202(a)(1)-(2) (42 U.S.C. 7521(a)(1)-(2)), which requires EPA to establish standards applicable to emissions of air pollutants from new motor vehicles and new motor vehicle engines which cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare. The statutory authorities for specific elements of this action are further described in the corresponding preamble sections.

List of Subjects
40 CFR Part 86
Environmental protection, Administrative practice and procedure, Confidential business information, Greenhouse gases, Labeling, Motor vehicle pollution, Reporting and recordkeeping requirements, Warranties.
40 CFR Part 1036
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Greenhouse gases, Incorporation by reference, Labeling, Motor vehicle pollution, Reporting and recordkeeping requirements, Warranties.
40 CFR Part 1037
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Incorporation by reference, Labeling, Motor vehicle pollution, Reporting and recordkeeping requirements, Warranties.
40 CFR Part 1039
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Labeling, Motor vehicle pollution, Reporting and recordkeeping requirements, Warranties.
40 CFR Part 1054
Environmental protection, Administrative practice and procedure, Air pollution control, Confidential business information, Imports, Labeling, Penalties, Reporting and recordkeeping requirements, Warranties.
40 CFR Part 1065
Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Reporting and recordkeeping requirements, Research.
Michael S. Regan,

Administrator.
For the reasons set out in the preamble, we are amending title 40, chapter I of the Code of Federal Regulations as set forth below.

PART 86—CONTROL OF EMISSIONS FROM NEW AND IN-USE HIGHWAY VEHICLES AND ENGINES
1. The authority citation for part 86 continues to read as follows:

Authority:
42 U.S.C. 7401-7671q.
2. Amend § 86.1819-14 by revising paragraph (d)(2)(i) and adding paragraph (d)(2)(iv) to read as follows:
§ 86.1819-14
Greenhouse gas emission standards for heavy-duty vehicles.
* * * * *
(d) * * *
(2) * * *
(i) Except as specified in paragraph (d)(2)(iv) of this section, credits you generate under this section may be used only to offset credit deficits under this section. You may bank credits for use in a future model year in which your average CO 2 level exceeds the standard. You may trade credits to another manufacturer according to § 86.1865-12(k)(8). Before you bank or trade credits, you must apply any available credits to offset a deficit if the deadline to offset that credit deficit has not yet passed.
* * * * *
(iv) Credits generated under this section may be used to demonstrate to compliance with the CO 2 emission standards for vehicles certified under 40 CFR part 1037 as described in 40 CFR 1037.150(z).
* * * * *

PART 1036—CONTROL OF EMISSIONS FROM NEW AND IN-USE HEAVY-DUTY HIGHWAY ENGINES
3. The authority citation for part 1036 continues to read as follows:

Authority:
42 U.S.C. 7401-7671q.
4. Revise § 1036.101 to read as follows:
§ 1036.101
Overview of exhaust emission standards.
(a) You must show that engines meet the following exhaust emission standards:
(1) Criteria pollutant standards for NO X , HC, PM, and CO apply as described in § 1036.104. These pollutants are sometimes described collectively as “criteria pollutants” because they are either criteria pollutants under the Clean Air Act or precursors to the criteria pollutants ozone and PM.
(2) This part contains standards and other regulations applicable to the emission of the air pollutant defined as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. Greenhouse gas (GHG) standards for CO 2 , CH 4 , and N 2 O apply as described in § 1036.108.
(b) You may optionally demonstrate compliance with the emission standards of this part by testing hybrid powertrains, rather than testing the engine alone. Except as specified, provisions of this part that reference engines apply equally to hybrid powertrains.
§ 1036.104
[Amended]
5. Amend § 1036.104 by removing paragraph (c)(2)(iii).
6. Amend § 1036.108 by revising paragraphs (a)(1) and (e) to read as follows:
§ 1036.108
Greenhouse gas emission standards—CO 2 , CH 4 , and N 2 O.
* * * * *
(a) * * *
(1) CO 2 emission standards in this paragraph (a)(1) apply based on testing as specified in subpart F of this part. The applicable test cycle for measuring CO 2 emissions differs depending on the engine family's primary intended service class and the extent to which the engines will be (or were designed to be) used in tractors. For Medium HDE and Heavy HDE certified as tractor engines, measure CO 2 emissions using the SET steady-state duty cycle specified in § 1036.510. This testing with the SET duty cycle is intended for engines designed to be used primarily in tractors and other line-haul applications. Note that the use of some SET-certified tractor engines in vocational applications does not affect your certification obligation under this paragraph (a)(1); see other provisions of this part and 40 CFR part 1037 for limits on using engines certified to only one cycle. For Medium HDE and Heavy HDE certified as both tractor and vocational engines, measure CO 2 emissions using the SET duty cycle specified in § 1036.510 and the FTP transient duty cycle specified in § 1036.512. Testing with both SET and FTP duty cycles is intended for engines that are designed for use in both tractor and vocational applications. For all other engines (including Spark-ignition HDE), measure CO 2 emissions using the FTP transient duty cycle specified in § 1036.512.
(i) Spark-ignition standards. The CO 2 standard for all spark-ignition engines is 627 g/hp·hr for model years 2016 through 2020.This standard continues to apply in later model years for all spark-ignition engines that are not Heavy HDE. Spark-ignition engines that qualify as Heavy HDE under § 1036.140(b)(2) for model years 2021 and later are subject to the compression-ignition engine standards for Heavy HDE-Vocational or Heavy HDE-Tractor, as applicable. You may certify spark-ignition engines to the compression-ignition standards for the appropriate model year under this paragraph (a). If you do this, those engines are treated as compression-ignition engines for all provisions of this part.
(ii) Compression-ignition standards. The following CO 2 standards apply for compression-ignition engines and model year 2021 and later spark-ignition engines that qualify as Heavy HDE:
Table 1 to Paragraph ( a )(1)( ii ) of § 1036.108—Compression-Ignition CO 2 Standards
[g/hp·hr]
Phase | Model years | Light HDE | Medium HDE- vocational | Heavy HDE- vocational | Medium HDE- tractor | Heavy HDE- tractor
1 | 2014-2016 | 600 | 600 | 567 | 502 | 475
| 2017-2020 | 576 | 576 | 555 | 487 | 460
2 | 2021-2023 | 563 | 545 | 513 | 473 | 447
| 2024-2026 | 555 | 538 | 506 | 461 | 436
| 2027 and later | 552 | 535 | 503 | 457 | 432
* * * * *
(e) Applicability for testing. The emission standards in this subpart apply as specified in this paragraph (e) to all duty-cycle testing (according to the applicable test cycles) of testable configurations, including certification, selective enforcement audits, and in-use testing. The CO 2 FCLs serve as the CO 2 emission standards for the engine family with respect to certification and confirmatory testing instead of the standards specified in paragraph (a)(1) of this section. The FELs serve as the emission standards for the engine family with respect to all other duty-cycle testing. See §§ 1036.235 and 1036.241 to determine which engine configurations within the engine family are subject to testing. Note that engine fuel maps and powertrain test results also serve as standards as described in §§ 1036.535, 1036.540, 1036.545, and 1036.630.
7. Amend § 1036.110 by revising paragraphs (b) introductory text, (b)(6), (b)(9) introductory text, (b)(11)(ii), and (c)(1) to read as follows:
§ 1036.110
Diagnostic controls.
* * * * *
(b) Engines must comply with the 2019 heavy-duty OBD requirements adopted for California as described in this paragraph (b). California's 2019 heavy-duty OBD requirements are part of 13 CCR 1968.2, 1968.5, 1971.1, and 1971.5 (incorporated by reference, see § 1036.810). We may approve your request to certify an OBD system meeting alternative specifications if you submit information as needed to demonstrate that it meets the intent of this section. For example, we may approve your request for a system that meets a later version of California's OBD requirements if you demonstrate that it meets the intent of this section; the demonstration must include identification of any approved deficiencies and your plans to resolve such deficiencies. To demonstrate that your engine meets the intent of this section, the OBD system meeting alternative specifications must address all the provisions described in this paragraph (b) and in paragraph (c) of this section. The following clarifications and exceptions apply for engines certified under this part:
* * * * *
(6) The provisions related to verification of in-use compliance in 13 CCR 1971.1(l)(4) do not apply. The provisions related to manufacturer self-testing in 13 CCR 1971.5(c) also do not apply.
* * * * *
(9) Design compression-ignition engines to make the following additional data-stream signals available on demand with a generic scan tool according to 13 CCR 1971.1(h)(4.2), if the engine is so equipped with the relevant components and OBD monitoring is required for those components (or modeling is required for some parameter related to those components):
* * * * *
(11) * * *
(ii) Send us results from any testing you performed for certifying engine families (including equivalent engine families) with the California Air Resources Board, including the results of any testing performed under 13 CCR 1971.1(l) for verification of in-use compliance and 13 CCR 1971.5(c) for manufacturer self-testing within the deadlines set out in 13 CCR 1971.1 and 1971.5.
* * * * *
(c) * * *
(1) For inducements specified in § 1036.111 and any other AECD that derates engine output related to SCR or DPF systems, indicate the fault code for the detected problem, a description of the fault code, and the current speed restriction. For inducement faults under § 1036.111, identify whether the fault condition is for DEF level, DEF quality, or tampering; for other faults, identify whether the fault condition is related to SCR or DPF systems. If there are additional derate stages, also indicate the next speed restriction and the time remaining until starting the next restriction. If the derate involves something other than restricting vehicle speed, such as a torque derate, adjust the information to correctly identify any current and pending restrictions.
* * * * *
8. Revise and republish § 1036.111 to read as follows:
§ 1036.111
Inducements related to SCR.
Engines using SCR to control emissions depend on a constant supply of diesel exhaust fluid (DEF). This section describes how manufacturers must design their engines to derate power output to induce operators to take appropriate actions to ensure the SCR system is working properly. The requirements of this section apply equally for engines installed in heavy-duty vehicles at or below 14,000 lbs GVWR. The requirements of this section apply starting in model year 2027, though you may comply with the requirements of this section in earlier model years.
(a) General provisions. The following terms and general provisions apply under this section:
(1) As described in § 1036.110, this section relies on terms and requirements specified for OBD systems by California ARB in 13 CCR 1968.2 and 1971.1 (incorporated by reference, see § 1036.810).
(2) The provisions of this section apply differently based on an individual vehicle's speed history. A vehicle's speed category is based on the OBD system's recorded value for average speed for the preceding 30 hours of non-idle engine operation. The vehicle speed category applies at the point that the engine first detects an inducement triggering condition identified under paragraph (b) of this section and continues to apply until the inducement triggering condition is fully resolved as specified in paragraph (e) of this section. Non-idle engine operation includes all operating conditions except those that qualify as idle based on OBD system controls as specified in 13 CCR 1971.1(h)(5.4.10). Apply speed derates based on the following categories:
Table 1 to Paragraph ( a )(2) of § 1036.111—Vehicle Categories
Vehicle category ^a | Average speed (mi/hr)
Low-speed | speed <15.
Medium-speed | 15 ≤ speed <25.
High-speed | speed ≥25.
^a A vehicle is presumed to be a high-speed vehicle if it has not yet logged 30 hours of non-idle operation.
(3) Where engines derate power output as specified in this section, the derate must decrease vehicle speed by 1 mi/hr for every five minutes of engine operation until reaching the specified derate speed. This paragraph (a)(3) applies at the onset of an inducement, at any transition to a different step of inducement, and for any derate that recurs under paragraph (e)(3) of this section.
(b) Inducement triggering conditions. Create derate strategies that monitor for and trigger an inducement based on the following conditions:
(1) DEF supply falling to 2.5 percent of DEF tank capacity or a level corresponding to three hours of engine operation, based on available information on DEF consumption rates.
(2) DEF quality failing to meet your concentration specifications.
(3) Any signal indicating that a catalyst is missing.
(4) Open circuit faults related to the following: DEF tank level sensor, DEF pump, DEF quality sensor, SCR wiring harness, NO X sensors, DEF dosing valve, DEF tank heater, DEF tank temperature sensor, and aftertreatment control module.
(c) [Reserved]
(d) Derate schedule. Engines must follow the derate schedule described in this paragraph (d) if the engine detects an inducement triggering condition identified in paragraph (b) of this section. The derate takes the form of a maximum drive speed for the vehicle. This maximum drive speed decreases over time based on hours of non-idle engine operation without regard to engine starting.
(1) Apply speed-limiting derates according to the following schedule:
Table 2 to Paragraph ( d )(1) of § 1036.111—Derate Schedule for Detected Inducement Triggering Conditions ^a
High-speed vehicles | Hours of non-idle engine operation | Maximum speed (mi/hr) | Medium-speed vehicles | Hours of non-idle engine operation | Maximum speed (mi/hr) | Low-speed vehicles | Hours of non-idle engine operation | Maximum speed (mi/hr)
0 | 65 | 0 | 55 | 0 | 45
6 | 60 | 6 | 50 | 5 | 40
12 | 55 | 12 | 45 | 10 | 35
20 | 50 | 45 | 40 | 30 | 25
86 | 45 | 70 | 35 | |
119 | 40 | 90 | 25 | |
144 | 35 | | | |
164 | 25 | | | |
^a Hours start counting when the engine detects an inducement triggering condition specified in paragraph (b) of this section. For DEF supply, you may program the engine to reset the timer to three hours when the engine detects an empty DEF tank.
(2) You may design and produce engines that will be installed in motorcoaches with an alternative derate schedule that starts with a 65 mi/hr derate when an inducement triggering condition is first detected, steps down to 50 mi/hr after 80 hours, and concludes with a final derate speed of 25 mi/hr after 180 hours of non-idle operation.
(e) Deactivating derates. Program the engine to deactivate derates as follows:
(1) Evaluate whether the detected inducement triggering condition continues to apply. Deactivate derates if the engine confirms that the detected inducement triggering condition is resolved.
(2) Allow a generic scan tool to deactivate inducement triggering codes while the vehicle is not in motion.
(3) Treat any detected inducement triggering condition that recurs within 40 hours of engine operation as the same detected inducement triggering condition, which would restart the derate at the same point in the derate schedule that the system last deactivated the derate.
9. Amend § 1036.115 by revising paragraph (h)(4) to read as follows:
§ 1036.115
Other requirements.
* * * * *
(h) * * *
(4) The AECD applies only for engines that will be installed in emergency vehicles, and the need is justified in terms of preventing the engine from losing speed, torque, or power due abnormal conditions of the emission control system, or in terms of preventing such abnormal conditions from occurring, during operation related to emergency response. Examples of such abnormal conditions may include excessive exhaust backpressure from an overloaded particulate trap, and running out of diesel exhaust fluid for engines that rely on urea-based selective catalytic reduction. The emission standards do not apply when any AECDs approved under this paragraph (h)(4) are active.
* * * * *
10. Amend § 1036.120 by revising paragraph (c) to read as follows:
§ 1036.120
Emission-related warranty requirements.
* * * * *
(c) Components covered. The emission-related warranty covers all components listed in 40 CFR part 1068, appendix A, and components from any other system you develop to control emissions. Note that this includes hybrid system components that you specify in a certified configuration. The emission-related warranty covers any components, regardless of the company that produced them, that are the original components or the same design as components from the certified configuration.
* * * * *
11. Amend § 1036.125 by revising paragraph (h)(8)(iii) to read as follows:
§ 1036.125
Maintenance instructions and allowable maintenance.
* * * * *
(h) * * *
(8) * * *
(iii) A description of the three types of SCR-related derates (DEF level, DEF quality and tampering) and that further information on the inducement cause ( e.g., trouble codes) is available using the OBD system.
* * * * *
12. Amend § 1036.150 by:
a. Revising paragraphs (a)(2)(ii) and (d);
b. Adding paragraph (f);
c. Revising paragraphs (j), (k) introductory text, (q), and (v); and
d. Adding paragraph (aa).
The additions and revisions read as follows:
§ 1036.150
Interim provisions.
* * * * *
(a) * * *
(2) * * *
(ii) Engines must meet a NO X standard when tested over the Low Load Cycle as described in § 1036.514. Engines must also meet an off-cycle NO X standard as specified in § 1036.104(a)(3). Calculate the NO X family emission limits for the Low Load Cycle and for off-cycle testing as described in § 1036.104(c)(3) with Std FTPNOx set to 35 mg/hp·hr and Std [cycle]NOx set to the values specified in § 1036.104(a)(1) or (3), respectively. No standard applies for HC, PM, and CO emissions for the Low Load Cycle or for off-cycle testing, but you must record measured values for those pollutants and include those measured values where you report NO X emission results.
* * * * *
(d) Small manufacturers. The greenhouse gas standards of this part apply on a delayed schedule for manufacturers meeting the small business criteria specified in 13 CFR 121.201. Apply the small business criteria for NAICS code 336310 for engine manufacturers with respect to gasoline-fueled engines and 333618 for engine manufacturers with respect to other engines; the employee limits apply to the total number employees together for affiliated companies. Qualifying small manufacturers are not subject to the greenhouse gas emission standards in § 1036.108 for engines with a date of manufacture on or after November 14, 2011, but before January 1, 2022. In addition, qualifying small manufacturers producing engines that run on any fuel other than gasoline, E85, or diesel fuel may delay complying with every later greenhouse gas standard under this part by one model year; however, small manufacturers may generate emission credits only by certifying all their engine families within a given averaging set to standards that apply for the current model year. Note that engines not yet subject to standards must nevertheless supply fuel maps to vehicle manufacturers as described in paragraph (n) of this section. Note also that engines produced by small manufacturers are subject to criteria pollutant standards.
* * * * *
(f) Testing exemption for hydrogen engines. Tailpipe CO 2 emissions from engines fueled with neat hydrogen are deemed to be 3 g/hp·hr and tailpipe CH 4 , HC, and CO emissions are deemed to comply with the applicable standard. Fuel mapping and testing for CO 2 , CH 4 , HC, or CO is optional under this part for these engines.
* * * * *
(j) Alternate standards under 40 CFR part 86. This paragraph (j) describes alternate emission standards that apply for model year 2023 and earlier loose engines certified under 40 CFR 86.1819-14(k)(8). The standards of § 1036.108 do not apply for these engines. The standards in this paragraph (j) apply for emissions measured with the engine installed in a complete vehicle consistent with the provisions of 40 CFR 86.1819-14(k)(8)(vi). The only requirements of this part that apply to these engines are those in this paragraph (j) and §§ 1036.115 through 1036.135, 1036.535, and 1036.540.
(k) Limited production volume allowance under ABT. You may produce a limited number of Heavy HDE that continue to meet the standards that applied under 40 CFR 86.007-11 in model years 2027 through 2029. The maximum number of engines you may produce under this limited production allowance is 5 percent of the annual average of your actual production volume of Heavy HDE in model years 2023-2025 for calculating emission credits under § 1036.705. Engine certification under this paragraph (k) is subject to the following conditions and requirements:
* * * * *
(q) Confirmatory and in-use testing of fuel maps defined in § 1036.505(b). For model years 2021 and later, where the results from Eq. 1036.235-1 for a confirmatory or in-use test are at or below 2.0%, we will not replace the manufacturer's fuel maps.
* * * * *
(v) OBD communication protocol. We may approve the alternative communication protocol specified in SAE J1979-2 (incorporated by reference, see § 1036.810) if the protocol is approved by the California Air Resources Board. The alternative protocol would apply instead of SAE J1939 and SAE J1979 as specified in 40 CFR 86.010-18(k)(1). Engines designed to comply with SAE J1979-2 must meet the freeze-frame requirements in § 1036.110(b)(8) and in 13 CCR 1971.1(h)(4.3.2) (incorporated by reference, see § 1036.810). This paragraph (v) also applies for model year 2026 and earlier engines.
* * * * *
(aa) Correcting credit calculations. If you notify us by October 1, 2024, that errors mistakenly decreased your balance of GHG emission credits for 2020 or any earlier model years, you may correct the errors and recalculate the balance of emission credits after applying a 10 percent discount to the credit correction.
13. Amend § 1036.205 by revising paragraph (v) to read as follows:
§ 1036.205
Requirements for an application for certification.
* * * * *
(v) Include good-faith estimates of U.S.-directed production volumes. Include a justification for the estimated production volumes if they are substantially different than actual production volumes in earlier years for similar models.
* * * * *
14. Amend § 1036.230 by revising paragraph (e) to read as follows:
§ 1036.230
Selecting engine families.
* * * * *
(e) Engine configurations certified as hybrid powertrains may not be included in an engine family with engines that have nonhybrid powertrains. Note that this does not prevent you from including engines in a nonhybrid family if they are used in hybrid vehicles, as long as you certify them based on engine testing.
* * * * *
15. Amend § 1036.240 by revising paragraph (c)(3) to read as follows:
§ 1036.240
Demonstrating compliance with criteria pollutant emission standards.
* * * * *
(c) * * *
(3) Sawtooth and other nonlinear deterioration patterns. The deterioration factors described in paragraphs (c)(1) and (2) of this section assume that the highest useful life emissions occur either at the end of useful life or at the low-hour test point. The provisions of this paragraph (c)(3) apply where good engineering judgment indicates that the highest useful life emissions will occur between these two points. For example, emissions may increase with service accumulation until a certain maintenance step is performed, then return to the low-hour emission levels and begin increasing again. Such a pattern may occur with battery-based hybrid powertrains. Base deterioration factors for engines with such emission patterns on the difference between (or ratio of) the point at which the highest emissions occur and the low-hour test point. Note that this paragraph (c)(3) applies for maintenance-related deterioration only where we allow such critical emission-related maintenance.
* * * * *
16. Amend § 1036.241 by revising paragraph (c)(3) to read as follows:
§ 1036.241
Demonstrating compliance with greenhouse gas emission standards.
* * * * *
(c) * * *
(3) Sawtooth and other nonlinear deterioration patterns. The deterioration factors described in paragraphs (c)(1) and (2) of this section assume that the highest useful life emissions occur either at the end of useful life or at the low-hour test point. The provisions of this paragraph (c)(3) apply where good engineering judgment indicates that the highest useful life emissions will occur between these two points. For example, emissions may increase with service accumulation until a certain maintenance step is performed, then return to the low-hour emission levels and begin increasing again. Such a pattern may occur with battery-based hybrid powertrains. Base deterioration factors for engines with such emission patterns on the difference between (or ratio of) the point at which the highest emissions occur and the low-hour test point. Note that this paragraph (c)(3) applies for maintenance-related deterioration only where we allow such critical emission-related maintenance.
* * * * *
17. Amend § 1036.245 by revising paragraphs (c)(3) introductory text and (c)(3)(ii) introductory text to read as follows:
§ 1036.245
Deterioration factors for exhaust emission standards.
* * * * *
(c) * * *
(3) Perform service accumulation in the laboratory by operating the engine or hybrid powertrain repeatedly over one of the following test sequences, or a different test sequence that we approve in advance:
* * * * *
(ii) Duty-cycle sequence 2 is based on operating over the LLC and the vehicle-based duty cycles from 40 CFR part 1037. Select the vehicle subcategory and vehicle configuration from § 1036.540 or § 1036.545 with the highest reference cycle work for each vehicle-based duty cycle. Operate the engine as follows for duty-cycle sequence 2:
* * * * *
18. Amend § 1036.250 by revising paragraph (a) to read as follows:
§ 1036.250
Reporting and recordkeeping for certification.
(a) By September 30 following the end of the model year, send the Designated Compliance Officer a report including the total U.S.-directed production volume of engines you produced in each engine family during the model year (based on information available at the time of the report). Report the production by serial number and engine configuration. You may combine this report with reports required under subpart H of this part. We may waive the reporting requirements of this paragraph (a) for small manufacturers.
* * * * *
19. Amend § 1036.301 by revising paragraph (c) to read as follows:
§ 1036.301
Measurements related to GEM inputs in a selective enforcement audit.
* * * * *
(c) If your certification includes powertrain testing as specified in § 1036.630, these selective enforcement audit provisions apply with respect to powertrain test results as specified in § 1036.545 and 40 CFR part 1037, subpart D. We may allow manufacturers to instead perform the engine-based testing to simulate the powertrain test as specified in 40 CFR 1037.551.
* * * * *
20. Amend § 1036.405 by revising paragraphs (a) and (d) to read as follows:
§ 1036.405
Overview of the manufacturer-run field-testing program.
(a) You must test in-use engines from the families we select. We may select the following number of engine families for testing, except as specified in paragraph (b) of this section:
(1) We may select up to 25 percent of your engine families in any calendar year, calculated by dividing the number of engine families you certified in the model year corresponding to the calendar year by four and rounding to the nearest whole number. We will consider only engine families with annual U.S.-directed production volumes above 1,500 units in calculating the number of engine families subject to testing each calendar year under the annual 25 percent engine family limit. If you have only three or fewer families that each exceed an annual U.S.-directed production volume of 1,500 units, we may select one engine family per calendar year for testing.
(2) Over any four-year period, we will not select more than the average number of engine families that you have certified over that four-year period (the model year when the selection is made and the preceding three model years), based on rounding the average value to the nearest whole number.
(3) We will not select engine families for testing under this subpart from a given model year if your total U.S.-directed production volume was less than 100 engines.
* * * * *
(d) You must complete all the required testing and reporting under this subpart (for all ten test engines, if applicable), within 18 months after we direct you to test a particular engine family. We will typically select engine families for testing and notify you in writing by June 30 of the applicable calendar year. If you request it, we may allow additional time to send us this information.
* * * * *
21. Amend § 1036.415 by revising paragraph (c)(1) to read as follows:
§ 1036.415
Preparing and testing engines.
* * * * *
(c) * * *
(1) You may use any diesel fuel that meets the specifications for S15 in ASTM D975 (incorporated by reference, see § 1036.810). You may use any commercially available biodiesel fuel blend that meets the specifications for ASTM D975 or ASTM D7467 (incorporated by reference, see § 1036.810) that is either expressly allowed or not otherwise indicated as an unacceptable fuel in the vehicle's owner or operator manual or in the engine manufacturer's published fuel recommendations. You may use any gasoline fuel that meets the specifications in ASTM D4814 (incorporated by reference, see § 1036.810). For other fuel types, you may use any commercially available fuel.
* * * * *
22. Amend § 1036.420 by revising paragraph (a) to read as follows:
§ 1036.420
Pass criteria for individual engines.
* * * * *
(a) Determine the emission standard for each regulated pollutant for each bin by adding the following accuracy margins for PEMS to the off-cycle standards in § 1036.104(a)(3):
Table 1 to Paragraph ( a ) of § 1036.420—Accuracy Margins for In-Use Testing
| NO X | HC | PM | CO
Bin 1 | 0.4 g/hr
Bin 2 | 5 mg/hp·hr | 10 mg/hp·hr | 6 mg/hp·hr | 0.25 g/hp·hr.
* * * * *
23. Amend § 1036.501 by revising paragraphs (e) and (f) and adding paragraphs (g) and (h) to read as follows:
§ 1036.501
General testing provisions.
* * * * *
(e) You may disable any AECDs that have been approved solely for emergency equipment applications under § 1036.115(h)(4). Note that the emission standards do not apply when any of these AECDs are active.
(f) You may use special or alternate procedures to the extent we allow them under 40 CFR 1065.10.
(g) This subpart is addressed to you as a manufacturer, but it applies equally to anyone who does testing for you, and to us when we perform testing to determine if your engines meet emission standards.
(h) For testing engines that use regenerative braking through the crankshaft only to power an electric heater for aftertreatment devices, you may use the nonhybrid engine testing procedures in §§ 1036.510, 1036.512, and 1036.514 and you may also or instead use the fuel mapping procedure in § 1036.505(b)(1) or (2). You may use this allowance only if the recovered energy is less than 10 percent of the total positive work for each applicable test interval. Otherwise, use powertrain testing procedures specified for hybrid powertrains to measure emissions and create fuel maps. For engines that power an electric heater with a battery, you must meet the requirements related to charge-sustaining operation as described in 40 CFR 1066.501(a)(3).
24. Amend § 1036.505 by revising paragraphs (a) and (b) to read as follows:
§ 1036.505
Engine data and information to support vehicle certification.
* * * * *
(a) Identify engine make, model, fuel type, combustion type, engine family name, calibration identification, and engine displacement. Also identify whether the engines meet CO 2 standards for tractors, vocational vehicles, or both. When certifying vehicles with GEM, for any fuel type not identified in table 1 to paragraph (b)(4) of § 1036.550, identify the fuel type as diesel fuel for engines subject to compression-ignition standards, and as gasoline for engines subject to spark-ignition standards.
(b) This paragraph (b) describes four different methods to generate engine fuel maps. For engines without hybrid components and for mild hybrid engines where you do not include hybrid components in the test, generate fuel maps using either paragraph (b)(1) or (2) of this section. For other hybrid engines, generate fuel maps using paragraph (b)(3) of this section. For hybrid powertrains and nonhybrid powertrains and for vehicles where the transmission is not automatic, automated manual, manual, or dual-clutch, generate fuel maps using paragraph (b)(4) of this section.
(1) Determine steady-state engine fuel maps as described in § 1036.535(b). Determine fuel consumption at idle as described in § 1036.535(c). Determine cycle-average engine fuel maps as described in § 1036.540, excluding cycle-average fuel maps for highway cruise cycles.
(2) Determine steady-state fuel maps as described in either § 1036.535(b) or (d). Determine fuel consumption at idle as described in § 1036.535(c). Determine cycle-average engine fuel maps as described in § 1036.540, including cycle-average engine fuel maps for highway cruise cycles. We may do confirmatory testing by creating cycle-average fuel maps from steady-state fuel maps created in paragraph (b)(1) of this section for highway cruise cycles. In § 1036.540 we define the vehicle configurations for testing; we may add more vehicle configurations to better represent your engine's operation for the range of vehicles in which your engines will be installed (see 40 CFR 1065.10(c)(1)).
(3) Determine fuel consumption at idle as described in § 1036.535(c) and (d) and determine cycle-average engine fuel maps as described in § 1036.545, including cycle-average engine fuel maps for highway cruise cycles. Set up the test to apply accessory load for all operation by primary intended service class as described in the following table:
Table 1 to Paragraph ( b )(3) of § 1036.505—Accessory Load
Primary intended service class | Power representing accessory load (kW)
Light HDV | 1.5
Medium HDV | 2.5
Heavy HDV | 3.5
(4) Generate powertrain fuel maps as described in § 1036.545 instead of fuel mapping under § 1036.535 or § 1036.540. Note that the option in § 1036.545(b)(2) is allowed only for hybrid engine testing. Disable stop-start systems and automatic engine shutdown systems when conducting powertrain fuel map testing using § 1036.545.
* * * * *
25. Amend § 1036.510 by:
a. Revising paragraphs (b) introductory text, (b)(2) introductory text, and (b)(2)(vii) and (viii);
b. Removing paragraph (b)(2)(ix); and
c. Revising paragraphs (c)(2) introductory text, (c)(2)(i) introductory text, and (d) through (g).
The revisions read as follows:
§ 1036.510
Supplemental Emission Test.
* * * * *
(b) Procedures apply differently for testing certain kinds of engines and powertrains as follows:
* * * * *
(2) Test hybrid powertrains as described in § 1036.545, except as specified in this paragraph (b)(2). Do not compensate the duty cycle for the distance driven as described in § 1036.545(g)(4). For hybrid engines, select the transmission from § 1036.540(c)(2), substituting “engine” for “vehicle” and “highway cruise cycle” for “SET”. Disregard duty cycles in § 1036.545(j). For cycles that begin with idle, leave the transmission in neutral or park for the full initial idle segment. Place the transmission into drive no earlier than 5 seconds before the first nonzero vehicle speed setpoint. For SET testing only, place the transmission into park or neutral when the cycle reaches the final idle segment. Use the following vehicle parameters instead of those in § 1036.545 to define the vehicle model in § 1036.545(a)(3):
* * * * *
(vii) Select a combination of drive axle ratio, k a, and a tire radius, r, that represents the worst-case combination of top gear ratio, drive axle ratio, and tire size for CO 2 expected for vehicles in which the hybrid engine or hybrid powertrain will be installed. This is typically the highest axle ratio and smallest tire radius. Disregard configurations or settings corresponding to a maximum vehicle speed below 60 mi/hr in selecting a drive axle ratio and tire radius, unless you can demonstrate that in-use vehicles will not exceed that speed. You may request preliminary approval for selected drive axle ratio and tire radius consistent with the provisions of § 1036.210. If the hybrid engine or hybrid powertrain is used exclusively in vehicles not capable of reaching 60 mi/hr, you may request that we approve an alternate test cycle and cycle-validation criteria as described in 40 CFR 1066.425(b)(5). Note that hybrid engines rely on a specified transmission that is different for each duty cycle; the transmission's top gear ratio therefore depends on the duty cycle, which will in turn change the selection of the drive axle ratio and tire size. For example, § 1036.520 prescribes a different top gear ratio than this paragraph (b)(2).
(viii) If you are certifying a hybrid engine, use a default transmission efficiency of 0.95 and create the vehicle model along with its default transmission shift strategy as described in § 1036.545(a)(3)(ii). Use the transmission parameters defined in § 1036.540(c)(2) to determine transmission type and gear ratio. For Light HDV and Medium HDV, use the Light HDV and Medium HDV parameters for FTP, LLC, and SET duty cycles. For Tractors and Heavy HDVs, use the Tractor and Heavy HDV transient cycle parameters for the FTP and LLC duty cycles and the Tractor and Heavy HDV highway cruise cycle parameters for the SET duty cycle.
(c) * * *
(2) The duty cycle for testing hybrid powertrains involves a schedule of vehicle speeds and road grade as follows:
(i) Determine road grade at each point based on the continuous rated power of the hybrid powertrain, P contrated , in kW determined in § 1036.520, the vehicle speed (A, B, or C) in mi/hr for a given SET mode, v ref[speed] , and the specified road-grade coefficients using the following equation:
* * * * *
(d) Determine criteria pollutant emissions for plug-in hybrid powertrains as follows:
(1) Carry out a charge-sustaining test as described in paragraph (b)(2) of this section.
(2) Carry out a charge-depleting test as described in paragraph (b)(2) of this section, except as follows:
(i) Fully charge the RESS after preconditioning.
(ii) Operate the engine or powertrain continuously over repeated SET duty cycles until you reach the end-of-test criterion defined in 40 CFR 1066.501(a)(3).
(iii) Calculate emission results for each SET duty cycle. Figure 1 to paragraph (d)(4) of this section provides an example of a charge-depleting test sequence where there are two test intervals that contain engine operation.
(3) Report the highest emission result for each criteria pollutant from all tests in paragraphs (d)(1) and (2) of this section, even if those individual results come from different test intervals.
(4) The following figure illustrates an example of an SET charge-depleting test sequence:

Figure 1 to Paragraph (d)(4) of § 1036.510—SET Charge-Depleting Criteria Pollutant Test Sequence.
(e) Determine greenhouse gas pollutant emissions for plug-in hybrid powertrains using the emissions results for all the SET test intervals for both charge-depleting and charge-sustaining operation from paragraph (d)(2) of this section. Calculate the utility factor-weighted composite mass of emissions from the charge-depleting and charge-sustaining test results, e UF[emission]comp, using the following equation:
Eq. 1036.510-10
Where:
i = an indexing variable that represents one test interval.
N = total number of charge-depleting test intervals.
e [emission][int]CDi = total mass of emissions in the charge-depleting portion of the test for each test interval, i, starting from i = 1, including the test interval(s) from the transition phase.
UF DCDi = utility factor fraction at distance D CDi from Eq. 1036.510-11, as determined by interpolating the approved utility factor curve for each test interval, i, starting from i = 1. Let UF DCD0 = 0.
j = an indexing variable that represents one test interval.
M = total number of charge-sustaining test intervals.
e [emission][int]CS j = total mass of emissions in the charge-sustaining portion of the test for each test interval, j, starting from j = 1.
UF RCD = utility factor fraction at the full charge-depleting distance, R CD, as determined by interpolating the approved utility factor curve. R CD is the cumulative distance driven over N charge-depleting test intervals.
Eq. 1036.510-11
Where:
k = an indexing variable that represents one recorded velocity value.
Q = total number of measurements over the test interval.
v = vehicle velocity at each time step, k, starting from k = 1. For tests completed under this section, v is the vehicle velocity from the vehicle model in § 1036.545. Note that this should include charge-depleting test intervals that start when the engine is not yet operating.
Δ t = 1/ f record
f record = the record rate.
Example using the charge-depletion test in figure 1 to paragraph (d)(4) of this section for the SET for CO 2
emission determination:
Q = 24000
v 1 = 0 mi/hr
v 2 = 0.8 mi/hr
v 3 = 1.1 mi/hr
f record = 10 Hz
Δ t = 1/10 Hz = 0.1 s
D CD1 = 30.1 mi
D CD2 = 30.0 mi
D CD3 = 30.1 mi
D CD4 = 30.2 mi
D CD5 = 30.1 mi
N = 5
UF DCD1 = 0.11
UF DCD2 = 0.23
UF DCD3 = 0.34
UF DCD4 = 0.45
UF DCD5 = 0.53
e CO2SETCD1 = 0 g/hp·hr
e CO2SETCD2 = 0 g/hp·hr
e CO2SETCD3 = 0 g/hp·hr
e CO2SETCD4 = 0 g/hp·hr
e CO2SETCD5 = 174.4 g/hp·hr
M = 1
e CO2SETCS = 428.1 g/hp·hr
UF RCD = 0.53
(f) Calculate and evaluate cycle-validation criteria as specified in 40 CFR 1065.514 for nonhybrid engines and § 1036.545 for hybrid powertrains.
(g) Calculate the total emission mass of each constituent, m, over the test interval as described in 40 CFR 1065.650. Calculate the total work, W, over the test interval as described in 40 CFR 1065.650(d). For hybrid powertrains, calculate W using system power, P sys as described in § 1036.520(f).
26. Revise and republish § 1036.512 to read as follows:
§ 1036.512
Federal Test Procedure.
(a) Measure emissions using the transient Federal Test Procedure (FTP) as described in this section to determine whether engines meet the emission standards in subpart B of this part. Operate the engine or hybrid powertrain over one of the following transient duty cycles:
(1) For engines subject to spark-ignition standards, use the transient test interval described in paragraph (b) of appendix B to this part.
(2) For engines subject to compression-ignition standards, use the transient test interval described in paragraph (c) of appendix B to this part.
(b) Procedures apply differently for testing certain kinds of engines and powertrains as follows:
(1) The transient test intervals for nonhybrid engine testing are based on normalized speed and torque values. Denormalize speed as described in 40 CFR 1065.512. Denormalize torque as described in 40 CFR 1065.610(d).
(2) Test hybrid powertrains as described in § 1036.510(b)(2), with the following exceptions:
(i) Replace P contrated with P rated, which is the peak rated power determined in § 1036.520.
(ii) Keep the transmission in drive for all idle segments after the initial idle segment.
(iii) For hybrid engines, you may request to change the engine-commanded torque at idle to better represent curb idle transmission torque (CITT).
(iv) For plug-in hybrid powertrains, test over the FTP in both charge-sustaining and charge-depleting operation for both criteria and greenhouse gas pollutant determination.
(c) Except as specified in paragraph (d) of this section for plug-in hybrid powertrains, the FTP duty cycle consists of an initial run through the test interval from a cold start as described in 40 CFR part 1065, subpart F, followed by a (20 ±1) minute hot soak with no engine operation, and then a final hot start run through the same transient test interval. Engine starting is part of both the cold-start and hot-start test intervals. Calculate the total emission mass of each constituent, m, over each test interval as described in 40 CFR 1065.650. Calculate the total work, W, over the test interval as described in 40 CFR 1065.650(d). For hybrid powertrains, calculate W using system power, P sys as described in § 1036.520(f). Determine P sys using § 1036.520(f). For powertrains with automatic transmissions, account for and include the work produced by the engine from the CITT load. Calculate the official transient emission result from the cold-start and hot-start test intervals using the following equation:
Eq. 1036.512-1
(d) Determine criteria pollutant emissions for plug-in hybrid powertrains as follows:
(1) Carry out a charge-sustaining test as described in paragraph (b)(2) of this section.
(2) Carry out a charge-depleting test as described in paragraph (b)(2) of this section, except as follows:
(i) Fully charge the battery after preconditioning.
(ii) Operate the engine or powertrain over one FTP duty cycle followed by alternating repeats of a 20-minute soak and a hot start test interval until you reach the end-of-test criteria defined in 40 CFR 1066.501(a)(3).
(iii) Calculate emission results for each successive pair of test intervals. Calculate the emission result by treating the first of the two test intervals as a cold-start test. Figure 1 to paragraph (d)(4) of this section provides an example of a charge-depleting test sequence where there are three test intervals with engine operation for two overlapping FTP duty cycles.
(3) Report the highest emission result for each criteria pollutant from all tests in paragraphs (d)(1) and (2) of this section, even if those individual results come from different test intervals.
(4) The following figure illustrates an example of an FTP charge-depleting test sequence:

Figure 1 to Paragraph (d)(4) of § 1036.512—FTP Charge-Depleting Criteria Pollutant Test Sequence
(e) Determine greenhouse gas pollutant emissions for plug-in hybrid engines and powertrains using the emissions results for all the transient duty cycle test intervals described in either paragraph (b) or (c) of appendix B to this part for both charge-depleting and charge-sustaining operation from paragraph (d)(2) of this section. Calculate the utility factor weighted composite mass of emissions from the charge-depleting and charge-sustaining test results, e UF[emission]comp, as described in § 1036.510(e), replacing occurances of “SET” with “transient test interval”. Note this results in composite FTP GHG emission results for plug-in hybrid engines and powertrains without the use of the cold-start and hot-start test interval weighting factors in Eq. 1036.512-1.
(f) Calculate and evaluate cycle-validation criteria as specified in 40 CFR 1065.514 for nonhybrid engines and § 1036.545 for hybrid powertrains.
27. Revise § 1036.514 to read as follows:
§ 1036.514
Low Load Cycle.
Measure emissions using the transient Low Load Cycle (LLC) as described in this section to determine whether engines meet the LLC emission standards in § 1036.104. The LLC duty cycle is described in paragraph (d) of appendix B to this part. Procedures apply differently for testing certain kinds of engines and powertrains as follows:
(a) Test nonhybrid engines using the following procedures:
(1) Use the normalized speed and torque values for engine testing in the LLC duty cycle. Denormalize speed and torque values as described in 40 CFR 1065.512 and 1065.610 with the following additional requirements for testing at idle:
(i) Apply the accessory load at idle in paragraph (c) of this section using declared idle power as described in 40 CFR 1065.510(f)(6). Declared idle torque must be zero.
(ii) Apply CITT in addition to accessory load as described in this paragraph (a)(1)(ii). Set reference speed and torque values as described in 40 CFR 1065.610(d)(3)(vi) for all idle segments that are 200 s or shorter to represent the transmission operating in drive. For longer idle segments, set the reference speed and torque values to the warm-idle-in-drive values for the first three seconds and the last three seconds of the idle segment. For the points in between, set the reference speed and torque values to the warm-idle-in-neutral values to represent the transmission being manually shifted from drive to neutral shortly after the extended idle starts and back to drive shortly before it ends.
(2) Calculate and evaluate cycle-validation criteria as described in 40 CFR 1065.514, except as specified in paragraph (e) of this section.
(b) Test hybrid powertrains as described in § 1036.510(b)(2), with the following exceptions:
(1) Replace P contrated with P rated , which is the peak rated power determined in § 1036.520.
(2) Keep the transmission in drive for all idle segments 200 seconds or less. For idle segments more than 200 seconds, leave the transmission in drive for the first 3 seconds of the idle segment, then immediately place the transmission in park or neutral, and shift the transmission into drive again 3 seconds before the end of the idle segment. The end of the idle segment occurs at the first nonzero vehicle speed setpoint.
(3) For hybrid engines, you may request to change the GEM-generated engine reference torque at idle to better represent curb idle transmission torque (CITT).
(4) Adjust procedures in this section as described in § 1036.510(d) and (e) for plug-in hybrid powertrains to determine criteria pollutant and greenhouse gas emissions, replacing “SET” with “LLC”. Note that the LLC is therefore the preconditioning duty cycle for plug-in hybrid powertrains.
(5) Calculate and evaluate cycle-validation criteria as specified in § 1036.545.
(c) Include vehicle accessory loading as follows:
(1) Apply a vehicle accessory load for each idle point in the cycle using the power values in the following table:
Table 1 to Paragraph ( c )(1) of § 1036.514—Accessory Load at Idle
Primary intended service class | Power representing accessory load (kW)
Light HDE | 1.5
Medium HDE | 2.5
Heavy HDE | 3.5
(2) For nonhybrid engine testing, apply vehicle accessory loads in addition to any applicable CITT.
(3) Additional provisions related to vehicle accessory load apply for engines with stop-start technology and hybrid powertrains where the accessory load is applied to the engine shaft. Account for the loss of mechanical work due to the lack of any idle accessory load during engine-off conditions by determining the total loss of mechanical work from idle accessory load during all engine-off intervals over the entire test interval and distributing that work over the engine-on portion of the entire test interval based on a calculated average power. You may determine the engine-off time by running practice cycles or through engineering analysis.
(d) Except as specified in paragraph (b)(4) of this section for plug-in hybrid powertrains, the test sequence consists of preconditioning the engine by running one or two FTPs with each FTP followed by (20 ± 1) minutes with no engine operation and a hot start run through the LLC. You may start any preconditioning FTP with a hot engine. Perform testing as described in 40 CFR 1065.530 for a test interval that includes engine starting. Calculate the total emission mass of each constituent, m, over the test interval as described in 40 CFR 1065.650. For nonhybrid engines, calculate the total work, W, over the test interval as described in 40 CFR 1065.650(d). For hybrid powertrains, calculate total positive work over the test interval using system power, P sys . Determine P sys using § 1036.520(f). For powertrains with automatic transmissions, account for and include the work produced by the engine from the CITT load.
(e) For testing spark-ignition gaseous-fueled engines with fuel delivery at a single point in the intake manifold, you may apply the alternative cycle-validation criteria for the LLC in the following table:
Table 2 to Paragraph ( e ) of § 1036.514—Alternative LLC Cycle Validation Criteria for Spark-Ignition Gaseous-Fueled Engines ^a
Parameter | Speed | Torque | Power
Slope, a 1 | | 0.800 ≤ a 1 ≤ 1.030 | 0.800 ≤ a 1 ≤ 1.030.
Absolute value of intercept, | a 0 |
Standard error of the estimate, SEE | | | ≤15% of maximum mapped power.
Coefficient of determination, r ^2 | | ≥0.650 | ≥0.650.
^a Cycle-validation criteria apply as specified in 40 CFR 1065.514 unless otherwise specified.
28. Amend § 1036.520 by revising the introductory text and paragraphs (b) introductory text, (d), and (h) through (j) to read as follows:
§ 1036.520
Determining power and vehicle speed values for powertrain testing.
This section describes how to determine the system peak power and continuous rated power of hybrid and nonhybrid powertrain systems and the vehicle speed for carrying out duty-cycle testing under this part and § 1036.545.
* * * * *
(b) Set up the powertrain test according to § 1036.545, with the following exceptions:
* * * * *
(d) Carry out the test as described in this paragraph (d). Warm up the powertrain by operating it. We recommend operating the powertrain at any vehicle speed and road grade that achieves approximately 75% of its expected maximum power. Continue the warm-up until the engine coolant, block, lubricating oil, or head absolute temperature is within ±2% of its mean value for at least 2 min or until the engine thermostat controls engine temperature. Within 90 seconds after concluding the warm-up, operate the powertrain over a continuous trace meeting the following specifications:
(1) Bring the vehicle speed to 0 mi/hr and let the powertrain idle at 0 mi/hr for 50 seconds.
(2) Set maximum driver demand for a full load acceleration at 6.0% road grade with an initial vehicle speed of 0 mi/hr, continuing for 268 seconds. You may increase initial vehicle speed up to 5 mi/hr to minimize clutch slip.
(3) Linearly ramp the grade from 6.0% down to 0.0% over 300 seconds. Stop the test after the acceleration is less than 0.02 m/s ^2 .
* * * * *
(h) Determine rated power, P rated, as the maximum measured power from the data collected in paragraph (d)(2) of this section where the COV determined in paragraph (g) of this section is less than 2%.
(i) Determine continuous rated power, P contrated , as follows:
(1) For nonhybrid powertrains, P contrated equals P rated .
(2) For hybrid powertrains, P contrated is the maximum measured power from the data collected in paragraph (d)(3) of this section where the COV determined in paragraph (g) of this section is less than 2%.
(j) Determine vehicle C speed, v refC , as follows:
(1) If the maximum P sys ( t ) in the highest gear during the maneuver in paragraph (d)(3) of this section is greater than 0.98· P contrated , v refC is the average of the minimum and maximum vehicle speeds where P sys ( t ) is equal to 0.98· P contrated during the maneuver in paragraph (d)(3) where the transmission is in the highest gear, using linear interpolation, as appropriate. If P sys ( t ) at the lowest vehicle speed where the transmission is in the highest gear is greater than 0.98· P contrated , use the lowest vehicle speed where the transmission is in the highest gear as the minimum vehicle speed input for calculating v refC.
(2) Otherwise, v refC is the maximum vehicle speed during the maneuver in paragraph (d)(3) of this section where the transmission is in the highest gear.
(3) You may use a declared v refC instead of measured v refC if the declared v refC is within (97.5 to 102.5)% of the corresponding measured value.
(4) Manufacturers may request approval to use an alternative vehicle C speed in place of the measured vehicle C speed determined in this paragraph (j) for series hybrid applications. Approval will be contingent upon justification that the measured vehicle C speed is not representative of the expected real-world cruise speed.
* * * * *
29. Amend § 1036.525 by revising the introductory text to read as follows:
§ 1036.525
Clean Idle test.
Measure emissions using the procedures described in this section to determine whether engines and hybrid powertrains meet the clean idle emission standards in § 1036.104(b). For plug-in hybrid powertrains, perform the test with the hybrid function disabled.
* * * * *
30. Amend § 1036.530 by revising paragraphs (g)(1) and (g)(2)(ii) and adding paragraph (j) to read as follows:
§ 1036.530
Test procedures for off-cycle testing.
* * * * *
(g) * * *
(1) Spark-ignition. For engines subject to spark-ignition standards, the off-cycle emission quantity, e [emission],offcycle, is the value for CO 2 -specific emission mass for a given pollutant over the test interval representing the shift-day converted to a brake-specific value, as calculated for each measured pollutant using the following equation:
Eq. 1036.530-3
Where:
m [emission] = total emission mass for a given pollutant over the test interval as determined in paragraph (d)(2) of this section.
m CO2 = total CO 2 emission mass over the test interval as determined in paragraph (d)(2) of this section.
e CO2FTPFCL = the engine's FCL for CO 2 over the FTP duty cycle.
Example:
(2) * * *
(ii) Off-cycle emissions quantity for bin 2. The off-cycle emission quantity for bin 2, e [emission],offcycle,bin2, is the value for CO 2 -specific emission mass for a given pollutant of all the 300 second test intervals in bin 2 combined and converted to a brake-specific value, as calculated for each measured pollutant using the following equation:
Eq. 1036.530-5
Where:
i = an indexing variable that represents one 300 second test interval.
N = total number of 300 second test intervals in bin 2.
m [emission],testinterval,i = total emission mass for a given pollutant over the test interval i in bin 2 as determined in paragraph (d)(2) of this section.
m CO2,testinterval,i = total CO 2 emission mass over the test interval i in bin 2 as determined in paragraph (d)(2) of this section.
e CO2,FTP,FCL = the engine's FCL for CO 2 over the FTP duty cycle.
Example:
N = 15439
m NOx1 = 0.546 g
m NOx2 = 0.549 g
m NOx3 = 0.556 g
m CO2,1 = 10950.2 g
m CO2,2 = 10961.3 g
m CO2,3 = 10965.3 g
e CO2,FTP,FCL = 428.1 g/hp·hr
* * * * *
(j) Fuel other than carbon-containing. The following procedures apply for testing engines using at least one fuel that is not a carbon-containing fuel:
(1) Use the following equation to determine the normalized equivalent CO 2 emission mass over each 300 second test interval instead of Eq. 1036.530-2:
Eq. 1036.530-6
Where:
W testinterval = total positive work over the test interval from both the engine and hybrid components, if applicable, as determined in 40 CFR 1065.650.
P max = the highest value of rated power for all the configurations included in the engine family.
t testinterval = duration of the test interval. Note that the nominal value is 300 seconds.
Example:
W testinterval = 8.95 hp·hr
P max = 406.5 hp
t testinterval = 300.01 s = 0.08 hr
(2) Determine off-cycle emissions quantities as follows:
(i) For engines subject to spark-ignition standards, use the following equation to determine the off-cycle emission quantity instead of Eq. 1036.530-3:
Eq. 1036.530-7
Where:
m [emission] = total emission mass for a given pollutant over the test interval as determined in paragraph (d)(2) of this section.
W testinterval = total positive work over the test interval as determined in 40 CFR 1065.650.
Example:
(ii) For engines subject to compression-ignition standards, use Eq. 1036.530-4 to determine the off-cycle emission quantity for bin 1.
(iii) For engines subject to compression-ignition standards, use the following equation to determine the off-cycle emission quantity for bin 2 instead of Eq. 1036.530-5:
Eq. 1036.530-8
Where:
i = an indexing variable that represents one 300 second test interval.
N = total number of 300 second test intervals in bin 2.
m [emission],testinterval, i = total emission mass for a given pollutant over the test interval i in bin 2 as determined in paragraph (d)(2) of this section.
W testinterval, i = total positive work over the test interval i in bin 2 as determined in 40 CFR 1065.650.
Example:
N = 15439
m NOx1 = 0.546 g
m NOx2 = 0.549 g
m NOx3 = 0.556 g
W testinterval1 = 8.91 hp·hr
W testinterval2 = 8.94 hp·hr
W testinterval3 = 8.89 hp·hr
31. Amend § 1036.535 by revising paragraphs (b)(1)(ii) and (iii), (b)(8) and (10), and (e) to read as follows:
§ 1036.535
Determining steady-state engine fuel maps and fuel consumption at idle.
* * * * *
(b) * * *
(1) * * *
(ii) Select the following required torque setpoints at each of the selected speed setpoints: zero ( T = 0), maximum mapped torque, T max mapped, and eight (or more) equally spaced points between T = 0 and T max mapped. Select the maximum torque setpoint at each speed to conform to the torque map as follows:
(A) Calculate 5 percent of T max mapped. Subtract this result from the mapped torque at each speed setpoint, T max.
(B) Select T max at each speed setpoint as a single torque value to represent all the required torque setpoints above the value determined in paragraph (b)(1)(ii)(A) of this section. All the other default torque setpoints less than T max at a given speed setpoint are required torque setpoints.
(iii) You may select any additional speed and torque setpoints consistent with good engineering judgment. For example, you may need to select additional points if the engine's fuel consumption is nonlinear across the torque map. Avoid creating a problem with interpolation between narrowly spaced speed and torque setpoints near T max. For each additional speed setpoint, we recommend including a torque setpoint of T max ; however, you may select torque setpoints that properly represent in-use operation. Increments for torque setpoints between these minimum and maximum values at an additional speed setpoint must be no more than one-ninth of T max,mapped. Note that if the test points were added for the child rating, they should still be reported in the parent fuel map. We will test with at least as many points as you. If you add test points to meet testing requirements for child ratings, include those same test points as reported values for the parent fuel map. For our testing, we will use the same normalized speed and torque test points you use, and we may select additional test points.
* * * * *
(8) If you determine fuel-consumption rates using emission measurements from the raw or diluted exhaust, calculate the mean fuel mass flow rate, m fuel , for each point in the fuel map using the following equation:
Eq. 1036.535-1
Where:
m = mean fuel mass flow rate for a given fuel map setpoint, expressed to at least the nearest 0.001 g/s.
M C = molar mass of carbon.
W Cmeas = carbon mass fraction of fuel (or mixture of test fuels) as determined in 40 CFR 1065.655(d), except that you may not use the default properties in 40 CFR 1065.655(e)(5) to determine α, β, and w C. You may not account for the contribution to α, β,
γ, and δ of diesel exhaust fluid or other non-fuel fluids injected into the exhaust.
n = the mean exhaust molar flow rate from which you measured emissions according to 40 CFR 1065.655.
x Ccombdry = the mean concentration of carbon from fuel and any injected fluids in the exhaust per mole of dry exhaust as determined in 40 CFR 1065.655(c).
x Oexhdry = the mean concentration of H 2 O in exhaust per mole of dry exhaust as determined in 40 CFR 1065.655(c).
m CO2DEF = the mean CO 2 mass emission rate resulting from diesel exhaust fluid decomposition as determined in paragraph (b)(9) of this section. If your engine does not use diesel exhaust fluid, or if you choose not to perform this correction, set equal to 0.
M CO2 = molar mass of carbon dioxide.
Example:
M C = 12.0107 g/mol
w Cmeas = 0.869
n = 25.534 mol/s
x Ccombdry = 0.002805 mol/mol
x H2Oexhdry = 0.0353 mol/mol
m CO2DEF = 0.0726 g/s
M CO2 = 44.0095 g/mol
* * * * *
(10) Correct the measured or calculated mean fuel mass flow rate, at each of the operating points to account for mass-specific net energy content as described in paragraph (e) of this section.
* * * * *
(e) Correction for net energy content. Correct the measured or calculated mean fuel mass flow rate, m fuel , for each test interval to a mass-specific net energy content of a reference fuel using the following equation:
Eq. 1036.535-4
Where:
E mfuelmeas = the mass-specific net energy content of the test fuel as determined in § 1036.550(b)(1). Note that dividing this value by w Cref (as is done in this equation) equates to a carbon-specific net energy content having the same units as E mfuelCref.
E mfuelCref = the reference value of carbon-mass-specific net energy content for the appropriate fuel. Use the values shown in table 1 to paragraph (b)(4) of § 1036.550 for the designated fuel types, or values we approve for other fuel types.
W Cref = the reference value of carbon mass fraction for the test fuel as shown in table 1 to paragraph (b)(4) of § 1036.550 for the designated fuels. For any fuel not identified in the table, use the reference carbon mass fraction of diesel fuel for engines subject to compression-ignition standards, and use the reference carbon mass fraction of gasoline for engines subject to spark-ignition standards.
Example:
= 0.933 g/s
* * * * *
32. Amend § 1036.540 by revising paragraph (b), table 1 to paragraph (c)(2), and paragraphs (d) introductory text, (d)(3), and (d)(12)(i)(A) to read as follows:
§ 1036.540
Determining cycle-average engine fuel maps.
* * * * *
(b) General test provisions. The following provisions apply for testing under this section:
(1) Measure NO X emissions for each specified sampling period in grams. You may perform these measurements using a NO X emission-measurement system that meets the requirements of 40 CFR part 1065, subpart J. Include these measured NO X values any time you report to us your fuel-consumption values from testing under this section. If a system malfunction prevents you from measuring NO X emissions during a test under this section but the test otherwise gives valid results, you may consider this a valid test and omit the NO X emission measurements; however, we may require you to repeat the test if we determine that you inappropriately voided the test with respect to NO X emission measurement.
(2) The provisions related to carbon balance error verification in § 1036.543 apply for all testing in this section. These procedures are optional, but we will perform carbon balance error verification for all testing under this section.
(3) Correct fuel mass to a mass-specific net energy content of a reference fuel as described in paragraph (d)(13) of this section.
(4) This section uses engine parameters and variables that are consistent with 40 CFR part 1065.
(c) * * *
(2) * * *
Table 1 to Paragraph ( c )(2) of § 1036.540—GEM Input for Gear Ratio
Gear No. | Spark-ignition HDE, light HDE, and medium HDE— all duty cycles | Heavy HDE— transient and ftp duty cycles | Heavy HDE— cruise and set duty cycles
1 | 3.10 | 3.51 | 12.8
2 | 1.81 | 1.91 | 9.25
3 | 1.41 | 1.43 | 6.76
4 | 1.00 | 1.00 | 4.90
5 | 0.71 | 0.74 | 3.58
6 | 0.61 | 0.64 | 2.61
7 | — | — | 1.89
8 | — | — | 1.38
9 | — | — | 1.00
10 | — | — | 0.73
Lockup Gear | 3 | 3 | —
* * * * *
(d) Test the engine with GEM cycles. Test the engine over each of the engine duty cycles generated in paragraph (c) of this section as follows:
* * * * *
(3) Control speed and torque to meet the cycle validation criteria in 40 CFR 1065.514 for each interval, except that the standard error of the estimate in 40 CFR 1065.514(f)(3) is the only speed criterion that applies if the range of reference speeds is less than 10 percent of the mean reference speed. For spark-ignition gaseous-fueled engines with fuel delivery at a single point in the intake manifold, you may apply the alternative cycle-validation criteria in table 5 to this paragraph (c)(3) for transient testing. Note that 40 CFR part 1065 does not allow reducing cycle precision to a lower frequency than the 10 Hz reference cycle generated by GEM.
Table 5 to Paragraph ( c )(3) of § 1036.540— Alternative Fuel-Mapping Cycle-Validation Criteria for Spark-Ignition Gaseous-Fueled Engines ^a
Parameter | Speed | Torque | Power
Slope, a 1
Absolute value of intercept, | a 0 | | | ≤3% of maximum mapped torque |
Standard error of the estimate, SEE | | ≤15% of maximum mapped torque | ≤15% of maximum mapped power.
Coefficient of determination, r ^2 | | ≥0.700 | ≥0.750.
^a Cycle-validation criteria apply as specified in 40 CFR 1065.514 unless otherwise specified.
* * * * *
(12) * * *
(i) * * *
(A) For calculations that use continuous measurement of emissions and continuous CO 2 from urea, calculate m fuel[cycle] using the following equation:
Eq. 1036.540-3
Where:
M C = molar mass of carbon.
w Cmeas = carbon mass fraction of fuel (or mixture of fuels) as determined in 40 CFR 1065.655(d), except that you may not use the default properties in 40 CFR 1065.655(e)(5) to determine α, β, and w C. You may not account for the contribution to α, β,
γ, and δ of diesel exhaust fluid or other non-fuel fluids injected into the exhaust.
i = an indexing variable that represents one recorded emission value.
N = total number of measurements over the duty cycle.
n 1 = exhaust molar flow rate from which you measured emissions according to 40 CFR 1065.655.
x Ccombdry i = amount of carbon from fuel and any injected fluids in the exhaust per mole of dry exhaust as determined in 40 CFR 1065.655(c).
x H2Oexhdry i = amount of H 2 O in exhaust per mole of exhaust as determined in 40 CFR 1065.655(c).
Δ t = 1/ f record
M CO2 = molar mass of carbon dioxide.
m CO2DEF i = mass emission rate of CO 2 resulting from diesel exhaust fluid decomposition over the duty cycle as determined from § 1036.535(b)(9). If your engine does not utilize diesel exhaust fluid for emission control, or if you choose not to perform this correction, set m CO2DEF i equal to 0.
Example:
M C = 12.0107 g/mol
w Cmeas = 0.867
N = 6680
n 1 = 2.876 mol/s
n 2 = 2.224 mol/s
x Ccombdryi 1 = 2.61·10 −3 mol/mol
x Ccombdryi 2 = 1.91·10 −3 mol/mol
x H2Oexh1 = 3.53·10 −2 mol/mol
x H2Oexh2 = 3.13·10 −2 mol/mol
f record = 10 Hz
Δ t = 1/10 = 0.1 s
M CO2 = 44.0095 g/mol
m CO2DEF1 = 0.0726 g/s
m CO2DEF2 = 0.0751 g/s
* * * * *
33. Revise § 1036.543 to read as follows:
§ 1036.543
Carbon balance error verification.
The optional carbon balance error verification in 40 CFR 1065.543 compares independent assessments of the flow of carbon through the system (engine plus aftertreatment). This procedure applies for each individual interval in §§ 1036.535(b), (c), and (d), 1036.540, and 1036.545.
34. Add § 1036.545 to read as follows:
§ 1036.545
Powertrain testing.
This section describes the procedure to measure fuel consumption and create engine fuel maps by testing a powertrain that includes an engine coupled with a transmission, drive axle, and hybrid components or any assembly with one or more of those hardware elements. Engine fuel maps are part of demonstrating compliance with Phase 2 and Phase 3 vehicle standards under 40 CFR part 1037; the powertrain test procedure in this section is one option for generating this fuel-mapping information as described in § 1036.505. Additionally, this powertrain test procedure is one option for certifying hybrid powertrains to the engine standards in §§ 1036.104 and 1036.108.
(a) General test provisions. The following provisions apply broadly for testing under this section:
(1) Measure NO X emissions as described in paragraph (k) of this section. Include these measured NO X values any time you report to us your greenhouse gas emissions or fuel consumption values from testing under this section.
(2) The procedures of 40 CFR part 1065 apply for testing in this section except as specified. This section uses engine parameters and variables that are consistent with 40 CFR part 1065.
(3) Powertrain testing depends on models to calculate certain parameters. You can use the detailed equations in this section to create your own models, or use the GEM HIL model contained within GEM Phase 2, Version 4.0 (incorporated by reference, see § 1036.810) to simulate vehicle hardware elements as follows:
(i) Create driveline and vehicle models that calculate the angular speed setpoint for the test cell dynamometer, f nref,dyno, based on the torque measurement location. Use the detailed equations in paragraph (f) of this section, the GEM HIL model's driveline and vehicle submodels, or a combination of the equations and the submodels. You may use the GEM HIL model's transmission submodel in paragraph (f) to simulate a transmission only if testing hybrid engines. If the engine is intended for vehicles with automatic transmissions, use the cycle configuration file in GEM to change the transmission state (in-gear or idle) as a function of time as defined by the duty cycles in this part.
(ii) Create a driver model or use the GEM HIL model's driver submodel to simulate a human driver modulating the throttle and brake pedals to follow the test cycle as closely as possible.
(iii) Create a cycle-interpolation model or use the GEM HIL model's cycle submodel to interpolate the duty-cycles and feed the driver model the duty-cycle reference vehicle speed for each point in the duty-cycle.
(4) The powertrain test procedure in this section is designed to simulate operation of different vehicle configurations over specific duty cycles. See paragraphs (h) and (j) of this section.
(5) For each test run, record engine speed and torque as defined in 40 CFR 1065.915(d)(5) with a minimum sampling frequency of 1 Hz. These engine speed and torque values represent a duty cycle that can be used for separate testing with an engine mounted on an engine dynamometer under 40 CFR 1037.551, such as for a selective enforcement audit as described in 40 CFR 1037.301.
(6) For hybrid powertrains with no plug-in capability, correct for the net energy change of the energy storage device as described in 40 CFR 1066.501(a)(3). For plug-in hybrid electric powertrains, follow 40 CFR 1066.501(a)(3) to determine End-of-Test for charge-depleting operation. You must get our approval in advance for your utility factor curve; we will approve it if you can show that you created it, using good engineering judgment, from sufficient in-use data of vehicles in the same application as the vehicles in which the plug-in hybrid electric powertrain will be installed. You may use methodologies described in SAE J2841 to develop the utility factor curve.
(7) The provisions related to carbon balance error verification in § 1036.543 apply for all testing in this section. These procedures are optional if you are only performing direct or indirect fuel-flow measurement, but we will perform carbon balance error verification for all testing under this section.
(8) Do not apply accessory loads when conducting a powertrain test to generate inputs to GEM if torque is measured at the axle input shaft or wheel hubs.
(9) If you test a powertrain over the Low Load Cycle specified in § 1036.514, control and apply the electrical accessory loads. We recommend using a load bank connected directly to the powertrain's electrical system. You may instead use an alternator with dynamic electrical load control. Use good engineering judgment to account for the efficiency of the alternator or the efficiency of the powertrain to convert the mechanical energy to electrical energy.
(10) The following instruments are required with plug-in hybrid systems to determine required voltages and currents during testing and must be installed on the powertrain to measure these values during testing:
(i) Measure the voltage and current of the battery pack directly with a DC wideband power analyzer to determine power. Measure all current entering and leaving the battery pack. Do not measure voltage upstream of this measurement point. The maximum integration period for determining amp-hours is 0.05 seconds. The power analyzer must have an accuracy for measuring current and voltage of 1% of point or 0.3% of maximum, whichever is greater. The power analyzer must not be susceptible to offset errors while measuring current.
(ii) If safety considerations do not allow for measuring voltage, you may determine the voltage directly from the powertrain ECM.
(11) The following figure provides an overview of testing under this section:

Figure 1 to Paragraph (a)(11) of § 1036.545—Overview of Powertrain Testing.
(b) Test configuration. Select a powertrain for testing as described in § 1036.235 or 40 CFR 1037.235 as applicable. Set up the engine according to 40 CFR 1065.110 and 1065.405(b). Set the engine's idle speed to idle speed defined in 40 CFR 1037.520(h)(1).
(1) The default test configuration consists of a powertrain with all components upstream of the axle. This involves connecting the powertrain's output shaft directly to the dynamometer or to a gear box with a fixed gear ratio and measuring torque at the axle input shaft. You may instead set up the dynamometer to connect at the wheel hubs and measure torque at that location. The preceding sentence may apply if your powertrain configuration requires it, such as for hybrid powertrains or if you want to represent the axle performance with powertrain test results. You may alternatively test the powertrain with a chassis dynamometer if you measure speed and torque at the powertrain's output shaft or wheel hubs.
(2) For testing hybrid engines, connect the engine's crankshaft directly to the dynamometer and measure torque at that location.
(c) Powertrain temperatures during testing. Cool the powertrain during testing so temperatures for oil, coolant, block, head, transmission, battery, and power electronics are within the manufacturer's expected ranges for normal operation. You may use electronic control module outputs to comply with this paragraph (c). You may use auxiliary coolers and fans.
(d) Engine break in. Break in the engine according to 40 CFR 1065.405(c), the axle assembly according to 40 CFR 1037.560, and the transmission according to 40 CFR 1037.565. You may instead break in the powertrain as a complete system using the engine break in procedure in 40 CFR 1065.405(c).
(e) Dynamometer setup. Set the dynamometer to operate in speed-control mode (or torque-control mode for hybrid engine testing at idle, including idle portions of transient duty cycles). Record data as described in 40 CFR 1065.202. Command and control the dynamometer speed at a minimum of 5 Hz, or 10 Hz for testing hybrid engines. Run the vehicle model to calculate the dynamometer setpoints at a rate of at least 100 Hz. If the dynamometer's command frequency is less than the vehicle model dynamometer setpoint frequency, subsample the calculated setpoints for commanding the dynamometer setpoints.
(f) Driveline and vehicle model. Use the GEM HIL model's driveline and vehicle submodels or the equations in this paragraph (f) to calculate the dynamometer speed setpoint, f nref,dyno , based on the torque measurement location. For all powertrains, configure GEM with the accessory load set to zero. For hybrid engines, configure GEM with the applicable accessory load as specified in §§ 1036.505, 1036.514, and 1036.525. For all powertrains and hybrid engines, configure GEM with the tire slip model disabled.
(1) Driveline model with a transmission in hardware. For testing with torque measurement at the axle input shaft or wheel hubs, calculate, f nref,dyno , using the GEM HIL model's driveline submodel or the following equation:
Eq. 1036.545-1
Where:
k a[speed] = drive axle ratio as determined in paragraph (h) of this section. Set k a[speed] equal to 1.0 if torque is measured at the wheel hubs.
v refi = simulated vehicle reference speed as calculated in paragraph (f)(3) of this section.
r [speed] = tire radius as determined in paragraph (h) of this section.
(2) Driveline model with a simulated transmission. For testing with the torque measurement at the engine's crankshaft, f nref,dyno is the dynamometer target speed from the GEM HIL model's transmission submodel. You may request our approval to change the transmission submodel, as long as the changes do not affect the gear selection logic. Before testing, initialize the transmission model with the engine's measured torque curve and the applicable steady-state fuel map from the GEM HIL model. You may request our approval to input your own steady-state fuel map. For example, this request for approval could include using a fuel map that represents the combined performance of the engine and hybrid components. Configure the torque converter to simulate neutral idle when using this procedure to generate engine fuel maps in § 1036.505 or to perform the Supplemental Emission Test (SET) testing under § 1036.510. You may change engine commanded torque at idle to better represent CITT for transient testing under § 1036.512. You may change the simulated engine inertia to match the inertia of the engine under test. We will evaluate your requests under this paragraph (f)(2) based on your demonstration that the adjusted testing better represents in-use operation.
(i) The transmission submodel needs the following model inputs:
(A) Torque measured at the engine's crankshaft.
(B) Engine estimated torque determined from the electronic control module or by converting the instantaneous operator demand to an instantaneous torque in N·m.
(C) Dynamometer mode when idling (speed-control or torque-control).
(D) Measured engine speed when idling.
(E) Transmission output angular speed, f ni,transmission , calculated as follows:
Eq. 1036.545-2
Where:
k a[speed] = drive axle ratio as determined in paragraph (h) of this section.
v refi = simulated vehicle reference speed as calculated in paragraph (f)(3) of this section.
r [speed] = tire radius as determined in paragraph (h) of this section.
(ii) The transmission submodel generates the following model outputs:
(A) Dynamometer target speed.
(B) Dynamometer idle load.
(C) Transmission engine load limit.
(D) Engine speed target.
(3) Vehicle model. Calculate the simulated vehicle reference speed, ν refi , using the GEM HIL model's vehicle submodel or the equations in this paragraph (f)(3):
Eq. 1036.545-3
Where:
i = a time-based counter corresponding to each measurement during the sampling period.
Let v ref1 = 0; start calculations at i = 2. A 10-minute sampling period will generally involve 60,000 measurements.
T = instantaneous measured torque at the axle input, measured at the wheel hubs, or simulated by the GEM HIL model's transmission submodel. For configurations with multiple torque measurements, such as when measuring torque at the wheel hubs, T is the sum of all torque measurements.
Eff axle = axle efficiency. Use Eff axle = 0.955 for T ≥ 0, and use Eff axle = 1/0.955 for T < 0.
Use Eff axle = 1.0 if torque is measured at the wheel hubs.
M = vehicle mass for a vehicle class as determined in paragraph (h) of this section.
g = gravitational constant = 9.80665 m/s ^2 .
C rr = coefficient of rolling resistance for a vehicle class as determined in paragraph (h) of this section.
G i -1 = the percent grade interpolated at distance, D i -1, from the duty cycle in 40 CFR part 1037, appendix D, corresponding to measurement ( i -1).
Eq. 1036.545-4
ρ = air density at reference conditions. Use ρ = 1.1845 kg/m ^3 .
C dA = drag area for a vehicle class as determined in paragraph (h) of this section.
F brake, i -1 = instantaneous braking force applied by the driver model.
F grade , i -1 = M · g · sin(atan( G i -1 ))
Eq. 1036.545-5
Δt = the time interval between measurements. For example, at 100 Hz, Δt = 0.0100 seconds.
M rotating = inertial mass of rotating components. Let M rotating = 340 kg for vocational Light HDV or vocational Medium HDV. See paragraph (h) of this section for tractors and for vocational Heavy HDV.
(4) Example. The following example illustrates a calculation of f nref,dyno using paragraph (f)(1) of this section where torque is measured at the axle input shaft. This example is for a vocational Light HDV or vocational Medium HDV with 6 speed automatic transmission at B speed (test 4 in table 1 to paragraph (h)(2)(ii) of this section).
k aB = 4.0
r B = 0.399 m
T 999 = 500.0 N·m
C rr = 7.7 N/kN = 7.7·10 −3 N/N
M = 11408 kg
C dA = 5.4 m ^2
G 999 = 0.39% = 0.0039
F brake,999 = 0 N
v ref,999 = 20.0 m/s
F grade,999 = 11408 · 9.81 · sin(atan(0.0039)) = 436.5 N
Δ t = 0.0100 s
M rotating = 340 kg
v ref1000 =
(g) Driver model. Use the GEM HIL model's driver submodel or design a driver model to simulate a human driver modulating the throttle and brake pedals. In either case, tune the model to follow the test cycle as closely as possible meeting the following specifications:
(1) The driver model must meet the following speed requirements:
(i) For operation over the highway cruise cycles, the speed requirements described in 40 CFR 1066.425(b) and (c).
(ii) For operation over the Heavy-Duty Transient Test Cycle specified in 40 CFR part 1037, appendix A, the SET as defined § 1036.510, the Federal Test Procedure (FTP) as defined in § 1036.512, and the Low Load Cycle (LLC) as defined in § 1036.514, the speed requirements described in 40 CFR 1066.425(b) and (c).
(iii) The exceptions in 40 CFR 1066.425(b)(4) apply to the highway cruise cycles, the Heavy-Duty Transient Test Cycle specified in 40 CFR part 1037, appendix A, SET, FTP, and LLC.
(iv) If the speeds do not conform to these criteria, the test is not valid and must be repeated.
(2) Send a brake signal when operator demand is zero and vehicle speed is greater than the reference vehicle speed from the test cycle. Include a delay before changing the brake signal to prevent dithering, consistent with good engineering judgment.
(3) Allow braking only if operator demand is zero.
(4) Compensate for the distance driven over the duty cycle over the course of the test. Use the following equation to perform the compensation in real time to determine your time in the cycle:
Eq. 1036.545-6
Where:
v vehicle = measured vehicle speed.
v cycle = reference speed from the test cycle. If v cycle, i -1 < 1.0 m/s, set v cycle, i -1 = v vehicle, i -1.
(h) Vehicle configurations to evaluate for generating fuel maps as defined in § 1036.505. Configure the driveline and vehicle models from paragraph (f) of this section in the test cell to test the powertrain. Simulate multiple vehicle configurations that represent the range of intended vehicle applications using one of the following options:
(1) For known vehicle configurations, use at least three equally spaced axle ratios or tire sizes and three different road loads (nine configurations), or at least four equally spaced axle ratios or tire sizes and two different road loads (eight configurations). Select axle ratios to represent the full range of expected vehicle installations. Select axle ratios and tire sizes such that the ratio of engine speed to vehicle speed covers the range of ratios of minimum and maximum engine speed to vehicle speed when the transmission is in top gear for the vehicles in which the powertrain will be installed. Note that you do not have to use the same axle ratios and tire sizes for each GEM regulatory subcategory. You may determine appropriate C rr , C d A , and mass values to cover the range of intended vehicle applications or you may use the C rr,
C d A , and mass values specified in paragraph (h)(2) of this section.
(2) If vehicle configurations are not known, determine the vehicle model inputs for a set of vehicle configurations as described in § 1036.540(c)(3) with the following exceptions:
(i) In the equations of § 1036.540(c)(3)(i), k topgear is the actual top gear ratio of the powertrain instead of the transmission gear ratio in the highest available gear given in table 1 to paragraph (c)(2) of § 1036.540.
(ii) Test at least eight different vehicle configurations for powertrains that will be installed in Spark-ignition HDE, vocational Light HDV, and vocational Medium HDV using the following table instead of table 2 to paragraph (c)(3)(ii) of § 1036.540:

TABLE 1 TO PARAGRAPH (h)(2)(ii) OF § 1036.545—VEHICLE CONFIGURATIONS FOR TESTING SPARK-IGNITION HDE, AND MEDIUM HDE
(iii) Select and test vehicle configurations as described in § 1036.540(c)(3)(iii) for powertrains that will be installed in vocational Heavy HDV and tractors using the following tables instead of tables 3 and 4 to paragraph (c)(3)(iii) of § 1036.540:

TABLE 2 TO PARAGRAPH (h)(2)(iii) OF § 1036.545—VEHICLE CONFIGURATIONS FOR TESTING GENERAL PURPOSE TRACTORS AND VOCATIONAL HEAVY HDV

TABLE 3 TO PARAGRAPH (h)(2)(iii) of § 1036.545—VEHICLE CONFIGURATIONS FOR TESTING HEAVY HDE INSTALLED IN HEAVY-HAUL TRACTORS
(3) For hybrid powertrain systems where the transmission will be simulated, use the transmission parameters defined in § 1036.540(c)(2) to determine transmission type and gear ratio. Use a fixed transmission efficiency of 0.95. The GEM HIL transmission model uses a transmission parameter file for each test that includes the transmission type, gear ratios, lockup gear, torque limit per gear from § 1036.540(c)(2), and the values from § 1036.505(b)(4) and (c).
(i) [Reserved]
(j) Duty cycles to evaluate. Operate the powertrain over each of the duty cycles specified in 40 CFR 1037.510(a)(2), and for each applicable vehicle configuration from paragraph (h) of this section. Determine cycle-average powertrain fuel maps by testing the powertrain using the procedures in § 1036.540(d) with the following exceptions:
(1) Understand “engine” to mean “powertrain”.
(2) Warm up the powertrain as described in § 1036.520(d).
(3) Within 90 seconds after concluding the warm-up, start the transition to the preconditioning cycle as described in paragraph (j)(5) of this section.
(4) For plug-in hybrid engines, precondition the battery and then complete all back-to-back tests for each vehicle configuration according to 40 CFR 1066.501(a)(3) before moving to the next vehicle configuration. The following figure illustrates a charge-depleting test sequence with engine operation during two duty cycles, which are used for criteria pollutant determination:

Figure 2 to Paragraph (j)(4) of § 1036.545—Generic Charge-Depleting Test Sequence
(5) If the preceding duty cycle does not end at 0 mi/hr, transition between duty cycles by decelerating at a rate of 2 mi/hr/s at 0% grade until the vehicle reaches zero speed. Shut off the powertrain. Prepare the powertrain and test cell for the next duty-cycle.
(6) Start the next duty-cycle within 60 to 180 seconds after shutting off the powertrain.
(i) To start the next duty-cycle, for hybrid powertrains, key on the vehicle and then start the duty-cycle. For conventional powertrains key on the vehicle, start the engine, wait for the engine to stabilize at idle speed, and then start the duty-cycle.
(ii) If the duty-cycle does not start at 0 mi/hr, transition to the next duty cycle by accelerating at a target rate of 1 mi/hr/s at 0% grade. Stabilize for 10 seconds at the initial duty cycle conditions and start the duty-cycle.
(7) Calculate cycle work using GEM or the speed and torque from the driveline and vehicle models from paragraph (f) of this section to determine the sequence of duty cycles.
(8) Calculate the mass of fuel consumed for idle duty cycles as described in paragraph (n) of this section.
(k) Measuring NO X
emissions. Measure NO X emissions for each sampling period in grams. You may perform these measurements using a NO X emission-measurement system that meets the requirements of 40 CFR part 1065, subpart J. If a system malfunction prevents you from measuring NO X emissions during a test under this section but the test otherwise gives valid results, you may consider this a valid test and omit the NO X emission measurements; however, we may require you to repeat the test if we determine that you inappropriately voided the test with respect to NO X emission measurement.
(l) [Reserved]
(m) Measured output speed validation. For each test point, validate the measured output speed with the corresponding reference values. If speed is measured at more than one location, the measurements at each location must meet validation requirements. If the range of reference speed is less than 10 percent of the mean reference speed, you need to meet only the standard error of the estimate in table 4 to this paragraph (m). You may delete points when the vehicle is stopped. If your speed measurement is not at the location of ƒ nref , correct your measured speed using the constant speed ratio between the two locations. Apply cycle-validation criteria for each separate transient or highway cruise cycle based on the following parameters:
Table 4 to Paragraph ( m ) of § 1036.545—Cycle-Validation Criteria
Parameter ^a | Speed control
Slope, a 1 | 0.990 ≤ a 1 ≤ 1.010.
Absolute value of intercept, | a 0 | | ≤2.0% of maximum ƒ nref speed.
Standard error of the estimate, SEE | ≤2.0% of maximum ƒ nref speed.
Coefficient of determination, r ^2 | ≥0.990.
^a Determine values for specified parameters as described in 40 CFR 1065.514(e) by comparing measured and reference values for ƒ nref,dyno .
(n) Fuel consumption at idle. Record measurements using direct and/or indirect measurement of fuel flow. Determine the fuel-consumption rates at idle for the applicable duty cycles described in 40 CFR 1037.510(a)(2) as follows:
(1) Direct fuel flow measurement. Determine the corresponding mean values for mean idle fuel mass flow rate, m fuelidle , for each duty cycle, as applicable. Use of redundant direct fuel-flow measurements require our advance approval.
(2) Indirect fuel flow measurement. Record speed and torque and measure emissions and other inputs needed to run the chemical balance in 40 CFR 1065.655(c). Determine the corresponding mean values for each duty cycle. Use of redundant indirect fuel-flow measurements require our advance approval. Measure background concentration as described in § 1036.535(b)(4)(ii). We recommend setting the CVS flow rate as low as possible to minimize background, but without introducing errors related to insufficient mixing or other operational considerations. Note that for this testing 40 CFR 1065.140(e) does not apply, including the minimum dilution ratio of 2:1 in the primary dilution stage. Calculate the idle fuel mass flow rate for each duty cycle, m fuelidle , for each set of vehicle settings, as follows:
Eq. 1036.545-7
Where:
M C = molar mass of carbon.
w Cmeas = carbon mass fraction of fuel (or mixture of test fuels) as determined in 40 CFR 1065.655(d), except that you may not use the default properties in 40 CFR 1065.655(e)(5) to determine α, β, and w C for liquid fuels.
n exh = the mean raw exhaust molar flow rate from which you measured emissions according to 40 CFR 1065.655.
χ Ccombdry = the mean concentration of carbon from fuel and any injected fluids in the exhaust per mole of dry exhaust.
χ H2Oexhdry = the mean concentration of H 2 O in exhaust per mole of dry exhaust.
m CO2DEF = the mean CO 2 mass emission rate resulting from diesel exhaust fluid decomposition over the duty cycle as determined in § 1036.535(b)(9). If your engine does not use diesel exhaust fluid, or if you choose not to perform this correction, set equal to 0.
M CO2 = molar mass of carbon dioxide.
Example:
M C = 12.0107 g/mol
w Cmeas = 0.867
n exh = 25.534 mol/s
χ Ccombdry = 2.805·10 −3 mol/mol
χ H2Oexhdry = 3.53·10 −2 mol/mol
m CO2DEF = 0.0726 g/s
M CO2 = 44.0095
(o) Create GEM inputs. Use the results of powertrain testing to determine GEM inputs for the different simulated vehicle configurations as follows:
(1) Correct the measured or calculated fuel masses, m fuel[cycle] , and mean idle fuel mass flow rates, m fuelidle , if applicable, for each test result to a mass-specific net energy content of a reference fuel as described in § 1036.535(e), replacing m fuel with m fuel[cycle] where applicable in Eq. 1036.535-4.
(2) Declare fuel masses, m fuel[cycle] and m fuelidle . Determine m fuel[cycle] using the calculated fuel mass consumption values described in § 1036.540(d)(12). In addition, declare mean fuel mass flow rate for each applicable idle duty cycle, m fuelidle . These declared values may not be lower than any corresponding measured values determined in this section. If you use both direct and indirect measurement of fuel flow, determine the corresponding declared values as described in § 1036.535(g)(2) and (3). These declared values, which serve as emission standards, collectively represent the powertrain fuel map for certification.
(3) For engines designed for plug-in hybrid electric vehicles, the mass of fuel for each cycle, m fuel[cycle] , is the utility factor-weighted fuel mass, m fuelUF[cycle] . This is determined by calculating m fuel for the full charge-depleting and charge-sustaining portions of the test and weighting the results, using the following equation:
Eq. 1036.545-8
Where:
i = an indexing variable that represents one test interval.
N = total number of charge-depleting test intervals.
m fuel[cycle]CD i = total mass of fuel in the charge-depleting portion of the test for each test interval, i , starting from i = 1, including the test interval(s) from the transition phase.
UF DCD i = utility factor fraction at distance D CD i from Eq. 1036.510-11 as determined by interpolating the approved utility factor curve for each test interval, i, starting from i = 1. Let UF DCD0 = 0
j = an indexing variable that represents one test interval.
M = total number of charge-sustaining test intervals.
m fuel[cycle]CS j = total mass of fuel over the charge-sustaining portion of the test for each test interval, j , starting from j = 1.
UF RCD = utility factor fraction at the full charge-depleting distance, R CD, as determined by interpolating the approved utility factor curve. R CD is the cumulative distance driven over N charge-depleting test intervals.
Eq. 1036.545-9
Where:
k = an indexing variable that represents one recorded velocity value.
Q = total number of measurements over the test interval.
v = vehicle velocity at each time step, k , starting from k = 1. For tests completed under this section, v is the vehicle velocity as determined by Eq. 1036.545-1. Note that this should include charge- depleting test intervals that start when the engine is not yet operating.
Δ t = 1/ƒ record
ƒ record = the record rate.
Example for the 55 mi/hr cruise cycle:
Q = 8790
y 1 = 55.0 mi/hr
y 2 = 55.0 mi/hr
y 3 = 55.1 mi/hr
ƒ record = 10 Hz
Δ t = 1/10 Hz = 0.1 s
(4) For the transient cycle specified in 40 CFR 1037.510(a)(2)(i), calculate powertrain output speed per unit of vehicle speed using one of the following methods:
(i) For testing with torque measurement at the axle input shaft:

Eq. 1036.545-10
Example:
(ii) For testing with torque measurement at the wheel hubs, use Eq. 1036.545-8 setting k a equal to 1.
(iii) For testing with torque measurement at the engine's crankshaft:
Eq. 1036.545-11
Where:
ƒ nengine = average engine speed when vehicle speed is at or above 0.100 m/s.
y ref = average simulated vehicle speed at or above 0.100 m/s.
Example:
(5) Calculate engine idle speed, by taking the average engine speed measured during the transient cycle test while the vehicle speed is below 0.100 m/s. (Note: Use all the charge-sustaining test intervals when determining engine idle speed for plug-in hybrid powertrains.)ƒ
(6) For the cruise cycles specified in 40 CFR 1037.510(a)(2)(ii), calculate the average powertrain output speed, ƒ npowertrain , and the average powertrain output torque (positive torque only), T powertrain , at vehicle speed at or above 0.100 m/s. (Note: Use all the charge-sustaining and charge-depleting test intervals when determining ƒ npowertrain and T powertrain for plug-in hybrid powertrains.)
(7) Calculate positive work, W [cycle], as the work over the duty cycle at the axle input shaft, wheel hubs, or the engine's crankshaft, as applicable, when vehicle speed is at or above 0.100 m/s. For plug-in hybrid powertrains, calculate W [cycle] by calculating the positive work over each of the charge-sustaining and charge-depleting test intervals and then averaging them together. If speed and torque are measured at more than one location, determine W [cycle] by integrating the sum of the power calculated from measured speed and torque measurements at each location.
(8) The following tables illustrate the GEM data inputs corresponding to the different vehicle configurations for a given duty cycle:
(i) For the transient cycle:

Table 5 to Paragraph (o)(8)(i) of § 1036.545—Example of Output Matrix for Transient Cycle Vehicle Configurations
(ii) For the cruise cycles:

Table 6 to Paragraph ((o)(8)(ii) of § 1036.545—Generic Example of Output Matrix for Cruise Cycle Vehicle Configurations
(p) Determine usable battery energy. Determine usable battery energy (UBE) for plug-in hybrid powertrains using one of the following procedures:
(1) Select a representative vehicle configuration from paragraph (h) of this section. Measure DC discharge energy, E DCD, in DC watt-hours and measure DC discharge current per hour, C D, for the charge-depleting test intervals of the Heavy-Duty Transient Test Cycle in 40 CFR part 1037, appendix A. The measurement period must include all the current flowing into and out of the battery pack during the charge-depleting test intervals, including current associated with regenerative braking. Eq. 1036.545-12 shows how to calculate E DCD, but the power analyzer specified in paragraph (a)(10)(i) of this section will typically perform this calculation internally. Battery voltage measurements made by the powertrain's on-board sensors (such as those available with a diagnostic port) may be used for calculating E DCD if they are equivalent to those from the power analyzer.
Eq. 1036.545-12
Where:
i = an indexing variable that represents one individual measurement.
N = total number of measurements.
V = battery DC bus voltage.
I = battery current.
Δ t = 1/ƒ record
ƒ record = the data recording frequency.
Example:
N = 13360
V 1 = 454.0
V 2 = 454. 0
I 1 = 0
I 2 = 0
ƒ record = 20 Hz
Δ t = 1/20 = 0.05 s
(2) Determine a declared UBE that is at or below the corresponding value determined in paragraph (p)(1) of this section, including those from redundant measurements. This declared UBE serves as UBE certified determined under 40 CFR 1037.115(f).
35. Amend § 1036.550 by:
a. Revising paragraphs (b)(1) and (2); and
b. Revising the entry for w Cmeas in paragraph (b)(4) after the “Example”.
The revisions read as follows:
§ 1036.550
Calculating greenhouse gas emission rates.
* * * * *
(b) * * *
(1) Determine your test fuel's mass-specific net energy content, E mfuelmeas, also known as lower heating value, in MJ/kg, expressed to at least three decimal places. Determine E mfuelmeas as follows:
(i) For liquid fuels, determine E mfuelmeas according to ASTM D4809 (incorporated by reference, see § 1036.810). Have the sample analyzed by at least three different labs and determine the final value of your test fuel's E mfuelmeas as the median of all the lab test results as described in 40 CFR 1065.602(m). If you have results from three different labs, we recommend you screen them to determine if additional observations are needed. To perform this screening, determine the absolute value of the difference between each lab result and the average of the other two lab results. If the largest of these three resulting absolute value differences is greater than 0.297 MJ/kg, we recommend you obtain additional results prior to determining the final value of E mfuelmeas.
(ii) For gaseous fuels, determine E mfuelmeas according to ASTM D3588 (incorporated by reference, see § 1036.810).
(2) Determine your test fuel's carbon mass fraction, w C, as described in 40 CFR 1065.655(d), expressed to at least three decimal places; however, you must measure fuel properties for α and β rather than using the default values specified in 40 CFR 1065.655(e).
(i) For liquid fuels, have the sample analyzed by at least three different labs, determine w C for each result as described in 40 CFR 1065.655(d), and determine the final value of your test fuel's w C as the median (as described in 40 CFR 1065.602(m)) of all the w C values. If you have results from three different labs, we recommend you screen them to determine if additional observations are needed. To perform this screening, determine the absolute value of the difference between each w C value and the average of the other two w C values. If the largest of these three resulting absolute value differences is greater than 1.56 percent carbon, we recommend you obtain additional results prior to determining the final value of w C.
(ii) For gaseous fuels, have the sample analyzed by a single lab and use that result as your test fuel's w C.
* * * * *
(4) * * *
w Cmeas = 0.870 kgC/kg
* * * * *
36. Amend § 1036.580 by adding paragraph (d) to read as follows:
§ 1036.580
Infrequently regenerating aftertreatment devices.
* * * * *
(d) If your engine family includes engines with one or more emergency AECDs approved under § 1036.115(h)(4), do not consider additional regenerations resulting from those AECDs when developing adjustments to measured values under paragraph (a) or (b) of this section.
37. Amend § 1036.601 by revising paragraph (c) to read as follows:
§ 1036.601
Overview of compliance provisions.
* * * * *
(c) The emergency vehicle field modification provisions of 40 CFR 85.1716 apply with respect to the standards of this part. Emergency vehicle field modifications under 40 CFR 85.1716 may include corresponding changes to diagnostic systems relative to the requirements in §§ 1036.110 and 1036.111. For example, the cab display required under § 1036.110(c)(1) identifying a fault condition may omit information about the timing or extent of a pending derate if an AECD will override the derate.
* * * * *
38. Amend § 1036.605 by revising paragraph (e) to read as follows:
§ 1036.605
Alternate emission standards for engines used in specialty vehicles.
* * * * *
(e) In a separate application for a certificate of conformity, identify the corresponding nonroad engine family, describe the label required under section, state that you meet applicable diagnostic requirements under 40 CFR part 1039 or 1048, and identify your projected U.S.-directed production volume.
* * * * *
39. Amend § 1036.615 by revising paragraph (a) to read as follows:
§ 1036.615
Engines with Rankine cycle waste heat recovery and hybrid powertrains.
* * * * *
(a) Pre-transmission hybrid powertrains. Test pre-transmission hybrid powertrains with the hybrid engine procedures of 40 CFR part 1065 or with the post-transmission procedures in § 1036.545. Pre-transmission hybrid powertrains are those engine systems that include features to recover and store energy during engine motoring operation but not from the vehicle's wheels. Engines certified with pre-transmission hybrid powertrains must be certified to meet the diagnostic requirements as specified in § 1036.110 with respect to powertrain components and systems; if different manufacturers produce the engine and the hybrid powertrain, the hybrid powertrain manufacturer may separately certify its powertrain relative to diagnostic requirements.
* * * * *
40. Amend § 1036.630 by revising paragraph (b) to read as follows:
§ 1036.630
Certification of engine greenhouse gas emissions for powertrain testing.
* * * * *
(b) If you choose to certify only fuel map emissions for an engine family and to not certify emissions over powertrain cycles under § 1036.545, we will not presume you are responsible for emissions over the powertrain cycles. However, where we determine that you are responsible in whole or in part for the emission exceedance in such cases, we may require that you participate in any recall of the affected vehicles (Note: this does not apply if you also hold the certificate of conformity for the vehicle).
* * * * *
41. Amend § 1036.705 by revising paragraph (c) to read as follows:
§ 1036.705
Generating and calculating emission credits.
* * * * *
(c) Compliance with the requirements of this subpart is determined at the end of the model year by calculating emission credits based on actual production volumes, excluding the following engines:
(1) Engines that you do not certify to the CO 2 standards of this part because they are permanently exempted under subpart G of this part or under 40 CFR part 1068.
(2) Exported engines.
(3) Engines not subject to the requirements of this part, such as those excluded under § 1036.5. For example, do not include engines used in vehicles certified to the greenhouse gas standards of 40 CFR 86.1819.
(4) Engines certified to state emission standards that are different than the emission standards referenced in this section, and intended for sale in a state that has adopted those emission standards.
(5) Any other engines if we indicate elsewhere in this part that they are not to be included in the calculations of this subpart.
* * * * *
42. Amend § 1036.725 by revising paragraph (b)(2) to read as follows:
§ 1036.725
Required information for certification.
* * * * *
(b) * * *
(2) Calculations of projected emission credits (positive or negative) based on projected production volumes as described in § 1036.705(c). We may require you to include similar calculations from your other engine families to project your net credit balances for the model year. If you project negative emission credits for a family, state the source of positive emission credits you expect to use to offset the negative emission credits.
43. Amend § 1036.730 by revising paragraphs (b)(4) and (f)(1) to read as follows:
§ 1036.730
ABT reports.
* * * * *
(b) * * *
(4) The projected and actual production volumes for calculating emission credits for the model year. If you changed an FEL/FCL during the model year, identify the actual production volume associated with each FEL/FCL.
* * * * *
(f) * * *
(1) If you notify us by the deadline for submitting the final report that errors mistakenly decreased your balance of emission credits, you may correct the errors and recalculate the balance of emission credits. If you notify us that errors mistakenly decreased your balance of GHG emission credits after the deadline for submitting the final report, you may correct the errors and recalculate the balance of emission credits after applying a 10 percent discount to the credit correction, but only if you notify us within 24 months after the deadline for submitting the final report. If you report a negative balance of emission credits, we may disallow corrections under this paragraph (f)(1).
* * * * *
44. Amend § 1036.735 by revising paragraph (d) to read as follows:
§ 1036.735
Recordkeeping.
* * * * *
(d) Keep appropriate records to document production volumes of engines that generate or use emission credits under the ABT program. For example, keep available records of the engine identification number (usually the serial number) for each engine you produce that generates or uses emission credits. You may identify these numbers as a range. If you change the FEL/FCL after the start of production, identify the date you started using each FEL/FCL and the range of engine identification numbers associated with each FEL/FCL. You must also identify the purchaser and destination for each engine you produce to the extent this information is available.
* * * * *
45. Amend § 1036.801 by:
a. Adding a definition of “Carbon-containing fuel” in alphabetical order;
b. Removing the definition of “Criteria pollutants”;
c. Revising the definition of “Emergency vehicle”;
d. Removing the definition of “Greenhouse gas”;
e. Revising the definition of “Hybrid”;
f. Removing the definitions of “Hybrid engine” and “Hybrid powertrain”;
g. Revising the definition of “Mild hybrid”;
h. Adding a definition of “Neat” in alphabetical order;
i. Revising the definition of “Small manufacturer”;
j. Adding a definition of “State of certified energy (SOCE)” in alphabetical order; and
k. Revising the definition of “U.S.-directed production volume”.
The additions and revisions read as follows:
§ 1036.801
Definitions.
* * * * *
Carbon-containing fuel has the meaning given in 40 CFR 1065.1001.
* * * * *
Emergency vehicle means a vehicle that meets one of the following criteria:
(1) It is an ambulance or a fire truck.
(2) It is a vehicle that we have determined will likely be used in emergency situations where emission control function or malfunction may cause a significant risk to human life. For example, we would consider a truck that is certain to be retrofitted with a slip-on firefighting module to become an emergency vehicle, even though it was not initially designed to be a fire truck. Also, a mobile command center that is unable to manually regenerate its DPF while on duty could be an emergency vehicle. In making this determination, we may consider any factor that has an effect on the totality of the actual risk to human life. For example, we may consider how frequently a vehicle will be used in emergency situations or how likely it is that the emission controls will cause a significant risk to human life when the vehicle is used in emergency situations. We would not consider the truck in the example above to be an emergency vehicle if there is merely a possibility (rather than a certainty) that it will be retrofitted with a slip-on firefighting module.
* * * * *
Hybrid means relating to an engine or powertrain that includes a Rechargeable Energy Storage System. Hybrid engines store and recover energy in a way that is integral to the engine or otherwise upstream of the vehicle's transmission. Examples of hybrid engines include engines with hybrid components connected to the front end of the engine (P0), connected to the crankshaft before the clutch (P1), or connected between the clutch and the transmission where the clutch upstream of the hybrid feature is in addition to the transmission clutch or clutches (P2). Engine-based systems that recover kinetic energy to power an electric heater in the aftertreatment are themselves not sufficient to qualify as a hybrid engine. The provisions in this part that apply for hybrid powertrains apply equally for hybrid engines, except as specified. Note that certain provisions in this part treat hybrid powertrains intended for vehicles that include regenerative braking different than those intended for vehicles that do not include regenerative braking. The definition of hybrid includes plug-in hybrid electric powertrains.
* * * * *
Mild hybrid means relating to a hybrid engine or hybrid powertrain with regenerative braking capability where the system recovers less than 20 percent of the total braking energy over the transient cycle defined in 40 CFR part 1037, appendix A.
* * * * *
Neat has the meaning given in 40 CFR 1065.1001.
* * * * *
Small manufacturer means a manufacturer meeting the criteria specified in 13 CFR 121.201. The employee and revenue limits apply to the total number of employees and total revenue together for all affiliated companies (as defined in 40 CFR 1068.30). Note that manufacturers with low production volumes may or may not be “small manufacturers”.
* * * * *
State of certified energy (SOCE) means a value representing the amount of usable battery energy available at a specific point in time relative to the certified value for a new battery, expressed as a percentage of the certified usable battery energy.
* * * * *
U.S.-directed production volume means the number of engines, subject to the requirements of this part, produced by a manufacturer for which the manufacturer has a reasonable assurance that sale was or will be made to ultimate purchasers in the United States.
* * * * *
46. Amend § 1036.805 by revising the introductory text and adding entries for “DPF” and “GCWR” in alphabetical order to table 5 to paragraph (e) to read as follows:
§ 1036.805
Symbols, abbreviations, and acronyms.
The procedures in this part generally follow either the International System of Units (SI) or the United States customary units, as detailed in NIST Special Publication 811 (incorporated by reference, see § 1036.810). See 40 CFR 1065.20 for specific provisions related to these conventions. This section summarizes the way we use symbols, units of measure, and other abbreviations.
* * * * *
(e) * * *
Table 5 to Paragraph ( e ) of § 1036.805—Other Acronyms and Abbreviations
Acronym | Meaning
* * * * *
DPF | diesel particulate filter.
* * * * *
GCWR | gross combined weight rating.
* * * * *
* * * * *
47. Amend § 1036.810 by adding paragraph (e) to read as follows:
§ 1036.810
Incorporation by reference.
* * * * *
(e) U.S. EPA, Office of Air and Radiation, 2565 Plymouth Road, Ann Arbor, MI 48105; www.epa.gov; complianceinfo@epa.gov .
(1) Greenhouse gas Emissions Model (GEM) Phase 2, Version 4.0, April 2022 (“GEM Phase 2, Version 4.0”); IBR approved for § 1036.545(a).
(2) [Reserved]
48. Amend § 1036.815 by revising paragraph (b) to read as follows:
§ 1036.815
Confidential information.
* * * * *
(b) Emission data or information that is publicly available cannot be treated as confidential business information as described in 40 CFR 1068.11. Data that vehicle manufacturers need for demonstrating compliance with greenhouse gas emission standards, including fuel-consumption data as described in §§ 1036.535 and 1036.545, also qualify as emission data for purposes of confidentiality determinations.

PART 1037—CONTROL OF EMISSIONS FROM NEW HEAVY-DUTY MOTOR VEHICLES
49. The authority citation for part 1037 continues to read as follows:

Authority:
42 U.S.C. 7401-7671q.
50. Amend § 1037.1 by revising paragraph (a) to read as follows:
§ 1037.1
Applicability.
(a) The regulations in this part apply for all new heavy-duty vehicles, except as provided in § 1037.5. This includes battery electric vehicles, fuel cell electric vehicles, and vehicles fueled by conventional and alternative fuels.
* * * * *
51. Amend § 1037.5 by:
a. Revising paragraph (e);
b. Removing paragraphs (g) and (h); and
c. Redesignating paragraph (i) as paragraph (g).
The revision reads as follows:
§ 1037.5
Excluded vehicles.
* * * * *
(e) Vehicles subject to emission standards under 40 CFR part 86, subpart S.
* * * * *
52. Revise and republish § 1037.101 to read as follows:
§ 1037.101
Overview of emission standards.
(a) You must show that vehicles meet the following emission standards:
(1) Exhaust emissions of criteria pollutants. Criteria pollutant standards for NO X , HC, PM, and CO apply as described in § 1037.102. These pollutants are sometimes described collectively as “criteria pollutants” because they are either criteria pollutants under the Clean Air Act or precursors to the criteria pollutants ozone and PM.
(2) Exhaust emissions of greenhouse gases. This part contains standards and other regulations applicable to the emission of the air pollutant defined as the aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. Emission standards apply as follows for greenhouse gas emissions:
(i) CO 2 emission standards apply as described in §§ 1037.105 and 1037.106. No CH 4 or N 2 O standards apply under this part. See 40 CFR part 1036 for CH 4 or N 2 O standards that apply to engines used in these vehicles.
(ii) Hydrofluorocarbon standards apply as described in § 1037.115(e). These pollutants are also “greenhouse gas pollutants” but are treated separately from exhaust greenhouse gas pollutants listed in paragraph (a)(2)(i) of this section.
(3) Fuel evaporative and refueling emissions. Requirements related to fuel evaporative and refueling emissions are described in § 1037.103.
(b) The regulated heavy-duty vehicles are addressed in different groups as follows:
(1) For criteria pollutants, vehicles are regulated based on gross vehicle weight rating (GVWR), whether they are considered “spark-ignition” or “compression-ignition,” and whether they are first sold as complete or incomplete vehicles.
(2) Greenhouse gas standards apply differently for vocational vehicles and tractors. Greenhouse gas standards also apply differently depending on the vehicle service class as described in § 1037.140. In addition, standards apply differently for vehicles with spark-ignition and compression-ignition engines. References in this part to “spark-ignition” or “compression-ignition” generally relate to the application of standards under 40 CFR 1036.140. For example, a vehicle with an engine certified to spark-ignition standards under 40 CFR part 1036 is generally subject to requirements under this part that apply for spark-ignition vehicles. However, note that emission standards for Heavy HDE are considered to be compression-ignition standards for purposes of applying vehicle emission standards under this part. Also, for spark-ignition engines voluntarily certified as compression-ignition engines under 40 CFR part 1036, you must choose at certification whether your vehicles are subject to spark-ignition standards or compression-ignition standards. Heavy-duty vehicles with no installed propulsion engine, such as battery electric vehicles, are subject to compression-ignition emission standards under §§ 1037.105 and 1037.106 for the purpose of calculating emission credits.
(3) For evaporative and refueling emissions, vehicles are regulated based on the type of fuel they use. Vehicles fueled with volatile liquid fuels or gaseous fuels are subject to evaporative and refueling emission standards.
53. Amend § 1037.102 by revising the section heading and paragraph (b) introductory text to read as follows:
§ 1037.102
Criteria exhaust emission standards—NO X , HC, PM, and CO.
* * * * *
(b) Heavy-duty vehicles with no installed propulsion engine, such as battery electric vehicles, are subject to criteria pollutant standards under this part. The emission standards that apply are the same as the standards that apply for compression-ignition engines under 40 CFR 86.007-11 or 1036.104 for a given model year.
* * * * *
54. Amend § 1037.103 by revising paragraph (e) introductory text to read as follows:
§ 1037.103
Evaporative and refueling emission standards.
* * * * *
(e) LNG refueling requirement. Fuel tanks for liquefied natural gas vehicles must meet the hold-time requirements in Section 4.2 of SAE J2343 (incorporated by reference, see § 1037.810), as modified by this paragraph (e). All pressures noted are gauge pressure. Vehicles with tanks meeting the requirements in this paragraph (e) are deemed to comply with evaporative and refueling emission standards. The provisions of this paragraph (e) are optional for vehicles produced before January 1, 2020. The hold-time requirements of SAE J2343 apply, with the following clarifications and additions:
* * * * *
§ 1037.104
[Removed]
55. Remove § 1037.104.
56. Revise and republish § 1037.105 to read as follows:
§ 1037.105
CO 2 emission standards for vocational vehicles.
(a) The standards of this section apply for the following vehicles:
(1) Heavy-duty vehicles at or below 14,000 pounds GVWR that are not subject to the greenhouse gas standards in 40 CFR part 86, subpart S, or that use engines certified under § 1037.150(m).
(2) Vehicles above 14,000 pounds GVWR and at or below 26,000 pounds GVWR, but not certified to the vehicle greenhouse gas standards in 40 CFR part 86, subpart S.
(3) Vehicles above 26,000 pounds GVWR that are not tractors.
(4) Vocational tractors.
(b) CO 2 standards in this paragraph (b) apply based on modeling and testing as specified in subpart F of this part. The provisions of § 1037.241 specify how to comply with the standards in this paragraph (b). Standards differ based on engine cycle, vehicle size, and intended vehicle duty cycle. See § 1037.510(c) to determine which duty cycle applies. Note that § 1037.230 describes how to divide vehicles into subcategories.
(1) Except as specified in paragraph (b)(2) of this section, model year 2027 and later vehicles are subject to Phase 3 CO 2 standards corresponding to the selected subcategories as shown in the following table:
Table 1 of Paragraph ( b )(1) of § 1037.105—Phase 3 CO 2 Standards for Model Year 2027 and Later Vocational Vehicles
Model year | Roof height | CO 2 standard by regulatory subcategory (g/ton·mile) | Class 7 all cab styles | Class 8 day cab | Class 8 sleeper cab | Heavy-haul
2027 | Low Roof | 96.2 | 73.4 | 64.1 | 48.3
| Mid Roof | 103.4 | 78.0 | 69.6
| High Roof | 100.0 | 75.7 | 64.3
2028 | Low Roof | 88.5 | 67.5 | 64.1 | 48.3
| Mid Roof | 95.1 | 71.8 | 69.6
| High Roof | 92.0 | 69.6 | 64.3
2029 | Low Roof | 84.7 | 64.6 | 64.1 | 47.8
| Mid Roof | 91.0 | 68.6 | 69.6
| High Roof | 88.0 | 66.6 | 64.3
2030 | Low Roof | 80.8 | 61.7 | 60.3 | 47.8
| Mid Roof | 86.9 | 65.5 | 65.4
| High Roof | 84.0 | 63.6 | 60.4
2031 | Low Roof | 69.3 | 52.8 | 56.4 | 46.9
| | Mid Roof | 74.4 | 56.2 | 61.2
| High Roof | 72.0 | 54.5 | 56.6
2032 and Later | Low Roof | 57.7 | 44.0 | 48.1 | 45.9
| Mid Roof | 62.0 | 46.8 | 52.2
| High Roof | 60.0 | 45.4 | 48.2
(2) Qualifying small manufacturers of model year 2027 and later vehicles may continue to meet Phase 2 CO 2 standards in this paragraph (b)(2) instead of the standards specified in paragraph (b)(1) of this section. If you certify to these Phase 2 CO 2 standards, you may use the averaging provisions of subpart H of this part to demonstrate compliance. You may use other credit provisions of this part only by certifying all vehicle families within a given averaging set to the Phase 3 standards that apply in that model year.
Table 2 of Paragraph ( b )(2) of § 1037.105—Small Manufacturer Phase 2 CO 2 Standards for Model Year 2027 and Later Vocational Vehicles
Engine cycle | Vehicle service class | CO 2 standard by regulatory subcategory (g/ton·mile) | Multi-purpose | Regional | Urban
Compression-ignition | Light HDV | 330 | 291 | 367
Compression-ignition | Medium HDV | 235 | 218 | 258
Compression-ignition | Heavy HDV | 230 | 189 | 269
Spark-ignition | Light HDV | 372 | 319 | 413
Spark-ignition | Medium HDV | 268 | 247 | 297
(3) Model year 2024 through 2026 vehicles are subject to Phase 2 CO 2 standards corresponding to the selected subcategories as shown in the following table:
Table 3 of Paragraph ( b )(3) of § 1037.105—Phase 2 CO 2 Standards for Model Year 2024 Through 2026 Vocational Vehicles
Engine cycle | Vehicle service class | CO 2 standard by regulatory subcategory (g/ton·mile) | Multi-purpose | Regional | Urban
Compression-ignition | Light HDV | 344 | 296 | 385
Compression-ignition | Medium HDV | 246 | 221 | 271
Compression-ignition | Heavy HDV | 242 | 194 | 283
Spark-ignition | Light HDV | 385 | 324 | 432
Spark-ignition | Medium HDV | 279 | 251 | 310
(4) Model year 2021 through 2023 vehicles are subject to Phase 2 CO 2 standards corresponding to the selected subcategories as shown in the following table:
Table 4 of Paragraph ( b )(4) of § 1037.105—Phase 2 CO 2 Standards for Model Year 2021 Through 2023 Vocational Vehicles
Engine cycle | Vehicle service class | CO 2 standard by regulatory subcategory (g/ton·mile) | Multi-purpose | Regional | Urban
Compression-ignition | Light HDV | 373 | 311 | 424
Compression-ignition | Medium HDV | 265 | 234 | 296
Compression-ignition | Heavy HDV | 261 | 205 | 308
Spark-ignition | Light HDV | 407 | 335 | 461
| Spark-ignition | Medium HDV | 293 | 261 | 328
(5) Model year 2014 through 2020 vehicles are subject to Phase 1 CO 2 standards as shown in the following table:
Table 5 of Paragraph ( b )(5) of § 1037.105—Phase 1 CO 2 Standards for Model Year 2014 Through 2020 Vocational Vehicles
[g/ton-mile]
Vehicle size | CO 2 standard for model years 2014-2016 | CO 2 standard for model year 2017-2020
Light HDV | 388 | 373
Medium HDV | 234 | 225
Heavy HDV | 226 | 222
(c) [Reserved]
(d) You may generate or use emission credits for averaging, banking, and trading to demonstrate compliance with the standards in paragraph (b) of this section as described in subpart H of this part. This requires that you specify a Family Emission Limit (FEL) for CO 2 for each vehicle subfamily. The FEL may not be less than the result of emission modeling from § 1037.520. These FELs serve as the emission standards for the vehicle subfamily instead of the standards specified in paragraph (b) of this section.
(e) The exhaust emission standards of this section apply for the full useful life, expressed in service miles or calendar years, whichever comes first. The following useful life values apply for the standards of this section:
(1) 150,000 miles or 15 years, whichever comes first, for Light HDV.
(2) 185,000 miles or 10 years, whichever comes first, for Medium HDV.
(3) 435,000 miles or 10 years, whichever comes first, for Heavy HDV.
(f) See § 1037.631 for provisions that exempt certain vehicles used in off-road operation from the standards of this section.
(g) You may optionally certify a vocational vehicle to the standards and useful life applicable to a heavier vehicle service class (such as Medium HDV instead of Light HDV). Provisions related to generating emission credits apply as follows:
(1) If you certify all your vehicles from a given vehicle service class in a given model year to the standards and useful life that applies for a heavier vehicle service class, you may generate credits as appropriate for the heavier service class.
(2) Class 8 hybrid vehicles with Light HDE or Medium HDE may be certified to compression-ignition standards for the Heavy HDV service class. You may generate and use credits as allowed for the Heavy HDV service class.
(3) Except as specified in paragraphs (g)(1) and (2) of this section, you may not generate credits with the vehicle. If you include lighter vehicles in a subfamily of heavier vehicles with an FEL below the standard, exclude the production volume of lighter vehicles from the credit calculation. Conversely, if you include lighter vehicles in a subfamily with an FEL above the standard, you must include the production volume of lighter vehicles in the credit calculation.
(h) You may optionally certify certain vocational vehicles to alternative standards as specified in this paragraph (h) instead of the standards specified in paragraph (b) of this section. You may apply the provisions in this paragraph (h) to any qualifying vehicles even though these standards were established for custom-chassis vehicles. For example, large, diversified vehicle manufacturers may certify vehicles to the refuse hauler standards of this section as long as the manufacturer ensures that those vehicles qualify as refuse haulers when placed into service. GEM simulates vehicle operation for each type of vehicle based on an assigned vehicle service class, independent of the vehicle's actual characteristics, as specified in § 1037.140(g)(7); however, standards apply for the vehicle's useful life based on its actual characteristics as specified in paragraph (e) of this section. Vehicles certified to the standards in this paragraph (h) must include the following statement on the emission control label: “THIS VEHICLE WAS CERTIFIED AS A [ identify vehicle type as identified in this section ] UNDER 40 CFR 1037.105(h)].” These custom-chassis provisions apply as follows:
(1) The following alternative emission standards apply by vehicle type and model year as follows:
(i) Except as specified in paragraph (h)(1)(ii) of this section, CO 2 standards apply for model year 2021 and later custom-chassis vehicles as shown in the following tables:
Table 6 of Paragraph ( h )(1)( i ) of § 1037.105—Custom-Chassis Standards School Buses, Other Buses, and Refuse Haulers
Phase | Model year | CO 2 standard by custom-chassis vehicle type (g/ton·mile) | School bus | Other bus | Refuse hauler
2 | 2021-2026 | 291 | 300 | 313
3 | 2027 | 236 | 286 | 298
| 2028 | 228 | 286 | 283
| 2029 | 220 | 249 | 268
| 2030 | 211 | 243 | 253
| 2031 | 187 | 220 | 250
| 2032 and later | 163 | 200 | 250
Table 7 of Paragraph ( h )(1)( i ) of § 1037.105—Custom-Chassis Standards for Motor Homes, Coach Buses, Concrete Mixers, Mixed-Use Vehicles, and Emergency Vehicles
Phase | Model year | CO 2 standard by custom-chassis vehicle type (g/ton·mile) | Motor home | Coach bus | Concrete mixer | Mixed-use vehicle | Emergency vehicle
2 | 2021-2026 | 228 | 210 | 319 | 319 | 324
3 | 2027 and later | 226 | 205 | 316 | 316 | 319
(ii) For qualifying small manufacturers, Phase 2 CO 2 standards apply for model year 2027 and later custom-chassis vehicles instead of the standards specified in paragraph (h)(1)(i) of this section.
Table 8 of Paragraph ( h )(1)( ii ) of § 1037.105— Small Manufacturer Phase 2 CO 2 Standards for Model Year 2027 and Later Custom-Chassis Vocational Vehicles
[g/ton-mile]
Vehicle type | CO 2 standard
School bus | 271
Motor home | 226
Coach bus | 205
Other bus | 286
Refuse hauler | 298
Concrete mixer | 316
Mixed-use vehicle | 316
Emergency vehicle | 319
(iii) Vehicle types identified in this paragraph (h)(1) are generally defined in § 1037.801. “Other bus” includes any bus that is not a school bus or a coach bus. A “mixed-use vehicle” is one that meets at least one of the criteria specified in § 1037.631(a)(1) or (2).
(2) You may generate or use emission credits for averaging to demonstrate compliance with the alternative standards as described in subpart H of this part. This requires that you specify a Family Emission Limit (FEL) for CO 2 for each vehicle subfamily. The FEL may not be less than the result of emission modeling as described in § 1037.520. These FELs serve as the emission standards for the vehicle subfamily instead of the standards specified in this paragraph (h). Calculate credits using the equation in § 1037.705(b) with the standard payload for the assigned vehicle service class and the useful life identified in paragraph (e) of this section. Each separate vehicle type identified in paragraph (h)(1) of this section (or group of vehicle types identified in a single row) represents a separate averaging set. You may not use averaging for vehicles meeting standards under paragraphs (h)(5) through (7) of this section, and you may not bank or trade emission credits from any vehicles certified under this paragraph (h).
(3) [Reserved]
(4) For purposes of emission modeling under § 1037.520, consider motor homes and coach buses to be subject to the Regional duty cycle, and consider all other vehicles to be subject to the Urban duty cycle.
(5) Emergency vehicles are deemed to comply with the standards of this paragraph (h) if they use tires with TRRL at or below 8.4 N/kN (8.7 N/kN for model years 2021 through 2026).
(6) Concrete mixers and mixed-use vehicles are deemed to comply with the standards of this paragraph (h) if they use tires with TRRL at or below 7.1 N/kN (7.6 N/kN for model years 2021 through 2026).
(7) Motor homes are deemed to comply with the standards of this paragraph (h) if they have tires with TRRL at or below 6.0 N/kN (6.7 N/kN for model years 2021 through 2026) and automatic tire inflation systems or tire pressure monitoring systems with wheels on all axles.
(8) Vehicles certified to standards under this paragraph (h) must use engines certified under 40 CFR part 1036 for the appropriate model year, except that motor homes and emergency vehicles may use engines certified with the loose-engine provisions of § 1037.150(m). This paragraph (h)(8) also applies for vehicles meeting standards under paragraphs (h)(5) through (7) of this section.
57. Amend § 1037.106 by:
a. Revising the section heading and paragraph (b);
b. Removing and reserving paragraph (c); and
c. Revising paragraph (f)(2).
The revisions read as follows:
§ 1037.106
CO 2 emission standards for tractors above 26,000 pounds GVWR.
* * * * *
(b) CO 2 standards in this paragraph (b) apply based on modeling and testing as described in subpart F of this part. The provisions of § 1037.241 specify how to comply with the standards in this paragraph (b). Note that § 1037.230 describes how to divide vehicles into subcategories.
(1) Except as specified in paragraph (b)(2) of this section, model year 2027 and later tractors are subject to Phase 3 CO 2 standards corresponding to the selected subcategories as shown in the following table:
Table 1 of Paragraph ( b )(1) of § 1037.106—Phase 3 CO 2 Standards for Model Year 2027 and Later Tractors
Model year | Roof height | CO 2 standard by regulatory subcategory (g/ton·mile) | Class 7 all cab styles | Class 8 day cab | Class 8 sleeper cab | Heavy-haul
2027 | Low Roof | 96.2 | 73.4 | 64.1 | 48.3
| Mid Roof | 103.4 | 78.0 | 69.6
| High Roof | 100.0 | 75.7 | 64.3
2028 | Low Roof | 88.5 | 67.5 | 64.1 | 48.3
| Mid Roof | 95.1 | 71.8 | 69.6
| High Roof | 92.0 | 69.6 | 64.3
2029 | Low Roof | 84.7 | 64.6 | 64.1 | 47.8
| Mid Roof | 91.0 | 68.6 | 69.6
| High Roof | 88.0 | 66.6 | 64.3
2030 | Low Roof | 80.8 | 61.7 | 60.3 | 47.8
| Mid Roof | 86.9 | 65.5 | 65.4
| High Roof | 84.0 | 63.6 | 60.4
2031 | Low Roof | 69.3 | 52.8 | 56.4 | 46.9
| Mid Roof | 74.4 | 56.2 | 61.2
| High Roof | 72.0 | 54.5 | 56.6
2032 and Later | Low Roof | 57.7 | 44.0 | 48.1 | 45.9
| Mid Roof | 62.0 | 46.8 | 52.2
| High Roof | 60.0 | 45.4 | 48.2
(2) Qualifying small manufacturers of model year 2027 and later vehicles may continue to meet Phase 2 CO 2 standards in this paragraph (b)(2) instead of the standards specified in paragraph (b)(1) of this section. If you certify to these Phase 2 CO 2 standards, you may use the averaging provisions of subpart H of this part to demonstrate compliance. You may use other credit provisions of this part only by certifying all vehicle families within a given averaging set to the Phase 3 standards that apply in that model year.
Table 2 of Paragraph ( b )(2) of § 1037.106—Small Manufacturer CO 2 Standards for Model Year 2027 and Later Tractors
Subcategory | Phase 2 CO 2 standards (g/ton·mile)
Class 7 Low-Roof (all cab styles) | 96.2
Class 7 Mid-Roof (all cab styles) | 103.4
Class 7 High-Roof (all cab styles) | 100.0
Class 8 Low-Roof Day Cab | 73.4
Class 8 Low-Roof Sleeper Cab | 64.1
Class 8 Mid-Roof Day Cab | 78.0
Class 8 Mid-Roof Sleeper Cab | 69.6
Class 8 High-Roof Day Cab | 75.7
Class 8 High-Roof Sleeper Cab | 64.3
Heavy-Haul Tractors | 48.3
(3) Model year 2026 and earlier tractors are subject to CO 2 standards corresponding to the selected subcategory as shown in the following table:
Table 3 of Paragraph ( b )(3) of § 1037.106—CO 2 Standards for Model Year 2026 and Earlier Tractors
[g/ton-mile]
Subcategory | Phase 1 standards for model years 2014-2016 | Phase 1 standards for model years 2017-2020 | Phase 2 standards for model years 2021-2023 | Phase 2 standards for model years 2024-2026
Class 7 Low-Roof (all cab styles) | 107 | 104 | 105.5 | 99.8
Class 7 Mid-Roof (all cab styles) | 119 | 115 | 113.2 | 107.1
Class 7 High-Roof (all cab styles) | 124 | 120 | 113.5 | 106.6
Class 8 Low-Roof Day Cab | 81 | 80 | 80.5 | 76.2
Class 8 Low-Roof Sleeper Cab | 68 | 66 | 72.3 | 68.0
Class 8 Mid-Roof Day Cab | 88 | 86 | 85.4 | 80.9
Class 8 Mid-Roof Sleeper Cab | 76 | 73 | 78.0 | 73.5
Class 8 High-Roof Day Cab | 92 | 89 | 85.6 | 80.4
Class 8 High-Roof Sleeper Cab | 75 | 72 | 75.7 | 70.7
Heavy-Haul Tractors | | | 52.4 | 50.2
* * * * *
(f) * * *
(2) You may optionally certify Class 7 tractors not covered by paragraph (f)(1) of this section to the standards and useful life for Class 8 tractors. This paragraph (f)(2) applies equally for hybrid vehicles, battery electric vehicles, and fuel cell electric vehicles. Credit provisions apply as follows:
(i) If you certify all your Class 7 tractors to Class 8 standards, you may use these Heavy HDV credits without restriction.
(ii) This paragraph (f)(2)(ii) applies if you certify some Class 7 tractors to Class 8 standards under this paragraph (f)(2) but not all of them. If you include Class 7 tractors in a subfamily of Class 8 tractors with an FEL below the standard, exclude the production volume of Class 7 tractors from the credit calculation. Conversely, if you include Class 7 tractors in a subfamily of Class 8 tractors with an FEL above the standard, you must include the production volume of Class 7 tractors in the credit calculation.
* * * * *
§ 1037.107
[Removed]
58. Remove § 1037.107.
59. Amend § 1037.115 by revising paragraphs (a) and (e)(1) and adding paragraph (f) to read as follows:
§ 1037.115
Other requirements.
* * * * *
(a) Adjustable parameters. Vehicles that have adjustable parameters must meet all the requirements of this part for any adjustment in the practically adjustable range. We may require that you set adjustable parameters to any specification within the practically adjustable range during any testing. See 40 CFR 1068.50 for general provisions related to adjustable parameters. You must ensure safe vehicle operation throughout the practically adjustable range of each adjustable parameter, including consideration of production tolerances. Note that adjustable roof fairings are deemed not to be adjustable parameters.
* * * * *
(e) * * *
(1) This paragraph (e) is intended to address air conditioning systems for which the primary purpose is to cool the driver compartment. This would generally include all cab-complete pickups and vans. Similarly, it does not apply for self-contained air conditioning used to cool passengers or refrigeration units used to cool cargo on vocational vehicles. For purposes of this paragraph (e), a self-contained system is an enclosed unit with its own evaporator and condenser even if it draws power from the engine.
* * * * *
(f) Battery durability monitor. Model year 2030 and later battery electric vehicles and plug-in hybrid electric vehicles must meet the following requirements to estimate and monitor usable battery energy for batteries serving as Rechargeable Energy Storage Systems:
(1) Create a customer-accessible system that monitors and displays the vehicle's State of Certified Energy ( SOCE ) with an accuracy of ±5%. Display the SOCE from paragraph (f)(2) of this section as a percentage expressed to the nearest whole number. Update the display as needed to reflect the current value of SOCE.
(2) Determine SOCE using the following equation:

Eq. 1037.115-1
Where:
UBE = usable battery energy as determined in paragraph (f)(3) or (4) of this section, where certified refers to the value established for certification and aged refers to the current value as the battery ages.
V = battery voltage.
t = the time for the test, running from time zero to the end point when the battery is not able to maintain the target power.
I = battery current.
(3) For battery electric vehicles, ask us to approve a procedure you develop to determine UBE that meets the following requirements:
(i) Measure UBE by discharging the battery at a constant power that is representative of the vehicle cruising on the highway. For many HDV, the power to cruise on the highway would result in a C-rate between 1/6 C and 1/2 C. Where C-rate is a measure of the rate at which a battery is discharged or charged relative to its maximum capacity and has units of inverse hours. For example, at a 2 C discharge rate, it would take 0.5 hours to fully discharge a battery. For test procedures that involve driving a vehicle, you may discharge the battery at variable rates until the last portion of the test, consistent with good engineering judgment.
(ii) The test is complete when the battery is not able to maintain the target power.
(iii) Use the same procedure for measuring certified and aged UBE.
(iv) Measurements to determine power must meet the requirements in 40 CFR 1036.545(a)(10).
(4) For plug-hybrid electric vehicles, determine UBE as described in 40 CFR 1036.545(p), or you may use a procedure that meets the requirements of paragraph (f)(3) of this section.
60. Amend § 1037.120 by revising paragraphs (b) and (c) to read as follows:
§ 1037.120
Emission-related warranty requirements.
* * * * *
(b) Warranty period. (1) Your emission-related warranty must be valid for at least:
(i) 5 years or 50,000 miles for Light HDV (except tires).
(ii) 5 years or 100,000 miles for Medium HDV and Heavy HDV (except tires).
(iii) 2 years or 24,000 miles for tires.
(2) You may offer an emission-related warranty more generous than we require. The emission-related warranty for the vehicle may not be shorter than any basic mechanical warranty you provide to that owner without charge for the vehicle. Similarly, the emission-related warranty for any component may not be shorter than any warranty you provide to that owner without charge for that component. This means that your warranty for a given vehicle may not treat emission-related and nonemission-related defects differently for any component. The warranty period begins when the vehicle is placed into service.
(c) Components covered. The emission-related warranty covers tires, automatic tire inflation systems, tire pressure monitoring systems, vehicle speed limiters, idle-reduction systems, devices added to the vehicle to improve aerodynamic performance (not including standard components such as hoods or mirrors even if they have been optimized for aerodynamics) to the extent such emission-related components are included in your application for certification. The emission-related warranty similarly covers fuel cell stacks, RESS, and other components used with hybrid systems, battery electric vehicles, and fuel cell electric vehicles. The emission-related warranty also covers other added emission-related components to the extent they are included in your application for certification, and any other components whose failure would increase a vehicle's CO 2 emissions. The emission-related warranty covers all components whose failure would increase a vehicle's emissions of air conditioning refrigerants (for vehicles subject to air conditioning leakage standards), and it covers all components whose failure would increase a vehicle's evaporative and refueling emissions (for vehicles subject to evaporative and refueling emission standards). The emission-related warranty covers components that are part of your certified configuration even if another company produces the component.
* * * * *
61. Amend § 1037.130 by revising paragraph (a) to read as follows:
§ 1037.130
Assembly instructions for secondary vehicle manufacturers.
(a) If you sell a certified incomplete vehicle to a secondary vehicle manufacturer, give the secondary vehicle manufacturer instructions for completing vehicle assembly consistent with the requirements of this part. Include all information necessary to ensure that the final vehicle assembly (including the engine) will be in its certified configuration.
* * * * *
62. Amend § 1037.135 by revising paragraph (c)(6) to read as follows:
§ 1037.135
Labeling.
* * * * *
(c) * * *
(6) For Phase 1 vehicles, identify the emission control system. Use terms and abbreviations as described in appendix C to this part or other applicable conventions.
* * * * *
63. Amend § 1037.140 by revising paragraphs (c) and (g) to read as follows:
§ 1037.140
Classifying vehicles and determining vehicle parameters.
* * * * *
(c) Base a standard trailer's length on the outer dimensions of the load-carrying structure. Do not include aerodynamic devices or HVAC units.
* * * * *
(g) The standards and other provisions of this part apply to specific vehicle service classes as follows:
(1) Tractors are divided based on GVWR into Class 7 tractors and Class 8 tractors. Where provisions of this part apply to both tractors and vocational vehicles, Class 7 tractors are considered “Medium HDV” and Class 8 tractors are considered “Heavy HDV”. This paragraph (g)(1) applies for hybrid and non-hybrid vehicles.
(2) Phase 1 vocational vehicles are divided based on GVWR. “Light HDV” includes Class 2b through Class 5 vehicles; “Medium HDV” includes Class 6 and Class 7 vehicles; and “Heavy HDV” includes Class 8 vehicles.
(3) Phase 2 and later vocational vehicles propelled by engines subject to the spark-ignition standards of 40 CFR part 1036 are divided as follows:
(i) Class 2b through Class 5 vehicles are considered “Light HDV”.
(ii) Class 6 through Class 8 vehicles are considered “Medium HDV”.
(4) Phase 2 and later vocational vehicles propelled by engines subject to the compression-ignition standards in 40 CFR part 1036 are divided as follows:
(i) Class 2b through Class 5 vehicles are considered “Light HDV”.
(ii) Class 6 through 8 vehicles are considered “Heavy HDV” if the installed engine's primary intended service class is Heavy HDE (see 40 CFR 1036.140), except that Class 8 hybrid vehicles are considered “Heavy HDV” regardless of the engine's primary intended service class.
(iii) All other Class 6 through Class 8 vehicles are considered “Medium HDV”.
(5) Heavy-duty vehicles with no installed propulsion engine, such as battery electric vehicles, are divided as follows:
(i) Class 2b through Class 5 vehicles are considered “Light HDV”.
(ii) Class 6 and 7 vehicles are considered “Medium HDV”.
(iii) Class 8 vehicles are considered “Heavy HDV”.
(6) In certain circumstances, you may certify vehicles to standards that apply for a different vehicle service class. For example, see §§ 1037.105(g) and 1037.106(f). If you optionally certify vehicles to different standards, those vehicles are subject to all the regulatory requirements as if the standards were mandatory.
(7) Vehicles meeting the custom-chassis standards of § 1037.105(h)(1) are subject to the following vehicle service classes instead of the other provisions in this section:
(i) School buses and motor homes are considered “Medium HDV”.
(ii) All other custom-chassis are considered “Heavy HDV”.
* * * * *
64. Revise and republish § 1037.150 to read as follows:
§ 1037.150
Interim provisions.
The provisions in this section apply instead of other provisions in this part.
(a) Incentives for early introduction. The provisions of this paragraph (a) apply with respect to vehicles produced in model years before 2014. Manufacturers may voluntarily certify in model year 2013 (or earlier model years for electric vehicles) to the greenhouse gas standards of this part.
(1) This paragraph (a)(1) applies for regulatory subcategories subject to the standards of § 1037.105 or § 1037.106. Except as specified in paragraph (a)(3) of this section, to generate early credits under this paragraph (a)(1) for any vehicles other than electric vehicles, you must certify your entire U.S.-directed production volume within the regulatory subcategory to the standards of § 1037.105 or § 1037.106. Except as specified in paragraph (a)(4) of this section, if some vehicle families within a regulatory subcategory are certified after the start of the model year, you may generate credits only for production that occurs after all families are certified. For example, if you produce three vehicle families in an averaging set and you receive your certificates for those families on January 4, 2013, March 15, 2013, and April 24, 2013, you may not generate credits for model year 2013 production in any of the families that occurs before April 24, 2013. Calculate credits relative to the standard that would apply in model year 2014 using the equations in subpart H of this part. You may bank credits equal to the surplus credits you generate under this paragraph (a) multiplied by 1.50. For example, if you have 1.0 Mg of surplus credits for model year 2013, you may bank 1.5 Mg of credits. Credit deficits for an averaging set prior to model year 2014 do not carry over to model year 2014. These credits may be used to show compliance with the standards of this part for 2014 and later model years. We recommend that you notify EPA of your intent to use this paragraph (a)(1) before submitting your applications.
(2) [Reserved]
(3) You may generate emission credits for the number of additional SmartWay designated tractors (relative to your 2012 production), provided you do not generate credits for those vehicles under paragraph (a)(1) of this section. Calculate credits for each regulatory subcategory relative to the standard that would apply in model year 2014 using the equations in subpart H of this part. Use a production volume equal to the number of designated model year 2013 SmartWay tractors minus the number of designated model year 2012 SmartWay tractors. You may bank credits equal to the surplus credits you generate under this paragraph (a)(3) multiplied by 1.50. Your 2012 and 2013 model years must be equivalent in length.
(4) This paragraph (a)(4) applies where you do not receive your final certificate in a regulatory subcategory within 30 days of submitting your final application for that subcategory. Calculate your credits for all production that occurs 30 days or more after you submit your final application for the subcategory.
(b) Phase 1 coastdown procedures. For tractors subject to Phase 1 standards under § 1037.106, the default method for measuring drag area ( C d A ) is the coastdown procedure specified in 40 CFR part 1066, subpart D. This includes preparing the tractor and the standard trailer with wheels meeting specifications of § 1037.528(b) and submitting information related to your coastdown testing under § 1037.528(h).
(c) Small manufacturers. The following provisions apply for qualifying small manufacturers:
(1) The greenhouse gas standards of §§ 1037.105 and 1037.106 are optional for small manufacturers producing vehicles with a date of manufacture before January 1, 2022. In addition, small manufacturers producing vehicles that run on any fuel other than gasoline, E85, or diesel fuel may delay complying with every later standard under this part by one model year.
(2) Qualifying manufacturers must notify the Designated Compliance Officer each model year before introducing excluded vehicles into U.S. commerce. This notification must include a description of the manufacturer's qualification as a small business under 13 CFR 121.201. Manufacturers must label excluded vehicles with the following statement: “THIS VEHICLE IS EXCLUDED UNDER 40 CFR 1037.150(c).”
(3) Small manufacturers may meet Phase 1 standards instead of Phase 2 standards in the first year Phase 2 standards apply to them if they voluntarily comply with the Phase 1 standards for the full preceding year. Specifically, small manufacturers may certify their model year 2022 vehicles to the Phase 1 greenhouse gas standards of §§ 1037.105 and 1037.106 if they certify all the vehicles from their annual production volume included in emission credit calculations for the Phase 1 standards starting on or before January 1, 2021.
(4) See paragraphs (r), (t), (u), and (w) of this section for additional allowances for small manufacturers.
(d) Air conditioning leakage for vocational vehicles. The air conditioning leakage standard of § 1037.115 does not apply for model year 2020 and earlier vocational vehicles.
(e) Delegated assembly. The delegated-assembly provisions of § 1037.621 do not apply before January 1, 2018.
(f) Testing exemption for qualifying vehicles. Tailpipe CO 2 emissions from battery electric vehicles, fuel cell electric vehicles, and vehicles with engines fueled with neat hydrogen are deemed to be zero. No CO 2 -related testing is required under this part for these vehicles.
(g) Compliance date. Compliance with the standards of this part was optional prior to January 1, 2014. This means that if your 2014 model year begins before January 1, 2014, you may certify for a partial model year that begins on January 1, 2014, and ends on the day your model year would normally end. You must label model year 2014 vehicles excluded under this paragraph (g) with the following statement: “THIS VEHICLE IS EXCLUDED UNDER 40 CFR 1037.150(g).”
(h) Off-road vehicle exemption. (1) Vocational vehicles with a date of manufacture before January 1, 2021, automatically qualify for an exemption under § 1037.631 if the tires installed on the vehicle have a maximum speed rating at or below 55 miles per hour.
(2) In unusual circumstances, vehicle manufacturers may ask us to exempt vehicles under § 1037.631 based on other criteria that are equivalent to those specified in § 1037.631(a); however, we will normally not grant relief in cases where the vehicle manufacturer has credits or can otherwise comply with applicable standards. Request approval for an exemption under this paragraph (h) before you produce the subject vehicles. Send your request with supporting information to the Designated Compliance Officer; we will coordinate with NHTSA in making a determination under § 1037.210. If you introduce into U.S. commerce vehicles that depend on our approval under this paragraph (h) before we inform you of our approval, those vehicles violate 40 CFR 1068.101(a)(1).
(i) Limited carryover from Phase 1 to Phase 2. The provisions for carryover data in § 1037.235(d) do not allow you to use aerodynamic test results from Phase 1 to support a compliance demonstration for Phase 2 certification.
(j) Limited prohibition related to early model year engines. The provisions of this paragraph (j) apply only for vehicles that have a date of manufacture before January 1, 2018. See § 1037.635 for related provisions that apply in later model years. The prohibition in § 1037.601 against introducing into U.S. commerce a vehicle containing an engine not certified to the standards applicable for the calendar year of installation does not apply for vehicles using model year 2014 or 2015 spark-ignition engines, or any model year 2013 or earlier engines.
(k) Verifying drag areas from in-use tractors. This paragraph (k) applies for tractors instead of § 1037.401(b) through model year 2020. We may measure the drag area of your vehicles after they have been placed into service. To account for measurement variability, your vehicle is deemed to conform to the regulations of this part with respect to aerodynamic performance if we measure its drag area to be at or below the maximum drag area allowed for the bin above the bin to which you certified (for example, Bin II if you certified the vehicle to Bin III), unless we determine that you knowingly produced the vehicle to have a higher drag area than is allowed for the bin to which it was certified.
(l) Optional certification to GHG standards under 40 CFR part 86. The greenhouse gas standards in 40 CFR part 86, subpart S, may apply instead of the standards of § 1037.105 as follows:
(1) Complete or cab-complete vehicles may optionally meet alternative standards as described in 40 CFR 86.1819-14(j).
(2) Complete high-GCWR vehicles must meet the greenhouse gas standards of 40 CFR part 86, subpart S, as described in 40 CFR 1036.635.
(3) Incomplete high-GCWR vehicles may meet the greenhouse gas standards of 40 CFR part 86, subpart S, as described in 40 CFR 1036.635.
(m) Loose engine sales. Manufacturers may certify certain spark-ignition engines along with chassis-certified heavy-duty vehicles where they are identical to engines used in those vehicles as described in 40 CFR 86.1819-14(k)(8). Vehicles in which those engines are installed are subject to standards under this part as specified in § 1037.105.
(n) Transition to engine-based model years. The following provisions apply for production and ABT reports during the transition to engine-based model year determinations for vehicles in 2020 and 2021:
(1) If you install model year 2020 or earlier engines in your vehicles in calendar year 2020, include all those Phase 1 vehicles in your production and ABT reports related to model year 2020 compliance, although we may require you identify these separately from vehicles produced in calendar year 2019.
(2) If you install model year 2020 engines in your vehicles in calendar year 2021, submit production and ABT reports for those Phase 1 vehicles separate from the reports you submit for Phase 2 vehicles with model year 2021 engines.
(o) Interim useful life for light heavy-duty vocational vehicles. Class 2b through Class 5 vocational vehicles certified to Phase 1 standards are subject to a useful life of 110,000 miles or 10 years, whichever comes first, instead of the useful life specified in § 1037.105. For emission credits generated from these Phase 1 vehicles, multiply any banked credits that you carry forward to demonstrate compliance with Phase 2 standards by 1.36.
(p) Credit multiplier for advanced technology. The following provisions describe how you may generate and use credits from vehicles certified with advanced technology:
(1) You may calculate credits you generate from vehicles certified with advanced technology as follows:
(i) For Phase 1 vehicles, multiply the credits by 1.50, except that you may not apply this multiplier in addition to the early-credit multiplier of paragraph (a) of this section.
(ii) For model year 2026 and earlier Phase 2 vehicles, apply multipliers of 3.5 for plug-in hybrid electric vehicles, 4.5 for battery electric vehicles, and 5.5 for fuel cell electric vehicles. Calculate credits relative to the Phase 2 standard.
(iii) For Phase 3 vehicles, the advanced-technology multipliers described in paragraph (p)(1)(ii) of this section apply only in model year 2027. Calculate credits relative to the Phase 3 standard.
(2) You may use credit quantities described in paragraphs (p)(1)(i) and (ii) of this section through model year 2026. The following provisions apply for advanced technology credits starting in model year 2027:
(i) Quantify accumulated credit balances in each model year that result from multiplier credit values. For example, if BEV earns 100 Mg of CO 2 credits that become 450 Mg of credits when multiplied, the base credit value is 100 Mg and the multiplier credit value is 350 Mg. Provide a detailed accounting of base and multiplier credits in your annual ABT reports for the relevant model years.
(ii) For each vehicle family, calculate a credit quantity with no consideration of credit multipliers. Sum these credit quantities for every family within a given averaging set.
(iii) Apply available credits in the following priority order as long as the summed credit quantity is negative.
(A) Base credits banked or traded within the same averaging set.
(B) Base credits earned in the same model year from other averaging sets as specified in paragraph (z) of this section.
(C) Base credits from other averaging sets as specified in paragraph (z) of this section that are banked or traded.
(D) Multiplier credits within the same averaging set for the same model year.
(E) Multiplier credits banked or traded within the same averaging set.
(F) Multiplier credits earned in the same model year from other averaging sets as specified in paragraph (z) of this section.
(G) Multiplier credits from other averaging sets as specified in paragraph (z) of this section that are banked or traded.
(iv) You may no longer use multiplier credits for certifying model year 2030 and later vehicles.
(v) Credit provisions not addressed in this paragraph (p)(2), such as limitations on credit life and credit trading, continue to apply as specified. Note the following:
(A) Unlike multiplier credits, the life of base credits is not limited under this paragraph (p)(2).
(B) You may apply multiplier credits without the restrictions described in this paragraph (p)(2) to resolve a deficit that remains from complying with Phase 2 standards in model years 2026 and earlier.
(q) Vehicle families for advanced and off-cycle technologies. Apply the following provisions for grouping vehicles into families if you use off-cycle technologies under § 1037.610 or advanced technologies under § 1037.615:
(1) For Phase 1 vehicles, create separate vehicle families for vehicles that contain advanced or off-cycle technologies; group those vehicles together in a vehicle family if they use the same advanced or off-cycle technologies.
(2) For Phase 2 and Phase 3 vehicles, create separate vehicle subfamilies for vehicles that contain advanced or off-cycle technologies; group those vehicles together in a vehicle subfamily if they use the same advanced or off-cycle technologies.
(r) Conversion to mid- roof and high-roof configurations. Secondary vehicle manufacturers that qualify as small manufacturers may convert low- and mid-roof tractors to mid- and high-roof configurations without recertification for the purpose of building a custom sleeper tractor or converting it to run on natural gas, as follows:
(1) The original low- or mid-roof tractor must be covered by a valid certificate of conformity.
(2) The modifications may not increase the frontal area of the tractor beyond the frontal area of the equivalent mid- or high-roof tractor with the corresponding standard trailer. Note that these dimensions have a tolerance of ±2 inches. Use good engineering judgment to achieve aerodynamic performance similar to or better than the certifying manufacturer's corresponding mid- or high-roof tractor.
(3) Add a permanent supplemental label to the vehicle near the original manufacturer's emission control information label. On the label identify your full corporate name and include the following statement: “THIS VEHICLE WAS MODIFIED AS ALLOWED UNDER 40 CFR 1037.150.”
(4) We may require that you submit annual production reports as described in § 1037.250.
(5) Modifications made under this paragraph (r) do not violate 40 CFR 1068.101(b)(1).
(s) Confirmatory testing for F alt-aero . If we conduct coastdown testing to verify your F alt-aero value for Phase 2 and later tractors, we will make our determination using the principles of SEA testing in § 1037.305. We will not replace your F alt-aero value if the tractor passes. If your tractor fails, we will generate a replacement value of F alt-aero based on at least one C d A value and corresponding effective yaw angle, ψ eff, from a minimum of 100 valid runs using the procedures of § 1037.528(h). Note that we intend to minimize the differences between our test conditions and those of the manufacturer by testing at similar times of the year where possible and the same location where possible and when appropriate.
(t) Glider kits and glider vehicles. (1) Glider vehicles conforming to the requirements in this paragraph (t)(1) are exempt from the Phase 1 emission standards of this part 1037 prior to January 1, 2021. Engines in such vehicles (including vehicles produced after January 1, 2021) remain subject to the requirements of 40 CFR part 86 applicable for the engines' original model year, but not subject to the Phase 1 or Phase 2 standards of 40 CFR part 1036 unless they were originally manufactured in model year 2014 or later.
(i) You are eligible for the exemption in this paragraph (t)(1) if you are a small manufacturer and you sold one or more glider vehicles in 2014 under the provisions of paragraph (c) of this section. You do not qualify if you only produced glider vehicles for your own use. You must notify us of your plans to use this exemption before you introduce exempt vehicles into U.S. commerce. In your notification, you must identify your annual U.S.-directed production volume (and sales, if different) of such vehicles for calendar years 2010 through 2014. Vehicles you produce before notifying us are not exempt under this section.
(ii) In a given calendar year, you may produce up to 300 exempt vehicles under this section, or up to the highest annual production volume you identify in this paragraph (t)(1), whichever is less.
(iii) Identify the number of exempt vehicles you produced under this exemption for the preceding calendar year in your annual report under § 1037.250.
(iv) Include the appropriate statement on the label required under § 1037.135, as follows:
(A) For Phase 1 vehicles, “THIS VEHICLE AND ITS ENGINE ARE EXEMPT UNDER 40 CFR 1037.150(t)(1).”
(B) For Phase 2 vehicles, “THE ENGINE IN THIS VEHICLE IS EXEMPT UNDER 40 CFR 1037.150(t)(1).”
(v) If you produce your glider vehicle by installing remanufactured or previously used components in a glider kit produced by another manufacturer, you must provide the following to the glider kit manufacturer prior to obtaining the glider kit:
(A) Your name, the name of your company, and contact information.
(B) A signed statement that you are a qualifying small manufacturer and that your production will not exceed the production limits of this paragraph (t)(1). This statement is deemed to be a submission to EPA, and we may require the glider kit manufacturer to provide a copy to us at any time.
(vi) The exemption in this paragraph (t)(1) is valid for a given vehicle and engine only if you meet all the requirements and conditions of this paragraph (t)(1) that apply with respect to that vehicle and engine. Introducing such a vehicle into U.S. commerce without meeting all applicable requirements and conditions violates 40 CFR 1068.101(a)(1).
(vii) Companies that are not small manufacturers may sell uncertified incomplete vehicles without engines to small manufacturers for the purpose of producing exempt vehicles under this paragraph (t)(1), subject to the provisions of § 1037.622. However, such companies must take reasonable steps to ensure that their incomplete vehicles will be used in conformance with the requirements of this part.
(2) Glider vehicles produced using engines certified to model year 2010 or later standards for all pollutants are subject to the same provisions that apply to vehicles using engines within their useful life in § 1037.635.
(3) For calendar year 2017, you may produce a limited number of glider kits and/or glider vehicles subject to the requirements applicable to model year 2016 glider vehicles, instead of the requirements of § 1037.635. The limit applies to your combined 2017 production of glider kits and glider vehicles and is equal to your highest annual production of glider kits and glider vehicles for any year from 2010 to 2014. Any glider kits or glider vehicles produced beyond this cap are subject to the provisions of § 1037.635. Count any glider kits and glider vehicles you produce under paragraph (t)(1) of this section as part of your production with respect to this paragraph (t)(3).
(u) Transition to Phase 2 standards. The following provisions allow for enhanced generation and use of emission credits from Phase 1 vehicles for meeting the Phase 2 standards:
(1) For vocational Light HDV and vocational Medium HDV, emission credits you generate in model years 2018 through 2021 may be used through model year 2027, instead of being limited to a five-year credit life as specified in § 1037.740(c). For Class 8 vocational vehicles with Medium HDE, we will approve your request to generate these credits in and use these credits for the Medium HDV averaging set if you show that these vehicles would qualify as Medium HDV under the Phase 2 program as described in § 1037.140(g)(4).
(2) You may use the off-cycle provisions of § 1037.610 to apply technologies to Phase 1 vehicles as follows:
(i) You may apply an improvement factor of 0.988 for vehicles with automatic tire inflation systems on all axles.
(ii) For vocational vehicles with automatic engine shutdown systems that conform with § 1037.660, you may apply an improvement factor of 0.95.
(iii) For vocational vehicles with stop-start systems that conform with § 1037.660, you may apply an improvement factor of 0.92.
(iv) For vocational vehicles with neutral-idle systems conforming with § 1037.660, you may apply an improvement factor of 0.98. You may adjust this improvement factor if we approve a partial reduction under § 1037.660(a)(2); for example, if your design reduces fuel consumption by half as much as shifting to neutral, you may apply an improvement factor of 0.99.
(3) Small manufacturers may generate emission credits for natural gas-fueled vocational vehicles as follows:
(i) Small manufacturers may certify their vehicles instead of relying on the exemption of paragraph (c) of this section. The provisions of this part apply for such vehicles, except as specified in this paragraph (u)(3).
(ii) Use GEM version 2.0.1 to determine a CO 2 emission level for your vehicle, then multiply this value by the engine's Family Certification Level for CO 2 and divide by the engine's applicable CO 2 emission standard.
(4) Phase 1 vocational vehicle credits that small manufacturers generate may be used through model year 2027.
(v) Constraints for vocational regulatory subcategories. The following provisions apply to determinations of vocational regulatory subcategories as described in § 1037.140:
(1) Select the Regional regulatory subcategory for coach buses and motor homes you certify under § 1037.105(b).
(2) You may not select the Urban regulatory subcategory for any vehicle with a manual or single-clutch automated manual transmission.
(3) Starting in model year 2024, you must select the Regional regulatory subcategory for any vehicle with a manual transmission.
(4) You may select the Multi-purpose regulatory subcategory for any vocational vehicle, except as specified in paragraph (v)(1) of this section.
(5) You may select the Urban regulatory subcategory for a hybrid vehicle equipped with regenerative braking, unless it is equipped with a manual transmission.
(6) You may select the Urban regulatory subcategory for any vehicle with a hydrokinetic torque converter paired with an automatic transmission, or a continuously variable automatic transmission, or a dual-clutch transmission with no more than two consecutive forward gears between which it is normal for both clutches to be momentarily disengaged.
(w) Custom-chassis standards for small manufacturers. The following provisions apply uniquely to qualifying small manufacturers under the custom-chassis standards of § 1037.105(h):
(1) You may use emission credits generated under § 1037.105(d), including banked or traded credits from any averaging set. Such credits remain subject to other limitations that apply under subpart H of this part.
(2) You may produce up to 200 drayage tractors in a given model year to the standards described in § 1037.105(h) for “other buses”. The limit in this paragraph (w)(2) applies with respect to vehicles produced by you and your affiliated companies. Treat these drayage tractors as being in their own averaging set.
(x) Transition to updated GEM. (1) Vehicle manufacturers may demonstrate compliance with Phase 2 greenhouse gas standards in model years 2021 through 2023 using GEM Phase 2, Version 3.0, Version 3.5.1, or Version 4.0 (all incorporated by reference, see § 1037.810). Manufacturers may change to a different version of GEM for model years 2022 and 2023 for a given vehicle family after initially submitting an application for certification; such a change must be documented as an amendment under § 1037.225. Manufacturers may submit an end-of-year report for model year 2021 using any of the three regulatory versions of GEM, but only for demonstrating compliance with the custom-chassis standards in § 1037.105(h); such a change must be documented in the report submitted under § 1037.730. Once a manufacturer certifies a vehicle family based on GEM Version 4.0, it may not revert back to using GEM Phase 2, Version 3.0 or Version 3.5.1 for that vehicle family in any model year.
(2) Vehicle manufacturers may certify for model years 2021 through 2023 based on fuel maps from engines or powertrains that were created using GEM Phase 2, Version 3.0, Version 3.5.1, or Version 4.0 (all incorporated by reference, see § 1037.810). Vehicle manufacturers may alternatively certify in those years based on fuel maps from powertrains that were created using GEM Phase 2, Version 3.0, GEM HIL model 3.8, or GEM Phase 2, Version 4.0 (all incorporated by reference, see § 1037.810). Vehicle manufacturers may continue to certify vehicles in later model years using fuel maps generated with earlier versions of GEM for model year 2024 and later vehicle families that qualify for using carryover provisions in § 1037.235(d).
(y) Correcting credit calculations. If you notify us by October 1, 2024, that errors mistakenly decreased your balance of emission credits for 2020 or any earlier model years, you may correct the errors and recalculate the balance of emission credits after applying a 10 percent discount to the credit correction.
(z) Credit exchanges across averaging sets for certain vehicles. The provisions of this paragraph (z) apply for credits generated from model year 2026 and earlier vehicles certified with advanced technology under this part. The provisions of this paragraph (z) also apply for credits generated from model year 2027 through 2032 vehicles, as follows:
(1) Credits generated under this part may be used through model year 2032 for any of the averaging sets identified in § 1037.740(a).
(2) Credits generated from vehicles certified to the standards in 40 CFR 86.1819-14 may be used through model year 2032 to demonstrate compliance with the CO 2 emission standards for Light HDV or Medium HDV in this part.
(3) The following provisions apply for redesignating credits for use in different averaging sets:
(i) The restrictions that apply for trading credits under § 1037.720 also apply for redesignating credits.
(ii) Send us a report by June 30 after model year to describe how you are redesignating credits. Identify the averaging set and number of credits generated from each vehicle family. Also identify the number of redesignated emission credits you intend to apply for each averaging set.
(4) You may trade redesignated credits as allowed under the standard setting part. Credit provisions not addressed in this paragraph (z), such as limitations on credit life and credit multipliers for advanced technology, continue to apply as specified.
(aa) Warranty for advanced technologies. The emission-related warranty requirements in § 1037.120 are optional for fuel cell stacks, RESS, and other components used with battery electric vehicles and fuel cell electric vehicles before model year 2027.
65. Amend § 1037.205 by revising the introductory text and paragraphs (a), (b) introductory text, (b)(6), (e), (o), and (q) to read as follows:
§ 1037.205
What must I include in my application?
This section specifies the information that must be in your application, unless we ask you to include less information under § 1037.201(c). We may require you to provide additional information to evaluate your application. References to testing and emission-data vehicles refer to testing vehicles or components to measure any quantity that serves as an input value for modeling emission rates under § 1037.520.
(a) Describe the vehicle family's specifications and other basic parameters of the vehicle's design and emission controls. List the fuel type on which your vehicles are designed to operate (for example, ultra-low-sulfur diesel fuel).
(b) Explain how the emission control system operates. As applicable, describe in detail all system components for controlling greenhouse gas emissions, including all auxiliary emission control devices (AECDs) and all fuel-system components you will install on any production vehicle. For any vehicle using RESS (such as hybrid vehicles, fuel cell electric vehicles, and battery electric vehicles), describe in detail all components needed to charge the system, store energy, and transmit power to move the vehicle. Identify the part number of each component you describe. For this paragraph (b), treat as separate AECDs any devices that modulate or activate differently from each other. Also describe your modeling inputs as described in § 1037.520, with the following additional information if it applies for your vehicles:
* * * * *
(6) If you perform powertrain testing under 40 CFR 1036.545, report both CO 2 and NO X emission levels corresponding to each test run.
* * * * *
(e) Describe any test equipment and procedures that you used, including any special or alternate test procedures you used (see § 1037.501). Include information describing the procedures you used to determine C d A values as specified in §§ 1037.525 and 1037.527. Describe which type of data you are using for engine fuel maps (see 40 CFR 1036.505).
* * * * *
(o) Report calculated and modeled emission results for ten configurations. Include modeling inputs and detailed descriptions of how they were derived. Unless we specify otherwise, include the configuration with the highest modeling result, the lowest modeling result, and the configurations with the highest projected sales.
* * * * *
(q) For battery electric vehicles and plug-in hybrid electric vehicles, describe the recharging procedures and methods for determining battery performance, such as state of charge and charging capacity. Also include the certified usable battery energy for each battery durability subfamily.
* * * * *
§ 1037.211
[Removed]
66. Remove § 1037.211.
67. Amend § 1037.230 by:
a. Revising paragraph (a)(1) introductory text;
b. Removing paragraph (a)(3);
c. Revising paragraph (d)(2) introductory text; and
d. Removing paragraph (d)(3).
The revisions read as follows:
§ 1037.230
Vehicle families, sub-families, and configurations.
(a) * * *
(1) Apply subcategories for vocational vehicles and vocational tractors as shown in table 1 of this section. This involves 15 separate subcategories for Phase 2 and later vehicles to account for engine characteristics, GVWR, and the selection of duty cycle for vocational vehicles as specified in § 1037.510; vehicles may additionally fall into one of the subcategories defined by the custom-chassis standards in § 1037.105(h). Divide Phase 1 vehicles into three GVWR-based vehicle service classes as shown in table 1 of this section, disregarding additional specified characteristics. Table 1 follows:
* * * * *
(d) * * *
(2) For a Phase 2 or later vehicle model that includes a range of GVWR values that straddle weight classes, you may include all the vehicles in the same vehicle family if you certify the vehicle family to the numerically lower CO 2 emission standard from the affected service classes. Vehicles that are optionally certified to a more stringent standard under this paragraph (d)(2) are subject to useful-life and all other provisions corresponding to the weight class with the numerically lower CO 2 emission standard. For a Phase 2 or later tractor model that includes a range of roof heights that straddle subcategories, you may include all the vehicles in the same vehicle family if you certify the vehicle family to the appropriate subcategory as follows:
* * * * *
68. Amend § 1037.231 by revising paragraph (a) to read as follows:
§ 1037.231
Powertrain families.
(a) If you choose to perform powertrain testing as specified in 40 CFR 1036.545, use good engineering judgment to divide your product line into powertrain families that are expected to have similar fuel consumptions and CO 2 emission characteristics throughout the useful life. Your powertrain family is limited to a single model year.
* * * * *
69. Amend § 1037.235 by:
a. Revising the introductory text and paragraphs (a) and (c)(3); and
b. Removing paragraph (g)(3).
The revisions read as follows:
§ 1037.235
Testing requirements for certification.
This section describes the emission testing you must perform to show compliance with respect to the greenhouse gas standards in subpart B of this part, and to determine any input values from § 1037.520 that involve measured quantities.
(a) Select emission-data vehicles that represent production vehicles and components for the vehicle family consistent with the specifications in §§ 1037.205(o) and 1037.520. Where the test results will represent multiple vehicles or components with different emission performance, use good engineering judgment to select worst-case emission data vehicles or components. In the case of powertrain testing under 40 CFR 1036.545, select a test engine, test hybrid components, test axle and test transmission as applicable, by considering the whole range of vehicle models covered by the powertrain family and the mix of duty cycles specified in § 1037.510. If the powertrain has more than one transmission calibration, for example economy vs. performance, you may weight the results from the powertrain testing in 40 CFR 1036.545 by the percentage of vehicles in the family by prior model year for each configuration. This can be done, for example, through the use of survey data or based on the previous model year's sales volume. Weight the results of M fuel[cycle] , f npowertrain / v powertrain , and W [cycle] from table 5 to paragraph (o)(8)(i) of 40 CFR 1036.545 according to the percentage of vehicles in the family that use each transmission calibration.
* * * * *
(c) * * *
(3) Before we test one of your vehicles or components, we may set its adjustable parameters to any point within the practically adjustable ranges, if applicable.
* * * * *
70. Revise § 1037.241 to read as follows:
§ 1037.241
Demonstrating compliance with exhaust emission standards for greenhouse gas pollutants.
(a) Compliance determinations for purposes of certification depend on whether or not you participate in the ABT program in subpart H of this part.
(1) If none of your vehicle families generate or use emission credits in a given model year, each of your vehicle families is considered in compliance with the CO 2 emission standards in §§ 1037.105 and 1037.106 if all vehicle configurations in the family have modeled CO 2 emission rates from § 1037.520 that are at or below the applicable standards. A vehicle family is deemed not to comply if any vehicle configuration in the family has a modeled CO 2 emission rate that is above the applicable standard.
(2) If you generate or use emission credits with one or more vehicle families in a given model year, your vehicle families within an averaging set are considered in compliance with the CO 2 emission standards in §§ 1037.105 and 1037.106 if the sum of positive and negative credits for all vehicle configurations in those vehicle families lead to a zero balance or a positive balance of credits, except as allowed by § 1037.745. Note that the FEL is considered to be the applicable emission standard for an individual configuration.
(b) We may require you to provide an engineering analysis showing that the performance of your emission controls will not deteriorate during the useful life with proper maintenance. If we determine that your emission controls are likely to deteriorate during the useful life, we may require you to develop and apply deterioration factors consistent with good engineering judgment. For example, you may need to apply a deterioration factor to address deterioration of battery performance for a hybrid vehicle. Where the highest useful life emissions occur between the end of useful life and at the low-hour test point, base deterioration factors for the vehicles on the difference between (or ratio of) the point at which the highest emissions occur and the low-hour test point.
§ 1037.310
[Removed]
71. Remove § 1037.310.
72. Amend § 1037.315 by revising paragraph (a) to read as follows:
§ 1037.315
Audit procedures related to powertrain testing.
(a) For vehicles certified based on powertrain testing as specified in 40 CFR 1036.545, we may apply the selective enforcement audit requirements to the powertrain. If engine manufacturers perform the powertrain testing and include those results in their certification under 40 CFR part 1036, they are responsible for selective enforcement audits related to those results. Otherwise, the certificate holder for the vehicle is responsible for the selective enforcement audit.
* * * * *
73. Amend § 1037.401 by revising paragraph (b) to read as follows:
§ 1037.401
General provisions.
* * * * *
(b) We may measure the drag area of a vehicle you produced after it has been placed into service. We may use any of the procedures as specified in §§ 1037.525 and 1037.527 for measuring drag area. Your vehicle conforms to the regulations of this part with respect to aerodynamic performance if we measure its drag area to be at or below the maximum drag area allowed for the bin to which that configuration was certified.
74. Amend § 1037.501 by:
a. Revising paragraphs (a), (g)(1)(v), and (h); and
b. Removing paragraph (i).
The revisions read as follows:
§ 1037.501
General testing and modeling provisions.
* * * * *
(a) Except as specified in subpart B of this part, you must demonstrate that you meet emission standards using emission modeling as described in § 1037.520. This modeling depends on several measured values as described in this subpart. You may use fuel-mapping information from the engine manufacturer as described in 40 CFR 1036.535 and 1036.540, or you may use powertrain testing as described in 40 CFR 1036.545.
* * * * *
(g) * * *
(1) * * *
(v) For the Phase 2 or later standards, include side skirts meeting the specifications of this paragraph (g)(1)(v). The side skirts must be mounted flush with both sides of the trailer. The skirts must be an isosceles trapezoidal shape. Each skirt must have a height of 36±2 inches. The top edge of the skirt must be straight with a length of 341±2 inches. The bottom edge of the skirt must be straight with a length of 268±2 inches and have a ground clearance of 8±2 inches through that full length. The sides of the skirts must be straight. The rearmost point of the skirts must be mounted 32±2 inches in front of the centerline of the trailer tandem axle assembly. We may approve your request to use a skirt with different dimensions if these specified values are impractical or inappropriate for your test trailer, and you propose alternative dimensions that provide an equivalent or comparable degree of aerodynamic drag for your test configuration.
* * * * *
(h) Note that declared GEM inputs for fuel maps and aerodynamic drag area typically includes compliance margins to account for testing variability; for other measured GEM inputs, the declared values are typically the measured values without adjustment.
75. Revise and republish § 1037.510 to read as follows:
§ 1037.510
Duty-cycle exhaust testing.
This section applies for powertrain testing, cycle-average engine fuel mapping, certain off-cycle testing under § 1037.610, and the advanced-technology provisions of § 1037.615.
(a) Measure emissions by testing the powertrain on a powertrain dynamometer with the applicable duty cycles. Each duty cycle consists of a series of speed commands over time—variable speeds for the transient test and constant speeds for the highway cruise tests. None of these cycles include vehicle starting or warmup.
(1) Perform testing for Phase 1 vehicles as follows to generate credits or adjustment factors for off-cycle or advanced technologies:
(i) Transient cycle. The transient cycle is specified in appendix A to this part. Warm up the vehicle. Start the duty cycle within 30 seconds after concluding the preconditioning procedure. Start sampling emissions at the start of the duty cycle.
(ii) Cruise cycle. For the 55 mi/hr and 65 mi/hr highway cruise cycles, warm up the vehicle at the test speed, then sample emissions for 300 seconds while maintaining vehicle speed within ±1.0 mi/hr of the speed setpoint; this speed tolerance applies instead of the approach specified in 40 CFR 1066.425(b)(1) and (2).
(2) Perform cycle-average engine fuel mapping for Phase 2 and later vehicles as described in 40 CFR 1036.540. For powertrain testing under 40 CFR 1036.545 or § 1037.555, perform testing as described in this paragraph (a)(2) to generate GEM inputs for each simulated vehicle configuration, and test runs representing different idle conditions. Perform testing as follows:
(i) Transient cycle. The transient cycle is specified in appendix A to this part.
(ii) Highway cruise cycles. The grade portion of the route corresponding to the 55 mi/hr and 65 mi/hr highway cruise cycles is specified in appendix D to this part. Maintain vehicle speed between -1.0 mi/hr and 3.0 mi/hr of the speed setpoint; this speed tolerance applies instead of the approach specified in 40 CFR 1066.425(b)(1) and (2).
(iii) Drive idle. Perform testing at a loaded idle condition for Phase 2 vocational vehicles. For engines with an adjustable warm idle speed setpoint, test at the minimum warm idle speed and the maximum warm idle speed; otherwise simply test at the engine's warm idle speed. Warm up the powertrain as described in 40 CFR 1036.520(d). Within 60 seconds after concluding the warm-up, linearly ramp the powertrain down to zero vehicle speed over 20 seconds. Apply the brake and keep the transmission in drive (or clutch depressed for manual transmission). Stabilize the powertrain for (60±1) seconds and then sample emissions for (30±1) seconds.
(iv) Parked idle. Perform testing at a no-load idle condition for Phase 2 vocational vehicles. For engines with an adjustable warm idle speed setpoint, test at the minimum warm idle speed and the maximum warm idle speed; otherwise simply test at the engine's warm idle speed. Warm up the powertrain as described in 40 CFR 1036.520(d). Within 60 seconds after concluding the warm-up, linearly ramp the powertrain down to zero vehicle speed in 20 seconds. Put the transmission in park (or neutral for manual transmissions and apply the parking brake if applicable). Stabilize the powertrain for (180±1) seconds and then sample emissions for (600±1) seconds.
(3) Where applicable, perform testing on a chassis dynamometer as follows:
(i) Transient cycle. The transient cycle is specified in appendix A to this part. Warm up the vehicle by operating over one transient cycle. Within 60 seconds after concluding the warm up cycle, start emission sampling and operate the vehicle over the duty cycle.
(ii) Highway cruise cycle. The grade portion of the route corresponding to the 55 mi/hr and 65 mi/hr highway cruise cycles is specified in appendix D to this part. Warm up the vehicle by operating it at the appropriate speed setpoint over the duty cycle. Within 60 seconds after concluding the preconditioning cycle, start emission sampling and operate the vehicle over the duty cycle, maintaining vehicle speed within ±1.0 mi/hr of the speed setpoint; this speed tolerance applies instead of the approach specified in 40 CFR 1066.425(b)(1) and (2).
(b) Calculate the official emission result from the following equation:

Eq. 1037.510-1
Where:
e CO2comp = total composite mass of CO 2 emissions in g/ton-mile, rounded to the nearest whole number for vocational vehicles and to the first decimal place for tractors.
PL = the standard payload, in tons, as specified in § 1037.705.
v moving = mean composite weighted driven vehicle speed, excluding idle operation, as shown in table 1 to paragraph (c)(3) of this section for Phase 2 vocational vehicles. For other vehicles, let v moving = 1.
w [cycle] = weighting factor for the appropriate test cycle, as shown in table 1 to paragraph (c)(3) of this section.
m [cycle] = CO 2 mass emissions over each test cycle (other than idle).
D [cycle] = the total driving distance for the indicated duty cycle. Use 2.842 miles for the transient cycle, and use 13.429 miles for both of the highway cruise cycles.
m [cycle]-idle = CO 2 emission rate at idle.
Example: Class 7 vocational vehicle meeting the Phase 2 standards based on the Regional duty cycle.
PL = 5.6 tons
v moving = 38.41 mi/hr
w transient = 20% = 0.20
w drive-idle = 0% = 0
w parked-idle = 25% = 0.25
w 55 = 24% = 0.24
w 65 = 56% = 0.56
m transient = 4083 g
m 55 = 13834 g
m 65 = 17018 g
D transient = 2.8449 miles
D 55 = 13.429 miles
D 65 = 13.429 miles
m drive-idle = 4188 g/hr
m parked-idle = 3709 g/hr
(c) Weighting factors apply for each type of vehicle and for each duty cycle as follows:
(1) GEM applies weighting factors for specific types of tractors as shown in table 1 to paragraph (c)(3) of this section.
(2) GEM applies weighting factors for vocational vehicles as shown in table 1 to paragraph (c)(3) of this section. Modeling for Phase 2 vocational vehicles depends on characterizing vehicles by duty cycle to apply proper weighting factors and average speed values. Select either Urban, Regional, or Multi-Purpose as the most appropriate duty cycle for modeling emission results with each vehicle configuration, as specified in §§ 1037.140 and 1037.150.
(3) Table 1 to this paragraph (c)(3) follows:
Table 1 to Paragraph ( c )(3) of § 1037.510—Weighting Factors for Duty Cycles
| Distance-weighted | Transient (%) | 55 mi/hr cruise (%) | 65 mi/hr cruise (%) | Time-weighted ^a | Drive idle (%) | Parked idle (%) | Non-idle (%) | Average speed during non-idle cycles (mi/hr) ^b
Day Cabs | 19 | 17 | 64 | | | |
Sleeper Cabs | 5 | 9 | 86 | | | |
Heavy-haul Tractors | 19 | 17 | 64 | | | |
Vocational—Regional | 20 | 24 | 56 | 0 | 25 | 75 | 38.41
Vocational—Multi-Purpose (2b-7) | 54 | 29 | 17 | 17 | 25 | 58 | 23.18
Vocational—Multi-Purpose (8) | 54 | 23 | 23 | 17 | 25 | 58 | 23.27
Vocational—Urban (2b-7) | 92 | 8 | 0 | 15 | 25 | 60 | 16.25
Vocational—Urban (8) | 90 | 10 | 0 | 15 | 25 | 60 | 16.51
Vocational with conventional powertrain (Phase 1 only) | 42 | 21 | 37 | | | |
Vocational Hybrid Vehicles (Phase 1 only) | 75 | 9 | 16 | | | |
^a Note that these drive idle and non-idle weighting factors do not reflect additional drive idle that occurs during the transient cycle. The transient cycle does not include any parked idle.
^b These values apply even for vehicles not following the specified speed traces.
(d) For highway cruise and transient testing, compare actual second-by-second vehicle speed with the speed specified in the test cycle and ensure any differences are consistent with the criteria as specified in 40 CFR 1036.545(g)(1). If the speeds are not consistent with the criteria as specified in 40 CFR 1036.545(g)(1), the test is not valid and must be repeated.
(e) Run test cycles as specified in 40 CFR part 1066. For testing vehicles equipped with cruise control over the highway cruise cycles, you may use the vehicle's cruise control to control the vehicle speed. For vehicles equipped with adjustable vehicle speed limiters, test the vehicle with the vehicle speed limiter at its highest setting.
(f) For Phase 1, test the vehicle using its adjusted loaded vehicle weight, unless we determine this would be unrepresentative of in-use operation as specified in 40 CFR 1065.10(c)(1).
(g) For hybrid vehicles, correct for the net energy change of the energy storage device as described in 40 CFR 1066.501(a)(3).
§ 1037.515
[Removed]
76. Remove § 1037.515.
77. Amend § 1037.520 by revising the section heading, introductory text, and paragraphs (a)(2) introductory text, (b)(3), (c)(1) and (2), (e)(1) and (3), (g)(4), (j)(1), and (j)(2)(iii) to read as follows:
§ 1037.520
Modeling CO 2 emissions to show that vehicles comply with standards.
This section describes how to use the Greenhouse gas Emissions Model (GEM) to show compliance with the CO 2 standards of §§ 1037.105 and 1037.106. Use GEM version 2.0.1 to demonstrate compliance with Phase 1 standards; use GEM Phase 2, Version 4.0 to demonstrate compliance with Phase 2 and Phase 3 standards (both incorporated by reference, see § 1037.810). Use good engineering judgment when demonstrating compliance using GEM.
(a) * * *
(2) For Phase 2 and later vehicles, the GEM inputs described in paragraphs (a)(1)(i) through (v) of this section continue to apply. Note that the provisions in this part related to vehicle speed limiters and automatic engine shutdown systems are available for Phase 2 and later vocational vehicles. The rest of this section describes additional GEM inputs for demonstrating compliance with Phase 2 and later standards. Simplified versions of GEM apply for limited circumstances as follows:
* * * * *
(b) * * *
(3) For Phase 2 and later tractors other than heavy-haul tractors, determine bin levels and C d A inputs as follows:
(i) Determine bin levels for high-roof tractors based on aerodynamic test results as specified in § 1037.525 and summarized in the following table:
Table 3 to Paragraph ( b )(3)( i ) of § 1037.520—Bin Determinations for Phase 2 and Later High-Roof Tractors Based on Aerodynamic Test Results
[ C d A in m ^2 ]
Tractor type | Bin I | Bin II | Bin III | Bin IV | Bin V | Bin VI | Bin VII
Day Cabs | ≥7.2 | 6.6-7.1 | 6.0-6.5 | 5.5-5.9 | 5.0-5.4 | 4.5-4.9 | ≤4.4
Sleeper Cabs | ≥6.9 | 6.3-6.8 | 5.7-6.2 | 5.2-5.6 | 4.7-5.1 | 4.2-4.6 | ≤4.1
(ii) For low- and mid-roof tractors, you may either use the same bin level that applies for an equivalent high-roof tractor as shown in table 3 to paragraph (b)(3)(i) of this section, or you may determine your bin level based on aerodynamic test results as described in table 4 to this paragraph (b)(3)(ii).
Table 4 to Paragraph ( b )(3)( ii ) of § 1037.520—Bin Determinations for Phase 2 and Later Low-Roof and Mid-Roof Tractors Based on Aerodynamic Test Results
[ C d A in m ^2 ]
Tractor type | Bin I | Bin II | Bin III | Bin IV | Bin V | Bin VI | Bin VII
Low-Roof Cabs | ≥5.4 | 4.9-5.3 | 4.5-4.8 | 4.1-4.4 | 3.8-4.0 | 3.5-3.7 | ≤3.4
Mid-Roof Cabs | ≥5.9 | 5.5-5.8 | 5.1-5.4 | 4.7-5.0 | 4.4-4.6 | 4.1-4.3 | ≤4.0
(iii) Determine the C d A input according to the tractor's bin level as described in the following table:
Table 5 to Paragraph ( b )(3)( iii ) of § 1037.520—Phase 2 and Later C d A Tractor Inputs Based on Bin Level
Tractor type | Bin I | Bin II | Bin III | Bin IV | Bin V | Bin VI | Bin VII
High-Roof Day Cabs | 7.45 | 6.85 | 6.25 | 5.70 | 5.20 | 4.70 | 4.20
High-Roof Sleeper Cabs | 7.15 | 6.55 | 5.95 | 5.40 | 4.90 | 4.40 | 3.90
Low-Roof Cabs | 6.00 | 5.60 | 5.15 | 4.75 | 4.40 | 4.10 | 3.80
Mid-Roof Cabs | 7.00 | 6.65 | 6.25 | 5.85 | 5.50 | 5.20 | 4.90
* * * * *
(c) * * *
(1) Use good engineering judgment to determine a tire's revolutions per mile to the nearest whole number as specified in SAE J1025 (incorporated by reference, see § 1037.810). Note that for tire sizes that you do not test, we will treat your analytically derived revolutions per mile the same as test results, and we may perform our own testing to verify your values. We may require you to test a sample of additional tire sizes that we select.
(2) Measure tire rolling resistance in newton per kilonewton as specified in ISO 28580 (incorporated by reference, see § 1037.810), except as specified in this paragraph (c). Use good engineering judgment to ensure that your test results are not biased low. You may ask us to identify a reference test laboratory to which you may correlate your test results. Prior to beginning the test procedure in Section 7 of ISO 28580 for a new bias-ply tire, perform a break-in procedure by running the tire at the specified test speed, load, and pressure for (60±2) minutes.
* * * * *
(e) * * *
(1) Vehicle weight reduction inputs for wheels are specified relative to dual-wide tires with conventional steel wheels. For purposes of this paragraph (e)(1), an aluminum alloy qualifies as light-weight if a dual-wide drive wheel made from this material weighs at least 21 pounds less than a comparable conventional steel wheel. The inputs are listed in table 6 to this paragraph (e)(1). For example, a tractor or vocational vehicle with aluminum steer wheels and eight (4×2) dual-wide aluminum drive wheels would have an input of 210 pounds (2×21 + 8×21).
Table 6 to Paragraph ( e )(1) of § 1037.520—Wheel-Related Weight Reductions
Tire type | Material | Weight reduction— Phase 1 (pounds per wheel) | Weight reduction— Phase 2 and later (pounds per wheel)
Wide-Base Single Drive Tire with . . . ^a | Steel Wheel | 84 | 84
| Aluminum Wheel | 139 | 147
| Light-Weight Aluminum Alloy Wheel | 147 | 147
Steer Tire or Dual-wide Drive Tire with . . . | High-Strength Steel Wheel | 8 | 8
| Aluminum Wheel | 21 | 25
| Light-Weight Aluminum Alloy Wheel | 30 | 25
^a The weight reduction for wide-base tires accounts for reduced tire weight relative to dual-wide tires.
* * * * *
(3) Weight-reduction inputs for vocational-vehicle components other than wheels are specified in the following table:
Table 8 to Paragraph ( e )(3) of § 1037.520—Nonwheel-Related Weight Reductions From Alternative Materials for Phase 2 and Later Vocational Vehicles
[Pounds] ^a
Component | Material | Vehicle type | Light HDV | Medium HDV ^b | Heavy HDV
Axle Hubs—Non-Drive | Aluminum | 40 | 40
| Axle Hubs—Non-Drive | High Strength Steel | 5 | 5
Axle—Non-Drive | Aluminum | 60 | 60
Axle—Non-Drive | High Strength Steel | 15 | 15
Brake Drums—Non-Drive | Aluminum | 60 | 60
Brake Drums—Non-Drive | High Strength Steel | 42 | 42
Axle Hubs—Drive | Aluminum | 40 | 80
Axle Hubs—Drive | High Strength Steel | 10 | 20
Brake Drums—Drive | Aluminum | 70 | 140
Brake Drums—Drive | High Strength Steel | 37 | 74
Suspension Brackets, Hangers | Aluminum | 67 | 100
Suspension Brackets, Hangers | High Strength Steel | 20 | 30
Crossmember—Cab | Aluminum | 10 | 15 | 15
Crossmember—Cab | High Strength Steel | 2 | 5 | 5
Crossmember—Non-Suspension | Aluminum | 15 | 15 | 15
Crossmember—Non-Suspension | High Strength Steel | 5 | 5 | 5
Crossmember—Suspension | Aluminum | 15 | 25 | 25
Crossmember—Suspension | High Strength Steel | 6 | 6 | 6
Driveshaft | Aluminum | 12 | 40 | 50
Driveshaft | High Strength Steel | 5 | 10 | 12
Frame Rails | Aluminum | 120 | 300 | 440
Frame Rails | High Strength Steel | 40 | 40 | 87
^a Weight-reduction values apply per vehicle unless otherwise noted.
^b For Medium HDV with 6×4 or 6×2 axle configurations, use the values for Heavy HDV.
* * * * *
(g) * * *
(4) GEM inputs associated with powertrain testing include powertrain family, transmission calibration identifier, test data from 40 CFR 1036.545, and the powertrain test configuration (dynamometer connected to transmission output or wheel hub). You do not need to identify or provide inputs for transmission gear ratios, fuel map data, or engine torque curves, which would otherwise be required under paragraph (f) of this section.
* * * * *
(j) * * *
(1) Intelligent controls. Enter 2 for tractors with predictive cruise control. This includes any cruise control system that incorporates satellite-based global-positioning data for controlling operator demand. For tractors without predictive cruise control and for all vocational vehicles, enter 1.5 if they have neutral coasting or the installed engine deactivates all cylinders closing all intake and exhaust valves when operator demand is zero while the vehicle is in motion, unless good engineering judgment indicates that a lower percentage should apply.
(2) * * *
(iii) If vehicles have a high-efficiency air conditioning compressor, enter 0.5 for tractors, 0.5 for vocational Heavy HDV, and 1 for other vocational vehicles. This includes all electrically powered compressors. It also include mechanically powered compressors if the coefficient of performance improves by 10 percent or greater over the baseline design, consistent with the provisions for improved evaporators and condensers in 40 CFR 86.1868-12(h)(5).
* * * * *
78. Amend § 1037.525 by revising paragraphs (a) introductory text, (b), (c)(1) introductory text, (c)(2) introductory text, and (c)(3)(v) to read as follows:
§ 1037.525
Aerodynamic measurements for tractors.
* * * * *
(a) General provisions. The GEM input for a tractor's aerodynamic performance is a C d value for Phase 1 and a C d A value for Phase 2 and later. The input value is measured or calculated for a tractor in a specific test configuration with a trailer, such as a high-roof tractor with a box van meeting the requirements for the standard trailer.
* * * * *
(b) Adjustments to correlate with coastdown testing. Adjust aerodynamic drag values from alternate methods to be equivalent to the corresponding values from coastdown measurements as follows:
(1) Determine the functional relationship between your alternate method and coastdown testing. Specify this functional relationship as F alt-aero for a given alternate drag measurement method. The effective yaw angle, C eff , is assumed to be zero degrees for Phase 1. For Phase 2 and later, determine C eff from coastdown test results using the following equation:
Eq. 1037.525-1
Where:
C d A coastdown ( C eff ) = the average drag area measured during coastdown at an effective yaw angle, C eff .
C d A alt ( C eff ) = the average drag area calculated from an alternate drag measurement method at an effective yaw angle, C eff .
(2) Unless good engineering judgment dictates otherwise, assume that coastdown drag is proportional to drag measured using alternate methods and apply a constant adjustment factor, F alt-aero , for a given alternate drag measurement method of similar vehicles.
(3) Determine F alt-aero by performing coastdown testing and applying your alternate method on the same vehicles. Consider all applicable test data including data collected during selective enforcement audits. Unless we approve another vehicle, one vehicle must be a Class 8 high-roof sleeper cab with a full aerodynamics package pulling a standard trailer. Where you have more than one tractor model meeting these criteria, use the tractor model with the highest projected sales. If you do not have such a tractor model, you may use your most comparable tractor model with our prior approval. In the case of alternate methods other than those specified in this subpart, good engineering judgment may require you to determine your adjustment factor based on results from more than the specified minimum number of vehicles.
(4) Measure the drag area using your alternate method for a Phase 2 and later tractor used to determine F alt-aero with testing at yaw angles of 0°, ±1°, ±3°, ±4.5°, ±6°, and ±9° (you may include additional angles), using direction conventions described in Figure 2 of SAE J1252 (incorporated by reference, see § 1037.810). Also, determine the drag area at the coastdown effective yaw angle, C d A alt ( C eff ), by taking the average drag area at C eff and− C eff for your vehicle using the same alternate method.
(5) For Phase 2 and later testing, determine separate values of F alt-aero for at least one high-roof day cab and one high-roof sleeper cab for model year 2021, at least two high-roof day cabs and two high-roof sleeper cabs for model year 2024, and at least three high-roof day cabs and three high-roof sleeper cabs for model year 2027. These test requirements are cumulative; for example, you may meet these requirements by testing two vehicles to support model year 2021 certification and four additional vehicles to support model year 2023 certification. For any untested tractor models, apply the value of F alt-aero from the tested tractor model that best represents the aerodynamic characteristics of the untested tractor model, consistent with good engineering judgment. Testing under this paragraph (b)(5) continues to be valid for later model years until you change the tractor model in a way that causes the test results to no longer represent production vehicles. You must also determine unique values of F alt-aero for low-roof and mid-roof tractors if you determine C d A values based on low or mid-roof tractor testing as shown in § 1037.520(b)(3)(ii). For Phase 1 testing, if good engineering judgment allows it, you may calculate a single, constant value of F alt-aero for your whole product line by dividing the coastdown drag area, C d A coastdown , by drag area from your alternate method, C d A alt.
(6) Determine F alt-aero to at least three decimal places. For example, if your coastdown testing results in a drag area of 6.430, but your wind tunnel method results in a drag area of 6.200, F alt-aero would be 1.037 (or a higher value you declare).
(7) If a tractor and trailer cannot be configured to meet the gap requirements specified in § 1037.501(g)(1)(ii), test with the trailer positioned as close as possible to the specified gap dimension and use good engineering judgment to correct the results to be equivalent to a test configuration meeting the specified gap dimension. For example, we may allow you to correct your test output using an approved alternate method or substitute a test vehicle that is capable of meeting the required specifications and is otherwise aerodynamically equivalent. The allowance in this paragraph (b)(7) applies for certification, confirmatory testing, SEA, and all other testing to demonstrate compliance with standards.
(8) You may ask us for preliminary approval of your coastdown testing under § 1037.210. We may witness the testing.
(c) * * *
(1) Apply the following method for all Phase 2 and later testing with an alternate method:
* * * * *
(2) Apply the following method for Phase 2 and later coastdown testing other than coastdown testing used to establish F alt-aero :
* * * * *
(3) * * *
(v) As an alternative, you may calculate the wind-averaged drag area according to SAE J1252 (incorporated by reference, see § 1037.810) and substitute this value into Eq. 1037.525-4 for the ±6° drag area.
* * * * *
§ 1037.526
[Removed]
79. Remove § 1037.526.
80. Revise § 1037.527 to read as follows:
§ 1037.527
Aerodynamic measurements for vocational vehicles.
This section describes an optional methodology for determining improved aerodynamic drag area, C d A , for vocational vehicles, as described in § 1037.520(m), rather than using the assigned values. A vocational vehicle's aerodynamic performance is based on a D C d A value relative to a baseline vehicle. Determine a D d A value by performing A to B testing as follows:
(a) Use any of the procedures described in this subpart, with appropriate adjustments, for calculating drag area.
(b) Determine a baseline C d A value for a vehicle representing a production configuration without the aerodynamic improvement. Repeat this testing and measure C d A for a vehicle with the improved aerodynamic design.
(c) Use good engineering judgment to perform paired tests that accurately demonstrate the reduction in aerodynamic drag associated with the improved design.
(d) Measure C d A in m ^2 to two decimal places. Calculate D d A by subtracting the drag area for the test vehicle from the drag area for the baseline vehicle.
81. Amend § 1037.528 by:
a. Revising the introductory text and paragraphs (b) introductory text, (h)(5) introductory text, (h)(5)(iv), and (h)(6) introductory text;
b. Removing paragraph (h)(7);
c. Redesignating paragraphs (h)(8) through (12) as paragraphs (h)(7) through (11), respectively; and
d. Revising newly redesignated paragraph (h)(10).
The revisions read as follows:
§ 1037.528
Coastdown procedures for calculating drag area ( C d A ).
This section describes the reference method for calculating drag area, C d A , for tractors using coastdown testing. Follow the provisions of Sections 1 through 9 of SAE J2263 (incorporated by reference, see § 1037.810), with the clarifications and exceptions described in this section. Several of the exceptions in this section are from SAE J1263 (incorporated by reference, see § 1037.810). The coastdown procedures in 40 CFR 1066.310 apply instead of the provisions of this section for Phase 1 tractors.
* * * * *
(b) To determine C d A values for a, perform coastdown testing with a tractor-trailer combination using the manufacturer's tractor and a standard trailer. Prepare the tractor-trailer combination for testing as follows:
* * * * *
(h) * * *
(5) Calculate the drive-axle spin loss force at high and low speeds, F spin[speed] , and determine D F spin as follows:
* * * * *
(iv) Calculate D F spin using the following equation:
D
F
spin
=
F
spinhi
−
F
spinlo

Eq. 1037.528-10
Example:
D F spin = 129.7−52.7
D F spin = 77.0 N
(6) Calculate the tire rolling resistance force at high and low speeds for steer, drive, and trailer axle positions, F TRR[speed,axle] , and determine D F TRR , the rolling resistance difference between 65 mi/hr and 15 mi/hr, for each tire as follows:
* * * * *
(10) Calculate drag area, C d A, in m ^2 for each high-speed segment using the following equation, expressed to at least three decimal places:

Eq. 1037.528-16
Where:
F hi = road load force at high speed determined from Eq. 1037.528-7.
F lo,pair = the average of F lo values for a pair of opposite direction runs calculated as described in paragraph (h)(8) of this section.
D F spin = the difference in drive-axle spin loss force between high-speed and low-speed coastdown segments as described in paragraph (h)(5) of this section.
D F TRR = the difference in tire rolling resistance force between high-speed and low-speed coastdown segments as described in paragraph (h)(6) of this section.
v 2 air,lo,pair = the average of v 2 air,lo values for a pair of opposite direction runs calculated as described in paragraph (h)(8) of this section.
R = specific gas constant = 287.058 J/(kg·K).
T = mean air temperature expressed to at least one decimal Place.
P act = mean absolute air pressure expressed to at least one decimal place.
Example:
F h i = 4645.5 N
F lo,pair = 1005.0 N
ΔF spin = 77.0 N
ΔF TRR = 187.4 N
v 2 air,hi = 933.4 m ^2 /s ^2
v 2 air,lo,pair = 43.12 m ^2 /s ^2
R = 287.058 J/(kg·K)
T = 285.97 K
R act = 101.727 kPa = 101727 Pa
* * * * *
82. Revise and republish § 1037.530 to read as follows:
§ 1037.530
Wind tunnel procedures for calculating drag area ( C d A ).
This section describes an alternate method for calculating drag area, C d A , for tractors using wind tunnel testing.
(a) You may measure drag areas consistent with published SAE procedures as described in this section using any wind tunnel recognized by the Subsonic Aerodynamic Testing Association, subject to the provisions of § 1037.525. If your wind tunnel does not meet the specifications described in this section, you may ask us to approve it as an alternate method under § 1037.525(d). All wind tunnels and wind tunnel tests must meet the specifications described in SAE J1252 (incorporated by reference, see § 1037.810), with the following exceptions and additional provisions:
(1) The Overall Vehicle Reynolds number, Re # w , must be at least 1.0·10 ^6 . Tests for Reynolds effects described in Section 7.1 of SAE J1252 are not required.
(2) For full-scale wind tunnel testing, use good engineering judgment to select a trailer that is a reasonable representation of the trailer used for reference coastdown testing. For example, where your wind tunnel is not long enough to test the tractor with a standard 53 foot box van, it may be appropriate to use a shorter box van. In such a case, the correlation developed using the shorter trailer would only be valid for testing with the shorter trailer.
(3) For reduced-scale wind tunnel testing, use a one-eighth or larger scale model of a tractor and trailer that is sufficient to simulate airflow through the radiator inlet grill and across an engine geometry that represents engines commonly used in your test vehicle.
(b) Open-throat wind tunnels must also meet the specifications of SAE J2071 (incorporated by reference, see § 1037.810).
(c) To determine C dA values, perform wind tunnel testing with a tractor-trailer combination using the manufacturer's tractor and a standard trailer. Use a moving/rolling floor if the facility has one. For Phase 1 tractors, conduct the wind tunnel tests at a zero yaw angle. For Phase 2 and later vehicles, conduct the wind tunnel tests by measuring the drag area at yaw angles of +4.5° and −4.5° and calculating the average of those two values.
(d) In your request to use wind tunnel testing, describe how you meet all the specifications that apply under this section, using terminology consistent with SAE J1594 (incorporated by reference, see § 1037.810). If you request our approval to use wind tunnel testing even though you do not meet all the specifications of this section, describe how your method nevertheless qualifies as an alternate method under § 1037.525(d) and include all the following information:
(1) Identify the name and location of the test facility for your wind tunnel method.
(2) Background and history of the wind tunnel.
(3) The wind tunnel's layout (with diagram), type, and construction (structural and material).
(4) The wind tunnel's design details: the type and material for corner turning vanes, air settling specification, mesh screen specification, air straightening method, tunnel volume, surface area, average duct area, and circuit length.
(5) Specifications related to the wind tunnel's flow quality: temperature control and uniformity, airflow quality, minimum airflow velocity, flow uniformity, angularity and stability, static pressure variation, turbulence intensity, airflow acceleration and deceleration times, test duration flow quality, and overall airflow quality achievement.
(6) Test/working section information: test section type ( e.g., open, closed, adaptive wall) and shape ( e.g., circular, square, oval), length, contraction ratio, maximum air velocity, maximum dynamic pressure, nozzle width and height, plenum dimensions and net volume, maximum allowed model scale, maximum model height above road, strut movement rate (if applicable), model support, primary boundary layer slot, boundary layer elimination method, and photos and diagrams of the test section.
(7) Fan section description: fan type, diameter, power, maximum angular speed, maximum speed, support type, mechanical drive, and sectional total weight.
(8) Data acquisition and control (where applicable): acquisition type, motor control, tunnel control, model balance, model pressure measurement, wheel drag balances, wing/body panel balances, and model exhaust simulation.
(9) Moving ground plane or rolling road (if applicable): construction and material, yaw table and range, moving ground length and width, belt type, maximum belt speed, belt suction mechanism, platen instrumentation, temperature control, and steering.
(10) Facility correction factors and purpose.
83. Amend § 1037.532 by revising the section heading, introductory text, and paragraphs (a) introductory text, (b), and (c) introductory text to read as follows:
§ 1037.532
Using computational fluid dynamics for calculating drag area ( C dA ).
This section describes an alternate method for calculating drag area, C dA, for tractors using commercially available computational fluid dynamics (CFD) software.
(a) For Phase 2 and later vehicles, use SAE J2966 (incorporated by reference, see § 1037.810), with the following clarifications and exceptions:
* * * * *
(b) For Phase 1 tractors, apply the procedures as specified in paragraphs (c) through (f) of this section. Paragraphs (c) through (f) apply for Phase 2 and later vehicles only as specified in paragraph (a) of this section.
(c) To determine C dA values, perform CFD modeling based on a tractor-trailer combination using the manufacturer's tractor and a standard trailer. Perform all CFD modeling as follows:
* * * * *
84. Amend § 1037.534 by revising the introductory text and paragraph (c) introductory text to read as follows:
§ 1037.534
Constant-speed procedure for calculating drag area ( C dA ).
This section describes an alternate method for calculating drag area, C dA, for tractors using constant-speed aerodynamic drag testing.
* * * * *
(c) Vehicle preparation. Perform testing with a tractor-trailer combination using the manufacturer's tractor and a standard trailer. Prepare the tractor-trailer combination for testing as described in § 1037.528(b). Install measurement instruments meeting the requirements of 40 CFR part 1065, subpart C, that have been calibrated as described in 40 CFR part 1065, subpart D, as follows:
* * * * *
85. Amend § 1037.540 by revising the introductory text and paragraphs (c), (d)(4), and (f) to read as follows:
§ 1037.540
Special procedures for testing vehicles with hybrid power take-off.
This section describes optional procedures for quantifying the reduction in greenhouse gas emissions for vehicles as a result of running power take-off (PTO) devices with a hybrid energy delivery system. See 40 CFR 1036.545 for powertrain testing requirements that apply for drivetrain hybrid systems. The procedures are written to test the PTO by ensuring that the engine produces all of the energy with no net change in stored energy (charge-sustaining), and for plug-in hybrid electric vehicles, also allowing for drawing down the stored energy (charge-depleting). The full charge-sustaining test for the hybrid vehicle is from a fully charged rechargeable energy storage system (RESS) to a depleted RESS and then back to a fully charged RESS. You must include all hardware for the PTO system. You may ask us to modify the provisions of this section to allow testing hybrid vehicles that use a technology other than batteries for storing energy, consistent with good engineering judgment. For plug-in hybrid electric vehicles, use a utility factor to properly weight charge-sustaining and charge-depleting operation as described in paragraph (f)(3) of this section.
* * * * *
(c) Measure PTO emissions from the fully warmed-up hybrid vehicle as follows:
(1) Perform the steps in paragraphs (b)(1) through (5) of this section.
(2) Prepare the vehicle for testing by operating it as needed to stabilize the RESS at a full state of charge (or equivalent for vehicles that use a technology other than batteries for storing energy).
(i) For plug-in hybrid electric vehicles, we recommend charging the battery with an external electrical source.
(ii) For other vehicles, we recommend running back-to-back PTO tests until engine operation is initiated to charge the RESS. The RESS should be fully charged once engine operation stops. The ignition should remain in the “on” position.
(3) Turn the vehicle and PTO system off while the sampling system is being prepared.
(4) Turn the vehicle and PTO system on such that the PTO system is functional, whether it draws power from the engine or a battery.
(5) Operate the vehicle over one or both of the denormalized PTO duty cycles without turning the vehicle off, until the engine starts and then shuts down. This may require running multiple repeats of the PTO duty cycles. For non-PHEV systems that are not plug-in hybrid systems, the test cycle is completed once the engine shuts down. For plug-in hybrid systems, continue running until the PTO hybrid is running in a charge-sustaining mode such that the “End of Test” requirements defined in 40 CFR 1066.501(a)(3) are met. Measure emissions as described in paragraph (b)(7) of this section. Use good engineering judgment to minimize the variability in testing between the two types of vehicles.
(6) For plug-in hybrid electric vehicles, follow 40 CFR 1066.501(a)(3) to divide the test into charge-depleting and charge-sustaining operation.
(7) Apply cycle-validation criteria as described in paragraph (b)(8) of this section to both charge-sustaining and charge-depleting operation.
(d) * * *
(4) Divide the total PTO operating time from paragraph (d)(3) of this section by a conversion factor of 0.0144 hr/mi for Phase 1 and 0.0217 hr/mi for Phase 2 and later to determine the equivalent distance driven. The conversion factors are based on estimates of average vehicle speed and PTO operating time as a percentage of total engine operating time; the Phase 2 and later conversion factor is calculated from an average speed of 27.1 mi/hr and PTO operation 37% of engine operating time, as follows:

Eq. 1037.540-2a
* * * * *
(f) For Phase 2 and later, calculate the delta PTO fuel results for input into GEM during vehicle certification as follows:
(1) Determine fuel consumption by calculating the mass of fuel for each test in grams, m fuelPTO, without rounding, as described in 40 CFR 1036.540(d)(12) for both the conventional vehicle and the charge-sustaining and charge-depleting portions of the test for the hybrid vehicle as applicable.
(2) Divide the fuel mass by the applicable distance determined in paragraph (d)(4) of this section and the appropriate standard payload as defined in § 1037.801 to determine the fuel-consumption rate in g/ton-mile.
(3) For plug-in hybrid electric vehicles calculate the utility factor weighted fuel-consumption rate in g/ton-mile, as follows:
(i) Determine the utility factor fraction for the PTO system from the table in appendix E of this part using interpolation based on the total time of the charge-depleting portion of the test as determined in paragraphs (c)(6) and (d)(3) of this section.
(ii) Weight the emissions from the charge-sustaining and charge-depleting portions of the test to determine the utility factor-weighted fuel mass, m fuelUF[cycle]plug-in, using the following equation:

Eq. 1037.540-3
Where:
i = an indexing variable that represents one test interval.
N = total number of charge-depleting test intervals.
m fuelPTOCD = total mass of fuel per ton-mile in the charge-depleting portion of the test for each test interval, i, starting from i = 1.
UF DCD i = utility factor fraction at time t CD i as determined in paragraph (f)(3)(i) of this section for each test interval, i, starting from i = 1.
j = an indexing variable that represents one test interval.
M = total number of charge-sustaining test intervals.
m fuelPTOCS = total mass of fuel per ton-mile in the charge-sustaining portion of the test for each test interval, j, starting from j = 1.
UF RCD = utility factor fraction at the full charge-depleting time, t CD, as determined by interpolating the utility factor curve in appendix E to this part. t CD is the sum of the time over N charge-depleting test intervals.
(4) Calculate the difference between the conventional PTO emissions result and the hybrid PTO emissions result for input into GEM.
* * * * *
§ 1037.550
[Removed]
86. Remove § 1037.550.
87. Revise § 1037.551 to read as follows:
§ 1037.551
Engine-based simulation of powertrain testing.
The regulations in 40 CFR 1036.545 describe how to measure fuel consumption over specific duty cycles with an engine coupled to a transmission; 40 CFR 1036.545(a)(5) describes how to create equivalent duty cycles for repeating those same measurements with just the engine. This section describes how to perform this engine testing to simulate the powertrain test. These engine-based measurements may be used for selective enforcement audits as described in § 1037.301, as long as the test engine's operation represents the engine operation observed in the powertrain test. If we use this approach for confirmatory testing, when making compliance determinations, we will consider the uncertainty associated with this approach relative to full powertrain testing. Use of this approach for engine SEAs is optional for engine manufacturers.
(a) Use the procedures of 40 CFR part 1065 to set up the engine, measure emissions, and record data. Measure individual parameters and emission constituents as described in this section. Measure NO X emissions for each sampling period in grams. You may perform these measurements using a NO X emission-measurement system that meets the requirements of 40 CFR part 1065, subpart J. Include these measured NO X values any time you report to us your greenhouse gas emissions or fuel consumption values from testing under this section. If a system malfunction prevents you from measuring NO X emissions during a test under this section but the test otherwise gives valid results, you may consider this a valid test and omit the NO X emission measurements; however, we may require you to repeat the test if we determine that you inappropriately voided the test with respect to NO X emission measurement. For hybrid powertrains, correct for the net energy change of the energy storage device as described in 40 CFR 1066.501(a)(3).
(b) Operate the engine over the applicable engine duty cycles corresponding to the vehicle cycles specified in § 1037.510(a)(2) for powertrain testing over the applicable vehicle simulations described in 40 CFR 1036.545(j). Warm up the engine to prepare for the transient test or one of the highway cruise cycles by operating it one time over one of the simulations of the corresponding duty cycle. Warm up the engine to prepare for the idle test by operating it over a simulation of the 65-mi/hr highway cruise cycle for 600 seconds. Within 60 seconds after concluding the warm up cycle, start emission sampling while the engine operates over the duty cycle. You may perform any number of test runs directly in succession once the engine is warmed up. Perform cycle validation as described in 40 CFR 1065.514 for engine speed, torque, and power.
(c) Calculate the mass of fuel consumed as described in 40 CFR 1036.545(n) and (o). Correct each measured value for the test fuel's mass-specific net energy content as described in 40 CFR 1036.550. Use these corrected values to determine whether the engine's emission levels conform to the declared fuel-consumption rates from the powertrain test.
88. Amend § 1037.555 by revising the introductory text and paragraph (h) to read as follows:
§ 1037.555
Special procedures for testing Phase 1 hybrid systems.
This section describes a powertrain testing procedure for simulating a chassis test with a pre-transmission or post-transmission hybrid system to perform A to B testing of Phase 1 vehicles. These procedures may also be used to perform A to B testing with non-hybrid systems. See 40 CFR 1036.545 for Phase 2 and later hybrid systems.
* * * * *
(h) Correct for the net energy change of the energy storage device as described in 40 CFR 1066.501(a)(3).
* * * * *
89. Amend § 1037.560 by revising paragraphs (e)(2) and (h)(1) to read as follows:
§ 1037.560
Axle efficiency test.
* * * * *
(e) * * *
(2) Maintain gear oil temperature at (81 to 83) °C. You may alternatively specify a lower range by shifting both temperatures down by the same amount for any or all test points. We will test your axle assembly using the same temperature range(s) you specify for your testing. If you use interpolation for mapping, use the same temperature range for all test points used in the interpolation. You may use an external gear oil conditioning system, as long as it does not affect measured values.
* * * * *
(h) * * *
(1) Test at least three axle assemblies within the same family representing at least the smallest axle ratio, the largest axle ratio, and an axle ratio closest to the arithmetic mean from the two other tested axle assemblies. Test each axle assembly as described in this section at the same speed and torque setpoints. Test all axle assemblies using the same gear oil temperature range for each setpoint as described in paragraph (e)(2) of this section.
* * * * *
90. Amend § 1037.601 by revising paragraph (b) to read as follows:
§ 1037.601
General compliance provisions.
* * * * *
(b) Vehicles exempted from the applicable standards of 40 CFR part 86 or 1036 other than glider vehicles are exempt from the standards of this part without request. Similarly, vehicles other than glider vehicles are exempt without request if the installed engine is exempted from the applicable standards in 40 CFR part 86 or 1036.
* * * * *
91. Amend § 1037.610 by revising paragraph (f)(2) to read as follows:
§ 1037.610
Vehicles with off-cycle technologies.
* * * * *
(f) * * *
(2) For model years 2021 and later, you may not rely on an approval for model years before 2021. You must separately request our approval before applying an improvement factor or credit under this section for Phase 2 and later vehicles, even if we approved an improvement factor or credit for similar vehicle models before model year 2021. Note that Phase 2 and later approval may carry over for multiple years.
* * * * *
92. Revise and republish § 1037.615 to read as follows:
§ 1037.615
Advanced technologies.
(a) This section describes how to calculate emission credits for advanced technologies. You may calculate Phase 1 advanced technology credits through model year 2020 for hybrid vehicles with regenerative braking, vehicles equipped with Rankine-cycle engines, battery electric vehicles, and fuel cell electric vehicles. You may calculate Phase 2 advanced technology credits through model year 2026 for plug-in hybrid electric vehicles, battery electric vehicles, and fuel cell electric vehicles. You may calculate Phase 3 advanced technology credits for model year 2027 for plug-in hybrid electric vehicles, battery electric vehicles, and fuel cell electric vehicles. You may not generate credits for Phase 1 engine technologies for which the engines generate CO 2 credits under 40 CFR part 1036.
(b) Generate Phase 1 advanced-technology credits for vehicles other than battery electric vehicles as follows:
(1) Measure the effectiveness of the advanced system by chassis-testing a vehicle equipped with the advanced system and an equivalent conventional vehicle, or by testing the hybrid systems and the equivalent non-hybrid systems as described in § 1037.555. Test the vehicles as specified in subpart F of this part. For purposes of this paragraph (b), a conventional vehicle is considered to be equivalent if it has the same footprint (as defined in 40 CFR 86.1803), vehicle service class, aerodynamic drag, and other relevant factors not directly related to the hybrid powertrain. If you use § 1037.540 to quantify the benefits of a hybrid system for PTO operation, the conventional vehicle must have the same number of PTO circuits and have equivalent PTO power. If you do not produce an equivalent vehicle, you may create and test a prototype equivalent vehicle. The conventional vehicle is considered Vehicle A and the advanced vehicle is considered Vehicle B. We may specify an alternate cycle if your vehicle includes a power take-off.
(2) Calculate an improvement factor and g/ton-mile benefit using the following equations and parameters:
(i) Improvement Factor = [(Emission Rate A)−(Emission Rate B)]/(Emission Rate A).
(ii) g/ton-mile benefit = Improvement Factor × (GEM Result B).
(iii) Emission Rates A and B are the g/ton-mile CO 2 emission rates of the conventional and advanced vehicles, respectively, as measured under the test procedures specified in this section. GEM Result B is the g/ton-mile CO 2 emission rate resulting from emission modeling of the advanced vehicle as specified in § 1037.520.
(3) If you apply an improvement factor to multiple vehicle configurations using the same advanced technology, use the vehicle configuration with the smallest potential reduction in greenhouse gas emissions resulting from the hybrid capability.
(4) Use the equation in § 1037.705 to convert the g/ton-mile benefit to emission credits (in Mg). Use the g/ton-mile benefit in place of the (Std−FEL) term.
(c) See § 1037.540 for special testing provisions related to Phase 1 vehicles equipped with hybrid power take-off units.
(d) For Phase 2 and Phase 3 plug-in hybrid electric vehicles and for fuel cells powered by any fuel other than hydrogen, calculate CO 2 credits using an FEL based on emission measurements from powertrain testing. Phase 2 and Phase 3 advanced technology credits do not apply for hybrid vehicles that have no plug-in capability.
(e) [Reserved]
(f) For battery electric vehicles and for fuel cell electric vehicles, calculate CO 2 credits using an FEL of 0 g/ton-mile. Note that these vehicles are subject to compression-ignition standards for CO 2 .
(g) As specified in subpart H of this part, advanced-technology credits generated from Phase 1 vehicles under this section may be used under this part outside of the averaging set in which they were generated, or they may be used under 40 CFR part 86, subpart S, or 40 CFR part 1036. Advanced-technology credits generated from Phase 2 and later vehicles are subject to the averaging-set restrictions that apply to other emission credits.
(h) You may certify using both provisions of this section and the off-cycle technology provisions of § 1037.610, provided you do not double count emission benefits.
§ 1037.620
[Amended]
93. Amend § 1037.620 by removing paragraph (c) and redesignating paragraphs (d) through (f) as paragraphs (c) through (e), respectively.
94. Amend § 1037.622 by revising the introductory text and paragraph (d)(5) to read as follows:
§ 1037.622
Shipment of partially complete vehicles to secondary vehicle manufacturers.
This section specifies how manufacturers may introduce partially complete vehicles into U.S. commerce (or in the case of certain custom vehicles, introduce complete vehicles into U.S. commerce for modification by a small manufacturer). The provisions of this section are intended to accommodate normal business practices without compromising the effectiveness of certified emission controls. You may not use the provisions of this section to circumvent the intent of this part. For vehicles subject to both exhaust greenhouse gas and evaporative standards, the provisions of this part apply separately for each certificate.
* * * * *
(d) * * *
(5) The provisions of this paragraph (d) may apply separately for vehicle greenhouse gas, evaporative, and refueling emission standards.
* * * * *
95. Amend § 1037.630 by revising paragraphs (a)(1)(iii) and (c) to read as follows:
§ 1037.630
Special purpose tractors.
(a) * * *
(1) * * *
(iii) Model year 2020 and earlier tractors with a gross combination weight rating (GCWR) at or above 120,000 pounds. Note that Phase 2 and later tractors meeting the definition of heavy-haul tractor in § 1037.801 must be certified to the heavy-haul standards in § 1037.106 or § 1037.670.
* * * * *
(c) Production limit. No manufacturer may produce more than 21,000 Phase 1 vehicles under this section in any consecutive three model year period. This means you may not exceed 6,000 in a given model year if the combined total for the previous two years was 15,000. The production limit applies with respect to all Class 7 and Class 8 Phase 1 tractors certified or exempted as vocational tractors. No production limit applies for tractors subject to Phase 2 and later standards.
* * * * *
96. Amend § 1037.631 by revising paragraph (a) introductory text to read as follows:
§ 1037.631
Exemption for vocational vehicles intended for off-road use.
* * * * *
(a) Qualifying criteria. Vocational vehicles intended for off-road use are exempt without request, subject to the provisions of this section, if they are primarily designed to perform work off-road (such as in oil fields, mining, forests, or construction sites), and they meet at least one of the criteria of paragraph (a)(1) of this section and at least one of the criteria of paragraph (a)(2) of this section. See § 1037.105(h) for alternate Phase 2 and Phase 3 standards that apply for vehicles meeting only one of these sets of criteria.
* * * * *
97. Amend § 1037.635 by revising paragraph (b)(1) to read as follows:
§ 1037.635
Glider kits and glider vehicles.
* * * * *
(b) * * *
(1) The engine must meet the greenhouse gas standards of 40 CFR part 1036 that apply for the engine model year corresponding to the vehicle's date of manufacture. For example, for a vehicle with a 2024 date of manufacture, the engine must meet the greenhouse gas standards that apply for model year 2024.
* * * * *
98. Amend § 1037.640 by revising the introductory text to read as follows:
§ 1037.640
Variable vehicle speed limiters.
This section specifies provisions that apply for vehicle speed limiters (VSLs) that you model under § 1037.520. This section is written to apply for tractors; however, you may use good engineering judgment to apply equivalent adjustments for Phase 2 and later vocational vehicles with vehicle speed limiters.
* * * * *
99. Amend § 1037.660 by revising paragraph (a) to read as follows:
§ 1037.660
Idle-reduction technologies.
* * * * *
(a) Minimum requirements. Idle-reduction technologies must meet all the following requirements to be modeled under § 1037.520 except as specified in paragraphs (b) and (c) of this section:
(1) Automatic engine shutdown (AES) systems. The system must shut down the engine within a threshold inactivity period of 60 seconds or less for vocational vehicles and 300 seconds or less for tractors when all the following conditions are met:
(i) The transmission is set to park, or the transmission is in neutral with the parking brake engaged. This is “parked idle.”
(ii) The operator has not reset the system timer within the specified threshold inactivity period by changing the position of the accelerator, brake, or clutch pedal; or by resetting the system timer with some other mechanism we approve.
(iii) You may identify systems as “tamper-resistant” if you make no provision for vehicle owners, dealers, or other service outlets to adjust the threshold inactivity period.
(iv) For Phase 2 and later tractors, you may identify AES systems as “adjustable” if, before delivering to the ultimate purchaser, you enable authorized dealers to modify the vehicle in a way that disables the AES system or makes the threshold inactivity period longer than 300 seconds. However, the vehicle may not be delivered to the ultimate purchaser with the AES system disabled or the threshold inactivity period set longer than 300 seconds. You may allow dealers or repair facilities to make such modifications; this might involve password protection for electronic controls, or special tools that only you provide. Any dealers making any modifications before delivery to the ultimate purchaser must notify you, and you must account for such modifications in your production and ABT reports after the end of the model year. Dealers failing to provide prompt notification are in violation of the tampering prohibition of 40 CFR 1068.101(b)(1). Dealer notifications are deemed to be submissions to EPA. Note that these adjustments may not be made if the AES system was not “adjustable” when first delivered to the ultimate purchaser.
(v) For vocational vehicles, you may use the provisions of § 1037.610 to apply for an appropriate partial emission reduction for AES systems you identify as “adjustable.”
(2) Neutral idle. Phase 2 and later vehicles with hydrokinetic torque converters paired with automatic transmissions qualify for neutral-idle credit in GEM modeling if the transmission reduces torque equivalent to shifting into neutral throughout the interval during which the vehicle's brake pedal is depressed and the vehicle is at a zero-speed condition (beginning within five seconds of the vehicle reaching zero speed with the brake depressed). If a vehicle reduces torque partially but not enough to be equivalent to shifting to neutral, you may use the provisions of § 1037.610(g) to apply for an appropriate partial emission reduction; this may involve A to B testing with the powertrain test procedure in 40 CFR 1036.545 or the spin-loss portion of the transmission efficiency test in § 1037.565.
(3) Stop-start. Phase 2 and later vocational vehicles qualify for stop-start reduction in GEM modeling if the engine shuts down no more than 5 seconds after the vehicle's brake pedal is depressed when the vehicle is at a zero-speed condition.
* * * * *
100. Revise and republish § 1037.665 to read as follows:
§ 1037.665
Production and in-use tractor testing.
We may require manufacturers with annual U.S.-directed production volumes of greater than 20,000 tractors to perform testing as described in this section. Tractors may be new or used.
(a) Test model year 2021 and later tractors as follows:
(1) Each calendar year, we may require you to select for testing three sleeper cabs and two day cabs certified to Phase 1 or Phase 2 standards. If we do not identify certain vehicle configurations for your testing, select models that you project to be among your 12 highest-selling vehicle configurations for the given year.
(2) Set up the tractors on a chassis dynamometer and operate them over all applicable duty cycles from § 1037.510(a)(3). You may use emission-measurement systems meeting the specifications of 40 CFR part 1065, subpart J. Calculate coefficients for the road-load force equation as described in Section 10 of SAE J1263 or Section 11 of SAE J2263 (both incorporated by reference, see § 1037.810). Use standard payload. Measure emissions of NO X , PM, CO, NMHC, CO 2 , CH 4 , and N 2 O. Determine emission levels in g/ton-mile.
(b) Send us an annual report with your test results for each duty cycle and the corresponding GEM results. Send the report by the next October 1 after the year we select the vehicles for testing, or a later date that we approve. We may make your test data publicly available.
(c) We may approve your request to perform alternative testing that will provide equivalent or better information compared to the specified testing. For example, we may allow you to provide CO 2 data from in-use operation or from manufacturer-run on-road testing as long as it allows for reasonable year-to-year comparisons and includes testing from production vehicles. We may also direct you to do less testing than we specify in this section.
(d) Greenhouse gas standards do not apply with respect to testing under this section. Note however that NTE standards apply for any qualifying operation that occurs during the testing in the same way that it would during any other in-use testing.
101. Amend § 1037.670 by revising paragraph (a) to read as follows:
§ 1037.670
Optional CO 2 emission standards for tractors at or above 120,000 pounds GCWR.
(a) You may certify model year 2026 and earlier tractors at or above 120,000 pounds GCWR to the following CO 2 standards instead of the Phase 2 CO 2 standards of § 1037.106:
Table 1 of Paragraph ( a ) of § 1037.670—Optional CO 2 Standards for Tractors Above 120,000 Pounds GCWR
[g/ton-mile] ^a
Subcategory | Model years 2021-2023 | Model years 2024-2026
Heavy Class 8 Low-Roof Day Cab | 53.5 | 50.8
Heavy Class 8 Low-Roof Sleeper Cab | 47.1 | 44.5
Heavy Class 8 Mid-Roof Day Cab | 55.6 | 52.8
Heavy Class 8 Mid-Roof Sleeper Cab | 49.6 | 46.9
Heavy Class 8 High-Roof Day Cab | 54.5 | 51.4
Heavy Class 8 High-Roof Sleeper Cab | 47.1 | 44.2
^a Note that these standards are not directly comparable to the standards for Heavy-Haul Tractors in § 1037.106 because GEM handles aerodynamic performance differently for the two sets of standards.
* * * * *
102. Amend § 1037.701 by revising paragraphs (a), (f), and (h) to read as follows:
§ 1037.701
General provisions.
(a) You may average, bank, and trade emission credits for purposes of certification as described in this subpart and in subpart B of this part to show compliance with the standards of §§ 1037.105 and 1037.106. Note that § 1037.105(h) specifies standards involving limited or no use of emission credits under this subpart. Participation in this program is voluntary.
* * * * *
(f) Emission credits may be used in the model year they are generated. Where we allow it, surplus emission credits may be banked for future model years. Surplus emission credits may sometimes be used for past model years, as described in § 1037.745. You may not apply banked or traded credits in a given model year until you have used all available credits through averaging to resolve credit balances for that model year.
* * * * *
(h) See § 1037.740 for special credit provisions that apply for credits generated under 40 CFR 86.1819-14(k)(7) or 1036.615 or § 1037.615.
* * * * *
103. Revise and republish § 1037.705 to read as follows:
§ 1037.705
Generating and calculating CO 2 emission credits.
(a) The provisions of this section apply separately for calculating CO 2 emission credits for each pollutant.
(b) For each participating family or subfamily, calculate positive or negative emission credits relative to the otherwise applicable emission standard. Calculate positive emission credits for a family or subfamily that has an FEL below the standard. Calculate negative emission credits for a family or subfamily that has an FEL above the standard. Sum your positive and negative credits for the model year before rounding. Round the sum of emission credits to the nearest megagram (Mg), using consistent units with the following equation:
Emission credits (Mg) = ( Std − FEL ) · PL · Volume · UL · 10 − ^6

Eq. 1037.705-1
Where:
Std = the emission standard associated with the specific regulatory subcategory (g/ton-mile).
FEL = the family emission limit for the vehicle subfamily (g/ton-mile).
PL = standard payload, in tons.
Volume = U.S.-directed production volume of the vehicle subfamily, subject to the exclusions described in paragraph (c) of this section. For example, if you produce three configurations with the same FEL, the subfamily production volume would be the sum of the production volumes for these three configurations.
UL = useful life of the vehicle, in miles, as described in §§ 1037.105 and 1037.106.
(c) Compliance with the requirements of this subpart is determined at the end of the model year by calculating emission credits based on actual production volumes, excluding any of the following vehicles:
(1) Vehicles that you do not certify to the CO 2 standards of this part because they are permanently exempted under subpart G of this part or under 40 CFR part 1068.
(2) Exported vehicles even if they are certified under this part and labeled accordingly.
(3) Vehicles not subject to the requirements of this part, such as those excluded under § 1037.5.
(4) Any other vehicles, where we indicate elsewhere in this part that they are not to be included in the calculations of this subpart.
104. Amend § 1037.710 by revising paragraph (c) to read as follows:
§ 1037.710
Averaging.
* * * * *
(c) If you certify a vehicle family to an FEL that exceeds the otherwise applicable standard, you must obtain enough emission credits to offset the vehicle family's deficit by the due date for the final report required in § 1037.730. The emission credits used to address the deficit may come from your other vehicle families that generate emission credits in the same model year (or from later model years as specified in § 1037.745), from emission credits you have banked from previous model years, or from emission credits generated in the same or previous model years that you obtained through trading.
105. Amend § 1037.715 by revising paragraph (a) to read as follows:
§ 1037.715
Banking.
(a) Banking is the retention of surplus emission credits by the manufacturer generating the emission credits for use in future model years for averaging or trading.
* * * * *
106. Amend § 1037.720 by revising paragraph (a) to read as follows:
§ 1037.720
Trading.
(a) Trading is the exchange of emission credits between manufacturers, or the transfer of credits to another party to retire them. You may use traded emission credits for averaging, banking, or further trading transactions. Traded emission credits remain subject to the averaging-set restrictions based on the averaging set in which they were generated.
* * * * *
107. Amend § 1037.730 by revising paragraphs (b)(4) and (f)(1) to read as follows:
§ 1037.730
ABT reports.
* * * * *
(b) * * *
(4) The projected and actual production volumes for the model year for calculating emission credits. If you changed an FEL during the model year, identify the actual production volume associated with each FEL.
* * * * *
(f) * * *
(1) If you notify us by the deadline for submitting the final report that errors mistakenly decreased your balance of emission credits, you may correct the errors and recalculate the balance of emission credits. If you notify us that errors mistakenly decreased your balance of emission credits after the deadline for submitting the final report, you may correct the errors and recalculate the balance of emission credits after applying a 10 percent discount to the credit correction, but only if you notify us within 24 months after the deadline for submitting the final report. If you report a negative balance of emission credits, we may disallow corrections under this paragraph (f)(1).
* * * * *
108. Amend § 1037.740 by revising paragraphs (a), (b)(1) introductory text, and (b)(2) to read as follows:
§ 1037.740
Restrictions for using emission credits.
* * * * *
(a) Averaging sets. Except as specified in § 1037.105(h) and paragraph (b) of this section, emission credits may be exchanged only within an averaging set. The following principal averaging sets apply for vehicles certified to the standards of this part involving emission credits as described in this subpart:
(1) Light HDV.
(2) Medium HDV.
(3) Heavy HDV.
(4) Note that other separate averaging sets also apply for emission credits not related to this part. For example, vehicles certified to the greenhouse gas standards of 40 CFR part 86, subpart S, comprise a single averaging set. Separate averaging sets also apply for engines under 40 CFR part 1036, including engines used in vehicles subject to this subpart.
(b) * * *
(1) Credits generated from Phase 1 vehicles may be used for any of the averaging sets identified in paragraph (a) of this section; you may also use those credits to demonstrate compliance with the CO 2 emission standards in 40 CFR part 86, subpart S, and 40 CFR part 1036. Similarly, you may use Phase 1 advanced-technology credits generated under 40 CFR 86.1819-14(k)(7) or 1036.615 to demonstrate compliance with the CO 2 standards in this part. The maximum amount of advanced-technology credits generated from Phase 1 vehicles that you may bring into each of the following service class groups is 60,000 Mg per model year:
* * * * *
(2) Credits generated from Phase 2 and later vehicles are subject to the averaging-set restrictions that apply to other emission credits.
* * * * *
109. Amend § 1037.745 by revising paragraph (a) to read as follows:
§ 1037.745
End-of-year CO 2 credit deficits.
* * * * *
(a) Your certificate for a vehicle family for which you do not have sufficient CO 2 credits will not be void if you remedy the deficit with surplus credits within three model years. For example, if you have a credit deficit of 500 Mg for a vehicle family at the end of model year 2015, you must generate (or otherwise obtain) a surplus of at least 500 Mg in that same averaging set by the end of model year 2018.
* * * * *
110. Amend § 1037.801 by:
a. Adding a definition of “Battery electric vehicle” in alphabetical order;
b. Removing the definition of “Box van”;
c. Revising the definition of “Class”;
d. Removing the definitions of “Container chassis”, “Electric vehicle”, and “Flatbed trailer”;
e. Adding a definition of “Fuel cell electric vehicle” in alphabetical order;
f. Revising the definitions of “Greenhouse gas Emissions Model (GEM)”, “Heavy-duty vehicle”, and “Heavy-haul tractor”;
g. Adding a definition of “Hybrid” in alphabetical order;
h. Removing the definitions of “Hybrid engine or hybrid powertrain” and “Hybrid vehicle”;
i. Revising the definitions of “Light-duty truck”, “Light-duty vehicle”, “Low rolling resistance tire”, “Manufacturer”, and “Model year”;
j. Adding a definition of “Neat” in alphabetical order;
k. Revising the definitions of “Neutral coasting”, “Phase 1”, and “Phase 2”;
l. Adding definitions of “Phase 3” and “Plug-in hybrid electric vehicle” in alphabetical order;
m. Revising the definitions of “Preliminary approval”, “Small manufacturer”, and “Standard payload”;
n. Removing the definition of “Standard tractor”;
o. Adding a definition of “State of certified energy (SOCE)” in alphabetical order;
p. Removing the definitions of “Tank trailer” and “Tonne”;
q. Adding a definition of “Ton” in alphabetical order;
r. Revising the definitions of “Trailer” and “U.S.-directed production volume”;
s. Adding a definition of “Usable battery energy (UBE)” in alphabetical order; and
t. Revising the definition of “Vehicle”.
The additions and revisions read as follows:
§ 1037.801
Definitions.
* * * * *
Battery electric vehicle means a motor vehicle powered solely by an electric motor where energy for the motor is supplied by one or more batteries that receive power from an external source of electricity. Note that this definition does not include hybrid vehicles or plug-in hybrid electric vehicles.
* * * * *
Class means relating to GVWR classes, as follows:
(1) Class 2b means relating to heavy-duty motor vehicles at or below 10,000 pounds GVWR.
(2) Class 3 means relating to heavy-duty motor vehicles above 10,000 pounds GVWR but at or below 14,000 pounds GVWR.
(3) Class 4 means relating to heavy-duty motor vehicles above 14,000 pounds GVWR but at or below 16,000 pounds GVWR.
(4) Class 5 means relating to heavy-duty motor vehicles above 16,000 pounds GVWR but at or below 19,500 pounds GVWR.
(5) Class 6 means relating to heavy-duty motor vehicles above 19,500 pounds GVWR but at or below 26,000 pounds GVWR.
(6) Class 7 means relating to heavy-duty motor vehicles above 26,000 pounds GVWR but at or below 33,000 pounds GVWR.
(7) Class 8 means relating to heavy-duty motor vehicles above 33,000 pounds GVWR.
* * * * *
Fuel cell electric vehicle means a motor vehicle powered solely by an electric motor where energy for the motor is supplied by hydrogen fuel cells. Fuel cell electric vehicles may include energy storage from the fuel cells or from regenerative braking in a battery.
* * * * *
Greenhouse gas Emissions Model (GEM) means the GEM simulation tool described in § 1037.520 (incorporated by reference, see § 1037.810).
* * * * *
Heavy-duty vehicle means any motor vehicle that has a GVWR above 8,500 pounds. An incomplete vehicle is also a heavy-duty vehicle if it has a curb weight above 6,000 pounds or a basic vehicle frontal area greater than 45 square feet.
Heavy-haul tractor means a tractor with GCWR greater than or equal to 120,000 pounds. A heavy-haul tractor is not a vocational tractor in Phase 2 and later.
* * * * *
Hybrid has the meaning given in 40 CFR 1036.801. Note that a hybrid vehicle is a vehicle with a hybrid engine or other hybrid powertrain. This includes plug-in hybrid electric vehicles.
* * * * *
Light-duty truck has the meaning given in 40 CFR 86.1803-01.
Light-duty vehicle has the meaning given in 40 CFR 86.1803-01.
* * * * *
Low rolling resistance tire means a tire on a vocational vehicle with a TRRL at or below of 7.7 N/kN, a steer tire on a tractor with a TRRL at or below 7.7 N/kN, a drive tire on a tractor with a TRRL at or below 8.1 N/kN.
* * * * *
Manufacturer has the meaning given in section 216(1) of the Act. In general, this term includes any person who manufactures or assembles a vehicle (including an incomplete vehicle) for sale in the United States or otherwise introduces a new motor vehicle into commerce in the United States. This includes importers who import vehicles for resale, entities that manufacture glider kits, and entities that assemble glider vehicles.
* * * * *
Model year means one of the following for compliance with this part. Note that manufacturers may have other model year designations for the same vehicle for compliance with other requirements or for other purposes:
(1) For vehicles with a date of manufacture on or after January 1, 2021, model year means the manufacturer's annual new model production period based on the vehicle's date of manufacture, where the model year is the calendar year corresponding to the date of manufacture, except as follows:
(i) The vehicle's model year may be designated as the year before the calendar year corresponding to the date of manufacture if the engine's model year is also from an earlier year. You may ask us to extend your prior model year certificate to include such vehicles. Note that § 1037.601(a)(2) limits the extent to which vehicle manufacturers may install engines built in earlier calendar years.
(ii) The vehicle's model year may be designated as the year after the calendar year corresponding to the vehicle's date of manufacture. For example, a manufacturer may produce a new vehicle by installing the engine in December 2023 and designating it as a model year 2024 vehicle.
(2) For Phase 1 vehicles with a date of manufacture before January 1, 2021, model year means the manufacturer's annual new model production period, except as restricted under this definition and 40 CFR part 85, subpart X. It must include January 1 of the calendar year for which the model year is named, may not begin before January 2 of the previous calendar year, and it must end by December 31 of the named calendar year. The model year may be set to match the calendar year corresponding to the date of manufacture.
(i) The manufacturer who holds the certificate of conformity for the vehicle must assign the model year based on the date when its manufacturing operations are completed relative to its annual model year period. In unusual circumstances where completion of your assembly is delayed, we may allow you to assign a model year one year earlier, provided it does not affect which regulatory requirements will apply.
(ii) Unless a vehicle is being shipped to a secondary vehicle manufacturer that will hold the certificate of conformity, the model year must be assigned prior to introduction of the vehicle into U.S. commerce. The certifying manufacturer must redesignate the model year if it does not complete its manufacturing operations within the originally identified model year. A vehicle introduced into U.S. commerce without a model year is deemed to have a model year equal to the calendar year of its introduction into U.S. commerce unless the certifying manufacturer assigns a later date.
* * * * *
Neat has the meaning given in 40 CFR 1065.1001.
Neutral coasting means a vehicle technology that automatically puts the transmission in neutral when the when operator demand is zero while the vehicle is in motion, such as driving downhill.
* * * * *
Phase 1 means relating to the Phase 1 standards specified in §§ 1037.105 and 1037.106. For example, a vehicle subject to the Phase 1 standards is a Phase 1 vehicle.
Phase 2 means relating to the Phase 2 standards specified in §§ 1037.105 and 1037.106.
Phase 3 means relating to the Phase 3 standards specified in §§ 1037.105 and 1037.106.
* * * * *
Plug-in hybrid electric vehicle means a hybrid vehicle that has the capability to charge one or more batteries from an external source of electricity while the vehicle is parked.
* * * * *
Preliminary approval means approval granted by an authorized EPA representative prior to submission of an application for certification, consistent with the provisions of § 1037.210.
* * * * *
Small manufacturer means a manufacturer meeting the small business criteria specified in 13 CFR 121.201 for heavy-duty truck manufacturing (NAICS code 336120). The employee limit applies to the total number employees for all affiliated companies (as defined in 40 CFR 1068.30).
* * * * *
Standard payload means the payload assumed for each vehicle, in tons, for modeling and calculating emission credits, as follows:
(1) For vocational vehicles:
(i) 2.85 tons for Light HDV.
(ii) 5.6 tons for Medium HDV.
(iii) 7.5 tons for Heavy HDV.
(2) For tractors:
(i) 12.5 tons for Class 7.
(ii) 19 tons for Class 8, other than heavy-haul tractors.
(iii) 43 tons for heavy-haul tractors.
* * * * *
State of certified energy (SOCE) means the measured or onboard UBE performance at a specific point in its lifetime, expressed as a percentage of the certified usable battery energy.
* * * * *
Ton means a short ton, which is exactly 2000 pounds.
* * * * *
Trailer means a piece of equipment designed for carrying cargo and for being drawn by a tractor when coupled to the tractor's fifth wheel.
* * * * *
U.S.-directed production volume means the number of vehicle units, subject to the requirements of this part, produced by a manufacturer for which the manufacturer has a reasonable assurance that sale was or will be made to ultimate purchasers in the United States.
Usable battery energy (UBE) means the energy the battery supplies from the start of the certification test procedure until the applicable break-off criterion. This part depends on certified and aged values of UBE to set battery monitoring requirements as described in § 1037.115(f).
* * * * *
Vehicle means equipment intended for use on highways that meets at least one of the criteria of paragraph (1) of this definition, as follows:
(1) The following equipment are vehicles:
(i) A piece of equipment that is intended for self-propelled use on highways becomes a vehicle when it includes at least an engine, a transmission, and a frame. (Note: For purposes of this definition, any electrical, mechanical, and/or hydraulic devices attached to engines for the purpose of powering wheels are considered to be transmissions.)
(ii) A piece of equipment that is intended for self-propelled use on highways becomes a vehicle when it includes a passenger compartment attached to a frame with one or more axles.
(2) Vehicles may be complete or incomplete vehicles as follows:
(i) A complete vehicle is a functioning vehicle that has the primary load carrying device or container (or equivalent equipment) attached when it is first sold as a vehicle. Examples of equivalent equipment would include fifth wheel trailer hitches, firefighting equipment, and utility booms.
(ii) An incomplete vehicle is a vehicle that is not a complete vehicle. Incomplete vehicles may also be cab-complete vehicles. This may include vehicles sold to secondary vehicle manufacturers.
(iii) You may ask us to allow you to certify a vehicle as incomplete if you manufacture the engines and sell the unassembled chassis components, as long as you do not produce and sell the body components necessary to complete the vehicle.
* * * * *
111. Amend § 1037.805 by:
a. Revising the introductory text; and
b. In table 5 to paragraph (e), removing the entries for “ECM”, “FE”, “FTP”, “LLC”, “PHEV”, and “SET”.
The revision reads as follows:
§ 1037.805
Symbols, abbreviations, and acronyms.
The procedures in this part generally follow either the International System of Units (SI) or the United States customary units, as detailed in NIST Special Publication 811 (incorporated by reference, see § 1037.810). See 40 CFR 1065.20 for specific provisions related to these conventions. This section summarizes the way we use symbols, units of measure, and other abbreviations.
* * * * *
112. Amend § 1037.810 by:
a. Revising paragraph (c)(2);
b. Removing paragraph (c)(9);
c. Redesignating paragraph (c)(10) as paragraph (c)(9); and
d. Revising paragraph (d).
The revisions read as follows:
§ 1037.810
Incorporation by reference.
* * * * *
(c) * * *
(2) SAE J1252 JUL2012, SAE Wind Tunnel Test Procedure for Trucks and Buses, Revised July 2012, (“SAE J1252”); IBR approved for §§ 1037.525(b) and (c); 1037.530(a).
* * * * *
(d) U.S. EPA, Office of Air and Radiation, 2565 Plymouth Road, Ann Arbor, MI 48105; www.epa.gov ; complianceinfo@epa.gov .
(1) Greenhouse gas Emissions Model (GEM), Version 2.0.1, September 2012 (“GEM version 2.0.1”); IBR approved for § 1037.520.
(2) Greenhouse gas Emissions Model (GEM) Phase 2, Version 3.0, July 2016 (“GEM Phase 2, Version 3.0”); IBR approved for § 1037.150(x).
(3) Greenhouse gas Emissions Model (GEM) Phase 2, Version 3.5.1, November 2020 (“GEM Phase 2, Version 3.5.1”); IBR approved for § 1037.150(x).
(4) Greenhouse gas Emissions Model (GEM) Phase 2, Version 4.0, April 2022 (“GEM Phase 2, Version 4.0”); IBR approved for §§ 1037.150(x); 1037.520.
(5) GEM's MATLAB/Simulink Hardware-in-Loop model, Version 3.8, December 2020 (“GEM HIL model 3.8”); IBR approved for § 1037.150(x).
113. Revise appendix C to part 1037 to read as follows:

Appendix C to Part 1037—Emission Control Identifiers
This appendix identifies abbreviations for emission control information labels, as required under § 1037.135.

Vehicle Speed Limiters
—VSL—Vehicle speed limiter
—VSLS—“Soft-top” vehicle speed limiter
—VSLE—Expiring vehicle speed limiter
—VSLD—Vehicle speed limiter with both “soft-top” and expiration

Idle Reduction Technology
—IRT5—Engine shutoff after 5 minutes or less of idling
—IRTE—Expiring engine shutoff

Tires
—LRRA—Low rolling resistance tires (all)
—LRRD—Low rolling resistance tires (drive)
—LRRS—Low rolling resistance tires (steer)

Aerodynamic Components
—ATS—Aerodynamic side skirt and/or fuel tank fairing
—ARF—Aerodynamic roof fairing
—ARFR—Adjustable height aerodynamic roof fairing
—TGR—Gap reducing tractor fairing (tractor to trailer gap)

Other Components
—ADVH—Vehicle includes advanced hybrid technology components
—ADVO—Vehicle includes other advanced-technology components ( i.e., non-hybrid system)
—INV—Vehicle includes innovative (off-cycle) technology components
—ATI—Automatic tire inflation system
—TPMS—Tire pressure monitoring system
114. Revise appendix D to part 1037 to read as follows:

Appendix D to Part 1037—Heavy-Duty Grade Profile for Steady-State Test Cycles
The following table identifies a grade profile for operating vehicles over the highway cruise cycles specified in subpart F of this part. Determine intermediate values by linear interpolation.
Distance (m) | Grade (%)
0 | 0
402 | 0
804 | 0.5
1206 | 0
1210 | 0
1222 | −0.10
1234 | 0
1244 | 0
1294 | 0.36
1344 | 0
1354 | 0
1408 | −0.28
1504 | −1.04
1600 | −0.28
1654 | 0
1666 | 0
1792 | 0.39
1860 | 0.66
1936 | 1.15
2098 | 2.44
2260 | 1.15
2336 | 0.66
2404 | 0.39
2530 | 0
2548 | 0
2732 | −0.46
2800 | −0.69
2880 | −1.08
2948 | −1.53
3100 | −2.75
3252 | −1.53
3320 | −1.08
3400 | −0.69
3468 | −0.46
3652 | 0
3666 | 0
3742 | 0.35
3818 | 0.90
3904 | 1.59
3990 | 0.90
4066 | 0.35
4142 | 0
4158 | 0
4224 | −0.10
4496 | −0.69
4578 | −0.97
4664 | −1.36
4732 | −1.78
4916 | −3.23
5100 | −1.78
5168 | −1.36
5254 | −0.97
5336 | −0.69
5608 | −0.10
5674 | 0
5724 | 0
5808 | 0.10
5900 | 0.17
6122 | 0.38
6314 | 0.58
6454 | 0.77
6628 | 1.09
6714 | 1.29
6838 | 1.66
6964 | 2.14
7040 | 2.57
7112 | 3.00
7164 | 3.27
7202 | 3.69
7292 | 5.01
7382 | 3.69
7420 | 3.27
7472 | 3.00
7544 | 2.57
7620 | 2.14
7746 | 1.66
7870 | 1.29
7956 | 1.09
8130 | 0.77
8270 | 0.58
8462 | 0.38
8684 | 0.17
8776 | 0.10
8860 | 0
8904 | 0
9010 | −0.38
9070 | −0.69
9254 | −2.13
9438 | −0.69
9498 | −0.38
9604 | 0
9616 | 0
9664 | 0.26
9718 | 0.70
9772 | 0.26
9820 | 0
9830 | 0
9898 | −0.34
10024 | −1.33
10150 | −0.34
10218 | 0
10228 | 0
10316 | 0.37
10370 | 0.70
10514 | 1.85
10658 | 0.70
10712 | 0.37
10800 | 0
10812 | 0
10900 | −0.37
10954 | −0.7
11098 | −1.85
11242 | −0.70
11296 | −0.37
11384 | 0
11394 | 0
11462 | 0.34
11588 | 1.33
11714 | 0.34
11782 | 0
11792 | 0
11840 | −0.26
11894 | −0.70
11948 | −0.26
11996 | 0
12008 | 0
12114 | 0.38
12174 | 0.69
12358 | 2.13
12542 | 0.69
12602 | 0.38
12708 | 0
12752 | 0
12836 | −0.10
12928 | −0.17
13150 | −0.38
13342 | −0.58
13482 | −0.77
13656 | −1.09
13742 | −1.29
13866 | −1.66
13992 | −2.14
14068 | −2.57
14140 | −3.00
14192 | −3.27
14230 | −3.69
14320 | −5.01
14410 | −3.69
14448 | −3.27
14500 | −3.00
14572 | −2.57
14648 | −2.14
14774 | −1.66
14898 | −1.29
14984 | −1.09
15158 | −0.77
15298 | −0.58
15490 | −0.38
15712 | −0.17
15804 | −0.10
15888 | 0
15938 | 0
16004 | 0.10
16276 | 0.69
16358 | 0.97
16444 | 1.36
16512 | 1.78
16696 | 3.23
16880 | 1.78
16948 | 1.36
17034 | 0.97
17116 | 0.69
17388 | 0.10
17454 | 0
17470 | 0
17546 | −0.35
17622 | −0.90
17708 | −1.59
17794 | −0.90
17870 | −0.35
17946 | 0
17960 | 0
| 18144 | 0.46
18212 | 0.69
18292 | 1.08
18360 | 1.53
18512 | 2.75
18664 | 1.53
18732 | 1.08
18812 | 0.69
18880 | 0.46
19064 | 0
19082 | 0
19208 | −0.39
19276 | −0.66
19352 | −1.15
19514 | −2.44
19676 | −1.15
19752 | −0.66
19820 | −0.39
19946 | 0
19958 | 0
20012 | 0.28
20108 | 1.04
20204 | 0.28
20258 | 0
20268 | 0
20318 | −0.36
20368 | 0
20378 | 0
20390 | 0.10
20402 | 0
20406 | 0
20808 | −0.50
21210 | 0
21612 | 0

PART 1039—CONTROL OF EMISSIONS FROM NEW AND IN-USE NONROAD COMPRESSION-IGNITION ENGINES
115. The authority citation for part 1039 continues to read as follows:

Authority:
42 U.S.C. 7401-7671q.
116. Amend § 1039.705 by revising paragraph (b) to read as follows:
§ 1039.705
How do I generate and calculate emission credits?
* * * * *
(b) For each participating family, calculate positive or negative emission credits relative to the otherwise applicable emission standard. Calculate positive emission credits for a family that has an FEL below the standard. Calculate negative emission credits for a family that has an FEL above the standard. Sum your positive and negative credits for the model year before rounding. Round the sum of emission credits to the nearest kilogram (kg), using consistent units throughout the following equation:
Emission credits (kg) = ( Std − FEL ) · Volume · AvgPR · UL · 10 − ^3

Eq. 1039.705-1
Where:
Std = the emission standard, in grams per kilowatt-hour, that applies under subpart B of this part for engines not participating in the ABT program of this subpart (the “otherwise applicable standard”).
FEL = the family emission limit for the engine family, in grams per kilowatt-hour.
Volume = the number of engines eligible to participate in the averaging, banking, and trading program within the given engine family during the model year, as described in paragraph (c) of this section.
AvgPR = the average value of maximum engine power values for the engine configurations within an engine family, calculated on a sales-weighted basis, in kilowatts.
UL = the useful life for the given engine family, in hours.
* * * * *

PART 1054—CONTROL OF EMISSIONS FROM NEW, SMALL NONROAD SPARK-IGNITION ENGINES AND EQUIPMENT
117. The authority citation for part 1054 continues to read as follows:

Authority:
42 U.S.C. 7401-7671q.
118. Amend § 1054.501 by revising paragraph (b)(7) to read as follows:
§ 1054.501
How do I run a valid emission test?
* * * * *
(b) * * *
(7) Determine your test fuel's carbon mass fraction, w c, using a calculation based on fuel properties as described in 40 CFR 1065.655(d); however, you must measure fuel properties for α and β rather than using the default values specified in 40 CFR 1065.655(e).
* * * * *

PART 1065—ENGINE-TESTING PROCEDURES
119. The authority citation for part 1065 continues to read as follows:

Authority:
42 U.S.C. 7401-7671q.
120. Amend § 1065.12 by revising paragraph (d)(1) to read as follows:
§ 1065.12
Approval of alternate procedures.
* * * * *
(d) * * *
(1) Theoretical basis. Give a brief technical description explaining why you believe the proposed alternate procedure should result in emission measurements equivalent to those using the specified procedure. You may include equations, figures, and references. You should consider the full range of parameters that may affect equivalence. For example, for a request to use a different NO X measurement procedure, you should theoretically relate the alternate detection principle to the specified detection principle over the expected concentration ranges for NO, NO 2 , and interference species. For a request to use a different PM measurement procedure, you should explain the principles by which the alternate procedure quantifies particulate mass similarly to the specified procedures.
* * * * *
121. Amend § 1065.170 by revising paragraph (c)(1)(i) to read as follows:
§ 1065.170
Batch sampling for gaseous and PM constituents.
* * * * *
(c) * * *
(1) * * *
(i) If you expect that a filter's total surface concentration of PM will exceed 400 µg, assuming a 38 mm diameter filter stain area, for a given test interval, you may use filter media with a minimum initial collection efficiency of 98%; otherwise you must use a filter media with a minimum initial collection efficiency of 99.7%. Collection efficiency must be measured as described in ASTM D2986 (incorporated by reference, see § 1065.1010), though you may rely on the sample-media manufacturer's measurements reflected in their product ratings to show that you meet the requirement in this paragraph (c)(1)(i).
* * * * *
122. Amend § 1065.190 by revising paragraph (b) to read as follows:
§ 1065.190
PM-stabilization and weighing environments for gravimetric analysis.
* * * * *
(b) We recommend that you keep both the stabilization and the weighing environments free of ambient contaminants, such as dust, aerosols, or semi-volatile material that could contaminate PM samples. We recommend that these environments conform with an “as-built” Class Six clean room specification according to ISO 14644-1 (incorporated by reference, see § 1065.1010); however, we also recommend that you deviate from ISO 14644-1 as necessary to minimize air motion that might affect weighing. We recommend maximum air-supply and air-return velocities of 0.05 m/s in the weighing environment.
* * * * *
123. Amend § 1065.210 by revising paragraph (a) to read as follows:
§ 1065.210
Work input and output sensors.
(a) Application. Use instruments as specified in this section to measure work inputs and outputs during engine operation. We recommend that you use sensors, transducers, and meters that meet the specifications in § 1065.205. Note that your overall systems for measuring work inputs and outputs must meet the linearity verifications in § 1065.307. In all cases, ensure that you are able to accurately demonstrate compliance with the applicable standards in this chapter. The following additional provisions apply related to work inputs and outputs:
(1) We recommend that you measure work inputs and outputs where they cross the system boundary as shown in figure 1 to paragraph (a)(5) of this section. The system boundary is different for air-cooled engines than for liquid-cooled engines.
(2) For measurements involving work conversion relative to a system boundary use good engineering judgment to estimate any work-conversion losses in a way that avoids overestimation of total work. For example, if it is impractical to instrument the shaft of an exhaust turbine generating electrical work, you may decide to measure its converted electrical work. As another example, you may decide to measure the tractive ( i.e., electrical output) power of a locomotive, rather than the brake power of the locomotive engine. For measuring tractive power based on electrical output, divide the electrical work by accurate values of electrical generator efficiency ( η <1), or assume an efficiency of 1 ( η =1), which would over-estimate brake-specific emissions. For the example of using locomotive tractive power with a generator efficiency of 1 ( η =1), this means using the tractive power as the brake power in emission calculations.
(3) If your engine includes an externally powered electrical heater to heat engine exhaust, assume an electrical generator efficiency of 0.67 ( η =0.67) to account for the work needed to run the heater.
(4) Do not underestimate any work conversion efficiencies for any components outside the system boundary that do not return work into the system boundary. And do not overestimate any work conversion efficiencies for components outside the system boundary that return work into the system boundary.
(5) Figure 1 to this paragraph (a)(5) follows:

Figure 1 to paragraph ( a )(5) of § 1065.210: Work Inputs, Outputs, and System Boundaries
* * * * *
124. Revise the undesignated center heading preceding § 1065.250 to read as follows:
Hydrocarbon, H 2 , and H 2 O Measurements
125. Add §§ 1065.255 and 1065.257 under newly revised undesignated center heading “Hydrocarbon, H 2 , and H 2 O Measurements” to read as follows:
§ 1065.255
H 2 measurement devices.
(a) Component requirements. We recommend that you use an analyzer that meets the specifications in § 1065.205. Note that your system must meet the linearity verification in § 1065.307.
(b) Instrument types. You may use any of the following analyzers to measure H 2 :
(1) Magnetic sector mass spectrometer.
(2) Raman spectrometer.
(c) Interference verification. Certain compounds can positively interfere with magnetic sector mass spectroscopy and raman spectroscopy by causing a response similar to H 2 . Use good engineering judgment to determine interference species when performing interference verification. In the case of raman spectroscopy, determine interference species that are appropriate for each H 2 infrared absorption band, or you may identify the interference species based on the instrument manufacturer's recommendations.
§ 1065.257
H 2 O measurement devices.
(a) Component requirements. We recommend that you use an analyzer that meets the specifications in § 1065.205. Note that your system must meet the linearity verification in § 1065.307 with a humidity generator meeting the requirements of § 1065.750(a)(6).
(b) Measurement principles. Use appropriate analytical procedures for interpretation of infrared spectra. For example, EPA Test Method 320 (see § 1065.266(b)) and ASTM D6348 (incorporated by reference, see § 1065.1010) are considered valid methods for spectral interpretation. You must use heated analyzers that maintain all surfaces that are exposed to emissions at a temperature of (110 to 202) °C.
(c) Instrument types. You may use any of the following analyzers to measure H 2 O:
(1) Fourier transform infrared (FTIR) analyzer.
(2) Laser infrared analyzer. Examples of laser infrared analyzers are pulsed-mode high-resolution narrow band mid-infrared analyzers and modulated continuous wave high-resolution narrow band near or mid-infrared analyzers.
(d) Interference verification. Certain compounds can interfere with FTIR and laser infrared analyzers by causing a response similar to water. Perform interference verification for the following interference species:
(1) Perform CO 2 interference verification for FTIR analyzers using the procedures of § 1065.357. Use good engineering judgment to determine other interference species for FTIR analyzers when performing interference verification. Consider at least CO, NO, C 2 H 4 , and C 7 H 8 . Perform interference verifications using the procedures of § 1065.357, replacing occurances of CO 2 with each targeted interference species. Determine interference species under this paragraph (d)(1) that are appropriate for each H 2 O infrared absorption band, or you may identify the interference species based on the instrument manufacturer's recommendations.
(2) Perform interference verification for laser infrared analyzers using the procedures of § 1065.375. Use good engineering judgment to determine interference species for laser infrared analyzers. Note that interference species are dependent on the H 2 O infrared absorption band chosen by the instrument manufacturer. For each analyzer determine the H 2 O infrared absorption band. Determine interference species under this paragraph (d)(2) that are appropriate for each H 2 O infrared absorption band, or you may identify the interference species based on the instrument manufacturer's recommendations.
126. Revise § 1065.266 to read as follows:
§ 1065.266
Fourier transform infrared analyzer.
(a) Application. For engines that run only on natural gas, you may use a Fourier transform infrared (FTIR) analyzer to measure nonmethane hydrocarbon (NMHC) and nonmethane nonethane hydrocarbon (NMNEHC) for continuous sampling. You may use an FTIR analyzer with any gaseous-fueled engine, including dual-fuel and flexible-fuel engines, to measure CH 4 and C 2 H 6 , for either batch or continuous sampling (for subtraction from THC).
(b) Component requirements. We recommend that you use an FTIR analyzer that meets the specifications in § 1065.205.
(c) Measurement principles. Note that your FTIR-based system must meet the linearity verification in § 1065.307. Use appropriate analytical procedures for interpretation of infrared spectra. For example, EPA Test Method 320 in 40 CFR part 63, appendix A, and ASTM D6348 (incorporated by reference, see § 1065.1010) are considered valid methods for spectral interpretation. You must use heated FTIR analyzers that maintain all surfaces that are exposed to emissions at a temperature of (110 to 202) °C.
(d) Hydrocarbon species for NMHC and NMNEHC additive determination. To determine NMNEHC, measure ethene, ethyne, propane, propene, butane, formaldehyde, acetaldehyde, formic acid, and methanol. To determine NMHC, measure ethane in addition to those same hydrocarbon species. Determine NMHC and NMNEHC as described in § 1065.660(b)(4) and (c)(3).
(e) NMHC and NMNEHC determination from subtraction of CH 4
and C 2 H 6
from THC. Determine NMHC from subtraction of CH 4 from THC as described in § 1065.660(b)(3) and NMNEHC from subtraction of CH 4 and C 2 H 6 as described § 1065.660(c)(2). Determine CH 4 as described in § 1065.660(d)(2) and C 2 H 6 as described § 1065.660(e).
(f) Interference verification. Perform interference verification for FTIR analyzers using the procedures of § 1065.366. Certain species can interfere with FTIR analyzers by causing a response similar to the hydrocarbon species of interest. When running the interference verification for these analyzers, use interference species as follows:
(1) The interference species for CH 4 are CO 2 , H 2 O, and C 2 H 6 .
(2) The interference species for C 2 H 6 are CO 2 , H 2 O, and CH 4 .
(3) The interference species for other measured hydrocarbon species are CO 2 , H 2 O, CH 4 , and C 2 H 6 .
127. Amend § 1065.267 by revising paragraph (b) to read as follows:
§ 1065.267
Gas chromatograph with a flame ionization detector.
* * * * *
(b) Component requirements. We recommend that you use a GC-FID that meets the specifications in § 1065.205 and that the measurement be done according to SAE J1151 (incorporated by reference, see § 1065.1010). The GC-FID must meet the linearity verification in § 1065.307.
128. Revise the undesignated center heading preceding § 1065.270 to read as follows:

NO X , N 2 O, and NH 3 Measurements
129. Amend § 1065.270 by revising the section heading to read as follows:
§ 1065.270
Chemiluminescent NO X analyzer.
* * * * *
130. Amend § 1065.272 by revising the section heading to read as follows:
§ 1065.272
Nondispersive ultraviolet NO X analyzer.
* * * * *
131. Amend § 1065.275 by revising paragraphs (b)(2) and (c) to read as follows:
§ 1065.275
N 2 O measurement devices.
* * * * *
(b) * * *
(2) Fourier transform infrared (FTIR) analyzer. Use appropriate analytical procedures for interpretation of infrared spectra. For example, EPA Test Method 320 in 40 CFR part 63, appendix A, and ASTM D6348 (incorporated by reference, see § 1065.1010) are considered valid methods for spectral interpretation.
* * * * *
(c) Interference verification. Certain compounds can positively interfere with NDIR, FTIR, laser infrared analyzers, and photoacoustic analyzers by causing a response similar to N 2 O. Perform interference verification for NDIR, FTIR, laser infrared analyzers, and photoacoustic analyzers using the procedures of § 1065.375. Interference verification is not required for GC-ECD. Perform interference verification for the following interference species:
(1) The interference species for NDIR analyzers are CO, CO 2 , H 2 O, CH 4 , and SO 2 . Note that interference species, with the exception of H 2 O, are dependent on the N 2 O infrared absorption band chosen by the instrument manufacturer. For each analyzer determine the N 2 O infrared absorption band. For each N 2 O infrared absorption band, use good engineering judgment to determine which interference species to evaluate for interference verification.
(2) Use good engineering judgment to determine interference species for FTIR and laser infrared analyzers. Note that interference species, with the exception of H 2 O, are dependent on the N 2 O infrared absorption band chosen by the instrument manufacturer. For each analyzer determine the N 2 O infrared absorption band. Determine interference species under this paragraph (c)(2) that are appropriate for each N 2 O infrared absorption band, or you may identify the interference species based on the instrument manufacturer's recommendations.
(3) The interference species for photoacoustic analyzers are CO, CO 2 , and H 2 O.
132. Add § 1065.277 under newly revised undesignated center heading “NO X , N 2 O, AND NH 3 MEASUREMENTS” to read as follows:
§ 1065.277
NH 3 measurement devices.
(a) General component requirements. We recommend that you use an analyzer that meets the specifications in § 1065.205. Note that your system must meet the linearity verification in § 1065.307.
(b) Instrument types. You may use any of the following analyzers to measure NH 3 :
(1) Nondispersive ultraviolet (NDUV) analyzer.
(2) Fourier transform infrared (FTIR) analyzer. Use appropriate analytical procedures for interpretation of infrared spectra. For example, EPA Test Method 320 (see § 1065.266(c)) and ASTM D6348 (incorporated by reference, see § 1065.1010) are considered valid methods for spectral interpretation.
(3) Laser infrared analyzer. Examples of laser infrared analyzers are pulsed-mode high-resolution narrow-band mid-infrared analyzers, modulated continuous wave high-resolution narrow band near and mid-infrared analyzers, and modulated continuous-wave high-resolution near-infrared analyzers. A quantum cascade laser, for example, can emit coherent light in the mid-infrared region where NH 3 and other nitrogen compounds can effectively absorb the laser's energy.
(c) Sampling system. Minimize NH 3 losses and sampling artifacts related to NH 3 adsorbing to surfaces by using sampling system components (sample lines, prefilters and valves) made of stainless steel or PTFE heated to (110 to 202) °C. If surface temperatures exceed ≥130 °C, take steps to prevent any DEF in the sample gas from thermally decomposing and hydrolyzing to form NH 3 . Use a sample line that is as short as practical.
(d) Interference verification. Certain species can positively interfere with NDUV, FTIR, and laser infrared analyzers by causing a response similar to NH 3 . Perform interference verification as follows:
(1) Perform SO 2 and H 2 O interference verification for NDUV analyzers using the procedures of § 1065.372, replacing occurances of NO X with NH 3 . NDUV analyzers must have combined interference that is within (0.0 ±2.0) µmol/mol.
(2) Perform interference verification for FTIR and laser infrared analyzers using the procedures of § 1065.377. Use good engineering judgment to determine interference species. Note that interference species, with the exception of H 2 O, are dependent on the NH 3 infrared absorption band chosen by the instrument manufacturer. Determine interference species under this paragraph (d)(2) that are appropriate for each NH 3 infrared absorption band, or you may identify the interference species based on the instrument manufacturer's recommendations.
133. Revise the undesignated center heading preceding § 1065.280 to read as follows:

O 2 And Air-to-Fuel Ratio Measurements
134. Amend § 1065.280 by revising paragraph (b) to read as follows:
§ 1065.280
Paramagnetic and magnetopneumatic O 2 detection analyzers.
* * * * *
(b) Component requirements. We recommend that you use a PMD or MPD analyzer that meets the specifications in § 1065.205. Note that it must meet the linearity verification in § 1065.307.
135. Remove the undesignated center heading “Air-to-Fuel Ratio Measurements” preceding § 1065.284.
136. Amend § 1065.284 by revising paragraph (b) to read as follows:
§ 1065.284
Zirconium dioxide (ZrO 2 ) air-fuel ratio and O 2 analyzer.
* * * * *
(b) Component requirements. We recommend that you use a ZrO 2 analyzer that meets the specifications in § 1065.205. Note that your ZrO 2 -based system must meet the linearity verification in § 1065.307.
137. Amend § 1065.315 by revising paragraphs (a)(2) and (3) to read as follows:
§ 1065.315
Pressure, temperature, and dewpoint calibration.
(a) * * *
(2) Temperature. We recommend digital dry-block or stirred-liquid temperature calibrators, with data logging capabilities to minimize transcription errors. We recommend using calibration reference quantities for absolute temperature that are NIST-traceable within ±0.5% uncertainty. You may perform linearity verification for temperature measurement systems with thermocouples, RTDs, and thermistors by removing the sensor from the system and using a simulator in its place. Use a NIST-traceable simulator that is independently calibrated and, as appropriate, cold-junction compensated. The simulator uncertainty scaled to absolute temperature must be less than 0.5% of T max. If you use this option, you must use sensors that the supplier states are accurate to better than 0.5% of T max compared with their standard calibration curve.
(3) Dewpoint. We recommend a minimum of three different temperature-equilibrated and temperature-monitored calibration salt solutions in containers that seal completely around the dewpoint sensor. We recommend using calibration reference quantities for absolute dewpoint temperature that are NIST-traceable within ±0.5% uncertainty.
* * * * *
138. Amend § 1065.341 by revising paragraph (c) introductory text to read as follows:
§ 1065.341
CVS and PFD flow verification (propane check).
* * * * *
(c) If you performed the vacuum-side leak verification of the HC sampling system as described in paragraph (b)(8) of this section, you may use the HC contamination procedure in § 1065.520(g) to verify HC contamination. Otherwise, zero, span, and verify contamination of the HC sampling system, as follows:
* * * * *
139. Amend § 1065.350 by:
a. Revising paragraph (b);
b. Removing the undesignated paragraph following paragraph (b);
c. Revising paragraph (d)(7); and
d. Adding paragraph (d)(8).
The revisions and addition read as follows:
§ 1065.350
H 2 O interference verification for CO 2 NDIR analyzers.
* * * * *
(b) Measurement principles. H 2 O can interfere with an NDIR analyzer's response to CO 2 . If the NDIR analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
* * * * *
(d) * * *
(7) Operate the analyzer to get a reading for CO 2 concentration and record results for 30 seconds. Calculate the arithmetic mean of this data.
(8) The analyzer meets the interference verification if the result of paragraph (d)(7) of this section meets the tolerance in paragraph (c) of this section.
* * * * *
140. Amend § 1065.355 by revising paragraphs (b) and (d)(7) to read as follows:
§ 1065.355
H 2 O and CO 2 interference verification for CO NDIR analyzers.
* * * * *
(b) Measurement principles. H 2 O and CO 2 can positively interfere with an NDIR analyzer by causing a response similar to CO. If the NDIR analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
* * * * *
(d) * * *
(7) Operate the analyzer to get a reading for CO concentration and record results for 30 seconds. Calculate the arithmetic mean of this data.
* * * * *
141. Add an undesignated center heading and § 1065.357 after § 1065.355 to read as follows:

H 2 O Measurements
§ 1065.357
CO 2 interference verification for H 2 O FTIR analyzers.
(a) Scope and frequency. If you measure H 2 O using an FTIR analyzer, verify the amount of CO 2 interference after initial analyzer installation and after major maintenance.
(b) Measurement principles. CO 2 can interfere with an FTIR analyzer's response to H 2 O. If the FTIR analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
(c) System requirements. An H 2 O FTIR analyzer must have a CO 2 interference that is within (0.0 ± 0.4) mmol/mol, though we strongly recommend a lower interference that is within (0.0 ± 0.2) mmol/mol.
(d) Procedure. Perform the interference verification as follows:
(1) Start, operate, zero, and span the H 2 O FTIR analyzer as you would before an emission test.
(2) Use a CO 2 span gas that meets the specifications of § 1065.750 and a concentration that is approximately the maximum CO 2 concentration expected during emission testing.
(3) Introduce the CO 2 test gas into the sample system.
(4) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the transfer line and to account for analyzer response.
(5) Operate the analyzer to get a reading for H 2 O concentration and record results for 30 seconds. Calculate the arithmetic mean of these data.
(6) The analyzer meets the interference verification if the result of paragraph (d)(5) of this section meets the tolerance in paragraph (c) of this section.
(e) Exceptions. The following exceptions apply:
(1) You may omit this verification for CO 2 for engines operating on fuels other than carbon-containing fuels.
(2) You may omit this verification if you can show by engineering analysis that for your H 2 O sampling system and your emission-calculation procedures, the CO 2 interference for your H 2 O FTIR analyzer always affects your brake-specific emission results within ±0.5% of each of the applicable standards in this chapter. This specification also applies for vehicle testing, except that it relates to emission results in g/mile or g/kilometer.
(3) You may use an H 2 O FTIR analyzer that you determine does not meet this verification, as long as you try to correct the problem and the measurement deficiency does not adversely affect your ability to show that engines comply with all applicable emission standards.
142. Amend § 1065.360 by revising paragraphs (a)(4), (b), (c), (d) introductory text, and (d)(12) to read as follows:
§ 1065.360
FID optimization and verification.
(a) * * *
(4) You may determine the methane (CH 4 ) and ethane (C 2 H 6 ) response factors as a function of the molar water concentration in the raw or diluted exhaust. If you choose the option in this paragraph (a)(4), generate and verify the humidity level (or fraction) as described in § 1065.365(g).
(b) Calibration. Use good engineering judgment to develop a calibration procedure, such as one based on the FID-analyzer manufacturer's instructions and recommended frequency for calibrating the FID. Alternately, you may remove system components for off-site calibration. For a FID that measures THC, calibrate using C 3 H 8 calibration gases that meet the specifications of § 1065.750. For a FID that measures CH 4 , calibrate using CH 4 calibration gases that meet the specifications of § 1065.750. We recommend FID analyzer zero and span gases that contain approximately the flow-weighted mean concentration of O 2 expected during testing. If you use a FID to measure CH 4 downstream of a nonmethane cutter (NMC), you may calibrate that FID using CH 4 calibration gases with the NMC. Regardless of the calibration gas composition, calibrate on a carbon number basis of one (C 1 ). For example, if you use a C 3 H 8 span gas of concentration 200 μmol/mol, span the FID to respond with a value of 600 μmol/mol. As another example, if you use a CH 4 span gas with a concentration of 200 μmol/mol, span the FID to respond with a value of 200 μmol/mol.
(c) THC FID response optimization. This procedure is only for FID analyzers that measure THC. Use good engineering judgment for initial instrument start-up and basic operating adjustment using FID fuel and zero air. Heated FIDs must be within their required operating temperature ranges. Optimize FID response at the most common analyzer range expected during emission testing. Optimization involves adjusting flows and pressures of FID fuel, burner air, and sample to minimize response variations to various hydrocarbon species in the exhaust. Use good engineering judgment to trade off peak FID response to propane calibration gases to achieve minimal response variations to different hydrocarbon species. For an example of trading off response to propane for relative responses to other hydrocarbon species, see SAE 770141 (incorporated by reference, see § 1065.1010). Determine the optimum flow rates and/or pressures for FID fuel, burner air, and sample and record them for future reference.
(d) THC FID CH 4
response factor determination. This procedure is only for FID analyzers that measure THC. Since FID analyzers generally have a different response to CH 4 versus C 3 H 8 , determine the THC-FID analyzer's CH 4 response factor, RF CH4[THC-FID], after FID optimization. Use the most recent RF CH4[THC-FID] measured according to this section in the calculations for HC determination described in § 1065.660 to compensate for CH 4 response. Determine RF CH4[THC-FID] as follows, noting that you do not determine RF CH4[THC-FID] for FIDs that are calibrated and spanned using CH 4 with an NMC:
* * * * *
(12) You may determine the response factor as a function of molar water concentration using the following procedures and use this response factor to account for the CH 4 response for NMHC determination described in § 1065.660(b)(2)(iii):
(i) Humidify the CH 4 span gas as described in § 1065.365(g) and repeat the steps in paragraphs (d)(7) through (9) of this section until measurements are complete for each setpoint in the selected range.
(ii) Divide each mean measured CH 4 concentration by the recorded span concentration of the CH 4 calibration gas, adjusted for water content, to determine the FID analyzer's CH 4 response factor, RF CH4[THC-FID].
(iii) Use the CH 4 response factors at the different setpoints to create a functional relationship between response factor and molar water concentration, downstream of the last sample dryer if any sample dryers are present.
(iv) Use this functional relationship to determine the response factor during an emission test.
* * * * *
143. Revise § 1065.365 to read as follows:
§ 1065.365
Nonmethane cutter penetration fractions and NMC FID response factors.
(a) Scope and frequency. If you use a FID analyzer and an NMC to measure methane (CH 4 ), verify that the catalytic activity of the NMC has not deteriorated as described in this section. Determine the NMC's penetration fractions (PF) of CH 4 and ethane (C 2 H 6 ) and, if applicable, the FID analyzer response factors using the appropriate procedures of paragraph (d), (e), or (f) of this section. As detailed in this section, these penetration fractions may be determined as a combination of NMC penetration fractions and FID analyzer response factors, depending on your particular NMC and FID analyzer configuration. Perform this verification after installing the NMC and repeat this verification within 185 days of testing. Note that because NMCs can deteriorate rapidly and without warning if they are operated outside of certain ranges of gas concentrations and outside of certain temperature ranges, good engineering judgment may dictate that you determine an NMC's penetration fractions more frequently. Use the most recently determined penetration fraction from this section to calculate HC emissions according to § 1065.660 as applicable.
(b) Measurement principles. An NMC is a heated catalyst that removes nonmethane hydrocarbons from an exhaust sample stream before the FID analyzer measures the remaining hydrocarbon concentration. An ideal NMC would have a CH 4 penetration fraction, PF CH4, of 1.000, and the penetration fraction for all other nonmethane hydrocarbons would be 0.000, as represented by PF C2H6. The emission calculations in § 1065.660 use the measured values from this verification to account for less than ideal NMC performance.
(c) System requirements. We do not require that you limit NMC penetration fractions to a certain range. However, we recommend that you optimize an NMC by adjusting its temperature to achieve a PF C2H6 <0.02, as determined by paragraph (d), (e), or (f) of this section, as applicable, using dry gases. If adjusting NMC temperature does not result in achieving the recommended PF C2H6 level, we recommend that you replace the catalyst material. Note that, if we use an NMC for testing, we will optimize it to achieve a PF C2H6 <0.02.
(d) Procedure for a FID calibrated with the NMC. The following procedure describes the recommended method for verifying NMC performance and the required method for any gaseous-fueled engine, including dual-fuel and flexible-fuel engines.
(1) Select CH 4 and C 2 H 6 analytical gas mixtures and ensure that both mixtures meet the specifications of § 1065.750. Select a CH 4 concentration that you would use for spanning the FID during emission testing and select a C 2 H 6 concentration that is typical of the peak NMHC concentration expected at the hydrocarbon standard or equal to the THC analyzer's span value. For CH 4 analyzers with multiple ranges, perform this procedure on the highest range used for emission testing.
(2) Start, operate, and optimize the NMC according to the manufacturer's instructions, including any temperature optimization.
(3) Confirm that the FID analyzer meets all the specifications of § 1065.360.
(4) Start and operate the FID analyzer according to the manufacturer's instructions.
(5) Zero and span the FID with the NMC as you would during emission testing. Span the FID through the NMC by using CH 4 span gas.
(6) Introduce the C 2 H 6 analytical gas mixture upstream of the NMC. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.
(7) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the NMC and to account for the analyzer's response.
(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of the analytical gas mixture.
(9) Calculate a reference concentration of C 2 H 6 , by converting C 2 H 6 to a C 1 basis and adjusted for water content, if necessary. Calculate the combined C 2 H 6 response factor and penetration fraction, RFPF C2H6[NMC-FID], by dividing the mean C 2 H 6 concentration from paragraph (d)(8) of this section by the reference concentration of C 2 H 6 . For any gaseous-fueled engine, including dual-fuel and flexible-fuel engines, you must determine RFPF C2H6[NMC-FID] as a function of the molar water concentration in the raw or diluted exhaust using paragraph (g) of this section. Use RFPF C2H6[NMC-FID] at the different setpoints to create a functional relationship between RFPF C2H6[NMC-FID] and molar water concentration, downstream of the last sample dryer if any sample dryers are present. Use this functional relationship to determine the combined response factor and penetration fraction during the emission test. For any other engine you may use the same procedure or you may determine RFPF C2H6[NMC-FID] at zero molar water concentration.
(10) For any gaseous-fueled engine, including dual-fuel and flexible-fuel engines, repeat the steps in paragraphs (d)(6) through (9) of this section, but with the CH 4 analytical gas mixture instead of C 2 H 6 and determine RFPF CH4[NMC-FID] as a function of the molar water concentration in the raw or diluted exhaust using paragraph (g) of this section. Note that RFPF CH4[NMC-FID] is set equal to 1.0 only for zero molar water concentration. For any other engine you may use the same procedure, or you may set RFPF CH4[NMC-FID] equal to 1.0.
(11) Use RFPF C2H6[NMC-FID] and RFPF CH4[NMC-FID] in emission calculations according to § 1065.660(b)(2)(i) and (d)(1)(i).
(e) Procedure for a FID calibrated with propane, bypassing the NMC. If you use a single FID for THC and CH 4 determination with an NMC that is calibrated with propane, C 3 H 8 , by bypassing the NMC, determine its penetration fractions, PF C2H6[NMC-FID] and PF CH4[NMC-FID], as follows:
(1) Select CH 4 and C 2 H 6 analytical gas mixtures and ensure that both mixtures meet the specifications of § 1065.750. Select a CH 4 concentration that you would use for spanning the FID during emission testing and select a C 2 H 6 concentration that is typical of the peak NMHC concentration expected at the hydrocarbon standard and the C 2 H 6 concentration typical of the peak total hydrocarbon (THC) concentration expected at the hydrocarbon standard or equal to the THC analyzer's span value. For CH 4 analyzers with multiple ranges, perform this procedure on the highest range used for emission testing.
(2) Start and operate the NMC according to the manufacturer's instructions, including any temperature optimization.
(3) Confirm that the FID analyzer meets all the specifications of § 1065.360.
(4) Start and operate the FID analyzer according to the manufacturer's instructions.
(5) Zero and span the FID as you would during emission testing. Span the FID by bypassing the NMC and by using C 3 H 8 span gas. Note that you must span the FID on a C 1 basis. For example, if your span gas has a propane reference value of 100 μmol/mol, the correct FID response to that span gas is 300 μmol/mol because there are three carbon atoms per C 3 H 8 molecule.
(6) Introduce the C 2 H 6 analytical gas mixture upstream of the NMC. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.
(7) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the NMC and to account for the analyzer's response.
(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of the analytical gas mixture.
(9) Reroute the flow path to bypass the NMC, introduce the C 2 H 6 analytical gas mixture, and repeat the steps in paragraphs (e)(7) and (8) of this section.
(10) Divide the mean C 2 H 6 concentration measured through the NMC by the mean C 2 H 6 concentration measured after bypassing the NMC. The result is the C 2 H 6 penetration fraction, PF C2H6[NMC-FID]. Use this penetration fraction according to § 1065.660(b)(2)(ii) and (d)(1)(ii).
(11) Repeat the steps in paragraphs (e)(6) through (10) of this section, but with the CH 4 analytical gas mixture instead of C 2 H 6 . The result will be the CH 4 penetration fraction, PF CH4[NMC-FID]. Use this penetration fraction according to § 1065.660(b)(2)(ii) or § 1065.665, as applicable.
(f) Procedure for a FID calibrated with CH 4,
bypassing the NMC . If you use a FID with an NMC that is calibrated with CH 4 by bypassing the NMC, determine its combined C 2 H 6 response factor and penetration fraction, RFPF C2H6[NMC-FID], as well as its CH 4 penetration fraction, PF CH4[NMC-FID ], as follows:
(1) Select CH 4 and C 2 H 6 analytical gas mixtures and ensure that both mixtures meet the specifications of § 1065.750. Select a CH 4 concentration that you would use for spanning the FID during emission testing and select a C 2 H 6 concentration that is typical of the peak NMHC concentration expected at the hydrocarbon standard or equal to the THC analyzer's span value. For CH 4 analyzers with multiple ranges, perform this procedure on the highest range used for emission testing.
(2) Start and operate the NMC according to the manufacturer's instructions, including any temperature optimization.
(3) Confirm that the FID analyzer meets all the specifications of § 1065.360.
(4) Start and operate the FID analyzer according to the manufacturer's instructions.
(5) Zero and span the FID as you would during emission testing. Span the FID by bypassing the NMC and by using CH 4 span gas.
(6) Introduce the C 2 H 6 analytical gas mixture upstream of the NMC. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.
(7) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the NMC and to account for the analyzer's response.
(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of the analytical gas mixture.
(9) Divide the mean C 2 H 6 concentration by the reference concentration of C 2 H 6 , converted to a C 1 basis. The result is the combined C 2 H 6 response factor and C 2 H 6 penetration fraction, RFPF C2H6[NMC-FID]. Use this combined C 2 H 6 response factor and penetration fraction according to § 1065.660(b)(2)(iii) and (d)(1)(iii).
(10) Introduce the CH 4 analytical gas mixture upstream of the NMC. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.
(11) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the NMC and to account for the analyzer's response.
(12) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.
(13) Reroute the flow path to bypass the NMC, introduce the CH 4 analytical gas mixture, and repeat the steps in paragraphs (e)(11) and (12) of this section.
(14) Divide the mean CH 4 concentration measured through the NMC by the mean CH 4 concentration measured after bypassing the NMC. The result is the CH 4 penetration fraction, PF CH4[NMC-FID]. Use this CH 4 penetration fraction according to § 1065.660(b)(2)(iii) and (d)(1)(iii).
(g) Test gas humidification. If you are generating gas mixtures as a function of the molar water concentration in the raw or diluted exhaust according to paragraph (d) of this section, create a humidified test gas by bubbling the analytical gas mixture that meets the specifications in § 1065.750 through distilled H 2 O in a sealed vessel or use a device that introduces distilled H 2 O as vapor into a controlled gas flow. Determine the mole fraction of H 2 O in the humidified calibration gas, x H2Oref, as an average value over intervals of at least 30 seconds. We recommend that you design your system to maintain temperatures at least 5 °C above the local calibration gas dewpoint in any transfer lines, fittings, and valves between the point at which you determine x H2Oref and the analyzer. Verify the humidity generator's uncertainty upon initial installation, within 370 days before verifying response factors and penetration fractions, and after major maintenance. Use the uncertainties from the calibration of the humidity generator's measurements and follow NIST Technical Note 1297 (incorporated by reference, see § 1065.1010) to verify that the amount of H 2 O in x H2Oref is determined within ±3% uncertainty, U xH2O, for one of the options described in § 1065.750(a)(6). If the humidity generator requires assembly before use, after assembly follow the instrument manufacturer's instructions to check for leaks.
(1) If the sample does not pass through a dryer during emission testing, generate at least five different H 2 O concentrations that cover the range from less than the minimum expected to greater than the maximum expected water concentration during testing. Use good engineering judgment to determine the target concentrations.
(2) If the sample passes through a dryer during emission testing, humidify your test gas to an H 2 O level at or above the level determined in § 1065.145(e)(2) for that dryer and determine a single wet analyzer response to the dehumidified sample.
144. Amend § 1065.366 by revising paragraph (b) to read as follows:
§ 1065.366
Interference verification for FTIR analyzers.
* * * * *
(b) Measurement principles. Certain species can interfere with analyzers by causing a response similar to the target analyte. If the analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
* * * * *
145. Amend § 1065.369 by revising paragraph (b) to read as follows:
§ 1065.369
H 2 O, CO, and CO 2 interference verification for photoacoustic alcohol analyzers.
* * * * *
(b) Measurement principles. H 2 O, CO, and CO 2 can positively interfere with a photoacoustic analyzer by causing a response similar to ethanol or methanol. If the photoacoustic analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
* * * * *
146. Amend § 1065.372 by revising paragraphs (b) and (d)(7) and adding paragraphs (d)(8) and (e)(2) to read as follows:
§ 1065.372
NDUV analyzer HC and H 2 O interference verification.
* * * * *
(b) Measurement principles. Hydrocarbons and H 2 O can positively interfere with an NDUV analyzer by causing a response similar to NO X . If the NDUV analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting such measurements to test the algorithms during the analyzer interference verification.
* * * * *
(d) * * *
(7) Multiply this difference by the ratio of the flow-weighted mean HC concentration expected at the standard to the HC concentration measured during the verification.
(8) The analyzer meets the interference verification of this section if the result of paragraph (d)(7) of this section meets the tolerance in paragraph (c) of this section.
(e) * * *
(2) You may use a NO X NDUV analyzer that you determine does not meet this verification, as long as you try to correct the problem and the measurement deficiency does not adversely affect your ability to show that engines comply with all applicable emission standards.
147. Amend § 1065.375 by revising paragraphs (a), (b), and (d)(3) and (9) to read as follows:
§ 1065.375
Interference verification for N 2 O analyzers.
(a) Scope and frequency. This section describes how to perform interference verification for certain analyzers as described in § 1065.275. Perform interference verification after initial analyzer installation and after major maintenance.
(b) Measurement principles. Certain species can positively interfere with analyzers by causing a response similar to N 2 O. If the analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
* * * * *
(d) * * *
(3) Introduce the humidified interference test gas into the sample system upstream or downstream of any sample dryer, if one is used during testing.
* * * * *
(9) You may also run interference procedures separately for individual interference species. If the concentrations of the interference species used are higher than the maximum levels expected during testing, you may scale down each observed interference value (the arithmetic mean of 30 second data described in paragraph (d)(7) of this section) by multiplying the observed interference by the ratio of the maximum expected concentration value to the actual value used during this procedure. You may run separate interference concentrations of H 2 O (down to 0.025 mol/mol H 2 O content) that are lower than the maximum levels expected during testing, but you must scale up the observed H 2 O interference by multiplying the observed interference by the ratio of the maximum expected H 2 O concentration value to the actual value used during this procedure. The sum of the scaled interference values must meet the tolerance for combined interference as specified in paragraph (c) of this section.
148. Add § 1065.377 to read as follows:
§ 1065.377
Interference verification for NH 3 analyzers.
(a) Scope and frequency. This section describes how to perform interference verification for certain analyzers as described in § 1065.277. Perform interference verification after initial analyzer installation and after major maintenance.
(b) Measurement principles. Certain compounds can positively interfere with analyzers by causing a response similar to NH 3 . If the analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, a correct result depends on simultaneously conducting these other measurements to test the compensation algorithms during the analyzer interference verification.
(c) System requirements. Analyzers must have combined interference that is within (0.0 ±2.0) µmol/mol.
(d) Procedure. Perform the interference verification as follows:
(1) Start, operate, zero, and span the NH 3 analyzer as you would before an emission test. If the sample is passed through a dryer during emission testing, you may run this verification test with the dryer if it meets the requirements of § 1065.342. Operate the dryer at the same conditions as you will for an emission test. You may also run this verification test without the sample dryer.
(2) Except as specified in paragraph (d)(9) of this section, select a multi-component span gas meeting the specification of § 1065.750 that incorporates the all the appropriate interference species. Use a humidity generator that meets the requirements in § 1065.750(a)(6) to humidify the span gas. If the sample does not pass through a dryer during emission testing, humidify your test gas to an H 2 O level at or above the maximum expected during emission testing. If the sample passes through a dryer during emission testing, humidify your test gas to an H 2 O level at or above the level determined in § 1065.145(e)(2) for that dryer. Use interference span gas concentrations that are at least as high as the maximum expected during testing.
(3) Introduce the humidified interference test gas into the sample system upstream or downstream of any sample dryer, if one is used during testing.
(4) If the sample does not pass through a dryer during this verification test, measure the H 2 O mole fraction, x H2O, of the humidified interference test gas as close as possible to the analyzer inlet. You may measure dewpoint, T dew, and absolute pressure, p total, to calculate x H2O. Verify that the H 2 O content meets the requirement in paragraph (d)(2) of this section. If the sample passes through a dryer during this verification test, either measure dewpoint, T dew, and absolute pressure, p total, to calculate x H2O or use good engineering judgment to estimate the value of x H2O based on the vessel pressure and temperature. For example, you may use previous direct measurements of H 2 O content at certain vessel pressures and temperatures to estimate x H2O.
(5) If the verification procedure does not include a sample dryer, use good engineering judgment to prevent condensation in the transfer lines, fittings, or valves between the point of x H2O measurement and the analyzer. We recommend that you design your system so that the wall temperatures in those transfer lines, fittings, and valves are at least 5 °C above the local sample gas dewpoint.
(6) Allow time for the analyzer response to stabilize. Stabilization time may include time to purge the transfer line and to account for analyzer response.
(7) Operate the analyzer to measures the sample's NH 3 concentration and record results for 30 seconds. Calculate the arithmetic mean of these data to determine the interference value. When performed with all the interference species simultaneously, this is the combined interference.
(8) The analyzer meets the interference verification if the result of paragraph (d)(7) of this section meets the tolerance in paragraph (c) of this section.
(9) You may instead perform interference verification procedures separately for individual interference species. The interference verification specified in paragraph (c) of this section applies based on the sum of the interference values from separate interference species. If the concentration of any interference species used is higher than the maximum levels expected during testing, you may scale down each observed interference value by multiplying the observed interference value by the ratio of the maximum expected concentration value to the concentration in the span gas. You may run separate H 2 O interference concentrations (down to 0.025 mol/mol H 2 O content) that are lower than the maximum levels expected during testing, but you must scale up the observed H 2 O interference value by multiplying the observed interference value by the ratio of the maximum expected H 2 O concentration value to the concentration in the span gas. The sum of the scaled interference values must meet the tolerance for combined interference as specified in paragraph (c) of this section.
149. Amend § 1065.378 by adding paragraphs (e)(2) and (3) to read as follows:
§ 1065.378
NO 2 -to-NO converter conversion verification.
* * * * *
(e) * * *
(2) You may use a converter that you determine does not meet this verification, as long as you try to correct the problem and the measurement deficiency does not adversely affect your ability to show that engines comply with all applicable emission standards.
(3) You may request to verify converter conversion efficiency using an NO 2 concentration whose value is representative of the peak total NO 2 concentration expected during testing, in place of the procedure in paragraph (d) of this section, with our approval.
150. Amend § 1065.510 by revising paragraphs (a) introductory text, (b), (d)(5)(i) and (iii), and (f) to read as follows:
§ 1065.510
Engine mapping.
(a) Applicability, scope, and frequency. An engine map is a data set that consists of a series of paired data points that represent the maximum brake torque versus engine speed, measured at the engine's primary output shaft. Map your engine if the standard-setting part requires engine mapping to generate a duty cycle for your engine configuration. Map your engine while it is connected to a dynamometer or other device that can absorb work output from the engine's primary output shaft according to § 1065.110. Configure any auxiliary work inputs and outputs such as hybrid, turbo-compounding, or thermoelectric systems to represent their in-use configurations and use the same configuration for emission testing. See figure 1 to paragraph (a)(5) of § 1065.210. This may involve configuring initial states of charge and rates and times of auxiliary-work inputs and outputs. We recommend that you contact the EPA Program Officer before testing to determine how you should configure any auxiliary-work inputs and outputs. If your engine has an auxiliary emission control device to reduce torque output that may activate during engine mapping, turn it off before mapping. Use the most recent engine map to transform a normalized duty cycle from the standard-setting part to a reference duty cycle specific to your engine. Normalized duty cycles are specified in the standard-setting part. You may update an engine map at any time by repeating the engine-mapping procedure. You must map or re-map an engine before a test if any of the following apply:
* * * * *
(b) Mapping variable-speed engines. Map variable-speed engines using the procedure in this paragraph (b). Note that under § 1065.10(c) we may allow or require you to use “other procedures” if the specified procedure results in unrepresentative testing or if your engine cannot be tested using the specified procedure. If the engine has a user-adjustable idle speed setpoint, you may set it to its minimum adjustable value for this mapping procedure and the resulting map may be used for any test, regardless of where it is set for running each test except that the warm idle speed(s) must be determined based on where it is set for running each test.
(1) Record the atmospheric pressure.
(2) Warm up the engine by operating it. We recommend operating the engine at any speed and at approximately 75% of its expected maximum power. Continue the warm-up until the engine coolant, block, lubricating oil, or head absolute temperature is within ±2% of its mean value for at least 2 min or until the engine thermostat controls engine temperature.
(3) Operate the engine at its warm idle speed as follows:
(i) For engines with a low-speed governor, set the operator demand to minimum, use the dynamometer or other loading device to target a torque of zero or the lowest idle load that you will use for cycle generation on the engine's primary output shaft, and allow the engine to govern the speed. If the idle load is a function of engine speeds ( e.g., the optional declared power from paragraph (f)(6) of this section), calculate the target torque in real time. Measure this warm idle speed; we recommend recording at least 30 values of speed and using the mean of those values. If you identify multiple warm idle loads under paragraph (f)(4), (f)(5)(iii), or (f)(6) of this section, measure the warm idle speed at the lowest torque level for this paragraph (b)(3). Measure the other warm idle speeds as described in paragraph (b)(7) of this section.
(ii) For engines without a low-speed governor, operate the engine at warm idle speed from paragraph (f)(2) of this section and zero torque or the lowest warm idle torque that you will use for cycle generation on the engine's primary output shaft. You may use the dynamometer to control either torque or speed and manipulate the operator demand to control the other parameter.
(4) Operate the engine at the minimum mapped speed. A minimum mapped speed equal to (95 ± 1)% of its warm idle speed determined in paragraph (b)(3) of this section may be used for any engine or test. A higher minimum mapped speed may be used if all the duty cycles that the engine is subject to have a minimum reference speed higher than the warm idle speed determined in paragraph (b)(3) of this section. In this case you may use a minimum mapped speed equal to (95 ± 1)% of the lowest minimum reference speed in all the duty cycles the engine is subject to. Set operator demand to maximum and control engine speed at this minimum mapped speed for at least 15 seconds. Set operator demand to maximum and control engine speed at (95 ± 1)% of its warm idle speed determined in paragraph (b)(3)(i) of this section for at least 15 seconds.
(5) Perform a continuous or discrete engine map as described in paragraph (b)(5)(i) or (ii) of this section. A continuous engine map may be used for any engine. A discrete engine map may be used for engines subject only to steady-state duty cycles. Use linear interpolation between the series of points generated by either of these maps to determine intermediate torque values. Use the series of points generated by either of these maps to generate the power map as described in paragraph (e) of this section.
(i) For continuous engine mapping, begin recording mean feedback speed and torque at 1 Hz or more frequently and increase speed at a constant rate such that it takes (4 to 6) min to sweep from the minimum mapped speed described in paragraph (b)(4) of this section to the check point speed described in paragraph (b)(5)(iii) of this section. Use good engineering judgment to determine when to stop recording data to ensure that the sweep is complete. In most cases, this means that you can stop the sweep at any point after the power falls to 50% of the maximum value.
(ii) For discrete engine mapping, select at least 20 evenly spaced setpoints from the minimum mapped speed described in paragraph (b)(4) of this section to the check point speed described in paragraph (b)(5)(iii) of this section. At each setpoint, stabilize speed and allow torque to stabilize. We recommend that you stabilize an engine for at least 15 seconds at each setpoint and record the mean feedback speed and torque of the last (4 to 6) seconds. Record the mean speed and torque at each setpoint.
(iii) The check point speed of the map is the highest speed above maximum power at which 50% of maximum power occurs. If this speed is unsafe or unachievable ( e.g., for ungoverned engines or engines that do not operate at that point), use good engineering judgment to map up to the maximum safe speed or maximum achievable speed. For discrete mapping, if the engine cannot be mapped to the check point speed, make sure the map includes at least 20 points from 95% of warm idle to the maximum mapped speed. For continuous mapping, if the engine cannot be mapped to the check point speed, verify that the sweep time from 95% of warm idle to the maximum mapped speed is (4 to 6) min.
(iv) Note that under § 1065.10(c)(1) we may allow you to disregard portions of the map when selecting maximum test speed if the specified procedure would result in a duty cycle that does not represent in-use operation.
(6) Determine warm high-idle speed for engines with a high-speed governor. You may skip this if the engine is not subject to transient testing with a duty cycle that includes reference speed values above 100%. You may use a manufacturer-declared warm high-idle speed if the engine is electronically governed. For engines with a high-speed governor that regulates speed by disabling and enabling fuel or ignition at two manufacturer-specified speeds, declare the middle of this specified speed range as the warm high-idle speed. You may alternatively measure warm high-idle speed using the following procedure:
(i) Run an operating point targeting zero torque.
(A) Set operator demand to maximum and use the dynamometer to target zero torque on the engine's primary output shaft.
(B) Wait for the engine governor and dynamometer to stabilize. We recommend that you stabilize for at least 15 seconds.
(C) Record 1 Hz means of the feedback speed and torque for at least 30 seconds. You may record means at a higher frequency as long as there are no gaps in the recorded data. For engines with a high-speed governor that regulates speed by disabling and enabling fuel or ignition, you may need to extend this stabilization period to include at least one disabling event at the higher speed and one enabling event at the lower speed.
(D) Determine if the feedback speed is stable over the recording period. The feedback speed is considered stable if all the recorded 1 Hz means are within ±2% of the mean feedback speed over the recording period. If the feedback speed is not stable because of the dynamometer, void the results and repeat measurements after making any necessary corrections. You may void and repeat the entire map sequence, or you may void and replace only the results for establishing warm high-idle speed; use good engineering judgment to warm-up the engine before repeating measurements.
(E) If the feedback speed is stable, use the mean feedback speed over the recording period as the measured speed for this operating point.
(F) If the feedback speed is not stable because of the engine, determine the mean as the value representing the midpoint between the observed maximum and minimum recorded feedback speed.
(G) If the mean feedback torque over the recording period is within (0 ± 1)% of T maxmapped, use the measured speed for this operating point as the warm high-idle speed. Otherwise, continue testing as described in paragraph (b)(6)(ii) of this section.
(ii) Run a second operating point targeting a positive torque. Follow the same procedure in paragraphs (b)(6)(i)(A) through (F) of this section, except that the dynamometer is set to target a torque equal to the mean feedback torque over the recording period from the previous operating point plus 20% of T max mapped.
(iii) Use the mean feedback speed and torque values from paragraphs (b)(6)(i) and (ii) of this section to determine the warm high-idle speed. If the two recorded speed values are the same, use that value as the warm high-idle-speed. Otherwise, use a linear equation passing through these two speed-torque points and extrapolate to solve for the speed at zero torque and use this speed intercept value as the warm high-idle speed.
(iv) You may use a manufacturer-declared T max instead of the measured T max mapped. If you do this, you may also measure the warm high-idle speed as described in this paragraph (b)(6) before running the operating point and speed sweeps specified in paragraphs (b)(4) and (5) of this section.
(7) This paragraph (b)(7) describes how to collect additional data to determine warm idle speed(s) for cycle generation if your engine has a low-speed governor. You may omit this paragraph (b)(7) if you use the option to declare a warm idle speed in paragraph (f)(3)(iv) of this section, or if you identify only one idle load and one user-adjustable idle speed setpoint under paragraph (b)(3)(i) of this section. Collect additional data to determine warm idle speed(s) using one of the following options:
(i) For each idle load ( e.g., idle with the transmission in neutral and drive) you identify under paragraph (f)(4), (f)(5)(iii), or (f)(6) of this section, operate the engine at each idle load and measure the warm idle speed at each idle load as described in paragraph (b)(3)(i) of this section. The warm idle operating point run in paragraph (b)(3)(i) of this section may be skipped and the measured warm idle speed from paragraph (b)(3)(i) of this section may be used for cycle generation for cycles where the user-adjustable idle speed setpoint is the same. Note that this option requires you to know all the idle loads in all the cycles that will be generated with this map at the time the map is run.
(ii) You may map the idle governor at multiple torque levels and use this map to determine the warm idle speed(s) at any idle load within the range of this map. For cases where the idle torque is a function of engine speeds ( e.g., if CITT is specified as a function of speed or if the optional declared power in paragraph (f)(6) of this section applies) we recommend that the warm idle speed be determined using a closed form solution assuming speed and torque vary linearly between points in this map. If an iterative method is used, continue to iterate until the value is within ±0.0001% of the previous value.
(8) This paragraph (b)(8) describes how to collect additional data to determine warm idle speed(s) for cycle generation if your engine has a low-speed governor and a user-adjustable idle speed setpoint and you need to generate cycles for tests with a different setpoint from the setpoint used in this mapping procedure. You may omit this paragraph (b)(8) if you use the option to declare a warm idle speed in paragraph (f)(3)(iv) of this section. Collect additional data using paragraph (b)(7) of this section to determine the warm idle speed for each setpoint for use in generating cycles. Record the warm idle speed and torque for each setpoint.
* * * * *
(d) * * *
(5) * * *
(i) For constant-speed engines subject only to steady-state testing, you may perform an engine map by using a series of discrete torques. Select at least five evenly spaced torque setpoints from no-load to 80% of the manufacturer-declared test torque or to a torque derived from your published maximum power level if the declared test torque is unavailable. Starting at the 80% torque point, select setpoints in 2.5% or smaller intervals, stopping at the endpoint torque. The endpoint torque is defined as the first discrete mapped torque value greater than the torque at maximum observed power where the engine outputs 90% of the maximum observed power; or the torque when engine stall has been determined using good engineering judgment ( i.e., sudden deceleration of engine speed while adding torque). You may continue mapping at higher torque setpoints. At each setpoint, allow torque and speed to stabilize. Record the mean feedback speed and torque at each setpoint. From this series of mean feedback speed and torque values, use linear interpolation to determine intermediate values. Use this series of mean feedback speeds and torques to generate the power map as described in paragraph (e) of this section.
* * * * *
(iii) For any isochronous governed (no speed droop) constant-speed engine, you may map the engine with two points as described in this paragraph (d)(5)(iii). After stabilizing at the no-load, or minimum achievable load, governed speed in paragraph (d)(4) of this section, record the mean feedback speed and torque. Continue to operate the engine with the governor or simulated governor controlling engine speed using operator demand and control the dynamometer to target a speed of 99.5% of the recorded mean no-load governed speed. Allow speed and torque to stabilize. Record the mean feedback speed and torque. Record the target speed. The absolute value of the speed error (the mean feedback speed minus the target speed) must be no greater than 0.1% of the recorded mean no-load governed speed. From this series of two mean feedback speed and torque values, use linear interpolation to determine intermediate values. Use this series of two mean feedback speeds and torques to generate a power map as described in paragraph (e) of this section. Note that the measured maximum test torque as determined in § 1065.610(b)(1) will be the mean feedback torque recorded on the second point.
* * * * *
(f) Measured and declared speeds, torques, and power. You must select speeds, torques, and power for engine mapping and for cycle generation as required in this paragraph (f). “Measured” values are either directly measured during the engine mapping process or they are determined from the engine map. “Declared” values are specified by the manufacturer. When both measured and declared values are available, you may use declared test speeds and torques instead of measured speeds and torques if they meet the criteria in this paragraph (f). Otherwise, you must use measured speeds and torques derived from the engine map.
(1) Measured speeds and torques. Determine the applicable speeds and torques for the duty cycles you will run:
(i) Measured maximum test speed for variable-speed engines according to § 1065.610.
(ii) Measured maximum test torque for constant-speed engines according to § 1065.610.
(iii) Measured “A”, “B”, and “C” speeds for variable-speed engines according to § 1065.610.
(iv) Measured intermediate speed for variable-speed engines according to § 1065.610.
(v) For variable-speed engines with a low-speed governor, measure warm idle speed(s) according to paragraph (b) of this section and use this (these) speed(s) for cycle generation in § 1065.512. For engines with no low-speed governor, instead use the manufacturer-declared warm idle speed from paragraph (f)(2) of this section.
(2) Required declared speeds. You must declare the lowest engine speed possible with minimum load ( i.e., manufacturer-declared warm idle speed). This is applicable only to variable-speed engines with no low-speed governor. For engines with no low-speed governor, the declared warm idle speed is used for cycle generation in § 1065.512. Declare this speed in a way that is representative of in-use operation. For example, if your engine is typically connected to an automatic transmission or a hydrostatic transmission, declare this speed at the idle speed at which your engine operates when the transmission is engaged.
(3) Optional declared speeds. You may use declared speed instead of measured speed as follows:
(i) You may use a declared value for maximum test speed for variable-speed engines if it is within (97.5 to 102.5)% of the corresponding measured value. You may use a higher declared speed if the length of the “vector” at the declared speed is within 2% of the length of the “vector” at the measured value. The term vector refers to the square root of the sum of normalized engine speed squared and the normalized full-load power (at that speed) squared, consistent with the calculations in § 1065.610.
(ii) You may use a declared value for intermediate, “A”, “B”, or “C” speeds for steady-state tests if the declared value is within (97.5 to 102.5)% of the corresponding measured value.
(iii) For electronically governed variable-speed engines, you may use a declared warm high-idle speed for calculating the alternate maximum test speed as specified in § 1065.610.
(iv) For electronically governed variable-speed engines with an isochronous low-speed governor ( i.e., no speed droop), you may declare that the warm idle speed is equal to the idle speed setpoint and use it for cycle generation instead of warm idle speed(s) determined from the data collected during the engine mapping procedure in paragraph (b) of this section. When generating cycles with multiple idle torque values, you may use this idle speed setpoint for all idle points. If the idle torque is a function of speed ( e.g., CITT is specified as a function of speed or if the optional declared power in paragraph (f)(6) of this section applies) use the setpoint to calculate the idle torque(s) for cycle generation. If the engine has a user-adjustable idle speed setpoint, generate the cycle using the idle speed setpoint that will be set when the engine is run for that cycle.
(4) Required declared torque. For variable-speed engines intended primarily for propulsion of a vehicle with an automatic transmission where that engine is subject to a transient duty cycle with idle operation, you must declare a Curb-Idle Transmission Torque (CITT). We recommend that you specify CITT as a function of idle speed for engines with adjustable warm idle or enhanced-idle. You may specify a CITT based on typical applications at the mean of the range of idle speeds you specify at stabilized temperature conditions. See the required deviations for cycle generation in § 1065.610(d)(3) for how the required declared CITT and the optional declared torque in paragraph (f)(5)(iii) of this section and the optional declared power in paragraph (f)(6) of this section are used in cycle generation.
(5) Optional declared torques. You may use declared torque instead of measured torque as follows:
(i) For variable-speed engines you may declare a maximum torque over the engine operating range. You may use the declared value for measuring warm high-idle speed as specified in this section.
(ii) For constant-speed engines you may declare a maximum test torque. You may use the declared value for cycle generation if it is within (95 to 100)% of the measured value. (iii) For variable-speed engines, you may declare a nonzero torque for idle operation that represents in-use operation. For example, if your engine is connected to a hydrostatic transmission with a minimum torque even when all the driven hydraulic actuators and motors are stationary and the engine is at idle, you may use this minimum torque as the declared value. As another example, if your engine is connected to a vehicle or machine with accessories, you may use a declared torque corresponding to operation with those accessories. You may specify a combination of torque and power as described in paragraph (f)(6) of this section. Use this option when the idle loads ( e.g., vehicle accessory loads) are best represented as a constant torque on the primary output shaft. You may use multiple warm idle loads and associated idle speeds in cycle generation for representative testing. As an example, see the required deviations for cycle generation in § 1065.610(d)(3) for improved simulation of idle points for engines intended primarily for propulsion of a vehicle with an automatic or manual transmission where that engine is subject to a transient duty cycle with idle operation.
(iv) For constant-speed engines, you may declare a warm minimum torque that represents in-use operation. For example, if your engine is typically connected to a machine that does not operate below a certain minimum torque, you may use this minimum torque as the declared value and use it for cycle generation.
(6) Optional declared power. For variable-speed engines, you may declare a nonzero power for idle operation that represents in-use operation. If you specify a torque in paragraph (f)(5)(iii) of this section and a power in this paragraph (f)(6), the combination of declared values must represent in-use operation and you must use the combination for cycle generation. Use the combination of declared values when the idle loads ( i.e., vehicle accessory loads) are best represented as a constant power.
* * * * *
151. Amend § 1065.512 by revising paragraphs (b)(1) and (2) to read as follows:
§ 1065.512
Duty cycle generation.
* * * * *
(b) * * *
(1) Engine speed for variable-speed engines. For variable-speed engines, normalized speed may be expressed as a percentage between warm idle speed, ƒ nidle, and maximum test speed, ƒ ntest, or speed may be expressed by referring to a defined speed by name, such as “warm idle,” “intermediate speed,” or “A,” “B,” or “C” speed. Section 1065.610 describes how to transform these normalized values into a sequence of reference speeds, ƒ nref. Running duty cycles with negative or small normalized speed values near warm idle speed may cause low-speed idle governors to activate and the engine torque to exceed the reference torque even though the operator demand is at a minimum. In such cases, we recommend controlling the dynamometer so it gives priority to follow the reference torque instead of the reference speed and let the engine govern the speed. Note that the cycle-validation criteria in § 1065.514 allow an engine to govern itself. This allowance permits you to test engines with enhanced-idle devices and to simulate the effects of transmissions such as automatic transmissions. For example, an enhanced-idle device might be an idle speed value that is normally commanded only under cold-start conditions to quickly warm up the engine and aftertreatment devices. In this case, negative and very low normalized speeds will generate reference speeds below this higher enhanced-idle speed. You may do any of the following when using enhanced-idle devices:
(i) While running an engine where the ECM broadcasts an enhanced-idle speed that is above the denormalized speed, use the broadcast speed as the reference speed. Use these new reference points for duty-cycle validation. This does not affect how you determine denormalized reference torque in paragraph (b)(2) of this section.
(ii) If an ECM broadcast signal is not available, perform one or more practice cycles to determine the enhanced-idle speed as a function of cycle time. Generate the reference cycle as you normally would but replace any reference speed that is lower than the enhanced-idle speed with the enhanced-idle speed. This does not affect how you determine denormalized reference torque in paragraph (b)(2) of this section.
(2) Engine torque for variable-speed engines. For variable-speed engines, normalized torque is expressed as a percentage of the mapped torque at the corresponding reference speed. Section 1065.610 describes how to transform normalized torques into a sequence of reference torques, T ref . Section 1065.610 also describes special requirements for modifying transient duty cycles for variable-speed engines intended primarily for propulsion of a vehicle with an automatic or manual transmission. Section 1065.610 also describes under what conditions you may command T ref greater than the reference torque you calculated from a normalized duty cycle, which permits you to command T ref values that are limited by a declared minimum torque. For any negative torque commands, command minimum operator demand and use the dynamometer to control engine speed to the reference speed, but if reference speed is so low that the idle governor activates, we recommend using the dynamometer to control torque to zero, CITT, or a declared minimum torque as appropriate. Note that you may omit power and torque points during motoring from the cycle-validation criteria in § 1065.514. Also, use the maximum mapped torque at the minimum mapped speed as the maximum torque for any reference speed at or below the minimum mapped speed.
* * * * *
152. Amend § 1065.520 by:
a. Redesignating paragraph (f) as paragraph (g);
b. Adding new paragraph (f); and
c. Revising newly redesignated paragraphs (g) introductory text and (g)(7)(iii).
The addition and revisions read as follows:
§ 1065.520
Pre-test verification procedures and pre-test data collection.
* * * * *
(f) If your testing requires a chemical balance, then before the start of emissions testing select the chemical balance method and the gaseous emission measurement equipment required for testing. Select the chemical balance method depending on the fuels used during testing:
(1) When using only carbon-containing fuels, use the carbon-based chemical balance procedure in § 1065.655.
(2) When using only fuels other than carbon-containing fuels, use the hydrogen-based chemical balance procedure in § 1065.656.
(3) When using constant mixtures of carbon-containing fuels and fuels other than carbon- containing fuels, use the following chemical balance methods and gaseous emission measurement equipment:
(i) If the hydrogen-to-carbon ratio, a , of the fuel mixture is less than or equal to 6, then use the carbon-based chemical balance procedure in § 1065.655.
(ii) Otherwise, use the hydrogen-based chemical balance procedure in § 1065.656.
(4) When using variable mixtures of carbon-containing fuels and fuels other than carbon-containing fuels, if the mean hydrogen-to-carbon ratio of the fuel mixture, a , is expected to be greater than 6 for a test interval, you must use the hydrogen-based chemical balance procedure in § 1065.656 for that test interval. Otherwise, you may use the carbon-based chemical balance procedure in § 1065.655.
(g) If your testing requires measuring hydrocarbon emissions, verify the amount of nonmethane hydrocarbon contamination in the exhaust and background HC sampling systems within 8 hours before the start of the first test interval of each duty-cycle sequence for laboratory tests. You may verify the contamination of a background HC sampling system by reading the last bag fill and purge using zero gas. For any NMHC measurement system that involves separately measuring CH 4 and subtracting it from a THC measurement or for any CH 4 measurement system that uses an NMC, verify the amount of THC contamination using only the THC analyzer response. There is no need to operate any separate CH 4 analyzer for this verification; however, you may measure and correct for THC contamination in the CH 4 sample path for the cases where NMHC is determined by subtracting CH 4 from THC or, where CH 4 is determined, using an NMC as configured in § 1065.365(d), (e), and (f); and using the calculations in § 1065.660(b)(2). Perform this verification as follows:
* * * * *
(7) * * *
(iii) Use mean analyzer values from paragraphs (g)(2) and (3) and (g)(7)(i) and (ii) of this section to correct the initial THC concentration recorded in paragraph (g)(6) of this section for drift, as described in § 1065.550.
* * * * *
153. Amend § 1065.530 by revising paragraphs (a)(2)(ii), (a)(2)(iii)(A), and (b)(4), (9), and (11) to read as follows:
§ 1065.530
Emission test sequence.
(a) * * *
(2) * * *
(ii) For hot-start duty cycles, first operate the engine at any speed above peak-torque speed and at (65 to 85)% of maximum mapped power until either the engine coolant, block, lubricating oil, or head absolute temperature is within ±2% of its mean value for at least 2 min or until the engine thermostat controls engine temperature. Shut down the engine. Start the duty cycle within 20 min of engine shutdown.
(iii) * * *
(A) Engine coolant, block, lubricating oil, or head absolute temperatures for water-cooled engines.
* * * * *
(b) * * *
(4) Pre-heat or pre-cool heat exchangers in the sampling system to within their operating temperature tolerances for a test interval.
* * * * *
(9) Select gas analyzer ranges. You may automatically or manually switch gas analyzer ranges during a test interval only if switching is performed by changing the span over which the digital resolution of the instrument is applied. During a test interval you may not switch the gains of an analyzer's analog operational amplifier(s).
* * * * *
(11) We recommend that you verify gas analyzer responses after zeroing and spanning by sampling a calibration gas that has a concentration near one-half of the span gas concentration. Based on the results and good engineering judgment, you may decide whether or not to re-zero, re-span, or re-calibrate a gas analyzer before starting a test interval.
* * * * *
154. Amend § 1065.550 by revising paragraphs (b) introductory text and (b)(3)(ii) to read as follows:
§ 1065.550
Gas analyzer range verification and drift verification.
* * * * *
(b) Drift verification. Gas analyzer drift verification is required for all gaseous exhaust constituents for which an emission standard applies. It is also required for CO 2 , H 2 , O 2 , H 2 O, and NH 3 , if required by the applicable chemical balance, even if there are no emission standards. It is not required for other gaseous exhaust constituents for which only a reporting requirement applies (such as CH 4 and N 2 O).
* * * * *
(3) * * *
(ii) Where no emission standard applies for CO 2 , H 2 , O 2 , H 2 O, and NH 3 , you must satisfy one of the following:
(A) For each test interval of the duty cycle, the difference between the uncorrected and the corrected brake-specific CO 2 , H 2 , O 2 , H 2 O, or NH 3 values must be within ±4% of the uncorrected value; or the difference between the uncorrected and the corrected CO 2 , H 2 , O 2 , H 2 O, or NH 3 mass (or mass rate) values must be within ±4% of the uncorrected value.
(B) For the entire duty cycle, the difference between the uncorrected and the corrected composite brake-specific CO 2 , H 2 , O 2 , H 2 O, or NH 3 values must be within ±4% of the uncorrected value.
* * * * *
155. Amend § 1065.601 by revising paragraph (c)(1) to read as follows:
§ 1065.601
Overview.
* * * * *
(c) * * *
(1) Mass-based emission calculations prescribed by the International Organization for Standardization (ISO), according to ISO 8178, except the following:
(i) ISO 8178-4 Section 9.1.6, NO X Correction for Humidity and Temperature. See § 1065.670 for approved methods for humidity corrections.
(ii) [Reserved]
* * * * *
156. Amend § 1065.602 by adding paragraph (m) to read as follows:
§ 1065.602
Statistics.
* * * * *
(m) Median. Determine median, M , as described in this paragraph (m). Arrange the data points in the data set in increasing order where the smallest value is ranked 1, the second-smallest value is ranked 2, etc.
(1) For even numbers of data points:
(i) Determine the rank of the data point whose value is used to determine the median as follows:
Eq. 1065.602-18
Where:
i = an indexing variable that represents the rank of the data point whose value is used to determine the median.
N = the number of data points in the set.
Example:
N = 4
y 1 = 41.515
y 2 = 41.780
y 3 = 41.861
y 4 = 41.902
i = 2
i = 2
(ii) Determine the median as the average of the data point i and the data point i + 1 as follows:
Eq. 1065.602-19
(2) For odd numbers of data points, determine the rank of the data point whose value is the median and the corresponding median value as follows:
Eq. 1065.602-20
Where:
i = an indexing variable that represents the rank of the data point whose value is the median.
N = the number of data points in the set.
Example:
N = 3
y 1 = 41.515
y 2 = 41.780
y 3 = 41.861
157. Amend § 1065.610 by revising paragraph (d)(3) to read as follows:
§ 1065.610
Duty cycle generation.
* * * * *
(d) * * *
(3) Required deviations. We require the following deviations for variable-speed engines intended primarily for propulsion of a vehicle with an automatic or manual transmission where that engine is subject to a transient duty cycle that specifies points with normalized reference speed of 0% and normalized reference torque of 0% ( i.e., idle points). These deviations are intended to produce a more representative transient duty cycle for these applications. For steady-state duty cycles or transient duty cycles with no idle operation, the requirements in this paragraph (d)(3) do not apply. Idle points for steady-state duty cycles of such engines are to be run at conditions simulating neutral or park on the transmission. For manual transmissions, set CITT to zero, which results in warm-idle-in-drive speed and torque values being the same as warm-idle-in-neutral values. For the case of a manual transmission where the optional declared idle torque in § 1065.510(f)(5)(iii) and the optional declared power in § 1065.510(f)(6) are not declared ( i.e., idle torque is zero), the required deviations in this paragraph (d)(3) have no impact and may be skipped.
(i) Determine the warm-idle-in-drive speed and torque values with the transmission in drive from the data collected during the engine mapping procedure in § 1065.510. The warm-idle-in-drive torque is the sum of CITT and the torques representing loads from vehicle accessories. For example, the sum of the required declared CITT in § 1065.510(f)(4), any optional declared torque in § 1065.510(f)(5)(iii), and the torque on the primary output shaft from any optional declared power in § 1065.510(f)(6).
(ii) Determine the warm-idle-in-neutral speed and torque values with the transmission in neutral from the data collected during the engine mapping procedure in § 1065.510. The warm-idle-in-neutral torque is the sum of any optional declared torque in § 1065.510(f)(5)(iii) and the torque on the primary output shaft from any optional declared power in § 1065.510(f)(6) ( i.e., the sum of the torques representing loads from vehicle accessories).
(iii) Zero-percent speed for denormalization of non-idle points is the warm-idle-in-drive speed.
(iv) For motoring points, make no changes.
(v) If the cycle begins with an idle segment ( i.e., a set of one or more contiguous idle points), set the reference speed and torque values to the warm-idle-in-neutral values for this initial segment. This is to represent idle operation with the transmission in neutral or park at the start of the transient duty cycle, after the engine is started. If the initial idle segment is longer than 24 seconds, change the reference speed and torque values for the remaining idle points in the initial idle segment to the warm-idle-in-drive values ( i.e., change idle points corresponding to 25 seconds to the end of the initial idle segment to warm-idle-in-drive). This is to represent manually shifting the transmission to drive.
(vi) For all other idle segments, set the reference speed and torque values to the warm-idle-in-drive values. This is to represent the transmission operating in drive.
(vii) If the engine is intended primarily for automatic transmissions with a Neutral-When-Stationary feature that automatically shifts the transmission to neutral after the vehicle is stopped for a designated time and automatically shifts back to drive when the operator increases demand ( i.e., pushes the accelerator pedal), reprocess all idle segments. Change reference speed and torque values from the warm-idle-in-drive values to the warm-idle-in-neutral values for idle points in drive after the designated time.
(viii) For all nonidle nonmotoring points with normalized speed at or below zero percent and reference torque from zero to the warm-idle-in-drive torque value, set the reference torque to the warm-idle-in-drive torque value. This is to represent the transmission operating in drive.
(ix) For consecutive nonidle nonmotoring points that immediately follow and precede idle segments, with reference torque values from zero to the warm-idle-in-drive torque value, change their reference torques to the warm-idle-in-drive torque value. This is to represent the transmission operating in drive.
(x) For consecutive nonidle nonmotoring points that immediately follow and precede any point(s) that were modified in paragraph (d)(3)(viii) of this section, with reference torque values from zero to the warm-idle-in-drive torque value, change their reference torques to the warm-idle-in-drive torque value. This is to provide smooth torque transition around these points.
* * * * *
158. Revise § 1065.644 to read as follows:
§ 1065.644
Vacuum-decay leak rate.
This section describes how to calculate the leak rate of a vacuum-decay leak verification, which is described in § 1065.345(e). Use the following equation to calculate the leak rate, , and compare it to the criterion specified in § 1065.345(e):
Eq. 1065.644-1
Where:
V vac = geometric volume of the vacuum-side of the sampling system.
R = molar gas constant.
p 2 = vacuum-side absolute pressure at time t 2.
T 2 = vacuum-side absolute temperature at time t 2.
p 1 = vacuum-side absolute pressure at time t 1.
T 1 = vacuum-side absolute temperature at time t 1.
t 2 = time at completion of vacuum-decay leak verification test.
t 1 = time at start of vacuum-decay leak verification test.
Example:
V vac = 2.0000 L = 0.00200 m ^3
R = 8.314472 J/(mol·K) = 8.314472 (m ^2 ·kg)/(s ^2 ·mol·K)
p 2 = 50.600 kPa = 50600 Pa = 50600 kg/(m·s ^2 )
T 2 = 293.15 K
p 1 = 25.300 kPa = 25300 Pa = 25300 kg/(m·s ^2 )
T 1 = 293.15 K
t 2 = 10:57:35 a.m.
t 1 = 10:56:25 a.m.
159. Amend § 1065.650 by revising paragraph (c)(1)(ii) to read as follows:
§ 1065.650
Emission calculations.
* * * * *
(c) * * *
(1) * * *
(ii) Correct all gaseous emission analyzer concentration readings, including continuous readings, sample bag readings, and dilution air background readings, for drift as described in § 1065.672. Note that you must omit this step where brake-specific emissions are calculated without the drift correction for performing the drift validation according to § 1065.550(b). When applying the initial THC and CH 4 contamination readings according to § 1065.520(g), use the same values for both sets of calculations. You may also use as-measured values in the initial set of calculations and corrected values in the drift-corrected set of calculations as described in § 1065.520(g)(7).
* * * * *
160. Amend § 1065.655 by:
a. Revising the section heading and paragraphs (a), (b)(4), and (e)(1) and (4);
b. Removing the first paragraph (f)(3); and
c. Revising the second paragraph (f)(3).
The revisions read as follows:
§ 1065.655
Carbon-based chemical balances of fuel, DEF, intake air, and exhaust.
(a) General. Chemical balances of fuel, intake air, and exhaust may be used to calculate flows, the amount of water in their flows, and the wet concentration of constituents in their flows. See § 1065.520(f) for information about when to use this carbon-based chemical balance procedure. With one flow rate of either fuel, intake air, or exhaust, you may use chemical balances to determine the flows of the other two. For example, you may use chemical balances along with either intake air or fuel flow to determine raw exhaust flow. Note that chemical balance calculations allow measured values for the flow rate of diesel exhaust fluid for engines with urea-based selective catalytic reduction.
(b) * * *
(4) The amount of water in a raw or diluted exhaust flow, x H2Oexh, when you do not measure the amount of water to correct for the amount of water removed by a sampling system. Note that you may not use the water measurement methods in § 1065.257 to determine x H2Oexh. Correct for removed water according to § 1065.659.
* * * * *
(e) * * *
(1) For liquid fuels, use the default values for α, β,
γ, and δ in table 2 of this section or determine mass fractions of liquid fuels for calculation of α, β,
γ, and δ as follows:
(i) Determine the carbon and hydrogen mass fractions according to ASTM D5291 (incorporated by reference, see § 1065.1010). When using ASTM D5291 to determine carbon and hydrogen mass fractions of gasoline (with or without blended ethanol), use good engineering judgment to adapt the method as appropriate. This may include consulting with the instrument manufacturer on how to test high-volatility fuels. Allow the weight of volatile fuel samples to stabilize for 20 minutes before starting the analysis; if the weight still drifts after 20 minutes, prepare a new sample). Retest the sample if the carbon, hydrogen, oxygen, sulfur, and nitrogen mass fractions do not add up to a total mass of 100 ±0.5%; you may assume oxygen has a zero mass contribution for this specification for diesel fuel and neat (E0) gasoline. You may also assume that sulfur and nitrogen have a zero mass contribution for this specification for all fuels except residual fuel blends.
(ii) Determine oxygen mass fraction of gasoline (with or without blended ethanol) according to ASTM D5599 (incorporated by reference, see § 1065.1010). For all other liquid fuels, determine the oxygen mass fraction using good engineering judgment.
(iii) Determine the nitrogen mass fraction according to ASTM D4629 or ASTM D5762 (incorporated by reference, see § 1065.1010) for all liquid fuels. Select the correct method based on the expected nitrogen content.
(iv) Determine the sulfur mass fraction according to subpart H of this part.
* * * * *
(4) Calculate α, β, γ, and δ as described in this paragraph (e)(4). If your fuel mixture contains fuels other than carbon-containing fuels, then calculate those fuels' mass fractions w C , w H , w O , w S , and w N as described in § 1065.656(d). Calculate α, β, γ, and δ using the following equations:
Eq. 1065.655-20
Eq. 1065.655-21
Eq. 1065.655-22
Eq. 1065.655-23
Where:
N = total number of fuels and injected fluids over the duty cycle.
j = an indexing variable that represents one fuel or injected fluid, starting with j = 1.
m j = the mass flow rate of the fuel or any injected fluid j. For applications using a single fuel and no DEF fluid, set this value to 1. For batch measurements, divide the total mass of fuel over the test interval duration to determine a mass rate.
w Hmeas j = hydrogen mass fraction of fuel or any injected fluid j.
w Cmeas j = carbon mass fraction of fuel or any injected fluid j.
w Omeas j = oxygen mass fraction of fuel or any injected fluid j.
w Smeas j = sulfur mass fraction of fuel or any injected fluid j.
w Nmeas j = nitrogen mass fraction of fuel or any injected fluid j.
Example:
N = 1
j = 1
m 1 = 1
w Hmeas1 = 0.1239
w Cmeas1 = 0.8206
w Omeas1 = 0.0547
w Smeas1 = 0.00066
w Nmeas1 = 0.000095
M C = 12.0107 g/mol
M H = 1.00794 g/mol
M O = 15.9994 g/mol
M S = 32.065 g/mol
M N = 14.0067
* * * * *
(f) * * *
(3) Fluid mass flow rate calculation. This calculation may be used only for steady-state laboratory testing. You may not use this calculation if the standard-setting part requires carbon balance error verification as described in § 1065.543. See § 1065.915(d)(5)(iv) for application to field testing. Calculate based on using the following equation:
Eq. 1065.655-25
Where:
n exh = raw exhaust molar flow rate from which you measured emissions.
j = an indexing variable that represents one fuel or injected fluid, starting with j = 1.
N = total number of fuels and injected fluids over the duty cycle.
m j = the mass flow rate of the fuel or any injected fluid j.
w C j = carbon mass fraction of the fuel and any injected fluid j , as determined in paragraph (d) of this section.
Example:
N = 1
j = 1
m 1 = 7.559 g/s
w C1 = 0.869 g/g
M C = 12.0107 g/mol
x Ccombdry1 = 99.87 mmol/mol = 0.09987 mol/mol
x H20exhdry1 = 107.64 mmol/mol = 0.10764 mol/mol
* * * * *
161. Add § 1065.656 to read as follows:
§ 1065.656
Hydrogen-based chemical balances of fuel, DEF, intake air, and exhaust.
(a) General. Chemical balances of fuel, DEF, intake air, and exhaust may be used to calculate flows, the amount of water in their flows, and the wet concentration of constituents in their flows. See § 1065.520(f) for information about when to use this hydrogen-based chemical balance procedure. With one flow rate of either fuel, intake air, or exhaust, you may use chemical balances to determine the flows of the other two. For example, you may use chemical balances along with either intake air or fuel flow to determine raw exhaust flow. Note that chemical balance calculations allow measured values for the flow rate of diesel exhaust fluid for engines with urea-based selective catalytic reduction.
(b) Procedures that require chemical balances. We require chemical balances when you determine the following:
(1) A value proportional to total work, when you choose to determine brake-specific emissions as described in § 1065.650(f).
(2) Raw exhaust molar flow rate either from measured intake air molar flow rate or from fuel mass flow rate as described in paragraph (f) of this section.
(3) Raw exhaust molar flow rate from measured intake air molar flow rate and dilute exhaust molar flow rate as described in paragraph (g) of this section.
(4) The amount of water in a raw or diluted exhaust flow, x H2Oexh , when you do not measure the amount of water to correct for the amount of water removed by a sampling system. Correct for removed water according to § 1065.659.
(5) The calculated total dilution air flow when you do not measure dilution air flow to correct for background emissions as described in § 1065.667(c) and (d).
(c) Chemical balance procedure. The calculations for a chemical balance involve a system of equations that require iteration. We recommend using a computer to solve this system of equations. You must guess the initial values of two of the following quantities: the amount of hydrogen in the measured flow, x H2exhdry , the fraction of dilution air in diluted exhaust, x dil/exhdry , and the amount of intake air required to produce actual combustion products per mole of dry exhaust, x int/exhdry . You may use time-weighted mean values of intake air humidity and dilution air humidity in the chemical balance; as long as your intake air and dilution air humidities remain within tolerances of ±0.0025 mol/mol of their respective mean values over the test interval. For each emission concentration, x, and amount of water, x H2Oexh , you must determine their completely dry concentrations, x dry and x H2Oexhdry . You must also use your fuel mixture's carbon mass fraction, w C , hydrogen mass fraction, w H , oxygen mass fraction, w O , sulfur mass fraction, w S , and nitrogen mass fraction, w N ; you may optionally account for diesel exhaust fluid (or other fluids injected into the exhaust), if applicable. Calculate w C , w H , w O , w S , and w N as described in paragraphs (d) and (e) of this section. You may alternatively use any combination of default values and measured values as described in paragraphs (d) and (e) of this section. Use the following steps to complete a chemical balance:
(1) Convert your measured concentrations such as x H2meas , x NH3meas , x CO2meas , x COmeas , x THCmeas , x O2meas , x H2meas , x NOmeas , x NO2meas , and x H2Oint , to dry concentrations by dividing them by one minus the amount of water present during their respective measurements; for example: x H2Omeas , x H2OxO2meas , x H2OxNOmeas , and x H2Oint . If the amount of water present during a “wet” measurement is the same as an unknown amount of water in the exhaust flow, x H2Oexh , iteratively solve for that value in the system of equations. If you measure only total NO X and not NO and NO 2 separately, use good engineering judgment to estimate a split in your total NO X concentration between NO and NO 2 for the chemical balances. For example, if you measure emissions from a stoichiometric combustion engine, you may assume all NO X is NO. For a lean-burn combustion engine, you may assume that your molar concentration of NO X , x NOx , is 75% NO and 25% NO 2 . For NO 2 storage aftertreatment systems, you may assume x NOx is 25% NO and 75% NO 2. Note that for calculating the mass of NO X emissions, you must use the molar mass of NO 2 for the effective molar mass of all NO X species, regardless of the actual NO 2 fraction of NO X .
(2) Enter the equations in paragraph (c)(5) of this section into a computer program to iteratively solve for x H2exhdry , x dil/exhdry , and x int/exhdry . Use good engineering judgment to guess initial values for x H2exhdry , x dil/exhdry , and x int/exhdry . We recommend guessing an initial amount of hydrogen of 0 mol/mol. We recommend guessing an initial x int/exhdry of 1 mol/mol. We also recommend guessing an initial x dil/exhdry of 0.8 mol/mol. Iterate values in the system of equations until the most recently updated guesses are all within ±1% or ±1 µmol/mol, whichever is larger, of their respective most recently calculated values.
(3) Use the following symbols and subscripts in the equations for performing the chemical balance calculations in this paragraph (c):
Table 1 to Paragraph ( c )(3) of § 1065.656—Symbols and Subscripts for Chemical Balance Equations
x [emission]meas | Amount of measured emission in the sample at the respective gas analyzer.
x [emission]exh | Amount of emission per dry mole of exhaust.
x [emission]exhdry | Amount of emission per dry mole of dry exhaust.
x H2O[emission]meas | Amount of H 2 O in sample at emission-detection location; measure or estimate these values according to § 1065.145(e)(2).
x Ccombdry | Amount of carbon from fuel and any injected fluids in the exhaust per mole of dry exhaust.
x Hcombdry | Amount of hydrogen from fuel and any injected fluids in the exhaust per mole of dry exhaust.
x dil/exh | Amount of dilution gas or excess air per mole of exhaust.
x dil/exhdry | amount of dilution gas and/or excess air per mole of dry exhaust.
x Hcombdry | Amount of hydrogen from fuel and any injected fluids in the exhaust per mole of dry exhaust.
| x int/exhdry | Amount of intake air required to produce actual combustion products per mole of dry (raw or diluted) exhaust.
x raw/exhdry | Amount of undiluted exhaust, without excess air, per mole of dry (raw or diluted) exhaust.
x CO2int | Amount of intake air CO 2 per mole of intake air.
x CO2intdry | amount of intake air CO 2 per mole of dry intake air; you may use x CO2intdry = 375 µmol/mol, but we recommend measuring the actual concentration in the intake air.
x H2Oint | Amount of H 2 O in the intake air, based on a humidity measurement of intake air.
x H2Ointdry | Amount of intake air H 2 O per mole of dry intake air.
x O2int | Amount of intake air O 2 per mole of intake air.
x CO2dil | Amount of dilution gas CO 2 per mole of dilution gas.
x CO2dildry | Amount of dilution gas CO 2 per mole of dry dilution gas; if you use air as diluent, you may use x CO2dildry = 375 µmol/mol, but we recommend measuring the actual concentration in the dilution gas.
x H2Odil | Amount of dilution gas H 2 O per mole of dilution gas.
x H2Odildry | Amount of dilution gas H 2 O per mole of dry dilution gas.
τ | Effective carbon content of the fuel and any injected fluids.
χ | Effective hydrogen content of the fuel and any injected fluids.
ϕ | Effective oxygen content of the fuel and any injected fluids.
ξ | Effective sulfur content of the fuel and any injected fluids.
ω | Effective nitrogen content of the fuel and any injected fluids.
w C | Carbon mass fraction of the fuel (or mixture of test fuels) and any injected fluids.
w H | Hydrogen mass fraction of the fuel (or mixture of test fuels) and any injected fluids.
w O | Oxygen mass fraction of the fuel (or mixture of test fuels) and any injected fluids.
w S | Sulfur mass fraction of the fuel (or mixture of test fuels) and any injected fluids.
w N | Nitrogen mass fraction of the fuel (or mixture of test fuels) and any injected fluids.
(4) Use the equations specified in this section to iteratively solve for x int/exhdry , x dil/exhdry , and x H2exhdry . The following exceptions apply:
(i) For x H2exhdry multiple equations are provided, see table 2 to paragraph (c)(6) of this section to determine for which cases the equations apply.
(ii) The calculation of x O2exhdry is only required when x O2meas is measured.
(iii) The calculation of x NH3exhdry is only required for engines that use ammonia as fuel and engines that are subject to NH 3 measurement under the standard setting part, for all other engines x NH3exhdry may be set to zero.
(iv) The calculation of x CO2exhdry is only required for engines that use carbon-containing fuels or fluids, either as single fuel or as part of the fuel mixture, and for engines that are subject to CO 2 measurement under the standard setting part, for all other engines x CO2exhdry may be set to a value that yields for x Ccombdry a value of zero. (v) The calculation of x COexhdry and x THCexhdry is only required for engines that use carbon-containing fuels and for engines that are subject to CO and THC measurement under the standard setting part, for all other engines x COexhdry and x THCexhdry may be set to zero. (vi) The calculation of x N2Oexhdry is only required for engines that are subject to N 2 O measurement under the standard setting part, for all other engines x N2Oexhdry may be set to zero.
(5) The chemical balance equations are as follows:
x Ccombdry = x co2exhdry + x coexhdry + x THCexhdry − x co2dil · x dil/exhdry − x co2int · x int/exhdry
Eq. 1065.656-1
Eq. 1065.656-2
Eq. 1065.656-3
Eq. 1065.656-4
Eq. 1065.656-5
Eq. 1065.656-6 (see table 2 of this section)
Eq. 1065.656-7 (see table 2 of this section)
Eq. 1065.656-8
Eq. 1065.656-9
Eq. 1065.656-10
Eq. 1065.656-11
Eq. 1065.656-12
Eq. 1065.656-13
Eq. 1065.656-14
Eq. 1065.656-15
Eq. 1065.656-16 (see table 2 of this section)
Eq. 1065.656-17
Eq. 1065.656-18
Eq. 1065.656-19
Eq. 1065.656-20
Eq. 1065.656-21
Eq. 1065.656-22
Eq. 1065.656-23
(6) Depending on your measurements, use the equations and guess the quantities specified in the following table:
Table 2 to Paragraph ( c )(6) of § 1065.656—Chemical Balance Equations for Different Measurements
When measuring | Guess . . . | Calculate . . .
(i) x O2meas | x int/exhdry and x H2exhdry | (A) x H2exhdry using Eq. 1065.656-7.
| | (B) x O2exhdry using Eq. 1065.656-16.
(ii) x H2meas | x int/exhdry and x dil/exhdry | (A) x H2exhdry using Eq. 1065.656-6.
| | (B) [Reserved].
(7) The following example is a solution for x int/exhdry,
x dil/exhdry, and x HOexhdry using the equations in paragraph (c)(5) of this section:
(d) Mass fractions of fuel. (1) For fuels other than carbon-containing fuels determine the mass fractions of fuel W C , W H , W O , W S , and W N, based on the fuel properties as determined in paragraph (e) of this section. Calculate W C , W H , W O , W S , and W N using the following equations:
Eq. 1065.656-24
Eq. 1065.656-25
Eq. 1065.656-26
Eq. 1065.656-27
Eq. 1065.656-28
Where:
w C = carbon mass fraction of the fuel and any injected fluids.
w H = hydrogen mass fraction of the fuel and any injected fluids.
w O = oxygen mass fraction of the fuel and any injected fluids.
w S = sulfur mass fraction of the fuel and any injected fluids.
w N = nitrogen mass fraction of the fuel and any injected fluids.
τ = effective carbon content of the fuel and any injected fluids.
M C = molar mass of carbon.
χ = effective hydrogen content of the fuel and any injected fluids.
M H = molar mass of hydrogen.
ϕ = effective oxygen content of the fuel and any injected fluids.
M O = molar mass of oxygen.
ξ = effective sulfur content of the fuel and any injected fluids.
M S = molar mass of nitrogen.
ω = effective nitrogen content of the fuel and any injected fluids.
M N = molar mass of nitrogen.
Example for NH 3
fuel:
τ = 0
χ = 3
ϕ = 0
ξ = 0
ω = 1
M C = 12.0107 g/mol
M H = 1.00794 g/mol
M O = 15.9994 g/mol
M S = 32.065 g/mol
M N = 14.0067 g/mol
w C = 0 g/g
w H = 0.1775530 g/g
w O = 0 g/g
w S = 0 g/g
w N = 0.8224470 g/g
(2) For carbon-containing fuels and diesel exhaust fluid determine the mass fractions of fuel, W C , W H , W O , W S , and W N , based on properties determined according to § 1065.655(d). Calculate W C , W H , W O , W S , and W N using the following equations:
Eq. 1065.656-29
Eq. 1065.656-30
Eq. 1065.656-31
Eq. 1065.656-32
Eq. 1065.656-33
Where:
w C = carbon mass fraction of the fuel and any injected fluids.
w H = hydrogen mass fraction of the fuel and any injected fluids.
w O = oxygen mass fraction of the fuel and any injected fluids.
w S = sulfur mass fraction of the fuel and any injected fluids.
w N = nitrogen mass fraction of the fuel and any injected fluids.
M C = molar mass of carbon.
α = atomic hydrogen-to-carbon ratio of the fuel and any injected fluids.
M H = molar mass of hydrogen.
β = atomic oxygen-to-carbon ratio of the fuel and any injected fluids.
M O = molar mass of oxygen.
γ = atomic sulfur-to-carbon ratio of the fuel and any injected fluids.
M S = molar mass of sulfur.
δ = atomic nitrogen-to-carbon ratio of the fuel and any injected fluids.
M N = molar mass of nitrogen.
Example:
α = 1.8
β = 0.05
γ = 0.0003
δ = 0.0001
M C = 12.0107
M H = 1.00794
M O = 15.9994
M S = 32.065
M N = 14.0067
(3) For nonconstant fuel mixtures, you must account for the varying proportions of the different fuels. This paragraph (d)(3) generally applies for dual-fuel and flexible-fuel engines, but optionally it may also be applied if diesel exhaust fluid or other fluids injected into the exhaust are injected in a way that is not strictly proportional to fuel flow. Account for these varying concentrations either with a batch measurement that provides averaged values to represent the test interval, or by analyzing data from continuous mass rate measurements. Application of average values from a batch measurement generally applies to situations where one fluid is a minor component of the total fuel mixture; consistent with good engineering judgment. Calculate W C , W H , W O , W S , and W N of the fuel mixture using the following equations:
Eq. 1065.656-34
Eq. 1065.656-35
Eq. 1065.656-36
Eq. 1065.656-37
Eq. 1065.656-38
Where:
w C = carbon mass fraction of the mixture of test fuels and any injected fluids.
w H = hydrogen mass fraction of the mixture of test fuels and any injected fluids.
w O = oxygen mass fraction of the mixture of test fuels and any injected fluids.
w S = sulfur mass fraction of the mixture of test fuels and any injected fluids.
w N = nitrogen mass fraction of the mixture of test fuels and any injected fluids.
N = total number of fuels and injected fluids over the duty cycle.
j = an indexing variable that represents one fuel or injected fluid, starting with j = 1.
m j = the mass flow rate of the fuel or any injected fluid j. For batch measurements, divide the total mass of fuel over the test interval duration to determine a mass rate.
w Cmeasj = carbon mass fraction of fuel or any injected fluid j.
w Hmeasj = hydrogen mass fraction of fuel or any injected fluid j.
w Omeasj = oxygen mass fraction of fuel or any injected fluid j.
w Smeasj = sulfur mass fraction of fuel or any injected fluid j.
w Nmeasj = nitrogen mass fraction of fuel or any injected fluid j.
Example for a mixture of diesel and NH 3
fuel where diesel represents 15% of energy:
N = 2
m 1 = 0.5352 g/s
m 2 = 7.024 g/s
w Cmeas1 = 0.820628 g/g
w Hmeas1 = 0.123961 g/g
w Omeas1 = 0.0546578 g/g
w Smeas1 = 0.00065725 g/g
w Nmeas1 = 0.0000957004 g/g
w Cmeas2 = 0 g/g
w Hmeas2 = 0.177553 g/g
w Omeas2 = 0 g/g
w Smeas2 = 0 g/g
w Nmeas2 = 0.822447 g/g
w C = 0.0581014 g/g
w H = 0.1737586 g/g
w O = 0.00386983 g/g
w S = 0.0000465341 g/g
w N = 0.76422359 g/g
(e) Fuel and diesel exhaust fluid composition. (1) For carbon-containing fuels and diesel exhaust fluid determine the composition represented by α, β,
γ, and δ, as described in § 1065.655(e).
(2) For fuels other than carbon-containing fuels use the default values for τ, χ,
ϕ, ξ, and ω in table 3 to this section, or use good engineering judgment to determine those values based on measurement. If you determine compositions based on measured values and the default value listed in table 3 to this section is zero, you may set τ, ϕ,
ξ, and ω to zero; otherwise determine τ, ϕ,
ξ, and ω (along with χ ) based on measured values.
(3) If your fuel mixture contains carbon-containing fuels and your testing requires fuel composition values referencing carbon, calculate α, β,
γ, and δ for the fuel mixture as described in § 1065.655(e)(4).
(4) Table 3 to this paragraph (e)(4) follows:
Table 3 to Paragraph ( e )(4) of § 1065.656—Default Values of τ , χ , ϕ , ξ , and ω
Fuel | Atomic carbon, oxygen, and nitrogen-to-hydrogen ratios C τ H> χ O ϕ S ξ N ω
Hydrogen | C 0 H 2 O 0 S 0 N 0 .
Ammonia | C 0 H 3 O 0 S 0 N 1 .
(f) Calculated raw exhaust molar flow rate from measured intake air molar flow rate or fuel mass flow rate. You may calculate the raw exhaust molar flow rate from which you sampled emissions, , based on the measured intake air molar flow rate, , or the measured fuel mass flow rate, , and the values calculated using the chemical balance in paragraph (c) of this section. The chemical balance must be based on raw exhaust gas concentrations. Solve for the chemical balance in paragraph (c) of this section at the same frequency that you update and record or . For laboratory tests, calculating raw exhaust molar flow rate using measured fuel mass flow rate is valid only for steady-state testing. See § 1065.915(d)(5)(iv) for application to field testing.
(1) Crankcase flow rate. If engines are not subject to crankcase controls under the standard-setting part, you may calculate raw exhaust flow based on or using one of the following:
(i) You may measure flow rate through the crankcase vent and subtract it from the calculated exhaust flow.
(ii) You may estimate flow rate through the crankcase vent by engineering analysis as long as the uncertainty in your calculation does not adversely affect your ability to show that your engines comply with applicable emission standards.
(iii) You may assume your crankcase vent flow rate is zero.
(2) Intake air molar flow rate calculation. Calculate n based on using the following equation:
Eq. 1065.656-39
Where:
n exh = raw exhaust molar flow rate from which you measured emissions.
n int = intake air molar flow rate including humidity in intake air.
Example:
n int = 3.780 mol/s
x int/exhdry = 0.69021 mol/mol
x raw/exhdry = 1.10764 mol/mol
x H20exhdry = 107.64 mmol/mol = 0.10764 mol/mol
(3) Fluid mass flow rate calculation. This calculation may be used only for steady-state laboratory testing. See § 1065.915(d)(5)(iv) for application to field testing. Calculate based on using the following equation:
Eq. 1065.656-40
Where:
n exh = raw exhaust molar flow rate from which you measured emissions.
j = an indexing variable that represents one fuel or injected fluid, starting with j = 1.
N = total number of fuels and injected fluids over the duty cycle.
m j = the mass flow rate of the fuel or any injected fluid j.
w Cj = carbon mass fraction of the fuel (or mixture of test fuels) and any injected fluid j.
w Hj = hydrogen mass fraction of the fuel (or mixture of test fuels) and any injected fluid j.
Example:
x H20exhdry1 = 312.013 mmol/mol = 0.10764 mol/mol
M C = 12.0107 g/mol
M H = 1.00794 g/mol
x Ccombdry1 = 6.45541 mmol/mol = 0.00645541 mol/mol
x Hcombdry1 = 641.384 mmol/mol = 0.641384 mol/mol
m 1 = 0.167974 g/s
m 2 = 7.39103 g/s
w C1 = 0.820628 g/g
w C2 = 0 g/g
w H1 = 0.123961 g/g
w H2 = 0.177553 g/g
N = 2
(g) Calculated raw exhaust molar flow rate from measured intake air molar flow rate, dilute exhaust molar flow rate, and dilute chemical balance. You may calculate the raw exhaust molar flow rate, n exh , based on the measured intake air molar flow rate, n int , the measured dilute exhaust molar flow rate, n dexh , and the values calculated using the chemical balance in paragraph (c) of this section. Note that the chemical balance must be based on dilute exhaust gas concentrations. For continuous-flow calculations, solve for the chemical balance in paragraph (c) of this section at the same frequency that you update and record n int and n dexh . This calculated n dexh may be used for the PM dilution ratio verification in § 1065.546; the calculation of dilution air molar flow rate in the background correction in § 1065.667; and the calculation of mass of emissions in § 1065.650(c) for species that are measured in the raw exhaust.
(1) Crankcase flow rate. If engines are not subject to crankcase controls under the standard-setting part, calculate raw exhaust flow as described in paragraph (f)(1) of this section.
(2) Dilute exhaust and intake air molar flow rate calculation. Calculate as follows:
n exh = ( x raw/exhdry − x int/exhdry ) · (1 − x H20exh ) · n dexh + n int
Eq. 1065.656-41
Example:
n int = 7.930 mol/s
x raw/exhdry = 0.1544 mol/mol
x int/exhdry = 0.1451 mol/mol
x H20exhdry = 32.46 mmol/mol = 0.03246 mol/mol
n dexh = 49.02 mol/s
n exh = (0.1544 − 0.1451) · (1 − 0.03246) · 49.02 + 7.930 = 0.4411 + 7.930 = 8.371 mol/s
162. Revise and republish § 1065.660 to read as follows:
§ 1065.660
THC, NMHC, NMNEHC, CH 4 , and C 2 H 6 determination.
(a) THC determination and initial THC/CH 4
contamination corrections. (1) If we require you to determine THC emissions, calculate x THC[THC-FID]cor using the initial THC contamination concentration x THC[THC-FID]init from § 1065.520 as follows:
x
THC[THC-FID]cor
=
x
THC[THC-FID]uncor
−
x
THC[THC-FID]init
Eq. 1065.660-1
Example:
x THCuncor = 150.3 µmol/mol
x THCinit = 1.1 µmol/mol
x THCcor = 150.3—1.1
x THCcor = 149.2 µmol/mol
(2) For the NMHC determination described in paragraph (b) of this section, correct x THC[THC-FID] for initial THC contamination using Eq. 1065.660-1. You may correct x THC[NMC-FID] for initial contamination of the CH 4 sample train using Eq. 1065.660-1, substituting in CH 4 concentrations for THC.
(3) For the NMNEHC determination described in paragraph (c) of this section, correct x THC[THC-FID] for initial THC contamination using Eq. 1065.660-1. You may correct x THC[NMC-FID] for initial contamination of the CH 4 sample train using Eq. 1065.660-1, substituting in CH 4 concentrations for THC.
(4) For the CH 4 determination described in paragraph (d) of this section, you may correct x THC[NMC-FID] for initial THC contamination of the CH 4 sample train using Eq. 1065.660-1, substituting in CH 4 concentrations for THC.
(5) You may calculate THC as the sum of NMHC and CH 4 if you determine CH 4 with an FTIR as described in paragraph (d)(2) of this section and NMHC with an FTIR using the additive method from paragraph (b)(4) of this section.
(6) You may calculate THC as the sum of NMNEHC, C 2 H 6 , and CH 4 if you determine CH 4 with an FTIR as described in paragraph (d)(2) of this section, C 2 H 6 with an FTIR as described in paragraph (e) of this section, and NMNEHC with an FTIR using the additive method from paragraph (c)(3) of this section.
(b) NMHC determination. Use one of the following to determine NMHC concentration, x NMHC :
(1) If you do not measure CH 4 , you may omit the calculation of NMHC concentrations and calculate the mass of NMHC as described in § 1065.650(c)(5).
(2) For an NMC, calculate x NMHC using the NMC's penetration fractions, response factors, and/or combined penetration fractions and response factors as described in § 1065.365, the THC FID's CH 4 response factor, RF CH4[THC-FID], from § 1065.360, the initial THC contamination and dry-to-wet corrected THC concentration, x THC[THC-FID]cor, as determined in paragraph (a) of this section, and the dry-to-wet corrected CH 4 concentration, x THC[NMC-FID]cor, optionally corrected for initial THC contamination as determined in paragraph (a) of this section.
(i) Use the following equation for an NMC configured as described in § 1065.365(d):
Eq. 1065.660-2
Where:
x NMHC = concentration of NMHC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.
x THC[NMC-FID]cor = concentration of THC, initial THC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.
RF CH4[THC-FID] = response factor of THC FID to CH 4, according to § 1065.360(d).
RFPF C2H6[NMC-FID] = NMC combined C 2 H 6 response factor and penetration fraction, according to § 1065.365(d).
RFPF CH4[NMC-FID] = NMC combined CH 4 response factor and penetration fraction, according to § 1065.365(d).
Example:
x THC[THC-FID]cor = 150.3 µmol/mol
x THC[NMC-FID]cor = 20.5 µmol/mol
RFPF C2H6[NMC-FID] = 0.019
RFPF CH4[NMC-FID] = 1.000
RF CH4[THC-FID] = 1.05
(ii) Use the following equation for penetration fractions determined using an NMC configuration as outlined in § 1065.365(e):
Eq. 1065.660-3
Where:
x NMHC = concentration of NMHC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.
PF CH4[NMC-FID] = NMC CH 4 penetration fraction, according to § 1065.365(e).
x THC[NMC-FID]cor = concentration of THC, initial THC contamination (optional) and dry-to-wet corrected, as measured by the THC FID during sampling through the NMC.
PF C2H6[NMC-FID] = NMC C 2 H 6 penetration fraction, according to § 1065.365(e).
Example:
x THC[THC-FID]cor = 150.3 µmol/mol
PF CH4[NMC-FID] = 0.990
x THC[NMC-FID]cor = 20.5 µmol/mol
PF C2H6[NMC-FID] = 0.020
(iii) Use the following equation for an NMC configured as described in § 1065.365(f):
Eq. 1065.660-4
Where:
x NMHC = concentration of NMHC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.
PF CH4[NMC-FID] = NMC CH 4 penetration fraction, according to § 1065.365(f).
x THC[NMC-FID]cor = concentration of THC, initial THC contamination (optional) and dry-to-wet corrected, as measured by the THC FID during sampling through the NMC.
RFPF C2H6[NMC-FID] = NMC combined C 2 H 6 response factor and penetration fraction, according to § 1065.365(f).
RF CH4[THC-FID] = response factor of THC FID to CH 4, according to § 1065.360(d).
Example:
x THC[THC-FID]cor = 150.3 µmol/mol
PF CH4[NMC-FID] = 0.990
x THC[NMC-FID]cor = 20.5 µmol/mol
RFPF C2H6[NMC-FID] = 0.019
RF CH4[THC-FID] = 0.980
(3) For a GC-FID or FTIR, calculate x NMHC using the THC analyzer's CH 4 response factor, RF CH4[THC-FID], from § 1065.360, and the initial THC contamination and dry-to-wet corrected THC concentration, x THC[THC-FID]cor, as determined in paragraph (a) of this section as follows:
χ NMHC = χ THC[THC-FID]cor − RF CH4[THC-FID] · χ CH4
Eq. 1065.660-5
Where:
x NMHC = concentration of NMHC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID.
RF CH4[THC-FID] = response factor of THC-FID to CH 4.
x CH4 = concentration of CH 4, dry-to-wet corrected, as measured by the GC-FID or FTIR.
Example:
x THC[THC-FID]cor = 145.6 µmol/mol
RF CH4[THC-FID] = 0.970
x CH4 = 18.9 µmol/mol
x NMHC = 145.6—0.970 · 18.9
x NMHC = 127.3 µmol/mol
(4) For an FTIR, calculate x NMHC by summing the hydrocarbon species listed in § 1065.266(c) as follows:
Eq. 1065.660-6
Where:
x NMHC = concentration of NMHC.
x HCi = the C 1 -equivalent concentration of hydrocarbon species i as measured by the FTIR, not corrected for initial contamination.
x HCi-init = the C 1 -equivalent concentration of the initial system contamination (optional) of hydrocarbon species i, dry-to-wet corrected, as measured by the FTIR.
Example:
x C2H6 = 4.9 µmol/mol
x C2H4 = 0.9 µmol/mol
x C2H2 = 0.8 µmol/mol
x C3H8 = 0.4 µmol/mol
x C3H6 = 0.5 µmol/mol
x C4H10 = 0.3 µmol/mol
x CH2O = 0.8 µmol/mol
x C2H4O = 0.3 µmol/mol
x CH2O2 = 0.1 µmol/mol
x CH4O = 0.1 µmol/mol
x NMHC = 4.9 + 0.9 + 0.8 + 0.4 + 0.5 + 0.3 + 0.8 + 0.3 + 0.1 + 0.1
x NMHC = 9.1 µmol/mol
(c) NMNEHC determination. Use one of the following methods to determine NMNEHC concentration, x NMNEHC :
(1) Calculate x NMNEHC based on the test fuel's ethane content as follows:
(i) If the content of your test fuel contains less than 0.010 mol/mol of ethane, you may omit the calculation of NMNEHC concentration and calculate the mass of NMNEHC as described in § 1065.650(c)(6)(i).
(ii) If the content of your fuel test contains at least 0.010 mol/mol of C 2 H 6 , you may omit the calculation of NMNEHC concentration and calculate the mass of NMNEHC as described in § 1065.650(c)(6)(ii).
(2) For a GC-FID, NMC FID, or FTIR, calculate x NMNEHC using the THC analyzer's CH 4 response factor, RF CH4[THC-FID], and C 2 H 6 response factor, RF C2H6[THC-FID], from § 1065.360, the initial contamination and dry-to-wet corrected THC concentration, x THC[THC-FID]cor, as determined in paragraph (a) of this section, the dry-to-wet corrected CH 4 concentration, x CH4, as determined in paragraph (d) of this section, and the dry-to-wet corrected C 2 H 6 concentration, x C2H6, as determined in paragraph (e) of this section as follows:
x NMNEHC = x THC[THC-FID}cor − RF CH4{THC-FID} . x CH4 − RF C2H6{THC-FID] . x C2H6

Eq. 1065.660-7
Where:
x NMNEHC = concentration of NMNEHC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID.
RF CH4[THC-FID] = response factor of THC-FID to CH 4.
x CH4 = concentration of CH 4, dry-to-wet corrected, as measured by the GC-FID, NMC FID, or FTIR.
RF C2H6[THC-FID] = response factor of THC-FID to C 2 H 6.
x C2H6 = the C 1 -equivalent concentration of C 2 H 6, dry-to-wet corrected, as measured by the GC-FID or FTIR.
Example:
x THC[THC-FID]cor = 145.6 µmol/mol
RF CH4[THC-FID] = 0.970
x CH4 = 18.9 µmol/mol
RF C2H6[THC-FID] = 1.02
x C2H6 = 10.6 µmol/mol
x NMNEHC = 145.6 − 0.970 · 18.9 − 1.02 · 10.6
x NMNEHC = 116.5 µmol/mol
(3) For an FTIR, calculate x NMNEHC by summing the hydrocarbon species listed in § 1065.266(c) as follows:

Eq. 1065.660-8
Where:
x NMNEHC = concentration of NMNEHC.
x HC i = the C 1 -equivalent concentration of hydrocarbon species i as measured by the FTIR, not corrected for initial contamination.
x HC i -init = the C 1 -equivalent concentration of the initial system contamination (optional) of hydrocarbon species i, dry-to-wet corrected, as measured by the FTIR.
Example:
x C2H4 = 0.9 µmol/mol
x C2H2 = 0.8 µmol/mol
x C3H8 = 0.4 µmol/mol
x C3H6 = 0.5 µmol/mol
x C4H10 = 0.3 µmol/mol
x CH2O = 0.8 µmol/mol
x C2H4O = 0.3 µmol/mol
x CH2O2 = 0.1 µmol/mol
x CH4O = 0.1 µmol/mol
x NMNEHC = 0.9 + 0.8 + 0.4 + 0.5 + 0.3 + 0.8 + 0.3 + 0.1 + 0.1
x NMNEHC = 4.2 µmol/mol
(d) CH 4 determination. Use one of the following methods to determine methane (CH 4 ) concentration, x CH4 :
(1) For an NMC, calculate x CH4 using the NMC's penetration fractions, response factors, and/or combined penetration fractions and response factors as described in § 1065.365, the THC FID's CH 4 response factor, RF CH4[THC-FID], from § 1065.360, the initial THC contamination and dry-to-wet corrected THC concentration, x THC[THC-FID]cor, as determined in paragraph (a) of this section, and the dry-to-wet corrected CH 4 concentration, x THC[NMC-FID]cor, optionally corrected for initial THC contamination as determined in paragraph (a) of this section.
(i) Use the following equation for an NMC configured as described in § 1065.365(d):

Eq. 1065.660-9
Where:
x CH4 = concentration of CH 4 .
x THC[NMC-FID]cor = concentration of THC, initial THC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.
RFPF C2H6[NMC-FID] = NMC combined C 2 H 6 response factor and penetration fraction, according to § 1065.365(d).
RF CH4[THC-FID] = response factor of THC FID to CH 4, according to § 1065.360(d).
RFPF CH4[NMC-FID] = NMC combined CH 4 response factor and penetration fraction, according to § 1065.365(d).
Example:
x THC[NMC-FID]cor = 10.4 µmol/mol
x THC[THC-FID]cor = 150.3 µmol/mol
RFPF C2H6[NMC-FID] = 0.019
RFPF CH4[NMC-FID] = 1.000
RF CH4[THC-FID] = 1.05
(ii) Use the following equation for an NMC configured as described in § 1065.365(e):

Eq. 1065.660-10
Where:
x CH4 = concentration of CH 4.
x THC[NMC-FID]cor = concentration of THC, initial THC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.
PF C2H6[NMC-FID] = NMC C 2 H 6 penetration fraction, according to § 1065.365(e).
RF CH4[THC-FID] = response factor of THC FID to CH 4, according to § 1065.360(d).
PF CH4[NMC-FID] = NMC CH 4 penetration fraction, according to § 1065.365(e).
Example:
x THC[NMC-FID]cor = 10.4 µmol/mol
x THC[THC-FID]cor = 150.3 µmol/mol
PF C2H6[NMC-FID] = 0.020
RF CH4[THC-FID] = 1.05
PF CH4[NMC-FID] = 0.990
(iii) Use the following equation for an NMC configured as described in § 1065.365(f):

Eq. 1065.660-11
Where:
x CH4 = concentration of CH 4.
x THC[NMC-FID]cor = concentration of THC, initial THC contamination (optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.
x THC[THC-FID]cor = concentration of THC, initial THC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.
RFPF C2H6[NMC-FID] = the combined C 2 H 6 response factor and penetration fraction of the NMC, according to § 1065.365(f).
PF CH4[NMC-FID] = NMC CH 4 penetration fraction, according to § 1065.365(f).
RF CH4[THC-FID] = response factor of THC FID to CH 4, according to § 1065.360(d).
Example:
x THC[NMC-FID]cor = 10.4 µmol/mol
x THC[THC-FID]cor = 150.3 µmol/mol
RFPF C2H6[NMC-FID] = 0.019
PF CH4[NMC-FID] = 0.990
RF CH4[THC-FID] = 1.05
(2) For a GC-FID or FTIR, x CH4 is the actual dry-to-wet corrected CH 4 concentration as measured by the analyzer.
(e) C 2 H 6 determination. For a GC-FID or FTIR, x C2H6 is the C 1 -equivalent, dry-to-wet corrected C 2 H 6 concentration as measured by the analyzer.
163. Amend § 1065.670 by revising paragraphs (a) introductory text and (b) introductory text to read as follows:
§ 1065.670
NO X intake-air humidity and temperature corrections.
* * * * *
(a) For compression-ignition engines operating on carbon-containing fuels and lean-burn combustion engines operating on fuels other than carbon-containing fuels, correct for intake-air humidity using the following equation:
* * * * *
(b) For spark-ignition engines operating on carbon-containing fuels and stoichiometric combustion engines operating on fuels other than carbon-containing fuels, correct for intake-air humidity using the following equation:
* * * * *
164. Amend § 1065.672 by revising paragraph (c) to read as follows:
§ 1065.672
Drift correction.
* * * * *
(c) Drift validation. After applying all the other corrections—except drift correction—to all the gas analyzer signals, calculate emissions according to § 1065.650. Then correct all gas analyzer signals for drift according to this section. Recalculate emissions using all of the drift-corrected gas analyzer signals. Validate and report the emission results before and after drift correction according to § 1065.550.
* * * * *
165. Amend § 1065.695 by:
a. Redesignating paragraphs (c)(9)(v) through (vii) as paragraphs (c)(9)(vi) through (viii); and
b. Adding new paragraph (c)(9)(v).
The addition reads as follows:
§ 1065.695
Data requirements.
* * * * *
(c) * * *
(9) * * *
(v) Chemical balance method—carbon-based or hydrogen-based chemical balance method.
* * * * *
166. Amend § 1065.705 by revising paragraph (b) to read as follows:
§ 1065.705
Residual and intermediate residual fuel.
* * * * *
(b) The fuel must be free of used lubricating oil. Demonstrate this by showing that the fuel meets at least one of the following specifications.
(1) Zinc is at or below 15 mg per kg of fuel based on the procedures specified in IP—470, IP—501, or ISO 8217 (incorporated by reference, see § 1065.1010).
(2) Phosphorus is at or below 15 mg per kg of fuel based on the procedures specified in IP—500, IP—501, or ISO 8217 (incorporated by reference, see § 1065.1010).
(3) Calcium is at or below 30 mg per kg of fuel based on the procedures specified in IP—470, IP—501, or ISO 8217 (incorporated by reference, see § 1065.1010).
* * * * *
167. Amend § 1065.715 in paragraph (a), table 1, by revising footnote “a” to read as follows:
§ 1065.715
Natural gas.
(a) * * *
Table 1 of § 1065.715—Test Fuel Specifications for Natural Gas
Property | Value ^a
* * * * * * *
^a Demonstrate compliance with fuel specifications based on the reference procedures in ASTM D1945 (incorporated by reference, see § 1065.1010), or on other measurement procedures using good engineering judgment.
* * * * *
168. Amend § 1065.750 by revising paragraphs (a)(1)(ii), (a)(2)(i), (a)(3) introductory text, and (a)(3)(xiii) and adding paragraph (a)(6) to read as follows:
§ 1065.750
Analytical gases.
* * * * *
(a) * * *
(1) * * *
(ii) Contamination as specified in the following table:
Table 1 to Paragraph ( a )(1)( ii ) of § 1065.750-General Specifications for Purified Gases ^a
Constituent | Purified Air | Purified N 2
THC (C 1 -equivalent) | ≤ 0.05 μmol/mol | ≤ 0.05 μmol/mol
CO | ≤ 1 μmol/mol | ≤ 1 μmol/mol
CO 2 | ≤ 10 μmol/mol | ≤ 10 μmol/mol
O 2 | 0.205 to 0.215 mol/mol | ≤ 2 μmol/mol
NO X | ≤ 0.02 μmol/mol | ≤ 0.02 μmol/mol
N 2 O ^b | ≤ 0.02 μmol/mol | ≤ 0.02 μmol/mol
H 2 ^c | ≤ 1 μmol/mol | ≤ 1 μmol/mol
NH 3 ^d | ≤ 1 μmol/mol | ≤ 1 μmol/mol
H 2 O ^e | ≤ 5 μmol/mol | ≤ 5 μmol/mol
^a We do not require these levels of purity to be NIST-traceable.
^b The N 2 O limit applies only if the standard-setting part requires you to report N 2 O or certify to an N 2 O standard.
^c The H 2 limit only applies for testing with H 2 fuel.
^d The NH 3 limit only applies for testing with NH 3 fuel.
^e The H 2 O limit only applies for water measurement according to § 1065.257.
(2) * * *
(i) FID fuel. Use FID fuel with a stated H 2 concentration of (0.39 to 0.41) mol/mol, balance He or N 2 , and a stated total hydrocarbon concentration of 0.05 μmol/mol or less. For GC-FIDs that measure methane (CH 4 ) using a FID fuel that is balance N 2 , perform the CH 4 measurement as described in SAE J1151 (incorporated by reference, see § 1065.1010).
* * * * *
(3) Use the following gas mixtures, with gases traceable within ±1% of the NIST-accepted gas standard value or other gas standards we approve:
* * * * *
(xiii) CH 4 , CH 2 O 2 , C 2 H 2 , C 2 H 4 , C 2 H 4 O, C 2 H 6 , C 3 H 8 , C 3 H 6 , CH 4 O, and C 4 H 10 . You may omit individual gas constituents from this gas mixture. If your gas mixture contains oxygenated hydrocarbons, your gas mixture must be in balance purified N 2 , otherwise you may use balance purified air.
* * * * *
(6) If you measure H 2 O using an FTIR analyzer, generate H 2 O calibration gases with a humidity generator using one of the options in this paragraph (a)(6). Use good engineering judgment to prevent condensation in the transfer lines, fittings, or valves from the humidity generator to the FTIR analyzer. Design your system so the wall temperatures in the transfer lines, fittings, and valves from the point where the mole fraction of H 2 O in the humidified calibration gas, x H2Oref , is measured to the analyzer are at a temperature of (110 to 202) °C. Calibrate the humidity generator upon initial installation, within 370 days before verifying the H 2 O measurement of the FTIR, and after major maintenance. Use the uncertainties from the calibration of the humidity generator's measurements and follow NIST Technical Note 1297 (incorporated by reference, see § 1065.1010) to verify that the amount of H 2 O in the calibration gas, x H2Oref , is determined within ±3% uncertainty, U xH2O . If the humidity generator requires assembly before use, after assembly follow the instrument manufacturer's instructions to check for leaks. You may generate the H 2 O calibration gas using one of the following options:
(i) Bubble gas that meets the requirements of paragraph (a)(1) of this section through distilled H 2 O in a sealed vessel. Adjust the amount of H 2 O in the calibration gas by changing the temperature of the H 2 O in the sealed vessel. Determine absolute pressure, p abs , and dewpoint, T dew , of the humidified gas leaving the sealed vessel. Calculate the amount of H 2 O in the calibration gas as described in § 1065.645(a) and (b). Calculate the uncertainty of the amount of H 2 O in the calibration gas, U xH2O , using the following equations:

Eq. 1065.750-1

Eq. 1065.750-2

Eq. 1065.750-3
Where:
T dew = saturation temperature of water at measured conditions.
U T dew = expanded uncertainty (k = 2) of the measured saturation temperature of water at measured conditions.
p abs = wet static absolute pressure at the location of the dewpoint measurement.
U Pabs = expanded uncertainty (k = 2) of the wet static absolute pressure at the location of the dewpoint measurement.
Example:
T dew = 39.5 °C = 312.65 K
U T dew = 0.390292 K
p abs = 99.980 kPa
U Pabs = 1.15340 kPa
Using Eq. 1065.645-1,
x H2O = 0.0718436 mol/mol
(ii) Use a device that introduces a measured flow of distilled H 2 O as vapor into a measured flow of gas that meets the requirements of paragraph (a)(1) of this section. Determine the molar flows of gas and H 2 O that are mixed to generate the calibration gas.
(A) Calculate the amount of H 2 O in the calibration gas as follows:

Eq. 1065.750-4
(B) Calculate the uncertainty of the amount of H 2 O in the generated calibration gas, U xH2O, using the following equations:

Eq. 1065.750-5

Eq. 1065.750-6

Eq. 1065.750-7
Where:
n gas = molar flow of gas entering the humidity generator.
U n gas = expanded uncertainty (k=2) of the molar flow of gas entering the humidity generator.
n H2O = molar flow of H 2 O entering the humidity generator, mol/s.
U n H2O = expanded uncertainty (k=2) of the molar flow of H2O entering the humidity generator.
x H2O = amount of H 2 O in the calibration gas.
U x H2O = expanded uncertainty (k=2) of the amount of H 2 O in the generated calibration gas.
(C) The following example is a solution for using the equations in paragraph (a)(6)(ii)(B) of this section:
n H2O = 0.00138771 mol/s
U n gas = 0.000226137 mol/s
n gas = 0.0148680 mol/s
U n H2O = 0.0000207436 mol/s
* * * * *
169. Amend § 1065.805 by revising paragraph (f) to read as follows:
§ 1065.805
Sampling system.
* * * * *
(f) You may sample alcohols or carbonyls using “California Non-Methane Organic Gas Test Procedures” (incorporated by reference, see § 1065.1010). If you use this method, follow its calculations to determine the mass of the alcohol/carbonyl in the exhaust sample, but follow subpart G of this part for all other calculations (40 CFR part 1066, subpart G, for vehicle testing).
* * * * *
170. Amend § 1065.935 by revising paragraph (g)(5)(ii) to read as follows:
§ 1065.935
Emission test sequence for field testing.
* * * * *
(g) * * *
(5) * * *
(ii) Invalidate any data for periods in which the CO and CO 2 gas analyzers do not meet the drift criterion in § 1065.550. For HC, invalidate data if the difference between the uncorrected and the corrected brake-specific HC emission values are not within ±10% of the uncorrected results or the applicable standard, whichever is greater. For data that do meet the drift criterion, correct the data for drift according to § 1065.672 and use the drift-corrected results in emissions calculations.
* * * * *
171. Amend § 1065.1001 by:
a. Adding a definition of “Carbon-containing fuel” in alphabetical order;
b. Revising the definition for “HEPA filter”;
c. Adding definitions of “Lean-burn engine” and “Neat” in alphabetical order; and
b. Revising the definitions of “NIST-traceable” and “Rechargeable Energy Storage System (RESS)”.
The additions and revisions read as follows:
§ 1065.1001
Definitions.
* * * * *
Carbon-containing fuel means an engine fuel that is characterized by compounds containing carbon. For example, gasoline, diesel, alcohol, liquefied petroleum gas, and natural gas are carbon-containing fuels.
* * * * *
HEPA filter means high-efficiency particulate air filters that are rated to achieve a minimum initial particle-removal efficiency of 99.97% using ASTM F1471 (incorporated by reference, see § 1065.1010).
* * * * *
Lean-burn engine means an engine with a nominal air fuel ratio substantially leaner than stoichiometric. For example, diesel-fueled engines are typically lean-burn engines, and gasoline-fueled engines are lean-burn engines if they have an air-to-fuel mass ratio above 14.7:1.
* * * * *
Neat means fuel that is free from mixture or dilution with other fuels. For example, hydrogen or natural gas fuel used without diesel pilot fuel are neat.
* * * * *
NIST-traceable means relating to a standard value that can be related to NIST-stated references through an unbroken chain of comparisons, all having stated uncertainties, as specified in NIST Technical Note 1297 (incorporated by reference, see § 1065.1010). Allowable uncertainty limits specified for NIST-traceability refer to the propagated uncertainty specified by NIST.
* * * * *
Rechargeable Energy Storage System (RESS) means engine or equipment components that store recovered energy for later use to propel the vehicle or accomplish a different primary function. Examples of RESS include the battery system or a hydraulic accumulator in a hybrid vehicle.
* * * * *
172. Amend § 1065.1010 by revising paragraphs (a)(40) and (e)(2) to read as follows:
§ 1065.1010
Incorporation by reference.
* * * * *
(a) * * *
(40) ASTM D6348-12 ^{ε1} , Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, approved February 1, 2012 (“ASTM D6348”), IBR approved for §§ 1065.257(b), 1065.266(c), 1065.275(b), and 1065.277(b).
* * * * *
(e) * * *
(2) NIST Technical Note 1297, 1994 Edition, Guidelines for Evaluating and Expressing the Uncertainty of NIST Measurement Results, IBR approved for §§ 1065.365(g), 1065.750(a), and 1065.1001.
* * * * *
173. Revise § 1065.1137 to read as follows:
§ 1065.1137
Determination of thermal reactivity coefficient.
This section describes the method for determining the thermal reactivity coefficient(s) used for thermal heat load calculation in the accelerated aging protocol.
(a) The calculations for thermal degradation are based on the use of an Arrhenius rate law function to model cumulative thermal degradation due to heat exposure. Under this model, the thermal aging rate constant, k, is an exponential function of temperature which takes the form shown in the following equation:

Eq. 1065.1137-1
Where:
A = frequency factor or pre-exponential factor.
E a = thermal reactivity coefficient.
R = molar gas constant.
T = catalyst temperature.
(b) The process of determining E a begins with determining what catalyst characteristic will be tracked as the basis for measuring thermal deactivation. This metric varies for each type of catalyst and may be determined from the experimental data using good engineering judgment. We recommend the following metrics; however, you may also use a different metric based on good engineering judgment:
(1) Copper-based zeolite SCR. Total ammonia (NH 3 ) storage capacity is a key aging metric for copper-zeolite SCR catalysts, and they typically contain multiple types of storage sites. It is typical to model these catalysts using two different storage sites, one of which is more active for NO X reduction, as this has been shown to be an effective metric for tracking thermal aging. In this case, there are two recommended aging metrics:
(i) The ratio between the storage capacity of the two sites, with more active site being in the denominator.
(ii) Storage capacity of the more active site.
(2) Iron-based zeolite SCR. Total NH 3 storage capacity is a key aging metric for iron-zeolite SCR catalysts. Using a single storage site is the recommended metric for tracking thermal aging.
(3) Vanadium SCR. Brunauer-Emmett-Teller (BET) theory for determination of surface area is a key aging metric for vanadium-based SCR catalysts. Total NH 3 storage capacity may also be used as a surrogate to probe the surface area. If you use NH 3 storage to probe surface area, using a single storage site is the recommended metric for tracking thermal aging. You may also use low temperature NO X conversion as a metric. If you choose this option, you may be limited in your choice of temperatures for the experiment described in paragraph (c)(1) of this section due to vanadium volatility. In that case, it is possible that you may need to run a longer experimental duration than the recommended 64 hours to reach reliably measurable changes in NO X conversion.
(4) Zone-coated zeolite SCR. This type of catalyst is zone coated with both copper- and iron-based zeolite. As noted in paragraphs (b)(1) and (2) of this section, total NH 3 storage capacity is a key aging metric, and each zone must be evaluated separately.
(5) Diesel oxidation catalysts. The key aging metric for tracking thermal aging for DOCs which are used to optimize exhaust characteristics for a downstream SCR system is the conversion rate of NO to NO 2 . Select a conversion rate temperature less than or equal to 200 °C using good engineering judgement. The key aging metric for DOCs, which are part of a system that does not contain an SCR catalyst for NO X reduction, is the HC reduction efficiency (as measured using ethylene). Select a conversion rate temperature less than or equal to 200 °C using good engineering judgement. This same guidance applies to an oxidation catalyst coated onto the surface of a DPF, if there is no other DOC in the system.
(c)(1) Use good engineering judgment to select at least three different temperatures to complete the degradation experiments. We recommend selecting these temperatures to accelerate thermal deactivation such that measurable changes in the aging metric can be observed at multiple time points over the course of no more than 64 hours. Avoid temperatures that are too high to prevent rapid catalyst failure by a mechanism that does not represent normal aging. An example of temperatures to run the degradation experiment at for a small-pore copper zeolite SCR catalyst is 600 °C, 650 °C, and 725 °C.
(2) For each aging temperature selected, perform testing to assess the aging metric at different times. These time intervals do not need to be evenly spaced and it is typical to complete these experiments using increasing time intervals ( e.g., after 2, 4, 8, 16, and 32 hours). Use good engineering judgment to stop each temperature experiment after sufficient data has been generated to characterize the shape of the deactivation behavior at a given temperature.
(i) For SCR-based NH 3 storage capacity testing, perform a Temperature Programmed Desorption (TPD) following NH 3 saturation of the catalyst ( i.e., ramping gas temperature from 200 to 550 °C) to quantify total NH 3 released during the TPD.
(ii) For DOC formulations, conduct an NO Reverse Light Off (RLO) to quantify oxidation conversion efficiency of NO to NO 2 ( i.e., ramping gas temperature from 500 to 150 °C).
(d) Generate a fit of the deactivation data generated in paragraph (b) of this section at each temperature.
(1) Copper-based zeolite SCR. Process all NH 3 TPD data from each aging condition using an algorithm to fit the NH 3 desorption data.
(i) We recommend that you use the Temkin adsorption model to quantify the NH 3 TPD at each site to determine the desorption peaks of individual storage sites. The adsorption model is adapted from “Adsorption of Nitrogen and the Mechanism of Ammonia Decomposition Over Iron Catalysts” (Brunauer, S. et al, Journal of the American Chemical Society, 1942, 64 (4), 751-758) and “On Kinetic Modeling of Change in Active Sites upon Hydrothermal Aging of Cu-SSZ-13” (Daya, R. et al, Applied Catalysis B: Environmental, 2020, 263, 118368-118380). It is generalized using the following equation (assuming a two-site model):

Eq. 1065.1137-2
Where:
k
=
e
−
E
a
(1−αθ)
/RT
E a = thermal reactivity coefficient of ammonia desorption.
α = Temkin constant.
θ = fraction of adsorption sites currently occupied (initial θ is assumed to be 1).
R = molar gas constant.
T = aging temperature.
(A) Use Eq. 1065.1137-2 to express the NH 3 storage site desorption peaks as follows:

Eq. 1065.1137-3
Where:
N 1 = moles of NH 3 desorbed from Site 1.
A 1 = pre-exponential factor associated with Site 1.
E a,T1 = thermal reactivity coefficient of ammonia desorption for Site 1.
N 2 = moles of NH 3 desorbed from Site 2.
A 2 = pre-exponential factor associated with Site 2.
E a,T2 = thermal reactivity coefficient of ammonia desorption for Site 2.
(B) Optimize E a,T1 , α 1 , A 1 , E a,T2 , α 2 , and A 2 to fit each NH 3 TPD peak to give the best fit. The moles of NH 3 ( N 1 and N 2 ) may vary for each individual TPD data set.
(ii) Use one of the following modeling approaches to derive the thermal reactivity coefficient, E a,D . We recommend that you use both models to fit the data and check that the resulting E a,D values for the two methods are within 3% of each other.
(A) General Power Law Expression (GPLE). Generate a fit of the deactivation data from paragraph (d)(1)(i) of this section for each aging temperature using the following expression:

Eq. 1065.1137-4
Where:
k D = the thermal aging rate constant.

Eq. 1065.1137-5
A = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
Ω = N 2 / N 1 or = N 2 (normalizing Ω to the degreened Ω value for each new catalyst component prior to aging is recommended ( i.e., Ω = 1 at t = 0 for each aging temperature).
Ω eq = aging metric at equilibrium (set = 0 unless there is a known activity minimum).
m = model order (assumed to be 2 for copper-based zeolite SCR).
( 1 ) Solve Eq. 1065.1137-4 for Ω to yield the following expression:

Eq. 1065.1137-6
Where:
Ω 0 = 1 (assumes that N 2 / N 1 or = N 2 values were normalized to the degreened value for each aging temperature).
A = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
t = aging time.
( 2 ) Use a global fitting approach to solve for E a,D and A D by applying a generalized reduced gradient (GRG) nonlinear minimization algorithm, or equivalent. For the global fitting approach, optimize the model by minimizing the Global Sum of Square Errors ( SSE Global ) between the experimental Ω and model Ω while only allowing E a,D and A D to vary. Global SSE is defined as the summed total SSE for all aging temperatures evaluated.

Eq. 1065.1137-7
Where:
n = total number of aging temperatures.
i = an indexing variable that represents one aging temperature.
SEE T = sum of square errors (SSE) for a single aging temperature, T , (see Eq. 1065.1137-8).

Eq. 1065.1137-8
Where:
n = total number of aging intervals for a single aging temperature.
i = an indexing variable that represents one aging interval for a single aging temperature.
Ω Exp = experimentally derived aging metric for aging temperature, T .
Ω model = aging metric calculated from Eq. 1065.1137-6 for aging temperature, T .
(B) Arrhenius approach. In the Arrhenius approach, the deactivation rate constant, k D , of the aging metric, Ω , is calculated at each aging temperature.
( 1 ) Generate a fit of the deactivation data in paragraph (d)(1)(i) of this section at each aging temperature using the following linear expression:

Eq. 1065.1137-9
Where:
Ω = N 2 /N 1 or = N 2 ( Ω is to be normalized to the degreened Ω value for each new catalyst component prior to aging, i.e., Ω = 1 at t = 0 for each aging temperature).

(Eq. 1065.1137-5)
A = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
( 2 ) Generate a plot of 1/ Ω versus t for each aging temperature evaluated in paragraph (c)(1) in this section. The slope of each line is equal to the thermal aging rate, k D , at a given aging temperature. Using the data pairs of aging temperature and thermal aging rate constant, k D , determine the thermal reactivity coefficient, E a , by performing a regression analysis of the natural log of k D versus the inverse of temperature, T , in Kelvin. Determine E a,D from the slope of the resulting regression line, m deactivation , using the following equation:
E
a,D
= −
m
deactivation
·
R

Eq. 1065.1137-10
Where:
m deactivation = the slope of the regression line of ln( k D ) versus 1/ T .
R = molar gas constant.
(2) Iron-based zeolite or vanadium SCR. Process all NH 3 TPD data from each aging condition using a GPLE to fit the NH 3 desorption data (or BTE surface area data for vanadium SCR). Note that this expression is different from the one used in paragraph (d)(1)(ii)(A) of this section because the model order m is allowed to vary. This general expression takes the following form:

Eq. 1065.1137-11
Where:
Ω = total NH 3 (or BET surface area) normalized to the degreened value for each new catalyst component prior to aging ( i.e., Ω = 1 at t = 0 for each aging temperature).

(Eq. 1065.1137-5)
A = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
t = time.
Ω eq = aging metric at equilibrium (set to 0 unless there is a known activity minimum).
m = model order.
(i) Solve Eq. 1065.1137-10 for Ω to yield the following expression:

Eq. 1065.1137-12
Where:
Ω 0 = 1 (assumes total NH 3 storage, or BET surface area, was normalized to the degreened value for each aging temperature).
A = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
t = aging time.
m = model order (to be varied from 1 to 8 using whole numbers).
(ii) Global fitting is to be used to solve for E a,D and A D by applying a GRG nonlinear minimization algorithm, as described in paragraph (d)(1)(ii)(A) of this section. Minimize the SSE Global for each model order, m , while only allowing E a,D and A D to vary. The optimal solution is determined by selecting the model order, m , that yields the lowest global fit SSE. If you have a range of model order solutions where the SSE Global does not vary substantially, use good engineering judgement to choose the lowest m for this range.
(3) Zone-coated zeolite SCR. Derive the thermal reactivity coefficient, E a,D , for each zone of the SCR, based on the guidance provided in paragraphs (d)(1) and (2) of this section. The zone that yields the lowest E a,D shall be used for calculating the target cumulative thermal load, as outlined in § 1065.1139.
(4) Diesel oxidation catalyst. (i) The catalyst monolith is modeled as a plug flow reactor with first order reaction rate:

Eq. 1065.1137-13
Where:
v = velocity.
X = conversion (NO to NO 2 ) in %/100.
V = volume of reactor.

Eq. 1065.1137-14
A D = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
(ii) For a diesel oxidation catalyst, the preexponential term A D is proportional to the number of active sites and is the desired aging metric. Solving Eq. 1065.1137-13 for k D, substituting it for k D in Eq. 1065.1137-5, and then solving for A D yields Eq. 1065.1137-15:

Eq. 1065.1137-15
Where:
SV = space velocity used during RLO testing.
X = conversion (NO to NO 2 ).
E a,D = thermal reactivity coefficient.
T = temperature where X was measured.
R = molar gas constant.
(iii) Process all NO to NO 2 oxidation RLO data for each aging condition by determining the average oxidation conversion efficiency, X, at the temperature determined in paragraph (b)(5) of this section. We recommend maintaining the target oxidation conversion temperature to ±5 °C. For each aging condition (aging temperature, T and aging time, t ), calculate the aging metric, Ω, by normalizing A D to the degreened A D value for each new catalyst component prior to aging ( i.e., Ω = 1 at t = 0 for each aging temperature).
(A) Use the GPLE to fit the NO to NO 2 conversion data, X, at each aging temperature. The GPLE takes the following form:

Eq. 1065.1137-16
Where:
Ω = aging metric for diesel oxidation catalysts.

(Eq. 1065.1137-14)
R = molar gas constant.
T = aging temperature.
t = aging time.
Ω eq = aging metric at equilibrium (set to 0 unless there is a known activity minimum).
m = model order.
(B) Solve Eq. 1065.1137-12 for to yield the following expression:

Eq. 1065.1137-17
Where:
Ω eq = 1 (assumes the oxidation efficiency, X, was normalized to the degreened value for each aging temperature).
A = pre-exponential factor.
E a,D = thermal reactivity coefficient.
R = molar gas constant.
T = aging temperature.
t = aging time.
m = model order (to be varied from 1 to 8 using whole numbers)
(iv) Use global fitting to solve for E a,D and A by applying a GRG nonlinear minimization algorithm, as described in paragraph (d)(1)(ii)(A) of this section. Minimize the SSE Global for each model order, m, while only allowing E a,D and A to vary. The optimal solution is determined by selecting the model order, m, that yields the lowest global fit SSE. If you have a range of model order solutions where the SSE Global does not vary substantially, use good engineering judgement to choose the lowest m for this range.
174. Amend § 1065.1139 by adding paragraphs (e)(6)(v) and (f)(3) and revising paragraphs (g)(1) introductory text and (h) to read as follows:
§ 1065.1139
Aging cycle generation.
* * * * *
(e) * * *
(6) * * *
(v) If you are not able to achieve the target D t,field using the steps in paragraphs (e)(6)(i) through (iv) of this section without exceeding catalyst temperature limits, use good engineering judgement to reduce the acceleration factor from 10 to a lower number. If you reduce the acceleration factor you must re-calculate the number of hours determine in paragraph (a) of this section and re-run the process in this paragraph (e). Note that if you reduce the acceleration factor you must use the same lower acceleration factor in the chemical exposure calculations in paragraph (h) of this section, instead of 10.
(f) * * *
(3) If you are not able to achieve the target D t,field using the steps in paragraphs (f)(1) and (2) of this section without exceeding catalyst temperature limits, use good engineering judgement to reduce the acceleration factor from 10 to a lower number. If you reduce the acceleration factor you must re-calculate the number of hours determine in paragraph (a) of this section and re-run the process in this paragraph (f). Note that if you reduce the acceleration factor you must use the same lower acceleration factor in the chemical exposure calculations in paragraph (h) of this section, instead of 10.
(g) * * *
(1) Cycle assembly with infrequent regenerations. For systems that use infrequent regenerations, the number of cycle repeats is equal to the number of regeneration events that happen over full useful life. The total cycle duration of the aging cycle is calculated as the total aging duration in hours divided by the number of infrequent regeneration events. In the case of systems with multiple types of infrequent regenerations, use the regeneration with the lowest frequency to calculate the cycle duration.
* * * * *
(h) Chemical exposure targets. Determine targets for accelerated oil and fuel sulfur exposure as follows:
(1) Oil exposure targets. The target oil exposure rate during accelerated aging is 10 times the field average oil consumption rate determined in § 1065.1133(a)(2). You must achieve this target exposure rate on a cycle average basis during aging. Use good engineering judgment to determine the oil exposure rates for individual operating modes that will achieve this cycle average target. For engine-based aging stands you will likely have different oil consumption rates for different modes depending on the speed and load conditions you set. For burner-based aging stands, you may find that you have to limit oil exposure rates at low exhaust flow or low temperature modes to ensure good atomization of injected oil. On a cycle average basis, the portion of oil exposure from the volatile introduction pathway ( i.e., oil doped in the burner or engine fuel) must be between (10 to 30) % of the total. The remainder of oil exposure must be introduced through bulk pathway.
(2) Fuel sulfur exposure targets. The target sulfur exposure rate for fuel-related sulfur is determined by utilizing the field mean fuel rate data for the engine determined in § 1065.1133(a)(3). Calculate the total sulfur exposure mass using this mean fuel rate, the total number of non-accelerated hours to reach full useful life, and a fuel sulfur level of 10 ppmw.
(i) For an engine-based aging stand, if you perform accelerated sulfur exposure by additizing engine fuel to a higher sulfur level, determine the accelerated aging target additized fuel sulfur mass fraction, w S, as follows:

Eq. 1065.1139-9
Where:
m fuel,field = field mean fuel flow rate.
m fuel,cycle = accelerated aging cylce mean fuel low rate.
m Sfuel,ref = reference mass of sulfur per mass of fuel = 0.00001 kg/kg.
S acc,rate = sulfur acceleration rate = 10.
Example:
m fuel,field = 54.3 kg/hr
m fuel,cycle = 34.1 kg/hr
m Sfuel,ref = 0.00001 kg/kg.
S acc,rate = 10
(ii) If you use gaseous SO 2 to perform accelerated sulfur exposure, such as on a burner-based stand, calculate the target SO 2 concentration to be introduced, x SO2,target , as follows:

Eq. 1065.1139-10
Where:
m fuel,field = field mean fuel flow rate.
m exhaust,cycle = mean exhaust flow rate during the burner aging cycle.
x Sfuel,ref = reference mol fraction of sulfur in fuel = 10 µmol/mol.
S acc,rate = sulfur acceleration rate = 10.
M exh = molar mass of exhaust = molar mass of air.
M S = molar mass of sulfur.
Example:
m fuel,field = 54.3 kg/hr
m exhaust,cycle = 1000.8 kg/hr
x Sfuel,ref = 10 µmol/mol
S acc,rate = 10
M exh = 28.96559 g/mol
M S = 32.065 g/mol
(iii) You may choose to turn off gaseous sulfur injection during infrequent regeneration modes, but if you do you must increase the target SO 2 concentration by the ratio of total aging time to total normal (non-regeneration) aging time.
175. Amend § 1065.1141 by revising paragraphs (b) and (f) to read as follows:
§ 1065.1141
Facility requirements for engine-based aging stands.
* * * * *
(b) Use good engineering judgment to modify the engine to increase oil consumption rates to levels required for accelerated aging. These increased oil consumption levels must be sufficient to reach the bulk pathway exposure targets determined in § 1065.1139(h). A combination of engine modifications and careful operating mode selection will be used to reach the final bulk pathway oil exposure target on a cycle average. You must modify the engine in a fashion that will increase oil consumption in a manner such that the oil consumption is still generally representative of oil passing the piston rings into the cylinder. Use good engineering judgment to break in the modified engine to stabilize oil consumption rates. We recommend the following methods of modification (in order of preference):
(1) Install the second compression ring inverted (upside down) on one or more of the cylinders of the bench aging engine. This is most effective on rings that feature a sloped design to promote oil control when normally installed.
(2) If the approach in paragraph (b)(1) of this section is insufficient to reach the targets, modify the oil control rings in one or more cylinders to reduce the spring tension on the oil control ring. It should be noted that this is likely to be an iterative process until the correct modification has been determined.
(3) If the approach in paragraph (b)(2) of this section is insufficient to reach the targets, modify the oil control rings in one or more cylinders to create small notches or gaps (usually no more than 2 per cylinder) in the top portion of the oil control rings that contact the cylinder liner (care must be taken to avoid compromising the structural integrity of the ring itself).
* * * * *
(f) Use good engineering judgment to incorporate a means of monitoring oil consumption on a periodic basis. You may use a periodic drain and weigh approach to quantify oil consumption. We recommend that you incorporate a method of continuous oil consumption monitoring, but you must validate that method with periodic draining and weighing of the engine oil. You must validate that the aging stand reaches oil consumption targets prior to the start of aging. You must verify oil consumption during aging prior to each emission testing point, and at each oil change interval. Validate or verify oil consumption over a running period of at least 72 hours to obtain a valid measurement. If you do not include the constant volume oil system recommended in paragraph (c) of this section, you must account for all oil additions.
* * * * *
176. Amend § 1065.1145 by revising paragraphs (d) and (e)(2)(i) to read as follows:
§ 1065.1145
Execution of accelerated aging, cycle tracking, and cycle validation criteria.
* * * * *
(d) Accelerated aging. Following zero-hour emission testing and any engine dynamometer aging, perform accelerated aging using the cycle validated in either paragraph (a)(1) or (2) of this section. Repeat the cycle the number of times required to reach full useful life equivalent aging. Interrupt the aging cycle as needed to conduct any scheduled intermediate emission tests, clean the DPF of accumulated ash, and for any facility-related reasons. We recommended you interrupt aging at the end of a given aging cycle, following the completion of any scheduled infrequent regeneration event. If an aging cycle is paused for any reason, we recommended that you resume the aging cycle at the same point in the cycle where it stopped to ensure consistent thermal and chemical exposure of the aftertreatment system.
(e) * * *
(2) * * *
(i) Changing engine oil. For an engine-based platform, periodically change engine oil to maintain stable oil consumption rates and maintain the health of the aging engine. Interrupt aging as needed to perform oil changes. Perform a drain-and-weigh measurement. If you see a sudden change in oil consumption it may be necessary to stop aging and either change oil or correct an issue with the accelerated oil consumption. If the aging engine requires repairs to correct an oil consumption issue in the middle of aging, you must re-validate the oil consumption rate for 72 hours before you continue aging. The engine exhaust should be left bypassing the aftertreatment system until the repaired engine has been validated.
* * * * *
89
78
Monday, April 22, 2024
Rules and Regulations
Part III
Department of Energy
10 CFR Part 431

Energy Conservation Program: Energy Conservation Standards for Distribution Transformers; Final Rule
DEPARTMENT OF ENERGY
10 CFR Part 431
[EERE-2019-BT-STD-0018]
RIN 1904-AE12
Energy Conservation Program: Energy Conservation Standards for Distribution Transformers

AGENCY:
Office of Energy Efficiency and Renewable Energy, Department of Energy.

ACTION:
Final rule.

SUMMARY:
The Energy Policy and Conservation Act, as amended (EPCA), prescribes energy conservation standards for various consumer products and certain commercial and industrial equipment, including distribution transformers. EPCA also requires the U.S. Department of Energy (DOE) to periodically review its existing standards to determine whether more stringent standards would be technologically feasible and economically justified, and would result in significant energy savings. In this final rule, DOE is adopting amended energy conservation standards for distribution transformers. It has determined that the amended energy conservation standards for these products would result in significant conservation of energy, and are technologically feasible and economically justified.

DATES:
The effective date of this rule is July 8, 2024. Compliance with the amended standards established for distribution transformers in this final rule is required on and after April 23, 2029.

ADDRESSES:
The docket for this rulemaking, which includes Federal Register notices, public meeting attendee lists and transcripts, comments, and other supporting documents/materials, is available for review at www.regulations.gov. All documents in the docket are listed in the www.regulations.gov index. However, not all documents listed in the index may be publicly available, such as information that is exempt from public disclosure.
The docket web page can be found at www.regulations.gov/docket/EERE-2019-BT-STD-0018. The docket web page contains instructions on how to access all documents, including public comments, in the docket.
For further information on how to review the docket, contact the Appliance and Equipment Standards Program staff at (202) 287-1445 or by email: ApplianceStandardsQuestions@ee.doe.gov.

FOR FURTHER INFORMATION CONTACT:
Mr. Jeremy Dommu, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Office, EE-5B, 1000 Independence Avenue SW, Washington, DC 20585-0121. Email: ApplianceStandardsQuestions@ee.doe.gov.
Mr. Matthew Schneider, U.S. Department of Energy, Office of the General Counsel, GC-33, 1000 Independence Avenue SW, Washington, DC 20585-0121. Telephone: (202) 597-6265. Email: matthew.schneider@hq.doe.gov.

SUPPLEMENTARY INFORMATION:

Table of Contents
I. Synopsis of the Final Rule
A. Benefits and Costs to Consumers
B. Impact on Manufacturers
C. National Benefits and Costs
1. Liquid-Immersed Distribution Transformers
2. Low-Voltage Dry-Type Distribution Transformers
3. Medium-Voltage Dry-Type Distribution Transformers
D. Conclusion
II. Introduction
A. Authority
B. Background
1. Current Standards
2. History of Standards Rulemaking for Distribution Transformers
III. General Discussion
A. General Comments
B. Equipment Classes and Scope of Coverage
C. Test Procedure
D. Technological Feasibility
1. General
2. Maximum Technologically Feasible Levels
E. Energy Savings
1. Determination of Savings
2. Significance of Savings
F. Economic Justification
1. Specific Criteria
a. Economic Impact on Manufacturers and Consumers
b. Savings in Operating Costs Compared to Increase in Price (LCC and PBP)
c. Energy Savings
d. Lessening of Utility or Performance of Products
e. Impact of Any Lessening of Competition
f. Need for National Energy Conservation
g. Other Factors
2. Rebuttable Presumption
IV. Methodology and Discussion of Related Comments
A. Market and Technology Assessment
1. Scope of Coverage
a. Autotransformers
b. Drive (Isolation) Transformers
c. Special-Impedance Transformers
d. Tap Range of 20 Percent or More
e. Sealed and Non-Ventilated Transformers
f. Step-Up Transformers
g. Uninterruptible Power Supply Transformers
h. Voltage Specification
i. kVA Range
2. Equipment Classes
a. Submersible Transformers
b. Large Single-Phase Transformers
c. Large Three-Phase Transformers With High-Currents
d. Multi-Voltage Capable Distribution Transformers
e. Data Center Distribution Transformers
f. BIL Rating
g. Other
3. Technology Options
4. Transformer Core Material Technology and Market Assessment
a. Amorphous Alloy Market and Technology
b. Grain-Oriented Electrical Steel Market and Technology
c. Transformer Core Production Dynamics
5. Distribution Transformer Supply Chain
B. Screening Analysis
1. Screened-Out Technologies
2. Remaining Technologies
C. Engineering Analysis
1. Efficiency Analysis
a. Representative Units
b. Data Validation
c. Baseline Energy Use
d. Higher Efficiency Levels
e. kVA Scaling
2. Cost Analysis
a. Electrical Steel Prices
b. Other Material Prices
3. Cost-Efficiency Results
D. Markups Analysis
E. Energy Use Analysis
1. Trial Standard Levels
2. Hourly Load Model
a. Low-Voltage and Medium-Voltage Dry-Type Distribution Transformers Data Sources
3. Future Load Growth
a. Liquid-Immersed Distribution Transformers
F. Life-Cycle Cost and Payback Period Analysis
1. Equipment Cost
2. Efficiency Levels
3. Modeling Distribution Transformer Purchase Decision
a. Equipment Selection
b. Total Owning Cost and Evaluators
c. Non-Evaluators and First Cost Purchases
4. Installation Cost
a. Overall Size Increase
b. Liquid-Immersed
c. Overhead (Pole) Mounted Transformers
d. Surface (Pad) Mounted Transformers
e. Logistics and Hoisting
f. Installation of Ancillary Equipment: Gas Monitors and Fuses
g. Low-Voltage Dry-Type
5. Annual Energy Consumption
6. Energy Prices
7. Maintenance and Repair Costs
8. Transformer Service Lifetime
9. Discount Rates
10. Energy Efficiency Distribution in the No-New-Standards Case
11. Payback Period Analysis
G. Shipments Analysis
1. Equipment Switching
2. Trends in Distribution Transformer Capacity (kVA)
3. Rewound and Rebuilt Equipment
H. National Impact Analysis
1. Equipment Efficiency Trends
2. National Energy Savings
3. Net Present Value Analysis
I. Consumer Subgroup Analysis
1. Utilities Serving Low Customer Populations
2. Utility Purchasers of Vault (Underground) and Subsurface Installations
J. Manufacturer Impact Analysis
1. Overview
2. Government Regulatory Impact Model and Key Inputs
a. Manufacturer Production Costs
b. Shipments Projections
c. Product and Capital Conversion Costs
d. Manufacturer Markup Scenarios
K. Emissions Analysis
1. Air Quality Regulations Incorporated in DOE's Analysis
L. Monetizing Emissions Impacts
1. Monetization of Greenhouse Gas Emissions
a. Social Cost of Carbon
b. Social Cost of Methane and Nitrous Oxide
c. Sensitivity Analysis Using EPA's New SC-GHG Estimates
2. Monetization of Other Emissions Impacts
M. Utility Impact Analysis
N. Employment Impact Analysis
V. Analytical Results and Conclusions
A. Trial Standard Levels
B. Economic Justification and Energy Savings
1. Economic Impacts on Individual Consumers
a. Life-Cycle Cost and Payback Period
b. Consumer Subgroup Analysis
c. Rebuttable Presumption Payback
2. Economic Impacts on Manufacturers
a. Industry Cash Flow Analysis Results
b. Direct Impacts on Employment
c. Impacts on Manufacturing Capacity
d. Impacts on Subgroups of Manufacturers
e. Cumulative Regulatory Burden
3. National Impact Analysis
a. National Energy Savings
b. Net Present Value of Consumer Costs and Benefits
c. Indirect Impacts on Employment
4. Impact on Utility or Performance of Products
5. Impact of Any Lessening of Competition
6. Need of the Nation To Conserve Energy
7. Other Factors
8. Summary of Economic Impacts
C. Conclusion
1. Benefits and Burdens of TSLs Considered for Liquid-Immersed Distribution Transformer Standards
2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-Type Distribution Transformer Standards
3. Benefits and Burdens of TSLs Considered for Medium-Voltage Dry-Type Distribution Transformer Standards
4. Annualized Benefits and Costs of the Adopted Standards for Liquid-Immersed Distribution Transformers
5. Annualized Benefits and Costs of the Adopted Standards for Low-Voltage Dry-Type Distribution Transformers
6. Annualized Benefits and Costs of the Adopted Standards for Medium-Voltage Dry-Type Distribution Transformers
7. Benefits and Costs of the Proposed Standards for all Considered Distribution Transformers
8. Severability
VI. Procedural Issues and Regulatory Review
A. Review Under Executive Orders 12866, 13563, and 14094
B. Review Under the Regulatory Flexibility Act
1. Need for, and Objectives of, Rule
2. Significant Issues Raised by Public Comments in Response to the IRFA
3. Description and Estimated Number of Small Entities Affected
4. Description of Reporting, Recordkeeping, and Other Compliance Requirements
5. Significant Alternatives Considered and Steps Taken To Minimize Significant Economic Impacts on Small Entities
C. Review Under the Paperwork Reduction Act
D. Review Under the National Environmental Policy Act of 1969
E. Review Under Executive Order 13132
F. Review Under Executive Order 12988
G. Review Under the Unfunded Mandates Reform Act of 1995
H. Review Under the Treasury and General Government Appropriations Act, 1999
I. Review Under Executive Order 12630
J. Review Under the Treasury and General Government Appropriations Act, 2001
K. Review Under Executive Order 13211
L. Information Quality
M. Congressional Notification
VII. Approval of the Office of the Secretary

I. Synopsis of the Final Rule
The Energy Policy and Conservation Act, Public Law 94-163, as amended (EPCA), ^1 authorizes DOE to regulate the energy efficiency of a number of consumer products and certain industrial equipment. (42 U.S.C. 6291-6317, as codified) Title III, Part B of EPCA ^2 established the Energy Conservation Program for Consumer Products Other Than Automobiles. (42 U.S.C. 6291-6309) Title III, Part C of the EPCA, as amended, ^3 established the Energy Conservation Program for Certain Industrial Equipment. (42 U.S.C. 6311-6317) The Energy Policy Act of 1992, Public Law 102-486, amended EPCA and directed DOE to prescribe energy conservation standards for those distribution transformers for which DOE determined such standards would be technologically feasible, economically justified, and would result in significant energy savings. (42 U.S.C. 6317(a)) The Energy Policy Act of 2005, Public Law. 109-58, amended EPCA to establish energy conservation standards for low-voltage dry-type (LVDT) distribution transformers. (42 U.S.C. 6295(y))
^1 All references to EPCA in this document refer to the statute as amended through the Energy Act of 2020, Public Law 116-260 (Dec. 27, 2020), which reflect the last statutory amendments that impact Parts A and A-1 of EPCA.
^2 For editorial reasons, upon codification in the U.S. Code, Part B was redesignated Part A.
^3 For editorial reasons, upon codification in the U.S. Code, Part C was redesignated Part A-1. While EPCA includes provisions regarding distribution transformers in both Part A and Part A-1, for administrative convenience DOE has established the test procedures and standards for distribution transformers in 10 CFR part 431, Energy Efficiency Program for Certain Commercial and Industrial Equipment. DOE refers to distribution transformers generally as “covered equipment” in this document.
Pursuant to EPCA, DOE is required to review its existing energy conservation standards for covered equipment no later than six years after issuance of any final rule establishing or amending a standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1)) Pursuant to that statutory provision, DOE must publish either a notification of determination that standards for the product do not need to be amended, or a notice of proposed rulemaking (NOPR) including new proposed energy conservation standards (proceeding to a final rule, as appropriate). ( Id. ) Any new or amended energy conservation standard must be designed to achieve the maximum improvement in energy efficiency that DOE determines is technologically feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)) Furthermore, the new or amended standard must result in significant conservation of energy. (42 U.S.C. 6295(o)(3)(B)) DOE has conducted this review of the energy conservation standards for distribution transformers under EPCA's six-year-lookback authority. ( Id. )
In accordance with these and other statutory provisions discussed in this document, DOE analyzed the benefits and burdens of five trial standard levels (TSLs) for liquid-immersed distribution transformers, low-voltage dry-type and medium-voltage dry-type distribution transformers. The TSLs and their associated benefits and burdens are discussed in detail in sections V.A through V.C of this document. As discussed in section V.C of this document, DOE has determined that TSL 3 for liquid-immersed distribution transformers, which corresponds to a 5 percent reduction in losses for single-phase transformers less than or equal to 100 kVA and three-phase transformers greater than or equal to 500 kVA and a 20 percent reduction in losses for single-phase transformers greater than 100 kVA and three-phase transformers less than 500 kVA, represents the maximum improvement in energy efficiency that is technologically feasible and economically justified. For low-voltage dry-type distribution transformers, DOE has determined that TSL 3, corresponding to a 30 percent reduction in losses for single-phase low-voltage dry-type distribution transformers, 20 percent reduction in losses for three-phase low-voltage dry-type distribution transformers represents the maximum improvement in energy efficiency that is technologically feasible and economically justified. For medium-voltage dry-type distribution transformers, DOE has determined that TSL 2 for medium-voltage dry-type (MVDT), corresponding to a 20 percent reduction in losses, represents the maximum improvement in energy efficiency that is technologically feasible and economically justified. The adopted standards, which are expressed in efficiency as a percentage, are shown in Table I.1 through Table I.3. These standards apply to all equipment listed in Table I.1 through Table I.3 and manufactured in, or imported into, the United States starting on April 23, 2029.

A. Benefits and Costs to Consumers
Table I.4 summarizes DOE's evaluation of the economic impacts of the adopted standards on consumers of distribution transformers, as measured by the average life-cycle cost (LCC) savings and the simple payback period (PBP). ^4 The average LCC savings are positive for all equipment classes in all cases, with the exception of equipment class 10 (e,g., medium-voltage, dry-type, three-phase with a BIL of greater than 96 kV and kVA range of 225-5000), and the PBP is less than the average lifetime of distribution transformers, which is estimated to be 32 years (see section IV.F.8 of this document). In the context of this final rule, the term "consumer" refers to different populations that purchase and bear the operating costs of distribution transformers. Consumers vary by transformer category: for medium-voltage liquid-immersed distribution transformers, the term "consumer" refers to electric utilities; for low- and medium-voltage dry-type distribution transformers, the term "consumer" refers to COMMERCIAL AND INDUSTRIAL entities.
^4 The average LCC savings refer to consumers that are affected by a standard and are measured relative to the efficiency distribution in the no-new-standards case, which depicts the market in the compliance year in the absence of new or amended standards (see section IV.F.10 of this document). The simple PBP, which is designed to compare specific efficiency levels, is measured relative to the baseline product (see section IV.C of this document).
DOE's analysis of the impacts of the adopted standards on consumers is described in section IV.F of this document.

B. Impact on Manufacturers
The industry net present value (INPV) is the sum of the discounted cash flows to the industry from the base year through the end of the analysis period (2024-2058). Using a real discount rate of 7.4 percent for liquid-immersed distribution transformers, 11.1 percent for LVDT distribution transformers, and 9.0 percent for MVDT distribution transformers, DOE estimates that the INPV for manufacturers of distribution transformers in the case without amended standards is $1,792 million in 2022 dollars for liquid-immersed distribution transformers, $212 million in 2022 dollars for LVDT distribution transformers, and $95 million in 2022 dollars for MVDT distribution transformers. Under the adopted standards, the change in INPV is estimated to range from −8.1 percent to −6.2 percent for liquid-immersed distribution transformers which represents a change in INPV of approximately −$145 million to −$111 million; from −12.8 percent to −8.9 percent for LVDT distribution transformers, which represents a change in INPV of approximately −$27.1 million to −$18.9 million; and −4.7 percent to −2.5 percent for MVDT distribution transformers, which represents a change in INPV of approximately −$4.4 million to −$2.3 million. In order to bring products into compliance with amended standards, it is estimated that the industry would incur total conversion costs of $187 million for liquid-immersed distribution transformer, $36.1 million for LVDT distribution transformers, and $5.7 million for MVDT distribution transformers.
DOE's analysis of the impacts of the adopted standards on manufacturers is described in sections IV.J and V.B.2 of this document.

C. National Benefits and Costs ^5
^5 All monetary values in this document are expressed in 2022 dollars and, where appropriate, are discounted to 2024 from the year of compliance (2029) unless explicitly stated otherwise.

1. Liquid-Immersed Distribution Transformers
DOE's analyses indicate that the adopted energy conservation standards for distribution transformers would save a significant amount of energy. Relative to the case without amended standards, the lifetime energy savings for liquid-immersed distribution transformers purchased in the 30-year period that begins in the anticipated year of compliance with the amended standards (2029-2058) amount to 2.73 quadrillion British thermal units (Btu), or quads. ^6 This represents a savings of 13 percent relative to the energy use of these products in the case without amended standards (referred to as the “no-new-standards case”).
^6 The quantity refers to full-fuel-cycle (FFC) energy savings. FFC energy savings includes the energy consumed in extracting, processing, and transporting primary fuels ( i.e., coal, natural gas, petroleum fuels) and, thus, presents a more complete picture of the impacts of energy efficiency standards. For more information on the FFC metric, see section IV.H of this document.
The cumulative net present value (NPV) of total consumer benefits of the standards for liquid-immersed distribution transformers ranges from $0.56 billion (at a 7-percent discount rate) to $3.41 billion (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product and installation costs for distribution transformers purchased in 2029-2058.
In addition, the adopted standards for liquid-immersed distribution transformers are projected to yield significant environmental benefits. DOE estimates that the standards will result in cumulative emission reductions (over the same period as for energy savings) of 51.40 million metric tons (Mt) ^7 of carbon dioxide (CO 2 ), 12.29 thousand tons of sulfur dioxide (SO 2 ), 89.85 thousand tons of nitrogen oxides (NO X ), 416.15 thousand tons of methane (CH 4 ), 0.40 thousand tons of nitrous oxide (N 2 O), and 0.08 tons of mercury (Hg). ^8
^7 A metric ton is equivalent to 1.1 short tons. Results for emissions other than CO 2 are presented in short tons.
^8 DOE calculated emissions reductions relative to the no-new-standards case, which reflects key assumptions in the Annual Energy Outlook 2023 ( AEO2023 ). AEO2023 reflects, to the extent possible, laws and regulations adopted through mid-November 2022, including the Inflation Reduction Act. See section IV.K of this document for further discussion of AEO2023 assumptions that affect air pollutant emissions.
DOE estimates the value of climate benefits from a reduction in greenhouse gases (GHG) using four different estimates of the social cost of CO 2 (SC-CO 2 ), the social cost of methane (SC-CH 4 ), and the social cost of nitrous oxide (SC-N 2 O). ^9 Together these represent the social cost of GHG (SC-GHG). DOE used interim SC-GHG values (in terms of benefit-per-ton of GHG avoided) developed by an Interagency Working Group on the Social Cost of Greenhouse Gases (IWG). ^{10} The derivation of these values is discussed in section IV.L of this document. For presentational purposes, the climate benefits associated with the average SC-GHG at a 3-percent discount rate are estimated to be $1.85 billion. DOE does not have a single central SC-GHG point estimate and it emphasizes the importance and value of considering the benefits calculated using all four sets of SC-GHG estimates.
^9 Estimated climate-related benefits are provided in compliance with Executive Order 12866.
^{10} To monetize the benefits of reducing GHG emissions, this analysis uses the interim estimates presented in the February 2021 SC-GHG TSD. www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
DOE estimated the monetary health benefits of SO 2 and NO X emissions reductions, using benefit-per-ton estimates from the Environmental Protection Agency, ^{11} as discussed in section IV.L of this document. DOE estimated the present value of the health benefits would be $1.11 billion using a 7-percent discount rate, and $3.71 billion using a 3-percent discount rate. ^{12} DOE is currently only monetizing health benefits from changes in ambient fine particulate matter (PM 2.5 ) concentrations from two precursors (SO 2 and NO X ), and from changes in ambient ozone from one precursor (NO X ), but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM 2.5 emissions.
^{11} U.S. EPA. Estimating the Benefit per Ton of Reducing Directly Emitted PM 2.5 , PM 2.5 Precursors and Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
^{12} DOE estimates the economic value of these emissions reductions resulting from the considered TSLs for the purpose of complying with the requirements of Executive Order 12866.
Table I.5 summarizes the monetized benefits and costs expected to result from the amended standards for liquid-immersed distribution transformers. There are other important unquantified effects, including certain unquantified climate benefits, unquantified public health benefits from the reduction of toxic air pollutants and other emissions, unquantified energy security benefits, and distributional effects, among others.
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The monetary values for the total annualized net benefits are (1) the reduced consumer operating costs, minus (2) the increase in product purchase prices and installation costs, plus (3) the value of climate and health benefits of emission reductions, all annualized. ^{13}
^{13} To convert the time-series of costs and benefits into annualized values, DOE calculated a present value in 2024, the year used for discounting the NPV of total consumer costs and savings. For the benefits, DOE calculated a present value associated with each year's shipments in the year in which the shipments occur ( e.g., 2020 or 2030), and then discounted the present value from each year to 2024. Using the present value, DOE then calculated the fixed annual payment over a 30-year period, starting in the compliance year, that yields the same present value.
The national operating cost savings are domestic private U.S. consumer monetary savings that occur as a result of purchasing the covered equipment and are measured for the lifetime of distribution transformers shipped in 2029-2058. The benefits associated with reduced emissions achieved as a result of the adopted standards are also calculated based on the lifetime of liquid-immersed distribution transformers shipped in 2029-2058. Total benefits for both the 3-percent and 7-percent cases are presented using the average GHG social costs with a 3-percent discount rate. ^{14} Estimates of total benefits are presented for all four SC-GHG discount rates in section IV.L of this document.
^{14} As discussed in section IV.L.1 of this document, DOE agrees with the IWG that using consumption-based discount rates e.g., 3 percent) is appropriate when discounting the value of climate impacts. Combining climate effects discounted at an appropriate consumption-based discount rate with other costs and benefits discounted at a capital-based rate ( i.e., 7 percent) is reasonable because of the different nature of the types of benefits being measured.
Table I.6 presents the total estimated monetized benefits and costs associated with the adopted standard, expressed in terms of annualized values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NOx and SO 2 reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for liquid-immersed distribution transformers is $151.1 million per year in increased equipment installed costs, while the estimated annual benefits are $210.2 million from reduced equipment operating costs, $106.1 million in GHG reductions, and $117.0 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $282.3 million per year.
Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for liquid-immersed distribution transformers is $152.6 million per year in increased equipment costs, while the estimated annual benefits are $348.3 million in reduced operating costs, $106.1 million from GHG reductions, and $213.2 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $515.1 million per year.

2. Low-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the adopted energy conservation standards for distribution transformers would save a significant amount of energy. Relative to the case without amended standards, the lifetime energy savings for low-voltage dry-type distribution transformers purchased in the 30-year period that begins in the anticipated year of compliance with the amended standards (2029-2058) amount to 1.71 quadrillion Btu, or quads. ^{15} This represents a savings of 35 percent relative to the energy use of these products in the no-new-standards case.
^{15} The quantity refers to FFC energy savings. FFC energy savings includes the energy consumed in extracting, processing, and transporting primary fuels ( i.e., coal, natural gas, petroleum fuels) and, thus, presents a more complete picture of the impacts of energy efficiency standards. For more information on the FFC metric, see section IV.H of this document.
The cumulative NPV of total consumer benefits of the standards for low-voltage dry-type distribution transformers ranges from $2.08 billion (at a 7-percent discount rate) to 6.68 billion (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product and installation costs for distribution transformers purchased in 2029-2058.
In addition, the adopted standards for low-voltage dry-type distribution transformers are projected to yield significant environmental benefits. DOE estimates that the standards will result in cumulative emission reductions (over the same period as for energy savings) of 31.28 million Mt ^{16} of CO 2 , 7.49 thousand tons of SO 2 , 55.92 thousand tons of NO X , 259.96 thousand tons of CH 4 , 0.24 thousand tons of N 2 O, and 0.05 tons of Hg. ^{17}
^{16} A metric ton is equivalent to 1.1 short tons. Results for emissions other than CO 2 are presented in short tons.
^{17} DOE calculated emissions reductions relative to the no-new-standards case, which reflects key assumptions in the AEO2023. AEO2023 reflects, to the extent possible, laws and regulations adopted through mid-November 2022, including the Inflation Reduction Act. See section IV.K of this document for further discussion of AEO2023 assumptions that affect air pollutant emissions.
DOE estimates the value of climate benefits from a reduction in GHG using four different estimates of the SC- CO2 CO 2 , the SC-CH 4 , and the SC-N 2 O. Together these represent the SC-GHG. ^{DOE} used interim SC-GHG values (in terms of benefit per ton of GHG avoided) developed by an IWG. ^{18} The derivation of these values is discussed in section IV.L of this document. For presentational purposes, the climate benefits associated with the average SC-GHG at a 3-percent discount rate are estimated to be $1.23 billion. DOE does not have a single central SC-GHG point estimate and it emphasizes the importance and value of considering the benefits calculated using all four sets of SC-GHG estimates.
^{18} To monetize the benefits of reducing GHG emissions, this analysis uses values that are based on the February 2021 SC-GHG TSD. www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
DOE estimated the monetary health benefits of SO 2 and NO X emissions reductions, using benefit per ton estimates from the Environmental Protection Agency, ^{19} as discussed in section IV.L of this document. DOE did not monetize the reduction in mercury emissions because the quantity is very small. DOE estimated the present value of the health benefits would be $0.76 billion using a 7-percent discount rate, and $2.42 billion using a 3-percent discount rate. ^{20} DOE is currently only monetizing health benefits from changes in ambient PM 2.5 concentrations from two precursors (SO 2 and NO X ), and from changes in ambient ozone from one precursor (for NO X ), but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM 2.5 emissions.
^{19} U.S. EPA. Estimating the Benefit per Ton of Reducing Directly Emitted PM 2.5 , PM 2.5 Precursors and Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
^{20} DOE estimates the economic value of these emissions reductions resulting from the considered TSLs for the purpose of complying with the requirements of Executive Order 12866.
Table I.7 summarizes the monetized benefits and costs expected to result from the amended standards for low-voltage dry-type distribution transformers. There are other important unquantified effects, including certain unquantified climate benefits, unquantified public health benefits from the reduction of toxic air pollutants and other emissions, unquantified energy security benefits, and distributional effects, among others.
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The monetary values for the total annualized net benefits are (1) the reduced consumer operating costs, minus (2) the increase in product purchase prices and installation costs, plus (3) the value of climate and health benefits of emission reductions, all annualized. ^{21}
^{21} To convert the time-series of costs and benefits into annualized values, DOE calculated a present value in 2024, the year used for discounting the NPV of total consumer costs and savings. For the benefits, DOE calculated a present value associated with each year's shipments in the year in which the shipments occur ( e.g., 2020 or 2030), and then discounted the present value from each year to 2024. Using the present value, DOE then calculated the fixed annual payment over a 30-year period, starting in the compliance year, that yields the same present value.
The national operating cost savings are domestic private U.S. consumer monetary savings that occur as a result of purchasing the covered equipment and are measured for the lifetime of distribution transformers shipped in 2029-2058. The benefits associated with reduced emissions achieved as a result of the adopted standards are also calculated based on the lifetime of low-voltage dry-type distribution transformers shipped in 2029-2058. Total benefits for both the 3-percent and 7-percent cases are presented using the average GHG social costs with a 3-percent discount rate. ^{22} Estimates of total benefits are presented for all four SC-GHG discount rates in section IV.L of this document.
^{22} As discussed in section IV.L.1 of this document, DOE agrees with the IWG that using consumption-based discount rates e.g., 3 percent) is appropriate when discounting the value of climate impacts. Combining climate effects discounted at an appropriate consumption-based discount rate with other costs and benefits discounted at a capital-based rate ( i.e., 7 percent) is reasonable because of the different nature of the types of benefits being measured.
Table I.8 presents the total estimated monetized benefits and costs associated with the adopted standard, expressed in terms of annualized values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NOx and SO 2 reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for low-voltage dry-type is $66.6 million per year in increased equipment installed costs, while the estimated annual benefits are $286.8 million from reduced equipment operating costs, $70.4 million in GHG reductions, and $80.3 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $370.8 million per year.
Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for low-voltage dry-type is $67.4 million per year in increased equipment costs, while the estimated annual benefits are $450.9 million in reduced operating costs, $70.4 million from GHG reductions, and $139.1 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $593.0 million per year.

3. Medium-Voltage Dry-Type Distribution Transformers
DOE's analyses indicate that the adopted energy conservation standards for medium-voltage dry-type distribution transformers would save a significant amount of energy. Relative to the case without amended standards, the lifetime energy savings for distribution transformers purchased in the 30-year period that begins in the anticipated year of compliance with the amended standards (2029-2058) amount to 0.14 quadrillion Btu, or quads. ^{23} This represents a savings of 9 percent relative to the energy use of these products in the no-new-standards case.
^{23} The quantity refers to FFC energy savings. FFC energy savings includes the energy consumed in extracting, processing, and transporting primary fuels ( i.e., coal, natural gas, petroleum fuels) and, thus, presents a more complete picture of the impacts of energy efficiency standards. For more information on the FFC metric, see section IV.H of this document.
The cumulative NPV of total consumer benefits of the standards for medium-voltage dry-type distribution transformers ranges from $0.03 (at a 7-percent discount rate) to $0.22 (at a 3-percent discount rate). This NPV expresses the estimated total value of future operating-cost savings minus the estimated increased product and installation costs for distribution transformers purchased in 2029-2058.
In addition, the adopted standards for medium-voltage dry-type distribution transformers are projected to yield significant environmental benefits. DOE estimates that the standards will result in cumulative emission reductions (over the same period as for energy savings) of 2.59 million Mt ^{24} of CO 2 , 0.63 thousand tons of SO 2 , 4.69 thousand tons of NO X , 21.86 thousand tons of CH 4 , 0.02 thousand tons of N 2 O, and 0.00 tons of Hg. ^{25}
^{24} A metric ton is equivalent to 1.1 short tons. Results for emissions other than CO 2 are presented in short tons.
^{25} DOE calculated emissions reductions relative to the no-new-standards case, which reflects key assumptions in the AEO2023. AEO2023 reflects, to the extent possible, laws and regulations adopted through mid-November 2022, including the Inflation Reduction Act. See section IV.K of this document for further discussion of AEO2023 assumptions that affect air pollutant emissions.
DOE estimates the value of climate benefits from a reduction in GHG using four different estimates of the SC-CO 2 , the SC-CH 4 , and the SC-N 2 O. Together these represent the SC-GHG. DOE used interim SC-GHG values (in terms of benefit per ton of GHG avoided) developed by an IWG. ^{26} The derivation of these values is discussed in section IV.L of this document. For presentational purposes, the climate benefits associated with the average SC-GHG at a 3-percent discount rate are estimated to be $0.10 billion. DOE does not have a single central SC-GHG point estimate and it emphasizes the importance and value of considering the benefits calculated using all four sets of SC-GHG estimates.
^{26} To monetize the benefits of reducing GHG emissions, this analysis uses values that are based on the February 2021 SC-GHG TSD. www.whitehouse.gov/wp-content/uploads/2021/02/TechnicalSupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
DOE estimated the monetary health benefits of SO 2 and NO X emissions reductions, using benefit per ton estimates from the Environmental Protection Agency, ^{27} as discussed in section IV.L of this document. DOE did not monetize the reduction in mercury emissions because the quantity is very small. DOE estimated the present value of the health benefits would be $0.06 billion using a 7-percent discount rate, and $0.20 billion using a 3-percent discount rate. ^{28} DOE is currently only monetizing health benefits from changes in ambient PM 2.5 concentrations from two precursors (SO 2 and NO X ), and from changes in ambient ozone from one precursor (for NO X ), but will continue to assess the ability to monetize other effects such as health benefits from reductions in direct PM 2.5 emissions.
^{27} U.S. EPA. Estimating the Benefit per Ton of Reducing Directly Emitted PM 2.5 , PM 2.5 Precursors and Ozone Precursors from 21 Sectors. Available at www.epa.gov/benmap/estimating-benefit-ton-reducing-pm25-precursors-21-sectors.
^{28} DOE estimates the economic value of these emissions reductions resulting from the considered TSLs for the purpose of complying with the requirements of Executive Order 12866.
Table I.9 summarizes the monetized benefits and costs expected to result from the amended standards for medium-voltage dry-type distribution transformers. There are other important unquantified effects, including certain unquantified climate benefits, unquantified public health benefits from the reduction of toxic air pollutants and other emissions, unquantified energy security benefits, and distributional effects, among others.
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The monetary values for the total annualized net benefits are (1) the reduced consumer operating costs, minus (2) the increase in product purchase prices and installation costs, plus (3) the value of climate and health benefits of emission reductions, all annualized. ^{29}
^{29} To convert the time-series of costs and benefits into annualized values, DOE calculated a present value in 2024, the year used for discounting the NPV of total consumer costs and savings. For the benefits, DOE calculated a present value associated with each year's shipments in the year in which the shipments occur ( e.g., 2020 or 2030), and then discounted the present value from each year to 2024. Using the present value, DOE then calculated the fixed annual payment over a 30-year period, starting in the compliance year, that yields the same present value.
The national operating cost savings are domestic private U.S. consumer monetary savings that occur as a result of purchasing the covered equipment and are measured for the lifetime of medium-voltage dry-type distribution transformers shipped in 2029-2058. The benefits associated with reduced emissions achieved as a result of the adopted standards are also calculated based on the lifetime of distribution transformers shipped in 2029-2058. Total benefits for both the 3-percent and 7-percent cases are presented using the average GHG social costs with a 3-percent discount rate. ^{30} Estimates of total benefits are presented for all four SC-GHG discount rates in section IV.L of this document.
^{30} As discussed in section IV.L.1 of this document, DOE agrees with the IWG that using consumption-based discount rates e.g., 3 percent) is appropriate when discounting the value of climate impacts. Combining climate effects discounted at an appropriate consumption-based discount rate with other costs and benefits discounted at a capital-based rate ( i.e., 7 percent) is reasonable because of the different nature of the types of benefits being measured.
Table I.10 presents the total estimated monetized benefits and costs associated with the adopted standard, expressed in terms of annualized values. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NO X and SO 2 reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for medium-voltage dry-type is $12.5 million per year in increased equipment installed costs, while the estimated annual benefits are $15.9 million from reduced equipment operating costs, $5.9 million in GHG reductions, and $6.7 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $16.0 million per year.
Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for medium-voltage dry-type distribution transformers is $12.7 million per year in increased equipment costs, while the estimated annual benefits are $25.1 million in reduced operating costs, $5.9 million from GHG reductions, and $11.7 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $29.9 million per year.
DOE's analysis of the national impacts of the adopted standards is described in sections IV.H, IV.K, and IV.L of this document.

D. Conclusion
DOE concludes that the standards adopted in this final rule represent the maximum improvement in energy efficiency that is technologically feasible and economically justified, and would result in the significant conservation of energy. Specifically, with regards to technological feasibility, products are already commercially available which either achieve these standard levels or utilize the technologies required to achieve these standard levels for all product classes covered by this proposal. As for economic justification, DOE's analysis shows that the benefits of the standards exceed, to a great extent, the burdens of the standards.
Table I.11 shows the annualized values for all distribution transformers under amended standards, expressed in 2022$. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NOx and SO 2 reduction benefits, and a 3-percent discount rate case for GHG social costs, the estimated cost of the standards for distribution transformers is $ 230.3 million per year in increased distribution transformers costs, while the estimated annual benefits are $512.9 million in reduced distribution transformers operating costs, $182.4 million in climate benefits, and $204.1 million in health benefits. The net benefit amounts to $669.1 million per year. DOE notes that the net benefits are substantial even in the absence of the climate benefits, ^{31} and DOE would adopt the same standards in the absence of such benefits.
^{31} The information on climate benefits is provided in compliance with Executive Order 12866.
The significance of energy savings offered by a new or amended energy conservation standard cannot be determined without knowledge of the specific circumstances surrounding a given rulemaking. ^{32} For example, some covered products and equipment have most of their energy consumption occur during periods of peak energy demand. The impacts of these products on the energy infrastructure can be more pronounced than products with relatively constant demand. Accordingly, DOE evaluates the significance of energy savings on a case-by-case basis.
^{32} Procedures, Interpretations, and Policies for Consideration in New or Revised Energy Conservation Standards and Test Procedures for Consumer Products and Commercial/Industrial Equipment, 86 FR 70892, 70901 (Dec. 13, 2021).
As previously mentioned, the standards are projected to result in estimated national energy savings of 4.58 quads full fuel cycle (FFC), the equivalent of the primary annual energy use of 49.2 million homes. In addition, they are projected to reduce cumulative CO 2 emissions by 85.27 Mt. Based on these findings, DOE has determined the energy savings from the standard levels adopted in this final rule are “significant” within the meaning of 42 U.S.C. 6295(o)(3)(B). A more detailed discussion of the basis for these conclusions is contained in the remainder of this document and the accompanying TSD.

II. Introduction
The following section briefly discusses the statutory authority underlying this final rule, as well as some of the relevant historical background related to the establishment of standards for distribution transformers.

A. Authority
EPCA authorizes DOE to regulate the energy efficiency of a number of consumer products and certain industrial equipment. (42 U.S.C. 6291-6317, as codified) Title III, Part B of EPCA established the Energy Conservation Program for Consumer Products Other Than Automobiles. (42 U.S.C. 6291-6309) Title III, Part C of EPCA, ^{33} as amended, established the Energy Conservation Program for Certain Industrial Equipment. (42 U.S.C. 6311-6317) The Energy Policy Act of 1992, Public Law 102-486, amended EPCA and directed DOE to prescribe energy conservation standards for those distribution transformers for which DOE determines such standards would be technologically feasible, economically justified, and would result in significant energy savings. (42 U.S.C. 6317(a)) The Energy Policy Act of 2005, Public Law 109-58, also amended EPCA to establish energy conservation standards for low-voltage dry-type distribution transformers. (42 U.S.C. 6295(y))
^{33} As noted previously, for editorial reasons, upon codification in the U.S. Code, Part C was redesignated Part A-1.
EPCA further provides that, not later than six years after the issuance of any final rule establishing or amending a standard, DOE must publish either a notice of determination that standards for the product do not need to be amended, or a NOPR including new proposed energy conservation standards (proceeding to a final rule, as appropriate). (42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1))
The energy conservation program under EPCA consists essentially of four parts: (1) testing, (2) labeling, (3) the establishment of Federal energy conservation standards, and (4) certification and enforcement procedures. Relevant provisions of EPCA include definitions (42 U.S.C. 6311), test procedures (42 U.S.C. 6314), labeling provisions (42 U.S.C. 6315), energy conservation standards (42 U.S.C. 6313), and the authority to require information and reports from manufacturers (42 U.S.C. 6316).
Federal energy efficiency requirements for covered equipment established under EPCA generally supersede State laws and regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6316(a) and 42 U.S.C. 6316(b); 42 U.S.C. 6297) DOE may, however, grant waivers of Federal preemption in limited instances for particular State laws or regulations, in accordance with the procedures and other provisions set forth under EPCA. (( See 42 U.S.C. 6316(a) (applying the preemption waiver provisions of 42 U.S.C. 6297).)
Subject to certain criteria and conditions, DOE is required to develop test procedures to measure the energy efficiency, energy use, or estimated annual operating cost of each covered product. ( See 42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(A) and (r).) Manufacturers of covered equipment must use the Federal test procedures as the basis for certifying to DOE that their equipment complies with the applicable energy conservation standards and as the basis for any representations regarding the energy use or energy efficiency of the equipment. (42 U.S.C. 6316(a); 42 U.S.C. 6295(s); 42 U.S.C. 6314(d)). Similarly, DOE must use these test procedures to evaluate whether a basic model complies with the applicable energy conservation standard(s). (42 U.S.C. 6316(a); 42 U.S.C. 6295(s)) The DOE test procedures for distribution transformers appear at title 10 of the Code of Federal Regulations (CFR) part 431, subpart K, appendix A.
DOE must follow specific statutory criteria for prescribing new or amended standards for covered equipment, including distribution transformers. Any new or amended standard for a covered product must be designed to achieve the maximum improvement in energy efficiency that the Secretary of Energy (“Secretary”) determines is technologically feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)) Furthermore, DOE may not adopt any standard that would not result in the significant conservation of energy. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(B))
Moreover, DOE may not prescribe a standard (1) for certain products, including distribution transformers, if no test procedure has been established for the product, or (2) if DOE determines by rule that the establishment of such standard will not result in significant conservation of energy (or, for certain products, water), or is not technologically feasible or economically justified. ((42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(A)-(B)) In deciding whether a proposed standard is economically justified, DOE must determine whether the benefits of the standard exceed its burdens. Id. DOE must make this determination after receiving comments on the proposed standard, and by considering, to the greatest extent practicable, the following seven statutory factors:
(1) The economic impact of the standard on manufacturers and consumers of the products subject to the standard;
(2) The savings in operating costs throughout the estimated average life of the covered equipment in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered equipment that are likely to result from the standard;
(3) The total projected amount of energy (or as applicable, water) savings likely to result directly from the standard;
(4) Any lessening of the utility or the performance of the covered equipment likely to result from the standard;
(5) The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the standard;
(6) The need for national energy and water conservation; and
(7) Other factors the Secretary considers relevant.
(42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(I)-(VII))
Further, EPCA, as codified, establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the energy savings during the first year that the consumer will receive as a result of the standard, as calculated under the applicable test procedure. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(iii))
EPCA, as codified, also contains what is known as an “anti-backsliding” provision, which prevents the Secretary from prescribing any amended standard that either increases the maximum allowable energy use or decreases the minimum required energy efficiency of a covered product. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(1)) Also, the Secretary may not prescribe an amended or new standard if interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States in any covered product type (or class) of performance characteristics (including reliability), features, sizes, capacities, and volumes that are substantially the same as those generally available in the United States. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(4))
Additionally, EPCA specifies requirements when promulgating an energy conservation standard for a covered product that has two or more subcategories. A rule prescribing an energy conservation standard for a type (or class) of product must specify a different standard level for a type or class of products that has the same function or intended use if DOE determines that products within such group (A) consume a different kind of energy from that consumed by other covered equipment within such type (or class); or (B) have a capacity or other performance-related feature which other products within such type (or class) do not have and such feature justifies a higher or lower standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)(1)) In determining whether a performance-related feature justifies a different standard for a group of products, DOE considers such factors as the utility to the consumer of such a feature and other factors DOE deems appropriate. Id. Any rule prescribing such a standard must include an explanation of the basis on which such higher or lower level was established. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)(2))

B. Background

1. Current Standards
DOE most recently completed a review of its distribution transformer standards in a final rule published on April 18, 2013 (“April 2013 Standards Final Rule”), through which DOE prescribed the current energy conservation standards for distribution transformers manufactured on and after January 1, 2016. 78 FR 23336, 23433. These standards are set forth in DOE's regulations at 10 CFR 431.196 and are repeated in Table II.1, Table II.2, and Table II.3.

2. History of Standards Rulemaking for Distribution Transformers
On June 18, 2019, DOE published notice that it was initiating an early assessment review to determine whether any new or amended standards would satisfy the relevant requirements of EPCA for a new or amended energy conservation standard for distribution transformers and a request for information (RFI). 84 FR 28239 (“June 2019 Early Assessment Review RFI”).
On August 27, 2021, DOE published a notification of a webinar and availability of a preliminary technical support document (TSD), which announced the availability of its analysis for distribution transformers. 86 FR 48058 (“August 2021 Preliminary Analysis TSD”). The purpose of the August 2021 Preliminary Analysis TSD was to make publicly available the initial technical and economic analyses conducted for distribution transformers, and present initial results of those analyses. DOE did not propose new or amended standards for distribution transformers at that time. The initial TSD and accompanying analytical spreadsheets for the August 2021 Preliminary Analysis TSD provided the analyses DOE used to examine the potential for amending energy conservation standards for distribution transformers and provided preliminary discussions in response to a number of issues raised in comments to the June 2019 Early Assessment Review RFI. It described the analytical methodology that DOE used and each analysis DOE performed.
On January 11, 2023, DOE published a NOPR and public meeting announcement, in which DOE proposed amended energy conservation standards for distribution transformers. 88 FR 1722 (“January 2023 NOPR”). DOE proposed amended standards for liquid-immersed, low-voltage dry-type, and MVDT distribution transformers. DOE additionally proposed to establish a separate equipment class for submersible distribution transformers, with standards maintained at the levels prescribed by the April 2013 Standards Final Rule. Id. On February 16, 2023, DOE presented the proposed standards and accompanying analysis in a public meeting.
On February 22, 2023, DOE published a notice extending the comment period for the January 2023 NOPR by an additional 14 days. 88 FR 10856.
DOE received 93 comments in response to the January 2023 NOPR from the interested parties listed in Table II.4.
A parenthetical reference at the end of a comment quotation or paraphrase provides the location of the item in the public record. ^{34} To the extent that interested parties have provided written comments that are substantively consistent with any oral comments provided during the February 16, 2023, public meeting, DOE cites the written comments throughout this final rule. Any oral comments provided during the webinar that are not substantively addressed by written comments are summarized and cited separately throughout this final rule.
^{34} The parenthetical reference provides a reference for information located in the docket of DOE's rulemaking to develop energy conservation standards for distribution transformers. (Docket No. EERE-2019-BT-STD-0018, which is maintained at www.regulations.gov ). The references are arranged as follows: (commenter name, comment docket ID number, page of that document).

III. General Discussion
DOE developed this final rule after a review of the market for the subject distribution transformers. DOE also considered comments, data, and information from interested parties that represent a variety of interests. This notice addresses issues raised by these commenters.

A. General Comments
This section summarizes general comments received from interested parties regarding rulemaking timing and process.
DOE received several comments recommending DOE pursue policies for saving energy or strengthening the supply chain either in place of or in addition to revised distribution transformer efficiency standards. Specifically, Standards Michigan commented that distribution transformers are oversized and recommended DOE work with electrical code committees to encourage proper distribution transformer sizing. (Standards Michigan, No. 109 at p. 1) APPA recommended DOE consider other efficiency measures to conserve energy, such as improving building codes and increasing the size of service conductors to reduce transmission losses. (APPA, No. 103 at p. 3) Pugh Consulting commented that DOE should work with the U.S. Environmental Protection Agency (EPA) to accelerate the permitting process under the Clean Air Act and Clean Water Act and to allow steel and transformer manufacturers to engage in nitrogen oxide (NOx) emission trading under EPA's Good Neighbor Plan. (Pugh Consulting, No. 117 at p. 7) Pugh Consulting further recommended DOE remove tariffs from friendly nations and explore agreements to increase electrical steel imports from these nations. (Pugh Consulting, No. 117 at p. 7) EVgo commented that DOE should use Defense Production Act investments to increase transformer supply to accommodate the increases in demand that are supporting administration electrification goals. (EVgo, No. 111 at p. 2)
DOE notes that this final rule pertains only to energy conservation standards for distribution transformers, and any efforts to amend national electrical codes, building codes, or other Federal regulatory programs and policies are beyond the scope of this rulemaking. DOE notes it is actively working with fellow government agencies and industry to better address the current supply chain challenges impacting the distribution transformer market, as well as the broader electricity industry. ^{35}
^{35} See Department of Energy. DOE Actions to Unlock Transformers and Grid Component Production. Available at www.energy.gov/policy/articles/doe-actions-unlock-transformer-and-grid-component-production (accessed Oct. 27, 2023).
Several commenters disagreed with DOE's assessment that the proposed standards are technologically feasible and economically justified generally.
Cliffs commented that DOE standards are not economically justified. (Cliffs, No. 105 at pp. 13-14) NAHB commented that the proposed standards are not economically justified because the benefits do not outweigh the costs. NAHB added that DOE's designation of economic justification is subjective and would be impacted by regulations from other agencies. (NAHB, No. 106 at pp. 2-3) SBA commented that the proposed standards are not economically justified due to the additional costs associated with amorphous cores and the significant shock to the market from a lack of market competition. (SBA, No. 100 at pp. 6-7) NRECA commented that the proposed standards are neither economically justified nor technologically feasible because DOE's NOPR is based on flawed assumptions. (NRECA, No. 98 at pp. 1-2) Pugh Consulting commented that DOE's proposal does not properly consider the requirements established under the Energy Policy Act of 2005. (Pugh Consulting, No. 117 at p. 2)
APPA commented that DOE's requests for comment in the January 2023 NOPR indicate some technical questions are unresolved and, therefore, DOE should address these questions before issuing any final rule. (APPA, No. 103 at pp. 17-18) Cliffs commented that insufficient collaboration with stakeholders was conducted prior to publication of the NOPR and because of that, the NOPR contains flawed assumptions and oversteps DOE's authority. (Cliffs, No. 105 at p. 2)
Entergy recommended that instead of finalizing the proposed rule, DOE should (1) adopt a standard that does not require a full move to amorphous or (2) use its authority to issue a determination that no new standard is required, which would allow DOE to work with industry through the Electricity Subsector Coordinating Council (ESCC) to further study the cost and benefits of enacting this rule and return with recommendations prior to 2027. (Entergy, No. 114 at p. 4)
CEC commented that DOE should ensure it adopts a final rule by June 30, 2024, because EPCA required DOE to update this standard by April 2019. (CEC, No. 124 at p. 2)
As stated, DOE has provided numerous notices with extensive comment periods to ensure stakeholders have an opportunity to provide data and to identify or correct any concerns in DOE's analysis of amended energy conservation standards. DOE has reviewed the many comments, data, and feedback received in response to the January 2023 NOPR and updated its analysis based on this information, as discussed throughout this final rule. In this final rule, DOE is adopting efficiency standards based on, but importantly different from, those proposed in the January 2023 NOPR. DOE is adopting standards that are expected to require significantly less amorphous material and extend the compliance period by two years, relative to what was proposed, which will reduce the burden on manufacturers and allow manufacturers considerable flexibility to meet standards without near-term supply chain impacts. DOE has concluded that the amended standards adopted in this final rule are technologically feasible and economically justified. A detailed discussion of DOE's analysis and conclusion is provided in section V.C of this document.
Specific comments regarding DOE's analysis are discussed in further detail below.

B. Equipment Classes and Scope of Coverage
This final rule covers the COMMERCIAL AND INDUSTRIAL equipment that meet the definition of “distribution transformer” as codified at 10 CFR 431.192.
When evaluating and establishing energy conservation standards, DOE divides covered products into equipment classes by the type of energy used or by capacity or other performance-related features that justify different standards. In making a determination whether a performance-related feature justifies a different standard, DOE must consider the utility of the feature to the consumer and other factors DOE determines are appropriate. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)) The distribution transformer equipment classes considered in this final rule are discussed in detail in section IV.A.2 of this document.
This final rule covers distribution transformers, which are currently defined as a transformer that (1) has an input voltage of 34.5 kV or less; (2) has an output voltage of 600 V or less; (3) is rated for operation at a frequency of 60 Hz; and (4) has a capacity of 10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for dry-type units; but (5) the term “distribution transformer” does not include a transformer that is an autotransformer; drive (isolation) transformer; grounding transformer; machine-tool (control) transformer; non-ventilated transformer; rectifier transformer; regulating transformer; sealed transformer; special-impedance transformer; testing transformer; transformer with tap range of 20 percent or more; uninterruptible power supply transformer; or welding transformer. 10 CFR 431.192.
See section IV.A.1 of this document for discussion of the scope of coverage and product classes analyzed in this final rule.

C. Test Procedure
EPCA sets forth generally applicable criteria and procedures for DOE's adoption and amendment of test procedures. (42 U.S.C. 6314(a)) Manufacturers of covered equipment must use these test procedures as the basis for certifying to DOE that their product complies with the applicable energy conservation standards and as the basis for any representations regarding the energy use or energy efficiency of the equipment. (42 U.S.C. 6316(e)(1); 42 U.S.C. 6295(s); and 42 U.S.C. 6314(d)). Similarly, DOE must use these test procedures to evaluate whether a basic model complies with the applicable energy conservation standard(s). 10 CFR 429.110(e). The current test procedure for distribution transformers is codified at 10 CFR part 431, subpart K, appendix A (“appendix A”). Appendix A includes provisions for determining percentage efficiency at rated per-unit load (PUL), the metric on which current standards are based. 10 CFR 431.193.
On September 14, 2021, DOE published a test procedure final rule for distribution transformers that contained revised definitions for certain terms, updated provisions based on the latest versions of relevant industry test standards, maintained PUL for the certification of efficiency, and added provisions for representing efficiency at alternative PULs and reference temperatures. 86 FR 51230 (“September 2021 TP Final Rule”). DOE determined that the amendments to the test procedure adopted in the September 2021 TP Final Rule do not alter the measured efficiency of distribution transformers or require retesting or recertification solely as a result of DOE's adoption of the amendments to the test procedure. 86 FR 51230, 51249.
Carte commented that they are not sure how to report data for a transformer with a dual-rated kVA based on the division of single-phase and three-phase power. (Carte, No. 140 at p. 9)
For distribution transformers, efficiency must be determined for each basic model, as defined in 10 CFR 431.192. Questions regarding how to report data for a specific unit can be submitted to ApplianceStandardsQuestions@ee.doe.gov.
Eaton commented that if DOE adopts higher efficiency standards, DOE should revisit the alternative methods for determining energy efficiency and energy use (AEDM) tolerance requirements in 10 CFR 429.70, because the original tolerances were based on a much higher number of absolute losses and amended standards would be based on a much smaller number of losses. (Eaton, No. 137 at pp. 29-30) Therefore, even though the difference in watts of loss could be similar, the percentage difference in losses may exceed the current requirements in 10 CFR 429.70. Id.
DOE notes that AEDM requirements are handled in a separate rulemaking that spans all certification, labeling, and enforcement provisions across many products and equipment ( see Docket No. EERE-2023-BT-CE-0001). AEDMs are widely used in certifying the efficiency of distribution transformers and DOE intends to continue to allow this under amended efficiency standards. DOE encourages stakeholders to submit any comment and data regarding distribution transformer AEDM tolerances to the docket referenced above.

D. Technological Feasibility

1. General
As discussed, any new or amended energy conservation standard must be designed to achieve the maximum improvement in energy efficiency that DOE determines is technologically feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A))
To determine whether potential amended standards would be technologically feasible, DOE first develops a list of all known technologies and design options that could improve the efficiency of the products or equipment that are the subject of the rulemaking. DOE considers technologies incorporated in commercially available products or in working prototypes to be “technologically feasible.” 10 CFR 431.4; 10 CFR 430, subpart C, appendix A, sections 6(b)(3)(i) and 7(b)(1). Section IV.A.3 of this document discusses the technology options identified by DOE for this analysis. For further details on the technology assessment conducted for this final rule, see chapter 3 of the final rule TSD.
After DOE has determined which, if any, technologies and design options are technologically feasible, it further evaluates each technology and design option in light of the following additional screening criteria: (1) practicability to manufacture, install, and service; (2) adverse impacts on product utility or availability; (3) adverse impacts on health or safety; and (4) unique-pathway proprietary technologies. 10 CFR 431.4; 10 CFR 430, subpart C, appendix A, sections 6(b)(3)(ii) through(v) and 7(b)(2) through(5). Those technology options that are “screened out” based on these criteria are not considered further. Those technology and design options that are not screened out are considered as the basis for higher efficiency levels that DOE could consider for potential amended standards. Section IV.B of this document discusses the results of this screening analysis conducted for this final rule. For further details on the screening analysis conducted for this final rule, see chapter 4 of the final rule TSD.

2. Maximum Technologically Feasible Levels
EPCA requires that for any proposed rule that prescribes an amended or new energy conservation standard, or prescribes no amendment or no new standard for a type (or class) of covered product, DOE must determine the maximum improvement in energy efficiency or maximum reduction in energy use that is technologically feasible for each type (or class) of covered products. (42 U.S.C. 6313(a); 42 U.S.C. 6295(p)(1)). Accordingly, in the engineering analysis, DOE identifies the maximum efficiency level currently available on the market. DOE also defines a “max-tech” efficiency level, representing the maximum theoretical efficiency that can be achieved through the application of all available technology options retained from the screening analysis. ^{36} In many cases, the max-tech efficiency level is not commercially available because it is not currently economically feasible.
^{36} In applying these design options, DOE would only include those that are compatible with each other that when combined, would represent the theoretical maximum possible efficiency.

E. Energy Savings

1. Determination of Savings
For each trial standard level (TSL), DOE projected energy savings from application of the TSL to distribution transformers purchased in the 30-year period that begins in the year of compliance with the amended standards (2029-2058). ^{37} The savings are measured over the entire lifetime of equipment purchased in the 30-year analysis period. DOE quantified the energy savings attributable to each TSL as the difference in energy consumption between each standards case and the no-new-standards case. The no-new-standards case represents a projection of energy consumption that reflects how the market for a product would likely evolve in the absence of amended energy conservation standards.
^{37} DOE also presents a sensitivity analysis that considers impacts for products shipped in a 9-year period. See section V.B.3 of this document for additional detail.
DOE used its national impact analysis (NIA) spreadsheet models to estimate national energy savings (NES) from potential amended standards for distribution transformers. The NIA spreadsheet model (described in section IV.H of this document) calculates energy savings in terms of site energy, which is the energy directly consumed by products at the locations where they are used. For electricity, DOE reports national energy savings in terms of primary energy savings, which is the savings in the energy that is used to generate and transmit the site electricity. For natural gas, the primary energy savings are considered to be equal to the site energy savings. DOE also calculates NES in terms of FFC energy savings. The FFC metric includes the energy consumed in extracting, processing, and transporting primary fuels ( i.e., coal, natural gas, petroleum fuels), and thus presents a more complete picture of the impacts of energy conservation standards. ^{38} DOE's approach is based on the calculation of an FFC multiplier for each of the energy types used by covered products or equipment. For more information on FFC energy savings, see section IV.H.2 of this document.
^{38} The FFC metric is discussed in DOE's statement of policy and notice of policy amendment. 76 FR 51282 (Aug. 18, 2011), as amended at 77 FR 49701 (Aug. 17, 2012).

2. Significance of Savings
To adopt any new or amended standards for a covered product, DOE must determine that such action would result in significant energy savings. (42 U.S.C. 6295(o)(3)(B))
The significance of energy savings offered by a new or amended energy conservation standard cannot be determined without knowledge of the specific circumstances surrounding a given rulemaking. ^{39} For example, some covered products and equipment have most of their energy consumption occur during periods of peak energy demand. The impacts of these products on the energy infrastructure can be more pronounced than products with relatively constant demand. Accordingly, DOE evaluates the significance of energy savings on a case-by-case basis, taking into account the significance of cumulative FFC national energy savings, the cumulative FFC emissions reductions, and the need to confront the global climate crisis, among other factors.
^{39} The numeric threshold for determining the significance of energy savings established in a final rule published on February 14, 2020 (85 FR 8626, 8670), was subsequently eliminated in a final rule published on December 13, 2021 (86 FR 70892).
As stated, the standard levels adopted in this final rule for all distribution transformers are projected to result in national energy savings of 4.58 quad, the equivalent of the primary annual energy use of 49.2 million homes . Based on the amount of FFC savings, the corresponding reduction in emissions, and the need to confront the global climate crisis, DOE has determined the energy savings from the standard levels adopted in this final rule are “significant” within the meaning of 42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(B).

F. Economic Justification

1. Specific Criteria
As noted previously, EPCA provides seven factors to be evaluated in determining whether a potential energy conservation standard is economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(I)-(VII)) The following sections discuss how DOE has addressed each of those seven factors in this rulemaking.

a. Economic Impact on Manufacturers and Consumers
In determining the impacts of potential new or amended standards on manufacturers, DOE conducts an MIA, as discussed in section IV.J. DOE first uses an annual cash flow approach to determine the quantitative impacts. This step includes both a short-term assessment—based on the cost and capital requirements during the period between when a regulation is issued and when entities must comply with the regulation—and a long-term assessment over a 30-year period. The industry-wide impacts analyzed include (1) INPV, which values the industry on the basis of expected future cash flows; (2) cash flows by year; (3) changes in revenue and income; and (4) other measures of impact, as appropriate. Second, DOE analyzes and reports the impacts on different types of manufacturers, including impacts on small manufacturers. Third, DOE considers the impact of standards on domestic manufacturer employment and manufacturing capacity, as well as the potential for standards to result in plant closures and loss of capital investment. Finally, DOE takes into account cumulative impacts of various DOE regulations and other regulatory requirements on manufacturers.
For individual consumers, measures of economic impact include the changes in LCC and PBP associated with new or amended standards. These measures are discussed further in the following section. For consumers in the aggregate, DOE also calculates the national net present value of the consumer costs and benefits expected to result from particular standards. DOE also evaluates the impacts of potential standards on identifiable subgroups of consumers that may be affected disproportionately by a standard.

b. Savings in Operating Costs Compared to Increase in Price (LCC and PBP)
EPCA requires DOE to consider the savings in operating costs throughout the estimated average life of the covered product in the type (or class) compared to any increase in the price of, or in the initial charges for, or maintenance expenses of, the covered product that are likely to result from a standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(II)) DOE conducts this comparison in its LCC and PBP analysis.
The LCC is the sum of the purchase price of a product (including its installation) and the operating cost (including energy, maintenance, and repair expenditures) discounted over the lifetime of the product. The LCC analysis requires a variety of inputs, such as product prices, product energy consumption, energy prices, maintenance and repair costs, product lifetime, and discount rates appropriate for consumers. To account for uncertainty and variability in specific inputs, such as product lifetime and discount rate, DOE uses a distribution of values, with probabilities attached to each value.
The PBP is the estimated amount of time (in years) it takes consumers to recover the increased purchase cost (including installation) of a more efficient product through lower operating costs. DOE calculates the PBP by dividing the change in purchase cost due to a more stringent standard by the change in annual operating cost for the year that standards are assumed to take effect.
For its LCC and PBP analysis, DOE assumes that consumers will purchase the covered equipment in the first year of compliance with new or amended standards. The LCC savings for the considered efficiency levels are calculated relative to the case that reflects projected market trends in the absence of new or amended standards. DOE's LCC and PBP analysis is discussed in further detail in section IV.F.

c. Energy Savings
Although significant conservation of energy is a separate statutory requirement for adopting an energy conservation standard, EPCA requires DOE, in determining the economic justification of a standard, to consider the total projected energy savings that are expected to result directly from the standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(III)) As discussed in section IV.H, DOE uses the NIA spreadsheet models to project national energy savings.

d. Lessening of Utility or Performance of Products
In establishing equipment classes, and in evaluating design options and the impact of potential standard levels, DOE evaluates potential standards that would not lessen the utility or performance of the considered equipment. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(IV)) Based on data available to DOE, the standards adopted in this document would not reduce the utility or performance of the equipment under consideration in this rulemaking.

e. Impact of Any Lessening of Competition
EPCA directs DOE to consider the impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from a standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(V)) It also directs the Attorney General to determine the impact, if any, of any lessening of competition likely to result from a standard and to transmit such determination to the Secretary within 60 days of the publication of a proposed rule, together with an analysis of the nature and extent of the impact. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(ii))
NAHB expressed concern that DOE has not published the determination made by the Attorney General on the impact of any lessening of competition that may result from this rule and recommended DOE withdraw its proposal until stakeholders have had the opportunity to review this document. (NAHB, No. 106 at p. 2)
Under EPCA, the Attorney General is required to make a determination of the impact, if any, of any lessening of competition likely to result from such standard no later than 60 days after publication of the proposed rule. DOE is then required to publish any such determination in the Federal Register . To assist the Department of Justice (DOJ) in making such a determination, DOE transmitted copies of its proposed rule and the NOPR TSD to the Attorney General for review, with a request that the DOJ provide its determination on this issue. In its assessment letter responding to DOE, DOJ concluded that the proposed energy conservation standards for distribution transformers are unlikely to have a significant adverse impact on competition. In accordance with EPCA, DOE is publishing the Attorney General's assessment at the end of this final rule.

f. Need for National Energy Conservation
DOE also considers the need for national energy and water conservation in determining whether a new or amended standard is economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(VI)) The energy savings from the adopted standards are likely to provide improvements to the security and reliability of the Nation's energy system. Reductions in the demand for electricity also may result in reduced costs for maintaining the reliability of the Nation's electricity system. DOE conducts a utility impact analysis to estimate how standards may affect the Nation's needed power generation capacity, as discussed in section IV.M of this document.
DOE maintains that environmental and public health benefits associated with the more efficient use of energy are important to take into account when considering the need for national energy conservation. The adopted standards are likely to result in environmental benefits in the form of reduced emissions of air pollutants and GHGs associated with energy production and use. DOE conducts an emissions analysis to estimate how potential standards may affect these emissions, as discussed in section IV.K of this document; the estimated emissions impacts are reported in section V.B.6 of this document. DOE also estimates the economic value of emissions reductions resulting from the considered TSLs, as discussed in section IV.L of this document.

g. Other Factors
In determining whether an energy conservation standard is economically justified, DOE may consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)(VII)) To the extent DOE identifies any relevant information regarding economic justification that does not fit into the other categories described previously, DOE could consider such information under “other factors.”

2. Rebuttable Presumption
EPCA creates a rebuttable presumption that an energy conservation standard is economically justified if the additional cost to the equipment that meets the standard is less than three times the value of the first year's energy savings resulting from the standard, as calculated under the applicable DOE test procedure. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(iii)) DOE's LCC and PBP analyses generate values used to calculate the effect potential amended energy conservation standards would have on the PBP for consumers. These analyses include, but are not limited to, the 3-year PBP contemplated under the rebuttable-presumption test. In addition, DOE routinely conducts an economic analysis that considers the full range of impacts to consumers, manufacturers, the Nation, and the environment, as required under 42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i). The results of this analysis serve as the basis for DOE's evaluation of the economic justification for a potential standard level (thereby supporting or rebutting the results of any preliminary determination of economic justification). The rebuttable presumption payback calculation is discussed in section IV.F.11 of this final rule.

IV. Methodology and Discussion of Related Comments
This section addresses the analyses DOE has performed for this rulemaking with regard to distribution transformers. Separate subsections address each component of DOE's analyses.
DOE used several analytical tools to estimate the impact of the standards considered in this document. The first tool is a spreadsheet that calculates the LCC savings and PBP of potential amended or new energy conservation standards. The national impacts analysis uses a second spreadsheet set that provides shipments projections and calculates national energy savings and net present value of total consumer costs and savings expected to result from potential energy conservation standards. DOE uses the third spreadsheet tool, the Government Regulatory Impact Model (GRIM), to assess manufacturer impacts of potential standards. These three spreadsheet tools are available on the DOE website for this rulemaking: www.regulations.gov/docket/EERE-2019-BT-STD-0018. Additionally, DOE used output from the latest version of the Energy Information Administration's (EIA's) Annual Energy Outlook ( AEO ) for the emissions and utility impact analyses.

A. Market and Technology Assessment
DOE develops information in the market and technology assessment that provides an overall picture of the market for the products concerned, including the purpose of the products, the industry structure, manufacturers, market characteristics, and technologies used in the products. This activity includes both quantitative and qualitative assessments, based primarily on publicly available information. The subjects addressed in the market and technology assessment for this rulemaking include (1) a determination of the scope of the rulemaking and product classes, (2) manufacturers and industry structure, (3) existing efficiency programs, (4) shipments information, (5) market and industry trends, and (6) technologies or design options that could improve the energy efficiency of distribution transformers. The key findings of DOE's market assessment are summarized in the following sections. See chapter 3 of the final rule TSD for further discussion of the market and technology assessment.

1. Scope of Coverage
The current definition for a distribution transformer codified in 10 CFR 431.192 is the following:
Distribution transformer means a transformer that—(1) has an input voltage of 34.5 kV or less; (2) has an output voltage of 600 V or less; (3) is rated for operation at a 60 Hz; and (4) has a capacity of 10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for dry-type units; but (5) The term “distribution transformer” does not include a transformer that is an—(i) autotransformer; (ii) drive (isolation) transformer; (iii) grounding transformer; (iv) machine-tool (control) transformer; (v) non-ventilated; (vi) rectifier transformer; (vii) regulating transformer; (viii) sealed transformer; (ix) special-impedance transformer; (x) testing transformer; (xi) transformer with tap range of 20 percent or more; (xii) uninterruptible power supply transformer; or (xiii) Welding transformer.
In the January 2023 NOPR, DOE discussed and proposed minor edits to the definitions of equipment excluded from the definition of distribution transformer. In response to the January 2023 NOPR, DOE received additional comments on its proposed definitional edits. These detailed comments are discussed below.

a. Autotransformers
The EPCA definition of distribution transformer excludes “a transformer that is designed to be used in a special purpose application and is unlikely to be used in general purpose applications, such as . . . [an] auto-transformer . . .”. (42 U.S.C. 6291(35)(b)(ii)) DOE has defined autotransformer as “a transformer that: (1) has one physical winding that consists of a series winding part and a common winding part; (2) has no isolation between its primary and secondary circuits; and (3) during step-down operation, has a primary voltage that is equal to the total of the series and common winding voltages, and a secondary voltage that is equal to the common winding voltage.” 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that, while stakeholders suggested that there may be certain applications for which autotransformers may be substitutable for an isolation transformer, these substitutions would be limited to specific applications and not common enough to regard as general practice. 88 FR 1722, 1741. Further, DOE stated that, because autotransformers do not provide galvanic isolation, they are unlikely to be used in at least some general-purpose applications. DOE did not propose to amend the exclusion of autotransformers under the distribution transformer definition. Id.
Schneider commented that autotransformers were used in the 1970's for distribution application. However, they do not allow for the creation of a neutral on the secondary side of the transformer nor do they allow for isolating the secondary and primary windings for power quality benefits. (Schneider, No. 101 at p. 15) Schneider commented that for applications with small loads, based on the increased purchase price and footprints at the proposed efficiency levels, the market will begin evaluating autotransformers and applying them to certain distribution applications. Id. Schneider recommended the statutory definition of low-voltage transformer be modified through legislation to subject autotransformers to energy conservation standards. Id. at p. 17.
DOE agrees that in certain applications, autotransformers may be capable of serving as a replacement for general purpose transformers. However, as discussed, the isolation and power quality benefits of distribution transformers make it unlikely that autotransformers would be widely viewed or used as a substitute for most general purpose distribution transformers. DOE notes that manufacturer literature already markets autotransformers as an “economical alternative to general purpose distribution isolation transformers to adjust the supply voltage to match specific load requirements when load isolation from the supply line is not required.” ^{40} As noted in the marketing, autotransformers are only suitable in transformer applications where load isolation is not required.
^{40} Hammond Power Solutions. Autotransformers, 2023. documents.hammondpowersolutions.com/documents/Literature/Specialty/HPS-Autotransformers-Brochure.pdf?_gl=1*db1907*_ga*NTA0ODk1MjQzLjE2NzExMzEzMTM.*_ga_RTZEGSXND8*MTY4MzIxNTc5My42Ni4xLjE2ODMyMTcyNjcuNTguMC4w .
Despite autotransformers being less expensive, having a smaller footprint than general purpose distribution transformers, and being marketed as suitable in certain applications, autotransformers have not seen widespread use in general purpose applications and their use has been limited to special purposes. While autotransformers may be capable of meeting similar efficiency regulations as general purpose distribution transformers, they are statutorily excluded from the definition of distribution transformer on account of being reserved for special purpose applications. Further, stakeholder comments reiterate that there are legitimate shortcomings of autotransformer that makes significant substitution unlikely. Based on this feedback, DOE has concluded that autotransformers are designed to be used in a special purpose application and are unlikely to be used in general purpose applications due to these shortcomings. Therefore, DOE is not amending the exclusion of autotransformers under the distribution transformer definition. DOE will continue to evaluate the extent to which autotransformers are used in general purpose applications in future rulemakings.

b. Drive (Isolation) Transformers
The EPCA definition of distribution transformer excludes a transformer that is designed to be used in a special purpose application and is unlikely to be used in general purpose applications, such as drive transformers. (42 U.S.C. 6291(35)(b)(ii)). DOE defines a drive (isolation) transformer as a “transformer that (1) isolates an electric motor from the line; (2) accommodates the added loads of drive-created harmonics; and (3) is designed to withstand the mechanical stresses resulting from an alternating current adjustable frequency motor drive or a direct current motor drive.” 10 CFR 431.192.
In the January 2023 NOPR, DOE responded to comments by Schneider and Eaton submitted on the August 2021 Preliminary Analysis TSD that claimed drive-isolation transformers have historically been sold with non-standard low-voltage ratings corresponding to typical motor input voltages, and as such were unlikely to be used in general-purpose applications. (Schneider, No. 49 at p. 3; Eaton, No. 55 at p. 3) Schneider and Eaton commented that they had seen a recent increase in drive-isolation transformers specified as having either a “480Y/277” or “208Y/120” voltage secondary, making it more difficult to ascertain whether these transformers were being used in general purpose applications. (Schneider, No. 49 at p. 3; Eaton, No. 55 at p. 3)
In response to these comments, DOE noted that while some drive-isolation transformers could, in theory, be used in general purpose applications, no evidence exists to suggest this is common practice. 88 FR 1722, 1742. Therefore, DOE concluded that drive-isolation transformers remain an example of a transformer that is designed to be used in special purpose applications and excluded by statute. However, DOE also noted that the overwhelming majority of general purpose applications use either 208Y/120 or 480Y/277 voltage while the overwhelming majority of drive-isolation transformers are designed with alternative voltages designed to match specific motor drives. Id. Therefore, DOE stated that a drive-isolation transformer with a rated secondary voltage of 208Y/120 or 480Y/277 is considerably more likely to be used in general purpose applications.
DOE proposed to amend the definition of drive (isolation) transformer to include the criterion that drive-isolation transformers have an output voltage other than 208Y/120 and 480Y/277. 88 FR 1722, 1742. DOE requested comment on its determination that a drive-isolation transformer with these common voltage ratings is likely to be used in general purpose applications and if any other common voltage ratings would indicate likely use in general purpose applications. Id.
In response, Schneider commented that it agrees with the evaluation completed by DOE and the proposed definition. (Schneider, No. 101 at p. 3) Schneider recommended Congress modify the statutory definition of LVDT distribution transformer to include all six-pulse drive-isolation transformers. (Schneider, No. 101 at p. 17) Schneider further commented that even if customers do need a secondary 208Y/120 or 480Y/277 voltage for their drive applications, they would still be able to purchase a transformer, but it would just be an energy efficient model. (Schneider, No. 101 at p. 3) Schneider has previously commented that six-pulse drive-isolation transformers are within the LVDT scope in Canada and their energy conservation standards align with current DOE energy conservation standards. (Schneider, No. 49 at p. 4) Therefore, energy efficient models are readily available for purchase.
NEMA commented that voltage ratings are a poor measure to capture the distinction between general purpose applications and special purpose applications. (NEMA, No. 141 at p. 7) NEMA did not provide an alternative recommendation.
DOE has previously stated that it intends to strictly and narrowly construe the exclusions from the definition of “distribution transformer.” 84 FR 24972, 24979 (April 27, 2009). Drive-isolation transformers are excluded from the definition of distribution transformers because 42 U.S.C. 6291 lists them as a special purpose product unlikely to be used in general purpose applications. (42 U.S.C. 6291(35)(b)(ii)) Therefore, even if all six-pulse drive-isolation transformers may be able to meet energy conservation standards, most drive-isolation transformers remain statutorily excluded since they are designed to be used in special purpose applications and are unlikely to be used in a general purpose application. To the extent that some transformers are marketed as drive-isolation transformers with rated output voltages aligning with common distribution voltages, DOE is unable to similarly conclude that these transformers are designed to be used in special purpose applications and are unlikely to be used in general purpose applications.
While NEMA commented that relying on output voltages may not capture the distinctions between all drive-isolation transformers and distribution transformers, NEMA did not provide any data to refute DOE's tentative determination that a transformer marketed as a drive-isolation transformer with rated output voltages aligning with common distribution voltages would be significantly more likely to be used in general purpose distribution applications. Further, as stated by Schneider, DOE's proposal does not prevent consumers that need these secondary voltages for their drive applications from purchasing a suitable product, it only requires them to purchase a product that meets energy conservation standards.
Based on the foregoing discussion, DOE is finalizing its proposed definition for drive (isolation) transformer to mean “a transformer that: (1) isolates an electric motor from the line; (2) accommodates the added loads of drive-created harmonics; (3) is designed to withstand the additional mechanical stresses resulting from an alternating current adjustable frequency motor drive or a direct current motor drive; and (4) has a rated output voltage that is neither `208Y/120' nor `480Y/277'.”

c. Special-Impedance Transformers
Impedance is an electrical property that relates voltage across and current through a distribution transformer. It may be selected to balance voltage drop, overvoltage tolerance, and compatibility with other elements of the local electrical distribution system. A transformer built to operate outside of the normal impedance range for that transformer's kVA rating, as specified in Tables 1 and 2 of 10 CFR 431.192 under the definition of “special-impedance transformer,” is excluded from the definition of “distribution transformer.” 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that the current tables in the “special-impedance transformer” definition do not explicitly address how to treat non-standard kVA values ( e.g., kVA values between those listed in the “special-impedance transformer” definition). 88 FR 1722, 1742-1743. DOE proposed to amend the definition of “special-impedance transformer” to specify that “distribution transformers with kVA ratings not appearing in the tables shall have their minimum normal impedance and maximum normal impedance determined by linear interpolation of the kVA and minimum and maximum impedances, respectively, of the values immediately above and below that kVA rating.” Id. DOE noted that this approach was consistent with the approach specified for determining the efficiency requirements of distribution transformers of non-standard kVA rating ( i.e., using a linear interpolation from the nearest bounding kVA values listed in the table). See 10 CFR 431.196. DOE requested comment on this proposed amendment and whether it provided sufficient clarity as to how to treat the normal impedance ranges for non-standard kVA distribution transformers. Id.
In response to the January 2023 NOPR, Prolec GE commented that the proposed definition is a helpful clarification. (Prolec GE, No. 120 at p. 5). NEMA, Howard, and Eaton all recommended DOE specify normal impedance for kVA ranges rather than using a linear interpolation method. (NEMA, No. 141 at pp. 7-8; Howard, No. 116 at pp. 6-7; Eaton, No. 137 at pp. 5-11)
Eaton further commented that the industry assumption was that a given impedance range was intended to apply to all non-standard kVA ratings occurring between two standard kVA ratings and the confusion was as to whether the impedance ranged corresponding to the lower, or the upper preferred kVA rating should be used. (Eaton, No. 137 at p. 5) Eaton identified two potential approaches, the ascending approach, wherein the impedance range is intended to change only upon reaching the next higher preferred kVA, and the descending approach, wherein the impedance range is intended to change immediately upon exceeding the lower kVA rating. (Eaton, No. 137 at pp. 5-7). Eaton commented that the normal impedance ranges change gradually with the only significant jump being between 500 to 666 kVA single-phase and 500 to 749 kVA three-phase, where the lower bound of the normal impedance range jumps from 1.0 percent to 5.0 percent. (Eaton, No. 137 at p. 7)
Eaton provided shipment data for years 2016 through 2022 for non-standard kVAs that coincide with this jump in the lower-bound of normal impedance. (Eaton, No. 137 at pp. 7-8) Eaton commented that they built zero non-standard kVA single-phase units between 501 and 666 kVA and 80 non-standard kVA three-phase units. Eaton added that of those 80 units, 57 were outside of scope regardless of the impedance, while the remaining 23 units were treated as within DOE's scope of coverage. Id. Of those units, only seven units were between 1.5 and 5.0 percent impedance. Meaning under the ascending interpretation, these seven units would be in-scope and under the descending interpretation, these seven units would be out of scope. Eaton provided the impedance for all 23 units. Id. DOE notes that all 23 units would be within scope under both the ascending interpretation and the proposed linear interpolation method, as the unit impedance values fall within the normal impedance range of both the ascending interpretation and the proposed linear interpolation method.
Eaton commented that current industry standards do not provide a clear answer but in comparing the ascending interpretation and the proposed linear interpolation, the linear interpolation is somewhat more computationally cumbersome and more confusing to audit. (Eaton, No. 137 at pp. 8-11) For these reasons, Eaton recommended DOE adopt normal-impedance tables with an ascending interpretation on kVA ranges. (Eaton, No. 137 at p. 11).
While Howard and NEMA didn't explicitly discuss the differences between the ascending interpretation, descending interpretation, and linear-interpolation methods, both recommended tables that apply the ascending interpretation. (NEMA, No. 141 at pp. 7-8; Howard, No. 116 at pp. 6-7)
As noted, DOE has not previously stated what the normal impedance ranges for non-standard kVA transformers are intended to be. While DOE proposed a linear interpolation, Eaton's data suggested that adopting an ascending interpretation would include an identical number of transformers within scope of the distribution transformer rulemaking. Further, multiple stakeholders preferred the simplicity of the ascending interpretation. Given that the number of impacted transformers is unchanged, the simplicity of defining normal impedance based on kVA ranges, and stakeholder support for the ascending interpretation, DOE is adopting amended tables to specify the normal impedance ranges for non-standard kVA transformers using an ascending interpretation. The adopted normal impedance ranges for each kVA range are given in Table IV.1 and Table IV.2.

d. Tap Range of 20 Percent or More
Distribution transformers are commonly sold with voltage taps that allow manufacturers to adjust for minor differences in the input or output voltage. Transformers with multiple voltage taps, the highest of which equals at least 20 percent more than the lowest, computed based on the sum of the deviations of the voltages of these taps from the transformer's nominal voltage, are excluded from the definition of distribution transformers. 10 CFR 431.192. ( See also 42 U.S.C. 6291(35)(B)(i))
In the response to the August 2021 Preliminary Analysis TSD, Schneider, NEMA, and Eaton recommended that only full-power taps should be permitted for tap range calculations. (Eaton, No. 55 at pp. 5-6; Schneider, No. 49 at pp. 5-6; NEMA, No. 50 at p. 4) Schneider and Eaton commented that the nominal voltage by which the tap range is calculated is a consumer choice and could result in two physically identical transformers being subject to standards or not, depending on the choice of nominal voltage. (Schneider No. 49 at p. 6; Eaton No. 55 at pp. 6-7)
In the January 2023 NOPR, DOE noted that, while traditional industry understanding of tap range is in percentages relative to the nominal voltage, stakeholder comments suggest that such a calculation can be applied such that two physically identical distribution transformers can be inside or outside of scope depending on the choice of nominal voltage. 88 FR 1722. To have a consistent standard for physically identical distribution transformers, DOE proposed to modify the calculation of tap range to only include full-power capacity taps and calculate tap range based on the transformer's maximum voltage rather than nominal voltage.
Prolec GE and NEMA commented that the proposed amendment to the calculation of a tap range of 20 percent or more was clear and removed ambiguity. (Prolec GE, No. 120 at p. 5; NEMA, No. 141 at p. 8) Howard and Eaton supported the proposed definition but recommended DOE make clarifying edits to avoid any confusion. (Howard, No. 116 at pp. 7-8; Eaton, No. 137 at p. 12)
Specifically, Eaton recommended changing DOE's proposal to use “full-power voltage taps” to read “a transformer with multiple voltage taps, each capable of operating at full, rated capacity (kVA) . . .” (Eaton, No. 137 at p. 12) Eaton commented that this clarification aligned with how full-power taps are more commonly described and clarified that full-capacity refers to kVA. Id.
Eaton and Howard also both noted that the description of how to calculate the tap range is confusing. Specifically, Eaton and Howard identified the text where DOE proposed to state “the highest of which equals at least 20% more than the lowest, computed based on the sum of the deviations of these taps from the transformer's maximum full-power voltage.” (Howard, No. 116 at pp. 7-8; Eaton, No. 137 at p. 12) Howard recommended DOE state “where the difference between the highest tap voltage and the lowest tap voltage is 20 percent or more of the highest tap voltage.” (Howard, No. 116 at pp.7-8) Eaton recommended DOE state “whose range, defined as the maximum tap voltage minus minimum tap voltage, is 20 percent or more of the maximum tap voltage rating appearing on the product nameplate.” (Eaton, No. 137 at p. 12)
Schneider commented that the proposed definition does clearly define how to calculate the tap percentage, but it does not address the fact that common LVDT products meet these criteria. (Schneider, No. 101 at p. 3) Schneider identified certain LVDT products designed to span multiple nominal voltages as having a tap-range greater than 20 percent. Id. Schneider recommended DOE modify the definition to allow for only one standard nominal voltage rating ( e.g., a transformer spanning 480V and 600V would not be exempted because it includes two standard voltage systems). Id.
Regarding Eaton's editorial suggestion as to how DOE specifies that only full-power taps are used, DOE agrees that Eaton's wording is clearer and better aligns with how industry addresses full-power taps. Therefore, DOE is adopting language that using full-power taps means “each capable of operating at full, rated capacity (kVA)”.
Regarding Eaton and Howard's editorial suggestion as to how DOE communicates the calculation for the tap range, DOE notes that the proposed definition simply modified the current definition in the CFR to be based on the transformer's maximum full-power voltage, rather than the nominal voltage. However, DOE agrees that, with more explicit directions as to how to compute the tap range, the phrasing “the highest of which equals at least 20 percent more than the lowest” could be redundant and confusing. Therefore, DOE is simplifying the wording, in accordance with Howard and Eaton's suggestions to read that “whose range, defined as the difference between the highest tap voltage and lowest tap voltage, is 20 percent or more of the highest tap voltage.”
Regarding Schneider's comment recommending that DOE only consider “standard” nominal voltage ratings to be eligible, DOE notes that the adopted test procedure for measuring the energy consumption of distribution transformers specifies how to handle reconfigurable nominal windings in the case of a dual- or multi-voltage capable transformers. ( See appendix A to subpart K of 10 CFR part 431).
Transformer taps are intended to offer consumers the ability to conduct minor corrections to system voltage. The addition of voltage taps generally adds to a manufacturer's costs and reduces the efficiency of a product due to requiring additional winding material. Therefore, EPCA listed transformers with a tap range of 20 percent or more as excluded from the scope of the distribution transformer rulemaking. ( See 42 U.S.C. 6291(35)(B)(i)) DOE's proposed amendment to the definition of a transformer with a tap range of 20 percent or more is only intended to clarify the provisions established under EPCA as to how this tap range is to be calculated across physically identical products. Transformers with tap ranges greater than 20 percent, are not within the scope of distribution transformers as defined in this final rule.
Based on the foregoing discussion, DOE is adopting a definition for transformer with a tap range of 20 percent or more to mean “a transformer with multiple voltage taps, each capable of operating at full, rated capacity (kVA), whose range, defined as the difference between the highest voltage tap and the lowest voltage tap, is 20 percent or more of the highest voltage tap.”

e. Sealed and Non-Ventilated Transformers
The statutory definition of distribution transformer excludes transformers that are designed to be used in a special purpose application and are unlikely to be used in general purpose applications, such as “sealed and non-ventilated transformers.” (42 U.S.C. 6291(356)(b)(ii)) DOE defines sealed transformer and non-ventilated transformer at 10 CFR 431.192.
In the January 2023 NOPR, DOE proposed to modify the definitions of sealed and non-ventilated transformers to clarify that only certain “dry-type” transformers meet the definition of sealed and non-ventilated transformers. 88 FR 1722, 1744 DOE requested comment on this proposed amendment. Id.
Eaton and NEMA commented that the amendment provides clarity and agreed with including it in the definition. (Eaton, No. 137 at p. 13; NEMA, No. 141 at p. 8) DOE received no further comment on the proposed definition and is finalizing the clarification that sealed and non-ventilated transformers only include “dry-type” transformers.
Regarding the statutory exclusion of non-ventilated transformers broadly, Schneider commented that the original rationale for excluding non-ventilated transformers from EPCA was because non-ventilated transformers have higher core losses, which makes it difficult to meet efficiency standards at 35-percent loading, and because their inclusion would not drive significant energy savings. (Schneider, No. 101 at pp. 8-9) DOE notes that, because non-ventilated transformers do not have airflow or oil surrounding the core and coil, they have a harder time dissipating heat than general purpose dry-type distribution transformers. Transformer thermal limitations are governed by total losses at full load ( i.e., 100-percent PUL), where load losses make up a much higher percentage of total losses. As such, manufacturers of sealed and non-ventilated transformers typically increase no-load losses to decrease load losses, and therefore meet temperature rise limitations.
Schneider commented that while non-ventilated transformers are typically used in specialty applications, ^{41} there is nothing inherent about non-ventilated transformers that would prevent them from being used in general purpose applications. (Schneider, No. 101 at pp. 8-9)
^{41} Nonventilated transformers are typically marketed for specific hazardous environment applications where airborne contaminants or large quantities of particles would potentially harm the performance of a traditional ventilated distribution transformer.
Schneider commented that non-ventilated transformers are typically larger and higher priced than general purpose LVDTs, which has historically discouraged consumers from using them in general purpose applications. (Schneider, No. 101 at p. 16) However, Schneider noted that if the proposed standards are adopted, specifically standards requiring amorphous cores, the increased volume and cost of general purpose LVDT units could become higher than non-ventilated units. Id. Schneider commented that if that were the case, manufacturers may choose to market non-ventilated transformer for general purpose applications to avoid the capital investment required to produce transformers with amorphous cores. Id. Schneider commented that if the proposed standards are finalized, it expects 50 percent of the LVDT market to purchase non-ventilated transformers instead of more efficient products. Schneider stated that because non-ventilated products are excluded from standards, the efficiency is likely to be very low, which would have a negative impact on any potential savings associated with LVDT transformers. Id. DOE notes that Schneider did not provide any specific data as to the relative increase in weight or production cost expected between non-ventilated transformers and general purpose distribution transformers to demonstrate how Schneider derived the 50 percent expected market share for non-ventilated transformers.
Schneider recommended that manufacturers work with Congress to modify the definition of low-voltage distribution transformer to remove the exclusion for non-ventilated transformers. (Schneider, No. 101 at p. 17)
DOE agrees that there are no technical features preventing a non-ventilated transformer from being used in general purpose applications. However, as described by Schneider, this substitution generally does not occur in industry because of the challenges associated with dissipating heat for non-ventilated transformers, which leads to non-ventilated transformers being larger and more expensive than a ventilated transformer of identical kVA. Further, dissipating heat becomes more of a challenge as the size of the transformer increases due to the significant amount of energy that larger transformers need to shed. As a result, the percentage increase in weight and cost of a non-ventilated transformer relative to a general purpose LVDT unit is greater for larger kVA transformers.
DOE reviewed manufacturer websites that listed product specifications and prices for both general purpose LVDTs and non-ventilated transformers (See Chapter 3 of the TSD). In general, DOE observed that the relatively higher cost and weight for non-ventilated transformers was considerably more than the modeled increase in cost and weight for even max-tech general purpose LVDTs. Therefore, non-ventilated distribution transformers are unlikely to become cost-competitive with more efficient, general purpose distribution transformers. Further, under the adopted standards, amorphous core transformers are not required for LVDTs. Therefore, it is unlikely for manufacturers to sell non-ventilated transformers into general purpose applications. As such, DOE maintains that non-ventilated transformers are statutorily excluded from the definition of distribution transformer on account of being used only in special purpose applications.

f. Step-Up Transformers
For transformers generally, the term “step-up” refers to the function of a transformer providing greater output voltage than input voltage. Step-up transformers primarily service energy producing applications, such as solar or wind electricity generation. In these applications, transformers accept an input source voltage, step-up the voltage in the transformer, and output higher voltages that feed into the electric grid. The definition of “distribution transformer” does not explicitly exclude transformers designed for step-up operation. However, most step-up transformers have an output voltage larger than the 600 V limit specified in the distribution transformer definition. See 10 CFR 431.192. ( See also 42 U.S.C. 6291(35)(A)(ii))
In the January 2023 NOPR, DOE discussed how it is technically possible to operate a step-up transformer in a reverse manner, by connecting the high-voltage to the “output” winding of a step-up transformer and the low-voltage to the “input” winding of a step-up transformer, such that it functions as a distribution transformer. 88 FR 1722, 1744. However, DOE has also previously identified that this is not a widespread practice. 78 FR 2336, 23354. Comments received in response to the 2021 Preliminary Analysis TSD confirmed that, while step-up transformers are typically less efficient than DOE standards would mandate and step-up transformers could, in theory, be used in distribution applications, this is not a common practice. 88 FR 1722, 1744. Feedback from stakeholders indicated that step-up transformers typically serve a separate and unique application, often in the renewable energy field where transformer designs may not be optimized for the distribution market but rather are optimized for integration with other equipment, such as inverters. Id. As such, DOE did not propose to amend the definition of “distribution transformer” to account for step-up transformers. Id.
DOE received additional comments specifically regarding low-voltage step-up transformers in response to the January 2023 NOPR.
Schneider commented that there is confusion as to whether low-voltage step-up transformers are included in scope and recommended DOE explicitly state in the LVDT definition that both step-up and step-down transformers are within scope. (Schneider, No. 101 at p. 4) NEMA recommended clarifying that step-up LVDT transformers are within scope since both the input and output voltages meet the definition of distribution transformers. (NEMA, No. 141 at p. 9)
As previously noted, the definition of “distribution transformer” specifies that a transformer “has an output voltage of 600 V or less” and the definition of a low-voltage distribution transformer specifies “a distribution transformer that has an input voltage of 600 volts or less”. See 10 CFR 431.192. Any step-up transformer with a primary input and output voltage less than our equal to 600 volts would therefore meet the definition of a low-voltage dry-type distribution transformer.
Any product meeting the definition of low-voltage dry-type distribution transformer, would be subject to DOE standards. DOE is not amending the definition of low-voltage dry-type distribution transformer to specifically include step-up transformers as this could be confusing to manufacturers of step-up transformers that do not meet the voltage limits (and therefore are not within the scope of distribution transformer efficiency standards). Further, as described in the foregoing discussion, these low-voltage dry-type products are already included within the definition of low-voltage dry-type distribution transformer.

g. Uninterruptible Power Supply Transformers
“Uninterruptible power supply transformer” is defined as a transformer that is used within an uninterruptible power system, which in turn supplies power to loads that are sensitive to power failure, power sags, over voltage, switching transients, line noise, and other power quality factors. 10 CFR 431.192. An uninterruptible power supply transformer is excluded from the definition of distribution transformer. 42 U.S.C. 6291(35)(B)(ii); 10 CFR 431.192. Such a system does not step-down voltage, but rather it is a component of a power conditioning device, and it is used as part of the electric supply system for sensitive equipment that cannot tolerate system interruptions or distortions to counteract such irregularities. 69 FR 45376, 45383. DOE has clarified that uninterruptible power supply transformers do not “supply power to” an uninterruptible power system; rather, they are “used within” the uninterruptible power system. 72 FR 58190, 58204. This clarification is consistent with the reference in the definition to transformers that are “within” the uninterruptible power system. 10 CFR 431.192.
In the January 2023 NOPR, DOE noted that transformers at the input, output or bypass that are supplying power to an uninterruptible power system are not uninterruptible power supply transformers. 88 FR 1722, 1745. Accordingly, DOE proposed to amend the definition of “uninterruptible power supply transformer” to explicitly state that transformers at the input, output, or bypass of a distribution transformer are not a part of the uninterruptible power system and requested comment on the proposed amendment. Id.
In response, NEMA recommended that DOE include in the definition of an uninterruptible power supply transformer that these transformers must include a core with an air gap and/or a shunt core. NEMA stated these features prevent uninterruptible power supply transformers from meeting the proposed efficiency standards and transformers that do not include at least one of these attributes would not meet the definition of an uninterruptible power supply transformer. (NEMA, No. 141 at p. 8) Prolec GE commented that the proposed amendment to the definition provides helpful clarification, but suggested DOE confirm its usage of the terms “uninterruptable” and “uninterruptible”. (Prolec GE, No. 120 at p. 5)
DOE notes that its usage of “uninterruptable” in the January 2023 NOPR was an inadvertent typographical error. In this final rule, all instances of “uninterruptable” have been corrected to “uninterruptible.”
Regarding NEMA's recommendation to include a requirement for a core with an air gap and/or a shunt core, DOE reviewed available literature to evaluate the relevance of these design features, specifically regarding how prevalent they are in the design of uninterruptible power supply transformers and how they may impact the efficiency of a distribution transformer. Based on its review, DOE interprets the terms “magnetic shunt” and “air gap” as they appear in NEMA's comment to refer to the definitions prescribed in in IEEE Standard 449-1998 (R2007) “IEEE Standard for Ferroresonant Voltage Regulators” (“IEEE 449”). ^{42} IEEE 449 defines a magnetic shunt as “the section of the core of the ferroresonant transformer that provides the major path for flux generated by the primary winding current that does not link the secondary winding”; IEEE 449 defines an air gap as “the space between the magnetic shunt and the core, used to establish the required reluctance of the shunt flux path.” DOE understands these features to provide a high reluctance pathway for excess magnetic flux such that the secondary voltage will remain constant, even when the primary side voltage fluctuates unexpectedly. This functionality would be particularly useful in uninterruptible power supply transformers, which provide a smooth and continuous supply of electricity to avoid damaging any downstream equipment.
^{42} IEEE SA. (1998). IEEE 449-1998—IEEE Standard for Ferroresonant Voltage Regulators (Accessed on 09/15/2023). Available online at: standards.ieee.org/ieee/449/675/ .
However, DOE notes that the definitions of “air gap” and “magnetic shunt” as they are presented in IEEE 449 do not appear to be the only examples of these features as they appear in transformer design. For example, stacked core designs have inherent air gaps that do not provide the same high reluctance pathway for magnetic flux. Additionally, DOE observed transformer designs advertised as having “magnetic shunts,” consisting of laminated steel sheets installed on or surrounding the transformer core to prevent leakage flux from affecting the transformer tank or other surrounding components. These alternative applications for these features could create confusion as to which transformers would meet the definition of an uninterruptible power supply transformer.
While inclusion of either an “air gap” or “shunt core” may be useful features in identifying uninterruptible power supply transformers, DOE lacks sufficient data to properly characterize these attributes. DOE also has not received sufficient feedback from stakeholders to indicate that these features are exclusive to uninterruptible power supply transformers or if they would encompass many other transformers not intended to be uninterruptible power supply transformers. Further, NEMA has previously commented that manufacturers are applying the definition of uninterruptible power supply transformer appropriately and clarification is not needed. (NEMA, No. 50 at p. 4)
DOE notes that the proposed definition only sought to codify DOE's existing interpretation that uninterruptible power supply transformers must be “within” an uninterruptible power system and not at the “input, output, or bypass” of an uninterruptible power system. Therefore, in this final rule, DOE is finalizing the proposed definition of “uninterruptible power supply transformer.”

h. Voltage Specification
As stated, the definition of “distribution transformer” is based, in part, on the voltage capacity of equipment, i.e., has an input voltage of 34.5 kV or less, and has an output voltage of 600 V or less. 10 CFR 431.192. (42 U.S.C. 6291(35)(A)) Three-phase distribution transformer voltage may be described as either “line,” i.e., measured across two lines, or “phase,” i.e., measured across one line and the neutral conductor. For delta-connected ^{43} distribution transformers, line and phase voltages are equal. For wye-connected distribution transformers, line voltage is equal to phase voltage multiplied by the square root of three.
^{43} Delta connection refers to three distribution transformer terminals, each one connected to two power phases.
DOE notes that it previously stated that the definition of distribution transformer applies to “transformers having an output voltage of 600 volts or less, not having only an output voltage of less than 600 volts.” ^{44} 78 FR 23336, 23353. For example, a three-phase wye-connected transformer for which the output phase voltage is at or below 600 V, but the output line voltage is above 600 V would satisfy the output criteria of the distribution transformer definition. DOE's test procedure requires that the measured efficiency for the purpose of determining compliance be based on testing in the configuration that produces the greatest losses, regardless of whether that configuration alone would have placed the transformer at-large within the scope of coverage. Id. Similarly, with input voltages, a transformer is subject to standards if either the “line” or “phase” voltages fall within the voltage limits in the definition of distribution transformers, so long as the other requirements of the definition are also met. Id
^{44} Inclusive of a transformer at 600 volts.
In response to the August 2021 Preliminary Analysis TSD, DOE received feedback that it should clarify the interpretation of voltage in the regulatory text. (Schneider, No. 49 at p. 8; NEMA, No. 50 at p. 4; Eaton, No. 55 at pp. 7-8). In the January 2023 NOPR, DOE noted that the voltage limits in the definition of distribution transformer established in EPCA do not specify whether line or phase voltage is to be used. 88 FR 1722, 1745; 42 U.S.C. 6291(35). However, DOE also discussed that, upon further evaluation, the distribution transformer input voltage limitation aligns with the common maximum distribution circuit voltage of 34.5 kV. 45 46 This common distribution voltage aligns with the distribution line voltage, implying that the intended definition of distribution transformer in EPCA was to specify the input and output voltages based on the line voltage. Accordingly, DOE tentatively determined that applying the phase voltage, as DOE cited in the April 2013 Standards Final Rule, would cover products not traditionally understood to be distribution transformers and not intended to be within the scope of distribution transformer as defined by EPCA. 88 FR 1722, 1745. DOE also noted in the January 2023 NOPR that the common distribution transformer voltages have both line and phase voltages that are within DOE's scope, and therefore the proposed change is not expected to impact the scope of this rulemaking aside from select, unique transformers with uncommon voltages. Id. Accordingly, DOE proposed to modify the definition of distribution transformer to state explicitly that the input and output voltage limits are based on the “line” voltage and not the phase voltage.
^{45} Pacific Northwest National Lab and U.S. Department of Energy (2016), “Electricity Distribution System Baseline Report.”, p. 27. Available at www.energy.gov/sites/prod/files/2017/01/f34/Electricity%20Distribution%20System%20Baseline%20Report.pdf.
^{46} U.S. Department of Energy (2015), “United States Electricity Industry Primer.” Available at www.energy.gov/sites/prod/files/2015/12/f28/united-states-electricity-industry-primer.pdf.
In response, Eaton commented that DOE's revised interpretation of input and output voltages better aligns with industry. (Eaton, No. 137 at p. 13). NEMA commented that the addition of line voltage removes ambiguity and clearly defines products that need to be in compliance. (NEMA, No. 141 at p. 9). NEMA further recommended that the LVDT definition should also be updated to clarify that the voltage specifications are line voltages. (NEMA, No. 141 at p. 8) Schneider also supported DOE's clarification that input and output voltages are line voltages and recommended adding a similar clarification to the LVDT definition. (Schneider, No. 101 at p. 4)
Howard commented that clarifying that voltage refers to line voltage is an improvement to the definition of input and output voltage. However, Howard further stated that it is more common in industry to refer to line voltage as the “nominal system” voltage. Howard recommended that rather than using “line” voltages, DOE should use ”nominal system voltage,” which is used in many industry standards, and proposed defining “nominal system voltage.” Howard additionally supported DOE's assessment that the revised definitions of input and output voltage would only impact products not considered by industry to be serving distribution applications. (Howard, No. 116 at p. 8-9)
DOE reviewed relevant industry standards to assess Howard's recommendation. Based on this review, DOE found that, while the term “nominal system voltage” has been adopted in several standards, its usage is not ubiquitous. For example, IEEE standard C57.91-2020 interchangeably uses the terms “nominal voltage,” “line voltage,” and “line-to-line voltage” to specify transformer voltage ratings. ^{47} Other standards similarly specify voltage ratings using the terms “phase-to-phase,” “line-to-ground nominal system voltage,” or “nominal line-to-line system voltage.” Further, DOE reviewed manufacturer catalogs for distribution transformers and observed that it is more common to specify transformer voltage ratings according to the “line voltage,” as opposed to the “nominal system voltage.” The comments received from Eaton and NEMA additionally indicate that the term “line voltage” is well understood in industry and sufficiently clarifies the definitions of input and output voltage.
^{47} IEEE SA. (2020). IEEE C57.12.91-2020—IEEE Standard Test Code for Dry-Type Distribution and Power Transformers. Available at standards.ieee.org/standard/C57_12_91-2020.html (last accessed June 21, 2023).
Therefore, for the reasons discussed, DOE is modifying the definition of distribution transformer in this final rule to state explicitly that the input and output voltage limits are based on the “line” voltage and not the phase voltage. Similarly, in accordance with the feedback submitted by NEMA and Schneider, DOE is similarly amending the definition of “low-voltage dry-type distribution transformer” to state a transformer that has “an input line voltage of 600 volts or less”.

i. kVA Range
The EPCA definition for distribution transformers does not include any capacity range. In codifying the current distribution transformer capacity ranges in 10 CFR 431.192, (10 kVA to 2500 kVA for liquid-immersed units and 15 kVA to 2500 kVA for dry-type units), DOE noted that distribution transformers outside of these ranges are not typically used for electricity distribution. 71 FR 24972, 24975-24976. Further, DOE noted that transformer capacity is to some extent tied to its primary and secondary voltages, meaning that the EPCA definition has the practical effect of limiting the maximum capacity of transformers that meet those voltage limitations to approximately 3,750 to 5,000 kVA, or possibly slightly higher. Id. DOE established the current kVA range for distribution transformers by aligning with NEMA publications in place at the time that DOE adopted the range, specifically the NEMA TP-1 standard. 78 FR 23336, 23352. DOE cited these documents as evidence that its kVA scope is consistent with industry understanding ( i.e., NEMA TP-1 and NEMA TP-2), but noted that it may revise its understanding in the future as the market evolves. 78 FR 2336, 23352.
In the January 2023 NOPR, DOE noted that several industry sources suggest that the distribution transformer kVA range may exceed 2,500 kVA. 88 FR 1722, 1746. Specifically, DOE cited Natural Resources Canada (NRCAN) regulations that include dry-type distribution transformers up to 7,500 kVA. ^{48} The European Union (EU) Ecodesign requirements also specify maximum load losses and maximum no-load losses for three-phase liquid- immersed distribution transformers up to 3,150 kVA. ^{49}
^{48} See NRCAN dry-type transformer energy efficiency regulations at www.nrcan.gc.ca/energyefficiency/energy-efficiency-regulations/guidecanadas-energy-efficiency-regulations/dry-typetransformers/6875.
^{49} Official Journal of the European Union, Commission Regulation (EU) No. 548/2014, May 21, 2014, Available at eur-lex.europa.eu/legal-content/EN/TXT/?uri=uriserv%3AOJ.L_.2014.152.01.0001.01.ENG.
DOE noted that manufacturers in interviews had stated that transformers beyond 2,500 kVA are typically step-up transformers serving renewable applications, which would be outside the scope of standards on account of exceeding the output voltage limit. 88 FR 1722, 1746. However, DOE cited comments by NEMA and Eaton, which suggested that some number of general purpose distribution transformers are sold beyond 2,500 kVA. (NEMA, No. 50 at p. 5; Eaton, No. 55 at p. 8). Further, DOE noted that some manufacturers expressed concern in interviews that in the presence of amended energy conservation standards, there may be increased incentive to build distribution transformers that are just above the existing scope ( e.g., 2,501 kVA). 88 FR 1722, 1746.
In response to this feedback, DOE proposed to expand the scope of the definition of distribution transformer to 5,000 kVA. DOE requested comment as to whether 5,000 kVA represented the upper limit for distribution transformers. Id. at 88 FR 1747.
DOE also estimated energy savings for transformers greater than 2,500 kVA but less than or equal to 5,000 kVA by scaling certain representative units. In estimating energy savings, DOE assumed these units are purchased based on lowest first cost and use similar grades of electrical steel as in-scope units but are not required to meet any efficiency standards. DOE requested comment on the number of shipments and distribution of efficiency for these large three-phase distribution transformers. Id.
NAHB submitted data showing that imports for liquid-immersed transformers with ratings above 2500 kVA have increased significantly in the past decade and expressed concern that the proposed standards would negatively impact the import market for these products. (NAHB, No. 106 at pp. 8-9) DOE notes that the data cited by NAHB is for all transformers greater than 2,500 kVA without considering their secondary voltage. Most transformers greater than 2,500 kVA would be substation or large power transformers with output voltages that vastly exceed 600V. Due to the voltage limitations, virtually all transformers cited by NAHB would not be subject to DOE efficiency regulations regardless of the kVA range for the definition of distribution transformer.
Howard commented that transformers beyond 2,500 kVA are not within the technical scope of what is considered a distribution transformer and should not be a part of distribution transformer regulations. (Howard, No. 116 at pp. 9, 19) Howard stated that they produce a very small number of 3,000, 3,750, and 5,000 kVA transformers per year that are primarily used for unique and specialized applications, not as a means to circumvent DOE regulations. Id. Howard referred DOE to IEEE C57.12.34 and C57.12.36 industry standards, which Howard stated do not specify an impedance value for 5,000 kVA transformers with a low-voltage rating of 600 V and below. ^{50}
Id. Prolec GE commented that transformers between 2,500 kVA and 5,000 kVA may maintain certain characteristics as distribution transformers but are mainly specified and purchased by industrial customers and not intended for general purpose applications. (Prolec GE, No. 120 at p. 5)
^{50} See Table 2 of IEEE Std C57.12.34-2022 and Table 5 of IEEE Std C57.12.36-2017.
Eaton commented that between 2016 and 2022, it built zero transformers above a kVA rating of 5,000 kVA that also had an output voltage of 600 V or less. (Eaton, No. 137 at p. 13) Howard commented that units above 2,500 kVA with secondary voltages of 600 V or less represent less than one percent of Howard's annual three-phase pad mounted transformer shipments. (Howard, No. 116 at p. 10) Howard stated that units over 2,500 kVA have very few shipments, representing a very small number of specialized units. (Howard, No. 116 a p. 19)
Howard stated that the average efficiency of these units is 99.4 percent and achieving lower losses than this becomes difficult due to the very high currents that lead to significant stray and eddy losses. (Howard, No. 116 at p. 10) Howard stated that if DOE elects to include these high-kVA units, their efficiencies should not be on-par with smaller units due to the unique challenges associated with high-kVA units. (Howard, No. 116 at p. 19)
Eaton commented that because the scaling relationships do not hold with high-kVA units, DOE should work with manufacturers to identify more accurate max-tech efficiency levels for high-kVA transformers. (Eaton, No. 137 at p. 28) Eaton provided data showing what their design software calculated as max-tech for 3-phase distribution transformers at various voltages across a range of kVA values. (Eaton, No. 137 at p. 28)
Prolec GE commented that the proposed standards for transformers above 2,500 kVA result in a much larger increase in standards than all other transformers because they are not currently subject to efficiency standards and therefore the baseline transformer is less efficient than transformers that are in-scope today. (Prolec GE, No. 120 at p. 12)
Hammond commented that the 5,000 kVA limit is preferrable for medium-voltage dry-type distribution transformer units; however, the high-currents of these designs may make efficiency standards infeasible and, therefore, it may be necessary to apply an exclusion for high-current units, similar to the NRCAN regulations. (Hammond, No. 142 at p. 3)
In reviewing the technical challenges associated with meeting energy conservation standards for large three-phase units, DOE agrees that the presence of both very high kVA ratings and an output voltage of 600V could lead to very high currents that would inherently lead to manufacturing challenges, making it more costly to meet a given efficiency standard. However, DOE notes that industry standards recommend minimum low-voltage ratings that vary based on kVA. ^{51} As a result, larger kVA transformer tend to have higher secondary voltages. While maintaining these recommended voltage ratings does not entirely eliminate the challenges faced by high-current transformers, as further discussed in section IV.A.2.c, it generally helps maintain a reasonable current.
^{51} See Table 3 of IEEE Std C57.12.36-2017.
DOE notes that one of the primary reasons it cited for proposing to include higher kVA distribution transformer within the scope of the distribution transformer rulemaking was concern from manufacturers that, in the presence of amended energy conservation standards, there may be increased incentive to build distribution transformers that are just above the existing scope ( e.g., 2,501 kVA). 88 FR 1722, 1746.
NEMA commented in response to the January 2023 NOPR that some customers have requested units just beyond the scope of regulations ( e.g. 2,501 kVA). (NEMA, No. 141 at p. 9) The Efficiency Advocates commented that they support DOE's proposal to include capacities up to 5,000 KVA based on manufacturer comment that some products are sold here that meet the voltage limits and to eliminate the potential incentive to build transformers just beyond the current scope in the presence of amended standards. (Efficiency Advocates, No. 121 at p.7)
Stakeholder comments indicate that losses for high-kVA transformers increase at a faster rate than modeled by the scaling relationships used in the January 2023 NOPR, causing the proposed standards for these high-kVA units to be beyond what is technologically feasible. Based on the feedback received, DOE conducted additional investigation into the interaction between capacity, current, and efficiency standards, as discussed in sections IV.A.2.c and IV.C.1.e. Based on the feedback received from manufacturers and this additional technical investigation, DOE has determined that the primary challenge associated with meeting efficiency standards for higher kVA distribution transformers is related to the high-current associated with those transformers.
If built per the minimum voltage recommendations of IEEE Std C57.12.36-2017, 5,000 kVA transformers would never have an output voltage less than or equal to 600V, and 3,750 kVA transformers would also typically be larger than 600V. This indicates that 3,750 kVA or 5,000 kVA transformers would likely not have output voltages that meet the definition of distribution transformers subject to energy conservation standards, if built per industry standards.
However, stakeholder comments also suggest that consumers have requested transformers just beyond 2,500 kVA ( i.e., 2,501 kVA), that are not built per industry standard kVA ranges to use in general purpose applications, which could increase in the presence of amended efficiency standards. As such, DOE is finalizing an expansion to include distribution transformers less than or equal to 5,000 kVA, as proposed in the January 2023 NOPR. However, DOE requested comment on its modeling of high-kVA units (88 FR 1722, 1760) and based on stakeholder feedback has modified its modeling (as discussed in section IV.C.1.e) and adopted efficiency levels for these high-kVA units to reflect the challenges associated with high-currents in distribution transformers.
DOE notes that this finalized definition reduces the risk of non-standard kVA transformers being built just beyond the scope of regulations in an effort to circumvent efficiency requirements, while accommodating the legitimate challenges associated with high-current transformers. DOE discusses the specific comments related to high-current transformers in section IV.A.2.c of this document.

2. Equipment Classes
When evaluating and establishing or amending energy conservation standards, DOE may establish separate standards for a group of covered equipment ( i.e., establish a separate equipment class) if DOE determines that separate standards are justified based on the type of energy used, or if DOE determines that a product's capacity or other performance-related feature justifies a different standard. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)) In making a determination whether a performance-related feature justifies a different standard, DOE considers such factors as the utility of the feature to the consumer and other factors DOE determines are appropriate. ( Id. )
Eleven equipment classes are established under the existing standards for distribution transformers, one of which (mining transformers ^{52} ) is not subject to energy conservation standards. 10 CFR 431.196. The remaining ten equipment classes are delineated according to the following characteristics: (1) type of transformer insulation: liquid-immersed or dry-type, (2) number of phases: single or three, (3) voltage class: low or medium (for dry-type only), and (4) basic impulse insulation level (BIL) (for MVDT only).
^{52} A mining distribution transformer is a medium-voltage dry-type distribution transformer that is built only for installation in an underground mine or surface mine, inside equipment for use in an underground mine or surface mine, on-board equipment for use in an underground mine or surface mine, or for equipment used for digging, drilling, or tunneling underground or above ground, and that has a nameplate which identified the transformer as being for this use only. 10 CFR 431.192.
Table IV.3 presents the eleven equipment classes that exist in the current energy conservation standards and provides the kVA range associated with each.
DOE notes that across the existing transformer equipment classes, numerous factors can impact the cost and efficiency of a distribution transformer. Certain factors like primary voltage, secondary voltage, insulation material, specific impedance designs, voltage taps, etc., can all increase the price of a given transformer and lead to an increase in transformer losses, which may make meeting any given efficiency standard more difficult. Distribution transformers are frequently customized by consumers to add features, safety margins, etc. However, DOE has determined that in general these differences are not sufficient to warrant separate equipment classes. Having a different equipment class for all possible kVA and voltage combinations is infeasible, would add complexity to optimization software, and was not suggested by any stakeholders. Within a given equipment class and efficiency standard, there is typically sufficient “margin” such that all small variabilities in design can meet efficiency standards without reaching an “efficiency wall” wherein any additional efficiency gains become substantially more expensive. However, certain design variabilities may warrant separation into additional equipment classes such that the product features remain on the market. In the January 2023 NOPR, DOE requested comment and data on a variety of other potential equipment features that may warrant a separate equipment class. 88 FR 1722, 1747. These comments are discussed in detail below.

a. Submersible Transformers
Certain distribution transformers are installed underground and, accordingly, may endure partial or total immersion in water. In the January 2023 NOPR, DOE stated that the subterranean installation of submersible distribution transformers means that there is less circulation of ambient air for shedding heat. 88 FR 1722, 1748. Operation while submerged in water and in contact with run-off debris further impacts the ability of a distribution transformer to transfer heat to the environment and limits the alternative approaches in the external environment that can be used to increase cooling ( e.g., adding radiators).
DOE noted that distribution transformer temperature rise tends to be governed by load losses and that it is typical for design options that reduce load losses to increase no-load losses. 88 FR 1722, 1748. While no-load losses make up a relatively small portion of losses at full load, no-load losses can contribute a significant portion of total losses at 50-percent PUL, at which manufacturers must certify efficiency. However, due to the potentially reduced heat transfer of a subterranean environment, combined with the possibility of operating while submerged, customers must reduce load losses to meet temperature rise limitations. Therefore, the design choices needed to meet a lower temperature rise may lead manufacturers to increase no-load losses and may make it more difficult to meet a given efficiency standard at 50-percent PUL.
In the January 2023 NOPR, DOE tentatively determined that distribution transformers designed to operate while submerged and in contact with run-off debris constitutes a performance-related feature which other types of distribution transformers do not have. 88 FR 1722, 1748. At max-tech efficiency levels, both no-load and load losses are low enough that distribution transformers generally do not meet their rated temperature rise. However, at intermediate efficiency levels, trading load losses for no-load losses allows distribution transformers to be rated for a lower temperature rise. This may make it more difficult to meet any amended efficiency standard, as no-load losses contribute proportionally more to efficiency at the test procedure PUL as compared to at the rated temperature rise. Id.
In defining a submersible distribution transformer, DOE noted that the IEEE C57.12.80-2010 includes numerous definitions for transformers designed to operate in partial or total submersion. Id. DOE attempted to identify the physical features that would distinguish transformers capable of operating in a submersible operation by reviewing industry standards IEEE C57.12.23-2018 and IEEE C57.12.24-2016. Id. DOE proposed to define a submersible distribution transformer as “a liquid-immersed distribution transformer so constructed as to be successfully operable when submerged in water including the following features: (1) is rated for a temperature rise of 55 °C; (2) has insulation rated for a temperature rise of 65 °C; (3) has sealed-tank construction; and (4) has the tank, cover, and all external appurtenances made of corrosion-resistant material.” Id. DOE noted that this definition sought to incorporate the physical features associated with submersible transformers that are included in industry standards. DOE requested comment on its definition of submersible distribution transformer and information regarding the specific design characteristics that limit efficiency. Id.
APPA supported creating a separate equipment class for vault, submersible, or special installation transformers and supported DOE's proposal not to establish higher efficiency standards for those units. (APPA, No. 103 at p. 3)
Howard supported a separate equipment class for submersible distribution transformers because of their lack of cooling, higher ambient temperatures, and higher installation costs. (Howard, No. 116 at p. 11) Howard commented that comparing its submersible transformers to its non-submersible transformers requires a 10- to 12-percent increase in no-load losses and comparable reduction in load losses to meet maximum temperature rise characteristics. (Howard, No. 116 at p. 11) Howard added that in addition to the reduced cooling, submersible transformers also frequently have bushings, switches, tap changers, and other accessories mounted on the cover, which increases lead lengths and therefore increases losses. (Howard, No. 116 at p. 11)
Prolec GE and NEMA commented that submersible transformers are limited in their ability to meet higher efficiency levels on account of needing to meet the strict dimensional requirements associated with fitting in existing vaults, their limited heat transformer on account of needing to operate in dirty water, and their need to have corrosion-resistant construction, which is thicker and reduces the transformer's ability to remove heat. (NEMA, No. 141 at p. 10; Prolec GE, No. 120 at p. 9) Due to these limitations, Prolec GE supported DOE establishing a separate equipment class for submersible transformers and not increasing efficiency standards. (Prolec GE, No. 120 at p. 9) Carte supported establishing a separate equipment class for submersible transformers and not establishing higher efficiency levels because of the strict dimensional constraints associated with installations in vault locations. (Carte, No. 140 at p. 7)
WEC commented that DOE's proposed equipment class and no-new-standard determination for submersible distribution transformers would not cover WEC's more cost effective approach of using pad mounted transformers in certain vault applications. (WEC, No. 118 at p. 2) DOE notes that in cases where utilities are using traditional pad-mounted distribution transformers in vault applications, there are not going to be the same thermal limitations that represent the technical features identified by stakeholders as warranting a separate equipment class.
Regarding DOE's proposed definition of submersible distribution transformer, Carte commented that some utilities in unique locations use a 65 °C temperature rise in their transformer vaults. (Carte, No. 140 at p. 7) Prolec GE and NEMA commented that submersible distribution transformer is already defined per IEEE standards C57.12.24 and C57.12.40. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp. 9-10) Prolec GE and NEMA further commented that the unique design and characteristics of submersible transformers makes them rarely compatible with above ground installation. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp. 9-10) Prolec GE and NEMA commented that IEEE C57.12.80 identifies installation in a vault as a common characteristic for submersible, subway, and network transformers. (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp. 9-10)
Howard commented that DOE should align the definition with IEEE standards C57.12.23, C57.12.24, and C57.12.40. Howard added that if DOE elects not to align with IEEE standards, DOE should modify feature (4) of the definition to clarify that copper-bearing steel with minimum specified thicknesses for tanks, covers, and auxiliary coolers is an acceptable alternative to stainless steel as a “corrosion-resistant material.” (Howard, No. 116 at p. 10) Prolec GE and NEMA recommended submersible distribution transformer be defined as “a liquid-immersed distribution transformer, so constructed as to be operable when fully submerged in water including the following feature: (1) has sealed tank construction; (2) has the tank, cover and all external appurtenances made of corrosion-resistance material or with appropriate corrosion-resistance surface treatment to induce the components surface to be corrosion resistant; and (3) is designed for installation in an underground vault.” (Prolec GE, No. 120 at p. 6; NEMA, No. 141 at pp. 9-10)
In reviewing the nuances NEMA, Prolec GE, and Howard described as to the different approaches manufacturers may take to ensure their distribution transformer is constructed to operate when submerged in water, DOE agrees that different insulating fluids may modify the exact temperature rise of a given submersible distribution transformer and the primary physical features associated with submersible transformers include having sealed tank construction and corrosion resistant surroundings. As noted, DOE described the physical features identified in the NOPR based on a review of these industry standards and intended to align its definition with the physical features identified in these standards.
Therefore, DOE is adopting a definition for submersible distribution transformer to mean “a liquid-immersed distribution transformer, so constructed as to be operable when fully or partially submerged in water including the following features: (1) has sealed-tank construction; and (2) has the tank, cover, and all external appurtenances made of corrosion-resistant material or with appropriate corrosion resistant surface treatment to induce the components surface to be corrosion resistant.”

b. Large Single-Phase Transformers
DOE received several comments from stakeholders (discussed in sections IV.C.1.d and IV.E.2 of this document) noting that in the immediate future, the ability to operate transformers efficiently at higher loading may represent a distinct consumer utility. (APPA, No. 103 at p. 17; NEPPA, No. 129 at p. 2; Cliffs, No. 105 at pp. 16-17; Carte, No. 140 at p. 6) Specifically, an increased ability to overload small single-phase transformers, which are often placed most directly near consumer loads, provides safety and reliability amidst uncertainty over near-future demand patterns as electrification proceeds. DOE notes that the ability to overload a distribution transformer is related to a transformer's temperature rise and insulation.
The likelihood of a distribution transformer being overloaded is a function of, among other factors, the size of the transformer and the number of consumers being served by a given distribution transformer. While smaller kVA transformers tend to serve a smaller number of households, the loading on those smaller transformers could vary with considerably more irregularity because the actions of a small number of individuals can drastically impact loading. Larger kVA transformers tend to serve a larger number of households, with overall loading on the transformer distributed across a larger number of individuals. Therefore, while loading still varies, it varies more predictably as no single individual can impact the loading on a single transformer as significantly. As a result, larger kVA transformers are less likely to be subject to overloading conditions than their smaller kVA counterparts.
Instantaneous temperature rise on a transformer tends to be governed by load losses and it is typical for design options that reduce load losses to increase no-load losses. While no-load losses typically make up a relatively small portion of losses at full load, no-load losses can contribute a significant portion of total losses at 50-percent PUL, at which manufacturers must currently demonstrate compliance with energy conservation standards at 10 CFR 431.196(b). The design choices needed to reduce temperature rise may lead manufacturers to increase no-load losses, as not doing so may increase the cost of the distribution transformer and diminish sales in a market sensitive to selling price. Further, because operating temperature is impacted by the ability of the transformer to dissipate heat, a transformer's tolerance of overloading is directly linked to its ability to shed heat. Heat transfer is directly dependent on the ratio of distribution transformer surface area to volume. In other words, the more surface area that a transformer has per unit of volume, the more effectively it will be able to shed heat. As transformer capacity increases, however, the weight and volume of the transformer tend to increase more rapidly than the surface area, meaning that heat transfer become less effective. As a result, smaller kVA transformers tend to be more physically suitable for sustaining overload conditions than larger kVA transformers, which typically need additional radiators to effectively remove heat.
Similarly to submersible transformers, at the max-tech efficiency levels for single phase transformers, both the no-load and load losses are low enough that distribution transformers generally do not meet their rated temperature rise. However, at intermediate efficiency levels, trading load losses for no-load losses may allow smaller distribution transformers serving fewer consumers to have increased overload capability, particularly if paired with less-flammable insulating liquid. This combination may make it more difficult to meet any amended efficiency standard, as no-load losses contribute proportionally more to efficiency at the test procedure PUL as compared to at the rated temperature rise. Id.
One utility investigated the likelihood of distribution transformers being overloaded based on potential electric vehicle (EV) charging penetration rates for single-phase transformers ranging from 15 to 100 kVA. This study found that smaller transformers have a high likelihood of being overloaded and, as the size of those transformers increases, the percentage of overloaded transformers at a given kVA goes to zero beyond 100 kVA. ^{53} While in the longer term, the study recommends upsizing transformers such that loading on transformers remains low, in the immediate future, consumers will value increased overload capacity as a consumer feature for small, single-phase transformers.
^{53} Dalah, S., Aswani, D., Geraghty, M., Dunckley, J., Impact of Increasing Replacement Transformer Size on the Probability of Transformer Overloads with Increasing EV Adoption, 36th International Electric Vehicle Symposium and Exhibition, June, 2023. Available online at: https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf.
Based on this data, for this final rule DOE has evaluated two equipment classes for single-phase liquid-immersed distribution transformers. Equipment Class 1A corresponds to single-phase liquid-immersed distribution transformers greater than 100 kVA. Equipment Class 1B corresponds to single-phase liquid-immersed distribution transformers ranging from 10-100 kVA. Equipment Class 1A includes units that are unlikely to be overloaded, while Equipment Class 1B includes units that are at higher likelihood of being overloaded and, therefore, consumers are more likely to exchange no-load losses for load losses, thereby making it more difficult to meet amended efficiency standards.
DOE notes that in the cited study exploring the likelihood of overloading in the presence of high-EV penetration (corresponding to a 50% penetration rate by 2035), the overloading likelihood ranges from 100 percent for 15 kVA transformers to 2.5 percent for 100 kVA transformers. However, when those 100 kVA transformers are upsized, the overload likelihood in the high-EV penetration scenario falls to 0.1 percent, indicating that 100 kVA approximately corresponds to the upper limit of single-phase transformers that are likely to experience overloading and therefore likely to be designed to trade load losses for no-load losses to reduce the loss-of-life impacts associated with overloading. DOE considered other potential capacities for separating equipment, as lower-EV penetration scenarios show that 75 kVA and 100 kVA transformers are unlikely to be overloaded. However, given the regional variance of EV penetration, DOE has determined that even in the most aggressive EV-penetration scenarios, the likelihood of overloading falls to virtually zero above 100 kVA. Therefore, in light of the above, DOE has determined that 10-100 kVA and above 100 kVA are reasonable capacity designation for determining product classes.
As noted, higher efficiency levels can result in low no-load and load losses; however, intermediate efficiency levels require trading off between the two. Further, the utility associated with increased overloading is likely limited to the near-term electrification build-out, wherein a significant number of new loads, notably electric vehicles, are being added to the grid. Longer-term, utilities are expected to replace this overloading ability with larger kVA transformers, as recommended by the aforementioned study.
While DOE did not propose separate equipment classes based upon kVA capacity for liquid-immersed transformers in the January 2023 NOPR, DOE requested comment on any other categories of equipment that may warrant a separate equipment class. 88 FR 1722, 1752. DOE also evaluated a separate equipment class in the January 2023 NOPR for submersible distribution transformer based, in part, on the high overload capabilities and reduced heat transformer needed for many submersible distribution transformers which require manufacturers to increase no-load losses in order to decrease load losses. 88 FR 1722, 1748. Stakeholder feedback in response to the NOPR regarding the likely increase in loading—as summarized at the beginning of this section—and the conclusions from the additional studies described previously in this section regarding the likelihood of overloading a transformers in the near-term justify evaluating single-phase liquid-immersed distribution-transformers as two equipment classes based on kVA size, based on a similar principle that increased ability to overload a transformer requires trading no-load losses for load losses at intermediate efficiency levels.

c. Large Three-Phase Transformers With High-Currents
Distribution transformers with high currents often have increased stray losses, which can impact the efficiency of distribution transformers. Because of this limitation, NRCAN regulations exclude transformers with a nominal low-voltage line current of 4000 A or more. DOE has historically not evaluated high-current transformers as a separate equipment class.
In the January 2023 NOPR, DOE noted that while stray losses may be slightly higher for high-current transformers, manufacturers have the option to use copper secondaries or a copper buss bar to decrease load losses. 87 FR 1722, 1750. Further, DOE noted that technologies that increase the efficiency of lower-current transformers tend to also increase the efficiency of high-current transformers. Id. Therefore, DOE did not propose a separate equipment class for high-current transformers. However, DOE stated that it may consider a separate equipment class for high-current transformers if sufficient data were provided, and DOE requested manufacturers provide data on the different cost-efficiency curve associated with high-current transformers along with the number of shipments of these units. Id. at 87 FR 1751.
Eaton provided data showing the max-tech of their designs with both amorphous and grain-oriented electrical steel (GOES) cores with 208Y/120 secondaries and 480Y/277 secondaries. (Eaton, No. 137 at p. 17) Eaton's data showed that the max-tech is similar at low kVA values, regardless of secondary current. (Eaton, No. 137 at p. 17) Eaton additionally provided cost efficiency curves for 500 kVA units which showed similar incremental costs at the proposed standard levels for designs with either a 208Y/120 or a 480Y/277 secondary. Id. However, as the transformer capacity increases and the secondary current increases, the maximum transformer efficiency that can be achieved begins to drop considerably. Id.
Most distribution transformers are sold at one of a handful of standard secondary voltages. For three-phase transformers, this is typically either 480Y/277 or 208Y/120. Eaton stated that 97 percent of their three-phase shipments use either a 208Y/120 or 480Y/277 secondary. (Eaton, No. 137 at p. 20)
Eaton recommended DOE set an efficiency standard with at least a 20-percent margin in base losses relative to the actual max-tech for 208Y/120 secondary transformers. Id. Eaton suggested that DOE could propose separate standards for transformers with 480Y/277V or 208Y/120V secondaries based on having a line voltage above or below 250 V respectively. (Eaton, No. 137 at p. 29)
DOE notes that across all transformers, variability in voltage can impact the price and maximum achievable efficiency of a transformer. As shown in Eaton's max-tech plots, there is a slight difference in the maximum efficiency that can be achieved across all kVA ranges as the stray and eddy currents and conductor thickness will vary slightly between designs. Similarly, the choice in primary voltage may slightly impact the maximum achievable efficiency of a given transformer design. However, in general, these differences are not sufficient to warrant separate equipment classes. As discussed in Eaton's comment, for most kVA values there is sufficient “margin” that both a 208Y/120 and a 480Y/277 transformer have similar cost-efficiency relationships. Having a different equipment class for all possible kVA and voltage combinations is infeasible and was not suggested by any stakeholders.
Eaton additionally commented that its modeling of max-tech shows that previous DOE efficiency standards may have resulted in the unavailability of many 2,000 kVA and 2,500 kVA distribution transformers with 208Y/120 secondaries, which should not have been allowed under 42 U.S.C. 6295(o)(4), as this represents a performance characteristic. (Eaton, No. 137 at p. 18)
DOE notes that 42 U.S.C. 6295(o)(4) specifies that DOE may not set any amended standard that is likely to result in the unavailability of any performance characteristics that are substantially the same as those generally available in the United States at the time of the Secretary's finding. DOE notes that voltage generally increases as transformer capacity increases. As such, the high-current units cited by Eaton generally were not available due to the challenges of designing a transformer with a wire of sufficient thickness to handle the very high-currents. DOE does not expect that the adopted standards will result in the unavailability of any high-current units that are currently being produced in any significant volume. Further, there is no distinct purpose where such a large kVA transformer with such a high-current would be the only option to provide a low secondary voltage because consumers can and do achieve identical utility more economically and efficiently with one or multiple smaller kVA transformer placed closer to the electricity's end-use.
Transmission losses are also related to transformer current, and as such, if a customer needs a very large amount of transformative capacity, it is typically more efficient and cost effective to step-down power to 480V/277 and then use smaller transformers to further step down the voltage to 208Y/120, closer to the actual point of use. For these reasons, industry standards recommend high-kVA transformers have higher-secondary voltages. As such, currents do not tend to reach problematic values.
However, transformers within common industry values may still have a high enough current such that the stray and eddy losses would make up a much greater percentage of the transformer load losses and require manufacturers to overdesign transformers to meet a given efficiency level. Additionally, as kVA increases, this effect may become progressively more pronounced.
Prolec GE commented that load losses tend to be ten percent higher for high-current transformers due to increased losses in the leads and electrical connections on the secondary side of the transformer. (Prolec GE, No. 120 at pp. 6-7) Carte commented that using a 120V secondary instead of a 277V secondary for a 500 kVA, single-phase transformer would increase the cost to meet current efficiency standards by 52 percent. (Carte, No. 140 at p. 9) Carte commented that for 1,500 kVA three-phase transformer, using 208Y/120 secondary instead of a 480Y/277 secondary results in a 66 percent increase in first cost. Carte added that a 1,500 kVA three-phase unit with 208Y/120 design could at best achieve a 5 percent reduction in losses and would increase the cost by 95 percent relative to current efficiency standards, unless they transitioned to an amorphous core. (Carte, No. 140 at p. 9)
Several stakeholders gave specific low-voltage line-currents at which stray and eddy losses grow disproportionately. Howard commented that for three-phase transformers, it currently is difficult to meet efficiency standards for currents greater than 3000 A. Howard commented that typical load losses grow disproportionately at high current, wherein the load loss to no-load loss ratio is typically between 3-5 for low-current transformers but increases to 7-8 for high-current transformers, requiring higher grades of core steel to offset the increased load losses. Howard added that under the NOPR proposed levels, currents greater than 2000 A would be difficult. (Howard, No. 116 at p. 12) Prolec GE commented that above 3000 A, the manufacturer needs to overdesign the transformer or it becomes infeasible to meet efficiency levels. (Prolec GE, No. 120 at pp. 6-7) NEMA commented that for, liquid-filled transformers, it is difficult to meet current energy conservation standards above 4000 A today and recommended DOE not increase efficiency standards for any transformers with a low voltage line current over 3000 A. (NEMA, No. 141 at p. 11)
The current limits mentioned by stakeholders typically correspond to a specific common kVA value and common secondary voltage. For example, a low-voltage line current of 2,000 A or greater corresponds to 3-phase transformers with either a 208Y/120 secondary voltage and a capacity of 750 kVA or transformers with a 480Y/277 secondary voltage and a capacity of 2,000 kVA. A low-voltage line current of 3,000 A or greater corresponds to transformers with a 208Y/120 secondary voltage and capacity greater than 1000 kVA or transformers with a 480Y/277 secondary voltage and a capacity of 2,500 kVA. A low-voltage line current of 4,000 A or greater corresponds to transformers with a 208Y/120 secondary voltage and capacity of 1,500 kVA or transformers with a 480Y/277 secondary voltage and a capacity of 3,750 kVA.
IEEE C57.12.36-2017 recommends a minimum low-voltage of 277V beginning at 1,500 kVA and a minimum of 1386V beginning at 5,000 kVA. Similarly, IEEE C57.12.34-2022 recommends a maximum kVA of 1,000 kVA for a 208Y/120 or 240V secondary. As such, the only IEEE standard recommended products with a 208Y/120 or 480Y/277 secondary above 2,000 A include 750 kVA and 1,000 kVA transformers with 208Y/120 secondaries and 2,000 kVA; 2,500 kVA; and 3,750 kVA with 480Y/277 secondaries. The only recommended products above 3,000 A include a 2,500 kVA and 3,750 kVA with a 480Y/277 secondary. The only recommended products above 4,000 A include a 3,750 kVA with 480Y/277 secondary. DOE notes that 3,750 kVA transformers are not currently subject to energy conservation standards but were proposed to be covered in the January 2023 NOPR.
Regarding transformers with low-voltage line currents exceeding 2,000 A that stakeholders identified as having a harder time meeting standard, Eaton's data suggests that the DOE modeled max-tech closely aligns with manufacturer data for the 2,000 kVA and 2,500 kVA transformers with 480Y/277 secondaries.
Howard commented that 4.8 percent of their three-phase transformer shipments exceed 2000 A. (Howard, No. 116 at p. 12) Howard did not give specifics as to which of those also exceed 3,000 A or 4,000 A; however, based on industry standards, DOE expects most of those units to be 2,000 kVA and 2,500 kVA transformers with 480Y/277 secondaries.
Eaton provided data showing that as transformer capacity increases, the percentage of units with the higher secondary, and therefore lower current, increases such that at 1500 kVA, only 7.9 percent of units have 208Y/120 secondaries, and at 2,000 kVA and above, 0 percent of shipments have 208Y/120 secondaries. (Eaton, No. 137 at p. 20)
The data supplied by Eaton indicates that, for lower kVA capacities, transformer max-tech efficiency increases with kVA as predicted in DOE's modeling. However, above a certain point, the transformer begins to reach the limits of its design capabilities and max-tech efficiency begins to decline, rather than increase. Eaton's data suggest that this design limit can vary by steel variety, but for grain oriented electrical steel begins at 500 kVA for a 208Y/120 secondary voltage, corresponding to a line current of 1,389 A. (Eaton, No. 137 at p. 18)
Further, the normal impedance range for transformers as specified in IEEE Standard C57.12.34 changes from 1.2%-6.0% below 500 kVA to 1.5%-7.0% at 500 kVA. ^{54} Although impedance does not necessarily correlate to transformer efficiency, as discussed in section IV.C.1.d, designing to a higher impedance range leaves transformer with less design flexibility to meet amended efficiency standards.
^{54} IEEE SA. (2022). IEEE C57.12.34-2023—IEEE Standard Requirements for Pad Mounted, Compartmental-Type, Self-Cooled, Three-Phase Distribution Transformers, 10 MVA and Smaller; High-Voltage, 34.5 kV Nominal System Voltage and Below; Low-Voltage, 15 kV Nominal System Voltage and Below. Available at https://standards.ieee.org/ieee/C57.12.34/6863/ (last accessed Nov. 8, 2021).
Based on the increase in stray and eddy losses associated with high-current and the change in impedance range, DOE has concluded that transformers greater than 500 kVA warrant a separate equipment class. Specifically, DOE has evaluated two equipment classes for three-phase liquid-immersed distribution transformers based upon capacity. Equipment Class 2A corresponds to three-phase liquid-immersed distribution transformers ranging from 15 to less than 500 kVA. Equipment Class 2B corresponds to three-phase liquid-immersed distribution transformers greater than or equal to 500 kVA).
Regarding further separation of large three-phase kVA transformers based on current, DOE acknowledges that high-current transformers may experience greater challenges in meeting amended efficiency standards and higher-current transformers tend to correspond to larger kVA sizes. However, DOE analyzed the incremental costs associated with three-phase 1,500 kVA units at 208Y/120 secondaries as compared to 480Y/277 secondaries. These results are discussed in Chapter 5 of the TSD. DOE has determined that both units are capable of meeting amended efficiency standards and therefore concluded that a transformer with a higher-current does not justify having a lower efficiency standard than transformers with lower-currents. Therefore, DOE has not established a separate equipment class for high-current transformers.

d. Multi-Voltage Capable Distribution Transformers
DOE's test procedure section 5.0 of appendix A requires determining the efficiency of multi-voltage-capable distribution transformers in the configuration in which the highest losses occur. In the August 2021 Preliminary Analysis TSD, DOE acknowledged that certain multi-voltage distribution transformers, particularly non-integer ratio distribution transformers, could have a harder time meeting an amended efficiency standard as it results in an unused portion of a winding when testing in the highest losses configuration and therefore reduces the measured efficiency. (August 2021 Preliminary Analysis TSD at pp. 2-21) In response to the August 2021 Preliminary Analysis TSD, DOE received comment reiterating that these transformers may experience additional losses which could make it more difficult to comply with standards, particularly when tested in the lower voltage configuration. (Schneider, No. 49 at p. 9; ERMCO, No. 45 at p. 1; NEMA, No. 50 at p. 6; Eaton, No. 55 at p. 12)
In the January 2023 NOPR, DOE discussed how multi-voltage distribution transformers, and specifically those with non-integer ratings, offer the performance feature of being able to be installed in multiple locations within the grid (such as in emergency applications) and easily upgrade grid voltages without requiring a replacement transformer. 88 FR 1722, 1750. DOE also acknowledged that these distribution transformers often have additional, unused winding turns when operated at their lower voltage, increasing the transformer losses. Id.
However, DOE noted that the efficiency of these transformers will increase once the distribution grid is increased to the higher voltage rating and the entire winding is used. Further, stakeholder comments suggested that the difference in losses associated with multi-voltage distribution transformers is relatively small. DOE also noted that the same technologies that increase the efficiency of single-voltage distribution transformers can be used to increase the efficiency of multi-voltage distribution transformers, meaning that the efficiency of either product could be increased via the same methods to meet amended standards. Id. Therefore, DOE did not propose a separate equipment class for multi-voltage-capable distribution transformers with a voltage ratio other than 2:1 but requested comment and data on the number of shipments for and degree of additional losses experienced by these products.
Howard commented that dual voltage transformers can increase load losses by 5-24 percent, requiring transformers to be overdesigned and possibly limiting manufacturers' ability to offer certain designs. Howard additionally commented that dual voltage ratios other than 2:1 represent less than 10 percent of shipments for all equipment classes. (Howard, No. 116 at pp. 11-12)
NEMA commented that it is difficult to say exactly how load loss changes with multi-voltage transformers and estimated that fewer than 2 percent of shipments are multi-voltage transformers with ratios other than 2:1. (NEMA, No. 141 at p. 10)
Eaton commented that load loss data for transformers with a voltage ratio other than 2:1 may not show a meaningful trend because load losses are adjusted based on the no-load losses to meet standards. Instead, Eaton provided cost versus efficiency data for 500 kVA transformers which indicated that transformers with a voltage rating other than 2:1 are capable of achieving effectively the same efficiencies as transformers with a single voltage rating. The data provided also indicated that the proposed efficiency levels could be met at a similar incremental cost for either a multi-voltage or single-voltage transformer. However, Eaton went on to state that this may vary across voltage and kVA ratings and that there is insufficient data to draw broad conclusions. (Eaton, No. 137 at pp. 14-15) Eaton additionally commented that they construct a considerable number of dual-voltage units, and provided data stating that 13.9 percent of their single-phase units and 4 percent of their three-phase units have non-2:1 voltage ratios. (Eaton, No. 137 at p. 15)
Carte commented that the cost to meet proposed efficiency levels with a GOES transformer increases substantially for dual- and multi-voltage transformers. (Carte, No. 140 at p. 9)
As described in section IV.A.2.d of this document, DOE may establish a separate equipment class for a product if DOE determines that separate standards are justified based on the type of energy used, or if DOE determines that a product's capacity or other performance-related feature justifies a different standard. DOE acknowledges that multi-voltage capable distribution transformers may provide a unique utility in allowing the grid to be upgraded to higher voltages without requiring that a transformer be replaced. As grid modernization continues to occur and as consumer loading increases, this utility may provide a unique benefit to utilities by enabling them to utilize transformers to the full extent of their lifetime and avoid early replacements.
However, DOE has not determined that this feature results in multi-voltage capable transformers being significantly disadvantage in meeting amended standards. DOE evaluated available loss data obtained from publicly available utility bid data for liquid-immersed distribution transformers and found distribution transformers with multi-voltage ratings, both in integer and non-integer ratios, occupying the same design space as general use transformers across all kVA sizes. (See chapter 5 of the TSD for additional detail). As pointed out by Howard, multi-voltage capable transformers may need to be overdesigned to meet standards at both the higher and lower voltage rating. While this might lead to a higher base cost for these transformers, available data does not indicate that the incremental cost to meet amended efficiency standards for these units would be higher. This is illustrated by the data provided by Eaton, which shows that multi-voltage capable distribution transformers are often more expensive at baseline but follow similar cost-efficiency curves. Eaton's data also indicated that multi-voltage capable distribution transformers, including those with non-integer ratios, can be designed to meet the same efficiencies as distribution transformers with single-voltage ratings up until the edge of max-tech.
Therefore, for the reasons discussed, DOE is not creating a separate equipment class in this final rule for multi-voltage capable distribution transformers with non-integer ratios.

e. Data Center Distribution Transformers
As noted in the January 2023 NOPR, DOE considered a separate equipment class for data center distribution transformers in the April 2013 Standard Final Rule, defined as the following:
“i. Data center transformer means a three-phase low-voltage dry-type distribution transformer that—
(i) is designed for use in a data center distribution system and has a nameplate identifying the transformer as being for this use only;
(ii) has a maximum peak energizing current (or inrush current) less than or equal to four times its rated full load current multiplied by the square root of 2, as measured under the following conditions—
1. during energizing of the transformer without external devices attached to the transformer that can reduce inrush current;
2. the transformer shall be energized at zero +/−3 degrees voltage crossing of a phase. Five consecutive energizing tests shall be performed with peak inrush current magnitudes of all phases recorded in every test. The maximum peak inrush current recorded in any test shall be used;
3. the previously energized and then de-energized transformer shall be energized from a source having available short circuit current not less than 20 times the rated full load current of the winding connected to the source; and
4. the source voltage shall not be less than 5 percent of the rated voltage of the winding energized; and
(iii) is manufactured with at least two of the following other attributes:
1. Listed as a Nationally Recognized Testing Laboratory (NRTL), under the Occupational Safety and Health Administration, U.S. Department of Labor, for a K-factor rating greater than K-4, as defined in Underwriters Laboratories (UL) Standard 1561: 2011 Fourth Edition, Dry-Type General Purpose and Power Transformers;
2. temperature rise less than 130 °C with class 220 ^{(25)} insulation or temperature rise less than 110 °C with class 200 ^{(26)} insulation;
3. a secondary winding arrangement that is not delta or wye (star);
4. copper primary and secondary windings;
5. an electrostatic shield; or
6. multiple outputs at the same voltage a minimum of 15° apart, which when summed together equal the transformer's input kVA capacity.” ^{55}
^{55} 78 FR 23336, 23358.
In the April 2013 Standards Final Rule, DOE did not adopt this definition of “data center distribution transformers” or establish a separate class for such equipment for the following reasons: (1) the considered definition listed several factors unrelated to efficiency; (2) the potential risk of circumvention of standards and that a transformer may be built to satisfy the data center definition without significant added expense; (3) operators of data centers are generally interested in equipment with high efficiencies because they often face large electricity costs, and therefore may be purchasing at or above the standard established and unaffected by the rule; and (4) data center operator can take steps to limit inrush current external to the data center transformer. 78 FR 23336, 23358.
In the August 2021 Preliminary Analysis TSD, DOE stated that data center distribution transformers could represent a potential equipment class-setting factor and requested additional data about the data center distribution transformer market, performance characteristics, and any physical features that could distinguish data center distribution transformers from general purpose distribution transformers. (August 2021 Preliminary Analysis TSD at pp. 2-22) However, DOE did not receive any comments as to physical features that could distinguish a data center distribution transformer from a general purpose distribution transformer.
In the January 2023 NOPR, DOE did not propose a definition for data center distribution transformers and did not evaluate them as a separate equipment class. However, DOE noted that it may consider a separate equipment class if provided sufficient data to demonstrate that data center transformers warrant a different efficiency level and can appropriately be defined. 88 FR 1722, 1751. Accordingly, DOE requested comment on its proposal not to establish a separate equipment class for data center distribution transformers and on any identifying features related to efficiency which would prevent a data center transformer from being used in general purpose applications. Id.
ABB SP commented that it supports a separate equipment class for data center transformers with standards maintained at the current levels. (ABB SP, No. 110 at pp. 1-2)
DOE noted that distribution transformers used in data centers may sometimes, but not necessarily, be subject to different operating conditions and requirements which carry greater concern surrounding inrush current. 88 FR 1722, 1751. DOE requested comment on the interaction of inrush current and data center distribution transformer design. Id.
Regarding the specific challenges related to inrush current for data center distribution transformers, Schneider and NEMA commented that because of the frequent energizing of data center transformers, designers typically seek to limit inrush to prevent nuisance trips of the system. However, both Schneider and NEMA further stated that the concerns for data center transformers inrush current are similar to the concerns for all LVDTs, and while inrush is often related to installation and restoration after power loss, increased adoption of alternate power systems will mean more general purpose LVDTs will have concerns when power is transferred from one source to another. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 12)
Regarding inrush current more broadly, Schneider and NEMA commented that the maximum inrush must be less than the over current trip value. (Schneider, No. 101 at pp. 6-8; NEMA, No. 141 at pp. 12-13) Schneider and NEMA further stated that inrush current can be limited using lower quality steel, modifying coil windings, and modifying core configurations. Id. Schneider and NEMA commented that nuisance tripping can be addressed by adding circuit resistance during energization of transformers, using electronic circuit breakers with adjustable trip settings, designing electrical system with the maximum allowed overcurrent protective device; however, all these approaches would add cost. Id.
Schneider commented that while DOE assumes equipment will be redesigned or modified to handle inrush, the market has not yet started this analysis. (Schneider, No. 101 at pp. 12-13) Schneider stated that the 2016 standards increased the size of the primary over current protection device near the limits set by the National Electric Code. Schneider commented that customers today can use electronic trip breakers or secondary breakers to address inrush concerns, but those solutions may not be suitable for the amended efficiency levels. Id.
ABB SP commented that data center transformers must be designed to account for inrush both during startup and during operation when part of the electrical system fails, and power is diverted to a redundant component. (ABB SP, No. 110 at p. 2) ABB SP stated that, while upstream infrastructure could be upsized to accommodate inrush current, this would decrease overall data center efficiency and consume more energy. Id.
APPA commented that higher inrush currents may require a change of protective equipment, such as relays, at a higher cost. (APPA, No. 103 at p. 13) APPA further stated that there is insufficient data on how to size protective devices for higher inrush, which will lead to transformer failure or excessive device tripping. Id. APPA stated that, in either scenario, excess fuse tripping will lead to millions of dollars of additional costs. Id. As such, APPA commented that DOE should publish protection standards and short circuit information prior to any changes and give a 4-year lead tie for industry to gain experience with amorphous transformers. Id.
Eaton commented that general use LVDT transformers can be designed to generate inrush currents up to 25x rated current, but data center transformers cannot exceed 8x rated current to avoid potential power outages. (Eaton, No. 137 at p. 34) Eaton further commented that traditional inrush current limiting schemes, such as impedance insertion, are not viable for data center transformers because they starve the critical load of rated operating voltage. Id. Eaton stated that mitigating inrush current by controlling transformer energization is also not feasible for data center transformers because the required equipment would delay energization. Id.
Prolec GE commented that the inrush current limit is 25x rated current for both data center transformers and general-use transformers as defined in IEEE standard C37.48.1. (Prolec GE, No. 120 at p. 7) Prolec GE commented that peak inrush current is determined by the air core inductance ^{56} and not the core steel. Id. Prolec GE also stated that technologies to mitigate inrush current have high complexity, low reliability, and high costs. Id. Prolec GE also stated that the relationship between operational flux density and remanence ^{57} matters more with regard to inrush current than the absolute magnitude of remanence. Id.
^{56} The air core inductance of transformer represents the properties of the winding if there were no core to induce ( i.e., using an “air core”). Peak inrush can be approximated based on the air core inductance because when a transformer is pushed into saturation conditions, which is when maximum inrush would occur, the instantaneous induction of the core is very low, allowing it to be modelled as an air core.
^{57} Operational flux density represents the max flux density at which a transformer is designed to operate, whereas remanence represents the magnitude of flux density that remains in a core after being de-energized. Both the remanence and the operational flux density must be considered when designing a transformer such that the core will not be pushed above its saturation flux density during normal operation, which can lead to very high inrush current and potentially damage the transformer or downstream equipment.
Stakeholder comments suggest that inrush current concerns may be of particular importance for data center distribution transformers, due to the sensitive nature of the equipment placed downstream of the transformer. Stakeholder comment also suggest that increased efficiency standards can increase the likelihood of inrush conditions exceeding the limitations of standard protective equipment, depending on how the flux density and construction of the core are modified to increase transformer efficiency.
However, increased inrush current is not guaranteed to occur because of increasing transformer efficiency and is partially within the control of the transformer designer. For example, designing a transformer with a lower flux density decreases the likelihood and magnitude of inrush current occurrences. Stakeholder feedback indicates that technologies exist to limit and protect against inrush current in situations when the transformer design cannot be modified to do so. Therefore, DOE does not consider inrush current to be an inhibiting factor which would prevent transformer manufacturers from meeting amended efficiency standards.
In the January 2023 NOPR, DOE also requested comment on the specific challenges that might arise with designing data center distribution transformers with cores made of amorphous cores. 88 FR 1722, 1751.
Metglas commented that it is not aware of any technical issues to prevent the use of amorphous transformer cores in data center applications. (Metglas, No. 125 at p. 5) Metglas commented that inrush current varies based on impedance for amorphous transformers and is not 20 percent different than for a GOES unit at the same impedance. (Metglas, No. 125 at p. 5)
Howard commented that it is unaware of any challenges with data center transformers and is not aware of amorphous core transformers being built for the data center market. (Howard, No. 116 at p. 13)
Schneider, Eaton, and NEMA stated that the inherent air gaps, high saturation flux density, and lower remnant flux density of stacked core construction cores helps limit inrush currents, but would no longer be viable under the proposed standards since amorphous can only be used in wound cores. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 11; Eaton, No. 137 at p. 37) Eaton commented that using amorphous in data center transformers in PDUs will require significant research and development because each of these units has specific requirements and cannot be standardized. (Eaton, No. 137 at p. 3)
Eaton commented that, due to the increased remnant flux and reduced saturation flux density, a data center transformer designed with an amorphous core would need to operate at about 9 to 12.6 kG to keep inrush current within the 4-8X limit. (Eaton, No. 137 at p. 35) Eaton stated that inrush current may be reduced for wound core amorphous transformers by increasing the winding turns to increase air core inductance, but this also increases load losses, impedance, winding temperature rise, and cost. Id. ABB SP further commented that the lower flux density of amorphous cores would require manufacturers of data center transformers to choose between higher inrush currents during emergency power transfers, longer transfer times, or significantly larger core and coil size. (ABB SP, No. 110 at p. 2)
DOE received several comments stating that higher efficiency units, and specifically amorphous core transformers, are less efficient at higher loading than conventional GOES transformers. For dry-type units, Eaton commented that PDU transformers designed to meet DOE standards at 35 percent loading are less efficient during typical operation at 60-80-percent load and this problem will be exacerbated by amorphous. (Eaton, No. 137 at p. 37) NEMA and Schneider commented that amorphous cores have not been used in data center applications and would not maximize savings because average loading is typically 65-80 percent. (Schneider, No. 92 at p. 6; NEMA, No. 141 at p. 11)
Powersmiths commented that the proposed efficiency standards at 35 percent loading will significantly increase losses in high load applications, such as data centers. (Powersmiths, No. 112 at p. 5) Accordingly, Powersmiths recommended that DOE consider a provision to accommodate high transformer load applications, such as exemptions for specific use cases or different requirements at a higher load point. Id.
Regarding stakeholder comment that data center distribution transformers transformer loading may be higher than general purpose transformers, DOE agrees that operating conditions with higher loading applications benefit less from reduced no-load losses. However, DOE disagrees that amorphous cores inherently are less efficient at higher loading. As discussed in section IV.C.1, amorphous transformers are not inherently designed with higher load losses. The reduced no-load losses for amorphous transformers provide additional design flexibility in meeting efficiency standards, often resulting in higher load losses to reduce costs in a minimally compliant amorphous transformer. However, amorphous transformers can be designed to target lower load losses, just as GOES transformers can. Further, DOE's modeling includes a variety of designs at higher efficiency levels, some with higher load losses and some with lower load losses. Hence, manufacturers have the capability to redesign transformers to meet higher efficiency standards either by reducing the no-load losses, reducing the load losses, or reducing some combination of the two.
DOE received additional comments that amorphous-core transformers in data center applications would be larger, which could create additional challenges.
For liquid-immersed units, Eaton stated that most of its data center transformers are in the size range of 2,500 to 3,500 kVA, which is outside the current range of transformer sizes that Eaton designs with amorphous cores. (Eaton, No. 137 at p. 21) Eaton also commented that the larger size of wound core amorphous transformers will increase the size of PDUs and go against Data Centers Industry efficiency goals for high power density per unit area. (Eaton, No. 137 at pp. 37-38) Eaton further stated that wound core designs may have difficulty meeting specific PDU requirements due to reduced design flexibility and greater likelihood of DC and/or subharmonic voltages issues resulting from the lack of air gaps. (Eaton, No. 137 at p. 38)
ABB SP commented that the increased volume of data center transformers designed with amorphous cores would increase load losses, strain the elevated floor systems common for PDU's, and remove the ability to replace transformers at the end of life due to other necessary changes to accommodate the increased volume. (ABB SP, No. 110 at p. 2)
As indicated by stakeholders, amorphous metal is not commonly utilized in the U.S. data center distribution transformer market today, resulting in limited data from manufacturers available to assess the performance of amorphous units in data center applications. Stakeholder comments identified challenges with using amorphous core transformers related to transformer inrush and transformer size. Stakeholder comment suggests that those challenges could be overcome, such as reducing an amorphous cores flux density or modifying protective equipment. However, these changes may have additional costs. Further, many of those challenges identified for data center transformers were noted as existing for all LVDTs, not something necessarily unique to data center transformers.
In DOE's review of the international market DOE observed several manufacturers marketing dry-type transformers with an amorphous metal core. 58 59 60 61 DOE also observed marketing of amorphous core transformers being used in data centers. 62 63 The existence of amorphous metal cores in dry-type distribution transformers, and particularly in LVDT distribution transformers, demonstrates the technological feasibility of converting to amorphous. While stakeholders indicated that data center distribution transformer may be subject to additional design constraints, commenters did not provide data to demonstrate how these design constraints may be impacted when using amorphous metal or specifics as to what these additional costs would be and when they come into effect ( e.g. only beyond certain kVA sizes, only in certain applications, etc. ). As such, DOE has concluded that there is insufficient data to warrant a separate equipment class for data center transformers.
^{58} Toyo Electric, Dry-Type Amorphous Core Transformer. Available at: www.toyo-elec.co.jp/products/download/catalog/transform/Amorphous_EN.pdf (last accessed Nov. 7, 2023).
^{59} Jiangsu Ryan Electric Company, SCBH15, SGBH15, SCBH16, SGBH16 amorphous alloy dry-type transformer. Available at en.redq.cc/SCBH15-SGBH15-SCBH16-SGBH16-amorphous-alloy-dry-type-transformer-pd49182496.html (last accessed Nov. 7, 2023).
^{60} Yuebian Electric, Amorphous Alloy Dry Type Transformer. Available at www.zjyb-electric.com/products/amorphous-alloy-dry-type-transformer.html (last accessed Nov. 7, 2023).
^{61} China Electric Equipment Group, Amorphous Alloy Dry Type Transformer Three Phase Power Transformer Factory. Available at ceegtransformer.com/products/amorphous-alloy-dry-type-transformer-three-phase-power-transformer-factory (last accessed Nov. 7, 2023).
^{62} CEEG, 42 Units of CEEG Amorphous Alloy Transformers For Data Center were Successfully Energized. Available at www.cnceeg.com/news/42-units-of-ceeg-amorphous-alloy-transformers-48777661.html (last accessed Nov. 7, 2023).
^{63} Qingdao Yunlu Advanced Materials Technology Co. Ltd. Introduction to Amorphous Alloy Core. Available at www.yunluamt.com/product-44-1.html (last accessed Nov. 7, 2023).
Stakeholders also commented as to what physical features of data center transformers could be identified to define data center transformers as an equipment class separate from other general purpose distribution transformers.
ABB SP commented that data center transformers are primarily distinguished from general purpose LVDT transformers by their application, with most data center transformers used in PDU's. Id. ABB SP stated that transformers used in PDUs must be designed to accommodate specific system requirements, including power quality requirements, exposure to harmonic sources, continuous loading at 50-90 percent, and the ability to supply a diverse variety of power sources without going into saturation or changing tap connections. Id. ABB SP also commented that since 2013, data center transformers have become larger, begun using elevated secondary voltage ratings, are designed with greater protections for arc flash and fault current, and are designed at higher ambient temperature. Id.
Eaton recommended that DOE specifically exempt low-voltage transformers used in PDUs for data centers. (Eaton, No. 137 at p. 2) Eaton commented that data center transformers are not sold as standalone equipment but rather as part of power distribution units (PDUs). (Eaton, No. 137 at p. 34) Eaton further commented that data center transformers have specific design requirements which distinguish them from general-purpose units, including (1) an inrush current rating of 8x or lower, (2) a higher k-factor to accommodate non-linear loads, (3) a requirement for two electrostatic shields connected to the ground, ^{64} (4) increased insulation inside the winding and increased clearances from the winding to ground to improve reliability, (5) and an occasional requirement for a lower temperature rise, which is becoming increasingly common in data center design. (Eaton, No. 137 at pp. 34-36) Eaton also commented that wide range of impedance requirements can make it difficult to design PDU transformers which both comply with DOE standards and meet k-factor specifications. (Eaton, No. 137 at p. 36) Eaton additionally commented that data center transformers must be operated using low flux and current densities to meet standards, which is an inefficient use of resources. (Eaton, No. 137 at p. 36)
^{64} Eaton commented that this is a unique requirement for all PDU transformers (Eaton No. 137 at p. 36)
Schneider commented that a separate equipment class is not required for data center transformers as it opens the door to many other industry segments requesting exclusions. (Schneider, No. 92 at pp. 4-5) Schneider commented that there are attributes for data center transformers that may make it more difficult to comply with energy conservation standards; however, these difficulties may be reduced with higher efficiency levels. Id. Schneider gave the example of K-ratings not being necessary for higher efficiency transformers because the thermal characteristics are no longer the limiting factor of kVA. Id. Schneider further commented that many of the concerns seen by the data center market would exist for all applications. Id. Schneider commented that the only way to prevent data center transformers from being used in general purpose applications would be to limit the secondary voltage to certain values. Id. Schneider also stated that requiring a secondary winding arrangement that is not delta or wye, as proposed in the April 2013 Standards Final Rule, relates to efficiency in that the efficiency of a transformer with a zig-zag secondary is less impacted under harmonic loading. Id.
Howard commented that no guidelines are needed to prevent data center transformers from being used in general purpose applications. (Howard, No. 116 at p. 13) Metglas commented that there does not seem to be a technical distinction between a data center transformer and a standard transformer. (Metglas, No. 125 at p. 5)
DOE recognizes that distribution transformers used in data center applications may be subject to unique requirements separate from those used in general-purpose applications, such as specific size constraints or a need for a higher k-factor. However, when establishing separate equipment classes for product groups, DOE is required to focus on capacity and performance related features that impact consumer utility. As indicated by stakeholders, the primary distinguisher between data center distribution transformers and general-purpose distribution transformers is their installation location, not the capacity or features of the transformer itself.
Further, in its review of manufacturer literature, DOE observed multiple manufacturers advertising general use transformers specifically designed with higher k-factor ratings, low inrush current, and/or electrostatic shields, all of which are design features suggested by commenters as being characteristic of data center transformers. As stated by Schneider, a number of applications, such as LVDT transformers used in hospital units, may require similar design requirements to those specified for data center transformers.
While some commenters provided specific features attributable to data center transformers, DOE notes that the majority of these features are not unique to data center distribution transformers. For example, several stakeholders indicated that data center distribution transformers must be designed with a higher k-factor to accommodate harmonic loading. In support of this claim, Eaton provided data comparing size and efficiency of DOE's modeling to k-factor rated transformers. However, Eaton's data did not demonstrate how an amorphous data center transformer would perform in this comparison. As stated by Schneider, the increased efficiency and reduced losses of an amorphous transformer would reduce the excess heat dissipation in a transformer, potentially reducing the need for higher k-factors.
In this final rule, DOE is not establishing a separate equipment class for data center distribution transformers. Based on the feedback received, DOE maintains that there are not sufficient physical features to differentiate data center distribution transformers from general-purpose distribution transformers. DOE does not have sufficient data to indicate that the characteristics that often distinguish a distribution transformer used in data center applications from one used in general purpose applications, such as a higher k-factor, would inhibit these units from being designed to meet an amended efficiency standard. Therefore, for the reasons discussed, DOE is not establishing a separate equipment class for data center transformers in this final rule.
While stakeholders did identify legitimate challenges associated with data center transformers, most stakeholders noted that they could be overcome. However, there is uncertainty as to the downstream impacts on protective equipment and transformer sizes, along with uncertainty of the costs associated with overcoming those challenges. For example, in circumstances when inrush current may become a concern for data center applications, additional measures may be taken to mitigate inrush conditions, both regarding the design of the transformer and the external technologies that could be applied. However, the degree of difficulty associated with each of these challenges is largely dependent on the compliance period with which stakeholders must meet amended efficiency standards and the degree of efficiency improvement of any proposed standards. DOE notes that the compliance period in this final rule is longer than the proposed in the NOPR and efficiency levels for LVDT units is lower than was proposed in the NOPR, indicating that manufacturers will have both more time and more design flexibility to overcome the challenges identified in response to the NOPR. DOE further notes that its adopted energy efficiency standards are achievable using many designs with continued usage of stacked core GOES designs, wherein manufacturers have considerable experience in designing data center transformers.

f. BIL Rating
Distribution transformers are built to carry different basic impulse insulation level (BIL) ratings. BIL ratings offer increased resistance to large voltage transients, for example, from lightning strikes. Due to the additional winding clearances required to achieve a higher BIL rating, high BIL distribution transformers tend to be less efficient, leading to higher costs and potentially more difficulty in achieving higher efficiencies. DOE currently separates medium-voltage dry-type distribution transformers into equipment classes based on BIL ratings, with classes for transforms with BIL ratings ranging from 20-45 kV, 46-95 kV, and above 96 kV. 10 CFR 431.196(c).
In the January 2023 NOPR, DOE discussed stakeholder comments which indicated that transformers with high BIL designs (≥150 BIL or ≥200 BIL) may experience higher losses that could inhibit them from meeting amended efficiency standards. 88 FR 1722, 1752. However, because no stakeholders provided data to indicate the degree to which transformers with high BIL ratings may be disadvantaged and because separating liquid-immersed transformers by BIL rating would add additional complications for potentially minor differences in losses, DOE did not propose separate equipment class based on BIL rating for liquid-immersed units.
In response to the January 2023 NOPR, DOE received several additional comments pertaining to BIL ratings for liquid-immersed distribution transformers.
Eaton commented that smaller kVA units with higher-voltage primary ratings, and corresponding higher BIL ratings, are more expensive to build; however, Eaton went on to state that these units are generally outside of the scope of what is commonly manufactured by Eaton. (Eaton, No. 137 at p. 21) Eaton added that the max-tech efficiency of a 500 kVA unit was similar for either a lower or higher BIL rating. (Eaton, No. 137 at p. 21)
Prolec GE commented that higher BIL designs have increased core and coil dimensions to account for the additional insulation needed, increasing the transformer losses. (Prolec GE, No. 120 at p. 8) Howard commented that each BIL increase results in a 0.02-0.07 percentage point drop in efficiency. (Howard, No. 116 at p. 13)
Carte commented that the increase in cost to meet the same efficiency for 200 kV BIL designs is the following: (1) a 20 percent increase relative to DOE's modeled 500 kVA, single-phase, 150 kV BIL design; (2) a 5 percent increase relative to DOE's modeled 150 kVA, three-phase, 95 kV BIL design; and (3) 16 percent increase relative to DOE's modeled 1,500 kVA, three-phase, 125 kV BIL design. (Carte, No. 140 at pp. 8-9)
To assess whether liquid-immersed units with high BIL ratings warranted being regulated under a separate equipment class, DOE evaluated publicly available utility bid data to investigate the performance of otherwise equivalent transformers with different BIL ratings. Based on this review, DOE observed designs with high BIL ratings (≥150 BIL) meeting higher efficiencies at a variety of kVA sizes. As stated by several stakeholders, units with higher BIL ratings may have a higher cost associated with them due to the added insulation and increased overall size of the unit. While the baseline cost for a high BIL unit may be greater than that for a lower BIL rating, DOE data indicates that the incremental cost to meet the amended efficiency standards would be similar for a transformer with a high BIL rating as opposed to one with a lower BIL rating. As such, DOE does not expect the consumers to lose access to the utility associated with high BIL designs absent designation in a new separate class.
Further, DOE notes that the cost increases and efficiency decreases referenced by stakeholders most likely assume that higher efficiencies are being achieved using a GOES core. DOE notes that its analysis shows that max-tech efficiency designs are able to reduce losses by considerably more than both the proposed standards for liquid-immersed distribution transformers and the adopted standards. While it may be considerably more expensive to have higher BIL designs with a GOES core at high-efficiency levels, manufacturers also have the option of using an amorphous core, which has a relatively flat cost-efficiency curve across significantly higher-efficiency levels.
Therefore, for the reasons discussed, DOE is not creating a separate equipment class based on BIL rating for liquid-immersed units in this final rule.

g. Other
DOE received additional comments discussing other potential equipment classes but generally did not receive any data regarding what technical features associated with these products warrant a separate equipment class.
NEMA commented that DOE should consider not including shovel transformers, above ground mining transformers, crane duty transformers, and marine application transformers. (NEMA, No. 141 at p. 13)
DOE notes that NEMA did not include any data or comment regarding the specific technical challenges this equipment would have in meeting efficiency standards or even suggest that these challenges exist. NEMA also did not provide comment regarding the physical features that would allow this equipment to be defined as compared to other general purpose distribution transformers. Therefore, DOE has not considered separate equipment classes for this equipment.
DOE received comment regarding triplex core transformers, which include three, single-phase core-coil assemblies grouped together to form a three-phase transformer. WEC commented that it commonly uses a triplex core design to prevent ferro resonance, which requires more pounds of core steel per kVA and could mean amended efficiency standards result in higher incremental costs. (WEC, No. 118 at p. 2) WEC commented that further increases in efficiency requirements could lead to the elimination of triplex core transformers, which would present additional operational and safety challenges to WEC employees and significantly extend outages to customers. Id. Howard supported creating a different equipment class for 3-phase pole mounted transformers because of their unique triplex design. (Howard, No. 116 at pp. 25-26) Howard additionally supported dividing pole and pad mounted transformers into separate equipment classes as utilities can more easily accommodate larger pad-mounted transformers. Id.
While triplex core transformers have more core steel per kVA than a traditional three-phase transformer, DOE did not receive any data as to the degree of difference. DOE notes that lower-loss core steel technology options would be expected to improve the performance of both traditional three-phase transformers and triplex core transformers. DOE's max-tech efficiency levels are typically met with amorphous cores, which would have lower no-load losses for both traditional three-phase transformer cores and triplex core transformers. Further, as WEC noted, triplex core transformers can be used in the exact same applications as three-phase pad-mounted transformers. For these reasons, DOE has not considered a separate equipment class for triplex core transformers. To the extent pole and pad-mounted transformers may have different installation challenges, those costs are accounted for in the installation costs, discussed in section IV.F.4 of this document.
Standards Michigan recommended DOE remove obstacles to manufacturers who choose to produce inexpensive, mobile transformers designed for the purpose of preventing civil unrest during major regional contingencies. Standards Michigan went on to state that these MRC transformers could be placed in a new product class. (Standards Michigan, No. 109 at pp. 1-2)
Utilities tend to keep distribution transformer reserves available for emergency situations, such as during a natural disaster or other storm. DOE notes that it develops separate equipment classes based on specific class-setting factors as set forth by EPCA, as described in section IV.A.2. (42 U.S.C. 6316(a); 42 U.S.C. 6295(q)(1)). Standards Michigan did not identify any specific features associated with contingency transformers. Therefore, DOE has not established a separate equipment class for these contingency transformers.

3. Technology Options
In the preliminary market analysis and technology assessment, DOE identified several technology options initially determined to improve the efficiency of distribution transformers, as measured by the DOE test procedure.
Increases in distribution transformer efficiency are based on a reduction of distribution transformer losses. There are two primary varieties of loss in distribution transformers: no-load losses and load losses. No-load losses are roughly constant with PUL and exist whenever the distribution transformer is energized ( i.e., connected to electrical power). Load losses, by contrast, are zero at zero percent PUL but grow quadratically with PUL.
No-load losses occur primarily in the transformer core, and for that reason the terms “no-load loss” and “core loss” are sometimes interchanged. Analogously, “winding loss” or “coil loss” is sometimes used in place of “load loss” because load loss arises chiefly in the windings. For consistency and clarity, DOE will use “no-load loss” and “load loss” generally and reserve “core loss” and “coil loss” for when those quantities expressly are meant.
Distribution transformer design is typically an optimization process. For a given core and conductor material, the mass and dimensions of the transformer core, winding material, insulation, radiators, transformer tank, etc., can be varied to minimize costs while meeting a variety of design criteria. Within a manufacturer's optimization process, transformers can be designed to be minimally efficient or, if customers place a dollar value on electrical loss, can be designed to minimize the transformers total owning costs. Typically, small improvements in efficiency can be met with modest increase in material quantities; however, at some point, achieving any further increases in efficiency can substantially increases costs ( i.e., hitting the “efficiency wall” where costs rise dramatically for small increases in efficiency).
Once manufacturers have reached the “efficiency wall” for a given core and conductor material, the only realistic option for meeting higher efficiency values is to transition to core materials with lower no-load losses and/or transition from aluminum to copper winding material. The relative costs and availability of these lower-loss core materials has varied over time and is discussed in detail in section IV.A.4 of this document.
With respect to analyzed inputs, in the engineering analysis, DOE considered various combinations of the following technology options to improve efficiency: (1) Higher grade electrical core steels, (2) different conductor types and materials, and (3) adjustments to core and coil configuration.

4. Transformer Core Material Technology and Market Assessment
Distribution transformer cores are constructed from a specialty kind of steel known as electrical steel. Electrical steel is an iron alloy which incorporates small percentages of silicon to enhance its magnetic properties, including increasing its magnetic permeability and reducing the iron losses associated with magnetizing that steel. Electrical steel is produced in thin laminations and either wound or stacked into a distribution transformer core shape.
Electrical steel used in distribution transformer applications can broadly be categorized as either amorphous alloy or GOES. There are different subcategories of material performance within both amorphous alloy and grain-oriented electrical steel. In the January 2023 NOPR, DOE carried over the same naming convention developed in the August 2021 Preliminary Analysis TSD to identify the various permutations of electrical steel. 88 FR 1722, 1754.
DOE notes that producing distribution transformer cores with amorphous alloy requires different core production machinery than producing distribution transformer cores with GOES. As such, some amount of investment in machinery is required to transition between producing cores with amorphous alloy and GOES. Today, there are many equipment classes and kVA sizes where amorphous core transformers compete with GOES transformers on first cost. However, the vast majority of current core production equipment is set-up to produce GOES cores, and therefore the vast majority of transformer shipments use GOES cores even for products where using an amorphous core would lead to a lower first-cost to the consumer.
In meeting efficiency standards with GOES, DOE notes that using lower-loss GOES steel allows manufacturers to achieve modest improvements in efficiency with essentially identical designs ( e.g., essentially no increase in product weight, just a direct swap of higher-loss core steel with lower-loss core steel). However, there is a limited capacity of lower-loss GOES grades and only a single domestic manufacturer of GOES steel, which limits the availability of GOES products to distribution transformer manufacturers.
In achieving higher efficiencies without changing GOES steel performance, Eaton commented that manufacturers increase the core cross sectional area and decrease the flux density. (Eaton, No. 137 at pp. 21-22) The larger transformer cores require thicker conductors in order to maintain current density but using thicker conductors increases stray and eddy losses, which requires even larger conductor size to combat the additional stray and eddy losses. (Eaton, No. 137 at pp. 21-22) Eaton stated that at some point, the only option is to transition to copper windings, at which point the cost of the transformer skyrockets and significant cost increases are needed for even modest efficiency gains. (Eaton, No. 137 at pp. 21-22)
In other words, achieving higher efficiencies without reducing the losses of the core steel material is technically possible but gets increasingly difficult (in terms of significant increases in product weights and selling prices) as manufacturers attempt to reduce losses further.
If lower-loss GOES were widely available, distribution transformer manufacturers could achieve modest improvements in efficiency with essentially identical designs ( e.g., essentially no increase in product weight, just a direct swap of higher-loss core steel with lower-loss core steel). However, as with higher-loss GOES, beyond a certain point reducing losses further is technically possible but results in substantial increases in product weight and selling price.
In the current market, distribution transformer manufacturers limit themselves to the single domestic GOES manufacturer's product offerings and pricing, as any imported GOES steel is subject to a tariff that makes such steel uncompetitive. Therefore, increasing the domestic availability of lower-loss GOES steel depends on the investments in product quality made by the single domestic GOES manufacturer.
Amorphous cores reduce transformer no-load losses by approximately 50 to 70 percent relative to GOES (see Chapter 5 of the TSD for relative performance of amorphous- and GOES-based designs). This substantial reduction in no-load losses means that much higher efficiency standards can be achieved with amorphous cores (DOE's max-tech efficiency assumes use of an amorphous core) and there is more flexibility in designing transformers to meet efficiency standards (in terms of the weight and dimensions of the cores, amount of winding material, etc.).
However, the different production equipment associated with producing amorphous cores means that distribution transformer manufacturers must decide how to meet potential amended efficiency standards. If using amorphous cores, manufacturers would need to make substantial investments in amorphous core production equipment. In exchange, they would likely be able to sell many transformer ratings at a lower first cost and win business in doing so. Alternatively, manufacturers could continue to use existing GOES production equipment, however, they would likely be selling a transformer at a higher first cost.
For modest reductions in transformer losses (generally through EL2 for liquid-immersed distribution transformers and EL 3 for dry-type distribution transformers), the difference in first cost is not substantial enough to warrant the considerable investment in amorphous core production that is needed to meet efficiency standards. However, between EL2 and EL4 for liquid-immersed distribution transformers and EL3 and EL5 for dry-type distribution transformers, the size and weight increase associated with GOES cores become substantial and it generally becomes economically infeasible to continue producing GOES transformers unless consumers ignore product cost ( e.g., if shortages have forced consumers to purchase any transformer they can access, regardless of product costs).
DOE notes that in this final rule, it evaluated an additional TSL for liquid-immersed distribution transformers (TSL 3) that is a combination of proposed ELs, wherein some equipment classes are set at EL2 and other equipment classes are set at EL4. DOE notes that the ELs used in the final rule correspond to an identical reduction in losses as the ELs used in the January 2023 NOPR. However, the grouping of these ELs by equipment class has been modified in response to stakeholder feedback. In consideration of this feedback, for this final rule DOE regrouped the ELs that comprise TSL 3 such that EC1A and EC2A were evaluated at EL4, which is expected to predominantly be met via use of amorphous cores, while EC1B and EC2B were evaluated at EL2, which can be met via use of either GOES or amorphous cores. The new TSL 3 is intended to reflect stakeholder concerns that standards requiring substantial amorphous core production are not economically justified. As explained further below, TSL 3, which DOE is adopting in this final rule, is economically justified, technologically, feasible and maximizes energy savings without requiring an entire market transition to amorphous cores.
Under the adopted standard, the kVA ranges that will be required to meet EL4 represent only a portion of the overall distribution transformer market, and the volumes of amorphous steel required to supply this segment of the market is similar to the existing domestic amorphous ribbon production. As such, the adopted standard ensures that even absent significant growth in amorphous ribbon production, capacity in that market will be sufficient to meet demand in the transformer market. Further, the kVA ranges that have to meet EL2 approximately correspond with the existing domestic GOES production that serves the distribution transformer market. Accordingly, DOE has determined that this TSL ensures that manufacturers will not have to scrap existing production equipment. Rather, manufacturers of distribution transformers, amorphous ribbon, and GOES steel can all focus on and invest in increased production.
The various markets, technologies, and naming conventions for amorphous and GOES are discussed in the following sections, along with a discussion as to the expected variables manufacturers would consider in deciding how to meet amended efficiency standards.

a. Amorphous Alloy Market and Technology
Amorphous alloy ^{65} is a variety of core material that is produced by rapidly cooling molten alloy such that crystals do not form. The resulting product is thinner than GOES and has lower core losses, but it reaches magnetic saturation at a lower flux density.
^{65} Throughout this rulemaking, amorphous alloy is referred to by stakeholders using various terms including “amorphous”, “amorphous alloy”, “amorphous material”, and “amorphous steel”. Each of these terms generally refers to amorphous ribbon which is then formed into an “amorphous core” that is used in the transformer.
DOE has identified three subcategories of amorphous alloy as possible technology options. These technology options and their DOE naming shorthand are shown in Table IV.4.
In the January 2023 NOPR, DOE discussed that it did not include any designs which utilized high-permeability amorphous because, although there are some design flexibility advantages to using high-permeability amorphous, it is only available from a single supplier. 87 FR 1722, 1754. DOE further noted that, in interviews, manufacturers had expressed a hesitance to rely on a single supplier of amorphous for any higher volume unit. Id. However, DOE also stated that hibam material can generally be used in place of standard am designs, though some specific applications may require redesigning. This assumption was supported by stakeholder comments in response to the August 2021 Preliminary Analysis TSD, as discussed in the January 2023 NOPR. 87 FR 1722, 1754-1755. Therefore, it is appropriate to include only standard am designs in the engineering analysis to avoid setting efficiency standards based on a steel variety, hibam, that is only available from a single supplier. Under this approach, manufacturers have the option to achieve efficiency levels that require am steel using either the standard am material or the hibam material depending on their sourcing practices and preferences. Id.
In the January 2023 NOPR, DOE also discussed the existence of a hibam material that uses domain refinement (“hibam-dr”) to further reduce core losses. 87 FR 1722, 1755. DOE stated that it had learned through interviews that the hibam-dr product is not yet widely commercially available. As such, DOE did not include the hibam-dr product in its analysis because DOE could not verify that the core loss reduction of this product is maintained throughout the core production process and because it is only produced by one supplier. Id.
DOE notes that, since the publication of the January 2023 NOPR, it has identified additional amorphous suppliers who may offer high permeability grades, or potentially even high permeability domain refined grades. 66 67 However, total capacity for these steels remains uncertain, potentially limiting their availability for use in the domestic distribution transformer market. Further, it is uncertain what the performance of amorphous ribbon would be from manufacturers with the technological know-how to produce amorphous 68 69 but who do not currently produce wide-cast amorphous ribbon and may enter the market if demand for amorphous were to increase. Therefore, to allow greater design flexibility for manufacturers attempting to meet any amended standards, DOE has continued to exclude designs in the engineering analysis that use higher grades of amorphous.
^{66} Qingdao Yunlu Advanced Materials Technology, Amorphous Ribbon Alloy. Available at www.yunluamt.com/product-50-1.html (last accessed Nov. 8, 2023).
^{67} Qingdao Yunlu Advanced Materials Technology, Amorphous alloy strip, precursor thereof, preparation method of amorphous alloy strip, amorphous alloy iron core and transformer. China Patent No. CN116162870A. May 26, 2023.
^{68} See Guidebook for POSCO's Amorphous Metal. Available at Docket No. EERE-2010-BT-STD-0048-0235.
^{69} Vacuumschmelze GmbH and Co KG, Amorphous metal foil and method for producing an amorphous metal foil using a rapid solidification technology, U.S. Patent No. 11,623,271. Jun. 29, 2023.

Amorphous Technological Feasibility
In response to the January 2023 NOPR, DOE received additional comments regarding the performance of amorphous cores.
Powersmiths stated a concern that amorphous core transformers may exhibit certain performance defects when compared to GOES, including shards breaking off from the core, which may lead to premature failures and higher audible noise, making it more difficult or impossible to achieve NEMA ST-20 audible noise levels. (Powersmiths, No. 112 at pp. 2-3) Powersmiths additionally commented that there are many technical challenges with using amorphous cores, including non-homogenous flux distributions for wound cores, incompatibility with the cruciform structures required for larger kVA transformers, and greater difficulty in meeting standards for lower temperature units. Accordingly, Powersmiths commented that a wholesale conversion to amorphous material does not make sense given the limitations of the technology. (Powersmiths, No. 112 at p. 6)
Schneider commented that more research is needed into the inrush current, sound levels, and reduced impedance of amorphous. (Schneider, No. 101 at p. 2) Carte commented that amorphous transformers are louder than GOES transformers and questioned what the impacts of amorphous transformers would be on noise-sensitive areas. (Carte, No. 140 at p. 5) HVOLT commented that amorphous transformers create more audible noise. (HVOLT, No. 134 at p. 5) APPA commented that amorphous transformers produce more noise than GOES transformers, which would cause utilities to install transformers further away and increase secondary cable losses. APPA also stated that there are potential health impacts from higher levels of background noise. (APPA, No. 103 at p. 14) Idaho Power recommended DOE include weight, noise, and cost in its engineering analysis, stating that the proposed standards will likely result in the use of heavier, noisier, and costlier amorphous core transformers. (Idaho Power, No. 139 at p. 3)
AISI and Pugh Consulting both commented that amorphous is brittle and untested. (AISI, No. 115 at p. 2; Pugh Consulting, No. 117 at p. 5) Pugh Consulting additionally questioned whether amorphous transformers could be “drop-in replacements” for current transformers. (Pugh Consulting, No. 117 at p. 5)
Exelon commented that domestic manufacturers have limited experience making amorphous core distribution transformers, a deficiency in domestic manufacturing experience that could have significant cost, supply chain, and reliability implications. Exelon added that most uses of amorphous core transformers have been limited to kVA ratings below Exelon's needs and its current research suggests the use of amorphous transformers at higher ratings is essentially experimental. (Exelon, No. 95 at p. 3)
Metglas commented that amorphous core transformers accounted for approximately 10 percent of new installs in 1992 but became less common largely due to fewer utilities using a total owning cost (TOC) model. (Metglas, No. 125 at p. 2) Metglas further stated that amorphous transformers have served the electrical grid since 1982, with an estimated 22 million units in operation globally and approximately 1 million additional units brought online each year. Id.
Efficiency advocates commented that amorphous transformers are a proven technology, with an estimated 3 million transformers globally and over 90% of liquid immersed transformers in Canada utilizing amorphous cores. (Efficiency Advocates, No. 121 at pp. 1-2) NYSERDA similarly commented that transformers with amorphous cores are field proven and cost effective. (NYSERDA, No. 102 at pp. 2-3)
EMS Consulting commented that GE produced over 600,000 amorphous transformers between 1986 and 2001 with very satisfactory field experiences, indicating that amorphous transformers are a reliable product. (EMS Consulting, No. 136 at pp. 2-3) EMS Consulting added that deregulation of electrical industries in the 1990s reduced demand for amorphous products in the U.S., but the products became more popular in developing countries like India and China due to its lower operating costs. Id. EMS Consulting stated that very few U.S. utilities purchase based on TOC but globally over 22M units have been installed and over 1M amorphous transformers are installed globally per year. Id.
EMS Consulting added that, although amorphous transformers exhibited certain performance challenges when they were first commercialized in the 1980s, such as increased transformer size and a tendency to be more brittle, improvements in amorphous properties and manufacturing methods have made them comparable in reliability to GOES transformers. (EMS Consulting, No. 136 at pp. 2-3) EMS Consulting further stated that the high-permeability amorphous products have a higher stacking factor and flux density, which will produce an even smaller and lighter transformer than that assumed by the NOPR. (EMS Consulting, No. 136 at p. 4)
DOE notes that amorphous core transformers are not a new technology. As stated by Metglas and EMS Consulting, installations of amorphous transformers have occurred for decades, beginning in the 1980s. While DOE agrees that amorphous core transformers are less common in the domestic market today than GOES core transformers, DOE disagrees with implication that this is the result of any performance defects precluding amorphous material from being used in place of GOES in distribution transformer cores. As pointed out by EMS consulting, early-stage amorphous core transformers faced certain technical challenges, such as increased noise levels and metal shards flaking from the core. However, the development of better manufacturing processes for both amorphous ribbon and amorphous cores has mitigated the impact of these issues.
In DOE's review of the market, it observed multiple major manufacturers of distribution transformers advertising amorphous transformers as reliable, low-loss alternatives to GOES transformers. 70 71 72 73 Manufacturers design these transformers to comply with the same industry standards that apply to GOES units, which include provisions for general mechanical requirements and audible noise limits. ^{74} During confidential manufacturer interviews, DOE also heard from stakeholders that amorphous transformers have become more comparable to GOES, with some manufacturers often providing specifications to customers for both GOES and amorphous core designs.
^{70} Howard, Howard Amorphous Core Transformers. Available at howardtransformer.com/Literature/Amorphous%20Core%20Trans.pdf (last accessed Oct. 30, 2023).
^{71} Hitachi, Hitachi Amorphous Transformers. Available at www.hitachi-ies.co.jp/english/catalog_library/pdf/transformers.pdf (last accessed Oct. 30, 2023).
^{72} Eaton, Three-phase pad-mounted compartmental type transformer. Available at www.eaton.com/content/dam/eaton/products/medium-voltage-power-distribution-control-systems/cooper-power-series-transformers/three-phase-pad-mounted-compartmental-type-transformer-ca202003en.pdf (last accessed Nov. 15, 2023).
^{73} Wilson Power Solutions, Amorphous Metal Transformers—Myth Buster. Available at www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf (last accessed Nov. 30, 2023).
^{74} IEEE SA. (2021). IEEE C57.12.00-2021—IEEE Standard for General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers. Available at standards.ieee.org/ieee/C57.12.00/6962/ (last accessed Nov. 8, 2021).
DOE also notes that adoption of amorphous metal transformers has significantly increased on a global scale in the past decade. In Canada, for example, over 90 percent of sales for liquid-immersed distribution transformer are estimated to utilize amorphous cores. ^{75} China and India have similarly exhibited large upticks in amorphous transformer sales. ^{74} The fact that significant numbers of amorphous distribution transformers have been installed to the electrical grid without any significant reports of failure or apparent design defects, including approximately 600,000 units sold within the U.S., ^{76} demonstrates that amorphous transformers can be readily substituted for GOES transformers. Further, some utilities have stated that certain liquid-immersed manufacturers do not even state in bid sheets whether their transformers have an amorphous core or GOES core, indicating that the performance of each transformer is viewed as similar enough to be irrelevant to the manufacturer. ^{77} For these reasons, DOE has maintained in this final rule that amorphous core transformers can be reasonably interchanged with GOES transformers without impacting performance.
^{75} Bonneville Power Administration, Amorphous Core Liquid Immersed Distribution Transformers. 2020. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/liquid-immersed-amorphous-core-distribution-transformers-2020-03-31-final.pdf (last accessed Oct. 30, 2023).
^{76} Metglas, Amorphous Metal Distribution Transformers. 2016. Available at metglas.com/wp-content/uploads/2021/06/Metglas-Power-Brochure-Updated.pdf (last accessed Oct. 30, 2023).
^{77} Bonneville Power Administration, Low-Voltage Liquid Immersed Amorphous Core Distribution Transformers. 2022. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-0216.pdf (last accessed Nov. 8, 2023).
Entergy expressed concern that ferroresonance might be a more prominent issue for amorphous core transformers, especially for lightly loaded transformers or those with protective switching, potentially damaging downstream equipment. (Entergy, No. 114 at p. 3) Entergy stated that an EPRI report indicated that increased noise is a common complaint for amorphous core transformers and that some users indicated that: (1) amorphous cores are more brittle and subject to breaking under strong forces; (2) operating practices may have to change to handle ferroresonance; and (3) lower harmonics passing through the transformer could interact with EV charging stations. Entergy commented that these technical challenges warrant additional research and development prior to the widespread deployment of amorphous technology. Id.
Manufacturer literature and public reports ^{78} widely indicate that technological improvements to the design of amorphous core transformers have largely resolved previous performance issues, such as brittleness of the core. As a result, amorphous core transformers have been deployed worldwide without any significant detriment to performance, as discussed further in Chapter 3 of the TSD, indicating that amorphous transformers can be substituted for GOES transformers in a wide array of applications, including those with sensitive downstream equipment. Regarding ferroresonance concerns specifically, DOE notes that increased instances of ferro resonant conditions have not been linked to use of amorphous metal cores. One study conducted by the Bonneville Power Administration indicated that amorphous core transformers do not significantly increase the probability or severity of ferroresonance incidents. ^{79} Stakeholder have also previously indicated that they have not experienced any increases in ferroresonance for amorphous core transformers. ^{80}
^{78} Bonneville Power Administration, Low-Voltage Liquid Immersed Amorphous Core Distribution Transformers. 2022. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf (last accessed Oct. 30, 2023).
^{79} Bonneville Power Administration, Low-Voltage Liquid Immersed Amorphous Core Distribution Transformers. 2022. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf (last accessed Oct. 30, 2023).
^{80} See Docket No. EERE-2019-BT-STD-0018, Eaton, No. 0055 at p. 10.
MTC commented that amorphous core transformers have approximately 20-25 percent more mass, including all non-core components, due to a lower saturation flux density and stacking factor. (MTC, No. 119 at pp. 11-12) Carte also asserted that amorphous cores require approximately 20 percent more material and the environmental and carbon footprint of producing that material might counter the energy savings. (Carte, No. 140 at p. 1) WEG commented that producing amorphous core transformers would increase the weight of units by 25 percent. (WEG, No. 92 at p. 3)
HVOLT commented that many transformers require stacked core constructions, which is only viable with GOES materials and three-phase construction with wound cores generally increases the transformer size which may not be feasible for applications such as power center transformers. (HVOLT, No. 134 at p. 7) Portland General Electric commented that the larger profile of the amorphous core and windings would require a larger tank, more winding copper/aluminum wire, more oil, and more labor to produce, resulting in higher upfront procurement costs approximately 15-20 percent greater than GOES. (Portland General Electric, No. 130 at p. 3) As an example, Portland General Electric stated that a 25kVA pole-mounted amorphous transformer is roughly the size of 50kVA GOES core transformer. (Portland General Electric, No. 130 at p. 3)
Historically, amorphous transformers have been larger than GOES transformers. GOES transformers have higher saturation flux density and a higher stacking factor than amorphous transformers, which allows GOES transformers to have a lower volume. However, quality improvements in amorphous ribbon have improved stacking factors. Further, the size of a GOES transformer is largely dependent on the loss performance of GOES being used. See Chapter 5 of the TSD for specific details. To reduce losses in a GOES transformer, manufacturers frequently design larger GOES cores with a reduced saturation flux density, meaning that the size of GOES transformers have increased in an effort to increase the efficiency of GOES transformers.
Eaton submitted data demonstrating that for certain transformer designs, an amorphous transformer weights less at baseline. (Eaton, No. 137 at p. 32) Further, Eaton stated that its data showed that in meeting the proposed efficiency standards, the incremental weight of a more efficient amorphous transformer is only 5.4 percent greater than the base amorphous design and ~1 percent relative to the base GOES design. Id. Eaton stated that its data also showed that achieving proposed efficiency levels with a GOES transformer results in a 50 percent weight increase. Id.
One study published by the Bonneville Power Administration in 2022 reported the incremental weight increase for baseline GOES transformers and baseline amorphous transformers using data submitted by a distribution transformer manufacturer. Their data indicated that the baseline amorphous transformer was, in many cases, smaller than an equivalent GOES transformer for a number of kVA sizes. ^{81}
^{81} Bonneville Power Administration, Low-Voltage Liquid Immersed Amorphous Core Distribution Transformers. 2022. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16. pdf (last accessed Oct. 30, 2023).
The actual cost and size difference between a GOES core transformer and an amorphous core transformer depends on the actual design of the transformer, the loss performance of the core materials used, the winding material used, and whether manufacturers are trying to meet strict dimensional constraints or simply designing the lowest cost transformer. DOE does not apply blanket cost increases to any transformer that has an amorphous core. Rather, DOE evaluates the change in material costs that would be incurred by both amorphous core and GOES core transformers meeting a range of efficiency levels. In its analysis, DOE does reflect the fact that more efficient transformers typically require more material. This additional material has a cost, which is accounted for in DOE's modeling, is discussed in section IV.C of this document. DOE also considers potential impact on installation costs ( see section IV.F.2 of this document).
Idaho Falls Power and Fall River stated that amorphous core transformers may have negative environmental impacts when considering the energy gains versus the increased energy usage for manufacturing. (Idaho Falls Power, No. 77 at p. 1; Fall River, No. 83 at p. 1) NAHB commented that 40 percent of electrical steel manufacturing costs are attributed to energy consumption and stated that DOE should consider the impact of high heat in both GOES and amorphous manufacturing. (NAHB, No. 106 at p. 12)
Regarding the energy usage associated with the manufacturing of amorphous cores, DOE notes that relative to GOES, amorphous ribbon production generally has lower temperatures used throughout its production process and a lower transformer core annealing temperature, which would indicate less energy use in manufacturing. Manufacturer literature has reported on the life-cycle assessment of amorphous and GOES cores, which would include the manufacturing, utilization, and end-of-life of the product, and concluded that the environmental impact of high-efficiency amorphous transformers is substantially lower than GOES transformers. ^{82}
^{82} ABB, Distribution goes green. Available at library.e.abb.com/public/f28b7caf32af14e8c1257a25002f2717/40-47%202m221_EN_72dpi.pdf (last accessed Nov. 9, 2023).
Pugh Consulting questioned whether amorphous metal could be recycled at the end of a transformer's lifetime and suggested DOE consider the costs associated with disposing of and/or recycling all current transformers by 2027. (Pugh Consulting, No. 117 at p. 5) DOE notes that amorphous cores can be recycled at end of life. ^{83} Further, transformers manufactured before the compliance date for this final rule would be subject to the relevant standards corresponding to their date of manufacture, not the efficiency standards amended in this rule ( i.e., all transformers do not need to be disposed of by 2027, as Pugh Consulting suggested). As such, any transformers currently installed, as well as those manufactured before the compliance date for this final rule, would not be required to be disposed of or replaced.
^{83} Metglas, Inc. Recycling of Amorphous Transformer Cores, 2010. Available at metglas.com/recycling-amorphous-transformer-cores/ (last accessed Nov. 9, 2023).
REC commented that amorphous transformers are known to suffer higher failure rates due to increased susceptibility to mechanical stresses, lower short-circuit tolerance, and greater brittleness of the core. (REC, No. 126 at pp. 2-3) APPA commented that amorphous cores are less able to withstand short-circuit faults than GOES transformers and have a lower overload capacity due to lower saturation flux-density. (APPA, No. 103 at p. 12)
APPA and Carte commented that amorphous transformers are subject to metal flakes in the oil which can lead to partial discharging and premature failure. (APPA, No. 103 at pp. 10-11; Carte, No. 140 at pp. 7-8) APPA added that these discharges could require the use of oil monitoring devices for amorphous transformers at an additional cost. (APPA, No. 103 at pp. 10-11) Carte stated that discharging is more likely to occur if amorphous cores are used for higher voltages, which to Carte's understanding they have not been thus far. Carte added that it wasn't sure how amorphous cores were grounded and noted that current core grounding techniques may not be sufficient at higher voltages, additionally risking premature failure. (Carte, No. 140 at pp. 7-8) Regarding increased susceptibility to mechanical stresses, as previously noted, while brittleness of amorphous cores has historically been reported as a performance complication, performance improvements to amorphous ribbon as well as technological developments in the design and bracing of amorphous transformer cores have helped resolve this issue. Additionally, in DOE's review of the market, it observed manufacturer literature advertising construction techniques which reinforce amorphous metal cores and add resilience to mechanical stresses. For example, it has become standard to encase amorphous metal cores in an epoxy resin which stabilizes the core and reduces the likelihood of metal shards forming. Technologies also exist which can be used in tandem with the transformer core to capture shards, ensuring that they do not contaminate the insulation fluid or cause short circuits in the transformer windings. These developments, paired with performance improvements made to the amorphous metal ribbon itself, have significantly reduced the risk of metal flakes from an amorphous core impacting overall transformer performance.
Regarding decreased short circuit capacity for amorphous transformers, industry standards set forth the provisions for short-circuit withstand capacity for all transformers, regardless of the transformer core material used. 84 85 As previously noted, amorphous core transformers are currently being designed and deployed in the field to meet these standards, indicating that they can be designed to withstand the same short circuit capacities as GOES transformers. Similar to the developments which have resolved brittleness issues experienced by early-stage amorphous transformers, technological improvements in the core and coil design for amorphous transformers have the capacity to withstand short circuit events over the years. For example, utilizing foil windings on the secondary coil, rather than rectangular wire or strip, reduces axial forces on the core and winding, reducing mechanical stresses and increasing short circuit capacity. Insulating materials can also be applied around the core to absorb mechanical stresses during operation, reducing the strain experienced by the core itself. ^{86} As a result, amorphous transformer cores can be reliably built without increased risk of short circuit or premature failure when compared to an equivalent GOES transformer.
^{84} International Electrotechnical Commission, IEC 60076-5:2006: Power transformers—Part 5: Ability to withstand short circuit. 2006. Available at webstore.iec.ch/publication/603.
^{85} IEEE SA. (2021). IEEE C57.164-2021—IEEE Guide for Establishing Short-Circuit Withstand Capabilities of Liquid-Filled Power Transformers, Regulators, and Reactors. 2021. Available at standards.ieee.org/ieee/C57.164/6804/ (last accessed Nov. 8, 2023).
^{86} Wilson Power Solutions, Amorphous Metal Transformers—Myth Buster. Available at www.wilsonpowersolutions.co.uk/app/uploads/2017/05/WPS_AMT_Myth_Buster_2018-2.pdf (last accessed Oct. 30, 2023).
APPA stated that DOE should investigate whether the use of amorphous cores would change the gases produced by transformers with the new fluids and steels, the potential impact of using amorphous transformers in areas with extremely hot or cold climates, and the impact of amorphous transformers having a lower overload capacity. (APPA, No. 103 at pp. 16-17)
DOE notes that amorphous core transformers use the same insulation fluids as GOES transformers and APPA did not elaborate as to how the use of an amorphous metal, rather than GOES, in the transformer core would cause the transformer to produce additional or different gases during operation, nor did they elaborate or provide data as to how a change in core material would impact gases produced in a transformer. As such, DOE does not have reason to believe that amorphous core transformers would perform any differently than GOES transformers with regard to gases produced during operation.
Regarding deployment of amorphous transformers in hot or cold climates, as previously noted, amorphous core transformers have been in deployment for several decades and have been deployed worldwide, including areas with extremely hot or cold climates. Further, amorphous core transformers do not inherently have lower overload capacity as detailed in section IV.C.1.d of this document as this is a function of temperature rise and transformer load losses.
APPA further commented that some research indicates that the performance of amorphous transformers degrades over time, with losses likely to become higher than GOES transformers. APPA stated that accounting for those losses would undermine any economic justification for the proposed standards. (APPA, No. 103 at pp. 10-11) DOE notes that both the study cited by APPA and the original 1996 study ^{87} are referring to degradation in the process of forming an amorphous core from amorphous ribbon ( i.e. the material destruction factor or build factor), not degradation of the material over time. This kind of degradation is accounted for in the losses for a transformer and is therefore considered in DOE's analysis of both GOES and amorphous core transformers.
^{87} Y. Okazaki, Loss deterioration in amorphous cores for distribution transformer, Journal of Magnetism and Magnetic Materials 160 (1996) 217-222.
Exelon stated its concern about the ability of amorphous core transformers to maintain their efficiency levels over an extended lifetime, calling into question the life-cycle environmental benefit of these new transformers. Exelon commented that studies to address these extended performance concerns are planned but have not yet been executed. (Exelon, No. 95 at p. 3) REC commented that, due to the metallurgical nature of amorphous material, there is a continuous erosion of loss-savings as core material ages and degrades. (REC, No. 126 at p. 3)
PSE commented that amorphous core transformers have lower overload capacity and experience greater mechanical stress during faults due to their rectangular core shape, as opposed round GOES cores. (PSE, No. 98 at p. 13) The SBA expressed concern that amorphous cores may degrade faster and be less capable of sustaining overload conditions than current GOES cores. (SBA, No. 100 at p. 6) REC commented that amorphous transformers have limited load and overload capacity compared to GOES, which will require additional or higher-capacity units to serve the same number of consumers. (REC, No. 126 at p. 2-3) Portland General Electric commented its current design practices allow for peak loads up to 150 percent of the transformer nameplate rating but would need to be revised to accommodate accelerated degradation during overloading for amorphous transformers. (Portland General Electric, No. 130 at p. 3) Cliffs commented that amorphous transformers cannot be loaded as efficiently as GOES cores, which increases likelihood of transformer failure. (Cliffs, No. 105 at p. 11)
Transformer overloading conditions can result in increased mechanical stress and excess heat generation. Therefore, a transformer's capacity to withstand overloading conditions is dependent on its ability to endure mechanical stress and effectively dissipate heat. As previously noted, construction techniques exist to reinforce amorphous metal transformers against mechanical stress, reducing the risk of damage caused by overloading conditions. With regard to an amorphous transformer's ability to shed heat, excess heat is primarily generated through transformer losses. At higher loads, the load losses primarily dictate heat generation due to the quadratic relationship between load losses and transformer loading. Since minimally compliant amorphous transformers are often designed with higher load losses than GOES units, this may lead to the belief that amorphous transformers are less equipped to handle overloading conditions. However, as further discussed in section IV.C.1.d of this document, amorphous transformers do not inherently have higher load losses. Just as GOES transformers can be designed to meet efficiency standards by either reducing no-load or load losses, amorphous transformers can similarly be designed with lower load losses. DOE's modeling includes amorphous core transformers with a range of load losses, thereby maintaining the availability of designs with higher overload capacity. As such, transformer customers will continue to have the option of purchasing transformers with higher or lower overload withstand capacity based on the needs of their application. In absence of overload capacity, customers would likely be forced to purchase higher kVA ratings than necessary and in doing so risk wasting money, energy, and electrical steel availability.
Although multiple stakeholders expressed concern that the efficiency of amorphous transformers may degrade over time, no stakeholders provided data to demonstrate any such loss of efficiency over time; rather, they only cited studies on the reduction in losses in converting amorphous ribbon into amorphous cores. DOE notes that degradation of transformer performance is often associated with a degradation of transformer insulation, typically due to operation at elevated operating temperatures. As discussed in section IV.C.1.d of this document, amorphous transformers are capable of achieving low load losses, meaning temperature rise would not increase as fast, even at higher-loading conditions. DOE does not have reason to believe that the rated efficiency of an amorphous transformer would degrade over time when compared to an equivalent GOES transformer. Further, manufacturer literature has reported on accelerated aging tests of amorphous transformers and concluded that they saw no degradation of losses in an amorphous core during the transformer life. ^{88} Therefore, given the lack of data supplied, and given the technological developments which have enabled amorphous transformers to withstand overload conditions and short circuit conditions, DOE did not consider there to be sufficient evidence to model amorphous transformers degrading in performance over time when compared to an equivalent GOES transformer.
^{88} ABB, Distribution goes green. Available at library.e.abb.com/public/f28b7caf32af14e8c1257a25002f2717/40-47%202m221_EN_72dpi.pdf (last accessed Nov. 9, 2023).

Amorphous Market
In the January 2023 NOPR, DOE discussed how amorphous ribbon capacity has increased since the April 2013 Standards Final Rule. 88 FR 1722, 1755. DOE stated that it had identified numerous companies capable of producing amorphous material (of standard am quality or better) and that global amorphous ribbon capacity is much greater than current demand. Id. DOE stated that it had learned through manufacturer interviews that amorphous production capacity increased in response to the April 2013 Standards Final Rule, but demand for amorphous did not necessarily correspondingly increase, resulting in excess capacity. DOE discussed how amorphous producers' response to the April 2013 Standards Final Rule demonstrated that, if there was expected to be an increase in market demand for amorphous, capacity would increase to meet that demand. Id. Further, DOE also learned through confidential manufacturer interviews conducted in support of the August 2021 Preliminary Analysis and the January 2023 NOPR that recent price increases for GOES have led amorphous to be far more cost competitive. However, despite this increased competitiveness, the industry has not seen an increase in amorphous transformer purchasing, likely due to existing distribution transformer core production equipment being set-up to produce GOES cores and a transition to amorphous cores requiring capital investment. Id. Based on these developments, in the January 2023 NOPR, DOE constrained the selection of amorphous alloys under the no-new-standards scenario to better match the current market share of distribution transformers; however, DOE did not apply any constraints to standard am steel purchasing in its evaluation of higher efficiency levels. 88 FR 1722, 1756.
In the January 2023 NOPR, DOE acknowledged that the availability of both GOES and amorphous alloy is a concern for distribution transformers, but expected that suppliers would be able to meet the market demand for amorphous for all TSLs analyzed given the NOPR's 3-year compliance period. 88 FR 1722, 1817. DOE noted that manufacturers should be able to significantly increase supply of amorphous if they know there will be an increase in demand as a result of the proposed energy conservation standards. Id. DOE requested comment on this assumption and how supply and demand would change in response to the proposed amended energy conservation standards. Id.
In response, HVOLT, Southwest Electric, Cliffs and NRECA expressed concern that there is not sufficient amorphous ribbon capacity currently and capacity will not be able to grow quickly enough to meet the amorphous demand increases expected from the proposed standards. (HVOLT, No. 134 at pp. 5-6; Southwest Electric, No. 87 at p. 3; Cliffs, No. 105 at pp. 10-11; NRECA, No. 98 at p. 3) Cliffs stated that even if all global capacity were used, it would not be enough to support the US market. (Cliffs, No. 105 at pp. 10-11) Cliffs added that DOE incorrectly assumes amorphous production can increase to meet demand without sufficient verification of if that is true. (Cliffs, No. 105 at pp. 10-11)
Hammond commented that only one amorphous producer serves the U.S. market and it cannot scale up in time to meet forecasted demand. (Hammond, No. 142 at p. 2) Hammond added that it is not aware of any efforts outside the U.S. to expand amorphous production to the levels needed to serve the U.S. market. (Hammond, No. 142 at p. 2) DOE notes there is one domestic producer of amorphous steel and one domestic producer of GOES.
Howard commented that the proposed standards will increase GOES demand by 60 percent, or increase amorphous by 600 million pounds, and if all amorphous is domestic, increase domestic amorphous ribbon capacity by 500 percent. (Howard, No. 116 at p. 2) Howard further stated that silicon steel plants typically require 3-4 years and $1-2B to design and build, whereas amorphous would require an additional 15-20 production lines and $1B investment, which isn't achievable in the proposed timeline. (Howard, No. 116 at p. 2) Cliffs commented that amorphous transformers currently make up a small fraction of domestic transformers production and cannot be scaled in the near-term to meet the domestic market. (Cliffs, No. 105 at p. 6)
Prolec GE commented that current and projected capacities of both amorphous metal ribbon and cores will likely remain below the levels required for future demand. (Prolec GE, No. 120 at p. 14) VA, MD, and DE House Representatives commented that the proposed standards will require a rapid expansion of amorphous ribbon capacity which could exacerbate near-term supply chain shortages. (VA, MD, and DE Members of Congress, No. 148 at pp. 1-2)
Several stakeholders expressed concern that there was only a single domestic supplier of amorphous material. Powersmiths commented that the single supplier of amorphous will not be able to expand capacity to meet the needs of the entire distribution transformer market and that it is not acceptable to rely on a single supplier regardless. (Powersmiths, No. 112 at p. 6) TMMA commented that the U.S. manufacturer of amorphous would not be able to serve the entire US transformer market, even with stated capacity expansions, leaving the U.S. reliant on foreign produced amorphous. (TMMA, No. 138 at pp. 3-4) Powersmiths commented that amorphous is not available in the narrower strips required for LVDTs and the 2027 compliance date does not provide sufficient time to put a supply chain in place. (Powersmiths, No. 112 at p. 6) Powersmiths further commented that hibam is the most viable for LVDT markets and expressed concern that this steel is offered from a single source. (Powersmiths, No. 112 at p. 6)
NAHB expressed concern that the proposed rule would worsen supply and competition concerns. NAHB recommended that, given the limited number of manufacturers for certain products, DOE should work with other Federal agencies to fully review and address the likelihood that this rule will exacerbate anticompetitive supply constraints. (NAHB, No. 106 at pp. 2, 6)
Idaho Falls Power and Fall River stated that relying upon a single domestic supplier of amorphous will create both a de facto monopoly and a bottleneck in an already constrained supply chain. (Idaho Falls Power, No. 77 at p. 1; Fall River, No. 83 at p. 2)
Alliant Energy commented that requiring all distribution transformers to be made from a material with a single domestic suppler representing less than 5 percent of the market will negatively impact transformer production capacity and availability. (Alliant Energy, No. 128 at pp. 2-3) Alliant Energy added that the significant transit times required to source amorphous from foreign nations would exacerbate existing supply chain challenges. (Alliant Energy, No. 128 at pp. 2-3)
In this final rule, DOE notes that it has modified its assumptions to reflect stakeholder feedback suggesting that even if amorphous is the lowest first-cost option, manufacturers may elect to build GOES transformers in order to maintain a more robust supply chain and reduce the impact on existing short to medium-term supply challenges. Specifically, DOE assumed that for liquid-immersed distribution transformers, amorphous adoption will be constrained at all efficiency levels through EL 2, as discussed in section IV.F.3 of this document.
Many stakeholders also commented expressing concern that the use of amorphous metal would increase U.S. reliance on foreign suppliers.
Schneider asserted that given that only one company in Japan and one company in the United States can produce amorphous materials, there is risk of an oligopoly. (Schneider, No. 92 at pp. 9-10) Schneider further stated that there are only two manufacturers that can produce amorphous to meet DOE requirements and the barriers to entry are extremely high. (Schneider, No. 92 at pp. 9-10) Prolec GE commented that manufacturers will be forced to rely on foreign steel suppliers, mainly from China, because the domestic supply of amorphous cannot meet the demand of the U.S. distribution transformer market. (Prolec GE, No. 120 at p. 3) Eaton commented that it would like to have at least three suppliers of amorphous, preferably located in different geographical regions of North America. (Eaton, No. 137 at p. 27)
The Chamber of Commerce commented that requiring transformers to use amorphous cores conflicts with public policy goals by increasing the domestic electricity sector's reliance on inputs from China. (Chamber of Commerce, No. 88 at p. 3) AISI commented that U.S. steel production has a lower carbon intensity that steel made in China. (AISI, No. 115 at p. 2)
EEI commented that the proposed standards will increase the need to rely on foreign sourced products, which will create national security concerns, eliminate American jobs, and increase transit times. (EEI, No. 135 at pp. 29-30) NRECA commented that the proposed standards will increase reliance on foreign nations for amorphous materials in distribution transformers and GOES for power transformers. (NRECA, No. 98 at pp. 3-4) NRECA stated that higher labor costs for amorphous core and a limited domestic capacity for amorphous materials will increase outsourcing of distribution transformer manufacturing, creating a national security risk. (NRECA, No. 98 at pp. 3-4) NRECA added that many utilities are Rural Utilities Service (RUS) borrowers, which prohibits them from purchasing products with foreign-sourced steel. (NRECA, No. 98 at p. 7) Michigan Members of Congress stated that offshoring manufacturing of distribution transformers raises national security concerns. (Michigan Members of Congress, No. 152 at p. 1) Pugh Consulting advised against relying upon a single steel variety and stated that transformer shortages are dangerous given the number of storms, hurricanes, and violent attacks by extremists against distribution transformers. (Pugh Consulting, No. 117 at p. 4) TMMA commented that the proposed standards increase our reliance on international and unfriendly suppliers which is a threat to national security. (TMMA, No. 138 at pp. 2, 4) Howard commented that transformers are vital to national security and given existing shortages, it is vital to maintain both GOES and amorphous as viable options. (Howard, No. 116 at p. 4) AISI commented that if distribution transformers transition to amorphous, that could eliminate domestic GOES, which would be harmful to national security. (AISI, No. 115 at p. 2)
Carte commented that the proposed standards present national security concerns because the timeline is not sufficient for amorphous ribbon capacity to ramp up, which will require additional imports of amorphous. Carte also noted that the domestic supplier's parent company is headquartered in Japan. (Carte, No. 140 at p. 4)
HVOLT expressed concern that the proposed standards requiring manufacturers to rely on a single amorphous supplier based in Japan, whereas they can currently source core steel from multiple GOES suppliers. (HVOLT, No. 134 at pp. 5-6)
Webb expressed concern that shifting towards amorphous cores will place utilities at greater risk and increase U.S. reliance on foreign suppliers. Webb compared this to the recent U.S. semiconductor scarcity and questioned whether the government would similarly address transformer shortages via Federal funding, as was done for semiconductors with the CHIPS and Science Act. (Webb, No. 133 at p. 2)
MTC commented that patent disputes have led Hitachi to consolidate all amorphous production in Japan, making the only global suppliers of amorphous Hitachi and Chinese suppliers. (MTC, No. 119 at p. 20) DOE notes that MTC's comment does not accurately reflect the current state of the market. DOE is aware of amorphous production in the United States today. See Appendix 3A of the TSD for a detailed discussion of the amorphous and GOES markets.
MTC further commented that there is insufficient global production capacity of amorphous to support the U.S. distribution transformer market, even if domestic production capacity were tripled. (MTC, No. 119 at p. 9) MTC additionally commented that lack of domestic steel supply is an issue of national security which should be referred to the Department of Commerce for remedies. (MTC, No. 119 at p. 20)
Exelon commented that the proposed standards could exacerbate supply chain constraints and drive more foreign transformer sourcing, creating new grid reliability challenges and increasing consumer costs. (Exelon, No. 95 at p. 4)
Cliffs commented that relying upon amorphous material represents a national security threat because it is not readily available in the U.S., cannot be manufactured using GOES production equipment, and cannot supply the U.S. grid. (Cliffs, No. 105 at pp. 4-5)
Schneider commented that the production of ferroboron ^{89} is limited to locations outside the U.S., which leads to long-term availability concerns and, because of this, prior evaluations did not consider max-tech. (Schneider, No. 92 at pp. 10-12) Cliffs added that the feedstock to produce amorphous is foreign-sourced, all other major amorphous producers are foreign, and amorphous is more labor intensive, making the U.S. more dependent on foreign supply chains. (Cliffs, No. 105 at p. 7) BCBC and BCGC expressed concern that DOE's proposal could be detrimental to the resiliency of the United States electric grid because amorphous is produced from imported, unproven, and foreign-sourced materials that could compromise both energy and national security in the United States. BCBC and BCGC recommended that DOE adopt policies that increase domestic production of key materials and components to strengthen national security and self-reliance. (BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 1) AISI commented that amorphous cores requires foreign-sourced materials whereas GOES is able to be produced with all stages using domestic manufacturing. (AISI, No. 115 at p. 2) ^{90}
^{89} Ferroboron is an input in amorphous production. It is produced by a well-known reaction of iron with boron (as boric acid). Both of these minerals are produced in the U.S., although actual ferroboron production typically occurs outside the U.S.
^{90} U.S. Department of Commerce, The Effect of Imports of Transformers and Transformer Components on the National Security. (2020). Available at www.bis.doc.gov/index.php/documents/section-232-investigations/2790-redacted-goes-report-20210723-ab-redacted/file.
DOE notes that the current status quo for the distribution transformer market involves a single domestic GOES manufacturer and multiple global GOES suppliers, with any imported GOES subject to tariffs. As a result, transformer manufacturers who produce transformer cores domestically are largely reliant on the single domestic GOES supplier, given that using GOES from any other supplier requires paying a tariff. For amorphous, there is similarly a single domestic amorphous manufacturer and multiple global suppliers. Meeting higher-efficiency standards with amorphous would result in domestic transformer manufacturers who produce transformer cores domestically being largely reliant on the single domestic amorphous supplier, given that using amorphous from any other supplier requires paying a tariff. This is similar to the current market structure for GOES. Therefore, DOE disagrees that a distribution transformer supply chain with substantial amorphous cores is inherently more of a national security risk than the existing GOES-based supply chain. The current distribution transformer supply chain, as well as how the market is expected to respond to amended standards, is further discussed in section IV.A.5 of this document.
DOE considers the effect of DT standards on the domestic supply chain in setting standards. However, DOE notes that a distribution transformer market served by 100 percent domestically produced electrical steel does not exist today. One transformer manufacturer noted that having only a single-domestic supplier of GOES represents a considerable supply risk. They further stated that developing the workforce skills and manufacturing capabilities to leverage both GOES and amorphous will reduce their electrical steel supply risk, provided development of that capability does not disrupt existing product output. ^{91} Several stakeholders expressed concern that too rapid of a transition to amorphous cores could worsen near-term supply chains and recommended DOE wait for capacity to increase prior to implementing any amended efficiency standards.
^{91} Markham, I., ERMCO CEO: For an Effective Outcome, Focus on Inputs, The Wall Street Journal, Jan. 5, 2024. Available online at: https://deloitte.wsj.com/riskandcompliance/ermco-ceo-for-an-effective-outcome-focus-on-inputs-3ecfbeff.
ABB stated that DOE should ensure that there is a sufficient and competitive supply of GOES and amorphous before requiring significantly higher energy conservation standards. (ABB, No. 107 at pp. 2-3) ABB went on to state that the transformer industry is already experiencing an insufficient domestic supply of GOES and expressed concern that the same challenges would be faced with amorphous cores. (ABB, No. 107 at pp. 2-3) NWPPA commented that manufacturers struggle to source the high performing GOES required to meet current standards and the proposed standards would require an even scarcer variety of steel for very small gains in efficiency. (NWPPA, No. 104 at p. 1) NRECA commented that DOE's proposal will not expand the market for distribution transformers because most current production using GOES will not be able to meet the proposed standards. (NRECA, No. 98 at p. 2)
WEG commented that amorphous cores will be the most cost effective way to meet standards, but the supply chain for amorphous material is not prepared to sustain the market or support the electrical grid. (WEG, No. 92 at pp. 2-3) WEG stated that U.S. manufacturers would need 200,000 tons of amorphous to meet the proposed standards, which would be 100 percent of global amorphous ribbon capacity just to support the U.S. (WEG, No. 92 at pp. 2-3) WEG additionally commented that using amorphous cores will require years of technical development and industry won't be able to use GOES in the meantime. (WEG, No. 92 at pp. 2-3)
Cliffs commented that requiring amorphous cores would make the transformer supply chain less secure and require considerable investment from transformer manufacturers at a time of existing supply chain and labor challenges. (Cliffs, No. 105 at p. 6) Cliffs commented that only a single domestic manufacturer has the technical know-how to produce amorphous ribbon and even if that manufacturer licensed the technology, if efficiency standards require amorphous cores, the manufacturer will effectively have a monopoly that will lead to increased prices. (Cliffs, No. 105 at pp. 15-16)
UAW commented that the proposed standards may upend the distribution transformer market by relying upon steel which is in short supply and more expensive than the GOES currently used. (UAW, No. 90 at p. 3)
Webb recommended that DOE confirm whether amorphous ribbon capacity can be made available to meet both current GOES demand and increased future demand due to distributed energy resource deployment. (Webb, No. 133 at p. 2)
Metglas commented that continued expansion of amorphous production by other producers demonstrates that there are no IP-related impediments to expanding use of amorphous transformers. (Metglas, No. 125 at pp. 3-4) Metglas commented that grades of GOES exist that can meet the proposed DOE standards and suggested that GOES will continue to serve a significant portion of U.S. demand for distribution transformers, even in the presence of amended standards. (Metglas, No. 125 at pp. 3-4) Metglas went on to state that the proposed standards will encourage competition for transformer core steel and help solidify a majority domestic supply of transformer core steel. (Metglas, No. 125 at pp. 3-4)
The current domestic demand for electrical steel used in distribution transformers is estimated to be approximately 225,000 metric tons, which is approximately equal to the global capacity for amorphous material. The response to the April 2013 Standards Final Rule demonstrated that amorphous material manufacturers are willing and capable of adding capacity in response to increased demand (See Chapter 3A of the TSD). Metglas commented that between 2015 and 2018, production of amorphous alloy in China increased by 50,000 metric tons. (Metglas, No. 11 at pp. 3-4). Eaton commented that between 2013 and 2019, three additional companies entered the amorphous market with similar product widths to the U.S. domestic producer of amorphous (Eaton, No. 12 at p. 7)
If amended standards created an assured demand for amorphous material, it can be reasonably expected that amorphous ribbon capacity would increase to meet the demands of the U.S. distribution transformer market. Given expected demand for amorphous ribbon, there are no technical constraints preventing amorphous ribbon capacity from increasing, eventually; however, there is uncertainty as to what time frame that capacity would be sufficient to meet the demand created by amended efficiency standards. Metglas commented that it currently has an installed capacity of 45,000 metric tons available domestically and stated that it can bring an additional 75,000 metric tons of production online in less than 37 months, bringing total domestic capacity to 120,000 metric tons. Further, Metglas stated that it is willing to invest beyond current facility location constraints to meet customer demand. (Metglas, No. 125 at p. 8) In addition to statements from the current domestic amorphous supplier and demonstrations of capacity additions in other countries, recent patent filings from several major steel producers indicate that the production of amorphous alloy is an area of active technological innovation. 92 93 94 95
^{92} VAC, Amorphous Material—VITROVAC, (Last Accessed 12/21/2023), Available online at: https://vacuumschmelze.com/products/soft-magnetic-materials-and-stamped-parts/amorphous-material-vitrovac.
^{93} Hartman, T., Amorphous Metal Foil and Method for Producing an Amorphous Metal Foil Using a Rapid Solidification Technology, U.S. 0201914, 2023.
^{94} Guidebook for POSCO's amorphous metal, Docket No. EERE-2010-BT-STD-0048-0235.
^{95} Nippon Steel Corp, Fe-Based Amorphous Alloy Having Excellent Soft Magnetic Characteristics and Processability, Fe-Based Amorphous Alloy Thin Strip Having Excellent Soft Magnetic Characteristics and Processability, Wound Core, Stacked Core and Rotary Electric Machine, JP20231017731A, 2023.
If all distribution transformers had to transition to amorphous cores immediately, stakeholders stated that the capacity and core-construction infrastructure would not exist and there would be considerable price increases which would very likely worsen supply chains and have negative cost impacts for consumers, at least until supply could catch up with demand. However, comments from stakeholders indicate that longer transition times could allow distribution transformer manufacturers to more gradually transition to amorphous cores, mitigating supply chain concerns. DOE received several comments from stakeholders as to what they believe would be a reasonable timeframe and scope to allow for a gradual transition to higher-efficiency without significantly impacting near term pricing. These comments are discussed in section IV.C.2.a of this document.
As discussed, for efficiency levels up through EL2 for liquid-immersed distribution transformers, both amorphous and GOES transformers are anticipated to be able to compete on first cost. While stakeholders expressed concern that amorphous would not be able to scale up sufficiently to serve the entire distribution transformer market, DOE estimates that approximately 48,000 metric tons of amorphous will be used to meet the amended standards for liquid-immersed distribution transformers. While this is a considerable increase from the amount of amorphous used in distribution transformer cores today, it is approximately equal to the current stated amorphous capacity (of approximately 45,000 metric tons). Meaning, even if the amorphous core market were to be entirely served by domestic manufacturing, no additional amorphous manufacturers were to enter the market, and the current domestic manufacturer were to add no production capacity, amorphous capacity would still be approximately sufficient to serve the distribution transformer market.

b. Grain-Oriented Electrical Steel Market and Technology
GOES is a variety of electrical steel that is processed with tight control over its crystal orientation such that its magnetic flux density is increased in the direction of the grain orientation. The single-directional flow is well suited for distribution transformer applications and GOES is the dominant technology in the manufacturing of distribution transformer cores. GOES is produced in a variety of thicknesses and with a variety of loss characteristics and magnetic saturation levels. In certain cases, steel manufacturers may further enhance the performance of electrical steel by introducing local strain on the surface of the steel through a process known as domain refinement, such that core losses are reduced. This can be done via several methods, some of which survive the distribution transformer core annealing process.
In the January 2023 NOPR, DOE maintained the four subcategories of GOES that it had identified in the August 2021 Preliminary Analysis as possible technology options. 87 FR 1722. 1756. These technology options and their DOE abbreviations are shown in Table IV.5.
DOE noted in the January 2023 NOPR that for high-permeability steels, steel manufacturers have largely adopted a naming convention that includes the steel's thickness, a brand-specific designator, followed by the guaranteed core loss of that steel in W/kg at 1.7 Tesla (T) and 50 Hz. Id. Power in the U.S. is delivered at 60 Hz and the flux density can vary based on distribution transformer design, therefore the core losses reported in the steel name are not identical to their performance in the distribution transformer. However, the naming convention is generally a good indicator of the relative performance of different steels.
In the January 2023 NOPR, DOE discussed how different grades of GOES, and in particular hib and dr GOES, are typically marketed as suitable for use in either power or distribution transformers. Id. However, DOE also noted that power transformers tend to have priority over distribution transformers and generally receive the highest performing grades of GOES, as stated by stakeholders in public comment. (Schneider, No. 49 at p. 14; Cliffs, No. 57 at p. 1) The larger volume of the liquid-immersed distribution transformer market similarly tends to be served before the dry-type distribution transformer market. Id.
In response to the August 2021 Preliminary Analysis TSD, DOE received comment from stakeholders that the GOES steel supply had become more constrained in recent years. Stakeholders commented that certain grades of steel are becoming more difficult to acquire and costs have increased for all grades of steel. 87 FR 1722, 1756. In the January 2023 NOPR, DOE noted that the combined effect of general commodity related supply chain issues and competition from the EV market likely contributed to these recent supply issues and cost increases. Id. In response to stakeholder feedback, DOE proposed screening out some of the highest performing grades of GOES, where steel manufacturers are not able to mass produce GOES of similar quality. Id. In this final rule, DOE continued to screen out these steel grades, as discussed in section IV.B of this document. Further, DOE also updated all material costs in this final rule to account for recent trends in market prices, as discussed in section IV.C.2 of this document.
In response to the January 2023 NOPR, DOE received additional comments regarding the supply and availability of GOES.
NEMA commented that GOES with better performance than M3 is typically not available from domestic suppliers. (NEMA, No. 141 at p. 14) WEG commented that there are global shortages of high-grade GOES today. (WEG, No. 92 at p. 1) Prolec GE commented that GOES supplies have been constrained by worldwide increase in demand for GOES coupled with shifting production capacity to non-oriented electrical steel (NOES). (Prolec GE, No. 120 at p. 10) Howard commented that the GOES market has been severely impacted by NOES demand spikes. (Howard, No. 116 at p. 23) Metglas commented that there is currently a shortage of GOES due to a combination of factors, including competition from NOES and thinner gauge requirements for EVs reducing steel mill output capacity. (Metglas, No. 125 at p. 5)
MTC provided US import and consumption data for GOES and commented that U.S. consumption of GOES for distribution transformers is approximately 175K MT. (MTC, No. 119 at p. 2) MTC additionally commented that Cliffs is not currently able to meet demand requirements for GOES in the U.S. (MTC, No. 119 at p. 2) MTC added that lack of a secure domestic steel supply is an issue of national security which should be referred to the Department of Commerce for remedies. (MTC, No. 119 at p. 20) Efficiency Advocates commented that the current domestic GOES supply is insufficient to meet market demands and additional suppliers of GOES are unlikely to form due to long lead times and significant capital requirements. Efficiency Advocates further commented that higher grades of GOES are not available in large quantities domestically. (Efficiency Advocates, No. 121 at pp. 2-3)
Pugh Consulting commented that the single supplier of GOES has not indicated that they will increase production to meet demand and it is unclear whether a new manufacturer could obtain a Title V Clean Air Act permit. (Pugh Consulting, No. 117 at p. 3) DOE notes that Title V of the Clean Air Act requires facilities that are major sources of air pollutants to obtain operating permits, which specify permissible limits of pollutant emissions. However, Title V permitting for steel manufacturers is beyond the scope of this rulemaking.
Hammond commented that it expects the market to provide an adequate supply of both NOES and GOES for the foreseeable future. (Hammond, No. 142 at p. 2) Schneider commented that the supply and demand of GOES is well balanced today, GOES capacity will gradually increase over time, and they do not expect manufacturers to shift production of GOES to NOES because steel manufacturers recognize the role of GOES. (Schneider, No. 101 at p. 9)
Cliffs commented that it recently invested $40M to expand domestic electrical steel production (both GOES and NOES) and aims to invest more in the near future to keep up with demand. (Cliffs, No. 105 at p. 15)
NAHB commented that GOES is harder and more costly to produce than NOES because it requires additional processing steps. NAHB pointed out that a new domestic electrical steel facility, which opened in 2023, elected to produce NOES rather than GOES, which may indicate other domestic steel producers are unlikely to add GOES production lines. (NAHB, No. 106 at pp. 9-10)
Stakeholder comments submitted in response to the January 2023 NOPR further confirm that the current GOES market is experiencing supply constraints, inhibiting the ability of manufacturers to obtain the full range of core steel grades. DOE notes that this appears to be especially true for the domestic steel market, which stakeholders have stated does not have a sufficient quantity of low-loss steels to serve the needs of U.S. distribution transformer market. ^{96} Although the sole domestic producer of GOES is capable of producing a full range of M-grades and some hi-b steels, the supply of dr steels is more constrained and there is currently no domestic production of pdr GOES. Further, as previously noted, distribution transformer manufacturers compete for GOES with power transformer manufacturers, with many of the highest performing grades dedicated to power transformer production over distribution transformer production.
^{96} See also Department of Commerce investigation into imports of laminations and wound cores for incorporation into transformers. Docket No. BIS-2020-0015. Available at www.regulations.gov/docket/BIS-2020-0015.
This leaves a limited supply of the lowest-loss grades of GOES for distribution transformer manufacturers. Since 2018, all raw imported electrical steel has also been subject to a 25 percent ad valorem tariff. ^{97} Therefore, manufacturers are forced to choose between sourcing from the single domestic provider of GOES or paying more for imported product. The result of these myriad factors is a strained GOES supply for distribution transformer production.
^{97} See 83 FR 11625.
DOE also received comments regarding how the proposed standards might impact the GOES market.
Pugh Consulting suggested DOE should explore options to incentivize the domestic production of amorphous and GOES steel for distribution transformers, such as funding authorized by Congress, tax credits, and use of the Defense Production Act. (Pugh Consulting, No. 117 at p. 7) DOE notes that this final rule pertains only to energy conservation standards for distribution transformers, and any efforts to amend other Federal regulatory programs and policies are beyond the scope of this rulemaking. However, separate agency actions may promote production of domestic amorphous and GOES including the Advanced Energy Project Credit (48C) Program in partnership with the Department of the Treasury and the Internal Revenue Service. ^{98}
^{98} See https://www.energy.gov/infrastructure/qualifying-advanced-energy-project-credit-48c-program.
CARES commented that there is insufficient supply of either GOES or amorphous to meet the demand required by the proposed standards. (CARES, No. 99 at p. 3)
Cliffs commented that the proposed standards are contrary to established Federal policies that have designated GOES a critical product essential to U.S. national security interests. (Cliffs, No. 105 at pp. 2, 5-6) Specifically, Cliffs commented that the proposed standards are counter to the 232 report which concluded that maintaining domestic GOES capacity is crucial to national security and that domestic steel producers must have viable markets beyond solely the defense industry. (Cliffs, No. 105 at pp. 4-5) Cliffs stated that the proposed standards would negate any benefits currently being realized by the 25 percent 232 tariffs, which undermines the entire purpose of the tariffs. (Cliffs, No. 105 at pp. 3-5)
Cliffs further commented that the majority of domestic GOES is manufactured for use in distribution transformers and the NOPR makes production of both GOES and NOES economically untenable, risking 1500 jobs and undermining the supply chain for transformers, electric motors, and other industries. (Cliffs, No. 105 at p. 6) Cliffs additionally noted that: (1) GOES is needed for bulk power infrastructure, (2) several Federal reports have recommended establishing a stockpile of domestic GOES, and (3) the Cybersecurity and Infrastructure Security Agency has stated that large-power transformers are overly reliant on foreign imports, all of which further demonstrate the importance of domestic GOES manufacturing for national security. (Cliffs, No. 105 at pp. 7-8) DOE notes that large-power transformers are not subject to energy conservation standards.
Several stakeholders suggested that producers of electrical steel would discontinue production of GOES without demand for distribution transformers, eliminating the domestic supply of electrical steel and causing layoffs of approximately 1500 employees. (UAW, No. 90 at p. 1; UAW Locals, No. 91 at p. 1; BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 1) Stakeholders stated that this would eliminate the supply of electrical steel for other industries, such as EV motors, and make the U.S. entirely reliant on foreign entities to support the grid. Id. BCBC and BCGC added that the Butler Works electrical steel plant supports Butler County and any loss will have an exponential and devastating impact well beyond the plant itself. (BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 1) UAW Locals and BCBC and BCGC recommended that DOE either withdraw the NOPR or proceed with an efficiency standard that ensures continued use of GOES in distribution transformers. (UAW Locals, No. 91 at p. 2; BCBC, No. 131 at p. 1; BCGC, No. 132 at p. 1)
A number of stakeholders similarly submitted comments expressing concern that the proposed rulemaking would weaken domestic supply chains and jeopardize U.S. jobs by making the U.S. more reliant on foreign amorphous suppliers and suggested DOE should ensure GOES can continue to be used in distribution transformers. (Thomas, No. 155 at p. 1-2; Pennsylvania AFL-CIO, No. 156 at p. 1-2; BCCC, No. 158 at p. 1-2; Renick Brothers Co., No. 160 at p. 1; Snyder Companies, No. 161 at p. 1; Nelson, No. 157 at p. 1)
Other stakeholders similarly expressed concern that the proposed standards may lead the single domestic producer of GOES to either reduce or discontinue production, which could hurt transformer supply chains and make transformer manufacturers more reliant on foreign steel importers. (Michigan Members of Congress, No. 152 at p. 1; HVOLT, No. 134 at p. 7; AISI, No. 115 at pp. 2-3; Alliant Energy, No. 128 at p. 3; Kansas Congress Member, No. 143 at p. 1; Entergy, No. 114 at p. 2)
Eaton commented that DOE should consider the possibility of domestic GOES manufacturing disappearing in response to standards, leaving other critical resources like power transformers without a stable supply chain. (Eaton, No. 137 at p. 26) TMMA commented that the domestic GOES producer is not planning to invest in producing premium GOES grades and, therefore, U.S. transformer manufacturers will need to use foreign-produced GOES which isn't available in sufficient capacity to support the U.S. transformer market. (TMMA, No. 138 at pp. 3-4) MTC commented that the proposed standards will increase the cost of GOES production, potentially jeopardizing refurbishment, resilience, and upgrading of the grid. (MTC, No. 119 at p. 19) NEMA commented that the administration has sought to increase domestic manufacturing and this rule creates a dangerous imbalance of core steel supply. (NEMA, No. 141 at p. 2) NAHB commented that declining imports of both finished transformers and GOES in recent years, paired with a lack of domestic competition for GOES production, have exacerbated the transformer crisis and expressed concern that the NOPR will worsen these issues. (NAHB, No. 106 at pp. 6-8)
In the January 2023 NOPR, DOE discussed how GOES production can be shifted to NOES production at only a modest cost. 88 FR 1722, 1767. Stakeholders have commented that this transition is already occurring and has partially contributed to the GOES shortages experienced by the transformer industry. Id. The shift towards NOES production is largely driven by electrification trends and increased production of EV motors, creating an assured demand for NOES well into the future. As such, manufacturers of GOES in the current market may have the option of converting GOES production lines to NOES capacity in the event that demand for GOES decreases.
While Cliffs indicated in its comment that GOES production is used to support NOES production, DOE notes that in 2023 an additional domestic NOES production facility opened without GOES production. ^{99} This indicates that a NOES production facility is a reasonable investment on its own.
^{99} U.S. Steel, Big River Steel Overview. Available at www.ussteel.com/bigriversteeloverview (last accessed Nov. 8, 2023).
DOE also notes that other markets for GOES exist. For example, the power transformer market also acts as an end-use for domestically produced GOES. Although this market is smaller than the distribution transformer market by volume, with total demand for medium and large power transformers estimated to be over 2,700 units per year, individual units can weigh several hundred tons, contributing a significant source of demand for GOES. 86 FR 64606, 64662. Increased electrification likely means that the demand for large-power transformers, and therefore demand for GOES in large-power transformers, will continue to increase. Given the assured demand for GOES from the power transformer industry and the available option to convert capacity to NOES, along with the fact that a second domestic NOES production facility recently began production, it is unlikely that domestic electrical steel production would entirely disappear because of amended efficiency standards.
However, lead times for distribution transformers have significantly increased in recent years and could be exacerbated by a wholesale transition to amorphous cores at this time. Further, the vast majority of domestic GOES production is used in distribution transformers, and while alternative uses for that capital equipment may exist, preemptive conversion of that capital in anticipation of disappearing demand could exacerbate near-term transformer shortages. In an effort to minimize this risk, DOE has evaluated an additional TSL in which certain segments of the distribution transformer market remain at efficiency levels that can be met cost-competitively via GOES, as discussed in section V.A. DOE has also, in response to stakeholder feedback, modified its consumer purchasing behavior model to reflect the emphasis that both manufacturers and utilities are placing on lead time, wherein consumers continue to purchase a GOES transformer even if an amorphous transformer is lower cost up to a certain efficiency level, as discussed in section IV.F.3 of this document.
Finally, the standards finalized in this final rule include several equipment classes, representing considerable volume of core material, where GOES is expected to remain cost-competitive. DOE estimates the volume of core steel used in the equipment classes where GOES is expected to remain cost-competitive to be over ~146,000 metric tons for liquid-immersed distribution transformers, only a 21 percent reduction from the ~185,000 metric tons for liquid-immersed distribution transformers assumed in the no-new standards case. DOE also understands that manufacturers prefer to continue using existing GOES core production equipment, rather than replace GOES core production equipment with amorphous core production equipment., Accordingly, DOE expects that, for those classes where GOES remains cost-competitive, manufacturers will continue purchasing GOES steel, and will do so in quantities approximately equal to the existing domestic GOES market. Therefore, DOE does not expect a significant decrease in domestic GOES sales as a result of this rule.
DOE notes that core production equipment is somewhat flexible to manufacturer a variety of core sizes. As such, if an existing piece of GOES core production equipment manufactures cores for 75 kVA, 100 kVA and 167 kVA, as an example, manufacturers can meet efficiency standards by shifting that equipment to increase 75 kVA and 100 kVA GOES cores and adding a new amorphous core production machinery to manufacture 167 kVA transformers. The resulting set-up results in an increase in total transformer core production capacity as the amorphous line is invested in as an additive equipment line, as opposed to replacing existing GOES production equipment.

c. Transformer Core Production Dynamics
In the January 2023 NOPR, DOE discussed how transformer manufacturers have the option of either making or purchasing transformer cores, with some manufacturers choosing to do a mix of the two. 88 FR 1722, 1757. DOE further stated that transformer manufacturers also have the choice of producing cores domestically or producing them in a foreign country and importing them into the U.S. This creates three unique pathways for producing distribution transformers: (1) producing both the distribution transformer core and finished transformer domestically; (2) producing the distribution transformer core and finished transformer in a foreign country and importing into the United States; (3) purchasing distribution transformer cores and producing only the finished transformer domestically. Id.
DOE discussed how each of these unique sourcing pathways has their own advantages and disadvantages. Manufacturers who produce cores domestically may have the most control over their lead times and supply chains but may be more limited in selection of steel grades as a result of tariffs on foreign-produced GOES and only having access to one domestic manufacturer. Producing cores in a foreign country and importing into the U.S., on the other hand, allows for the same in-house production with access to the entire global market for GOES without the tariff on electrical steel, but provides less supply chain control and may lead to longer lead times. Finally, purchasing finished cores directly allows manufacturers to avoid investing in the labor and capital equipment required for core production, but provides the least control over delivery lead times and often will result in a higher cost per pound of steel when compared to manufacturers producing their own cores. Id.
In the January 2023 NOPR, DOE assumed that, in the presence of amended standards, manufacturers would maintain the same core production practices that they currently employ. 88 FR 1722, 1757-1758. For manufacturers that produce their own cores, this would mean investing in their in-house production processes and purchasing additional capital equipment, as required, in order to produce cores from higher grades of steel. For manufacturers that purchase finished cores, this would mean switching from purchasing cores of one steel grade to purchasing cores of a higher steel grade. Further, DOE stated that it did not view any one of these core and transformer production processes as becoming more advantaged or disadvantaged through amended standards and requested comment on whether the proposed standards would alter any of the current production pathways. Id.
A Kansas Congress Member recommended that DOE consider the immediate economic impacts that new standards may have on domestic steel and transformer manufacturers, energy providers, and developers. (Kansas Congress Member, No. 143 at p. 1)
Schneider commented that the 2016 standards caused many companies to shift from slitting steels to outsourcing core production. Schneider stated the proposed standards could potentially impact U.S. labor by further pushing core assembly to foreign suppliers. (Schneider, No. 92 at p. 10)
NEMA commented that GOES cores are both manufactured in-house and purchased from third party sources, but stated that distribution transformer manufacturers do not have the ability to produce amorphous cores internally. (NEMA, No. 141 at pp. 2-3) NEMA stated that the proposed standards would force manufacturers to either purchase transformer cores, weakening the supply chain, or make substantial investments in new capital. Id. NEMA added that there is only a single domestic company manufacturing amorphous cores and due to large capital costs, new capacity is unlikely to increase in the foreseeable future without Federal funding to expand domestic amorphous core manufacturing. (NEMA, No. 141 at pp. 2-3) NEMA further stated that the capital expenses needed for amorphous cores are likely to increase outsourcing of core manufacturing, potentially shifting jobs overseas and giving a monopolistic hold to the sole domestic manufacturer of amorphous cores. (NEMA, No. 141 at pp. 16-17) DOE notes that multiple domestic manufacturers have in-house amorphous core production capacity, although typically in substantially lesser volume than GOES core production. Substantial capital investments would be needed to add amorphous core production capacity. DOE has accounted for these capital investments in its MIA as discussed in section IV.J.
Howard commented that any regulation favoring GOES or amorphous will result in single source availability of core steel and encourage core offshoring, as tariffs have already done. (Howard, No. 116 at p. 18)
MTC expressed concern that the more labor intensive production process for amorphous metal cores will push core production outside the U.S. (MTC, No. 119 at p. 19)
The SBA commented that DOE must consider statutory factors including “the impact of any lessening of competition.” The SBA went on to state that there is only one domestic manufacturer of transformer cores which is already unable to keep up with demand. (SBA, No. 100 at p. 5) DOE notes that there are multiple domestic producers of distribution transformers, many of whom also produce cores domestically as detailed in Chapter 3 of the TSD.
Alliant Energy commented that it prefers to procure transformers domestically to protect grid security, expressing concern that there is currently only one U.S. producer of amorphous core steel with limited capacity. (Alliant Energy, No. 128 at pp. 2-3) DOE notes that most distribution transformers are produced domestically; however, depending on distribution transformer core production dynamics, the core steel in those products may or may not be produced domestically. As discussed in section IV.A.4.a of this document, both the amorphous and GOES market have one domestic producer and multiple global producers with capacity largely reflecting current demand.
Metglas stated that it does not control amorphous core costs, but an increased number of amorphous core makers should promote competition and drive down costs. (Metglas, No. 125 at p. 6)
DOE notes that while some stakeholders speculated efficiency standards where amorphous cores were most cost competitive would change core production dynamics, manufacturer's early responses in anticipation of a final rule suggest that a similar core production dynamic will exist (see chapter 3 of the TSD for additional details). DOE notes that distribution transformer manufacturers have already invested in additive facilities to produce amorphous cores domestically (and are already producing them). ^{100} DOE also notes that core manufactures have stated that they are planning on adding new facilities to produce amorphous cores in Canada and sell them to transformer manufacturers. ^{101}
^{100} Howard, T. Howard Industries cuts ribbon on Quitman plant, The Meridian Star, 2023. Available at www.meridianstar.com/news/howard-industries-cuts-ribbon-on-quitman-plant/article_022f5248-7a7e-11ee-91f9-873895c690d6.html.
^{101} Worthington Steel, Investor Day. Transcript. Available at s201.q4cdn.com/849745219/files/doc_events/2023/Oct/17/worthington-steel-investor-day-transcript-final-10-11-23.pdf.
DOE additionally notes that the adopted standards will maintain cost-competitive market segments for both GOES and amorphous. Therefore, manufacturers producing their own cores today can continue to utilize existing core production equipment.
Further, distribution transformer manufacturers are already investing in manufacturing expansions to support increased capacity demands on the electrical grid. In the past several years, manufacturers across the distribution transformer market have announced expansions of current capacity and intentions expand (some of these announced capacity expansions are discussed in chapter 3 of the TSD). As such, even without amended standards, manufacturers currently producing their own cores would need to invest in additional core production equipment to support these capacity additions or make alternative core procurement decisions. Therefore, manufacturers will have the option to add amorphous production capacity as part of these planned expansions in an additive fashion to meet increased demand, rather than adding amorphous production capacity to replace existing GOES capacity. This will further reduce the capital expenditures that manufacturers would be required to incur to meet amended standards, mitigating the risk that outsourcing of cores will increase.
Therefore, for the reasons discussed, DOE continued to assume in this final rule that all three core and transformer production pathways will remain viable options in the presence of amended standards, with manufacturers expected to maintain their current production practices.

5. Distribution Transformer Supply Chain
The distribution transformer market is divided into three segments—liquid-immersed, low-voltage dry-type, and medium-voltage dry-type—each of which has unique market dynamics and production practices. In recent years, the distribution transformer market has experienced significant supply chain challenges across all three segments of the market that have largely been attributed to demand for distribution transformers, along with other electric grid related equipment, increasing substantially. As result, lead times for transformers have increased and utility companies' transformer inventories have been reduced.
DOE notes that current shortages in the distribution transformer market are unrelated to efficiency standards. Current distribution transformer shortages are instead related to a significant increase in demand for many electric grid related products, which includes not only distribution transformers but many other products associated with expansion of the electrical grid not subject to any efficiency standards. Distribution transformer manufacturers have reported record production, in terms of number of shipments, but still noted that demand has grown even faster. ^{102}
^{102} TB&P, Electric Coops CEO wrestles with ever-evolving factors to maintain reliability, affordability, Jan. 15, 2023. Available online at: https://talkbusiness.net/2023/01/electric-coops-ceo-wrestles-with-ever-evolving-factors-to-maintain-reliability-affordability/.
PSE commented that lead times for distribution voltage regulators are even longer than for distribution transformers and this is unlikely to improve if electrical steelmakers are forced to shift to amorphous. (PSE, No. 98 at p. 11) DOE notes that voltage regulators are not subject to energy conservation standards but serve as an example of how product shortages are associated with many electric grid related products.
While numerous expansions of distribution transformer production plants have been announced, as discussed in Chapter 3 of the TSD, it takes time for those capacity expansions to come online. DOE notes that its proposed standards have considered the interaction between capacity expansions and conversion investment costs to meet the amended efficiency standards. Specifically, DOE adopted standards wherein manufacturers can choose to comply using either GOES or amorphous for the vast majority of shipments and significantly limited the shipments that can realistically only be met with amorphous cores. Stakeholders have noted that the ability to leverage both GOES and amorphous will reduce their electrical steel supply risk, provided development of that capability does not disrupt existing product output. ^{103}
^{103} Markham, I., ERMCO CEO: For an Effective Outcome, Focus on Inputs, The Wall Street Journal, Jan. 5, 2024. Available online at: https://deloitte.wsj.com/riskandcompliance/ermco-ceo-for-an-effective-outcome-focus-on-inputs-3ecfbeff.
In response to the January 2023 NOPR, DOE received comments on the current state of the distribution transformer market.
A variety of utility companies, trade associations, and other stakeholders commented that increased demand has led to nationwide distribution transformer shortages, with utility reserve stocks significantly reduced and lead times on the scale of 2 to 4 years. (APPA, No. 103 at p. 4; TMMA, No. 138 at p. 2; Indiana Electric Co-Ops, No. 81 at p. 1; Fall River, No. 83 at p. 2; Central Lincoln, No. 85 at p. 1; NRECA, No. 98 at p. 2; EEI, No. 135 at pp. 6-7, 9-10; Pugh Consulting, No. 117 at p. 3; NWPPA, No. 104 at p. 1-2; Entergy, No. 114 at p. 2; REC, No. 126 at p. 1-2; Xcel Energy, No. 127 at p. 1; Alliant Energy, No. 128 at p. 2; NMHC & NAA, No. 97 at p. 3; Portland General Electric, No. 130 at pp. 2-3; Webb, No. 133 at p. 1) Accordingly, many stakeholders advised against amending efficiency standards due to concerns that standards would further exacerbate supply chain challenges, increase the cost of transformers, delay transformer deliveries, and introduce additional strain on the electrical grid. (BIAW, No. 94 at p. 1; TMMA, No. 138 at p. 2; Entergy, No. 114 at p. 2; Alliant Energy, No. 128 at p. 1; Idaho Falls Power, No. 77 at pp. 1-2; Fall River, No. 83 at p. 1; Joint Associates, No. 68 at p. 2; Central Lincoln, No. 85 at p. 1; Chamber of Commerce, No. 88 at p. 3; NRECA, No. 98 at pp. 2-3; SBA, No. 100 at p. 5; Pugh Consulting, No. 117 at pp. 2-3; HVOLT, No. 134 at p. 6; Exelon, No. 95 at pp. 1-2; REC, No. 126 at pp. 1-3; Idaho Power, No. 139 at pp. 3, 6; Portland General Electric, No. 130 at pp. 1, 4-5; Indiana Electric Co-Ops, No. 81 at p. 1; NEPPA, No. 129 at p. 3; WEC, No. 118 at p. 3; TVPPA, No. 144 at p. 2; AISI, No. 115 at pp. 2-3; TVPPA, No. 144 at p. 1-2; NAHB, No. 106 at p. 4; CARES, No. 99 at p. 5; APPA, No. 103 at p. 2; Webb, No. 133 at p. 2; Allen-Batchelor Construction, No. 79 at p. 1; EEI, No. 135 at p. 1) NRECA urged DOE to not amend standards and instead focus on other means to incentivize amorphous cores without jeopardizing electric reliability. (NRECA, No. 98 at p. 8)
Many elected officials submitted comments describing how their local jurisdictions have been impacted by the national shortage of distribution transformers, expressing concern that the proposed standards could worsen the impacts of this shortage. (New York Members of Congress, No. 153 at p. 1; Kansas Congress Member, No. 143 at p. 1; Alabama Senator, No. 113 at p. 1; VA, MD, and DE Members of Congress, No. 148 at p. 1; Texas Congress Member, No. 149 at p. 1; Florida Members of Congress, No. 150 at pp. 1-2; South Dakota Congress Member, No. 145 at p. 1)
EEI attached a joint response to DOE's RFI on the Defense Production Act (87 FR 61306) reiterating a request that DOE dedicate funding to provide financial support to transformer manufacturers and producers of electrical steel. In that request, EEI stated that the primary challenges for transformer manufacturers include attracting and retaining a strong workforce and uncertainty of whether demand will continue to grow. (EEI, No. 135 at pp. 32-43)
DOE notes that this final rule pertains only to energy conservation standards for distribution transformers, and any efforts to amend other Federal regulatory programs and policies are beyond the scope of this rulemaking.
Several stakeholders specifically recommended that DOE abandon the proposed standard and instead issue a temporary waiver of the existing standards to allow more ubiquitous steel components to be used in the manufacturing process to increase transformer supplies. (NEPPA, No. 129 at p. 3; NWPPA, No. 104 at p. 2; TVPPA, No. 144 at p. 2; CARES, No. 99 at pp. 2-3)
As discussed, DOE has made modifications to its distribution transformer purchasing model to reflect the current challenges associated with the distribution transformer supply chain as discussed in section IV.F.3 of this document.
Pugh Consulting commented that the proposed rule will reduce competition for electric utilities, distribution transformer manufacturers, and home building construction companies. (Pugh Consulting, No. 117 at p. 4) DOE notes that its adopted standard allows for a diversity of core materials to be used and allows for manufacturers to largely maintain existing production equipment. Therefore, DOE does not anticipate reduced competition in the distribution transformer market. This conclusion is consistent with the assessment of the Attorney General as detailed in the letter published at the end of this final rule.
Separately, DOE also received feedback that distribution transformer shortages are delaying building projects, negatively impacting the housing market and impeding the availability of affordable housing in the U.S. (NAHB, No. 106 at p. 2; APPA, No. 103 at p. 5; Fall River, No. 83 at p. 1; Cleveland, No. 80 at p. 1; Ivey Residential, No. 82 at p. 1; BIAW, No. 94 at p. 1; Pugh Consulting, No. 117 at p. 4; NMHC & NAA, No. 97 at p. 1, Williams Development Partners, No. 84 at p. 1, Kansas Congress Member, No. 143 at p. 1; Allen-Batchelor Construction, No. 79 at p. 1; Alliant Energy, No. 128 at pp. 4-6) Several stakeholders also noted that the shortage of transformers is limiting the ability of utilities to interconnect new customers across the country, thereby impeding economic development in other sectors. (Alliant Energy, No. 128 at p. 2; EEI, No. 135 at pp. 10-11)
Several stakeholders specifically commented that the shortage of distribution transformers is delaying the construction of new housing developments which increases costs for homebuyers and, in some cases, may cause them to lose their rate lock on mortgage interest rates. (BIAW, No. 94 at p. 1; NAHB, No. 106 at pp. 4-5; NMHC & NAA, No. 97 at pp. 1-4; LBA, No. 108 at pp. 1-3)
Stakeholder comments demonstrate how distribution transformers play an integral role in the electrical grid, and how the impact that a shortage of transformers can have across industry and especially in certain infrastructure-oriented segments such as the housing market. DOE notes that the transformer industry is actively responding to current shortages of distribution transformers, with multiple major suppliers having announced capacity expansions in recent months and years (as discussed in chapter 3 of the TSD). While additional capacity takes time to build and the effects will not be immediately felt by the broader distribution transformer market, once online, these capacity expansions should help alleviate some of the current supply challenges.
DOE notes that, historically, amended efficiency standards have not significantly increased transformer lead times, and current transformer shortages began occurring long after the most recent energy conservation standards went into effect. This is demonstrated by the producer price index time series data for the electric power and specialty transformer industry, which shows relatively steady pricing from 2010 to 2020 followed by significant price increases starting in 2021. ^{104} However, DOE acknowledges that if investments in conversion costs compete with needed investments in capacity expansions, lead times for distribution transformers could increase. At the same time, investment in new amorphous production equipment could allow for higher efficiency standards for specific equipment classes, while shifting existing production equipment to increase production of other equipment classes, thereby increasing total capacity to produce distribution transformers. DOE has considered the impact that amended standards could have on distribution transformers costs in section IV.C.2 of this document.
^{104} U.S. Bureau of Labor Statistics, Producer Price Index by Industry: PPI industry data for Electric power and specialty transformer mfg, not seasonally adjusted., Available online at: https://www.bls.gov/ppi/databases/ (retrieved on 03/17/2024).
Several stakeholders specifically expressed concern that shortages of distribution transformers will reduce grid reliability, potentially impeding the ability of utilities to restore power following natural disasters and in emergency situations. (EEI, No. 135 at pp. 16-17, 28-29; Michigan Members of Congress, No. 152 at p. 1; Alliant Energy, No. 128 at p. 2; Portland General Electric, No. 130 at pp. 4-5, Pugh Consulting, No. 117 at p. 6; Florida Members of Congress, No. 150 at pp. 1-2; Entergy, No. 114 at p. 3; APPA, No. 103 at p. 12; Exelon, No. 95 at p. 3)
Other stakeholders commented that transformer shortages are negatively impacting grid resilience and modernization, and recommended that DOE prioritize restoring a steady supply of distribution transformers, which would facilitate electrification efforts. (Chamber of Commerce, No. 88 at p. 3; CARES, No. 99 at p. 2; EEI, No. 135 at pp. 4-5; Pugh Consulting, No. 117 at p. 7; Exelon, No. 95 at p. 4; Xcel Energy, No. 127 at p. 1; Alliant Energy, No. 128 at p. 3; Alliant Energy, No. 128 at p. 4; NMHC & NAA, No. 97 at p. 3; Ivey Residential, No. 82 at p. 1; NWPPA, No. 104 at pp. 1-2; New York House Representatives, No. 153 at p. 1; Michigan Members of Congress, No. 152 at p. 1; Florida Members of Congress, No. 150 at p. 1)
Portland General Electric commented that it has made changes to reduce the impact of shortages on its customers, such as delaying non-critical, non-customer jobs and exploring new sources, including offshore manufacturers, for refurbished transformers. (Portland General Electric, No. 130 at p. 3) Similarly, WEC commented that it has taken drastic steps to address the transformer shortages, and any additional supply chain issues will further limit the company's ability to support Federal and State grid resiliency initiatives, such as storm hardening and increasing capacity to support electric-vehicle-charging and solar installations. (WEC, No. 118 at p. 2)
EVgo commented that the distribution transformer supply chain shortages are impacting deployment of EV charging infrastructure and encouraged DOE to prioritize adequate supply of transformers so that regulations do not hamper EV charger deployment goals. (EVgo, No. 111 at pp. 1-2)
APPA commented that this rulemaking will increase lead times by 6-20 months and worsen supply chain constraints, which would negatively impact larger electrification efforts. (APPA, No. 103 at pp. 1-2, 6-7) NEMA commented that the proposed standards will increase production time and will negatively impact electrification and grid resiliency efforts while weakening domestic manufacturing capacity. (NEMA, No. 141 at pp. 1, 5) NEPPA commented that the proposed standards are infeasible and may inhibit electric grid reliability, electrification, and modernization goals. (NEPPA, No. 129 at p. 1)
NYSERDA commented that it anticipates a surge of distribution transformer installations as utilities make up for recent pandemic-related supply chain delays. NYSERDA further stated that any delay of standards could result in a significant number of less efficient transformers remaining in service well beyond 2050. (NYSERDA, No. 102 at p. 2)
DOE recognizes that a stable transformer supply chain will be essential to grid modernization. However, DOE disagrees with the notion that amended standards stand in opposition of those goals. As pointed out by the CEC, increasing transformer efficiency saves energy that would otherwise need to pass through the electrical grid, thereby reducing strain on the electrical grid. Further, as stated by NYSERDA, delaying efficiency standards for distribution transformers in a time when additional capacity is expected to come online in the near-to medium-term would result in the loss of significant energy savings which could otherwise be realized. As discussed above, providing certainty as to future transformer efficiency standards could incentivize manufacturers to invest in more efficient core production technology in an additive fashion that diversifies core materials and increases overall production in the near term. DOE also notes that the adopted standard levels provide the maximum improvement in energy efficiency while still being technologically feasible and economically justified. As discussed further, DOE has included in its consideration of whether efficiency standards are justified the potential effect that a given standard would have on existing distribution transformer shortages, on the domestic electrical steel supply, and on projected changes to the transformer market to support electrification.
DOE also received feedback on how the proposed rule might impact costs to consumers because of the effect that standards would have on the transformer supply chain.
Several stakeholders commented that the added costs of using amorphous core transformers, both in the original purchase price and increased installation/maintenance costs, will be borne by the end consumer. (NEPPA, No. 129 at p. 3; REC, No. 126 at p. 2; TMMA, No. 138 at p. 3; Fall River, No. 83 at p. 2; Idaho Falls Power, No. 77 at p. 1) NEPPA commented that during the 2016 rulemaking process, utilities and manufacturers predicted that forcing increased efficiency levels would cause increases to both per-unit cost and lead times. (REC, No. 126 at p. 2) NEPPA commented that prices are currently up to four times the predicted price and lead times are upwards of 188 weeks compared to 90-percent shorter lead times just a few years ago, with many suppliers not even providing a guaranteed price or lead time to small-volume purchasers. (NEPPA, No. 129 at p. 2)
Portland General Electric further stated that prices are spiking as utilities seek more transformers and that utilities are in a precarious position as they commit to buying and storing more transformers than may actually be needed. (Portland General Electric, No. 130 at p. 3) Webb advised against amending efficiency standards given the current volatility of the transformer market, with high material costs, restricted production capacity and labor resources, and increasing raw material costs all contributing to high prices and lead times for distribution transformers. (Webb, No. 133 at pp. 1-2) WEG commented that the initial costs of this rule outweigh the benefits, especially when considering current supply chains. (WEG, No. 92 at p. 1)
DOE notes that the price increases and extended lead times currently exhibited in the distribution transformer market do not appear to be the direct result of standards amended in the 2013 Standards Final Rule, as suggested by NEPPA. Rather, the price of distribution transformers stayed relative constant for several years following the implementation of standards in 2016. ^{105}
It was not until late 2020 or early 2021, when significant disruptions to the market and industry-wide supply chain challenges began to occur, that distribution transformer prices began to significantly increase. These price increases were directly correlated to price increases for grain oriented electrical steel, which nearly doubled in price from 2021 to 2023. ^{106} These price trends demonstrate how recent price hikes for distribution transformers have been more the result of increase demand, as opposed to amended efficiency standards. DOE has considered the potential impact that amended efficiency standards could have on transformer prices in section IV.C.2 of this document.
^{105} U.S. Bureau of Labor Statistics, PPI Commodity data for Machinery and equipment-Power and distribution transformers, except parts, not seasonally adjusted. Available at data.bls.gov/ pdq/SurveyOutputServlet (last accessed Nov. 3, 2023).
^{106} Metal Miner, Global M3 Price Index. November 2023. Available at agmetalminer.com/metal-prices/grain-oriented-electrical-steel/ (last accessed Nov. 3, 2023).
DOE also received comments relating to the specific challenges that the transformer supply chain might face in transitioning to amorphous cores.
Portland General Electric commented that a shift to amorphous core transformers would lead to even more widespread unavailability of distribution transformers as transformer manufacturers retool and redesign production, which would require new submittal and approval drawings to be provided to utilities. (Portland General Electric, No. 130 at p. 3) Entergy commented that the proposed standard creates an additional supply constraint for distribution transformers, creates technical issues that need to be vetted, increases costs, and hampers resiliency efforts in an area of the country that is critical to energy security. (Entergy, No. 114 at p. 4)
APPA commented that transformer manufacturers are not expanding due to concern that the NOPR would make investments obsolete, concerns over electrical steel availability, and labor shortages, which would be exacerbated by the additional labor needed to produce amorphous transformers. (APPA, No. 103 at p. 6) Webb recommended DOE confirm that manufacturers can gear up their factories in a timely manner to effectively produce the equipment required for the proposed standards. (Webb, No. 133 at pp. 1-2)
ERMCO and Exelon stated that the proposed rule would divert resources from resolving the current transformer supply crisis. (ERMCO, No. 86 at p. 1; Exelon, No. 95 at p. 2) ERMCO added that this redirect of resources will take focus off meeting current demand, which will inevitably open the door for overseas manufacturers to supply the US electrical grid. (ERMCO, No. 86 at p. 1) WEG commented that if implemented, the proposed standards will significantly reduce the supply of distribution transformers to the U.S. (WEG, No. 92 at p. 4) Southwest Electric commented that enforcing the proposed standards before sufficient capacity for both amorphous core material and copper is established could restrict availability of new transformers and further increase lead times. (Southwest Electric, No. 87 at p. 3)
Prolec GE commented that longer cycle times for amorphous could reduce production capacity up to 20 percent. (Prolec GE, No. 120 at p. 3) Similarly, Prolec GE commented that thinner laminations for lower-loss GOES grades affect total mill production capacity and make it difficult to justify shifting production to lower-loss steels. (Prolec GE, No. 120 at p. 10)
Eaton commented that prolonged labor and supply chain challenges have driven lead times up to 18 months for LVDT units and ranging from 2 to 4 years for liquid immersed units. Eaton added that a forced transition to amorphous will require multiple development projects and significant capital investment, exacerbating existing labor and material supply issues. (Eaton, No. 137 at pp. 2-3) Howard commented that the NOPR has created uncertainty causing electrical steel manufacturers not to build new silicon steel plants at a time when they are desperately needed. Howard stated that even absent amended standards, additional electrical steel capacity is needed to serve the EV market and increasing efficiency standards magnify these requirements. (Howard, No. 116 at p. 2) Howard went on to state that virtually all components of transformers are experiencing a shortage right now driven by the limited number of suppliers and global labor and material shortages. Howard encouraged DOE to delay the implementation of any standards until the existing transformer shortage is resolved and lead times are back to normal. (Howard, No. 116 at pp. 4-5) Hammond commented that it has expanded capacity by 20 percent in 2020, with another 20 percent planned in 2023, but has still been struggling to meet demand. Hammond added that all of the expanded capacity is for GOES core construction, not amorphous. (Hammond, No. 142 at p. 2) ABB stated that the transformer industry will be unable to provide an adequate supply of transformers to fuel grid modernization without a robust supply of transformer core steel. (ABB, No. 107 at p. 3)
SolaHD commented that distribution transformers are already very efficient, and due to the intricate designs, increasing efficiency by even a fraction of a percent could add weeks or months to lead times. (SolaHD, No. 93 at p. 2) SolaHD expressed concern that the proposed standards will worsen existing lead times, which are currently over 16 months times for medium- and high-voltage distribution transformers and 6-8 weeks for the LVDT units that SolaHD produces. SolaHD added that this might delay national efficiency improvements and electrification initiatives. (SolaHD, No. 93 at pp. 1-2)
SolaHD, ABB, NEMA, and APPA commented that the administration clearly recognized the severity of the current supply chain crisis for transformers given the use of the Defense Production Act to prioritize domestic transformer production. (SolaHD, No. 93 at p. 2; ABB, No. 107 at p. 3; NEMA, No. 141 at pp. 1-2; APPA, No. 103 at p. 5) Environmental and Climate Advocates commented that funds from the Bipartisan Infrastructure Bill and the Inflation Reduction Act can be used by utilities and buildings owners to cover the costs of new transformers. (Environmental and Climate Advocates, No. 122 at p. 2)
As previously stated, DOE notes the distribution transformer market is in a unique position in which capacity needs to be added to meet demand, regardless of the implementation of standards. This provides the opportunity for industry to bring capital equipment online through additions to existing capacity. In light of these comments, DOE has evaluated an additional TSL in which certain equipment classes remain at efficiency levels that can cost-competitively be met via GOES. DOE notes the adopted efficiency levels allows GOES to remain cost-competitive for a substantial volume of distribution transformer shipments, meaning that manufacturers can retain their existing capital equipment, thereby not worsening near-term supply chain issues.
DOE also notes that the standards adopted in this final rule will allow distribution transformers to cost-competitively utilize existing GOES capacity across many kVA ratings. As discussed, core production equipment generally carries flexibility to manufacture a range of core sizes. As such, if an existing piece of GOES core production equipment manufactures cores for 75 kVA, 100 kVA and 167 kVA, as an example, manufacturers can meet efficiency standards by shifting that equipment to increase 75 kVA and 100 kVA GOES cores and adding a new amorphous core production machinery to manufacture 167 kVA transformers. The resulting arrangement results in an increase in total transformer core production capacity as the amorphous line is invested in as an additive equipment line, as opposed to replacing existing GOES production equipment.
Further, DOE notes that the compliance period for amended standards has been extended beyond what was proposed in the January 2023 NOPR. DOE believes the additional time provided to redesign transformers and build capacity will further mitigate the risk of disrupting production necessary to meet current demand.

B. Screening Analysis
DOE uses the following four screening criteria to determine which technology options are suitable for further consideration in an energy conservation standards rulemaking:
(1) Technological feasibility. Technologies that are not incorporated in commercial products or in commercially viable, existing prototypes will not be considered further.
(2) Practicability to manufacture, install, and service. If it is determined that mass production of a technology in commercial products and reliable installation and servicing of the technology could not be achieved on the scale necessary to serve the relevant market at the time of the projected compliance date of the standard, then that technology will not be considered further.
(3) Impacts on product utility. If a technology is determined to have a significant adverse impact on the utility of the product to subgroups of consumers, or result in the unavailability of any covered product type with performance characteristics (including reliability), features, sizes, capacities, and volumes that are substantially the same as products generally available in the United States at the time, it will not be considered further.
(4) Safety of technologies. If it is determined that a technology would have significant adverse impacts on health or safety, it will not be considered further.
(5) Unique-pathway proprietary technologies. If a technology has proprietary protection and represents a unique pathway to achieving a given efficiency level, it will not be considered further, due to the potential for monopolistic concerns.
10 CFR 431.4; 10 CFR part 430, subpart C, appendix A, 6(c)(3) and 7(b).
In sum, if DOE determines that a technology, or a combination of technologies, fails to meet one or more of the listed five criteria, it will be excluded from further consideration in the engineering analysis. The reasons for eliminating any technology are discussed in the following sections.
The subsequent sections include comments from interested parties pertinent to the screening criteria, DOE's evaluation of each technology option against the screening analysis criteria, and whether DOE determined that a technology option should be excluded (“screened out”) based on the screening criteria.

1. Screened-Out Technologies
In the January 2023 NOPR, DOE screened-out the technology options listed in Table IV.6 and detailed the basis for screening in chapter 4 of the NOPR TSD. ^{107} DOE did not receive any comments on the screened-out technology options. As such, DOE has retained those technology options as screened-out.
^{107} Available at Docket No. EERE-2019-BT-STD-0018-0060.

2. Remaining Technologies
Through a review of each technology, DOE concludes that the remaining combinations of core steels, winding configurations and core configurations as combinations of “design options” for improving distribution transformer efficiency met all five screening criteria to be examined further as design options in DOE's final rule analysis.
DOE determined that these technology options are technologically feasible because they are being used or have previously been used in commercially available products or working prototypes. DOE also finds that all of the remaining technology options meet the other screening criteria ( i.e., practicable to manufacture, install, and service; do not result in adverse impacts on consumer utility, product availability, health, or safety; and do not utilize unique-pathway proprietary technologies). For additional details, see chapter 4 of the final rule TSD.
DOE received comments from certain stakeholders suggesting that amorphous cores should be screened out as a technology option.
Regarding use of amorphous cores in high-kVA distribution transformers, Eaton commented that it is not aware of any amorphous core transformers that are commercially available beyond 1,500 kVA and therefore DOE should screen-out amorphous cores for distribution transformers beyond 1,500 kVA. (Eaton, No. 137 at p. 19) Eaton stated that manufacturers would need to resolve technical challenges before manufacturing amorphous cores over 1,500 kVA and therefore DOE should not evaluate efficiency standards for transformers above 1,500 kVA that cannot be met with GOES. (Eaton, No. 137 at p. 26) TMMA commented that amorphous is unproven for transformers larger than 2,500 kVA and therefore it is not clear that the proposed standards are technically feasible. (TMMA, No. 138 at p. 3) Prolec GE commented that amorphous is not proven all the way up to 5,000 kVA. (Prolec GE, No. 120 at p. 3) LBA commented that amorphous transformers have more limited capacity, which will require manufacturers to increase the number of transformers. (LBA, No. 108 at p. 3)
Carte commented that amorphous cores are highly susceptible to any outside pressure on the cores and as such cannot be used to secure the coils inside a transformer on larger kVA. (Carte, No. 140 at p. 2) Carte stated that certain manufacturers had not built amorphous core transformers beyond certain sizes due to these clamping limitations and encouraged DOE to investigate if large amorphous cores could be built. (Carte, No. 140 at p. 2) Carte added that developing new technology to be able to brace large amorphous cores could take years and cost hundreds of thousands of dollars. (Carte, No. 140 at p. 2)
DOE notes that amorphous transformers do exist over 1,500 kVA. Numerous foreign manufacturers advertise both liquid-immersed and MVDT distribution transformers above 1,500 kVA. One manufacturer in Korea markets 15,000 kVA amorphous oil-immersed transformers, with deliveries as early as 2007, and markets amorphous MVDT units up to 5,000 kVA. ^{108} One manufacturer in India markets amorphous liquid-immersed distribution transformers up to 5,000 kVA. ^{109} Dating back to the early 2010's, ABB offered an amorphous MVDT unit up to 4,000 kVA. ^{110} Further, in public utility bid data, DOE has observed numerous manufacturer bids for 2,500 kVA amorphous core distribution transformers ( see chapter 4 of the TSD). While Carte is correct that amorphous cores do not have the same inherent mechanical strength as GOES, manufacturers have developed core clamps and bracing to provide the necessary mechanical strength. In some cases, this may even include using a strip of GOES steel on the exterior of an amorphous core to provide additional mechanical strength. ^{111}
^{108} Cheryong Electric, Power Products. Available at en.cheryongelec.com/eng/library/catalog.php.
^{109} Kotsons, Power & Distribution Transformers. Available at www.kotsons.com/assets/images/Broucher.pdf.
^{110} ABB, Responding to a changing world: ABB launches new dry-type transformer products, 2012. Available at library.e.abb.com/public/74cdbc97d4588a1cc1257ab8003a00b5/22-27%20sr105a_72dpi.pdf.
^{111} Advanced Amorphous Technology, About Amorphous Distribution Transformer. Available at advancedamorphous.com/about-amorphous-distribution-transformer/ (last accessed Oct. 17, 2023).
Regarding use of amorphous cores in LVDT distribution transformers, Hammond commented that the performance of amorphous cores degrades above 160C and LVDTs frequently are rated with an insulation system capable of 220C, so there is insufficient technical data to understand how amorphous cores will perform long term in LVDT applications. (Hammond, No. 142 at pp. 2-3)
SolaHD expressed concern that amorphous cores are largely untested for LVDT distribution transformers, stating that amorphous cores are less flexible and more expensive than GOES. (SolaHD, No. 93 at p. 2) Schneider commented that amorphous will increase the sound emitted from distribution transformers, which likely won't be an issue for products installed outdoors or in large electrical rooms but may be an issue for LVDTs, which are typically in smaller rooms. (Schneider, No. 101 at p. 14) Eaton commented that there is a lack of technical data to validate the performance of amorphous cores for LVDT transformers. Eaton further stated that developing manufacturing processes for amorphous LVDT transformers will require significant investment, years of research and development, and impact required accuracy to meet customer specifications. (Eaton, No. 137 at p. 41)
DOE notes that Hammond did not provide any data or modeling as to the change in transformer core performance above 160C. However, distribution transformer temperature rise is governed by transformer losses. A more efficient transformer may not ever meet the insulation temperature limits. In the case of amorphous dry-type transformers, Schneider commented regarding K-factor rated transformers that computer modeling suggests that the reduced losses of amorphous LVDT units would place the thermal characteristics well below the insulation material. (Schneider, No. 101 at pp. 5-6) Further, in the amorphous LVDT and MVDT products marketed in international markets, it is common for transformers to be marketed with Class H or Class F insulation, corresponding to 150C and 115C temperature rise, or 220C and 185C performance. 112 113 A comparison of the performance of these LVDT units to DOE modeled units is given in chapter 5 of the TSD and indicates that it is technically feasible to build LVDTs with amorphous cores that satisfy common customer specifications.
^{112} Toyo Electric, “Dry-type Amorphous core transformer.” Available at www.toyo-elec.co.jp/en/products/dry-type-amorphous-core-transformer/ (last accessed Oct. 2023).
^{113} Chu Lei Electric Co., “Amorphous Transformers.” Available online at: www.powertransformer.com.tw/en/amorphous-transformers.html (last accessed Oct. 2023).
APPA stated that rewinding transformers, rather than purchasing a new transformer, can result in a lower cost and shorter lead time for utilities. (APPA, No. 103 at pp. 11-12) APPA commented that utilities today are rewinding up to 15 percent of their transformers due to the significant lead times. (APPA, No. 103 at pp. 11-12). APPA commented that the ability to rewind GOES transformers is a consumer utility that would be lost if DOE standards require amorphous cores. (APPA, No. 103 at pp. 11-12)
APPA stated that GOES transformer rewinding equipment is incompatible with amorphous cores and notes that amorphous rewinding equipment is far more complex and expensive. (APPA, No. 103 at pp. 11-12) DOE notes that amorphous core transformers can also be rewound, as acknowledged by APPA, and therefore DOE disagrees that the ability to rewind a transformer is lost if an amorphous core is used.
DOE notes that the transformer rebuilding/rewinding market has historically been relatively small. Rewinding a distribution transformer requires additional labor (because labor is required both to deconstruct the transformer and rebuild it) that has made replacing a distribution transformer the preferred option when a transformer fails. While recently there has been an uptick in transformer rewinding, that is primarily a function of long lead times for new transformers.
Regardless of the core steel used to meet efficiency standards, rewinding of GOES transformers will continue to be an option for utilities for as long as existing GOES transformers remain in the field. Given that rewinding of transformers does not typically occur until late in a distribution transformer's lifetime, any existing utility investment in rewinding equipment will likely be used on the existing stock of transformers for many decades. Any investment in amorphous core rewinding equipment would likely be in an additive function and not impact near or medium-term ability to rewind transformers.
DOE notes that amorphous core transformers have been used as a technology option for high-efficiency transformers for many decades. While there are conversion costs, required to transition from producing GOES cores to amorphous cores, those costs are considered in the manufacturer impact analysis. Additionally, while amorphous cores are different than GOES cores and require a degree of technological understanding to properly use amorphous core transformers, the vast majority of liquid-immersed transformer manufacturers have some experience building amorphous core transformers, and numerous foreign manufacturers produce amorphous core transformers spanning a range of product classes. Further, manufacturers have the option to purchase finished amorphous cores from third-party electrical processing companies, which provides another avenue to producing amorphous core transformers. Based on the foregoing discussion, DOE has retained amorphous cores as a technology option for achieving higher efficiency standards in distribution transformers.

C. Engineering Analysis
The purpose of the engineering analysis is to establish the relationship between the efficiency and cost of distribution transformers. There are two elements to consider in the engineering analysis; the selection of efficiency levels to analyze ( i.e., the “efficiency analysis”) and the determination of product cost at each efficiency level ( i.e., the “cost analysis”). In determining the performance of higher-efficiency equipment, DOE considers technologies and design option combinations not eliminated by the screening analysis. For each equipment class, DOE estimates the baseline cost, as well as the incremental cost for the product/equipment at efficiency levels above the baseline. The output of the engineering analysis is a set of cost-efficiency “curves” that are used in downstream analyses ( i.e., the LCC and PBP analyses and the NIA).

1. Efficiency Analysis
DOE typically uses one of two approaches to develop energy efficiency levels for the engineering analysis: (1) relying on observed efficiency levels in the market ( i.e., the efficiency-level approach), or (2) determining the incremental efficiency improvements associated with incorporating specific design options to a baseline model ( i.e., the design-option approach). Using the efficiency-level approach, the efficiency levels established for the analysis are determined based on the market distribution of existing products (in other words, based on the range of efficiencies and efficiency level “clusters” that already exist on the market). Using the design option approach, the efficiency levels established for the analysis are determined through detailed engineering calculations and/or computer simulations of the efficiency improvements from implementing specific design options that have been identified in the technology assessment. DOE may also rely on a combination of these two approaches. For example, the efficiency-level approach (based on actual products on the market) may be extended using the design option approach to interpolate to define “gap fill” levels (to bridge large gaps between other identified efficiency levels) and/or to extrapolate to the “max-tech” level (particularly in cases where the “max-tech” level exceeds the maximum efficiency level currently available on the market).
For this final rule analysis, DOE used an incremental efficiency (design-option) approach. This approach allows DOE to investigate the wide range of design option combinations, including varying the quantity of materials, the core steel material, primary winding material, secondary winding material, and core manufacturing technique.
For each representative unit analyzed, DOE generated hundreds of unique distribution transformer designs by contracting with Optimized Program Services, Inc. (OPS), a software company specializing in distribution transformer design. The OPS software uses two primary inputs: (1) a design option combination, which includes core steel grade, primary and secondary conductor material, and core configuration, and (2) a loss valuation.
DOE examined number design option combinations for each representative unit. The OPS software generated 518 designs for each design option combination based on unique loss valuation combinations. Taking the loss value combinations, known in industry as A and B values and representing the commercial consumer's present value of future no-load and load losses in a distribution transformer respectively, the OPS software sought to generate the minimum TOC. TOC can be calculated using the equation below.
TOC = Transformer Purchase Price + A * [No Load Losses] + B * [Load Losses]

a. Representative Units
Distribution transformers are divided into different equipment classes, categorized by the physical characteristics that affect equipment efficiency. DOE's current equipment classes are detailed in section IV.A.2.
Because it is impractical to conduct detailed engineering analysis at every kVA rating, DOE conducts detailed modeling on “representative units” (RUs). These RUs are selected both to represent the more common designs found in the market and to include a variety of design specifications to enable generalization of results.
DOE detailed the specific RUs used in the NOPR analysis and those units' characteristics in chapter 5 of the NOPR TSD. ^{114} Each RU represents an individual transformer model referred to by a specific RU number ( e.g., RU1, RU2, etc.). DOE requested comment on its representative units as well as any data for potential equipment that may have a different cost-efficiency curve than those that can be represented by the representative units. 88 FR 1722, 1759-1760.
^{114} Available at Docket No. EERE-2019-BT-STD-0018-0060.
Regarding the characteristics of the representative units, Carte commented that RU3 uses a 150 kV BIL when, based on its primary voltage of 14.4 kV, it should use a 95 kV BIL or 125 kV BIL. (Carte No. 140 at p. 9)
DOE notes that representative units are selected to represent both common designs found on the market and to include a variety of design specifications to enable generalization of results. In the case of RU3, DOE selected a more conservative BIL rating to assist in generalization of result. The resulting design would be slightly more costly than a 95 kV BIL or 125 kV BIL and therefore represents a more conservative design than the most common design.
Regarding any units that have different cost-efficiency curves, Carte commented that high-impedance transformers still within the normal impedance range can be more challenging to meet efficiency standards. (Carte, No. 140 at p. 10) Carte commented that certain high-BIL transformers can have higher costs in order to meet the current efficiency levels as compared to the modeled BIL values. (Carte, No. 140 at pp. 9-10) Carte also identified multi-voltage transformers, and main and teaser transformers as other designs that have a very high-cost to meet NOPR levels using GOES. (Carte, No. 140 at pp. 9-10) Carte commented that meeting NOPR levels with GOES for main and teaser transformers increases costs by over 100 percent. (Carte, No. 140 at p. 9) DOE notes that the data cited by Carte refer to meeting EL 4 without using amorphous and does not discuss the cost increase if those same transformers were designed using amorphous cores.
DOE agrees that certain distribution transformers with uncommon features may have a more difficult time meeting any given efficiency level. However, typically those uncommon features result in higher costs both at baseline and under amended efficiency standards. Therefore, the incremental costs of building that same transformer are similar.
In the January 2023 NOPR, DOE also noted that while some applications may generally have a harder time meeting a given efficiency standard, most applications would generally be able to use amorphous cores to achieve higher efficiency levels. This includes designs at efficiency levels beyond the max-tech efficiency included in DOE's analysis. 88 FR 1722, 1759.
Eaton provided data demonstrating relatively consistent incremental costs for a variety of multi-voltage distribution transformers. (Eaton, No. 137 at p. 16) Eaton's data showed the cost-efficiency curve for a 500-kVA distribution transformer with an amorphous core and a variety of different primary voltage configurations. Id. Eaton's data showed that, depending on the voltage configuration, the baseline cost of a given transformer could vary. Id. However, the incremental cost associated with meeting any given efficiency level is similar for all transformers up until that specific design reaches its “efficiency wall” wherein the costs begin to increase rapidly.
As discussed in the January 2023 NOPR, Eaton's data shows that all designs for this unit can meet max-tech efficiency levels using an amorphous core; however, certain designs may have a harder time meeting the max-tech level as evidence by the higher costs. Further, Eaton's data shows that all of these designs have a similar incremental cost to increase efficiency from a baseline design through the NOPR levels, indicating that DOE's analysis is likely sufficient to encompass all of these designs.
While Carte commented that the incremental costs associated with meeting higher efficiency values is significant for distribution transformers with a variety of characteristics, DOE notes that Carte generally was referring to meeting higher standards without transiting to amorphous cores. DOE data similarly shows that meeting NOPR efficiency levels without using amorphous cores results in a significant cost increase. However, if using an amorphous core, higher efficiency levels can be met without extreme cost increases.
Several stakeholders commented regarding potential challenges associated with transformers' ability to handle harmonics and the potential challenges units would have in meeting efficiency standards.
Carte commented that solar inverters can create harmonics and speculated that the modifications needed to accommodate these harmonics may increase losses or not be achievable with amorphous cores. (Carte, No. 140 at p. 3) Carte commented that IEEE is evaluating the impact of solar generation on power quality and transformer design. Id. Nichols commented that the smart grid will have increased harmonics and additional control switches will be needed to monitor harmonics in addition to the amount of power. (Nichols, No. 73 at p. 1) Eaton commented that EV charging is likely to increase the amount of harmonics currents on transformers. (Eaton, No. 137 at p. 38)
Harmonics lead to excess losses in both the transformer core and transformer coil. Distribution transformer efficiency is measured using a sinusoidal wave function ( i.e., a current without harmonics) and therefore the impact of harmonic currents is not captured in the DOE's test procedure. The primary concern with harmonic currents is that they lead to excess heat generation. This excess heat can lead a transformer to overheat, even if it is not loaded at its maximum capacity. In dealing with harmonic currents, consumers can purchase harmonic mitigating transformers, K-factor rated transformers, or intentionally oversize transformers such that they never operate near their thermal loads. Regarding harmonic mitigating transformers, DOE notes harmonic mitigating transformers involve phase-shifted windings, which would be an option both at baseline and higher-efficiency levels, including with amorphous cores.
Powersmiths commented that DOE did not consider K-factor rated transformers in its representative units, which have larger footprints and windings in order to deal with the thermal impacts of harmonic currents, and stated that K-factor rated transformers have a lower achievable efficiency. (Powersmiths, No. 112 at p. 2) Eaton expressed concern that the OPS software may not accurately model the additional requirements for data center transformers, such as higher k-factors, lower flux density, and adjusted temperature rise. To demonstrate this, Eaton provided data comparing the specifications of an OPS design without a K-factor rating to the specifications of manufactured data center transformers with various K-factor ratings. (Eaton, No. 137 at p. 37)
Regarding modeling a K-factor rated transformer as a representative unit, DOE notes that a transformer that has a K-factor rating is designed to accommodate the additional thermal stress of equipment harmonics. Rather than trying to cancel out harmonic currents, as harmonic mitigating transformers do, K-factor rated transformers are typically oversized and derated to accommodate the additional heat from harmonics. As such, they have larger transformer cores and, therefore, higher no-load losses. However, DOE notes that more efficient transformers may not ever meet the insulation temperature limits. In the case of amorphous dry-type transformers, Schneider commented regarding K-factor rated transformers that computer modeling suggests that the reduced losses of amorphous LVDT units would result in thermal characteristics that are well below the insulation material. (Schneider, No. 101 at pp. 5-6) Further, amorphous cores have lower no-load losses per pound of core material. Hence, transformer with additional core material, such as K-factor rated transformers, would experience a greater improvement in efficiency relative to a baseline transformer. For these reasons, DOE has not included a specific representative unit for K-factor rated transformers and assumes the current representative units are sufficiently representative.

b. Data Validation
There can be differences between distribution transformer modeling and real-world data. In order to ensure DOE's modeled data reflects reality, DOE has relied on a variety of manufacturer literature, manufacturer public utility bid data, and feedback from stakeholders. DOE presented plots demonstrating how real-world data compares with modeled data in chapter 5 of the NOPR TSD. ^{115}
^{115} Available at Docket No. EERE-2019-BT-STD-0018-0060.
Regarding data validation for LVDTs, Powersmiths commented that DOE should ensure models meeting the proposed LVDT efficiency standards have actually been built because gaps exist between transformer modeling and real-world performance. (Powersmiths, No. 112 at p. 2) Powersmiths stated that the OPS modeling software does not accurately model stray and eddy losses, which for certain high-kVA designs can increase significantly and requires comparison of modeling to real designs in order to create a feedback loop to ensure the modeled designs can actually be built. (Powersmith, No. 112 at pp. 3-4) Powersmiths particularly expressed concern that DOE NOPR levels for LVDTs are largely based on amorphous core transformers which include deviations between the real-world data and the modeled data. (Powersmiths, No. 112 at p. 2) Powersmiths recommended that DOE work with industry to build, test, and verify modelled designs. (Powersmiths, No. 112 at p. 6) Eaton commented that using modeling to reflect what is achievable is a valid approach; however, software modeling does not necessarily include the manufacturer-to-manufacturer variability that exists in the real world. (Eaton, No. 137 at p. 41) Hammond commented that their modeling confirms that amorphous cores would be used to meet the NOPR efficiency levels for LVDTs. (Hammond, No. 142 at p. 2)
For dry-type transformers, DOE notes that chapter 5 of the NOPR TSD presents plots comparing the range of no-load and load loss combinations modeled for each representative unit to real world no-load and load loss data certified in NRCAN's database. These plots show the modeled design space for GOES transformers very closely aligns with the real-world design space shown in NRCAN's database. DOE notes that Powersmiths did not identify any unique features associated with amorphous core LVDTs that would result in the modeling for GOES to be accurate while the modeling for amorphous transformers to not be accurate. DOE has included additional data points taken from manufacturer literature in chapter 5 of the final rule TSD to demonstrate the real-world designs of amorphous LVDT transformers. DOE notes that this real-world data shows that the modeled amorphous design space very closely aligns with the real-world loss performance of amorphous core LVDTs.
For liquid-immersed transformers, DOE has similarly presented a comparison of the no-load and load loss combinations modeled in each representative unit as compared to real world manufacturer data. These plots show the modeled design space for both amorphous and GOES transformers very closely aligns with the real-world design space shown in manufacturer bid sheets.
Regarding the accuracy of DOE equipment costs, HVOLT commented that DOE's optimization model understates selling prices by as much as 40-50 percent and suspected that this because some of DOE's designs were developed as part of the previous rulemaking. (HVOLT, No. 134 at p. 6)
DOE notes that the difference between current prices and modeled prices is related to the fact that DOE modeling uses a 5-year average pricing while current prices for a baseline transformer are higher than the 5-year average. DOE's modeled prices have historically been in-line with real-world data, indicating that the physical construction of the transformers is accurate.
Current distribution transformer pricing is near its all-time high due to shortages. However, because most of the market relies on GOES, the price of GOES steel has increased more than the price of amorphous alloy. If DOE relied on current spot prices, as HVOLT suggests, the cost of the baseline transformer would increase considerably and be more in-line with the 40-50 percent increase cited by HVOLT. However, higher efficiency levels, particularly those with amorphous cores, would become far more cost competitive because amorphous alloy has not had the same demand pressure as GOES steel in recent years. DOE has updated prices for the final rule, as described in section IV.C.2 of this document, to reflect updated 5-year average prices.
Eaton submitted independently developed cost-efficiency and max-tech performance curves. Eaton provided a cost-efficiency curve for both amorphous and GOES transformers of similar kVA sizes as DOE's RU5 unit. (Eaton, No. at p. 19) DOE has provided a comparison between Eaton's data and DOE's modeled data in chapter 5 of the TSD. In general, the two are very closely aligned.
Eaton stated that its modeling showed some discrepancies between some of the max-tech efficiencies modeled by DOE and its max-tech efficiencies resulting from scaling representative units to high-kVA units. Eaton recommended DOE work with manufacturers to compare its modeling to real world max-tech values, particularly for omitted kVA ratings in the analysis. (Eaton, No. 137 at p. 20) DOE appreciates Eaton's work to validate its modeling and has relied on Eaton's modeling, in addition to other data sources, to modify DOE's scaling methodology for high-kVA units, as detailed in section IV.C.1.e of this document.

c. Baseline Energy Use
For each product/equipment class, DOE generally selects a baseline model as a reference point for each class, and measures anticipated changes resulting from potential energy conservation standards against the baseline model. The baseline model in each product/equipment class represents the characteristics of a product/equipment typical of that class ( e.g., capacity, physical size). Generally, a baseline model is one that just meets current energy conservation standards, or, if no standards are in place, the baseline is typically the most common or least efficient unit on the market.
DOE's analysis for distribution transformers generally relies on a baseline approach. However, instead of selecting a single unit for each efficiency level, DOE selects a set of units to reflect that different distribution transformer purchasers may not choose distribution transformers with identical characteristics because of difference in applications and manufacturer practices. The mechanics of the customer choice model at baseline and higher efficiency level are discussed in section IV.F.3 of this document.

d. Higher Efficiency Levels
Regarding evaluating higher efficiency standards, numerous stakeholders commented that transformers are already efficient and stated that because efficiency is only increased by less than one percentage point, amended standards aren't worth the burdens that they would impose on manufacturers and the supply chains. (NMHC & NAA, No. 97 at p. 4; TVPPA, No. 144 at p. 1; APPA, No. 103 at p. 7; Pugh Consulting, No. 117 at p. 2; Alabama Senator, No. 113 at p. 2; Webb, No. 133 at p. 2; CARES, No. 99 at pp. 2-3; AISI, No. 115 at p. 1; Strauch, No. 74 at p. 1; VA, MD, and DE Members of Congress, No. 148 at p. 2; New York Members of Congress, No. 153 at p. 2; EEI, No. 135 at pp. 44-47)
REC commented that, while amorphous cores provide a significant percentage reduction in losses, the increase in rated efficiency is small. (REC, No. 126 at p. 3)
CEC commented that distribution transformers are ubiquitous, and even small improvements to standards can have significant benefits to energy generators and distributors, manufacturers, consumers, and the environment. (CEC, No. 124 at p. 1)
Stakeholders are correct in their assessment that currently available distribution transformers are typically over 98 percent efficient. However, nearly all electricity passes through at least one distribution transformer and distribution transformers experience those losses 24 hours a day, 365 days per year, across a usable life that spans decades. Therefore, the losses from any single transformer, even if small in a particular instance, can be substantial in the aggregate and make up a considerable portion of a given transformer's total ownership costs.
Further, the efficiency levels proposed in the January 2023 NOPR represent a 2.5 to 50 percent reduction in transformer losses. DOE conducts its analysis to determine if the benefits of these operating cost and energy savings are economically justified. Hence, even though the change in efficiency appears to be a small number, the benefits of the evaluated efficiency standards may be substantial compared to existing performance, as reflected in DOE's analysis.
In evaluating higher efficiency levels, DOE relies on a similar approach to its baseline engineering analysis. DOE's modeled designs span the entire design space. In evaluating a higher efficiency level up until the max-tech that DOE considers, DOE evaluates the modeled units that would exceed the higher efficiency level. Then, rather than selecting a single unit, DOE applies a customer choice model to evaluate the distribution transformer that would be purchased if standards were amended.
DOE notes that for a given design option combination, the least efficient units typically tend to be the lowest cost unit.
Eaton commented that when meeting higher efficiency levels with GOES, manufacturers increase the core cross sectional area and decrease the flux density. (Eaton, No. 137 at pp. 21-22) The larger transformer cores require thicker conductors in order to maintain current density but using thicker conductors increases stray and eddy losses, which requires even larger conductor size to combat the additional stray and eddy losses. (Eaton, No. 137 at pp. 21-22) Eaton stated that at some point, the only option is to transition to copper windings, at which point the cost of the transformer skyrockets and significant cost increases are needed for even modest efficiency gains. (Eaton, No. 137 at pp. 21-22)
HVOLT commented that DOE proposed levels result in several products that will hit an efficiency wall where significant cost increases would result in very little efficiency improvement. (HVOLT, No. 134 at p. 2) HVOLT did not specify which products or clarify if that comment was across all core materials or only GOES.
Prolec GE commented that in their modeling, they found it was technically feasible to meet proposed standards with GOES cores and copper windings, but they would be at a cost disadvantage relative to amorphous cores that could use aluminum windings to meet efficiency standards. (Prolec GE, No. 120 at p. 8)
Powersmiths commented that the proposed standards for LVDTs are at max-tech, which does not leave sufficient margin for manufacturing and material batch variability. (Powersmiths, No. 112 at p. 2)
WEG commented that it is possible to reduce transformer losses to get halfway to the NOPR standards using a GOES core and copper windings, but the cost of the transformer would increase by 60 percent. (WEG, No. 92 at p. 1) NEMA commented that meeting the proposed LVDT efficiency standards with GOES would result in large weight increases and be impractical. (NEMA, No. 141 at p. 6)
Stakeholder comment is consistent with DOE modeling that it is technically feasible to meet many higher efficiency levels with GOES. However, beyond some efficiency levels it is no longer the lowest cost option. In evaluating higher efficiency levels, beyond a certain reduction in losses, transitioning from a GOES steel core to an amorphous core becomes by far the most cost effective approach for meeting higher-efficiency standards due to the significant reduction in no-load losses associated with an amorphous core.
As noted, the DOE test procedure specifies measuring efficiency at 50 percent PUL for liquid-immersed and MVDT distribution transformers and 35 percent PUL for LVDT distribution transformers. Distribution transformer performance at any given PUL can be approximated as no-load losses plus load losses multiplied by the square of the PUL. In meeting higher efficiency standards, manufacturers can employ design options that reduce no-load losses, reduce load losses, or a combination of the two. DOE models different design options that reduce both no-load losses and load losses and generally relies on manufacturer selling prices to determine what consumers are likely to purchase.
REC stated that if DOE measured energy efficiency at 100 percent PUL, the losses of an amorphous transformer could be higher than the losses of a GOES transformer. (REC, No. 126 at pp. 2-3) Idaho Power commented that it prefers technologies that reduce load losses rather than those that improve no-load losses. (Idaho Power, No. 139 at p. 2) Cliffs stated that when load levels are at 50 percent or higher, GOES transformers outperform amorphous transformers and provided plots to demonstrate this. (Cliffs, No. 105 at pp. 16-17) HVOLT recommended that DOE not implement any standards that exclude GOES given that amorphous cores hit peak efficiency at 20 percent loading and are less efficient than GOES above 50 percent loading. (HVOLT, No. 134 at p. 5) Cliffs further commented that AM transformers will not be able to sustain grid loading requirements, jeopardizing Department of Defense applications which rely upon resilient grid systems to supply backup power generation for mission requirements. (Cliffs, No. 105 at pp. 8-9)
NEPPA commented that amorphous cores may have slightly lower no-load losses than GOES cores, but they typically have higher load losses. NEPPA added that as loading levels increase due to electrification, amorphous core use does not guarantee overall lower losses when transformer loading increases over time. (NEPPA, No. 129 at p. 2) Idaho Power further recommended DOE evaluate transformer efficiency designs at higher load-losses (above 50 percent) instead of targeting increased efficiencies in no-load losses, given expected increases in loading with electrification. (Idaho Power, No. 139 at pp. 2-3) CARES and AISI commented that amorphous transformers are less efficient at higher loads and therefore the benefits of the NOPR are limited. (CARES, No. 99 at p. 4; AISI, No. 115 at p. 3) MTC commented that both low-loss GOES and amorphous core transformers provide similar energy savings at higher load factors. MTC provided data for both GOES and amorphous designs compliant with the European ECO-1 and ECO-2 efficiency standards to demonstrate this point. (MTC, No. 119 at pp. 13-15) MTC added that higher losses above 50 percent loading is not ubiquitous for amorphous transformers and is driven by DOE's testing requirement at 50 percent load. (MTC, No. 119 at p. 15)
DOE notes that its analysis considers technologies that reduce both no-load losses and load losses. As discussed, both amorphous core transformers and GOES core transformers have no-load and load losses wherein the no-load losses are approximately constant and the load losses vary with loading. DOE evaluates efficiency at 50 percent loading for liquid-immersed and MVDT distribution transformers and 35 percent for LVDT distribution transformers. DOE models any potential energy savings by evaluating the actual loading on transformers and accounts for both no-load and load losses as discussed in section IV.E of this document.
Cliffs and Carte stated that increasing demand on the electric grid will result in distribution transformers frequently operating beyond 50 percent load, which means that GOES transformers will have higher efficiency in the field. (Cliffs, No. 105 at pp. 16-17; Carte, No. 140 at p. 6) WEG commented that amorphous cores have their peak efficiency at lower loads and as loading increases as a result of electrification, a GOES design will be better optimized for higher loading. (WEG, No. 92 at p. 3) WEC and Xcel Energy commented that new load growth, such as the load growth associated with adding electric vehicles, will lead to load losses becoming more important and no-load losses becoming less important. (WEC, No. 118 at p. 1; Xcel Energy, No. 127 at p. 1) Webb commented that DOE should confirm amorphous transformers are efficient across a broad range of equipment loadings. (Webb, No. 133 at p. 2) NEMA commented that certain LVDTs could operate less efficiently if average load exceeds 35 percent. (NEMA, No. 141 at p. 6) Hammond commented that future electrification may result in many LVDT loaded above 35 percent and that puts greater emphasis on load losses, which favors GOES over amorphous. (Hammond, No. 142 at p. 2) Efficiency Advocates commented and provided data to show that, even under heavy load growth which would results in near 100 percent average load by 2058, DOE's proposed standards would still provide energy savings. (Efficiency Advocates, No. 121 at pp. 5-6)
Regarding the plots cited by Cliffs to support the claim that GOES transformers outperform amorphous transformers beyond 50 percent loading, DOE notes that Cliffs is making a comparison between a GOES and amorphous transformers that are equally efficient at 50 percent load. In evaluating higher efficiency standards, DOE makes a comparison between the baseline transformer (one purchased under current standards) and the transformer that would be purchased under amended efficiency standards. The plots cited by Cliffs show that both the GOES and amorphous designs at the proposed standards would outperform a baseline GOES design up to and beyond 100 percent loading. However, DOE notes that the GOES designs are expected to a require a significantly higher increase in both cost and weight, making them less favorable when compared to a current baseline design. ^{116}
^{116} See attachment 2 of comment submitted by HVOLT for underlying data (HVOLT, No. 134).
Eaton commented that the efficiency of an amorphous transformer can be improved at little cost by using larger conductors up until the size limits for aluminum conductors, at which point it becomes very expensive to reduce losses further. (Eaton, No. 137 at p. 22) Eaton commented that it is a misconception that amorphous units are less efficient than GOES transformers above 50 percent PUL. (Eaton, No. 137 at p. 32) Eaton provided similar plots to Cliffs and noted that amorphous transformers that were designed to meet the current DOE 2016 efficiency levels required very little investment in the transformer windings due to their very low no-load losses. Id. As such, the amorphous core transformer is the lowest weight product but also has an efficiency curve that decreases considerably as loading increases. Id.
Eaton further commented that amorphous transformers designed to meet the proposed levels in the January 2023 NOPR include a modest investment in the transformer winding such that the efficiency of an amorphous design is greater than the baseline GOES design across all loading points. (Eaton, No. 137 at p. 32) Eaton stated that the incremental weight of the more efficient transformer is only 5.4 percent relative to the base amorphous design and ~1 percent relative to the base GOES design. Id. Eaton noted that while a GOES design can still meet the January 2023 NOPR levels and that GOES transformer would have a higher efficiency beyond 50 percent load than the amorphous transformer, considerably more material is needed, leading to a 50 percent weight increase. Id.
Eaton provided an additional design point to represent an amorphous design with additional investment windings, which reduces the load losses such that the amorphous design is more efficient across all loading points than even the GOES design that meets the January 2023 NOPR levels. Id. Eaton noted that this amorphous transformer can be built with an “extremely modest weight increase of 14.5 percent” relative to the baseline amorphous transformer. Id.
The data provided by Eaton further confirms that amorphous transformers can be designed to maintain high efficiency across the entire range of transformer loading. While a baseline GOES transformer may exhibit higher efficiency than a baseline amorphous transformer at higher loading, both DOE's modeling and stakeholder comment indicate that either an amorphous or a GOES transformer designed to meet amended efficiency standards would outperform a baseline transformer at all loading points. As such, DOE maintains that amorphous transformers stand to provide significant energy savings, even if average transformer loading were to increase.
Southwest Electric commented that they used current design data to model a baseline transformer and transformers that met the NOPR efficiency levels for 3-phase pad-mount transformers ranging from 112.5 kVA to 3750 kVA. (Southwest Electric, No. 87 at p. 2) Southwest Electric stated that in their case, all of the baseline transformer designs would use amorphous cores. (Southwest Electric, No. 87 at p. 2) Southwest Electric stated that based on their data, simply switching to an amorphous core would not be sufficient to meet the NOPR efficiency standards and additional investment would be needed in the conductor in order to meet the NOPR proposed levels. (Southwest Electric, No. 87 at p. 2)
DOE notes that manufacturer data from both Southwest Electric and Eaton suggest that for at least some 3-phase, liquid-immersed units, their design software suggest that the lowest cost design to meet baseline efficiency standards is using an amorphous core transformer. Despite this lower first cost, stakeholders have regularly stated that amorphous cores make up a very small percentage of the current distribution transformer market. DOE models amorphous core transformers across a range of efficiencies. Due to the substantial reduction in no-load losses associated with amorphous cores, a baseline transformer with an amorphous core can meet DOE 2016 efficiency standards with very little investment into the transformer windings. In evaluating higher efficiency models with amorphous cores, DOE designs include additional investment in the transformer windings which reduce load losses. DOE incorporates both the additional costs in the transformer core and the investment in the transformer windings in its analysis.
Schneider commented that lower losses correspond to lower impedance, which will increase the let-through current during short circuits. Schneider stated that this will increase the required ratings for connected equipment and impact system arc flash studies and protection for workers. Schneider further commented that impedance limits the impact of harmonics, which protects sensitive electronic loads. Schneider added that lower impedance will reduce voltage drop internal to LVDT devices. (Schneider, No. 101 at p. 14) APPA commented that while within the “normal” impedance ranges, amorphous transformers tend to have lower impedance which increases likelihood of an extremely high fault current. (APPA, No. 103 at p. 13) NEMA commented that higher efficiency standards met with GOES results in low impedance levels and anything below 4 percent or preferably 5 percent makes it difficult to design power systems and choose circuit breakers or fuses to handle fault currents. (NEMA, No. 141 at p. 6)
Metglas commented that impedance is fixed at 5.75 percent for units above 500 kVA and easily varied for smaller units. (Metglas, No. 125 at p. 5)
In the January 2023 NOPR, DOE discussed that the design options considered in the engineering analysis, including those that utilize amorphous metal, span a range of impedance values within the “normal impedance” range, as currently defined. 88 FR 1722, 1743. The design options considered in this final rule continue to span a range of impedance values at higher efficiency levels, both for designs that utilize GOES and those that utilize amorphous metal. Further, DOE notes that, while lower-loss transformer designs often have lower impedances, higher efficiency does not necessarily correlate to lower impedance.
Based on a review of manufacturer literature, DOE found that manufacturers often provide a range of impedance values for a given design, with customers able to request a specific impedance range to fit their application. DOE also observed transformers of varying levels of efficiency that provide the same impedance offerings. 117 118 119 This indicates that options exist to increase transformer impedance, even for higher efficiency transformers. Therefore, in this final rule, DOE did not further separate transformers based on impedance, aside from ensuring that a range of normal impedance values are available at higher efficiency levels.
^{117} Powersmiths, E-Saver Opal Series, Available at: https://www.powersmiths.com/products/transformers/e-saver-opal-series/ (accessed on 3/17/2024).
^{118} Eaton, General Purpose Ventilated Transformers, Available at: https://www.eaton.com/us/en-us/catalog/low-voltage-power-distribution-controls-systems/ventilated-general-purpose-transformers.html (accessed on 3/17/2024).
^{119} Hammond Power Solutions, HPS Sentinel Energy Efficient Distribution Transformers, Available at: https://americas.hammondpowersolutions.com/products/low-voltage-distribution/general-purpose-transformers (accessed on 3/17/2024).

e. kVA Scaling
In the January 2023 NOPR, DOE proposed to expand the scope of the distribution transformer definition to include units up to 5,000 kVA. 88 FR 1722, 1746 To assess the impact and potential energy savings associated with the expanded scope, DOE modeled three new representative units by using the scaling rules for transformer dimensions, weight, no-load losses, and load losses. 88 FR 1722, 1759-1760. DOE noted that it only includes distribution transformers in its downstream analysis if they would meet or exceed current energy conservation standards. Because transformers greater than 2,500 kVA have not historically been subject to energy conservation standards, DOE relied on the consumer choice model to determine the efficiency of a typical baseline unit that would be selected in the present market based on lowest first-cost. DOE did not consider any units which did not meet or exceed the efficiency of this assumed baseline unit. Id. DOE requested comment on its approach to modeling these high-kVA transformers.
DOE received numerous comments about scaling of design data for units beyond 2,500 kVA.
Several stakeholders noted that the percentage that stray and eddy losses contribute to load losses increases substantially at high-current values, which typically correspond to high-kVA ratings. Therefore, the 0.75 loss scaling cited by DOE does not hold when scaling to larger kVA ratings. (Eaton, No. 137 at p. 23; Prolec GE, No. 120 at pp. 7-9; HVOLT, No. 134 at pp. 6-7; Howard, No. 116 at p. 14; NEMA, No. 141 at p. 5; NEMA, No. 141 at p. 14; Powersmiths, No. 112 at p. 3)
Prolec GE commented that several of the high-kVA rated designs would be forced to use amorphous under the proposed standards because manufacturers would not be able to meet the proposed efficiency levels even with GOES and copper windings. (Prolec GE, No. 120 at p. 3) NEMA commented that for high-current transformers, it would be impractical to meet the NOPR efficiency levels with GOES as the flux density would be forced to such low values to make up for the increased buss and load losses. (NEMA, No. 141 at pp. 5-6)
Howard commented that designing transformers to meet the NOPR efficiency levels is technically feasible for transformers 2,500 kVA and less. However, the proposed standards beyond 2,500 kVA are not feasible and therefore DOE should not include them in any amended efficiency standards. (Howard, No. 116 at p. 5) Howard and HVOLT stated that they have not been able to develop any valid designs, even with amorphous cores, that meet the proposed standards at 3,750 kVA or 5,000 kVA. (Howard, No. 116 at p. 14; HVOLT, No. 134 at p. 7)
Eaton speculated that OPS modeling uses a constant stray loss percentage, which could significantly underestimate the percentage of load losses made up by stray losses for large kVA values. (Eaton, No. 137 at pp. 23-25) DOE notes that stray losses vary based on the design specifications of each specific unit modelled using the OPS design software and are not applied as a constant percentage of load losses.
Eaton noted that improper scaling of stray losses in DOE's analysis may result in an overestimation of the efficiencies that can be achieved and an underestimation of the transformer costs. (Eaton, No. 137 at p. 25) NEMA commented that for large kVA, high-current designs, stray and eddy losses can make up nearly 80 percent of the total load losses. (NEMA, No. 141 at pp. 13-14) HVOLT stated that stray and eddy losses can increase the load losses of a transformer over 3,000 kVA by as much as 50 percent. (HVOLT, No. 134 at p. 6)
Eaton commented and provided data to show that as conductor sizes increase to meet higher efficiency standards, stray losses increase as a percentage of total load losses. (Eaton, No. 137 at p. 23) Eaton's data shows that a baseline transformer has stray and eddy losses which make up about 15 percent of total load losses, whereas at max-tech, stray and eddy losses make-up 30 percent of load losses. (Eaton, No. 137 at p. 23)
Howard stated that the scaling DOE used to estimate the performance of 3,750 kVA units is not accurate due to the unique challenges associated with the high-current densities in these units. (Howard, No. 116 at p. 15) HVOLT commented that the 0.75 scaling relationship is only accurate over a narrow band of parameters and noted that scaling to high kVA ratings could result in underestimating winding losses by more than 50 percent. (HVOLT, No. 134 at p. 6) Howard recommended DOE refer to Annex G of IEEE C57.110-2018 to review industry data on stray and eddy losses and their relationship with kVA. (Howard, No. 116 at p. 16)
Eaton referenced DOE's compliance certification management system (CCMS) database and noted that the maximum reported percentage efficiencies do not increase beyond 1,000 kVA. Eaton stated this was evidence that the 0.75 scaling relationship does not hold for higher kVA values. (Eaton, No. 137 at pp. 27-28) Eaton noted that in evaluating the max-tech in their design software, some of the proposed standards for high-kVA transformers were near the technological limit, indicating a potential flaw in the 0.75 scaling relationship. (Eaton, No. 137 at p. 22)
Regarding scaling generally, NEMA commented that the 0.75 scaling relationship is only applicable across narrow kVA ranges. (NEMA, No. 141 at p. 4) NEMA commented that one of their members looked at their design data for MVDT transformers to investigate how accurate scaling transformer costs, no-load losses, and load losses from a 1,500 kVA and 300 kVA transformer were. (NEMA, No. 141 at p. 4) NEMA's member found that the actual scaling factor can vary widely and at times can be much more or much less than the DOE scaling factors. (NEMA, No. 141 at p. 4) NEMA stated that this variability was a result of constraints on wire sizes, impedance ranges, and construction requirements which can result in considerably different scaling relationships. (NEMA, No. 141 at p. 5) NEMA identified the small wire sizes associated with small kVA transformers as a very expensive component that skews the cost curve for small kVA units. (NEMA, No. 141 at p. 5) NEMA commented that the NOPR scaling factors only results in costs and losses that are within 5 percent across a small range of kVA values and not across the entire range of kVA values. (NEMA, No. 141 at p. 4)
Eaton provided data demonstrating how the max-tech in their design software varies based on secondary winding voltage and kVA. (Eaton, No. 137 at p. 18) Eaton's data shows that max-tech efficiency percentages tend to increase as the kVA increase up until a certain point. (Eaton, No. 137 at p. 18) Beyond that point, the current, and specifically the additional stray and eddy losses associated with the higher currents, can make a considerable difference as to the max-tech at a given kVA. (Eaton, No. 137 at p. 18) Eaton's data shows that for a 480Y/277 secondary voltage, the maximum efficiency occurs around 1,500 kVA. (Eaton, No. 137 at p. 18)
Based on the comments received, DOE re-evaluated the accuracy of the OPS modeling of stray and eddy losses for the 1,500 kVA units and how that modeling varies for high-current transformers. For DOE's modeled RU5, corresponding to a 1,500 kVA distribution transformer with 480Y/277 secondary, OPS modeling indicates that stray and eddy losses as a percentage of total load losses typically vary with design and with efficiency. While the exact percentage varies depending on the unique design specifications ( e.g., efficiency, whether copper or aluminum windings are used, core steel, etc. ) the stray and eddy losses for most designs make up between 10-20 percent of total load losses. These values align well with the percentage of stray losses submitted in Eaton's comment for a similar unit and many of the stray and eddy values listed in Annex G of IEEE C57.110-2018. Therefore, DOE has concluded that the OPS modeling accurately accounts for stray and eddy losses.
Regarding the scaling of these OPS modeled representative units to other kVA ratings that are not individually modeled, DOE notes that scaling of units using power laws requires a variety of assumptions to remain valid. In chapter 5 of the TSD, DOE notes that these scaling relationships are valid if the core configuration, core material, core flux density, current density, physical proportions, eddy loss proportion, and insulation space factor are all held constant. DOE notes that in practical applications, it is rare that all of these are constant; however, scaling relationships can be used to establish reasonable estimates of performance.
Real world data can vary depending on what variables are changing between transformer designs. The data submitted by NEMA suggests that material cost scaling can be as low as 0.14 or as high as 1.13, no-load loss scaling can be as low as 0.33 or as high as 0.88, and load loss scaling can be as low as 0.51 or as high as 1.02. IEEE C57.110-2018 shows real world load loss scaling data with transformer kVA for solid cast transformers from 630 kVA to 20 MVA. These data show load loss scaling of 0.76. Data submitted by Eaton show that DOE's max-tech efficiency for 3-phase liquid-immersed distribution transformers are within a few tenths of a percentage point for the vast majority of kVA ratings, but the accuracy can vary depending on the current in the transformer.
All of the data identified by manufacturers indicate that for the vast majority of the kVA ranges, the scaling laws used in the NOPR are sufficient to provide reasonable estimates of performance, dimensions, costs, and losses. Stakeholder data also indicate that when the stray and eddy losses increase substantially, those scaling relationships may be less accurate.
However, stakeholders are correct in pointing out that for very high currents, stray and eddy losses may increase substantially such that it becomes much more difficult to meet efficiency standards. As noted in section IV.A.2.c of this document, industry standards recommend high-kVA transformers have higher-secondary voltages. As such, currents do not tend to reach problematic values. Beyond 1,500 kVA, there tend to be considerably more 480Y/277 secondary voltages and 208Y/120 voltages become relatively rare. However, if a manufacturer were to build a transformer with a very high-secondary current, the stray and eddy losses would make up a much greater percentage of the transformer load losses and, as such, the losses would scale at a higher factor. This was pointed out by numerous manufacturers who stated that DOE's proposed standards at 3,750 kVA may become technologically impossible.
To account for the change in scaling relationships that occur for high kVA transformers with high currents, DOE has established and evaluated a separate equipment class for large three-phase transformers with kVA ratings greater than or equal to 500 kVA, as discussed in section IV.A.2.c of this document. DOE has also revised its high-kVA scaled representative units to account for the increase in load losses that occurs as a result of growing stray and eddy losses. These scaling factors are discussed in chapter 5 of the TSD.

2. Cost Analysis
The cost analysis portion of the engineering analysis is conducted using one or a combination of cost approaches. The selection of cost approach depends on a suite of factors, including the availability and reliability of public information, characteristics of the regulated product, and the availability and timeliness of purchasing the equipment on the market. The cost approaches are summarized as follows:
• Physical teardowns: Under this approach, DOE physically dismantles a commercially available product, component-by-component, to develop a detailed bill of materials for the product.
• Catalog teardowns: In lieu of physically deconstructing a product, DOE identifies each component using parts diagrams (available from manufacturer websites or appliance repair websites, for example) to develop the bill of materials for the product.
• Price surveys: If neither a physical nor catalog teardown is feasible ( e.g., for tightly integrated products such as fluorescent lamps, which are infeasible to disassemble and for which parts diagrams are unavailable), cost-prohibitive, or otherwise impractical ( e.g. large commercial boilers), DOE conducts price surveys using publicly available pricing data published on major online retailer websites and/or by soliciting prices from distributors and other commercial channels.
In the present case, DOE conducted the analysis by applying material prices to the distribution transformer designs modeled by OPS. The resulting bill of materials provides the basis for the manufacturer production cost (MPC) estimates for products at various efficiency levels spanning the full range of efficiencies from the baseline to max-tech. Markups are applied these MPCs to generate manufacturer selling prices (MSP). The primary material costs in distribution transformers come from electrical steel used for the core and the aluminum or copper conductor used for the primary and secondary winding. In the January 2023 NOPR, DOE noted that while prices have been up in recent years, it is difficult to say for certain how prices will vary in the medium to long term and, therefore, DOE relies on a 5-year average in its base scenario and evaluates how the results would change with different pricing scenarios. 88 FR 1722, 1765.
Regarding the cost analysis generally, WEC commented that based on information received from manufacturers, the costs used to support the NOPR are out of date and do not reflect current costs. (WEC, No. 118 at p. 1) APPA commented that DOE did not consider the recent rapid increases in transformer costs; APPA provided data indicating that the cost of transformers has increased substantially since 2018. (APPA, No. 103 at p. 7-8)
DOE data confirm that prices for distribution transformers have been up significantly from their historical averages. However, it is difficult to say for certain how those prices will vary in the medium to long term. The distribution transformer producer price index was approximately constant between 2010 and 2020, a time period that included implementation of two sets of energy efficiency standards (initial standards went into effect in 2010 and amended standards went into effect in 2016). Beginning in 2021, the producer price index of distribution transformers began to increase substantially through mid-2022. Since mid-2022, prices have remained approximately constant.
As discussed in section IV.A.5 of this document, the current distribution transformer shortage is largely driven by a supply-demand imbalance that exists across both distribution transformers and many electric and grid-related products. Considerable manufacturer investments in capacity increases have been publicly announced, including new locations which serve to expand accessible local labor markets. However, it is difficult to predict with certainty how the price of distribution transformers will vary when supply rises sufficiently to expected demand. DOE continues to rely on a 5-year average in its analysis. ^{120} The five-year period preceding this rulemaking includes price increases in addition to those accounted for in the NOPR. Accordingly, material and transformer prices are generally higher in this final rule than in the NOPR. Additional comments on specific material prices are discussed in the sections that follow.
^{120} Engineering results with current pricing are included in Appendix 5B of the TSD.

a. Electrical Steel Prices
Electrical steel is one of the main material costs in distribution transformers and as such makes up a significant percentage of manufacturer production costs. Using lower-loss core materials is one of the primary tools for improving the energy efficiency of distribution transformers. As such, the relative costs associated with transitioning from the current baseline core materials to lower-loss core materials has a considerable impact on the cost effectiveness of amended efficiency standards.
In the January 2023 NOPR, DOE relied on 5-year average pricing for the various grades of electrical steel evaluated. 88 FR 1722, 1765-1767. In response to stakeholder comments submitted on the August 2021 Preliminary Analysis TSD that amended standards may introduce higher volatility that may make 5-year average prices inaccurate, DOE stated that historically, when amended standards have been adopted, core material manufacturers have increased capacity of the electrical steel grades needed to meet amended efficiency standards. Id.
DOE stated that substantial volatility has characterized the U.S. steel market, including the existing transformer core steel market, over the last several decades. From 2000 to 2007, U.S. steel markets, and more specifically the U.S. electrical steel market, began to experience pressure from several directions. Demand in China and India for high-efficiency, grain-oriented core steel contributed to increased prices and reduced global availability. Cost-cutting measures and technical innovation at their respective facilities, combined with the lower value of the U.S. dollar, enabled domestic core steel suppliers to become globally competitive exporters.
In late 2007, the U.S. steel market began to decline with the onset of the global economic crisis. U.S. steel manufacturing declined to nearly 50 percent of production capacity utilization in 2009 from almost 90 percent in 2008. Only in China and India did the production and use of electrical grade steel increase for 2009. ^{121} In 2010, the price of steel began to recover. However, the recovery was driven more by increasing costs of material inputs, such as iron ore and coking coal, than broad demand recovery.
^{121} International Trade Administration. Global Steel Report. Available at legacy.trade.gov/steel/pdfs/global-monitor-report-2018.pdf (last accessed Sept. 1, 2022).
In 2011, core steel prices again fell considerably. At this time, China began to transition from a net electrical steel importer to a net electrical steel exporter. ^{122} Between 2005 and 2011, China imported an estimated 253,000 to 353,000 tonnes of electrical steel. During this time, China added significant domestic electrical steel production capacity, such that from 2016 to 2019 only about 22,000 tonnes were imported to China annually. China also exported nearly 200,000 tonnes of electric steel annually by the late 2010s.
^{122} Capital Trade Incorporated, Effective Trade Relief on Transformer Cores and Laminations, 2020. Submitted as part of AK Steel comment at Docket No. BIS-2020-0015-0075 at p. 168.
Many of the exporters formerly serving China sought new markets around 2011, namely the United States. The rise in U.S. imports at this time hurt domestic U.S. steel manufacturers, such that in 2013, domestic U.S. steel stakeholders filed anti-dumping and countervailing duty petitions with the U.S. International Trade Commission. ^{123} The resulting investigation found, however, that “industry in the United States is neither materially injured nor threatened with material injury by reason of imports of grain-oriented electrical steel . . . to be sold in the United States at less than fair value.” ^{124}
^{123} U.S. International Trade Commission, Grain-Oriented Electrical Steel from Germany, Japan, and Poland, Investigation Nos. 731-TA-1233, 1234, and 1236. September 2014.
^{124} Id.
In the amorphous ribbon market, the necessary manufacturing technology has existed for many decades and has been used in distribution transformers since the late 1980s. ^{125} In many countries, amorphous ribbon is widely used in the cores of distribution transformers. ^{126} Significant amorphous ribbon use tends to occur in regions with relatively high valuations on losses ( e.g., certain provinces of Canada, certain U.S. municipalities).
^{125} DeCristofaro, N., Amorphous Metals in Electric-Power Distribution Applications, Material Research Society, MRS Bulletin, Volume 23, Number 5, 1998.
^{126} BPA's Emerging Technologies Initiative, Phase 1 report: High Efficiency Distribution Transformer Technology Assessment, April 2020. Available at www.bpa.gov/EE/NewsEvents/presentations/Documents/Transformer%20webinar%204-7-20%20Final.pdf.
Beginning in 2018, the U.S. government instituted a series of import duties on aluminum and steel articles, among other items. Steel and aluminum articles were generally subject to respective import duties of 25 and 10 percent ad valorem. 127 83 FR 11619; 83 FR 11625. Since March 2018, several presidential proclamations have created or modified steel and aluminum tariffs, including changes to the products covered, countries subject to the tariffs, exclusions, etc. ^{128}
^{127} Ad valorem tariffs are assessed in proportion to an item's monetary value.
^{128} Congressional Research Service, Section 232 Investigations: Overview and Issues for Congress, May 18, 2021, Available at fas.org/sgp/crs/misc/R45249.pdf.
Another recent trend in distribution transformer manufacturing is an increase in the rate of import or purchase of finished core products. The impact of electrical steel tariffs on manufacturers' costs varies widely depending on if manufacturers are purchasing raw electrical steel and paying a 25-percent tariff on imported steel, or if they are importing finished transformer cores which, along with distribution transformer core laminations and finished transformer imports, are not subject to the tariffs. Some stakeholders have argued that this trend toward importing distribution transformer cores, primarily from Mexico and Canada, is a method of circumventing tariffs, as electrical steel sold in the global market has been less expensive than domestic electrical steel on account of being allegedly unfairly traded. 129 130 Conversely, other stakeholders have commented that this trend predated the electrical steel tariffs and that importation of transformer components is often necessary to remain competitive in the U.S. market, given the limited number of domestic manufacturers that produce transformer laminations and cores. 131 132
^{129} (AK Steel, Docket No. BIS-2020-0015-0075 at pp. 43-58).
^{130} (American Iron and Steel Institute, Docket No. BIS-2020-0015-0033 at pp. 2-5).
^{131} (Central Maloney Inc., Docket No. BIS-2020-0015-0015 at p. 1).
^{132} (NEMA, Docket No. BIS-2020-0015-0034 at pp. 3-4).
On May 19, 2020, the U.S. Department of Commerce (DOC) opened an investigation into the potential circumvention of tariffs via imports of finished distribution transformer cores and laminations. 85 FR 29926. On November 18, 2021, DOC published a summary of the results of their investigation in a notice to the Federal Register . The report stated that importation of both GOES laminations and finished wound and stacked cores has significantly increased in recent years, with importation of laminations increasing from $15 million in 2015 to $33 million in 2019, and importation of finished cores increasing from $22 million in 2015 to $167 million in 2019. DOC attributed these increases, at least in part, to the increased electrical steel costs resulting from the imposed tariffs on electrical steel. In response to its investigation, DOC stated it is exploring several options to shift the market toward domestic production and consumption of GOES, including extending tariffs to include laminations and finished cores. No trade action has been taken at the time of publication of this final rule. 86 FR 64606.
More recently, DOE learned from stakeholders during manufacturer interviews and from public comments that pricing of electrical steel has risen such that in the current market, the price of foreign electrical steel, without any tariffs applied, is similar to the price of domestic steel. (Powersmiths, No. 46 at p. 6; Carte, No. 54 at p. 3) These recent price increases, particularly in foreign-produced electrical steel, were cited as being a result of both general supply chain complications and increased demand for non-oriented electrical steel from electric motor applications. (NEMA, No. 50 at p. 9; Powersmiths, No. 46 at p. 5; Zarnowski, Public Meeting Transcript, No. 40 at p. 36; Looby, Public Meeting Transcript, No. 40 at p. 37)
For the January 2023 NOPR, DOE stated that rather than constructing sensitivity analysis scenarios to reflect every potential combination of factors that may affect steel pricing, DOE relies on a 5-year average pricing for its core steel. DOE requested comment on the market, prices, and barriers to added capacity for both amorphous and GOES. 88 FR 1722, 1767.
Regarding the impact of other products on GOES and amorphous supply, Howard agreed that the price of GOES has increased significantly based on NOES becoming a more valuable investment and utilizing similar production equipment to GOES, thereby occupying some of the production capacity that otherwise would produce GOES, leading to material shortages of GOES. (Howard, No. 116 at p. 5) ABB commented that shortages of domestic GOES and likely amorphous would require transformer manufacturers to import electrical steel and bear the cost of tariffs, adding to the cost of transformers. (ABB, No. 107 at p. 3)
Howard commented that competition for amorphous ribbon is limited to low-volume and niche products, including brazing foil and high-frequency transformers. (Howard, No. 116 at p. 18) Metglas added that amorphous is almost exclusively used in distribution transformers, without other significant sources of competition. (Metglas, No. 125 at pp. 5-6) Efficiency and Climate Advocates commented that the proposed rule will improve the transformer supply chain because amorphous does not have as much price competition from EVs as GOES. (Efficiency and Climate Advocates, No. 154 at p. 1)
NAHB commented that amorphous metals are used in aerospace, medical devices, electric motor parts, and robotics. (NAHB, No. 106 at pp. 10-11) NAHB stated that demand for both amorphous metals and GOES will continue to increase due to grid modernization. Id. NAHB stated that, although amorphous metals are not suited to EV motors, they are well suited for other applications in EV manufacturing and will experience increased demand within that segment of the automotive market. (NAHB, No. 106 at pp. 10-11)
Stakeholder comments confirm that competition from other products is greater for GOES than it is for amorphous. These statements generally confirm DOE's January 2023 NOPR observations as to how the price of GOES has risen more in the previous 5-years than the price of amorphous alloy.
Southwest Electric commented that the five-year average price of GOES is much lower than the current price of GOES and therefore DOE should update its cost models to reflect the more likely costs from 2023-2027, rather than incorporating the discounted prices that existed between 2017 and 2021. (Southwest Electric, No. 87 at p. 3) NEMA commented that the pricing of GOES is impacted by global demand and stated that some foreign manufacturers of GOES have committed part of their production capacity to serving their domestic markets. As such, this foreign GOES capacity is no longer available to serve the U.S. transformer market. (NEMA, No. 141 at p. 14) NAHB stated that energy rationing policies in China increased electrical steel prices in 2021-22 and, although prices have begun to stabilize, they are expected to increase again as demand for GOES and NOES rises. (NAHB, No. 106 at p. 11) Webb questioned whether the tariffs were exacerbating industry challenges. (Webb, No. 133 at p. 2) Carte commented that the market should decide what steel to use, stating that the recent increase in GOES prices paired with increased competition from NOES might naturally shift the market toward increased usage of amorphous material. (Carte, No. 140 at pp. 4-5)
DOE reiterates that there are a number of factors that can impact core material pricing, including competition from other markets, disruptions to supply chains, trade actions from both the U.S. and foreign countries, and increased demand. DOE has updated its base material prices in this final rule based on 5-year averages to capture more recent pricing trends as well as broader market developments. In general, the five-year average prices in this final rule are greater than the prices in the January 2023 NOPR, consistent with the observations from stakeholders.
DOE received numerous comments suggesting that the future price of materials could be dependent on DOE's policy choice as to whether to amend efficiency standards.
Howard commented that revised standards would further increase the demand for GOES and that its preliminary data shows transformer prices could be 50-125-percent greater than today's prices. (Howard, No. 116 at p. 5) Prolec GE stated that electrical steel price volatility is expected to continue or become worse unless current supply and demand issues are resolved. (Prolec GE, No. 120 at pp. 10-11) Prolec GE added that increased demand coupled with limited supply for lower-loss steels, both amorphous and GOES, will lead to price hikes. (Prolec GE, No. 120 at pp. 10-11) Regarding the price of amorphous ribbon, Eaton commented that DOE should consider the possibility that amorphous prices will increase to curtail demand, causing distribution transformer prices to increase 50-100 percent whether GOES or amorphous is used. (Eaton, No. 137 at p. 26)
Metglas commented that the price of amorphous ribbon has been stable relative to GOES over the last decade and additional amorphous ribbon capacity would drive down the fixed costs of amorphous ribbon and cores, which would improve the value of amorphous relative to GOES. (Metglas, No. 125 at pp. 5-6)
DOE notes that both GOES and amorphous core production tend to carry volume-based efficiencies. In Canadian markets, stakeholders have noted that while amorphous core transformers previously had a 10% cost-delta relative to GOES transformers, that cost-delta has fallen such that costs today are “more or less even” with GOES transformers. ^{133} DOE further notes that the adopted standards include equipment classes with substantial volume where both GOES and amorphous are expected to be cost-competitive. DOE also notes that the compliance period for amended standards has been extended, from the 3-year compliance period proposed in the January 2023 NOPR to a 5-year compliance period adopted in this final rule. As discussed further below, DOE has considered comments at to what length of compliance period is necessary to ensure a competitive market.
^{133} Bonneville Power Administration, Low-Voltage Liquid Immersed Amorphous Core Distribution Transformers. 2022. Available at www.bpa.gov/-/media/Aep/energy-efficiency/emerging-technologies/ET-Documents/liquid-immersed-dist-transformers-final-22-02-16.pdf (last accessed Oct. 30, 2023).
Howard commented that, while current cost structures indicate amorphous is the cost effective option for meeting the proposed efficiency standards, shortages of amorphous would increase amorphous costs and decrease GOES costs, meaning GOES could remain a cost effective option. (Howard, No. 116 at p. 3) Howard commented that both amorphous and GOES prices are expected to increase due to tariffs and increased demand due to the larger cores needed to meet the proposed efficiency standards. (Howard, No. 116 at p. 17) TMMA commented that the challenges associated with transitioning to amorphous cores will cause a further increase in the cost of producing and delivering a transformer, which will ultimately be borne by consumers. (TMMA, No. 138 at p. 3) WEG commented that the constrained supply of amorphous metal will significantly increase the cost of distribution transformers, amassing to $20M when applied across all of WEG's products. (WEG, No. 92 at p. 2) APPA commented that its current quotes from one vendor indicate that there would be a significant increase in costs if purchasing amorphous core transformers. (APPA, No. 103 at pp.7-8)
Prolec GE commented that DOE's analysis underestimates incremental costs because it is unrealistic that the market will fully transition to amorphous cores. (Prolec GE, No. 120 at p. 3) Prolec GE commented that, because the supply of amorphous ribbon is insufficient to serve the present market, manufacturers would be required to produce GOES transformers with a 40-70-percent increase in incremental cost. (Prolec GE, No. 120 at p. 2) TMMA added that an insufficient supply of amorphous will force manufacturers to use GOES to meet standards, leading to heavier transformers and higher costs that will be passed on to consumers. (TMMA, No. 138 at pp. 3-4) Southwest Electric stated that amorphous prices should be updated as well to reflect the expected cost increases that would occur if DOE's NOPR efficiencies go into effect in 2027. (Southwest Electric, No. 87 at p. 3) Powersmiths commented that DOE's costing estimate for amorphous transformers is flawed because a 5-year average includes low demand of the Covid pandemic period and does not properly reflect current market prices, which are nearly double and not expected to decline. (Powersmiths, No. 112 at p. 3) Prolec GE commented that heavy investments in increasing amorphous production capacity would be required to meet demand, implying that an ROI cost would be added for new production. (Prolec GE, No. 120 at p. 10) Alliant Energy commented in support of numerous manufacturers who expressed concern that conversion to amorphous cores by 2027 would increase prices and worsen existing supply chain concerns. (Alliant Energy, No. 128 at p. 2)
As noted, the current market for distribution transformers is experiencing an imbalance in supply and demand that has led to price increases for distribution transformers in recent years. This has also led to an increase in the price of GOES material needed to build distribution transformers. Compounding these price increases is the fact that there is only a single domestic supplier of GOES and, with tariffs on imported electrical steel, domestic transformer manufacturers are generally limited to purchasing M3 ^{134} steel from the single domestic GOES supplier. Manufacturers do have the option of purchasing electrical steel from global suppliers, but that would mean paying a 25-percent tariff and result in even higher electrical steel prices. These factors have left manufacturers with a limited supply of core material available for distribution transformer production.
^{134} M3 steel is the short-hand naming convention for conventional ( i.e., not high-permeability) GOES that is 0.23 mm thick. It makes up the majority of domestically produced GOES used in distribution transformers in the U.S.
In theory, manufacturers—under current standards—have the option of building amorphous transformers if the price of GOES transformers becomes prohibitively expensive. However, amorphous transformers require different capital equipment, meaning that manufacturers cannot easily switch between amorphous and GOES without new capital investments. As a result, the demand for GOES steel has increased by more than the demand for amorphous ribbon.
Data submitted in Eaton's comment indicates that for a 1,500 kVA, 3-phase liquid immersed transformer, an amorphous transformer is less expensive at baseline than a GOES transformer. Further, the proposed efficiency levels can be met with virtually zero incremental costs relative to a GOES transformer meeting efficiency standards today. If DOE applied current spot prices, as stakeholders have suggested, the baseline GOES transformer would get considerably more expensive while amorphous costs would remain relatively steady.
Regarding stakeholder concerns that incremental costs will be greater than DOE's analysis predicts due to a limited supply of amorphous metal, DOE notes that it has constrained the consumer choice model in this final rule to reflect the actions manufacturers will take given their existing production equipment and concerns over core steel supply. Specifically, consumers are assumed to meet standards with GOES up to EL 2. ( See section IV.F.3.a of this document). Further, the adopted standards are expected to be met via a combination of GOES and amorphous core steel, such that a limited supply of amorphous ribbon will not be a constraining factor in meeting amended standards. As such, DOE does not anticipate the supply of amorphous metal to become significantly constrained as a result of standards such that the incremental costs modeled in DOE's analysis to meet amended efficiency standards would greatly increase. Eaton expressed concern that relying on a single supplier of amorphous could create a virtual monopoly that would prevent competition from keeping prices in check. Accordingly, Eaton recommended DOE consider providing pricing and availability assurances until the market can create additional competition. (Eaton, No. 137 at p. 27) NEMA commented that it anticipates production of amorphous cores to be the bottleneck in meeting the NOPR efficiency standards. (NEMA, No. 141 at p. 14) NEMA stated that because it knew of just one domestic manufacturer of amorphous cores, there would likely be a dramatic increase in material price if the entire market is reliant on a single supplier. (NEMA, No. 141 at p. 14) NEMA commented that the NOPR would establish a monopoly on amorphous ribbon, which will increase costs and lead times. (NEMA, No. 141 at p. 3) NRECA commented that the proposed standards could eliminate production of GOES while likely creating a monopoly supplier for amorphous. (NRECA, No. 98 at p. 3)
Regarding the notion that amended efficiency standards would significantly increase amorphous material prices by providing a monopoly to the single domestic supplier, DOE notes that the current distribution transformer market operates with a single domestic supplier of GOES and multiple foreign suppliers. As discussed in section IV.A.4.a of this document, in the presence of amended standards, the distribution transformer market is expected to be subject to the same dynamics present in the current market, even at efficiency levels expected to be met with amorphous.
DOE does not assume having a single domestic supplier of GOES leads to monopolistic pricing. DOE notes that domestic GOES experiences competition from foreign-produced GOES. While direct imports of raw GOES are subject to tariff, transformer cores and laminations are not subject to tariffs. As previously discussed, transformer manufacturers rely on a combination of domestic steel—to produce their own cores—and imported cores (that use foreign-produced steel).
Similarly, DOE does not assume that because there is currently only a single domestic supplier of amorphous today, that there will be monopolistic pricing of amorphous in the presence of amended efficiency standards. Similar to GOES transformers, amorphous ribbon experiences competition from foreign-produced amorphous for which direct imports are subject to tariffs but transformer cores are not. In both cases, there are foreign competitors and opportunity for other suppliers to enter the market.
However, there is uncertainty in the short-term price of electrical steel, with a variety of factors impacting core steel pricing. Short-term prices could be driven by policy decisions and decisions of select market actors, including decisions made by distribution transformer manufacturers, amorphous ribbon manufacturers, and GOES steel manufacturers. The current market has limited supply of both amorphous and GOES steel with better loss performance than M3. Long-term pricing is driven by supply and demand, as well as the prices of the underlying commodities. DOE's updated 5-year pricing is intended to estimate a competitive market for core materials. While many factors are influencing competition in the distribution transformer market, the variety of supply pathways to produce transformers ( e.g., domestically producing transformer core, importing transformer cores and domestically producing transformers, or importing finished transformers) support the continued existence of a competitive market for core materials in the long-term.
Further, DOE notes while the majority of the distribution transformer shipments can meet adopted efficiency standards using either GOES or amorphous, for certain equipment classes DOE is adopting standards at EL4, which is likely to be met via amorphous cores. The expected increase in amorphous core production equipment to meet the adopted standards for equipment classes set at EL4 is likely to send a demand signal to amorphous alloy producers, thereby increasing amorphous supply. Further, because amorphous core production equipment can manufacture a range of transformer sizes, it is likely that additional competition will occur between GOES and amorphous core equipment classes set at EL2 for liquid-immersed distribution transformers.
Efficiency standards have a multi-year compliance period and stakeholders are able to plan and invest such that a competitive market exists. Indeed, DOE notes that the compliance period for amended standards has been extended, from the 3-year compliance period proposed in the January 2023 NOPR to a 5-year compliance period adopted in this final rule. As previously discussed, DOE has considered comments at to what sort of compliance period is necessary to ensure a market for GOES and amorphous steel sufficiently robust and competitive to provide adequate supply to the distribution transformer market to allow manufacturers to meet demand at the efficiency standards adopted.
EEI commented that the proposed standards are in violation of EPCA because there is not a sufficient supply of amorphous metal capacity to replace GOES, making it likely that the available supply of compliant distribution transformers will be reduced. EEI stated that the conversion to amorphous will result in significant downtime for distribution transformer production lines, limiting production capacity in the near to medium term. (EEI, No. 135 at pp. 12-17) EEI added that the proposed standards will require significant changes across the entire value chain for distribution transformers, which raises concerns regarding the practicability of manufacturing and reliably installing and servicing amorphous core distribution transformers by the proposed effective date. (EEI, No. 135 at pp. 17-19) Portland General Electric commented that requiring amorphous metal transformers at a time when supplies are already severely constrained risks electric grid reliability, raising concerns regarding EPCA's requirement that DOE consider the availability of covered products and the practicability of manufacturing, installing, and servicing them. (Portland General Electric, No. 130 at p. 3)
DOE notes that the adopted standards allow for both GOES and amorphous transformers on the market. DOE estimates that the majority of distribution transformers (the entirety of equipment class 1B and 2B) will use GOES to meet the adopted standard (corresponding to over 140,000 metric tons of GOES steel in just the liquid-immersed distribution transformer market), while the remainder of the liquid-immersed distribution transformer market will use amorphous cores. Therefore, DOE has concluded that the adopted standards would not result in the unavailability of distribution transformers or negatively impact the distribution transformer supply chain.
Idaho Falls Power and Fall River both commented that a 3-year compliance period is too aggressive and recommended that DOE consider a longer compliance period, which allows efficiency goals to be completed through innovation and utilization of incentives. (Idaho Falls Power, No. 77 at p. 2; Fall River, No. 83 at p. 2). Pugh Consulting commented that DOE did not consider the length of time and costs required to meet the proposed standards by the 2027 compliance deadline. (Pugh Consulting, No. 117 at p. 3) Portland General Electric questioned whether the proposed standards can be met in a 3-year compliance period, given the array of changes likely to result from the proposed rule. (Portland General Electric, No. 130 at p. 4) LBA commented that the proposed timeline is insufficient for the industry to make the required changes, including redesigning factories, establishing a dependable supply chain, hiring a workforce, and redesigning infrastructure to accommodate a new variety of distribution transformer. (LBA, No. 108 at p. 3)
ERMCO commented that the timeline to meet the proposed standards will take longer than 3 years when considering the development of new supply chains, certification of new apparatus designs, and engagement of new manufacturing processes. (ERMCO, No. 86 at p. 1) Southwest Electric stated that converting to amorphous for entities that either supply or refine their own GOES appears to require more than the 3 years currently being allowed. (Southwest Electric, No. 87 at p. 3) Howard commented that transformer manufacturers will not be able to begin shipping amorphous transformers within 3 years because both amorphous and GOES manufacturers would need to construct new facilities and transformer manufacturers would need to invest in new equipment. (Howard, No. 116 at pp. 1-2, 16)
Powersmiths stated that January 2027 is too short a timeframe for the proposed standards due to how the technology change will disrupt existing manufacturing processes and supply chains. (Powersmiths, No. 112 at p. 2) Schneider commented that the market is not prepared for the proposed efficiency levels and more time is needed to explore the risks of product substitution, impact on other power distribution equipment, supply chain and capital investment, non-ideal capital solutions, and electric room/building impacts. (Schneider, No. 101 at pp. 2, 16)
DOE notes that the adopted standards include substantially lower conversion costs, as discussed in section IV.J of this document, and a longer compliance period, ensuring the energy savings associated with the amended standards can be achieved without negatively impacting the availability of distribution transformers.
While there was general agreement from stakeholders that a 3-year compliance period was insufficient for the majority of liquid-immersed and LVDT transformers to transition to amorphous cores, as was proposed in the NOPR, there were a variety of opinions as to what efficiency levels and timelines were achievable and would not exacerbate shortages or lead to significant increases in material costs.
Several stakeholders specifically recommended DOE delay any potential amendment of transformer standards until transformer prices and lead times return to historical averages.
ABB recommended that DOE create an interagency working group to focus on the increased production of GOES, amorphous metal, and other constrained materials. (ABB, No. 107 at pp. 3-4)
Eaton recommended DOE delay consideration of the NOPR until supply and demand for distribution transformers more closely aligns with historical levels. (Eaton, No. 137 at pp. 1-2) Southwest Electric recommended that the proposed standards be delayed until appropriate measures are taken to stabilize supply chains, including increasing the U.S. supplies of amorphous and copper, improving infrastructure for supporting heavier overhead transformers, and decreasing average lead times for liquid-filled transformers under 40 weeks. (Southwest Electric, No. 87 at p. 4) Howard commented that the timeline for proposed standards is too aggressive, reducing grid security by removing GOES, and making current supply chain issues more challenging. Accordingly, Howard encouraged DOE to delay implementation of standards based on the supply crisis and overly aggressive timeline. (Howard, No. 116 at p. 5)
DOE notes that an indefinite delay in efficiency standards violates DOE's statutory obligation to adopt the maximum increase in efficiency that is technologically feasible and economically justified ( See 42 U.S.C. 6295(m)). The adopted standards are both technologically feasible and economically justified and do not pose substantial risk to the distribution transformer supply chain as discussed in section V.C of this document. The existing distribution transformer shortages are primarily associated with increased demand for grid products and shortages are unrelated to transformer efficiency. The adopted standards complement the efforts to resolve these shortages by allowing for significant flexibility in meeting efficiency standards such that energy savings can be achieved while also investing in additive transformer capacity that can diversify the core steel market and increase total transformer capacity.
Several stakeholders suggested that implementing efficiency standards that increased amorphous production could reduce the shortage concerns by shifting the distribution transformer market to amorphous material and freeing up GOES supply to be used in other applications or converted to NOES for EV applications.
Environmental and Climate Advocates commented that current transformer steel manufacturers are becoming increasingly focused on the EV market, creating greater reliance on electrical steel imports. Environmental and Climate Advocates stated that transitioning to amorphous could alleviate current GOES capacity constraints and will lead to a more robust long-term supply of distribution transformers since amorphous is not used in EV motors. Environmental and Climate Advocates also added that increasing capacity to amorphous production is relatively fast and inexpensive compared to adding GOES capacity. (Environmental and Climate Advocates, No. 122 at pp. 1-2)
Similarly, Efficiency Advocates and CEC commented that the proposed standards will help create a more secure long-term distribution transformer supply because amorphous does not experience competitive pressure from the electric vehicle market as GOES does. (Efficiency Advocates, No. 121 at p. 2; CEC, No. 124 at p. 2) Efficiency Advocates further commented that it is reasonable to expect that amorphous production would rapidly expand in response to standards given that adding amorphous ribbon capacity is less capital-intensive than adding GOES capacity. Efficiency Advocates added that there is a bias against amorphous due to transformer production being geared toward GOES, causing GOES transformers to be selected even in some instances when amorphous transformers are cheaper. Efficiency Advocates stated that the proposed standards would address this bias by spurring manufacturers to invest in producing amorphous transformers. (Efficiency Advocates, No. 121 at pp. 3-4)
DOE notes that the adopted standards include certain equipment classes that are expected to be met by transitioning to amorphous cores. Thereby, the adopted standards are likely to increase the number of domestic core steel suppliers serving the U.S. market from a single GOES producer to a mix of GOES and amorphous.
Several stakeholders suggested that DOE should establish revised efficiency standards where GOES steel will likely remain cost competitive and expand the compliance time to allow for more investment in GOES steel.
A group of U.S. Senators commented requesting that DOE finalize the proposed standards and extend the compliance date. The U.S. Senators stated that the proposed standards would provide Americans with significant savings on energy bills, but a longer compliance period is required to address current shortages and strengthen domestic supply chains. (U.S. Senators, No. 147 at pp. 1-2)
ERMCO suggested that DOE should either maintain current efficiency standards or propose standards at EL 2 or less, which would allow the U.S. supply chain to leverage both GOES and amorphous core steel supplies. ERMCO commented that this would allow sufficient time to validate the availability of raw materials, clarify load efficiency tradeoffs, and properly consider the total manufacturing investment. (ERMCO, No. 86 at pp. 1-2)
Sychak commented that Cliffs can supply lower-loss GOES grades but needs sufficient time to implement changes to its product mix. (Sychak, No. 89 at pp. 1-2) Sychak recommended DOE revise efficiency standards to allow for lower-loss GOES grades to remain cost competitive and revise the compliance date to 2030. (Sychak, No. 89 at pp. 1-2) Cliffs encouraged DOE to withdraw the proposed rule and meet with stakeholders to investigate alternative approaches, such as the possibility of producing higher-efficiency grades of GOES, given sufficient lead time to develop and manufacture these grades. (Cliffs, No. 105 at pp. 17-18)
Carte commented that GOES manufacturers are working to improve quality and the timeline of the proposed standards is very aggressive, not giving industry time to develop better GOES products. (Carte, No. 140 at pp. 3-4) Carte commented that future alloys will be able to maintain the durability of GOES and reduce eddy currents, but the proposed efficiency levels will inhibit this technology. (Carte, No. 140 at p. 4)
Carte recommended DOE delay standards until many of the concerns with amorphous are further investigated and work with industry to discuss what energy efficiency levels make sense. (Carte, No. 140 at p. 11)
MTC recommended DOE follow the lead of the European ECO-2 standards, which represent efficiency improvements over DOE's 2016 standards while allowing the use of GOES to ensure energy savings are cost effective. (MTC, No. 119 at pp. 16-17) MTC further recommended DOE delay amending efficiency standards for single phase transformers until experience with new core designs has been developed for three phase transformers similar to ECO-2. (MTC, No. 119 at p. 18)
DOE notes that the adopted standards include certain equipment classes that are at EL 2, as suggested by ERMCO, and are expected to be met with GOES cores. Further, the compliance period for amended standards has been extended, from the 3-year compliance period proposed in the January 2023 NOPR to a 5-year compliance period adopted in this final rule. The expanded compliance time also offers substantial opportunity for GOES manufacturers to increase production of lower-loss GOES products, as Sychak and Cliffs suggested.
Several other manufacturers recommended DOE move a portion of the market to amorphous and/or have expanded compliance dates in order to provide certainty that amorphous capacity will be sufficient and capital investment can be made without worsening near term transformer shortages.
CPI recommended that the final rule provide enough time for domestic transformer manufacturers to adjust to the proposed amorphous requirement without exacerbating current supply chain issues. (CPI, No. 78 at p. 1) CPI urged DOE to ensure that adequate sources of amorphous ribbon exist before the proposed rule becomes effective, suggesting that this could be achieved through a phased approach to the proposed rule. (CPI, No. 78 at p. 1)
Powersmiths and Eaton both commented that a tiered approach could be taken to implement efficiency standards with a more gradual impact to industry. (Powersmiths, No. 112 at p. 7; Eaton, No. 137 at p. 3)
Hammond commented that LVDT standards should not be amended because LVDTs already meet the most stringent efficiency requirements in the United States and Canada. However, Hammond stated that if DOE is going to amend efficiency standards, it recommends no higher than EL 3 for LVDTs. (Hammond, No. 142 at p. 3) Hammond also commented that the MVDT proposed standards are achievable and reasonable, especially given the proposed liquid-immersed levels. (Hammond, No. 142 at p. 3) DOE notes that Hammond's recommended efficiency levels correspond to efficiencies that could likely be cost effectively met using GOES.
Schneider stated that time would be needed to transition to amorphous in order to validate models, finalize footprint impacts, finalize capital requirements, and research impacts on sustainability, but supply chain constraints are inhibiting this research from being conducted via engineering samples. (Schneider, No. 92 at pp. 10-12) Schneider recommended that DOE establish the NOPR levels immediately as a voluntary ENERGY STAR level and delay the mandatory compliance date until January 1, 2030, to gradually convert the market toward new efficiency. Schneider stated this would provide manufacturers more time to evaluate technical impacts and establish supply chain partners. (Schneider, No. 92 at pp. 2, 16)
DOE notes that while a 3-year compliance period was proposed in the NOPR, stakeholder comment suggest that between 6 and 7 years would be needed to fully retool their production process to meet the proposed standards. WEG commented that between 5-7 years would be needed to retool their facility. (WEG, No. 92 at pp. 3-4) Schneider recommended mandatory compliance be delayed until 2030. (Schneider, No. 92 at pp. 2, 16) Sychak recommended DOE revise efficiency standards to allow for lower-loss GOES grades to remain cost competitive and revise the compliance date to 2030. (Sychak, No. 89 at pp. 1-2).
The timelines cited by stakeholders were generally based on the need to add substantially more amorphous core production capacity, as the January 2023 NOPR proposed EL4 for all liquid-immersed and EL5 for all low-voltage dry-type transformers. The standards adopted here, however, are expected to require less amorphous core production capacity. Accordingly, DOE anticipates that these lower efficiency standards could be achieved in fewer than the 7 years suggested by commenters. However, based on existing transformer shortages, DOE believes a 3-year compliance period may risk electrical steel prices increasing due to increased demand, which could result in exacerbating shortages in the near term. EPCA does not prescribe a specific time period for compliance with new or amended standards for distribution transformers. ^{135} Therefore, DOE has concluded that it is appropriate to extend the compliance period to 5 year to ensure sufficient time to allow investments in amorphous core production equipment, amorphous ribbon, and so that lower-loss GOES can be made without substantially increasing electrical steel prices. DOE further notes that a five-year compliance period is not uncommon for COMMERCIAL AND INDUSTRIAL equipment regulated under EPCA. See generally, 42 U.S.C. 6313.
^{135} EPCA prohibits the application of new standards to a product with respect to which other new standards have been required during the prior 6-year period. 42 U.S.C. 6295(m)(4)(B). As noted earlier, however, the standards for distribution transformers were last amended in April 2013.
As discussed, the adopted efficiency standards include different efficiency levels for different equipment classes as well as an expanded timeline, thereby providing certainty that amorphous capacity will be sufficient and capital investment can be made without worsening near term transformer shortages. DOE notes that existing capacity expansion announcements suggest that the near-term reaction to the January 2023 NOPR was to invest in amorphous in an additive capacity, given that additional distribution transformer production was needed anyway, as discussed in Chapter 3 of the TSD.
In evaluating whether higher efficiency standards would be met with GOES, DOE considers that, at baseline, most transformers are built with M3, as that is the predominant product sold by the single domestic GOES manufacturer. Lower-loss GOES exists and is included in DOE modeling; however, it generally has a price premium relative to M3 in the present market. As such, a transformer using lower-loss steel may be able to meet higher efficiency levels than a baseline M3 transformer using the same amount of steel (because the amount of losses per pound of steel are lower). However, because the lower-loss steel is sold at a price premium in the present market, the overall cost of that transformer may increase.
Howard commented that the primary barrier to using lower-loss GOES steels is supply related and manufacturers would use lower-loss GOES if tariffs were removed and domestic core manufacturers could import lower-loss GOES steel or domestic GOES manufacturers were incentivized to make lower-loss material. (Howard, No. 116 at p. 17) Howard commented that it produces its own cores domestically due to insufficient availability of lower-loss GOES material. (Howard, No. 116 at p. 17)
In the presence of amended standards, Cliffs, Sychak, and Howard suggested that existing producers of GOES may increase production of lower-loss GOES to meet the demand of the market or new producers of GOES may enter the market. If the increase in production capacity of this lower-loss GOES results in a reduction in the price premium, higher efficiency standards could be met without a transformer cost or size increase. For example, if the single domestic producer transitioned M3 grades to a lower-loss steel and did not increase the price per pound of GOES, higher efficiency standards (up to a point) could be met by building the exact same size transformers with the exact same costs and no required capital investment from distribution transformer manufacturers.
Schneider commented that as other countries require high grade dr core steel, lower quality hib and M-grade steels may become extremely cheap. (Schneider, No. 101 at p. 10)
Steel production tends to have volume-based efficiencies, wherein an initial transition to higher performing grades requires some degree of investment. However, once that investment is made and production is standardized on lower-loss steels, the incremental cost may decrease. DOE notes this sort of transitioning of core steel production was observed in response to the April 2013 Standards Final Rule. Prior to the compliance date of amended standards in 2016, baseline distribution transformers used a significant amount of M4, M5, or M6 core steel. 78 FR 23336. However, following the implementation of amended standards in 2016, the domestic GOES producer standardized on primarily M3 steel while many foreign producers standardized on hib and dr steels. These volume-based efficiencies resulted in a lower incremental cost between lower-loss GOES steel and M4, M5 or M6 grades. Not extremely cheap grades of these steels, as Schneider suggested.
For the current rulemaking, DOE's modeling indicates there is greater flexibility in transformer design, in terms of transformer size and core and coil design, when meeting amended standards with lower-loss GOES as compared to M3. Despite higher per pound prices, as higher-efficiency standards are evaluated, designing transformers with lower-loss core steel begins to achieve price parity with those designed with M3 steel, as the M3 designs typically operate at a reduced flux-density and add additional core material and/or use more (or more expensive) winding materials in order to meet higher efficiency standards, as demonstrated in Chapter 5 of the TSD. Whereas designs using lower-loss core steels can use a lesser amount of material to achieve the same efficiencies.
As stated by Howard, increased usage of lower-loss grades of GOES has traditionally been limited due to supply constraints on these steels which, in turn, contribute to a price premium on their market sale. (Howard, No. 116 at p. 17) In the past, the sole domestic producer of GOES has stated that it has the technical experience and ability to invest in additional grades of GOES as required by the market. ^{136}
^{136} (AK Steel, Docket No. BIS-2020-0015-0112 at pp. 7, 21).
Cliffs commented that they could produce higher-efficiency grades of GOES, given sufficient lead time to develop and manufacture these grades. (Cliffs, No. 105 at pp. 17-18) DOE notes that the adopted standards for liquid-immersed distribution transformers both extended the compliance period and adopted EL2 for equipment classes representing a substantial volume of shipments. Given Cliffs stated ability to manufacture lower-loss grades, expected demand for these grades into the future, the widespread existence of these grades in the global market, and the expanded compliance period by which these grades will be needed, it is expected that an increase in domestically produced lower-loss GOES grades will occur. As such, in the presence of amended standards, it is likely that the supply of higher grades of GOES would increase and, as a result of increased supply, the price premium that currently exists between M3 grades and higher grades of GOES would decrease.
Based on stakeholder feedback and historical GOES trends in the presence of amended efficiency standards, DOE has revised its pricing model for GOES in this final rule. In the no-new-standards case, DOE has continued to rely upon 5-year average pricing to develop base electrical steel prices. However, in the standards case, DOE revised its pricing for GOES for the liquid-immersed representative units to reflect an increased supply of low-loss GOES, as suggested by stakeholders. DOE notes that it is difficult to predict the exact investment and pricing strategy the domestic GOES manufacturer would employ. However, DOE assumed it would follow similar pricing dynamics to many of the foreign GOES suppliers that currently produce those steel grades. While the domestic GOES manufacturer could choose to follow different pricing dynamics, DOE notes that this would create considerable risk of losing market share to foreign GOES producers or the amorphous core market.
DOE modeled the price of 23hib090 at amended efficiency levels to match the price of baseline M3 grades. DOE notes these two products are sold for approximately the same price today (and, as discussed, foreign produced hib was less expensive than domestic GOES prior to tariffs), indicating that once manufacturers have invested in significant volumes of hib grades, they sell them at approximately equivalent prices to M3. For domain-refined grades, DOE reduced the price to a $0.10 cost-per-pound premium between 23hib090 grades and domain-refined grades. This premium aligns relatively well with the cost at which domain-refined grades become cost competitive with M3 grades at baseline, which stakeholders have noted is typical in the global market when sufficient supply is available. ^{137} This $0.10 cost-per-pound premium additionally accounts for the incremental production costs associated with the domain-refinement process. ^{138}
^{137} Central Moloney, a domestic manufacturer of distribution transformers, has commented that they purchase cores made of pdr steel for 90 percent of their designs. Indicating that if not subject to supply constraints, pdr can compete with M3 on first cost. See Docket No. EERE-2020-0015-0015.
^{138} DOE notes that while pdr grades are modeled for liquid-immersed distribution transformers, there may be instances where dr grades can be used in certain wound core transformer designs without annealing, specifically if using a unicore production machinery. It is uncertain whether investments would be into pdr steel or dr steel as pdr steel typically requires greater investment (and therefore have a greater premium than dr steel) but would achieve greater loss reduction on account of annealing benefits.
DOE notes that the domain-refinement process can be either an integrated process, such that domain-refined GOES is the direct output of production, or an independent additional processing step, wherein hib steel is separately treated to add domain-refinement. While the latter of these options requires additional floor space and capital investment, neither option has high input costs. As such, the material inputs required to produce domain-refined grades are not likely to lead to a significantly higher selling price once manufacturers have invested in the necessary production equipment. Rather, in the presence of sufficient supply, only a modest price premium is likely to exist between domain-refined and hib grades to account for the additional processing step required to add domain refinement to high permeability steel grades. Additionally, since domain refinement can occur as an independent processing step, it does not necessarily have to occur at the steel production site. While domain-refinement is typically conducted at the steel manufacturer sites, some manufacturers of domain-refinement equipment market the products for transformer core manufacturers to conduct their own laser scribing, which may be an option for large volume core manufacturers to minimize the cost-premium associated with domain-refined products, particularly if hib grades are available in sufficient volume domestically. ^{139}
^{139} Castellini, Laser Scribing Machine, (Last Accessed 1/23/2024), Available online at: https://www.castellini.it/products/solution/coil-processing/laser-scribing/.
These pricing updates reflect the fact that, in the no-new-standards case, steel manufacturers are likely to maintain the status quo. However, they also reflect stakeholder feedback that lower loss GOES pricing is largely demand dependent and would likely be reduced if GOES manufacturers invest in lower loss grades of GOES in the presence of amended standards, or if tariffs were lifted. Further, given the volume-based benefits of standardized production at a given steel grade, the price of these lower loss GOES materials may decrease as a result of increased production. Therefore, DOE evaluated any potential amended standards for liquid-immersed distribution transformers based on the reduced price of GOES that would be expected when compared to the no-new-standards case. Additional details on DOE's modelling of electrical steel pricing are provided in chapter 5 of the final rule TSD.
Additionally, as previously noted, DOE's modeling, as well as stakeholder comment, indicates that amorphous core transformer designs are already cost competitive with GOES core transformers for many transformer designs and would become even more favorable in the presence of amended standards, given the inherent improvement in no-load losses associated with amorphous cores as discussed in Eaton's comment. (Eaton, No. 137 at pp. 21-22). Therefore, at standard levels in which both GOES and amorphous metal can compete on a first cost basis, provided manufacturers make investment into amorphous core production equipment, it will be even more imperative for GOES producers to provide a supply of lower loss grades of GOES at a competitive price.
As discussed in section IV.F.3 of this document, DOE has also revised its assumptions to reflect transformer manufacturers' desire to not disrupt their existing GOES-core production capacity. Therefore, consumer amorphous core selection is limited through EL 2. The assumption limiting amorphous core selection is more likely to be valid the more cost- and performance-competitive GOES is. If there is a substantial increase in GOES core transformer cost, either resulting from a lack of investment in higher performing GOES steel or a substantial price premium for these lower loss GOES materials, customers would be more likely to select amorphous transformer at EL 1 and EL 2.
For medium-voltage and low-voltage dry-type equipment classes, DOE did not similarly estimate a decrease in the price of higher grades of GOES as a result of amended efficiency standards because the dry-type market is served by a different supply chain than the liquid-immersed market. As discussed in section IV.A.4.b of this document, although both the liquid-immersed and dry-type markets may, in theory, be supplied by the same grades of core steel, the liquid-immersed market tends to be served first in practice due to its higher volume of shipments. As a result, since the dry-type market represents a smaller proportion of total distribution transformer shipments and, in turn, a smaller required core steel capacity, any changes to amended efficiency standards the dry-type market are less likely to significantly impact the electrical steel market or incentivize manufacturers to invest in higher grades of GOES. Further, even if standards were amended for the liquid-immersed market and the supply of higher grades of GOES were to increase as a result, the dry-type market would not necessarily experience the price-reduction benefits of these investments. Since core steel supply chains are established to serve the liquid-immersed market first, any investments in GOES capacity would likely be primarily directed towards the liquid-immersed market. As such, dry-type transformer manufacturers may be required to either continue to use M3 grades of GOES and meet amended efficiency standards via other design improvements or continue to pay a premium on higher grades of GOES in order to secure a supply chain over the liquid-immersed market. Therefore, for the reasons discussed, DOE only revised its GOES pricing model for the liquid-immersed representative units in this final rule and has continued to use 5-year averages (updated to reflect recent price changes between the January 2023 NOPR and final rule) to model electrical steel prices at all evaluated standard levels for the dry-type representative units.
Additionally, as discussed in sections IV.A.2.b and IV.A.2.c of this document, DOE has established separate equipment classes for liquid-immersed distribution transformers based on kVA rating. For certain equipment kVA ranges, levels were set at the NOPR efficiency levels, thereby assuring manufacturers that some portion of the market will likely be cost-effectively met by amorphous, and assuring amorphous ribbon manufacturers that capacity can be increased to meet expected increases in demand. However, for other kVA ranges, DOE walked back the efficiency levels such that GOES remains a very cost-competitive option, even if standards may be more cost-effectively met with amorphous. As such, manufacturers will continue to have the design flexibility to decide which core material to utilize. Lastly, distribution transformer capital equipment is capable of producing a wide array of kVA ranges. Hence, existing GOES equipment can focus on levels that are more cost-effectively met with GOES while additive amorphous equipment can focus on levels that are more cost-effectively met with amorphous. Additionally, DOE has expanded the compliance period, such that transformers do not have to meet any higher efficiency levels for 5 years, ensuring additional time for these investments.
Taken together with an expanded compliance period, the standards adopted here will give GOES manufacturers, amorphous manufacturers, and distribution transformer manufacturers sufficient time and market certainty to make investments in both GOES and amorphous such that, prices will remain in line with DOE's modeling across a range of all reasonable manufacturer choices and efficiency standards will not make existing distribution transformer shortages worse. Further, DOE believes at least some additional portion of the market is likely to be met via amorphous ribbon, meaning the U.S. distribution transformer core market will likely be served in considerable volume by at least two domestic manufacturers, one for amorphous and one for GOES—as compared to today, wherein nearly all of the domestic market is served by a single domestic GOES manufacturer. A more diversified domestic supply ensures that uncertainty in policy decisions, such as implementation of tariffs, have less of an impact on domestic producers of distribution transformers.
In the economic analysis for distribution transformers, DOE models consumer purchases for baseline distribution transformers based on the current market trends, whereby a utility customer purchases the lowest cost distribution transformer that uses existing widely produced core steels, as discussed in section IV.F.3.a of this document. At EL1 and EL2 for liquid-immersed distribution transformers, DOE's analysis continues to model that distribution transformer manufacturers will choose to maintain their existing GOES equipment in order to avoid the investments needed to upgrade their production facilities to accommodate more-efficient types of steel used to make more-efficient distribution transformers. Therefore, DOE models consumers as purchasing GOES-core distribution transformers, even if amorphous-core transformers would be lower first-cost. Starting at EL3, DOE assumes liquid-immersed distribution transformer customers purchase the lowest cost distribution transformer that meets the evaluated efficiency level and therefore generally assumes most of that market transitions to amorphous cores. DOE assumes manufacturers begin shift to amorphous at EL 3 by making investments to upgrade their distribution transformer production facilities to accommodate amorphous steel, even though they would not at lower levels. Even though EL 3 can be met with more efficient GOES, manufacturers may choose to use amorphous steel to make distribution transformers cores because it is more economical. DOE considers various Trial Standard Levels as discussed in section V.A of this document; TSL 4 and above include all equipment classes at EL 4 and above, while TSL 3, the amended standard level, includes only equipment class1A and 2A at EL 4 (with the remaining classes at EL 2), resulting in only 48,000 metric tons of amorphous usage. That level of amorphous steel usage is not expected to impact the current domestic steel market given the existing domestic capacity and announced amorphous capacity expansions.
As discussed, amended standards could increase or decrease the demand for certain grades of GOES and amorphous steels that are used in cores to make more-efficient distribution transformers. To the extent that these shifts in market shares across raw material sources are large, such as in the case of TSL 4, it is possible that shifts in demand could change the underlying steel prices if supply cannot accommodate the demand increases. The pricing dynamics of the electric steel market are complicated given the global market dynamics, tariff structures and the modernization of the U.S. electric grid to help support resilience. DOE's adopted standard level accounts for these dynamics by setting efficiency levels which, based on the assumptions and data discussed above, are expected to maintain the demand for domestic GOES while beginning to grow the demand for amorphous steel in a managed transition that allows time for businesses and the workforce to gain experience, familiarity, and confidence in amorphous core distribution transformers.
Beyond any endogenous effect on steel demand—and price—resulting from the standards adopted in this rule, demand for electrical steel could be further heightened by efforts across the country to electrify building end-uses and transportation, including government initiatives, through legislation and rulemakings, outside the scope of this document. As one example, the proposed rulemaking by EPA on emissions standards for light duty vehicles projects that electricity demand will increase by 4.2% in 2055 as a result of that rule. ^{140} In this rulemaking, for the reasons explained above, DOE models an increase in distribution transformer shipments annually, which results in a 0.7-percent increase annually or approximately 75,000 units. These estimates are derived from AEO2023's growth rate to account for the increase in electricity demand resulting from various electrification policies and standards across the United States. DOE's use of AEO 2023 projections to drive its future shipments (and stock) growth result in a 190-percent increase in total installed stock (in terms of capacity) by 2050 as compared to a 2021 baseline. A report ^{141} by the National Renewable Energy Laboratory estimates future growth in stock between 160 and 260 percent by 2050 for distribution transformers, including step-up transformers which are not in the scope of DOE's rulemaking, but it shows consistent projections regarding future growth. DOE also ran higher and lower growth sensitivities, which were developed from the high and low scenarios in AEO 2023. ^{142} Lastly, DOE presents in appendix 10C of the TSD a sensitivity scenario examining the impacts of utilities installing larger distribution transformers (increased per unit average capacity) in response to growing decarbonization/electrification initiatives. These are all further detailed in section VI.E.3.a of this document. If these electrification increases are not adequately captured by AEO 2023 energy usage projections and sensitivities, DOE may be underestimating the demand for electricity-and therefore distribution transformers-in the analysis.
^{140} 88 FR 29184. Multi-Pollutant Emissions Standards for Model Years 2027 and Later Light-Duty and Medium-Duty Vehicles. May 5, 2023.
^{141} K. McKenna et al: Major Drivers of Long-Term Distribution Transformer Demand, Feb 2024, NREL/TP-6A40-87653.
^{142} See appendix 10B of the TSD. National Impacts Analysis Using Alternative Economic Growth Scenarios.
An additional pricing consideration within the market for distribution transformers is the role of competition and market structure. As elsewhere discussed in this document, GOES and amorphous demand in the United States are each supplied by one (separate) domestic producer. Existing foreign supply sources for amorphous alloy is limited to one producer in Japan, as well as several producers in China. As mentioned earlier, DOE does not expect the adopted standard level to alter the demand for GOES, in addition to the estimated efficiency benefits that amorphous steel transformers provide, DOE further believes that shifting some demand to amorphous steel might on the margin alleviate existing supply chain issues with GOES core transformers that was the source of extensive stakeholder feedback in response to the NOPR. While the increase in demand for amorphous alloy caused by today's standard might encourage additional entrants into the supply chain, it is worth considering the resulting market structure for amorphous alloy suppliers should all new demand be serviced only by existing producers.
At TSL 4, the demand for amorphous cores is projected to be approximately equal to today's global capacity of amorphous alloy. In the short term, an inability for suppliers to scale production and manufacturers to retool production lines towards amorphous core distribution transformers could lead to short-term market disruptions. If amorphous demand is serviced by the domestic manufacturer of amorphous alloy and tariffs remain in place, this introduces a possibility for a shift towards monopoly markups absent price competition. If foreign supply or additional domestic entrants for amorphous alloy are available, these monopoly markup issues can be somewhat mitigated. For example, in an alternative energy industry context it has been empirically shown that duopoly markups are lower than economic theory might otherwise predict, due to issues associated with protecting against additional market entrants and imperfect information. ^{143}
^{143} Wolfram, Catherine. Measuring Duopoly Power in the British Electricity Spot Market. American Economic Review. 89 (4) 805-826. 1999.
DOE acknowledges the above issues with respect to this rulemaking's potential impact on prices, and further acknowledges the complexity of accurately modeling price responses to regulations. To address the aforementioned concerns with endogenous price changes as a consequence of the rulemaking, as well as increased demand resulting from exogenous policy changes, in lieu of a market structure analysis, DOE has adopted standards that DOE expects to require an increase in amorphous demand that can be met with much higher probability in the revised 5-year compliance window. DOE has determined that such standards achieve the greatest energy savings that are economically justified. That is so even though DOE estimates consumer benefits would be maximized under the TSL4 standard that requires additional amorphous steel. However, based on these market-structure concerns, DOE has determined such standards are economically justified at this time.
General considerations for price responses and market structure are areas DOE plans to explore in a forthcoming rulemaking action related to the agency's updates to its overall analytic framework.
For TSL 3, DOE assumes that for the 1A and 2A equipment classes where DOE has proposed efficiency level 4, all future demand for distribution transformers will likely be met be met by amorphous cores. However, at TSL 3 for all other liquid-immersed equipment classes where DOE has proposed efficiency level 2, DOE assumes minimal amorphous core production even where amorphous is the lower first-cost product. In the long-run, it is possible that amorphous alloy supply will adequately increase to meet the new demand and will increase adoption of amorphous even for segments of the market that subject to standards that could be met with GOES cores. In that scenario, consumer and energy savings may be even greater than those modeled in this analysis. However, for distribution transformers, given the acute shortages this market has experienced in the past several years and the resulting higher prices, DOE has accounted for stakeholder feedback that total conversion from GOES to amorphous is not feasible in the short-term. Therefore, DOE has adopted a TSL that reflects the extensive feedback and data supplied to the rulemaking record that is economically justified and technologically feasible.

b. Other Material Prices
Regarding other materials used in a distribution transformer, DOE similarly relies on 5-year average costs for materials and includes labor costs derived largely from public indices, markup costs, and transportation costs. DOE detailed all of these costs in chapter 5 of the NOPR TSD.
Regarding these costs, Idaho Power commented that the metal price indices used by DOE are appropriate, but recommended DOE consider labor and transportation costs. (Idaho Power, No. 139 at p. 4) Pugh Consulting commented that DOE did not properly account for the impact of labor shortages. (Pugh Consulting, No. 117 at p. 3)
Regarding labor requirements, Georg commented that automation can reduce the labor-intensive work associated with transformer production and stated that Georg offers solutions to automate wound core production for both GOES and amorphous cores and stacked GOES cores. (Georg, No. 76 at p. 1)
DOE notes that Idaho Power did not suggest an alternative method for considering labor or transportation costs. As noted in the January 2023 NOPR, DOE applies a labor cost per hour that is generally derived from the U.S. Bureau of Labor Statistics rates for North American Industry Classification System (NAICS) Code 335311—“Power, Distribution, and Specialty Transformer Manufacturing” production employees hourly rates and applies markups for indirect production, overhead, fringe, assembly labor up-time, and a non-production markup to get a fully burdened cost of labor. 88 FR 1722, 1768. DOE has updated these labor rates, which reflect the recent increase in labor costs as discussed in chapter 5 of the TSD.
Regarding other materials costs, DOE notes that the majority of materials in a distribution transformer, aside from the transformer core, are commodities used across many products.
Southwest Electric stated that it predicts a 47.5-percent average increase in copper weight to meet the proposed standards and expressed concern that this increased demand will both increase the cost of copper and lead to potential shortages. (Southwest Electric, No. 87 at p. 3) Southwest Electric commented that the 5-year average price of copper is much lower than the current price of copper and therefore DOE should update its cost models to reflect the more likely costs from 2023-2027, rather than incorporating the discounted prices that existed between 2017-2021. (Southwest Electric, No. 87 at p. 3) Southwest Electric further recommended that DOE correct its cost model before finalizing a standard to reflect the direct cost increases associated with rising metal prices and the indirect cost increases associated with transporting, supporting, and repairing heavier overhead transformers. Id.
Powersmiths commented that copper will be required to meet many efficiency standards, which is more expensive, volatile, and subject to substantial competing demand to meet efficiency standards. Accordingly, Powersmiths encouraged DOE to set efficiency levels that can be met with aluminum windings. (Powersmiths, No. 112 at p. 3)
WEG commented that the supply of copper is limited and higher standards will drive more need for copper material vs aluminum. (WEG, No. 92 at p. 2) Eaton recommended that DOE consider the risk of reduced copper availability over the next two decades. (Eaton, No. 137 at p. 29) HVOLT commented that many designs will need to convert to copper windings in a time when copper is in tight supply. (HVOLT, No. 134 at p. 8) Carte commented that 20-percent additional conductor material would also have environmental and supply chain impacts. (Carte, No. 140 at p. 2)
Howard commented that copper usage will likely increase, making it more difficult for manufacturers to obtain. Howard added that, while other materials like oil, transformer tank steel, and insulating paper likely will not face significant shortages in the presence of amended standards, the quantity of these materials used will increase, thereby increasing the transformer MSP. (Howard, No. 116 at p. 24)
DOE notes that copper is used in a variety of industries and with a variety of electrical products. Hence, the distribution transformer market does not singularly dictate the supply and demand dynamics that impact the price of copper. DOE has used common indexes to determine the 5-year average price of copper. Further, DOE notes that the adopted efficiency levels for liquid-immersed distribution transformers can be met with GOES cores and aluminum windings for the equipment classes set at EL2 and with amorphous cores and aluminum windings for the equipment classes set at EL4. Low-voltage dry-type and medium-voltage dry-type transformer efficiency levels can also be met with GOES cores and aluminum windings.
Southwest Electric commented that, although a more efficient transformer allows manufacturers to reduce the amount of radiators required, the reduction is not enough to offset the material and labor increases needed to reach those efficiencies. (Southwest Electric, No. 87 at p.2)
Regarding transportation and labor costs, Schneider commented that DOE should consider the climate costs associated with increased transportation costs if the size of LVDTs increases. (Schneider, No. 101 at p. 11) Multiple commenters stated that larger transformers, and specifically amorphous core transformers, will require more truckloads to deliver the same number of transformers and additional weight will increase fuel costs, which DOE should account for in additional transportation costs. (ERMCO, No. 86 at p. 1; Powersmiths, No. 112 at p. 3; Idaho Power, No. 139 at p. 6; Eaton, No. 137 at p. 41)
Regarding transportation costs, DOE noted in the January 2023 NOPR that it uses a price per pound estimate for the shipping cost of distribution transformers. 88 FR 1722, 1768-1769. This methodology means that transformers with increased weight will have increased shipping costs reflected in DOE's analysis. DOE understands that the cost to ship each unit will vary depending on weight, volume, footprint, order size, destination, distance, and other, general shipping costs (fuel prices, drive wages, demand, etc.). DOE has previously sought comment as to whether this cost-per-pound accurately models the complexity of distribution transformer shipping costs. Id.
In response, Eaton commented that shipping costs vary, but DOE's shipping cost estimates are reasonable. (Eaton, No. 55 at p. 16) DOE did not receive comments suggesting that its cost-per-pound to ship transformers is inaccurate, or any suggestions as to how to model the complexity of distribution transformer shipping costs more accurately. Therefore, DOE retained its cost-per-pound shipping methodology described in chapter 5 of the TSD.
The resulting bill of materials provides the basis for the manufacturer production cost (MPC) estimates.
To account for manufacturers' non-production costs and profit margin, DOE applies a multiplier (the manufacturer markup) to the MPC. The resulting manufacturer selling price (MSP) is the price at which the manufacturer distributes a unit into commerce.
DOE's average gross margin was developed by examining the annual Securities and Exchange Commission (SEC) 10-K reports filed by publicly traded manufacturers primarily engaged in distribution transformer manufacturing and with a combined product range that includes distribution transformers. For distribution transformers, DOE applied a gross margin percentage of 20 percent for all distribution transformers. ^{144}
^{144} The gross margin percentage of 20 percent is based on a manufacturer markup of 1.25.
In the January 2023 NOPR, DOE acknowledges that while some manufacturer may have higher gross margins, the gross margin is unchanged from the April 2013 Standards Final Rule and was presented to manufacturers in confidential interviews as part of both the preliminary analysis and the NOPR analysis and there was general agreement that a 20-percent gross margin was appropriate for the industry. 88 FR 1722, 1769. DOE has retained the 20-percent gross margin as part of this analysis.

3. Cost-Efficiency Results
The results of the engineering analysis are reported as cost-efficiency data (or “curves”) in the form of energy efficiency (in percentage) versus MSP (in dollars), which form the basis for subsequent analyses in the final rule. DOE developed 19 curves representing the 16 representative units. DOE implemented design options by analyzing a variety of core steel material, winding material, and core construction methods for each representative unit and applying manufacturer selling prices to the output of the model for each design option combination. See chapter 5 of the TSD for additional details on the engineering analysis.
DOE then relies on these cost-efficiency curves and models consumer choices in the presence of various amended efficiency levels to calculate the downstream impacts of each theoretical efficiency standard. In general, DOE's analysis assumes most distribution transformer customers purchase based on lowest first cost and there is limited market above minimum efficiency standards ( see section IV.F.3 of this document).

D. Markups Analysis
The markups analysis develops appropriate markups ( e.g., retailer markups, distributor markups, and contractor markups) in the distribution chain and sales taxes to convert the MSP estimates derived in the engineering analysis to consumer prices, which are then used in the LCC and PBP analysis. At each step in the distribution channel, companies mark up the price of the product to cover costs. DOE's markup analysis assumes that the MSPs estimated in the engineering analysis ( see section IV.C of this document) are occurring in a competitive distribution transformer market as discussed in section V.B.2.d of this document.
As part of the analysis, DOE identifies key market participants and distribution channels. For distribution transformers, the main parties in the distribution chain differ depending on purchaser and on the variety of distribution transformer being purchased.
For the January 2023 NOPR, DOE assumed that liquid-immersed distribution transformers are almost exclusively purchased and installed by electrical distribution companies; as such, the distribution chain assumed by DOE reflects the different parties involved. 88 FR 1722, 1769. DOE also assumed that dry-type distribution transformers are used to step down voltages from primary service into the building to voltages used by different circuits within a building, such as plug loads, lighting, and specialty equipment; as such, DOE modeled that dry-type distribution transformers are purchased by non-residential customers ( i.e., COMMERCIAL AND INDUSTRIAL customers). Id.
DOE considered the following distribution channels in Table IV.7.
DOE did not receive any comments on the distribution channels applied in the NOPR and maintains the same approach in this final rule.
Chapter 6 of the final rule TSD provides details on DOE's development of markups for distribution transformers.

E. Energy Use Analysis
The energy use analysis produces energy use estimates and end-use load shapes for distribution transformers. The energy use analysis estimates the range of energy use of distribution transformers in the field ( i.e., as they are used by consumers), enabling evaluation of energy savings from the operation of distribution transformer equipment at various efficiency levels, while the end-use load characterization allows evaluation of the impact on monthly and peak demand for electricity. The energy use analysis provides the basis for other analyses DOE performed, particularly assessments of the energy savings and the savings in operating costs that could result from adoption of amended or new standards.
As presented in section IV.A.3, transformer losses can be categorized as “no-load” or “load.” No-load losses are roughly constant with the load on the transformer and exist whenever the distribution transformer is energized ( i.e., connected to electrical power). Load losses, by contrast, are zero when the transformer is unloaded, but grow quadratically with load on the transformer.
Because the application of distribution transformers varies significantly by category of distribution transformer (liquid-immersed or dry-type) and ownership (electric utilities own approximately 95 percent of liquid-immersed distribution transformers; commercial/industrial entities use mainly dry type), DOE performed two separate end-use load analyses to evaluate distribution transformer efficiency. The analysis for liquid-immersed distribution transformers assumes that these are owned by utilities and uses hourly load and price data to estimate the energy, peak demand, and cost impacts of improved efficiency. For dry-type distribution transformers, the analysis assumes that these are owned by commercial and industrial entities, so the energy and cost savings estimates are based on monthly building-level demand and energy consumption data and marginal electricity prices. In both cases, the energy and cost savings are estimated for individual distribution transformers and aggregated to the national level using weights derived from transformer shipments data.

1. Trial Standard Levels
As discussed in detail in section V.A of this final rule, DOE typically evaluates potential new or amended standards for products and equipment by grouping individual efficiency levels for each class into TSLs. Use of TSLs allows DOE to identify and consider manufacturer cost interactions between the equipment classes, to the extent that there are such interactions, and price elasticity of consumer purchasing decisions that may change when different standard levels are set. For this analysis, as in the NOPR, DOE applied a Purchase Decision model ( See section IV.F.3 of this document) to simulate the process that consumers use to purchase their equipment in the field within the LCC and PBP analysis ( See section IV.F of this document). To conduct these analysis DOE must know the composition of potential amended standards (TSL) as an input as they represent the purchasing environment to consumers under amended standards. The results that follow are presented by TSL to capture the consumer, national, and manufacturer impacts under the amended standards scenarios considered by DOE.

2. Hourly Load Model
For utilities, the cost of serving the next increment of load varies as a function of the current load on the system. To appropriately estimate the cost impacts of improved distribution transformer efficiency in the LCC analysis, it is therefore important to capture the correlation between electric system loads and operating costs and between individual distribution transformer loads and system loads. For this reason, DOE estimated hourly loads on individual liquid-immersed distribution transformers using a statistical model that simulates two relationships: (1) the relationship between system load and system marginal price; and (2) the relationship between the distribution transformer load and system load. Both are estimated at a regional level. Distribution transformer loading is an important factor in determining which varieties of distribution transformer designs will deliver a specified efficiency, and for calculating distribution transformer losses, and the time-dependent values of those losses. To inform the hourly load model, DOE examined data made available through the IEEE Distribution Transformer Subcommittee Task Force (IEEE TF).
DOE received the following comment regarding the loading of liquid-immersed distribution transformers: Carte questioned if DOE's analysis considered the wide range of loads that transformers serve in the field and whether DOE considered periods of high loading and low loading as part of its simulation. (Carte, No. 140 at p. 7) Central Hudson Gas and Electric (CHG&E) commented that it attempts to size its transformers at 80-percent of their nameplate capacity on new installations, and that some of its transformers are loaded at almost 200-percent of their nameplate rating. (CHG&E, Public Meeting Transcript, No. 75 at pp. 92-93) Metglas commented that an IEEE TF on Loading revealed that there is less than a 20-percent load on most transformers—well below the 50-percent loading test condition. Metglas added that it has heard from multiple utilities and OEMs that oversizing transformers is common and that, due to this fact, the actual loading is likely to remain around 20 percent. (Metglas, No. 125 at pp. 4, 7) Idaho Power commented that it supports DOE's application of an hourly load model for liquid-immersed distribution transformers. (Idaho Power, No. 139 at p. 4)
In response to CHG&E, DOE assumes CHG&E is referring to its customers' maximum peak demand, and maximum peak demand is not the average load on the distribution transformer. DOE loading analysis accounts for occurrences where the distribution transformers are loaded at a high percentage of their nameplate. While the overloading that CHG&E describes is discussed in IEEE C57.91-2011 as acceptable practice, DOE understands that overloading is the exception and not the rule as, depending on seasonality, the additional heat accumulated in the distribution transformer on high-temperature peak days can be detrimental to distribution transformer insulation lifetimes, potentially resulting in premature replacement. This strategy may be beneficial to CHG&E given its operational cost structures, but runs counter to DOE's understanding that utilities strive to reduce the cost of operation.
In response to CHG&E, Carte, Idaho Power, and Metglas, DOE's hourly load simulation, as discussed in the January 2023 NOPR, was designed specifically to account for the wide range of loads seen in the field, and for non-linear impacts on load losses when the transformer is under high loads. 88 FR 1722, 1770-1772. To do so, DOE used a two-step approach. Transformer load data were used to develop a set of joint probability distribution functions (JPDF), which capture the relationship between individual transformer loads and the total system load. ^{145} The transformer loads were calculated as the sum load of all connected meters on a given transformer for each available hour of the year. Because the system load is the sum of the individual transformer loads, the value of the system load in a given hour conditions the probability of the transformer load taking on a particular value. To represent the full range of system load conditions in the United States, DOE used FERC Form 714 ^{146} data to compile separate system load PDFs for each census division. These system PDFs are combined with a selected transformer JPDF to generate a simulated load appropriate to that system. As the simulated transformer loads are scaled to a maximum of one to calculate the losses, the load is multiplied by a scaling factor selected from the distribution of Initial Peak Loads (IPLs), and by the capacity of the representative unit being modeled. In the August 2021 Preliminary Analysis, DOE defined the IPL as a triangular distribution between 50 and 130 percent of a transformer's capacity, with a mean of 85 percent. This produces an hourly distribution of PUL values from which hourly load losses are determined. These distributions of loads capture the variability of distribution transformers load diversity, from very low to very high loads, that are seen in the field. The comments received did not provide data or evidence beyond anecdotal statements for DOE to change the modeling assumptions in the NOPR; as such, this distribution was maintained from the NOPR in this final rule.
^{145} See Distribution Transformer Load Simulation Inputs, Technical Support Document, chapter 7.
^{146} Available at www.ferc.gov/industries-data/electric/general-information/electric-industry-forms/form-no-714-annual-electric/data.
APPA commented that amorphous transformers are larger and more expensive, but the expense does not rise linearly with the capacity of the transformer. APPA commented that higher capacity transformers are cheaper per kW than smaller ones, so to save money, it is only logical that where shared secondary cable already exists, one should replace two or more (smaller capacity) transformers with a single (larger capacity) transformer and combine the shared portion of the secondary network. APPA commented that this has been shown to increase losses in the shared secondary cable to between 0.6 and 2.2 percent of total power delivered, far outstripping the increased efficiency of the amorphous transformer. APPA added that although DOE could consider working with utilities on secondary issues for more efficiency, the NOPR's analysis does not adequately account for this issue, which would undercut the efficiency conclusions in the proposed rule. (APPA, No. 103 at p. 15)
Regarding the APPA comment, when DOE conducts its analysis, it compares the costs and benefits of a revised standard against the no-new standards case. APPA's scenario asserts that at the time of transformer replacement, “it is only logical that . . . banks of distribution transformers should be replaced with a single,” DOE assumes a larger-capacity distribution transformer to optimize the cost per unit capacity of service being delivered. The lack of information provided by APPA makes it impossible for DOE to respond technically to this assertion; DOE notes that any single-unit replacement of multiple-unit installations would need to be sized in terms of capacity to meet the aggregate maximum demand of all connected customers (plus any safety margins) on said circuit. APPA's comment asserts that additional losses on the secondary is a function of equipment aggregation—a decision made at the individual utility's operational level, and, as described by APPA, is an example of a utility favoring operational efficiency over energy efficiency, which would happen in the absence of a revised standard by DOE and, as such, is not considered in this final rule.

a. Low-Voltage and Medium-Voltage Dry-Type Distribution Transformers Data Sources
Idaho Power commented it believes the base data used in the April 2013 Standards Final Rule was scaled from 1992 and 1995 data, and there have been many energy efficiency standards that have been incorporated over the last 30 years. Idaho Power recommended that DOE consider updating the standard to reflect current loading data and include advanced data collection methods that provide more granular data. Idaho Power added that many power companies have automated meter read data that could be leveraged for better analysis. (Idaho Power, No. 139 at p. 5)
DOE agrees with Idaho Power's comments that since the CBECS last included monthly demand and energy use profiles for respondents in 1992 and 1995 editions that many energy efficiency standards have been promulgated. For its dry-type analysis, DOE used the hourly load data for COMMERCIAL AND INDUSTRIAL customers from data provided to the IEEE TF (from 2020 and 2021) to scale these monthly values in its loading analysis for low-, and medium-voltage dry-type distribution transformers ( see chapter 7 of this final rule TSD). DOE is aware that many utilities meter their customers using real-time meters; however, DOE does not have the authority to demand such data from said utilities. Instead, DOE must rely on such industry initiatives such as the IEEE TF or individual companies to voluntarily come forward with data.

3. Future Load Growth

a. Liquid-Immersed Distribution Transformers
Several commenters stated their concerns over the possibility that future loads would rise on distribution transformers as a result of increased electrification. While no single commenter provided data or projections (simulated or otherwise) to support this concern, some commenters did hypothesize that liquid-immersed distribution transformer loads may grow in the future. (Mulkey Engineering, No. 96 at p. 1; Cliffs, No. 105 at pp. 12-13; HVOLT, No. 134 at pp. 3-4; WEG, No. 92 at p. 3; Idaho Power, No. 139 at p. 2)
Metglas commented that electrification impacts on distribution transformers would be uncertain. Metglas commented that electrification is likely to increase in response to global decarbonization goals. However, Metglas added that efficiency improvements in HVAC units, electric lighting, and other areas have kept the demand for electricity consumption essentially flat since 2010. The proposed DOE efficiency regulations will also help to decrease loading on the grid. (Metglas, No. 125 at p. 4)
CEC commented that electrification is increasing energy demands, with demand expected to increase by nearly 29 percent by 2035. CEC noted that increasing transformer efficiency would help reduce demand on the grid, but recommended DOE closely examine technical, cost, and reliability issues because of the unique risk that transformers pose to broader electrification trends. (CEC, No. 124 at pp. 1-2)
HVOLT and WEG commented that based on information supplied by EIA, total (net) generation had grown at a rate of 3.3 percent between 2021 and 2023. (HVOLT, No. 134 at pp. 3-4; WEG, No. 92 at p. 3) Further, APPA questioned DOE's use of EIA's AEO projection of future delivered electricity, stating that other trends suggest potentially much higher rates of electric end-use consumption, and citing President Biden's Executive Order No. 14037, which calls for 50 percent of all new passenger cars and light trucks sold in 2030 to be zero-emission vehicles. APPA commented that there are a wide variety of projections of electric vehicle sales by 2030, and EV sales already reached nearly 6 percent of all new car purchases in 2022, and that share is only expected to increase. Additionally, APPA commented that Federal and State governments are mandating that homes and buildings be electrified to cut emissions. (APPA, No. 103 at p. 5) NYSERDA commented that EIA forecasts of electricity demand do not reflect the significant demand increases anticipated in New York and other parts of the country due to aggressive decarbonization policies and accelerating rates of EV adoption. As such, NYSERDA anticipates DOE has underestimated the potential energy-saving impact of these standards, underscoring the need to complete this rulemaking as quickly as possible. (NYSERDA, No. 102 at pp. 1-2) Carte commented that EIA's loading appears to be based on history and not forward looking, which could explain why such a low increase in loading is predicted. Carte commented that electrification does not appear to be considered when talking about 0.9 percent increases per year. (Carte, No. 140 at p. 6)
Further, APPA commented that with electric vehicles, solar photovoltaic, building decarbonization, and other energy transition technologies, the average household will move from an average load of 2 kW to an average of 6 kW and a peak of 5 kW to a peak of 10 to 25 kW (with range based on EV sizing). APPA commented that currently, 25 kVA transformers serve two to six residences, and transformers are going to see at least twice the load, with fewer low/no load hours. APPA commented that an economic justification analysis for the proposed distribution transformer efficiency standards would need to address the change in the way transformers will operate during and after the transition and analyze how NOES transformer efficiency will be impacted by these changes, and whether those changes impact the NOPR's cost/benefit analysis. (APPA, No. 103 at p. 17)
Regarding HVOLT and WEG's comment about net generation growth, DOE notes that net generation cannot be used as a proxy for distribution transformer loads. ^{147} Net generation is a “top-down” indicator of how much generation is required to meet “bottom-up” demands of electrical consumption (purchases) and must account for generating capacity to meet total peak generation, reserve margins, the capacity factors of each variety of generating unit, and transmission losses, plus unavailable capacity (outages). 148 149 150 DOE finds that EIA's changes in projected purchased electricity to the final consumer represents a more appropriate proxy for distribution transformer load growth due to the distribution system's physical proximity to the final electrical consumer. For this final rule, DOE has continued to use AEO's projection of Energy Use: Delivered: Purchased Electricity, noting that the rate has changed from that in the NOPR to 0.7 percent per year in this final rule. ^{151}
^{147} Net generation: the amount of gross generation less the electrical energy consumed at the generating station(s) for station service or auxiliaries. See www.eia.gov/tools/glossary/index.php?id=Net%20generation#:~:text=Net%20generation%3A%20The%20amount%20of,is%20deducted%20from%20gross%20generation.
^{148} Rserve margin: The amount of unused available capability of an electric power system (at peak load for a utility system) as a percentage of total capability. See www.eia.gov/tools/glossary/index.php?id=R.
^{149} Capacity factor: The ratio of the electrical energy produced by a generating unit for the period of time considered to the electrical energy that could have been produced at continuous full power operation during the same period. See www.eia.gov/tools/glossary/index.php?id=C.
^{150} Capacity factors vary by generating unit, ranging from 92 percent for nuclear generation (almost always on and available) to 24 percent for solar PV (the sun isn't always shining where the collector are located). See www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_a, and www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_b.
^{151} See www.eia.gov/outlooks/aeo/data/browser/#/?id=2-AEO2023&region=1-0&cases=ref2023&start=2021&end=2050&f=A&linechart=~~~~ref2023-d020623a.103-2-AEO2023.1-0&map=ref2023-d020623a.3-2-AEO2023.1-0&ctype=linechart&sourcekey=0.
APPA's comments to DOE did not suggest any specific alternative trends that would suggest potentially much higher rates of electric end-use consumption in place of AEO. As discussed later in this section, DOE applies the rate of load growth over its entire analysis period resulting in a significant growth of 22 percent, which results in positive consumer benefits for all liquid-immersed equipment at today's amended standard levels ( see broadly: section V) Additionally, as specified in 10 CFR part 431, subpart K, appendix A certification of medium-voltage liquid-immersed distribution transformers must occur at 50 percent PUL—a rate that ensures efficient load-loss performance over a wide range of loads, both low and high. If loads were to grow at a rate greater than that estimated by AEO, the standard adopted by DOE would result in greater energy savings, and consumer and National benefits.
Further APPA, NYSERDA, and Carte commented that future loads would be driven by increased EV adoption, claiming that EV adoption is not included in AEO's total purchase electricity projection. DOE's examination of AEO2023, Table 2, Energy Consumption by Sector and Source, shows purchased electricity to transportation (including light duty vehicles) to increase at a rate of 9.7 percent per year.
Idaho Power commented that it expects residential loads to increase 10 to 25 percent; however, no time period for this increase was provided. (Idaho Power, No. 139 at p. 2) Xcel Energy commented that with increased electrification, it expects an increase in load factor and a higher rate of changeouts (to larger-capacity units). (Xcel Energy, Public Meeting Transcript, No. 57 at p. 133) WEC commented that it projected that loading would increase by 5 to 15 percent on its single-phase distribution transformers; again, no period over which this would occur was provided. (WEC, No. 118 at p. 1) Carte commented that increased adoption of EVs and other electrification technologies will greatly increase transformer loads. (Carte, No. 140 at pp. 5-6) Further, Carte and CARES expressed a belief that loads will grow by 50 percent, a number that they attribute to EEI without citation. (Carte, No. 140 at p 6; CARES, No. 99 at p. 4)
Specifically, in response to the assertions from Carte and CARES that loads will grow by 50 percent over the next 5 to 10 years, DOE has identified a presentation that is believed to be the source document of these values; ^{152} the presentation forecasts that the range of electric loads increase will “vary wildly, anywhere from 5 and 50 percent, depending on multiple factors,” indicating that 50 percent is a maximum bound of EEI's load growth estimate—not the likely outcome indicated by Carte and CARES.
^{152} See: https://www.regulations.gov/document/EERE-2019-BT-STD-0018-0162 .
As stated in the January 2023 NOPR, and evidenced by the comments received, many factors potentially impact future distribution transformer load growth, and these factors may be in opposition. At this time, many utilities, States, and municipalities are pursuing EV charging programs, and it is unclear the extent to which increases in electricity demand for EV charging or other State-level decarbonization efforts, will impact current distribution transformer sizing practices (for example, whether distribution utilities plan to upgrade their systems to increase the capacity of connected distribution transformers, thus maintaining current loads as a function of distribution transformer capacity; or if distribution utilities do not plan to upgrade their systems and will allow the loads on existing distribution transformers to rise). DOE recognizes that this is further complicated by the current supply shortage of distribution equipment. Some stakeholders speculate that these initiatives will increase the intensive per-unit load over time as a function of per unit of installed capacity. However, these stakeholders did not provide any quantitative evidence that this is indeed happening on their distribution systems, or in regions that are moving forward with decarbonization efforts. Further, the hypothesis that intensive load growth will be a factor in the future is not supported by available future trends in AEO2023, as indicated by the purchased electricity trend representing the delivered electricity to the customer. Others asserted that higher loads in response to decarbonization initiatives would be met with the extensive growth of the distribution system ( i.e., increasing the total capacity of the distribution system through larger distribution transformers, or greater shipments, or some combination of both). Again, data were not provided to support this position, but some utilities stated they were maintaining service by (a) increasing the distribution capacity of given circuits ( i.e., installing larger transformers); or (b) reducing the number of customers on a given circuit ( i.e., installing more transformers). ^{153} (APPA, No. 103 at p. 17; Highline Electric, No. 71 at pp. 1-2; Idaho Power, No. 139 at p. 5) For this final rule, DOE finds that neither position provides enough evidence to change its assumptions from the January 2023 NOPR and August 2021 Preliminary Analysis TSD. For this final rule, DOE updated its load growth assumption for liquid-immersed distribution transformers based on the change in average growth of AEO2023: Purchased Electricity: Delivered Electricity, which shows a year-on-year growth rate of 0.7 percent. While this value may seem low, when compounded over the analysis period it results in a significant growth of 22 percent, which is higher than the rates indicated by Idaho Power and WEC, albeit over a presumed longer timeframe.
^{153} Discussed in section IV.G.2 of this document in detail.
Additionally, DOE has examined a scenario in the NIA to measure the potential impacts of increased capacity by shifting smaller units to larger units. There is little information from which to model this shift—specifically over how long a period this shift to larger capacities would occur. Based on report studying the impact of EVs on transformer overloading, ^{154} and the impacts of reduced transformer lifetimes from increased transformer loads ^{155} DOE estimated the extensive growth of the distribution system that would be needed. These studies indicate that it is distribution transformer up to 100 kVA that are at risk of overloading (EC 1B), and associated lifetime reductions, and most likely to be replaced with larger capacity equipment. These studies indicate that the risk of overload diminishes with increased capacity, with 100 kVA being the upper limit. DOE's approach shifts the capacities transformer shipments over to larger capacity equipment. DOE includes this scenario for illustrative purposes. This shift and results can be found in appendix 10C of the TSD. These results indicate that for EC 1B in the event of such a capacity shift, the national full-fuel cycle energy savings will increase by 21 percent, with the net present value of consumer savings also increasing by 19 and 20 percent, at 3 and 7 percent discount rates, respectively.
^{154} Dalah, S., Aswani, D., Geraghty, M., Dunckley, J., Impact of Increasing Replacement Transformer Size on the Probability of Transformer Overloads with Increasing EV Adoption, 36th International Electric Vehicle Symposium and Exhibition, June, 2023. Available online at: https://evs36.com/wp-content/uploads/finalpapers/FinalPaper_Dahal_Sachindra.pdf.
^{155} Jodie Lupton, Right-Sizing Residential Transformers for EVs, T&D World,January 2024, Available online: https://prismic-io.s3.amazonaws.com/wwwpowerengcom/9dd90ffc-4df8-442c-92c2-eb175f687ea0_Right-sizing+residential+transformers+for+EVs.pdf .
Chapter 7 of the final rule TSD provides details on DOE's energy use analysis for distribution transformers.

F. Life-Cycle Cost and Payback Period Analysis
DOE conducted LCC and PBP analyses to evaluate the economic impacts on individual consumers (in this case distribution utilities for liquid-immersed, and COMMERCIAL AND INDUSTRIAL entities for low-, and medium-voltage dry-type) of potential energy conservation standards for distribution transformers. The effect of amended energy conservation standards on individual consumers usually involves a reduction in operating cost and an increase in purchase cost. DOE used the following two metrics to measure consumer impacts:
The LCC is the total consumer expense of an appliance or product over the life of that product, consisting of total installed cost (manufacturer selling price, distribution chain markups, sales tax, and installation costs) plus operating costs (expenses for energy use, maintenance, and repair). To compute the operating costs, DOE discounts future operating costs to the time of purchase and sums them over the lifetime of the product.
The PBP is the estimated amount of time (in years) it takes consumers to recover the increased purchase cost (including installation) of a more-efficient product through lower operating costs. DOE calculates the PBP by dividing the change in purchase cost at higher efficiency levels by the change in annual operating cost for the year that amended or new standards are assumed to take effect.
For any given efficiency level, DOE measures the change in LCC relative to the LCC in the no-new-standards case, which reflects the estimated efficiency distribution of distribution transformers in the absence of new or amended energy conservation standards. In contrast, the PBP for a given efficiency level is measured relative to the baseline product.
For each considered efficiency level in each product class, DOE calculated the LCC and PBP for a nationally representative set of electric distribution utilities and commercial and industrial customers. As stated previously, DOE developed these customer samples from various sources, including utility data from the Federal Energy Regulatory Commission (FERC), EIA; and commercial and industrial data from the Commercial Building Energy Consumption Survey (CBECS) and Manufacturing Energy Consumption Survey (MECS). For each sample, DOE determined the energy consumption in terms of no-load and load losses for distribution transformers and the appropriate electricity price. By developing a representative sample of consumer entities, the analysis captured the variability in energy consumption and energy prices associated with the use of distribution transformers.
Inputs to the LCC calculation include the installed cost to the consumer, operating expenses, the lifetime of the product, and a discount rate. Inputs to the calculation of total installed cost include the cost of the equipment—which includes MSPs, retailer and distributor markups, and sales taxes—and installation costs. Inputs to the calculation of operating expenses include annual energy consumption, electricity prices and price projections, repair and maintenance costs, equipment lifetimes, and discount rates. Inputs to the PBP calculation include the installed cost to the consumer and first year operating expenses. DOE created distributions of values for equipment lifetime, discount rates, and sales taxes, with probabilities attached to each value, to account for their uncertainty and variability.
The computer model DOE uses to calculate the LCC and PBP relies on a Monte Carlo simulation to incorporate uncertainty and variability into the analysis. The Monte Carlo simulations randomly sample input values from the probability distributions and distribution transformer samples. For this rulemaking, the Monte Carlo approach is implemented as a computer simulation. The model calculated the LCC and PBP for products at each efficiency level for 10,000 individual distribution transformer installations per simulation run. The analytical results include a distribution of 10,000 data points showing the range of LCC savings for a given efficiency level relative to the no-new-standards case efficiency distribution. In performing an iteration of the Monte Carlo simulation for a given consumer, product efficiency is as a function of the consumer choice model described in section IV.F.2 of this document. If the chosen equipment's efficiency is greater than or equal to the efficiency of the standard level under consideration, the LCC and PBP calculation reveals that a consumer is not impacted by the standard level. By accounting for consumers who are already projected to purchase more-efficient products in a given case, DOE avoids overstating the potential benefits from increasing product efficiency.
DOE calculated the LCC and PBP for all consumers of distribution transformers as if each were to purchase new equipment in the expected year of required compliance with amended standards. Amended standards would apply to distribution transformers manufactured five years after the date on which any new or amended standard is published in the Federal Register . Therefore, DOE used 2029 as the first year of compliance with any amended standards for distribution transformers.
Table IV.11 summarizes the approach and data DOE used to derive inputs to the LCC and PBP calculations. The subsections that follow provide further discussion. Details of the model, and of all the inputs to the LCC and PBP analyses, are contained in chapter 8 of the TSD and its appendices.

1. Equipment Cost
To calculate consumer product costs, DOE multiplied the MPCs developed in the engineering analysis by the markups described previously (along with sales taxes). DOE used different markups for baseline products and higher-efficiency products because DOE applies an incremental markup to the increase in MSP associated with higher-efficiency products.
DOE examined historical producer price index (PPI) data for electric power and specialty transformer manufacturing available between 1967 and 2022 from the BLS. ^{156} Even though this PPI series may also contain prices of electrical equipment other that distribution transformers, this is the most disaggregated price series that is representative of distribution transformers. DOE assumes that this PPI is a close proxy to historical price trends for distribution transformers, including liquid-immersed, and medium-, and low-voltage dry-type transformers. The PPI data reflect nominal prices adjusted for product quality changes. The inflation-adjusted (deflated) price index for electric power and specialty transformer manufacturing was calculated by dividing the PPI series by the Gross Domestic Product Chained Price Index.
^{156} Product series ID: PCU3353113353111. Available at www.bls.gov/ppi/.
DOE has observed a spike in the trend of annual real prices between 2021 and 2022. However, when the PPI is examined at a month-by-month level, the deflated PPI from 2022 through 2023 appears to be leveling off. Specifically, the deflated monthly PPI data in Table IV.12 shows a near constant value since June 2022. DOE further examined the trends on key inputs into distribution transformers: steel, aluminum, and copper—these inputs show a similar trend over this same period. 157 158 159 DOE notes that the engineering analysis estimated MSPs in 2023; additionally, and that it has captured the impact of this spike, if it were realized, as a constant increase in real prices in the low economic price scenario results shown in section V.C of this document.
^{157} Steel: WPU101
^{158} Aluminum: ID: WPU10250105
^{159} Copper: WPU10260314
DOE received no comments on its future price trend methodology in the NOPR. For this final rule, DOE maintained the same approach for determining future equipment prices as in the NOPR and assumed that equipment prices would be constant over time in terms of real dollars ( i.e., constant 2023 prices).

2. Efficiency Levels
As in the January 2023 NOPR, for this final rule, DOE analyzed various efficiency levels expressed as a function of loss reduction over the equipment baseline ^{160} as well as an overall efficiency rating. For units greater than 2,500 kVA, there is not a current baseline efficiency level that must be met. Therefore, DOE established EL 1 for these units as if they were aligning with the current energy conservation standards efficiency vs kVA relationship, scaled to the larger kVA sizes. To calculate this, DOE scaled the maximum losses of the minimally compliant design from the next highest kVA representative unit to the 3,750 kVA size using the equipment class specific scaling relationships in TSD appendix 5C. For example, for three-phase liquid-immersed distribution transformers, the highest kVA representative unit is RU5, corresponding to a 1,500 kVA transformer. A minimally compliant 1,500 kVA design is 99.48-percent efficient and has 3,920 W of total losses at 50-percent load, with representative no-load and load losses of 1,618 W and 2,290 W respectively based on RU5. Using the updated scaling factors of 0.73 and 1.04 for no-load and load losses respectively, as described in appendix 5C, the total losses of a 3,750 kVA unit would be 9,096 W, corresponding to 99.52-percent efficient at 50-percent load.
^{160} Calculated as the current percentage loss ( i.e., 100 percent minus the current standard) multiplied by the percent reduction in loss plus the current standard
EL 2 through EL 5 align with the same percentage reduction in loss as their respective equipment class, but rather than being relative to a baseline level, efficiency levels were established relative to EL 1 levels.
The rate of reduction is shown in Table IV.13, and the corresponding efficiency ratings in Table IV.14.
DOE did not receive any comments regarding either the loss rates or the efficiency levels applied in the NOPR and continued their use for this final rule.

3. Modeling Distribution Transformer Purchase Decision
In the January 2023 NOPR TSD, DOE presented its modelling assumptions on how distribution transformers were purchased. DOE used an approach that focuses on the selection criteria that customers are known to use when purchasing distribution transformers. Those criteria include first costs as well as the total ownership cost (TOC) method, which combines first costs with the cost of losses. Purchasers of distribution transformers, especially in the utility sector, have historically used the TOC method to determine which distribution transformers to purchase. However, comments received from stakeholders responding to the 2012 ECS NOPR (77 FR 7323) and the June 2019 Early Assessment RFI (84 FR 28254) indicated that the widespread practice of concluding the final purchase of a distribution transformer based on TOC is rare. Instead, customers have been purchasing the lowest first cost transformer design regardless of its loss performance. Respondents noted that some purchasers of distribution transformers do so on the basis of first cost in order to, among other things, maximize their inventories of transformers per dollar invested. This behavior allows transformer purchasers to have the maximum inventory of units available to quickly respond to demand for new transformers, as well as have replacements readily available in the event of transformer failure. DOE continues to explore consumer choice and market reaction to the new efficiency standards levels and the impact it would have on purchasers' inventory of transformers. This may be further explored in a future RFI. As discussed in section IV.F.3.b of this document the practice of purchasing based on first cost is unlikely to change over time.
The utility industry developed TOC evaluation as a tool to reflect the unique financial environment faced by each distribution transformer purchaser. To express variation in such factors as the cost of electric energy, and capacity and financing costs, the utility industry developed a range of evaluation factors: A and B values, to use in their calculations. ^{161} A and B are the equivalent first costs of the no-load and load losses (in $/watt), respectively.
^{161} In modeling the purchase decision for distribution transformers DOE developed a probabilistic model of A and B values based on utility requests for quotations when purchasing distribution transformers. In the context of the LCC the A and B model estimates the likely values that a utility might use when making a purchase decision.
In response to the NOPR analysis, DOE received the following comments regarding the modeling of distribution transformer purchases.

a. Equipment Selection
DOE did not receive comments regarding how engineering designs were selected by the consumer choice model in the LCC and maintained the material constraints in be no-new-standards case from the January 2023 NOPR in this final rule. For the January 2023 NOPR, DOE's research indicated that distribution transformers can be fabricated with amorphous core steels that are cost competitive with conventional steels, as shown in the engineering analysis ( see section IV.C), but they cannot currently be fabricated in the quantities needed to meet the large order requirements of electric utilities, and, as such, are limited to niche products. DOE experience shows that this lack of market response to the availability of new materials, amorphous, to be unique to the purchase of distribution transformers. The current market environment for distribution transformers is shaped primarily by the availability of products with short lead times to consumers given current demand dynamics. This in turn is driven by the availability of existing production capacity. Currently, distribution transformer capacity is primarily set up to produce equipment with GOES cores (97 percent of units). Because GOES production equipment cannot be readily modified to manufacture amorphous distribution transformers, DOE understands that this production capacity will continue to produce GOES distribution transformers unless it is entirely replaced with amorphous specific production equipment. As a result, the availability of GOES core transformers will be maintained, even as amorphous production capacity is added under amended standards.
This circumstance is unique to transformers where the production lines for GOES and amorphous core equipment are not interchangeable, meaning that to meet amended standards requiring amorphous core steel manufacturers cannot retool existing production lines, but must add new production capacity. DOE expects that, in the long term, manufacturers may begin to replace GOES production equipment with amorphous production equipment where amorphous is more cost competitive in the presence of amended standards. However, as discussed in section IV.A.5 of this document, the distribution transformer market is currently experiencing significant supply constraints, creating extended lead times and supply shortages for distribution transformers. Therefore, to address these supply shortages, manufacturers may choose to maintain their GOES production to maximize their production output in the presence of amended standards, even if amorphous production is a more cost competitive production route. To reflect this, DOE has revised its customer choice model in the no-new-standards and standards cases in this final rule to limit the variety of core steel materials by TSL to the ratios shown in Table IV.15. DOE updated the consumer choice model from the January 2023 NOPR, which did not constrain the selection of designs based on core material variety in the standards case, based on feedback received expressing that manufacturers may maintain GOES production, even in instances when amorphous transformers may be the lowest cost option (S ee sections IV.A.4.c and IV.A.5 of this document). These material limits account for impacts in the amended standards case where GOES steel may continue to be used to meet the trial standard levels ( see section V.A of this document). These material limits represent a conservative view of the future where AM does not displace any GOES production, or the demand for GOES distribution transformers is not diminished in favor of AM core distribution transformers. While it is likely that over time there would be some displacement, it is too speculative for DOE to establish amended standards on such a modeling assumption. For informational purposes DOE has included LCC sensitivities where the amorphous core distribution transformers increase in availability to 10 percent, and 25 percent. These sensitivity analyses, which demonstrate a higher percentage of distribution transformer manufacturers utilizing amorphous steel cores to meet TSL 3 standards, result in increasing LCC savings for EC 1B by 62 and 193 percent, respectively. Further for EC 2B the LCC savings increased by 578 and 589 percent for increases in AM availability of 10 and 25 percent, respectively. The impacts of these sensitivities can be reviewed in appendix 8E of the final rule TSD.

b. Total Owning Cost and Evaluators
In the January 2023 NOPR Analysis TSD, DOE used TOC evaluation rates as follows: 10 percent of liquid-immersed transformer purchases were concluded using TOC, and 0 percent of low-voltage dry-type and medium-voltage dry-type transformer purchases were concluded using TOC. DOE received comments from several stakeholders regarding the rates at which TOC are practiced.
NEMA and Prolec GE commented that the current percentage of transformers that are being purchased using TOC is estimated to be below 10 percent for both single-phase and three-phase transformers. (Prolec GE, No. 120 at p. 12; NEMA, No. 141 at p. 15) However, Howard commented that in 2022, its TOC adoption rate was in the 40-percent range for both single- and three-phase liquid-immersed distribution transformers. (Howard, No. 116 at p. 19) NRECA commented that many electric cooperatives are RUS borrowers and thus use RUS Bulletin 1724D-107, “Guide for Economic Evaluation of Distribution Transformers,” to calculate the cost of owning a transformer over its useful life using the TOC method. ^{162} NRECA added that given today's supply chain challenges, its members' primary concern is the availability of transformers, not the cost, and therefore DOE's estimation of the utilities using TOC is not representative of real-world experience. (NRECA, No. 98 at p. 7)
^{162} See: https://www.rd.usda.gov/sites/default/files/UEP_Bulletin_1724D-107.pdf.
Prolec GE, NEMA, NRECA, and Colorado Springs Utilities commented that the low usage of TOC was the implementation of DOE's current minimum efficiency levels (adopted in the April 2013 Standards Final Rule (78 FR 23335) with compliance required in 2016) due to the TOC formula becoming less relevant when defining the most cost-competitive transformer design option resulting in most customers are purchasing transformers based on lowest first-cost that meets the current DOE efficiency levels. (Prolec GE, No. 120 at p. 12; NEMA, No. 141 at p. 15; Colorado Springs Utilities, Public Meeting Transcript, No. 75 at p. 114; NRECA, No. 98 at p. 7)
WEC commented that the best interests of its customers would be served by allowing utilities to use their A and B factors to calculate efficiency requirements, as cost evaluation is unique to each utility. (WEC, No. 118 at p. 1) Rochester PU commented that it uses loss-evaluated transformers for 30-plus years and if amorphous transformers are the best choice based on its loss evaluation (which considers energy cost), then those are the transformers Rochester PU would purchase. (Rochester PU, Public Meeting Transcript, No. 75 at pp. 61-62)
Given the comments received, DOE has maintained the same modeling assumption in this final rule as it used in the January 2023 NOPR, where an estimated 10 percent of purchases are concluded using TOC. DOE notes however that this final rule is not prescriptive, and that distribution transformers can be designed to meet any combination of A and B values if the overall design meets the amended minimum efficiency standards.
Howard provided the fraction of sales that are concluded based on TOC. (Howard, No. 116 at p. 20) DOE applied the shipment weights per EMM region from Howard's data in DOE's customer choice model with an additional percentage assigned to random EMM regions as was done in the NOPR, and the entry for California split evenly between Northern and Southern California. DOE found that for consumers who evaluate based on TOC in DOE's modeling, they are limited to the EMM regions based on the weights shown in Table IV.16.

Band of Equivalents
In the August 2021 Preliminary Analysis TSD, DOE proposed the following definition for Band of Equivalents (BOE): as a method to establish equivalency between a set of transformer designs within a range of similar TOC. BOE is defined as those transformer designs within a range of similar TOCs. The range of TOC varies from utility to utility and is expressed in percentage terms. In practice, the purchaser would consider the TOC of the transformer designs within the BOE and would select the lowest first-cost design from this set.
NEMA commented that BOE is generally not used for low- or medium-voltage dry-type transformer purchases. (NEMA, No. 141 at p. 15) Based on this comment from NEMA, DOE maintained its approach from the NOPR where TOC and BOE are not applied to low- and medium-voltage distribution transformers.
Mulkey Engineering commented on the risks associated with following TOC “to the penny,” suggesting that a combination of TOC and BOE be used when evaluating transformer purchases. In addition to other experience-driven suggestions, Mulkey Engineering asserted a BOE rate within TOC of 10 percent. (Mulkey Engineering, No. 96 at pp. 1-2) NEMA commented that most utilities who use TOC methods also apply a band of equivalency ranging from 3-10 percent of the TOC, where the lowest first cost transformer in the band is purchased. (NEMA, No. 141 at p. 15) Finally, Prolec GE commented that BOE is used in less than half of the cases where a TOC formula is specified. (Prolec GE, No. 120 at p. 12)
Based on the comments received, DOE will maintain the definition as per the NOPR. Additionally, for this final rule, DOE included a BOE rate of 5 percent for those consumers who use TOC in the consumer choice model.

c. Non-Evaluators and First Cost Purchases
DOE defined those consumers who do not purchase based on TOC as those who purchase based on lowest first costs. DOE did not receive any comments regarding lowest first cost purchases and maintained the approach from the NOPR in this final rule.

4. Installation Cost
Installation cost includes labor, overhead, and any miscellaneous materials and parts needed to install the product. DOE used data from RSMeans to estimate the baseline installation cost for distribution transformers. ^{163} In the January 2023 NOPR TSD, DOE asserted that there would be no difference in installation costs between baseline and more efficient equipment. DOE also asserted that 5 percent of replacement installations would face increased costs over baseline equipment due to the need for site modifications. Stakeholders responded to DOE's assertions regarding installation costs as they related to the increases in efficiency proposed in the NOPR.
^{163} Gordian, RSMeans Online, www.rsmeans.com/products/online (last accessed Sept. 2023).

a. Overall Size Increase
Stakeholders had concerns over the increased size and weight of equipment due to amended efficiency standards, specifically that increased transformer size and weight would result in increased technical issues and increased costs when replacement transformers are installed in sensitive locations. (Cliffs, No. 105 at pp. 11-12; NEMA, No. 141 at p. 6; Highline Electric, No. 71 at pp. 1-2; Indiana Electric Co-Ops, No. 81 at p. 1; Southwest Electric, No. 87 at p. 3; Howard, No. 116 at pp. 24-25; Chamber of Commerce, No. 88 at p. 4; Pugh Consulting, No. 117 at p. 5; NRECA, No. 98 at p. 6; Entergy, No. 114 at p. 4; SBA, No. 100 at p. 6; WEC, No. 118 at p. 2; Portland General Electric, No. 130 at p. 4; Southwest Electric, No. 87 at pp. 2-3; Xcel Energy, No. 127 at p. 1; Idaho Power, No. 139 at pp. 5-6; APPA, No. 103 at p. 9; Schneider, No. 101 at p. 2; Powersmiths, No. 112 at pp. 4-5)
The Efficiency Advocates commented that any size-related impacts resulting from DOE's proposal are not expected to significantly impact transformer installations. The Efficiency Advocates commented that as of 2015, more than 4 million AM transformers had been sold globally, with about 600,000 installed in the United States, over 1 million in China, and 1.3 million in India—this number of installed global AM units has increased several-fold since 2015. The Efficiency Advocates estimated that over 90 percent of liquid-immersed transformers sold in Canada use AM. The Efficiency Advocates commented it understands that “well-designed AM transformers” are not meaningfully larger than current GOES transformers and noted that DOE's NOPR analysis considered the potential impact of increased transformer size on pole and vault installations. (Efficiency Advocates, No. 121 at pp. 6-7)
In response to these comments, the amended standard in this final rule shows the following increases in transformer size and weight shown in Table IV.17 through Table IV.19. The impact on liquid immersed transformer weight om amended standards is expected to be less than 10 percent for small (≤100 kVA) single-phase (overhead and surface mounts). For large (>100 kVA) single-phase the weight is expected to increase from 16 to 21 percent. For small three-phase (<500 kVA) the expected increase in weight and footprint (ft ^2 ) are 4 and 1 percent, respectively. For large (≥500 kVA) three-phase the expected increase in weight and footprint (ft ^2 ) are expected to be 2 and 1 percent, respectively; with the exception of three-phase liquid-immersed distribution transformers greater than 2500 kVA where ethe increases in the weight and footprint (ft ^2 ) are expected to be 25 and 8 percent, respectively.
DOE appreciates these general comments and refers to its responses below on specific installation cost concerns.

b. Liquid-immersed
NEMA, commented that the proposed amended standard would result in medium-voltage liquid- and dry-type unit weight increasing by 50 percent and generally result in 15-percent taller, wider, and deeper units compared to those designed to meet the current standards; and that tank diameters and/or tank heights increases of 15 percent or more will create new logistical challenges. (NEMA, No. 141 at p. 6). WEB and LBA also expressed concerns regarding the potential increased weights of transformers more generally. (WEG, No. 92 at p. 2; LBA, No. 108 at p. 3)
EEI and NEMA commented that the transportation, delivery, and handling of the new (heavier) equipment will also be impacted. EEI and NEMA commented that the increased size means fewer units per truck, with larger and heavier equipment requiring more trucks to move units to their installation locations. EEI and NEMA commented that for pole mounted transformers, new poles to support the weight will have to be sourced; for pad-mounted transformers, thicker and larger concrete pads will have to be poured. EEI and NEMA added that larger and heavier also means bigger boom cranes necessary to lift such equipment will need to be procured. (EEI, No. 135 at pp. 20-21; NEMA, No. 141 at p. 3)
Idaho Falls Power and Fall River commented that amorphous core transformers are larger in size and heavier per kW rating than their counterparts, sometimes by more than 40 percent, leading to issues related to space and weight, such as placement in existing vaults where clearances must be maintained for safety reasons, or placement on poles designed to hold a specific weight. (Idaho Falls Power, No. 77 at p. 1; Fall River, No. 83 at p. 2)
WEG commented that another major consideration, especially for urban areas, will be physical space requirements, as distribution transformers in major cities are often located in some variety of physical structure with specific limitations as to what size transformer can be installed. WEG commented that increased overall transformer size could drive a significant civil engineering issue in urban areas to accommodate transformers that meet these amended standards. (WEG, No. 92 at p. 2)
As shown in in Table IV.17 through Table IV.19, DOE expects the maximum weight increase from amended standards to be no greater 25 percent for three-phase liquid-immersed transformer over 2500 kVA, representing less than 0.5 percent of unit shipped. This is much less than 50 percent increase indicated by NEMA. DOE notes that for the vast majority of unit shipped (small single-phase up to and including 100 kVA), representing 91 percent of single-phase shipments, the impact on weight is an increase of between 1 and 2 percent.

c. Overhead (Pole) Mounted Transformers
Highline Electric provided information describing its fleet of distribution transformers and limitations, including approximately 250 banks of three 75 kVA pole-mount transformers and 500 banks of three 50 kVA pole-mount transformers. Highline Electric commented that it currently does not deploy larger than 75 kVA pole-mount transformers due to pole load limitations and the proposed amended standards would result in new, standards compliant, 50 kVA transformers with a weight like existing baseline 75 kVA transformers, and compliant 75 kVA transformers with a weight more than a baseline100 kVA pole-mount unit. Highline Electric added that it discontinued use of 100 kVA pole-mount units decades ago after outage records indicated such installations were prone to unacceptable rates of pole failure. (Highline Electric, No. 71 at pp. 1-2)
Further, Highline Electric commented that if transformer weights are increased by 20-40 percent, compliant 75 kVA transformers could not be installed on Highline Electric's standard class of poles. Highline Electric commented it would instead have to: (1) Utilize pole-mount transformers that predate the proposed amended standards, which would require a two-man crew with a material handler truck plus a few hours of labor and can be done proactively or reactively during outage conditions; (2) Convert to pad-mount transformers, which would require a 3-plus man crew, a digger derrick truck, and enough hours of labor that such an operation could only be completed proactively as it would require unacceptably long outage restoration times; or, (3) Replace the existing pole to a much heavier-class of pole, which would require a 3-plus man crew, a digger derrick truck, and enough hours of labor that such an operation could only be completed proactively as it would require unacceptably long outage restoration times—this option assumes that the heavier-class of pole is available at the time of need. (Highline Electric, No. 71 at p. 2)
Idaho Power commented that it considers the 25-percent estimate for pole replacements to be too low, as it is likely that every transformer larger than 100 kVA on its distribution system would require an upsized pole. Idaho Power commented this may also be the case for 50 kVA and 75 kVA transformers. Idaho Power recommended that DOE consider increasing the 25-percent replacement number used in 2013 to better reflect the impact of the additional weight from amorphous core transformers on pole replacements. (Idaho Power, No. 139 at pp. 5-6) Additionally, Idaho Power stated it had designs for a few pole-mounted transformers with amorphous cores, noting that for 50 kVA and smaller transformers, the additional weight is not enough to increase the installation cost, but for transformers 100 kVA and larger, the weights increased between 40 and 60 percent and will likely require higher class poles resulting in increased installation costs. (Idaho Power, No. 139 at p. 5)
Alliant Energy commented that DOE's proposal presents implementation and installation challenges given the greater size and weight of amorphous core distribution transformers, which may require additional pole replacement, larger trucks for transport, and the use of cranes for installation. (Alliant Energy, No. 128 at p. 3)
Howard and Chamber of Commerce commented that the proposed amended standards may require the upgrading and/or full replacement of the brackets as IEEE standards stipulate that the top support lug must be at least five times the transformer weight. Howard and Chamber of Commerce commented that for most manufacturers, the current transformer weight limit for support lug A is about 1000 lbs., B is about 3000 lbs., and Big B is 4000 lbs. Further, Howard and Chamber of Commerce commented that the new designs under this NOPR would also increase tank diameters, moving the center of gravity further away from the pole interface and increasing the moment force on the pole bracket. (Howard, No. 116 at pp. 24-25; Chamber of Commerce, No. 88 at p. 1) Highline Electric commented that pole replacements are not directly attributable to the larger kVA capacity, but rather are attributable to the weight of these larger kVA units. Highline Electric commented that poles are not rated to hold certain amounts of kVA capacity in the air; they are rated to hold certain pounds in weight and certain pounds in wind-loading (cross-sectional area of a transformer bank). (Highline Electric, No. 71 at p. 1)
Southwest Electric commented that the proposed amended standard for single-phase designs, which typically include simpler cooling capability (fins versus cooling plates), will result in percent increases in tank and conductor weights exceeding that of 3-phase, raising the significant problem that most single-phase transformers are mounted overhead via utility poles, scaffolding, or some other platform. Southwest Electric commented that the increased weight of NOPR-compliant transformers could lead to further potential outages, pushing these annual costs even higher. (Southwest Electric, No. 87 at p. 3)
EEI, Entergy, and Pugh Consulting commented that the electric utility industry is experiencing constraints with wood pole supplies, especially poles with higher strength capacities, and an increase in demand for stronger poles could cause additional challenges. (Entergy, No. 114 at p. 4; Pugh Consulting, No. 117 at p. 5; EEI, No. 135 at pp. 21-24)
DOE's analysis at the amended standard levels indicate the following weight increases for overhead mounted distribution transformers. DOE's engineering and LCC analysis of overheard transformers are conducted for the representative units discussed in section IV.C.1, representative unit 2 (25 kVA) and representative unit 3 (500 kVA). DOE has scaled the weights determined in the engineering, and selected in the LCC model to the other common capacities shown in Table IV.17. These show that the increased weight under amended standards is projected to be modest, under 10 percent for transformers up to and including 100 kVA in capacity—which is approximately 95 percent of all single-phase shipments (in terms units) and 99 percent of overhead shipments (in terms of units). Further, the projected weights, except for 833 kVA, which are less than 0.05 percent of annual overhead units shipped, are not expected to change the application of the support lugs mentioned by NEMA from current practices. ^{164} The modest weight increases are below the supplied thresholds for premature pole change outs supplied by Highline Electric and Idaho Power and consequently are not expected results in undue burden of requiring new, higher-grade poles.
^{164} Overhead transformers at 833 kVA represent less than 0.01 precent of units shipped. See section G for detailed shipments projections.
DOE cannot directly comment on the availability of wooden poles at higher strength classes. The comments from EEI, Entergy, and Pugh Consulting did not state which classes of poles they considered commonly used, or which classes of poles are considered higher strength. DOE reiterates that the increase in transformer weight determined in its analysis is expected to be sufficiently modest (estimated to be less than 20 percent), that it will not likely disrupt the current wooden pole supply chains, and not in the 40 to 60-percent range suggested by stakeholders. There is insufficient information to justify increased installation costs given the modest projected increase in equipment weight resulting from amended standards, however, DOE recognizes the uncertainty surrounding installation costs because it is a complex issue. DOE's technical analysis in appendix 8F of this final rule TSD shows there to be minimal load bearing impact on the structures used to mount overhead distribution transformers resulting from amended standards. However, each utility's distribution system is unique with different equipment build-outs of different vintages. Given the heterogeneous nature of distribution systems it is not possible for DOE to account for every potential hypothetical installation circumstance. To account for the uncertainty faced by distribution utilities raised in the comments above, DOE has increased the fraction of installations that will face additional costs from 5 percent in the January 2023 NOPR to 50 percent when the weight increase over current baseline equipment is greater than 10 percent.
NRECA commented that DOE analysis assumes like-for-like pole replacements, which is misguided. NRECA commented it expects that more transformer replacements will be necessary to allow for greater-capacity transformers due to electrification, thus requiring larger poles. (NRECA, No. 98 at p. 6)
In response to NRECA, for the purpose of estimating the cost and benefits to consumers from a modeling perspective DOE needs to bound the issue of what is considered a replacement versus new installation. While NRECA comments that it expects future replacements to be of greater capacity than what is currently installed, NRECA did not provide any information on what it considers the current typical capacity, and what they'd be replaced with in the future. DOE can agree with NRECA that, in practice, replacing a 25 kVA overhead with a new 50 kVA to maintain current levels of service can reasonably be considered a replacement. However, DOE maintains that, for example, installing a 167 kVA in the place of a 25 kVA to meet new service would be a new installation, as it would require additional planning, secondary conductors, and likely a new structure (pole).

Replacement Costs
Idaho Power typically charges between $3,500-5,000 for a pole replacement. (Idaho Power, No. 139 at p. 6) SBA provided cost estimates for wooden poles range anywhere from $500 to $1,400 per pole depending on labor and material shipping costs for small utilities. (SBA, No. 100 at p. 6) WEC commented that it does not install transformers over 4,500 lbs. on a single pole. To change to a two-pole structure will cost from $10,000 to $15,000 per transformer, assuming there is room for a two-pole structure which is not viable in all locations. WEC further commented it would cost anywhere from $2,000 to $10,000 to change out the pole for a single transformer depending on its location and what other equipment is installed on the pole, which could lead to increased costs beyond these estimates. (WEC, No. 118 at p. 2)
Based on the comments from Idaho Power, SBA and WEC DOE examined the values it used in the NOPR for the cost of pole replacement. DOE derived its values based on the RSMeans 2023, and found that the average price of a new single-pole installation ranged in cost, equipment and labor, (excluding profit, and excavation) ranged from $504 to $3,125 for 30 and 70 foot treated poles, respectively. The data from RSMeans indicates a strong relationship between pole length and cost, and did not include the additional cost for excavation that would be incurred by a utility. While the stakeholders did not provide the pole length or grades associated with the supplied costs, which DOE would expect such costs to vary on a utility-by-utility bases. Based on the information provided by stakeholders and RSMeans DOE has updated its pole replacement cost distribution for this final rule, which is a triangular distribution, for single-pole structures: low: $2,025; mode: $4,012; high: $5,999. And for multi-pole structures: low: $5,877; mode: $11,388; high: $16,899.

d. Surface (Pad) Mounted Transformers
WEC and Xcel Energy commented that pad-mounded 167 kVA single-phase transformers will roughly increase in size (1-4 inches) under the proposed amended standards, and that this increase of the dimensional footprint will be incompatible with pad and fiberglass box-pad foundations that the current transformers are using and have used for many decades. WEC and Xcel Energy stated that this will make it more difficult to use existing underground infrastructure (trench and connections) for transformer changeouts and may result in extra digging to install a compatible fiberglass box and pad. (Xcel Energy, No. 127 at p. 1; WEC, No. 118 at pp. 2-3)
Southwest Electric commented that the proposed amended standard for 3-phase designs will result in a significant weight increase, exceeding the weights the pads were designed to support—especially in areas where seismic zoning requires additional anchoring. (Southwest Electric, No. 87 at pp. 2-3)
Howard commented that it and other manufacturers have difficulty meeting some utilities' pad dimensions at the current efficiency levels. Howard commented it had taken exception to required footprint dimensions in the past for 100 kVA and above dual voltage and 167 kVA and above straight voltage transformers for many utilities. Regarding three-phase pads, Howard commented that utilities may have two or three different pad sizes, and a bigger footprint for transformers will require utilities to utilize large pad sizes. (Howard, No. 116 at p. 21)
In response to these comments, DOE's analysis shows an increase in weight and footprint area of 7 and 3 percent, respectively, for single-phase surface-mounted liquid-immersed distribution transformers up to and including 100 kVA, and an increase in weight and footprint area of 18 and 19 percent, respectively, for single-phase liquid-immersed surface mounted distribution transformers greater than100 kVA designed to meet the current standard, see Table IV.17. Additionally, DOE's analysis shows that that the impacts to weight and footprint area of three-phase surface mounted distribution transformers to be 4 and 1 percent, respectively, for capacities up to 500 kVA, while for capacities equal to or greater than 500 kVA the increase in weight and footprint area is 2 and 1 percent (5 and 1 percent for 500 kVA) over current standards, see Table IV.19. Commenters did not provide enough information to directly model the costs of increasing pad, or fiberglass box size; however, for some of the capacity ranges the increase in weight, particularly for single-phase surface-mounted distribution transformers over 100 kVA, may be enough to trigger the need to use additional materials or different crews to complete installations. While the specifics are not available to DOE, to capture these additional costs DOE increased the fraction of installation from 5 percent in the NOPR (88 FR 1777) to 50 percent in this final rule.

e. Logistics and Hoisting
Chamber of Commerce, EEI, Portland General Electric, WEC, and Southwest Electric commented that heavier transformers may trigger transportation and hoisting considerations and challenges, likely requiring flatbed trucks, additional permitting, and cranes to install. These commenters stated that weight and access restrictions for roads and certain areas, especially in rural places, may create further challenges for replacements of transformers. (Portland General Electric, No. 130 at p. 4; Southwest Electric, No. 87 at pp. 2-3; Chamber of Commerce, No. 88 at pp. 4-5; EEI, No. 135 at pp. 24-28; WEC, No. 118 at pp. 2-3) SPA commented that small utilities were concerned whether their current equipment (namely trucks and lifts) will be able to handle increased sizes and weights. (SBA, No. 100 at p. 6) Chamber of Commerce commented that larger transformers will consume more storage space on an individual basis than current GOES models, thereby reducing the number of units that can be held in reserve to support system restoration efforts. (Chamber of Commerce, No. 88 at pp. 4-5)
As discussed in sections IV.F.4.c and IV.F.4.d of this document, DOE's analysis shows that the projected increase in size and weight of transformers under amended standards to be modest, which DOE believes will not be disruptive to current logistics and hoisting procedures.

f. Installation of Ancillary Equipment: Gas Monitors and Fuses
APPA insinuated that DOE did not account for the costs associated with more than 10 million gas monitors, which would equate to $25 billion in additional costs, and that these additional costs alone would exceed the $13 billion of economic benefits cited in the NOPR. APPA further stated that DOE's analysis did not consider the additional cost of labor to remove and install the gas monitor and the cost of a replacement transformer. (APPA, No. 103 at p. 11)
DOE disagrees with the assertions from APPA that there would be an additional cost of $25 billion to consumers of distribution transformers for the removal and installation of gas monitor or other ancillary equipment not related to the transformer's efficiency. A gas monitor is a device installed by the customer that monitors the conditions of the transformer's internal insulating fluid to help predict future equipment faults. Due to the additional cost, they are typically installed by utilities on larger capacity (kVA) transformers for operational reliability, with their installation occurring regardless of the efficiency of the transformer. Further, DOE has never prescribed the use of gas monitors for distribution transformers; gas monitors are installed at the discretion of each individual utility, and outside the scope of DOE's authority. DOE has not included the use of gas monitoring equipment in this final rule.
APPA commented that amorphous core transformers experience higher inrush currents, creating the need for external protective devices ( e.g., fuses) to be reviewed and changed. APPA commented that the amount of core steel significantly increases, creating a much heavier device that could force the utility to rerate framing hardware while increasing pole size and class and potentially increasing costs in a way that DOE has not addressed. (APPA, No. 103 at p. 15)
DOE's installation costs analysis includes increasing installation costs as a function of transformer weight. As generally indicated by stakeholders through their comments, there are many factors and costs that are unique to each utility's operating procedures; as such, these factors are beyond the practicality of DOE to model in detail. As discussed in section IV.F.4.c of this document, DOE increased the fraction of installations which would incur additional cost under amended standards from 5 to 50 percent to account for the circumstances described by APPA. This fraction is constant at all considered efficiency levels above the baseline.

g. Low-Voltage Dry-Type
Increased floor space to store the LVDT units—product is commercially available off the shelf (COTS) device (Schneider, No. 101 at p. 15) Powersmiths commented that an amended standard for LVDT, which requires amorphous cores would, for retrofits, to be successful the replacement transformers. In addition to customization to meet footprint needs, they will require design changes to match terminal layout, impedance. temperature rise and k-rating. These accommodations, while possible today with GOES core transformers, will further increase the level of difficulty of retrofitting with amorphous-based transformers. Many older transformers are closer to people than newer buildings so any increase the audible noise is a big issue—noise is one of the biggest complaints from users, itself driving retrofit projects.” (Powersmiths, No. 112 at p. 4-5)
To alleviate concerns from Schneider and Powersmiths regarding potential installation issues arising from moving to amended standard that are achievable only using amorphous core materials, the amended standards in this final rule are set at level that is achievable with GOES core materials, TSL 3.

5. Annual Energy Consumption
For each sampled customer, DOE determined the energy consumption for a distribution transformer at different efficiency levels using the approach described previously in section IV.E of this document.

6. Energy Prices
DOE derived average and marginal electricity prices for distribution transformers using two different methodologies to reflect the differences in how the electricity is paid for by consumers of distribution transformers. For liquid-immersed distribution transformers, which are largely owned and operated by electric distribution companies who purchase electricity from a variety of markets, DOE developed an hourly electricity cost model. For low- and medium-voltage dry-type, which are primarily owned and operated by commercial and industrial entities, DOE developed a monthly electricity cost model.
Fall River commented that the amended standards would in turn drive up costs, which would ultimately be borne by rate payers where energy burdens are already growing at a severe rate. (Fall River, No. 83 at p. 2) DOE notes that any amended standard is determined based on the specific criteria discussed in section III.F.1 of this document, and in the context of Fall River's comment criteria III.F.1.b of this document. The results in section V.B.1.a of this document show that most consumers are projected to show a net benefit from amended standards.
DOE did not receive any further comments regarding its electricity costs analysis and maintained the approach used in the NOPR for this final rule.

7. Maintenance and Repair Costs
Repair costs are associated with repairing or replacing product components that have failed in an appliance; maintenance costs are associated with maintaining the operation of the product. Typically, small incremental increases in product efficiency produce no, or only minor, changes in repair and maintenance costs compared to baseline efficiency products. In the NOPR analysis, DOE asserted that maintenance and repair costs do not increase with transformer efficiency.
Cliffs commented that the costs of the rule would not outweigh the benefits if the substantial increase in price and maintenance requirements for amorphous metal cores were properly accounted for. (Cliffs, No. 105 at p. 16) However, Cliffs did not specify how amorphous metal cores increase the maintenance costs of a transformer nor did it provide any data to showcase these higher costs. DOE understands that most distribution transformers incur few maintenance or repairs throughout their product lifetime and typically none to the transformer core. As discussed in sections IV.A.4.a and IV.G.3 of this document, both amorphous and GOES cores can be rewound and rebuilt. DOE does not have any data to support that amorphous core transformers would be subject to substantially higher maintenance costs than GOES core transformers.
DOE did not receive any comments on this assertion and continued its assumptions that maintenance and repair costs do not increase with transformer efficiency for this final rule analysis.

8. Transformer Service Lifetime
For distribution transformers, DOE used a distribution of lifetimes, with an estimated average of 32 years and a maximum of 60 years. ^{165} 78 FR 23336, 23377. DOE received the following comments on transformer service lifetime. Prolec GE and NEMA commented that the current estimated transformer lifetime of 32 years is adequate, as distribution transformers are extremely durable. However, Prolec GE and NEMA noted, certain factors might accelerate transformer replacement rates, such as increased trends in transformer loading practices due to electrification and decarbonization initiatives. (Prolec GE, No. 120 at p. 13; NEMA, No. 141 at p. 16) APPA commented that GOES service transformers are typically run to failure (no operations and maintenance costs) and last 40 to 70 years and that amorphous distribution transformers are likely to have a lifetime of 20 to 40 years. (APPA, No. 103 at p. 11)
^{165} Barnes, P. R., Van Dyke, J. W., McConnell, B. W. & Das, S. Determination Analysis of Energy Conservation Standards for Distribution Transformers. (Oak Ridge National Laboratory, 1996).
In response to Prolec GE, NEMA, and APPA, DOE characterizes transformer lifetimes as distribution of the possibility of equipment failure in each year up to the estimated maximum lifetime—in this case 60 years—to account for circumstances where the transformer either fails prematurely (degradation from heat or otherwise) or is prematurely removed from service. APPA's range of service lifetimes for GOES and amorphous distribution transformers overlaps considerably with DOE's estimates. Additionally, DOE finds the APPA discussion from Australia regarding high amorphous failure rates to be excessively speculative, based on anecdotal discussion with unknown persons regarding an unknown sample size of distribution transformers of unknown vintage in a jurisdiction that operates on a fundamentally different frequency (50 hertz versus 60 hertz), and presented without citation, data, or analysis. For this final rule DOE is maintaining the distribution of service lifetimes from the NOPR; the distribution is shown in Table IV.20.

9. Discount Rates
The discount rate is the rate at which future expenditures are discounted to estimate their present value. DOE employs a two-step approach in calculating discount rates for analyzing customer economic impacts ( e.g., LCC). The first step is to assume that the actual cost of capital approximates the appropriate customer discount rate. The second step is to use the capital asset pricing model (CAPM) to calculate the equity capital component of the customer discount rate. For this final rule, DOE estimated a statistical distribution of commercial customer discount rates that varied by distribution transformer category, by calculating the cost of capital for the different varieties of distribution transformer owners.
DOE's method views the purchase of a higher-efficiency appliance as an investment that yields a stream of energy cost savings. DOE derived the discount rates for the LCC analysis by estimating the cost of capital for companies or public entities that purchase distribution transformers. For private firms, the weighted average cost of capital (WACC) is commonly used to estimate the present value of cash flows to be derived from a typical company project or investment. Most companies use both debt and equity capital to fund investments, so their cost of capital is the weighted average of the cost to the firm of equity and debt financing, as estimated from financial data for publicly traded firms in the sectors that purchase distribution transformers. ^{166} As discount rates can differ across industries, DOE estimates separate discount rate distributions for a number of aggregate sectors with which elements of the LCC building sample can be associated.
^{166} Previously, Damodaran Online provided firm-level data, but now only industry-level data is available, as compiled from individual firm data, for the period of 1998-2018. The data sets note the number of firms included in the industry average for each year.
DOE did not receive any comments in the NOPR to its approach to determining discount rates and maintained the same approach in this final rule. The discount rates applied to consumers of liquid-immersed distribution transformers are shown in Table IV.21, and those applied to low- and medium-voltage dry-type distribution transformers are shown in Table IV.22.
See chapter 8 of the NOPR TSD for further details on the development of consumer discount rates.

10. Energy Efficiency Distribution in the No-New-Standards Case
To accurately estimate the share of consumers that would be affected by a potential energy conservation standard at a particular efficiency level, DOE's LCC analysis considered the projected distribution (market shares) of product efficiencies under the no-new-standards case ( i.e., the case without amended or new energy conservation standards) in the compliance year. This approach reflects the fact that some consumers may purchase products with efficiencies greater than the baseline levels in the absence of new or amended standards. To determine an appropriate basecase against which to compare various potential standard levels, DOE used the purchase-decision model described in section IV.F.3 of this document, where distribution transformers are purchased based on either lowest first cost or lowest TOC (with BOE). In the no-new-standards case, distribution transformers are chosen from among the entire range of available distribution transformer designs for each representative unit simulated in the engineering analysis based on this purchase-decision model with the core material constraints discussed in section IV.F.3.a of this document. This selection is constrained only by purchase price in most cases (90 percent, and 100 percent for liquid-immersed and all dry-type transformers, respectively) and reflects the MSPs of the available designs determined in the engineering analysis in section IV.C of this document.
DOE did not receive any comments regarding its methodology of determining its energy efficiency distribution in the no-new-standards case and maintained the methodology from the NOPR in this final rule.

11. Payback Period Analysis
The PBP is the amount of time (expressed in years) it takes the consumer to recover the additional installed cost of more-efficient products, compared to baseline products, through energy cost savings. PBPs that exceed the life of the product mean that the increased total installed cost is not recovered in reduced operating expenses.
The inputs to the PBP calculation for each efficiency level are the change in total installed cost of the product and the change in the first-year annual operating expenditures relative to the baseline. DOE refers to this as a “simple PBP” because it does not consider changes over time in operating cost savings. The PBP calculation uses the same inputs as the LCC analysis when deriving first-year operating costs.
As noted previously, EPCA establishes a rebuttable presumption that a standard is economically justified if the Secretary finds that the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the first year's energy savings resulting from the standard, as calculated under the applicable test procedure. (42 U.S.C. 6295(o)(2)(B)(iii)) For each considered efficiency level, DOE determined the value of the first year's energy savings by calculating the energy savings in accordance with the applicable DOE test procedure, and multiplying those savings by the average energy price projection for the year in which compliance with the amended standards would be required.
Carte commented that a study found that the increase to 2016 transformer efficiencies will take approximately 80 years to payback (no citation provided) and questions what the PBP would be for the proposed standard level. (Carte, No. 140 at pp. 6-7) In response to Carte, DOE acknowledges that some consumers may be negatively affected by amended standards due to the details of how they operate their equipment. For example, consumers with low electricity costs may take longer to realize the benefits from more efficient equipment than might be seen from consumers with higher electricity costs. DOE's LCC analysis uses a Monte Carlo simulation to incorporate uncertainty and variability into the analysis precisely to capture and quantify the differences in costs and benefits to consumers Nationally. Carte's comment did not provide details for DOE to alter its LCC and PBP analysis. The PBPs of this final rule is shown in section V.C.1 through V.C.3 of this document.

G. Shipments Analysis
DOE uses projections of annual product shipments to calculate the national impacts of potential amended or new energy conservation standards on energy use, NPV, and future manufacturer cash flows. ^{167} The shipments model takes an accounting approach, tracking market shares of each product class and the vintage of units in the stock. Stock accounting uses product shipments as inputs to estimate the age distribution of in-service product stocks for all years. The age distribution of in-service product stocks is a key input to calculations of both the NES and NPV, because operating costs for any year depend on the age distribution of the stock.
^{167} DOE uses data on manufacturer shipments as a proxy for national sales, as aggregate data on sales are lacking. In general, one would expect a close correspondence between shipments and sales.
As in the NOPR, for this final rule DOE projected distribution transformer shipments for the no-new standards case by assuming that long-term growth in distribution transformer shipments will be driven by long-term growth in electricity consumption. For this final rule, DOE did not receive any comments regarding initial shipments estimates presented in the NOPR—which were based on data from the previous final rule, data submitted to DOE from interested parties and confidential manufacturer interviews. These initial shipments are shown for the assumed compliance year (2029), by distribution transformer category, in Table IV.23 through Table IV.25. DOE developed the shipments projection for liquid-immersed distribution transformers by assuming that annual shipments growth is equal to growth in electricity consumption (sales) for all sectors, as given by the AEO2023 forecast through 2050. DOE's model assumed that growth in annual shipments of dry-type distribution transformers would be equal to the growth in electricity consumption for COMMERCIAL AND INDUSTRIAL sectors, respectively. The model starts with an estimate of the overall growth in distribution transformer capacity, and then estimates shipments for particular representative units and capacities, using estimates of the recent market shares for different design and size categories.
Idaho Power commented that it supported DOE's approach and believed it was still valid. (Idaho Power, No. 139 at p. 6)

1. Equipment Switching
In the January 2023 NOPR, DOE stated MVDTs can be used as replacements for liquid-immersed distribution transformers, but DOE has historically considered it as an edge case due to the differences in purchase price as well as consumer sensitivity to first costs. At the time it proposed amended standards, DOE did not have sufficient data to model the substitution of liquid-immersed distribution transformers with MVDTs. DOE requested comment on the topic of using MVDT as a substitute for liquid-immersed distribution transformers. 88 FR 1754, 1782. NEMA responded that this is not typical, and these two categories of distribution transformers coexist in the market. (NEMA, No. 141 at p. 16) Additionally, Prolec GE commented that switching tended to be with three-phase substation transformers for indoor applications. (Prolec GE, No. 120 at p. 13)
In response to comments from NEMA and Prolec GE, DOE did not include the possible replacement of liquid-immersed distribution transformers with MVDT or vice versa in its analysis of this final rule.

2. Trends in Distribution Transformer Capacity (kVA)
In response to the August 2021 Preliminary Analysis, NEMA commented that as consumer demand increases due to migration to all-electric homes and buildings, it stands to reason that kVA sizes will increase over time as infrastructure upgrades capacity to serve these consumer demands. Likewise, NEMA commented that investments in renewable energy generation would cause changes to transformer shipments, unit sizes, and selections, and that DOE should examine non-static capacity scenarios, where kVA of units by category increases over time as NEMA members express growth in average kVA of ordered units over time in recent years, presumably due to increased electrification of consumer and industrial applications. 88 FR 1722, 1782. In response to the NOPR, NEMA further commented that roughly 15 percent of the low-voltage commercial market is increasing their distribution capacity sizes, going from 500 kVA to 1,000 or 1,500 kVA. (NEMA, No. 141 at p. 16) Additionally, DOE has found evidence that a similar shift in transformer capacity occurs with liquid-immersed distribution transformer to meet increasing loads. ^{168} DOE's approach to shifting capacities is discussed in section E.3.a, Idaho Power commented it believes the base data used in the April 2013 Standards Final Rule was scaled from 1992 and 1995 data, and there have been many energy efficiency standards that have been incorporated over the last 30 years. Idaho Power recommended that DOE consider updating the standard to reflect current loading data and include advanced data collection methods that provide more granular data. Idaho Power added that many power companies have automated meter read data that could be leveraged for better analysis. (Idaho Power, No. 139 at p. 5)
^{168} Dahal, S, Aswami D, Geraghty M, Dunckley, J. Impact of Increasing Replacement Transformer Sizing on the Probability of Transformer Overloads with Increasing EV Adoptions. 36th International Electric Vehicle Symposium and Exhibition Sacramento. California, USA, June 2023.
DOE agrees with Idaho Power's comments that since the CBECS last included monthly demand and energy use profiles for respondents in 1992 and 1995 editions that many energy efficiency standards have been promulgated. For its dry-type analysis, DOE used the hourly load data for COMMERCIAL AND INDUSTRIAL customers from data provided to the IEEE TF (from 2020 and 2021) to scale these monthly values in its loading analysis for low-, and medium-voltage dry-type distribution transformers ( see chapter 7 of this final rule TSD). DOE is aware that many utilities meter their customers using real-time meters; however, DOE does not have the authority to demand such data from said utilities. Instead, DOE must rely on such industry initiatives such as the IEEE TF or individual companies to voluntarily come forward with data.

3. Rewound and Rebuilt Equipment
APPA estimated that more than 15 percent of transformers used Nationally are rebuilt/rewound units. These units would have been rebuilt/rewound by the owning utility or as a service performed by rewinding business. (APPA, No. 103 at p 11; NEMA, No. 141 at p. 15) Howard and APPA commented that rewinding was a common occurrence (especially for units greater than 300 kVA) and that the service life could be extended up to 60 years. (APPA, No. 103 at p. 11; Howard, No. 116 at p. 21) However, NEMA responded that rebuilding, as they understood, did not typically occur with liquid-filled distribution transformers and was undertaken typically as a consequence of equipment failure unrelated to end of life. NEMA further commented that to its knowledge, no one was rebuilding low-voltage distribution transformers. (NEMA, No. 141 at p. 15)
APPA continued that because most of a transformer's parts can be reused when rewinding (or when other repairs are made), it is possible that a new core could be installed in the old transformer, that costs could be lower, and that lead times could be currently shorter than purchasing new equipment. However, APPA stated that the rewinding equipment used for GOES core transformers is incompatible with amorphous core transformers, and for amorphous transformers the rewinding process is more complex (time-consuming) and therefore more expensive, resulting in a loss of benefit from rewinding to individual utilities and cutting the total available capacity of transformers. (APPA, No. 103 at pp. 11-12) Also, Idaho Power commented that it has refurbished some transformers and returned them to service. Idaho Power stated that this decision is based on reduced lead time and availability rather than cost, which is somewhat close between new and refurbished transformers. Idaho Power stated that its refurbished units are put back into inventory and used according to their nameplate data. (Idaho Power, No. 139 at p. 7)
Despite the contradictory statements from NEMA and APPA, DOE is aware that transformer rewinding/repair is a service available to utilities, either as an “in-house” service or at an external repair shop that provides an additional avenue for utilities to maintain transformer stocks (as indicated by Idaho Power). DOE has viewed the rewind/repair services as additive and not in direct competition with new distribution transformer manufacturers. While APPA asserts that amorphous core rewinding may be more complex and diminishes the value of rewinding these transformers, DOE understands that rewinding this equipment is still possible and that a shift to amorphous core transformers does not negate the value of these services. Additionally, this final rule can be met with GOES core materials for approximately 90 percent of projected annual units shipments.
Regarding APPA's comment about reusing transformer parts to potential reduce lead times, DOE notes that the transformer rebuilding/rewinding market has historically been relatively small. Rebuilding a distribution transformer requires additional labor (because labor is required both to deconstruct the transformer and rebuild it) that has made purchasing a new distribution transformer the preferred option when replacing a failed transformer. While recently there has been an uptick in transformer rebuilds, that is primarily a function of long lead times for new transformers and likely temporary as the transformer market recalibrates. Further, in response to Howard, as rewound equipment falls outside the scope of DOE authority, they are not considered in this final rule.

H. National Impact Analysis
The NIA assesses the national energy savings (NES) and the NPV from a national perspective of total consumer costs and savings that would be expected to result from new or amended standards at specific efficiency levels. ^{169} (“Consumer” in this context refers to consumers of the product being regulated.) DOE calculates the NES and NPV for the potential standard levels considered based on projections of annual product shipments, along with the annual energy consumption and total installed cost data from the energy use and LCC analyses. For the present analysis, DOE projected the energy savings, operating cost savings, product costs, and NPV of consumer benefits over the lifetime of distribution transformers sold from 2029 through 2058.
^{169} The NIA accounts for impacts in the 50 states and U.S. territories.
DOE evaluates the impacts of new or amended standards by comparing a case without such standards with standards-case projections. The no-new-standards case characterizes energy use and consumer costs for each product class in the absence of new or amended energy conservation standards. For this projection, DOE considers historical trends in efficiency and various forces that are likely to affect the mix of efficiencies over time. DOE compares the no-new-standards case with projections characterizing the market for each product class if DOE adopted new or amended standards at specific energy efficiency levels ( i.e., the TSLs or standards cases) for that class. For the standards cases, DOE considers how a given standard would likely affect the market shares of products with efficiencies greater than the standard.
DOE uses a spreadsheet model to calculate the energy savings and the national consumer costs and savings from each TSL. Interested parties can review DOE's analyses by changing various input quantities within the spreadsheet. The NIA spreadsheet model uses typical values (as opposed to probability distributions) as inputs.
Table IV.26 summarizes the inputs and methods DOE used for the NIA analysis for the final rule. Discussion of these inputs and methods follows the table. See chapter 10 of the final rule TSD for further details.

1. Equipment Efficiency Trends
A key component of the NIA is the trend in energy efficiency projected for the no-new-standards case and each of the amended standards cases. Section IV.F.3 of this document describes how DOE developed an energy efficiency distribution for the no-new-standards case for each of the considered equipment classes for the year of anticipated compliance with an amended or new standard. As discussed in section IV.F.3 of this document, DOE has found that the vast majority of distribution transformers are purchased based on first cost. For both the no-new-standards case and amended standards case, DOE used the results of the consumer choice mode in the LCC, described in section IV.F.3 of this document, to establish the shipment-weighted efficiency for the year potential standards are assumed to become effective (2029). For this final rule, despite the availability of a wide range of efficiencies, DOE modelled that these efficiencies would remain static over time because the purchase decision is largely based on first costs ( see section IV.F.3 of this document) and DOE's application of constant future equipment costs ( see section IV.F.1 of this document).

2. National Energy Savings
The national energy savings analysis involves a comparison of national energy consumption of the considered products between each TSL and the case with no new or amended energy conservation standards. DOE calculated the national energy consumption by multiplying the number of units (stock) of each product (by vintage or age) by the unit energy consumption (also by vintage). DOE calculated annual NES based on the difference in national energy consumption for the no-new-standards case and for each higher-efficiency standard case. DOE estimated energy consumption and savings based on site energy and converted the electricity consumption and savings to primary energy ( i.e., the energy consumed by power plants to generate site electricity) using annual conversion factors derived from AEO2023. For natural gas, primary energy is the same as site energy. Cumulative energy savings are the sum of the NES for each year over the timeframe of the analysis.
Use of higher-efficiency equipment is occasionally associated with a direct rebound effect, which refers to an increase in utilization of the equipment due to the increase in efficiency and its lower operating cost. A distribution transformer's utilization is entirely dependent on the aggregation of the connected loads on the circuit the distribution transformer serves. Greater utilization would result in greater PUL on the distribution transformer. Any increase in distribution transformer PUL is coincidental and not related to rebound effect. NEMA and Howard agreed that a rebound effect is not needed for distribution transformers analysis. (NEMA, No. 141 at p. 16; Howard, No. 116 at p. 22) Howard additionally speculated that a possible caveat to this is that utility companies could conceivably be inclined to increase the load on more efficient transformers. (Howard, No. 116 at p. 22)
For this final rule, DOE has maintained the approach used in the NOPR and has not applied an additional rebound effect in the form of additional load. DOE accounts for incidental load growth on the distribution transformer resulting from additional connections not related to the rebound effect due to increased equipment efficiency in the LCC analysis in the form of future load growth. See section 0 for more details on DOE approach to load growth.
In 2011, in response to the recommendations of a committee on “Point-of-Use and Full-Fuel-Cycle Measurement Approaches to Energy Efficiency Standards” appointed by the National Academy of Sciences, DOE announced its intention to use FFC measures of energy use and greenhouse gas and other emissions in the national impact analyses and emissions analyses included in future energy conservation standards rulemakings. 76 FR 51281 (Aug. 18, 2011). After evaluating the approaches discussed in the August 18, 2011 notice, DOE published a statement of amended policy in which DOE explained its determination that EIA's National Energy Modeling System (NEMS) is the most appropriate tool for its FFC analysis and its intention to use NEMS for that purpose. 77 FR 49701 (Aug. 17, 2012). NEMS is a public domain, multi-sector, partial equilibrium model of the U.S. energy sector ^{170} that EIA uses to prepare its Annual Energy Outlook. The FFC factors incorporate losses in production and delivery in the case of natural gas (including fugitive emissions) and additional energy used to produce and deliver the various fuels used by power plants. The approach used for deriving FFC measures of energy use and emissions is described in appendix 10B of the final rule TSD.
^{170} For more information on NEMS, refer to The National Energy Modeling System: An Overview DOE/EIA-0581(2023), May 2023 (Available at: https://www.eia.gov/outlooks/aeo/nems/overview/pdf/0581(2023).pdf ) (Last accessed Oct. 23, 2023).

3. Net Present Value Analysis
The inputs for determining the NPV of the total costs and benefits experienced by consumers are (1) total annual installed cost, (2) total annual operating costs (energy costs and repair and maintenance costs), and (3) a discount factor to calculate the present value of costs and savings. DOE calculates net savings each year as the difference between the no-new-standards case and each standards case in terms of total savings in operating costs versus total increases in installed costs. DOE calculates operating cost savings over the lifetime of each product shipped during the projection period.
As discussed in section IV.F.1 of this document, DOE developed distribution transformers price trends based on historical PPI data. DOE applied the same trends to project prices for each product class at each considered efficiency level, which was a constant price trend through the end of the analysis period in 2058. DOE's projection of product prices is described in appendix 10C of the NOPR TSD.
To evaluate the effect of uncertainty regarding the price trend estimates, DOE investigated the impact of different product price projections on the consumer NPV for the considered TSLs for distribution transformers. In addition to the default price trend, DOE considered two product price sensitivity cases: (1) a high price decline case based on the years between 2003 and 2019 and (2) a low price decline case based on the years between 1967 and 2002. The derivation of these price trends and the results of these sensitivity cases are described in appendix 10C of the NOPR TSD.
The operating cost savings are energy cost savings, which are calculated using the estimated energy savings in each year and the projected price of the appropriate form of energy. To estimate energy prices in future years, DOE multiplied the average regional energy prices by the projection of annual national-average electricity price changes in the Reference case from AEO2023, which has an end year of 2050. To estimate price trends after 2050, DOE maintained the price constant at 2050 levels. As part of the NIA, DOE also analyzed scenarios that used inputs from variants of the AEO2023 Reference case that have lower and higher economic growth. Those cases have lower and higher energy price trends compared to the Reference case. NIA results based on these cases are presented in appendix 10C of the final rule TSD.
In calculating the NPV, DOE multiplies the net savings in future years by a discount factor to determine their present value. For this final rule, DOE estimated the NPV of consumer benefits using both a 3-percent and a 7-percent real discount rate. DOE uses these discount rates in accordance with guidance provided by the Office of Management and Budget (OMB) to Federal agencies on the development of regulatory analysis. ^{171} The discount rates for the determination of NPV are in contrast to the discount rates used in the LCC analysis, which are designed to reflect a consumer's perspective. The 7-percent real value is an estimate of the average before-tax rate of return to private capital in the U.S. economy. The 3-percent real value represents the “social rate of time preference,” which is the rate at which society discounts future consumption flows to their present value.
^{171} U.S. Office of Management and Budget. Circular A-4: Regulatory Analysis. Available at www.whitehouse.gov/omb/information-for-agencies/circulars (last accessed January 2, 2024). DOE used the prior version of Circular A-4 (September 17, 2003) in accordance with the effective date of the November 9, 2023 version.

I. Consumer Subgroup Analysis
In analyzing the potential impact of new or amended energy conservation standards on consumers, DOE evaluates the impact on identifiable subgroups of consumers that may be disproportionately affected by a new or amended national standard. The purpose of a subgroup analysis is to determine the extent of any such disproportional impacts. DOE evaluates impacts on particular subgroups of consumers by analyzing the LCC impacts and PBP for those particular consumers from alternative standard levels. For this NOPR, DOE analyzed the impacts of the considered standard levels on two subgroups: (1) utilities serving low population densities and (2) utility purchasers of vault (underground) and subsurface installations. DOE used the LCC and PBP model to estimate the impacts of the considered efficiency levels on these subgroups. Chapter 11 in the NOPR TSD describes the consumer subgroup analysis.

1. Utilities Serving Low Customer Populations
In rural areas, mostly served by electric cooperatives (COOPs), the number of customers per distribution transformer is lower than in metropolitan areas and may result in lower PULs.
Idaho Power commented that low-population areas should include adjustments in the PUL and it supported the DOE adjustments to the PUL. Idaho Power commented that its transformers in rural areas do not experience the same levels of loading as in densely populated areas. (Idaho Power, No. 139 at p. 5) NEMA commented that for liquid-filled transformers, its members estimated PUL would typically be 10 percent of RMS-equivalent nameplate rating. (NEMA, No. 141 at p. 16) Further, PSE indicated that an increase in equipment costs of 50 percent would not be ideal for COOPs, as these additional costs would ultimately fall on their member-owners. (PSE, No. 98 at pp. 9-10)
For this final rule, as in the January 2023 NOPR (88 FR 1722, 1785) and April 2013 Standards Final Rule, DOE reduced the PUL by adjusting the distribution of IPL s, as discussed in section IV.E.2.a of this document, resulting in the PULs shown below in Table IV.27. Further, DOE altered the customer sample to limit the distribution of discount rates (see section IV.F.9 of this document) to those observed by State and local governments discussed in IV.F.9 of this document.
In the NOPR, DOE stated that while COOPs deploy a range of distribution transformers to serve their customers, in low population densities the most common unit is a 25 kVA pole overhead liquid-immersed distribution transformer, which is represented in this analysis as representative unit 2B of equipment class 1B (small single-phase liquid-immersed). NRECA suggested that 15 kVA transformers are used more commonly in areas with densities of six customers per mile. (NRECA, No. 98 at p. 7)
DOE recognizes the suggestion by NRECA that the most common capacity used by their members to serve areas with very low customer densities would be 15 kVA. However, DOE's engineering analysis is limited to 25 kVA in this final rule, which is embodied in the results for equipment class 1B, single-phase distribution transformers up to and including 100 kVA.
The results of the subgroups analysis are presented in section IV.I.1 for equipment class 1B. As equipment class 1B encompasses designs that are both pole-mounted (representative unit 2B) and pad-mounted (representative unit 1B) these results represent the capacity scaled, shipment weighted average consumer benefits. NRECA stated that the 15 kVA pole mounted unit is the most used in low costumer density installations—this equipment is represented by representative unit 2B (a 25 kVA pole mount). It can be inferred through examining the LCC results by representative unit that shows that consumer benefits for pole mounted transformers are higher than those of pad mounted transformers, and that the consumer benefits for the 15 kVA pole mounted units would likely be greater than those shown for the entirety of equipment class 1B. ^{172}
^{172} See appendix 8E of the TSD for LCC results by representative unit.

2. Utility Purchasers of Vault (Underground) and Subsurface Installations
In some urban areas, utilities provide service to customers by deploying parts of their transformer fleet in subsurface vaults, or other prefabricated underground concrete structures, referred to as vaults. At issue in the potential amended standards case is that the volume (ft ^3 ) of the more efficient replacement transformers may be too large to fit into the existing vault, which would have to be replaced to fit the new equipment. This analysis is applied to the representative units 15 and 16, specifically defined in the engineering analysis for vault and submersible liquid-immersed distribution transformers (see section IV.C.1 of this document).
DOE received numerous comments on the topic of installing transformers in vaults: Subsurface and Confined Space Installations. APPA commented that its members do not have an inventory of existing vaults or their locations and dimensions; and that most vaults were built to “fit” the equipment that is housed within the vault, and currently many do not have “safe working space” for workers, given rules changes since they were built. APPA commented that such vaults are currently grandfathered into many of the work rules, but having to expand them to take a new transformer that is larger will mean also retrofitting them to safe working space rules. APPA added that under these circumstances, if the transformer is only 10 or 15 percent larger than the vault, expansion will likely be much larger. (APPA, No. 103 at p. 10)
APPA commented that the $23,550 cost assigned in the NOPR to replace an existing vault by DOE is low for transformers installed in building interior vaults. By way of example, APPA commented that simple single-story buildings with parking lot-located vaults may cost at least $200,000; and there may be as much as a $4,000,000 to $50,000,000 discrepancy in vault replacement cost for a multi-story building that would need to be braced and supported to have the foundation removed to expand the vault. (APPA, No. 103 at p. 9) Carte also speculated that in extreme cases, such as rooftop vaults, a weight increase could be achieved by reinforcing the structure. (Carte, No. 140 at p. 7) APPA and the Chamber of Commerce commented that DOE did not account for the potential of significant increased infrastructure replacement and business disruption costs that would be incurred if replacement transformers could not fit into existing locations. (Chamber of Commerce, No. 88 at p. 4; APPA, No. 103 at p. 9) Pugh Consulting commented that for submersible transformers, installing a new transformer that is larger than the existing vault size would lead to significant costs for utilities and municipal governments, including costs associated with potential soil testing to determine if soil can be removed and costs associated with shutting down streets, highways, and sidewalks while a vault is expanded. (Pugh Consulting, No. 117 at p. 6)
DOE recognizes the potential for the cost to install transformers underground, or in building vaults to carry tremendous financial risk to utilities. While the examples provided by APPA, Carte, Chamber of Commerce, and Pugh Consulting are extreme cases where a utility's decision to alter or upgrade the existing installation location could lead to service disruptions, and maybe even health and safety liabilities. It is reasonable that utilities exercising good governance and financial responsibility to their ratepayers would approach such extreme projects only after exhausting all other avenues of maintaining service. As such DOE views these examples as edge cases. Further, stakeholders did not provide any technical information, such as specific transformer designs, weights, volumes; whether these cost estimates are for vaults that contain single or banks of multiple transformers from which DOE can improve its technical analysis. As such DOE is limited to revising its existing model. To address the cost concerns that stakeholders raised regarding the cost being too low in the NOPR, DOE reexamined the costs presented in RSMeans and found they lacked details such as excavation, disposal or fill—further they didn't account the additional costs associated with working in space confined spaces. To better capture these costs, for this final rule DOE has revised its transformer vault installation cost function to the following:
Transformer Vault Installation Cost = 220.37 × DTVolume ^{1.1436}
The Efficiency Advocates commented that the creation of equipment classes for submersible distribution transformers (equipment class 12) will largely mitigate any size concerns regarding underground vaulted network transformer installations because the vast majority of these are submersible designs and thus would not have to meet the higher efficiency levels proposed for other liquid-immersed transformer equipment classes. (Efficiency Advocates, No. 75 at p. 35)
DOE separated the vault and submersible equipment into their own equipment class (equipment class 12) which are designed to operate under higher heat loads which are experienced by equipment installed in enclosed spaces than general purpose distribution transformers. DOE is not amending standards for this equipment at this time precisely for the multitude of installation challenges described by commenters.

J. Manufacturer Impact Analysis

1. Overview
DOE performed an MIA to estimate the financial impacts of amended energy conservation standards on manufacturers of distribution transformers and to estimate the potential impacts of such standards on employment and manufacturing capacity. The MIA has both quantitative and qualitative aspects and includes analyses of projected industry cash flows, the INPV, investments in research and development (R&D) and manufacturing capital, and domestic manufacturing employment. Additionally, the MIA seeks to determine how amended energy conservation standards might affect manufacturing employment, capacity, and competition, as well as how standards contribute to overall regulatory burden. Finally, the MIA serves to identify any disproportionate impacts on manufacturer subgroups, including small business manufacturers.
The quantitative part of the MIA primarily relies on the Government Regulatory Impact Model (GRIM), an industry cash flow model with inputs specific to this rulemaking. The key GRIM inputs include data on the industry cost structure, unit production costs, equipment shipments, manufacturer markups, and investments in R&D and manufacturing capital required to produce compliant equipment. The key GRIM outputs are the INPV, which is the sum of industry annual cash flows over the analysis period, discounted using the industry-weighted average cost of capital, and the impact to domestic manufacturing employment. The model uses standard accounting principles to estimate the impacts of more-stringent energy conservation standards on a given industry by comparing changes in INPV and domestic manufacturing employment between a no-new-standards case and the various standards cases ( i.e., TSLs). To capture the uncertainty relating to manufacturer pricing strategies following amended standards, the GRIM estimates a range of possible impacts under different manufacturer markup scenarios.
The qualitative part of the MIA addresses manufacturer characteristics and market trends. Specifically, the MIA considers such factors as a potential standard's impact on manufacturing capacity, competition within the industry, the cumulative impact of other DOE and non-DOE regulations, and impacts on manufacturer subgroups. The complete MIA is outlined in chapter 12 of the final rule TSD.
DOE conducted the MIA for this rulemaking in three phases. In Phase 1 of the MIA, DOE prepared a profile of the distribution transformer manufacturing industry based on the market and technology assessment, preliminary manufacturer interviews, and publicly available information. This included a top-down analysis of distribution transformer manufacturers that DOE used to derive preliminary financial inputs for the GRIM ( e.g., revenues; materials, labor, overhead, and depreciation expenses; selling, general, and administrative expenses (SG&A); and R&D expenses). DOE also used public sources of information to further calibrate its initial characterization of the distribution transformer manufacturing industry, including company filings of form 10-K from the SEC, ^{173} corporate annual reports, the U.S. Census Bureau's “Economic Census,” ^{174} and reports from D&B Hoovers. ^{175}
^{173} See: www.sec.gov/edgar
^{174} See: www.census.gov/programs-surveys/asm/data/tables.html
^{175} See: app.avention.com
In Phase 2 of the MIA, DOE prepared a framework industry cash flow analysis to quantify the potential impacts of amended energy conservation standards. The GRIM uses several factors to determine a series of annual cash flows starting with the announcement of the standard and extending over a 30-year period following the compliance date of the standard. These factors include annual expected revenues, costs of sales, SG&A and R&D expenses, taxes, and capital expenditures. In general, energy conservation standards can affect manufacturer cash flow in three distinct ways: (1) creating a need for increased investment, (2) raising production costs per unit, and (3) altering revenue due to higher per-unit prices and changes in sales volumes.
In addition, during Phase 2, DOE developed interview guides to distribute to manufacturers of distribution transformers in order to develop other key GRIM inputs, including product and capital conversion costs, and to gather additional information on the anticipated effects of energy conservation standards on revenues, direct employment, capital assets, industry competitiveness, and subgroup impacts.
In Phase 3 of the MIA, DOE conducted structured, detailed interviews with representative manufacturers. During these interviews, DOE discussed engineering, manufacturing, procurement, and financial topics to validate assumptions used in the GRIM and to identify key issues or concerns. As part of Phase 3, DOE also evaluated subgroups of manufacturers that may be disproportionately impacted by amended standards or that may not be accurately represented by the average cost assumptions used to develop the industry cash flow analysis. Such manufacturer subgroups may include small business manufacturers, low-volume manufacturers (LVMs), niche players, and/or manufacturers exhibiting a cost structure that largely differs from the industry average. DOE identified one subgroup for a separate impact analysis: small business manufacturers. The small business subgroup is discussed in section VI.B, “Review under the Regulatory Flexibility Act,” and in chapter 12 of the final rule TSD.

2. Government Regulatory Impact Model and Key Inputs
DOE uses the GRIM to quantify the changes in cash flow due to amended standards that result in a higher or lower industry value. The GRIM uses a standard, annual discounted cash flow analysis that incorporates manufacturer costs, manufacturer markups, shipments, and industry financial information as inputs. The GRIM models changes in costs, distribution of shipments, investments, and manufacturer margins that could result from amended energy conservation standards. The GRIM spreadsheet uses the inputs to arrive at a series of annual cash flows, beginning in 2024 (the base year of the analysis) and continuing to 2058. DOE calculated INPVs by summing the stream of annual discounted cash flows during this period. For manufacturers of distribution transformers, DOE used a real discount rate of 7.4 percent for liquid-immersed distribution transformers, 11.1 percent for LVDT distribution transformers, and 9.0 percent for MVDT distribution transformers, which was derived from the April 2013 Standards Final Rule and then modified according to feedback received during manufacturer interviews. ^{176}
^{176} See Chapter 12 of the April 2013 Standards Final Rule TSD for discussion of where initial discount factors were derived, available online at www.regulations.gov/document/EERE-2010-BT-STD-0048-0760. For the April 2013 Standards Final Rule, DOE initially calculated a 9.1 percent discount rate, however during manufacturer interviews conducted for that rulemaking, manufacturers suggested using different discount rates specific for each equipment class group. During manufacturer interviews conducted for the January 2023 NOPR, manufacturers continued to agree that using different discount rates for each equipment class group is appropriate.
The GRIM calculates cash flows using standard accounting principles and compares changes in INPV between the no-new-standards case and each standards case. The difference in INPV between the no-new-standards case and a standards case represents the financial impact of amended energy conservation standards on manufacturers. As discussed previously, DOE developed critical GRIM inputs using a number of sources, including publicly available data, results of the engineering analysis, and information gathered from industry stakeholders during the course of manufacturer interviews. The GRIM results are presented in section V.B.2 of this document. Additional details about the GRIM, the discount rate, and other financial parameters can be found in chapter 12 of the final rule TSD.

a. Manufacturer Production Costs
Manufacturing more efficient equipment is typically more expensive than manufacturing baseline equipment due to the use of more complex components, which are typically more costly than baseline components. The changes in the MPCs of covered equipment can affect the revenues, gross margins, and cash flow of the industry.
During the engineering analysis, DOE used transformer design software to create a database of designs spanning a broad range of efficiencies for each of the representative units. This design software generated a bill of materials. DOE then applied markups to allow for scrap, handling, factory overhead, and other non-production costs, as well as profit, to estimate the MSP.
These designs and their MSPs are subsequently inputted into the LCC customer choice model. For each efficiency level and within each representative unit, the LCC model uses a consumer choice model and criteria described in section IV.F.3 of this document to select a subset of all the potential designs options (and associated MSPs). This subset is meant to represent those designs that would actually be shipped in the market under the various analyzed TSLs. DOE inputted into the GRIM the weighted average cost of the designs selected by the LCC model and scaled those MSPs to other selected capacities in each design line's KVA range.
For a complete description of the MSPs, see chapter 5 of the final rule TSD.

b. Shipments Projections
The GRIM estimates manufacturer revenues based on total unit shipment projections and the distribution of those shipments by efficiency level. Changes in sales volumes and efficiency mix over time can significantly affect manufacturer finances. For this analysis, the GRIM uses the NIA's annual shipment projections derived from the shipments analysis from 2024 (the base year) to 2058 (the end year of the analysis period). See chapter 9 of the final rule TSD for additional details.

c. Product and Capital Conversion Costs
Amended energy conservation standards could cause manufacturers to incur conversion costs to bring their production facilities and equipment designs into compliance. DOE evaluated the level of conversion-related expenditures that would be needed to comply with each considered efficiency level in each equipment class. For the MIA, DOE classified these conversion costs into two major groups: (1) product conversion costs; and (2) capital conversion costs. Product conversion costs are investments in research, development, testing, marketing, and other non-capitalized costs necessary to make equipment designs comply with amended energy conservation standards. Capital conversion costs are investments in property, plants, and equipment necessary to adapt or change existing production facilities such that new compliant equipment designs can be fabricated and assembled.
For capital conversion costs, DOE prepared bottom-up estimates of the costs required to meet the analyzed amended energy conservation standards at each EL for each representative unit. Major drivers of capital conversion costs include changes in core steel variety (and thickness), core weight, and core stack height, all of which are interdependent and can vary by efficiency level. The MIA used the estimated quantity of the core steel (by steel variety) for each EL at each representative unit that was modeled as part of the engineering analysis and incorporated into the LCC analysis, to estimate the additional production equipment that the distribution transformer industry would need to purchase in order to meet each analyzed EL.
Capital conversion costs are primarily driven at each EL by the potential need for the industry to expand production capacity for the potential increase in amorphous alloy used in distribution transformer cores. In the January 2023 NOPR, DOE estimated that an amorphous production line capable of producing 1,200 tons annual of amorphous cores would cost approximately $1,000,000 in capital investments. This capital investment includes costs associated with purchasing annealing ovens, core cutting machines, lacing tables, as well as additional conveyors and cranes to move the potentially larger amorphous cores, new winding machines and assembly tools specific to amorphous core production. Lastly, this capital investment also accounts for the potential additional production floor space that could be needed to accommodate these additional or larger production equipment that would be required to manufacture amorphous cores. The quantity of amorphous cores are outputs of the engineering analysis and the LCC. At higher ELs, the percent of distribution transformers selected in the LCC consumer choice model that have amorphous cores increases. Additionally, at the highest ELs, the quantity of amorphous material per distribution transformer also increases. As the increasing stringency of the ELs drive the use of more amorphous cores in distribution transformers (and more amorphous material per distribution transformer), capital conversion costs increase.
For product conversion costs, DOE understands the production of amorphous cores requires unique production expertise from a manufacturer's employees and engineering labor to create new equipment designs for distribution transformers using amorphous cores. For manufacturers without experience with amorphous core production, standards that would likely be met using amorphous cores would require the development or the procurement of the technical knowledge to produce cores as well as potentially re-training production employees. Because amorphous material is thinner and more brittle after annealing, materials management, safety measures, and design considerations that are not associated with non-amorphous materials would need to be implemented.
In the January 2023 NOPR, DOE estimated product conversion costs would be equal to 100 percent of the normal annual industry R&D expenses for those ELs where a majority of the market would be expected to transition to amorphous material. These one-time product conversion costs would be in addition to the annual R&D expenses normally incurred by distribution transformer manufacturers. These one-time expenditures account for the design, engineering, prototyping, re-training of production employees, and other R&D efforts the industry would have to undertake to move to a predominately amorphous market. For ELs that would not require the use of amorphous cores, but would still require distribution transformer models to be redesigned to meet higher efficiency levels, the January 2023 NOPR estimated product conversion costs would be equal to 50 percent of the normal annual industry R&D expenses. These one-time product conversion costs would also be in addition to the annual R&D expenses normally incurred by distribution transformer manufacturers.
Several interested parties commented on the conversion cost estimate used in the January 2023 NOPR. Several interested parties commented that manufacturers converting from GOES core production to amorphous core production will require large investments and the acquisition of several production equipment as well as re-training production employees. MTC commented that using amorphous cores requires different mandrels, winding, assembly processes, and equipment, including specialty annealing equipment and that the costs are significant and would be a major cost burden on distribution transformer manufacturers. (MTC, No. 119 at p. 19) Prolec GE commented that converting to amorphous cores would require investment in larger production lines in addition to other manufacturing equipment like cutting lines and annealing ovens. (Prolec GE, No. 120, at pp. 2-3) TMMA commented that in order to meet the standards proposed in the January 2023 NOPR, distribution transformer manufacturers will be required to make a significant investment for new manufacturing equipment, including cutting machines and annealing ovens. (TMMA, No. 138 at pp. 2-3) NEMA commented that producing distribution transformers that use amorphous cores requires manufacturers to reconfigure their assembly processes, including time to retrain electricians to match transformer coils to calibrate with the properties of the new steel and the steel tanks which house both the coil and cores will need to be reconfigured to match these new dimensions. (NEMA, No. 141 at p. 3) Schneider commented that the January 2023 NOPR conversion cost estimates only considered core conversion costs when in actuality the standards proposed in the January 2023 NOPR would require new winding equipment to handle larger cores, expanded conveyors, cranes, and ovens to handle larger equipment, and potentially new facilities to handle the larger manufacturing footprints. (Schneider, No. 101 at p. 11) Howard commented that in addition to the capital equipment to produce amorphous cores, some facilities will need to be upgraded to accommodate the additional core-making equipment. (Howard, No. 116 at p. 2) Carte commented that amorphous core production is totally different than GOES core production and would require either a large expansion of their plant or purchasing cores from an external vendor. (Carte, No. 140 at p. 1) Eaton commented that distribution transformer manufacturers that currently manufacture GOES cores will be left with scrapping their equipment due to very little shared processes or equipment between GOES and amorphous steel. (Eaton, No. 137 at p. 26) Lastly, WEG commented that the standards proposed in the January 2023 NOPR would require 50 percent of their operations to be retooled for amorphous core production and their employees would have to be completely retrained. (WEG, No. 92 at p. 3)
DOE acknowledges that distribution transformer manufacturers would incur significant conversion costs to convert production facilities that are currently designed to produce GOES cores into production facilities that would produce amorphous steel cores in order to meet energy conservation standards. The January 2023 NOPR and this final rule analysis attempts to capture the full costs that distribution transformer manufacturers would incur to be able to produce compliant distribution transformers analyzed in this rulemaking. The cost estimates used in the January 2023 NOPR and this final rule analysis, include manufacturing equipment used in the cutting lines, annealing ovens, new winding equipment to handle larger cores, expanded conveyors and cranes, as well as costs to expand production floor space.
Several interested parties commented that the conversion cost estimates used in the January 2023 NOPR were underestimated and should be increased. Cliffs commented that the substantial conversion costs estimated in the January 2023 NOPR are far below the reasonably foreseeable economic impact on manufacturers. (Cliffs, No. 105 at p. 14) Additionally, Cliffs commented that the January 2023 NOPR conversion cost estimates were based on manufacturer interviews conducted in 2019 and did not account for the significant inflationary forces have substantially increased capital equipment costs by at least 50 percent. ( Id. ) Cliffs continued by commenting that in order for manufacturers to comply with the standards proposed in the January 2023 NOPR, it would require new investments of between $30 and $50 million for each individual manufacturer to retool existing production factories, which they estimate would cost the entire industry between $500 million and $800 million to convert all distribution transformer production facilities into being capable of producing amorphous cores for the entire U.S. distribution transformer market. (Cliffs, No. 105 at p. 15) Hammond stated that they estimate having their production facility produce amorphous cores for all of their distribution transformers would take twice as long to produce and would require $40 million to $45 million in investment to ensure current and planned capacity could be shifted to the production of distribution transformers using amorphous cores. (Hammond, No. 142 at p. 2) Howard commented that if standards directly or indirectly force all distribution transformer designs only to use amorphous cores, the investment required from a monetary and time perspective would be even larger and longer that the conversion costs estimated in the January 2023 NOPR. (Howard, No. 116 at p. 3) Howard commented that they estimate distribution transformer manufacturers would need to invest between $500 million and $1 billion to convert all distribution transformer manufacturing to accommodate producing amorphous cores for all distribution transformers sold in the U.S. (Howard, No. 116 at p. 2) Prolec GE commented that it would need to invest approximately $50 million to convert their liquid-immersed distribution transformer production, which currently used GOES cores to use amorphous cores. (Prolec GE, No. 120 at p. 1) WEG commented that they estimate that it would take 5-7 years to retool their distribution transformer production facilities to support the necessary production equipment and methods to produce amorphous core transformers at an estimated investment of between $25 million and $30 million. (WEG, No. 92 at pp. 3-4) Additionally WEG commented that developing amorphous core designs would require building 20 prototypes and need three full time engineers to complete this transition to all amorphous core distribution transformers. WEG estimates this engineering effort would cost their company approximately $2 million. (WEG, No, 92 at pp. 1-2)
As part of this final rule MIA, DOE reexamined the estimated conversion costs used in the January 2023 NOPR. For this final rule analysis, DOE continues to use the same methodology to estimate the conversion costs that industry would incur at each analyzed EL for each representative unit. However, DOE has increased the estimated capital conversion costs used in the January 2023 NOPR from $1,000,000 in capital investments to build a production line capable of producing distribution transformers that use 1,200 tons annually of amorphous core material to $2,000,000 in capital investments for the same quantity of amorphous core material. This increase in capital investments reflect both the inflationary market mentioned by Cliffs and the additional production equipment that would be in addition to the production equipment that is specific to amorphous core production, as well as the potential increase in production floor space that might be needed to accommodate additional or larger production equipment associated with amorphous core production.
Additionally, DOE increased the estimated product conversion costs for distribution transformers using amorphous cores from 100 percent of the annual industry R&D expenses to be 150 percent of the annual industry R&D expenses; and for distribution transformers continuing to use GOES cores from 50 percent the annual industry R&D expenses to be 75 percent of annual R&D expenses. The end result is that product conversion cost estimates used in this final rule analysis are 50 percent more than the product conversion cost estimates used in the January 2023 NOPR, for the same level of amorphous core production requirements. These one-time product conversion costs would be in addition to the annual R&D expenses normally incurred by distribution transformer manufacturers. This increase in product conversion costs from the January 2023 NOPR to this final rule analysis reflect the additional redesigning, engineering, prototyping, re-training of production employees, and other R&D efforts the industry would have to undertake to move to producing distribution transformers using amorphous cores.
The conversion costs by TSL and representative unit are displayed in Table IV.29. These conversion costs are incorporated into the cash flow analysis discussed in section V.B.2.a. The industry-wide conversion cost estimates to convert all distribution transformer manufacturing to accommodate producing amorphous cores for all distribution transformers sold in the U.S. (which would occur at TSL 5) would be approximately $825 million. This industry-wide conversion estimate aligns with the estimates that several interested parties suggested in response to the January 2023 NOPR.
Capital and product conversion costs are key inputs into the GRIM and directly impact the change in INPV (which is outputted from the model) due to analyzed amended standards. The GRIM assumes all conversion-related investments occur between the year of publication of this final rule and the year by which manufacturers must comply with the amended standards. The conversion cost figures used in the GRIM can be found in section V.B.2.a of this document. For additional information on the estimated capital and product conversion costs, see chapter 12 of the final rule TSD.

d. Manufacturer Markup Scenarios
MSPs include direct manufacturing production costs ( i.e., labor, materials, and overhead estimated in DOE's MPCs) and all non-production costs ( i.e., SG&A, R&D, and interest), along with profit. To calculate the MSPs in the GRIM, DOE applied non-production cost markups to the MPCs estimated in the engineering analysis for each equipment class and efficiency level. Modifying these manufacturer markups in the standards case yields different sets of impacts on manufacturers. For the MIA, DOE modeled two standards-case manufacturer markup scenarios to represent uncertainty regarding the potential impacts on prices and profitability for manufacturers following the implementation of amended energy conservation standards: (1) a preservation of gross margin scenario; and (2) a preservation of operating profit scenario. These scenarios lead to different manufacturer markup values that, when applied to the MPCs, result in varying revenue and cash flow impacts.
Under the preservation of gross margin percentage markup scenario, DOE applied a single uniform “gross margin percentage” across all efficiency levels, which assumes that manufacturers would be able to maintain the same amount of profit as a percentage of revenues at all efficiency levels within an equipment class. This scenario assumes that manufacturers would be able to maintain the same amount of profit as a percentage of revenues at all TSLs, even as the MPCs increase in the standards case. Based on data from the April 2013 Standards Final Rule, publicly available financial information for manufacturers of distribution transformers, and comments made during manufacturer interviews, DOE estimated a gross margin percentage of 20 percent for all distribution transformers. ^{177} This is the same value used in the January 2023 NOPR. Because this scenario assumes that manufacturers would be able to maintain the same gross margin percentage as MPCs increase in response to the analyzed energy conservation standards, it represents the upper bound to industry profitability under amended energy conservation standards.
^{177} The gross margin percentage of 20 percent is based on a manufacturer markup of 1.25.
Under the preservation of operating profit scenario, DOE modeled a situation in which manufacturers are not able to increase per-unit operating profit in proportion to increases in MPCs. Under this scenario, as the MPCs increase, manufacturers reduce their manufacturer markups (on a percentage basis) to a level that maintains the no-new-standards operating profit (in absolute dollars). The implicit assumption behind this scenario is that the industry can only maintain its operating profit in absolute dollars after compliance with amended standards. Therefore, operating margin in percentage terms is reduced between the no-new-standards case and the analyzed standards cases. DOE adjusted the manufacturer markups in the GRIM at each TSL to yield approximately the same earnings before interest and taxes in the standards case in the year after the compliance date of the amended standards as in the no-new-standards case. This scenario represents the lower bound to industry profitability under amended energy conservation standards.
A comparison of industry financial impacts under the two manufacturer markup scenarios is presented in section V.B.2.a of this document.

K. Emissions Analysis
The emissions analysis consists of two components. The first component estimates the effect of potential energy conservation standards on power sector and site (where applicable) combustion emissions of CO 2 , NO X , SO 2 , and Hg. The second component estimates the impacts of potential standards on emissions of two additional greenhouse gases, CH 4 and N 2 O, as well as the reductions in emissions of other gases due to “upstream” activities in the fuel production chain. These upstream activities comprise extraction, processing, and transporting fuels to the site of combustion.
The analysis of electric power sector emissions of CO 2 , NO X , SO 2 , and Hg uses emissions intended to represent the marginal impacts of the change in electricity consumption associated with amended or new standards. The methodology is based on results published for the AEO, including a set of side cases that implement a variety of efficiency-related policies. The methodology is described in appendix 13A in the final rule TSD. The analysis presented in this notice uses projections from AEO2023. Power sector emissions of CH 4 and N 2 O from fuel combustion are estimated using Emission Factors for Greenhouse Gas Inventories published by the Environmental Protection Agency (EPA). ^{178}
^{178} Available at www.epa.gov/sites/production/files/2021-04/documents/emission-factors_apr2021.pdf (last accessed July 12, 2021).
Site emissions of these gases were estimated using Emission Factors for Greenhouse Gas Inventories and, for NO X and SO 2 , emissions intensity factors from an EPA publication. ^{179}
^{179} U.S. Environmental Protection Agency. External Combustion Sources. In Compilation of Air Pollutant Emission Factors. AP-42. Fifth Edition. Volume I: Stationary Point and Area Sources. Chapter 1. Available at www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors#Proposed/ (last accessed July 12, 2021).
FFC upstream emissions, which include emissions from fuel combustion during extraction, processing, and transportation of fuels, and “fugitive” emissions (direct leakage to the atmosphere) of CH 4 and CO 2 , are estimated based on the methodology described in chapter 15 of the final rule TSD.
The emissions intensity factors are expressed in terms of physical units per MWh or MMBtu of site energy savings. For power sector emissions, specific emissions intensity factors are calculated by sector and end use. Total emissions reductions are estimated using the energy savings calculated in the national impact analysis.

1. Air Quality Regulations Incorporated in DOE's Analysis
DOE's no-new-standards case for the electric power sector reflects the AEO, which incorporates the projected impacts of existing air quality regulations on emissions. AEO2023 reflects, to the extent possible, laws and regulations adopted through mid-November 2022, including the emissions control programs discussed in the following paragraphs and the Inflation Reduction Act. ^{180}
^{180} For further information, see the Assumptions to AEO2023 report that sets forth the major assumptions used to generate the projections in the Annual Energy Outlook. Available at www.eia.gov/outlooks/aeo/assumptions/ (last accessed January 2, 2024).
SO 2 emissions from affected electric generating units (EGUs) are subject to nationwide and regional emissions cap-and-trade programs. Title IV of the Clean Air Act sets an annual emissions cap on SO 2 for affected EGUs in the 48 contiguous States and the District of Columbia (“D.C.”). (42 U.S.C. 7651 et seq. ) SO 2 emissions from numerous States in the eastern half of the United States are also limited under the Cross-State Air Pollution Rule (“CSAPR”). 76 FR 48208 (Aug. 8, 2011). CSAPR requires these States to reduce certain emissions, including annual SO 2 emissions, and went into effect as of January 1, 2015. ^{181} The AEO incorporates implementation of CSAPR, including the update to the CSAPR ozone season program emission budgets and target dates issued in 2016. 81 FR 74504 (Oct. 26, 2016). Compliance with CSAPR is flexible among EGUs and is enforced through the use of tradable emissions allowances. Under existing EPA regulations, for states subject to SO 2 emissions limits under CSAPR, any excess SO 2 emissions allowances resulting from the lower electricity demand caused by the adoption of an efficiency standard could be used to permit offsetting increases in SO 2 emissions by another regulated EGU.
^{181} CSAPR requires states to address annual emissions of SO 2 and NO X , precursors to the formation of fine particulate matter (PM 2.5 ) pollution, in order to address the interstate transport of pollution with respect to the 1997 and 2006 PM 2.5 National Ambient Air Quality Standards (NAAQS). CSAPR also requires certain states to address the ozone season (May-September) emissions of NO X , a precursor to the formation of ozone pollution, in order to address the interstate transport of ozone pollution with respect to the 1997 ozone NAAQS. 76 FR 48208 (Aug. 8, 2011). EPA subsequently issued a supplemental rule that included an additional five states in the CSAPR ozone season program; 76 FR 80760 (Dec. 27, 2011) (Supplemental Rule), and EPA issued the CSAPR Update for the 2008 ozone NAAQS. 81 FR 74504 (Oct. 26, 2016).
However, beginning in 2016, SO 2 emissions began to fall as a result of the Mercury and Air Toxics Standards (MATS) for power plants. ^{182} 77 FR 9304 (Feb. 16, 2012). The final rule establishes power plant emission standards for mercury, acid gases, and non-mercury metallic toxic pollutants. Because of the emissions reductions under the MATS, it is unlikely that excess SO 2 emissions allowances resulting from the lower electricity demand would be needed or used to permit offsetting increases in SO 2 emissions by another regulated EGU. Therefore, energy conservation standards that decrease electricity generation will generally reduce SO 2 emissions. DOE estimated SO 2 emissions reduction using emissions factors based on AEO2023.
^{182} In order to continue operating, coal power plants must have either flue gas desulfurization or dry sorbent injection systems installed. Both technologies, which are used to reduce acid gas emissions, also reduce SO 2 emissions.
CSAPR also established limits on NO X emissions for numerous States in the eastern half of the United States. Energy conservation standards would have little effect on NO X emissions in those States covered by CSAPR emissions limits if excess NO X emissions allowances resulting from the lower electricity demand could be used to permit offsetting increases in NO X emissions from other EGUs. In such case, NO X emissions would remain near the limit even if electricity generation goes down. Depending on the configuration of the power sector in the different regions and the need for allowances, however, NO X emissions might not remain at the limit in the case of lower electricity demand. That would mean that standards might reduce NO X emissions in covered States. Despite this possibility, DOE has chosen to be conservative in its analysis and has maintained the assumption that standards will not reduce NO X emissions in States covered by CSAPR. Standards would be expected to reduce NO X emissions in the States not covered by CSAPR. DOE used AEO2023 data to derive NO X emissions factors for the group of States not covered by CSAPR.
The MATS limit mercury emissions from power plants, but they do not include emissions caps and, as such, DOE's energy conservation standards would be expected to slightly reduce Hg emissions. DOE estimated mercury emissions reduction using emissions factors based on AEO2023, which incorporates the MATS.
EEI commented that electric companies are already reducing greenhouse gas emissions via clean energy initiatives such as utilizing more renewable energy technology. (EEI, No. 135 at pp. 7-8) Several other stakeholders similarly commented that utility companies are actively reducing greenhouse gas emissions and already utilize carbon-free energy sources. (Idaho Falls Power, No. 77 at p. 2; Fall River, No. 83 at p. 2; WEC, No. 118 at p. 3)
In response to EEI and other utility stakeholders, DOE notes that the emissions factors are determined by AEO, which accounts for declining future carbon emissions due increased renewable generation.

L. Monetizing Emissions Impacts
As part of the development of this final rule, for the purpose of complying with the requirements of Executive Order 12866, DOE considered the estimated monetary benefits from the reduced emissions of CO 2 , CH 4 , N 2 O, NO X , and SO 2 that are expected to result from each of the TSLs considered. In order to make this calculation analogous to the calculation of the NPV of consumer benefit, DOE considered the reduced emissions expected to result over the lifetime of products shipped in the projection period for each TSL. This section summarizes the basis for the values used for monetizing the emissions benefits and presents the values considered in this final rule.
To monetize the benefits of reducing GHG emissions, this analysis uses the interim estimates presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates Under Executive Order 13990 published in February 2021 by the IWG.

1. Monetization of Greenhouse Gas Emissions
DOE estimates the monetized benefits of the reductions in emissions of CO 2 , CH 4 , and N 2 O by using a measure of the SC of each pollutant ( e.g., SC-CO 2 ). These estimates represent the monetary value of the net harm to society associated with a marginal increase in emissions of these pollutants in a given year, or the benefit of avoiding that increase. These estimates are intended to include (but are not limited to) climate-change-related changes in net agricultural productivity, human health, property damages from increased flood risk, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services.
DOE exercises its own judgment in presenting monetized climate benefits as recommended by applicable Executive orders, and DOE would reach the same conclusion presented in this rulemaking in the absence of the social cost of greenhouse gases. That is, the social costs of greenhouse gases, whether measured using the February 2021 interim estimates presented by the IWG on the Social Cost of Greenhouse Gases or by another means, did not affect the rule ultimately adopted by DOE.
DOE estimated the global social benefits of CO 2 , CH 4 , and N 2 O reductions using SC-GHG values that were based on the interim values presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990, published in February 2021 by the IWG (“February 2021 SC-GHG TSD”). The SC-GHG is the monetary value of the net harm to society associated with a marginal increase in emissions in a given year, or the benefit of avoiding that increase. In principle, the SC-GHG includes the value of all climate change impacts, including (but not limited to) changes in net agricultural productivity, human health effects, property damage from increased flood risk and natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. The SC-GHG, therefore, reflects the societal value of reducing emissions of the gas in question by 1 metric ton. The SC-GHG is the theoretically appropriate value to use in conducting benefit-cost analyses of policies that affect CO 2 , N 2 O, and CH 4 emissions. As a member of the IWG involved in the development of the February 2021 SC-GHG TSD, DOE agrees that the interim SC-GHG estimates represent the most appropriate estimate of the SC-GHG until revised estimates have been developed reflecting the latest, peer-reviewed science. DOE continues to evaluate recent developments in the scientific literature, including the updated SC-GHG estimates published by the EPA in December 2023 within their rulemaking on oil and natural gas sector sources. ^{183} For this rulemaking, DOE used these updated SC-GHG values to conduct a sensitivity analysis of the value of GHG emissions reductions associated with alternative standards for distribution transformers (see section IV.L.1.c of this document).
^{183} U.S. EPA. (2023). Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review”: EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances. Washington, DC: U.S. EPA. https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/epas-final-rule-oil-and-natural-gas.
The SC-GHG estimates presented here were developed over many years, using peer-reviewed methodologies, a transparent process, the best science available at the time of that process, and input from the public. Specifically, in 2009, the IWG, which included DOE and other Executive branch agencies and offices, was established to ensure that agencies were using the best available science and to promote consistency in the SC-CO 2 values used across agencies. The IWG published SC-CO 2 estimates in 2010 that were developed from an ensemble of three widely cited integrated assessment models (IAMs) that estimate global climate damages using highly aggregated representations of climate processes and the global economy combined into a single modeling framework. The three IAMs were run using a common set of input assumptions in each model for future population, economic, and CO 2 emissions growth, as well as equilibrium climate sensitivity—a measure of the globally averaged temperature response to increased atmospheric CO 2 concentrations. These estimates were updated in 2013 based on new versions of each IAM. In August 2016 the IWG published estimates of the SC-CH 4 and SC-N 2 O using methodologies that are consistent with the methodology underlying the SC-CO 2 estimates. The modeling approach that extends the IWG SC-CO 2 methodology to non-CO 2 GHGs has undergone multiple stages of peer review. The SC-CH 4 and SC-N 2 O estimates were developed by Marten et al. ^{184} and underwent a standard double-blind peer review process prior to journal publication. In 2015, as part of the response to public comments received to a 2013 solicitation for comments on the SC-CO 2 estimates, the IWG announced a National Academies of Sciences, Engineering, and Medicine review of the SC-CO 2 estimates to offer advice on how to approach future updates to ensure that the estimates continue to reflect the best available science and methodologies. In January 2017, the National Academies released their final report, “Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide,” and recommended specific criteria for future updates to the SC-CO 2 estimates, a modeling framework to satisfy the specified criteria, and both near-term updates and longer-term research needs pertaining to various components of the estimation process. ^{185} Shortly thereafter, in March 2017, President Trump issued Executive Order 13783, which disbanded the IWG, withdrew the previous TSDs, and directed agencies to ensure SC-CO 2 estimates used in regulatory analyses are consistent with the guidance contained in OMB's Circular A-4, “including with respect to the consideration of domestic versus international impacts and the consideration of appropriate discount rates” (E.O. 13783, Section 5(c)). Benefit-cost analyses following E.O. 13783 used SC-GHG estimates that attempted to focus on the U.S.-specific share of climate change damages as estimated by the models and were calculated using two discount rates recommended by Circular A-4, 3 percent and 7 percent. All other methodological decisions and model versions used in SC-GHG calculations remained the same as those used by the IWG in 2010 and 2013, respectively.
^{184} Marten, A.L., E.A. Kopits, C.W. Griffiths, S.C. Newbold, and A. Wolverton. Incremental CH 4 and N 2 O mitigation benefits consistent with the U.S. Government's SC-CO 2 estimates. Climate Policy. 2015. 15(2): pp. 272-298.
^{185} National Academies of Sciences, Engineering, and Medicine. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. 2017. The National Academies Press: Washington, DC. nap.nationalacademies.org/catalog/24651/valuing-climate-damages-updating-estimation-of-the-social-cost-of .
On January 20, 2021, President Biden issued Executive Order 13990, which re-established the IWG and directed it to ensure that the U.S. Government's estimates of the social cost of carbon and other greenhouse gases reflect the best available science and the recommendations in the National Academies 2017 report. The IWG was tasked with first reviewing the SC-GHG estimates currently used in Federal analyses and publishing interim estimates within 30 days of the E.O. that reflect the full impact of GHG emissions, including by taking global damages into account. The interim SC-GHG estimates published in February 2021 are used here to estimate the climate benefits for this rulemaking. The E.O. instructs the IWG to undertake a fuller update of the SC-GHG estimates that takes into consideration the advice in the National Academies 2017 report and other recent scientific literature. The February 2021 SC-GHG TSD provides a complete discussion of the IWG's initial review conducted under E.O. 13990. In particular, the IWG found that the SC-GHG estimates used under E.O. 13783 fail to reflect the full impact of GHG emissions in multiple ways.
First, the IWG found that the SC-GHG estimates used under E.O. 13783 fail to fully capture many climate impacts that affect the welfare of U.S. citizens and residents, and those impacts are better reflected by global measures of the SC-GHG. Examples of omitted effects from the E.O. 13783 estimates include direct effects on U.S. citizens, assets and investments located abroad, supply chains, U.S. military assets and interests abroad, tourism, and spillover pathways such as economic and political destabilization and global migration that can lead to adverse impacts on U.S. national security, public health, and humanitarian concerns. In addition, assessing the benefits of U.S. GHG mitigation activities requires consideration of how those actions may affect mitigation activities by other countries, as those international mitigation actions will provide a benefit to U.S. citizens and residents by mitigating climate impacts that affect U.S. citizens and residents. A wide range of scientific and economic experts have emphasized the issue of reciprocity as support for considering global damages of GHG emissions. If the United States does not consider impacts on other countries, it is difficult to convince other countries to consider the impacts of their emissions on the United States. The only way to achieve an efficient allocation of resources for emissions reduction on a global basis—and so benefit the U.S. and its citizens—is for all countries to base their policies on global estimates of damages. As a member of the IWG involved in the development of the February 2021 SC-GHG TSD, DOE agrees with this assessment and, therefore, in this final rule DOE centers attention on a global measure of SC-GHG. This approach is the same as that taken in DOE regulatory analyses from 2012 through 2016. A robust estimate of climate damages that accrue only to U.S. citizens and residents does not currently exist in the literature. As explained in the February 2021 SC-GHG TSD, existing estimates are both incomplete and an underestimate of total damages that accrue to the citizens and residents of the U.S. because they do not fully capture the regional interactions and spillovers discussed above, nor do they include all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature. As noted in the February 2021 SC-GHG TSD, the IWG will continue to review developments in the literature, including more robust methodologies for estimating a U.S.-specific SC-GHG value, and explore ways to better inform the public of the full range of carbon impacts. As a member of the IWG, DOE will continue to follow developments in the literature pertaining to this issue.
Second, the IWG found that the use of the social rate of return on capital (estimated to be 7 percent under OMB's 2003 Circular A-4 guidance) to discount the future benefits of reducing GHG emissions inappropriately underestimates the impacts of climate change for the purposes of estimating the SC-GHG. Consistent with the findings of the National Academies and the economic literature, the IWG continued to conclude that the consumption rate of interest is the theoretically appropriate discount rate in an intergenerational context, ^{186} and it recommended that discount rate uncertainty and relevant aspects of intergenerational ethical considerations be accounted for in selecting future discount rates.
^{186} Interagency Working Group on Social Cost of Carbon. Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866. 2010. United States Government. www.epa.gov/sites/default/files/2016-12/documents/scc_tsd_2010.pdf (last accessed April 15, 2022.); Interagency Working Group on Social Cost of Carbon. Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. 2013. www.federalregister.gov/documents/2013/11/26/2013-28242/technical-support-document-technical-update-of-the-social-cost-of-carbon-for-regulatory-impact (last accessed April 15, 2022.); Interagency Working Group on Social Cost of Greenhouse Gases, United States Government. Technical Support Document: Technical Update on the Social Cost of Carbon for Regulatory Impact Analysis—Under Executive Order 12866. August 2016. www.epa.gov/sites/default/files/2016-12/documents/sc_co2_tsd_august_2016.pdf (last accessed January 18, 2022.); Interagency Working Group on Social Cost of Greenhouse Gases, United States Government. Addendum to Technical Support Document on Social Cost of Carbon for Regulatory Impact Analysis under Executive Order 12866: Application of the Methodology to Estimate the Social Cost of Methane and the Social Cost of Nitrous Oxide. August 2016. www.epa.gov/sites/default/files/2016-12/documents/addendum_to_sc-ghg_tsd_august_2016.pdf (last accessed January 18, 2022.).
Furthermore, the damage estimates developed for use in the SC-GHG are estimated in consumption-equivalent terms, and so an application of OMB Circular A-4's guidance for regulatory analysis would then use the consumption discount rate to calculate the SC-GHG. DOE agrees with this assessment and will continue to follow developments in the literature pertaining to this issue. DOE also notes that while OMB's 2003 Circular A-4 recommends using 3-percent and 7-percent discount rates as “default” values, Circular A-4 also reminds agencies that “different regulations may call for different emphases in the analysis, depending on the nature and complexity of the regulatory issues and the sensitivity of the benefit and cost estimates to the key assumptions.” On discounting, Circular A-4 recognizes that “special ethical considerations arise when comparing benefits and costs across generations,” and Circular A-4 acknowledges that analyses may appropriately “discount future costs and consumption benefits . . . at a lower rate than for intragenerational analysis.” In the 2015 Response to Comments on the Social Cost of Carbon for Regulatory Impact Analysis, OMB, DOE, and the other IWG members recognized that “Circular A-4 is a living document” and “the use of 7 percent is not considered appropriate for intergenerational discounting. There is wide support for this view in the academic literature, and it is recognized in Circular A-4 itself.” Thus, DOE concludes that a 7-percent discount rate is not appropriate to apply to value the social cost of greenhouse gases in the analysis presented in this analysis.
To calculate the present and annualized values of climate benefits, DOE uses the same discount rate as the rate used to discount the value of damages from future GHG emissions, for internal consistency. That approach to discounting follows the same approach that the February 2021 SC-GHG TSD recommends “to ensure internal consistency— i.e., future damages from climate change using the SC-GHG at 2.5 percent should be discounted to the base year of the analysis using the same 2.5 percent rate.” DOE has also consulted the National Academies' 2017 recommendations on how SC-GHG estimates can “be combined in RIAs with other cost and benefits estimates that may use different discount rates.” The National Academies reviewed several options, including “presenting all discount rate combinations of other costs and benefits with [SC-GHG] estimates.”
As a member of the IWG involved in the development of the February 2021 SC-GHG TSD, DOE agrees with the above assessment and will continue to follow developments in the literature pertaining to this issue. While the IWG works to assess how best to incorporate the latest, peer-reviewed science to develop an updated set of SC-GHG estimates, it set the interim estimates to be the most recent estimates developed by the IWG prior to the group being disbanded in 2017. The estimates rely on the same models and harmonized inputs and are calculated using a range of discount rates. As explained in the February 2021 SC-GHG TSD, the IWG has recommended that agencies revert to the same set of four values drawn from the SC-GHG distributions based on three discount rates as were used in regulatory analyses between 2010 and 2016 and were subject to public comment. For each discount rate, the IWG combined the distributions across models and socioeconomic emissions scenarios (applying equal weight to each) and then selected a set of four values recommended for use in benefit-cost analyses: an average value resulting from the model runs for each of three discount rates (2.5 percent, 3 percent, and 5 percent), plus a fourth value, selected as the 95th percentile of estimates based on a 3-percent discount rate. The fourth value was included to provide information on potentially higher-than-expected economic impacts from climate change. As explained in the February 2021 SC-GHG TSD, and DOE agrees, this update reflects the immediate need to have an operational SC-GHG for use in regulatory benefit-cost analyses and other applications that was developed using a transparent process, peer-reviewed methodologies, and the science available at the time of that process. Those estimates were subject to public comment in the context of dozens of proposed rulemakings as well as in a dedicated public comment period in 2013.
There are a number of limitations and uncertainties associated with the SC-GHG estimates. First, the current scientific and economic understanding of discounting approaches suggests discount rates appropriate for intergenerational analysis in the context of climate change are likely to be less than 3 percent, near 2 percent or lower. ^{187} Second, the IAMs used to produce these interim estimates do not include all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature and the science underlying their “damage functions”— i.e., the core parts of the IAMs that map global mean temperature changes and other physical impacts of climate change into economic (both market and nonmarket) damages—lags behind the most recent research. For example, limitations include the incomplete treatment of catastrophic and non-catastrophic impacts in the integrated assessment models, their incomplete treatment of adaptation and technological change, the incomplete way in which inter-regional and intersectoral linkages are modeled, uncertainty in the extrapolation of damages to high temperatures, and inadequate representation of the relationship between the discount rate and uncertainty in economic growth over long time horizons. Likewise, the socioeconomic and emissions scenarios used as inputs to the models do not reflect new information from the last decade of scenario generation or the full range of projections. The modeling limitations do not all work in the same direction in terms of their influence on the SC-CO 2 estimates. However, as discussed in the February 2021 SC-GHG TSD, the IWG has recommended that, taken together, the limitations suggest that the interim SC-GHG estimates used in this final rule likely underestimate the damages from GHG emissions. DOE concurs with this assessment.
^{187} Interagency Working Group on Social Cost of Greenhouse Gases. 2021. Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990. February. United States Government. Available at www.whitehouse.gov/briefing-room/blog/2021/02/26/a-return-to-science-evidence-based-estimates-of-the-benefits-of-reducing-climate-pollution/.
DOE's derivations of the SC-CO 2 , SC-N 2 O, and SC-CH 4 values used for this NOPR are discussed in the following sections, and the results of DOE's analyses estimating the benefits of the reductions in emissions of these GHGs are presented in section V.B.6 of this document.

a. Social Cost of Carbon
The SC-CO 2 values used for this final rule were based on the values developed for the February 2021 SC-GHG TSD, which are shown in Table IV.30 in 5-year increments from 2020 to 2050. The set of annual values that DOE used, which was adapted from estimates published by EPA, ^{188} is presented in appendix 14A of the final rule TSD. These estimates are based on methods, assumptions, and parameters identical to the estimates published by the IWG (which were based on EPA modeling), and include values for 2051 to 2070. DOE expects additional climate benefits to accrue for products still operating after 2070, but a lack of available SC-CO 2 estimates for emissions years beyond 2070 prevents DOE from monetizing these potential benefits in this analysis.
^{188} See EPA, “Revised 2023 and Later Model Year Light-Duty Vehicle GHG Emissions Standards: Regulatory Impact Analysis,” Washington, DC, December 2021. Available at nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1013ORN.pdf (last accessed Feb. 21, 2023).
DOE multiplied the CO 2 emissions reduction estimated for each year by the SC-CO 2 value for that year in each of the four cases. DOE adjusted the values to 2022$ using the implicit price deflator for gross domestic product (GDP) from the Bureau of Economic Analysis. To calculate a present value of the stream of monetary values, DOE discounted the values in each of the four cases using the specific discount rate that had been used to obtain the SC-CO 2 values in each case.

b. Social Cost of Methane and Nitrous Oxide
The SC-CH 4 and SC-N 2 O values used for this final rule were based on the values developed for the February 2021 SC-GHG TSD. Table IV.31 shows the updated sets of SC-CH 4 and SC-N 2 O estimates from the latest interagency update in 5-year increments from 2020 to 2050. The full set of annual values used is presented in appendix 14A of the final rule TSD. To capture the uncertainties involved in regulatory impact analysis, DOE has determined it is appropriate to include all four sets of SC-CH 4 and SC-N 2 O values, as recommended by the IWG. DOE derived values after 2050 using the approach described above for the SC-CO 2 .
DOE multiplied the CH 4 and N 2 O emissions reduction estimated for each year by the SC-CH 4 and SC-N 2 O estimates for that year in each of the cases. DOE adjusted the values to 2022$ using the implicit price deflator for GDP from the Bureau of Economic Analysis. To calculate a present value of the stream of monetary values, DOE discounted the values in each of the cases using the specific discount rate that had been used to obtain the SC-CH 4 and SC-N 2 O estimates in each case.

c. Sensitivity Analysis Using EPA's New SC-GHG Estimates
In the regulatory impact analysis of EPA's December 2023 Final Rulemaking, “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review,” EPA estimated climate benefits using a new set of Social Cost of Greenhouse Gas (SC-GHG) estimates. These estimates incorporate recent research addressing recommendations of the National Academies (2017), responses to public comments on an earlier sensitivity analysis using draft SC-GHG estimates, and comments from a 2023 external peer review of the accompanying technical report. ^{189}
^{189} For further information about the methodology used to develop these values, public comments, and information pertaining to the peer review, see https://www.epa.gov/environmental-economics/scghg.
The full set of annual values is presented in appendix 14C of the direct final rule TSD. Although DOE continues to review EPA's estimates, for this rulemaking, DOE used these new SC-GHG values to conduct a sensitivity analysis of the value of GHG emissions reductions associated with alternative standards for distribution transformers. This sensitivity analysis provides an expanded range of potential climate benefits associated with amended standards. The final year of EPA's new estimates is 2080; therefore, DOE did not monetize the climate benefits of GHG emissions reductions occurring after 2080.
The results of the sensitivity analysis are presented in appendix 14C of the final rule TSD. The overall climate benefits are larger when using EPA's higher SC-GHG estimates, compared to the climate benefits using the more conservative IWG SC-GHG estimates. However, DOE's conclusion that the standards are economically justified remains the same regardless of which SC-GHG estimates are used.

2. Monetization of Other Emissions Impacts
For the final rule, DOE estimated the monetized value of NO X and SO 2 emissions reductions from electricity generation using benefit-per-ton estimates for that sector from the EPA's Benefits Mapping and Analysis Program. ^{190} DOE used EPA's values for PM 2.5 -related benefits associated with NO X and SO 2 and for ozone-related benefits associated with NO X for 2025 and 2030, 2035, and 2040, calculated with discount rates of 3 percent and 7 percent. DOE used linear interpolation to define values for the years not given in the 2025 to 2040 period; for years beyond 2040, the values are held constant (rather than extrapolated) to be conservative. DOE combined the EPA regional benefit-per-ton estimates with regional information on electricity consumption and emissions from AEO2023 to define weighted-average national values for NO X and SO 2.
^{190} U.S. Environmental Protection Agency. Estimating the Benefit per Ton of Reducing Directly-Emitted PM 2.5 , PM 2.5 Precursors and Ozone Precursors from 21 Sectors. www.epa.gov/benmap/estimating-benefit-ton-reducing-directly-emitted-pm25-pm25-precursors-and-ozone-precursors.
DOE received the following comments regarding its monetization of emissions impacts.
The Chamber of Commerce urged DOE to reconsider the use of the SC-GHG estimates in this rulemaking based on three core concerns. First, the Chamber of Commerce commented that before DOE considers applying the SC-GHG estimates to the proposed rule (and, likewise, to any final rule resulting from this rulemaking), the SC-GHG estimates should be subject to a proper administrative process, including a full and fair public comment process, as well as a robust independent peer review. Second, the Chamber of Commerce stated that there are statutory limitations on using the SC-GHG estimates, and it urged DOE to fully consider the applicable limits before applying the estimates. Third, the Chamber of Commerce urged DOE to carefully consider whether the “major questions” doctrine precludes the application of the SC-GHG estimates in the proposed rule given the political and economic significance of the estimates. (Chamber of Commerce, No. 88 at p. 6)
In response, DOE first notes that it would reach the same conclusion presented in this final rule in the absence of the social cost of greenhouse gases. As it relates to the Chamber of Commerce's first comment, DOE reiterates that the SC-GHG estimates were developed using a transparent process, peer-reviewed methodologies, the best science available at the time of that process, and input from the public.
Regarding possible statutory limitations on using the SC-GHG estimates, DOE maintains that environmental and public health benefits associated with the more efficient use of energy, including those connected to global climate change, are important to take into account when considering the “need for national energy . . . conservation,” which is one of the factors that EPCA requires DOE to evaluate in determining whether a potential energy conservation standard is economically justified. (42 U.S.C. 6295(o)(2)(B)(i)(VI)); Zero Zone, Inc. v. United States DOE, 832 F.3d 654, 677 (7th Cir. 2016) (pointing to 42 U.S.C. 6295(o)(2)(B)(i)(VI) in concluding that “[w]e have no doubt that Congress intended that DOE have the authority under the EPCA to consider the reduction in SCC.”) DOE has been analyzing the monetized emissions impacts from its rules, for over 10 years. In addition, Executive Order 13563, “Improving Regulation and Regulatory Review,” which was re-affirmed on January 20, 2021, states that each agency, among other things, must, to the extent permitted by law: “select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity).” E.O. 13563, Section 1(b). Furthermore, as noted previously, E.O. 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” re-established the IWG and directed it to ensure that the U.S. Government's estimates of the social cost of carbon and other greenhouse gases reflect the best available science and the recommendations of the National Academies. As a member of the IWG involved in the development of the February 2021 SC-GHG TSD, DOE agrees that the interim SC-GHG estimates represent the most appropriate estimate of the SC-GHG until revised estimates have been developed reflecting the latest, peer-reviewed science. For these reasons, DOE includes monetized emissions reductions in its evaluation of potential standard levels.
Regarding whether the “major questions” doctrine precludes the application of the SC-GHG estimates in proposed or final rules, DOE notes that the “major questions” doctrine raised by the Chamber of Commerce applies only in “extraordinary cases” concerning Federal agencies claiming highly consequential regulatory authority beyond what Congress could reasonably be understood to have granted. West Virginia v. EPA, 142 S. Ct. 2587, 2609 (2022); N.C. Coastal Fisheries Reform Grp. v. Capt. Gaston LLC, 2023 U.S. App. LEXIS 20325, *6-8 (4th Cir., Aug. 7, 2023) (listing the hallmarks courts have recognized to invoke the major questions doctrine, such as a hesitancy “to recognize new-found powers in old statutes against a backdrop of an agency failing to invoke them previously,” “when the asserted power raises federalism concerns,” or “when the asserted authority falls outside the agency's traditional expertise, . . . or is found in an `ancillary provision.' ”). DOE has clear authorization under EPCA to regulate the energy efficiency or energy use of a variety of COMMERCIAL AND INDUSTRIAL equipment, including distribution transformers. Although DOE routinely conducts an analysis of the anticipated emissions impacts of potential energy conservation standards under consideration, see, e.g., Zero Zone, 832 F.3d at 677, DOE does not purport to regulate such emissions, and as stated elsewhere in this document, DOE's selection of standards would be the same without consideration of emissions. Where DOE applied the factors it was tasked to consider under EPCA and the rule is justified even absent use of the SC-GHG analysis, the major questions doctrine has no bearing.
The Institute for Policy Integrity (IPI) commented that DOE appropriately applies the social cost estimates developed by the IWG to its analysis of climate benefits. IPI stated that these values are widely agreed to underestimate the full social costs of greenhouse gas emissions, but for now they remain appropriate to use as conservative estimates. (IPI, No. 123 at p. 1)
DOE agrees that the interim SC-GHG values applied for this final rule are conservative estimates. In the February 2021 SC-GHG TSD, the IWG stated that the models used to produce the interim estimates do not include all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature. For these same impacts, the science underlying their “damage functions” lags behind the most recent research. In the judgment of the IWG, these and other limitations suggest that the range of four interim SC-GHG estimates presented in the TSD likely underestimate societal damages from GHG emissions. The IWG is in the process of assessing how best to incorporate the latest peer-reviewed science and the recommendations of the National Academies to develop an updated set of SC-GHG estimates, and DOE remains engaged in that process.
IPI suggested that DOE should state that criticisms of the social cost of greenhouse gases are moot in this rulemaking because the proposed rule is justified without them. DOE agrees that the proposed rule is economically justified without including climate benefits associated with reduced GHG emissions. (IPI, No. 123 at p. 2)
IPI commented that DOE should consider applying sensitivity analysis using EPA's draft climate-damage estimates released in November 2022, as EPA's work faithfully implements the road map laid out in 2017 by the National Academies of Sciences and applies recent advances in the science and economics on the costs of climate change. (IPI, No. 123 at p. 1)
DOE typically does not conduct analyses using draft inputs that are still under review. DOE notes that because the EPA's draft estimates are considerably higher than the IWG's interim SC-GHG values applied for this final rule, an analysis that used the draft values would result in significantly greater climate-related benefits. However, such results would not affect DOE's decision in this proposed rule.

M. Utility Impact Analysis
The utility impact analysis estimates the changes in installed electrical capacity and generation projected to result for each considered TSL. The analysis is based on published output from the NEMS associated with AEO2023. NEMS produces the AEO Reference case, as well as a number of side cases that estimate the economy-wide impacts of changes to energy supply and demand. For the current analysis, impacts are quantified by comparing the levels of electricity sector generation, installed capacity, fuel consumption and emissions in the AEO2023 Reference case and various side cases. Details of the methodology are provided in the appendices to chapters 13 and 15 of the final rule TSD.
The output of this analysis is a set of time-dependent coefficients that capture the change in electricity generation, primary fuel consumption, installed capacity and power sector emissions due to a unit reduction in demand for a given end use. These coefficients are multiplied by the stream of electricity savings calculated in the NIA to provide estimates of selected utility impacts of potential new or amended energy conservation standards.

N. Employment Impact Analysis
DOE considers employment impacts in the domestic economy as one factor in selecting a standard. Employment impacts from new or amended energy conservation standards include both direct and indirect impacts. Direct employment impacts are any changes in the number of employees of manufacturers of the products subject to standards, their suppliers, and related service firms. The MIA addresses those impacts. Indirect employment impacts are changes in national employment that occur due to the shift in expenditures and capital investment caused by the purchase and operation of more-efficient appliances. Indirect employment impacts from standards consist of the net jobs created or eliminated in the national economy, other than in the manufacturing sector being regulated, caused by (1) reduced spending by consumers on energy, (2) reduced spending on new energy supply by the utility industry, (3) increased consumer spending on the products to which the new standards apply and other goods and services, and (4) the effects of those three factors throughout the economy.
One method for assessing the possible effects on the demand for labor of such shifts in economic activity is to compare sector employment statistics developed by the Labor Department's Bureau of Labor Statistics (BLS). BLS regularly publishes its estimates of the number of jobs per million dollars of economic activity in different sectors of the economy, as well as the jobs created elsewhere in the economy by this same economic activity. Data from BLS indicate that expenditures in the utility sector generally create fewer jobs (both directly and indirectly) than expenditures in other sectors of the economy. ^{191} There are many reasons for these differences, including wage differences and the fact that the utility sector is more capital-intensive and less labor-intensive than other sectors. Energy conservation standards have the effect of reducing consumer utility bills. Because reduced consumer expenditures for energy likely lead to increased expenditures in other sectors of the economy, the general effect of efficiency standards is to shift economic activity from a less labor-intensive sector ( i.e., the utility sector) to more labor-intensive sectors ( e.g., the retail and service sectors). Thus, the BLS data suggest that net national employment may increase due to shifts in economic activity resulting from energy conservation standards.
^{191} See U.S. Department of Commerce-Bureau of Economic Analysis. Regional Input-Output Modeling System (RIMS II) User's Guide. Available at: apps.bea.gov/resources/methodologies/RIMSII-user-guide (last accessed Sept. 12, 2022).
DOE estimated indirect national employment impacts for the standard levels considered in this final rule using an input/output model of the U.S. economy called Impact of Sector Energy Technologies version 4 (ImSET). ^{192} ImSET is a special-purpose version of the U.S. Benchmark National Input-Output (I-O) model, which was designed to estimate the national employment and income effects of energy-saving technologies. The ImSET software includes a computer-based I-O model having structural coefficients that characterize economic flows among 187 sectors most relevant to industrial, commercial, and residential building energy use.
^{192} Livingston, O. V., S. R. Bender, M. J. Scott, and R. W. Schultz. ImSET 4.0: Impact of Sector Energy Technologies Model Description and User's Guide. 2015. Pacific Northwest National Laboratory: Richland, WA. PNNL-24563.
DOE notes that ImSET is not a general equilibrium forecasting model, and that there are uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Because ImSET does not incorporate price changes, the employment effects predicted by ImSET may overestimate actual job impacts over the long run for this rule. Therefore, DOE used ImSET only to generate results for near-term timeframes (2034), where these uncertainties are reduced. In the long-term DOE expects that the net effect from amended standards will be an increased shift towards consumer goods from the utility sector. For more details on the employment impact analysis, see chapter 16 of the final rule TSD.

V. Analytical Results and Conclusions
The following section addresses the results from DOE's analyses with respect to the considered energy conservation standards for distribution transformers. It addresses the TSLs examined by DOE, the projected impacts of each of these levels if adopted as energy conservation standards for distribution transformers, and the standards levels that DOE is adopting in this final rule. Additional details regarding DOE's analyses are contained in the final rule TSD supporting this document.

A. Trial Standard Levels
In general, DOE typically evaluates potential new or amended standards for products and equipment by grouping individual efficiency levels for each class into TSLs. Use of TSLs allows DOE to identify and consider manufacturer cost interactions between the equipment classes, to the extent that there are such interactions, and price elasticity of consumer purchasing decisions that may change when different standard levels are set.
In the analysis conducted for this final rule, DOE analyzed the benefits and burdens of five TSLs for distribution transformers. DOE developed TSLs that combine efficiency levels for each analyzed equipment class and kVA rating. For this analysis, DOE defined its efficiency levels as a percentage reduction in baseline losses ( See section IV.F.2 of this document). To create TSLs, DOE maintained this approach and directly mapped ELs to TSLs, for low-voltage dry-type and medium-voltage dry-type distribution transformers. To create TSLs for liquid-immersed distribution transformers other than submersible distribution transformers, DOE directly mapped ELs to TSLs for TSL 1, 2, 4, and 5. For TSL 3, DOE considered a TSL wherein class 1A and 2A were mapped to EL 4 and equipment class 1B and 2B were mapped to EL 2, which corresponds to a TSL where a diversity of domestically produced core materials are cost competitive without requiring substantial investments in new capacity for core materials.
DOE notes that all TSLs align with the TSLs from the NOPR except for liquid-immersed TSL 3. In the NOPR, DOE mapped EL 3 to TSL 3.
In this final rule, DOE modified TSL 3 for liquid-immersed distribution transformers such that for equipment classes 1A, 1B, 2A, and 2B TSL3 is a combination wherein equipment classes 1B and 2B are set at EL2, and 1A and 2A are set at EL4. This ensures that capacity for amorphous ribbon increases driven by equipment classes 1A and 2A; and leaves a considerable portion of the market at efficiency levels where GOES remains cost competitive, equipment classes 1B and 2B. Further, TSL 3 ensures that units that are more likely to have high currents (equipment class 2B) and units that are more likely to be overloaded (equipment class 1B), have additional flexibility in meeting efficiency standards to accommodate this consumer utility, as discussed in sections IV.A.2.b and IV.A.2.c of this document. For all other equipment classes TSL 3 is identical to that which was presented in the January 2023 NOPR. DOE notes that the ELs used in the final rule correspond to an identical reduction in rated losses as the ELs used in the January 2023 NOPR. However, the grouping of these ELs by equipment class has been modified in response to stakeholder feedback. TSL3 is intended to reflect stakeholder concerns that substantial amorphous core production could lead to near term supply chain constraints given the investment required to transition the entire U.S. market to amorphous cores.
DOE notes that both EL 3 and EL 4 for liquid-immersed distribution transformers generally are met with substantial amorphous core production and therefore would have similar consumer and manufacturer impacts along with similar concerns regarding supply chain and domestic core production. DOE considered, and adopts, TSL 3 in this final rule to maximize the energy savings and consumer benefits without requiring that the entire market transition to amorphous cores, which, as discussed, would not be economically justified.
Liquid-immersed submersible distribution transformers remain at baseline for all TSLs except max-tech. For submersible distribution transformers, being able to fit in an existing vault is a performance related feature of significant consumer utility and these transformers often serve high density applications. DOE recognizes that beyond some size increase a vault replacement may be necessary, however, DOE lacks sufficient data as to where exactly that vault replacement is needed. In order to maintain the consumer utility associated with submersible transformers, DOE has taken the conservative approach of not considering TSLs for submersible transformers aside from max-tech. DOE presents the results for the TSLs in this document, while the results for all efficiency levels that DOE analyzed are in the final rule TSD.
Table V.2 presents the TSLs and the corresponding efficiency levels that DOE has identified for potential amended energy conservation standards for distribution transformers. TSL 5 represents the maximum technologically feasible (“max-tech”) energy efficiency for all product classes. TSL 4 represents a loss reduction over baseline of 20 percent for liquid-immersed transformers, except submersible liquid-immersed transformers which remain at baseline; a 40 and 30 percent reduction in baseline losses for single-, and three-phase low-voltage distribution transformers, respectively; and a 30 percent reduction in baseline losses for all medium-voltage dry-type distribution transformers. TSL 3 represents a loss reduction over baseline of 5 percent for liquid-immersed transformers for single-phase transformers less than or equal to 100 kVA and three-phase transformers greater than or equal to 500 kVA and a loss reduction over baseline of 20 percent for all other liquid-immersed transformers, except submersible liquid-immersed transformers which remain at baseline; a 30 and 20 percent reduction in baseline losses for single-, and three-phase low-voltage distribution transformers, respectively; and a 20 percent reduction in baseline losses for all medium-voltage dry-type distribution transformers. TSL 2 represents a loss reduction over baseline of 5 percent for liquid-immersed transformers, except submersible liquid-immersed transformers which remain at baseline; a 20 and 10 percent reduction in baseline losses for single-, and three-phase low-voltage distribution transformers, respectively; and a 10 percent reduction in baseline losses for all medium-voltage dry-type distribution transformers. TSL 1 represents a loss reduction over baseline of 2.5 percent for liquid-immersed transformers, except submersible liquid-immersed transformers which remain at baseline; a 10 and 5 percent reduction in baseline losses for single-, and three-phase low-voltage distribution transformers, respectively; and a 5 percent reduction in baseline losses for all medium-voltage dry-type distribution transformers.
DOE constructed the TSLs for this final rule to include ELs representative of ELs with similar characteristics ( i.e., using similar technologies and/or efficiencies, and having roughly comparable equipment availability) and taking into consideration the domestic electrical steel and amorphous capacity and conversion cost impacts associated with various ELs. The use of representative ELs provided for greater distinction between the TSLs. While representative ELs were included in the TSLs, DOE considered all efficiency levels as part of its analysis. ^{193}
^{193} Efficiency levels that were analyzed for this final rule are discussed in section IV.F.2 of this document. Results by efficiency level are presented in TSD chapters 8, 10, and 12.

B. Economic Justification and Energy Savings

1. Economic Impacts on Individual Consumers
DOE analyzed the economic impacts on distribution transformer consumers by looking at the effects that potential amended standards at each TSL would have on the LCC and PBP. DOE also examined the impacts of potential standards on selected consumer subgroups. These analyses are discussed in the following sections.

a. Life-Cycle Cost and Payback Period
In general, higher-efficiency products affect consumers in two ways: (1) purchase price increases and (2) annual operating costs decrease. Inputs used for calculating the LCC and PBP include total installed costs ( i.e., product price plus installation costs), and operating costs ( i.e., annual energy use, energy prices, energy price trends, repair costs, and maintenance costs). The LCC calculation also uses product lifetime and a discount rate. Chapter 8 of the final rule TSD provides detailed information on the LCC and PBP analyses.
The following sections show the LCC and PBP results for the TSLs considered for each product class. In the first of each pair of tables, the simple payback is measured relative to the baseline product. In the second table, the impacts are measured relative to the efficiency distribution in the in the no-new-standards case in the compliance year ( see section IV.F.10 of this document). Because some consumers purchase products with higher efficiency in the no-new-standards case, the average savings are less than the difference between the average LCC of the baseline product and the average LCC at each TSL. The savings refer only to consumers who are affected by a standard at a given TSL. Those who already purchase a product with efficiency at or above a given TSL are not affected. Consumers for whom the LCC increases at a given TSL experience a net cost.

Liquid-Immersed Distribution Transformer

Medium-Voltage Dry-Type Distribution Transformer

b. Consumer Subgroup Analysis
In the consumer subgroup analysis, DOE estimated the impact of the considered TSLs on utilities who deploy distribution transformers in vaults or other space constrained areas, and utilities who serve low population densities. For each of these subgroups, DOE compares the average LCC savings and PBP at each efficiency level for the consumer subgroups with similar metrics.
For the utilities serving low-population densities subgroup DOE presents the impacts of small single-phase liquid-immersed (equipment class 1B) against the those determined for the National average. DOEs analysis show that the impacts for utilities serving low populations to be negligible in terms of impacts and increased total installed cost, see Table V.23 and Table V.24.
In most cases, the average LCC savings and PBP for utilities serving low populations at the considered trial standard levels are not substantially different from the average for all consumers. Chapter 11 of the final rule TSD presents the complete LCC and PBP results for the subgroups.

Utilities Serving Low Population Densities

Utilities That Deploy Distribution Transformers in Vaults or Other Space Constrained Areas
As noted in section IV.I of this document, for this final rule DOE considered submersible distribution transformers and their associated vault, or space constrained installation costs with individual representative units, 15 and 16. DOE has incorporated increased installation costs as a function of increased volume in these results. However, as discussed in sections IV.1.2 and V.A of this document, there is considerable uncertainty surrounding the volume increase at which vault replacement would become necessary, and were this to occur at a lower volume than assumed and/or were the volume to increase with EL at a higher rate than assumed, this would result in significantly worse average LCC savings. Due to this significant uncertainty, DOE is unable to pinpoint at which EL, if any, this would occur. The consumer results for these equipment are presented in Table V.25 and Table V.26.

c. Rebuttable Presumption Payback
As discussed in section IV.F.11, EPCA establishes a rebuttable presumption that an energy conservation standard is economically justified if the increased purchase cost for a product that meets the standard is less than three times the value of the first-year energy savings resulting from the standard. In calculating a rebuttable presumption PBP for each of the considered TSLs, DOE used discrete values and, as required by EPCA, based the energy use calculation on the DOE test procedures for distribution transformers. In contrast, the PBPs presented in section V.B.1.a of this document were calculated using distributions that reflect the range of energy use in the field.
Table V.27 presents the rebuttable-presumption PBPs for the considered TSLs for distribution transformers. While DOE examined the rebuttable-presumption criterion, it considered whether the standard levels considered for this rule are economically justified through a more detailed analysis of the economic impacts of those levels, pursuant to 42 U.S.C. 6295(o)(2)(B)(i), that considers the full range of impacts to the consumer, manufacturer, Nation, and environment. The results of that analysis serve as the basis for DOE to definitively evaluate the economic justification for a potential standard level, thereby supporting or rebutting the results of any preliminary determination of economic justification.

2. Economic Impacts on Manufacturers
DOE performed an MIA to estimate the impact of amended energy conservation standards on manufacturers of distribution transformers. The next section describes the expected impacts on manufacturers at each considered TSL. Chapter 12 of the final rule TSD explains the analysis in further detail.

a. Industry Cash Flow Analysis Results
In this section, DOE provides GRIM results from the analysis, which examines changes in the industry that would result from amended standards. The following tables summarize the estimated financial impacts (represented by changes in INPV) of potential amended energy conservation standards on manufacturers of distribution transformers, as well as the conversion costs that DOE estimates manufacturers of distribution transformers would incur at each TSL. DOE analyzes the potential impacts on INPV separately for each category of distribution transformer manufacturer: liquid-immersed, LVDT, and MVDT.
As discussed in section IV.J.2.d of this document, DOE modeled two scenarios to evaluate a range of cash flow impacts on the distribution transformer industry: (1) the preservation of gross margin scenario and (2) the preservation of operating profit scenario. In the preservation of gross margin scenario, distribution transformer manufacturers are able to maintain the same gross margin percentage, even as the MPCs of distribution transformers increase due to energy conservation standards. In this scenario, the same gross margin percentage of 20 percent ^{194} is applied across all ELs. In the preservation of operating profit scenario, manufacturers do not earn additional operating profit when compared to the no-standards case scenario. While manufacturers make the necessary upfront investments required to produce compliant equipment, per-unit operating profit does not change in absolute dollars. The preservation of operating profit scenario results in the lower (or more severe) bound to impacts of amended standards on industry.
^{194} The gross margin percentage of 20 percent is based on a manufacturer markup of 1.25.
Each of the modeled scenarios results in a unique set of cash flows and corresponding industry values at each TSL for each category of distribution transformer manufacturer. In the following discussion, the INPV results refer to the difference in industry value between the no-new-standards case and each standards case resulting from the sum of discounted cash flows from 2024 through 2058. To provide perspective on the short-run cash flow impact, DOE includes in the discussion of results a comparison of free cash flow between the no-new-standards case and the standards case at each TSL in the year before amended standards are required.
DOE presents the range in INPV for liquid-immersed distribution transformer manufacturers in Table V.28 and Table V.29; the range in INPV for LVDT distribution transformer manufacturers in Table V.31 and Table V.32; and the range in INPV for MVDT distribution transformer manufacturers in Table V.34 and Table V.35.

Liquid-Immersed Distribution Transformers
At TSL 5, DOE estimates the impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$686 million to −$338 million, corresponding to a change in INPV of −38.3 percent to −18.8 percent. At TSL 5, industry free cash flow is estimated to decrease by approximately 245 percent to −$175 million, compared to the no-new-standard case value of $121 million in 2028, the year before the compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech, for all liquid-immersed distribution transformers. DOE estimates that less than one percent of shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates liquid-immersed distribution transformer manufacturers would spend approximately $194 million in product conversion costs to redesign transformers and approximately $503 million in capital conversion costs as all liquid-immersed distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 5, the shipment weighted average MPC for liquid-immersed distribution transformers significantly increases by 27.0 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $697 million in conversion costs estimated at TSL 5, ultimately results in a significantly negative change in INPV at TSL 5 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 27.0 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $697 million in conversion costs incurred by manufacturers cause a significantly negative change in INPV at TSL 5 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 4, DOE estimates the impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$476 million to −$388 million, corresponding to a change in INPV of −26.6 percent to −21.6 percent. At TSL 4, industry free cash flow is estimated to decrease by approximately 204 percent to −$125 million, compared to the no-new-standard case value of $121 million in 2028, the year before the compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all liquid-immersed distribution transformer representative units, except for representative units 15 and 16, which are set at baseline. DOE estimates that less than one percent of shipments would meet or exceed these energy conservation standards in the no-new-standards case in 2029. DOE estimates liquid-immersed distribution transformer manufacturers would spend approximately $193 million in product conversion costs to redesign transformers and approximately $395 million in capital conversion costs as almost all liquid-immersed distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 4, the shipment weighted average MPC for liquid-immersed distribution transformers increases by 6.9 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $587 million in conversion costs estimated at TSL 4, ultimately results in a moderately negative change in INPV at TSL 4 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 6.9 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $587 million in conversion costs incurred by manufacturers cause a moderately negative change in INPV at TSL 4 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 3, DOE estimates the impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$145 million to −$111 million, corresponding to a change in INPV of −8.1 percent to −6.2 percent. At TSL 3, industry free cash flow is estimated to decrease by approximately 60 percent to $48 million, compared to the no-new-standard case value of $121 million in 2028, the year before the compliance date.
TSL 3 would set the energy conservation standard at EL 4 for the liquid-immersed distribution transformer representative units 1A, 2A, 3, and 4A; at EL 2 for the liquid-immersed distribution transformer representative units 1B, 2B, 4B, 5, and 17; and at baseline for the liquid-immersed distribution transformer representative units 15 and 16. DOE estimates that approximately 3.7 percent of shipments would meet or exceed these energy conservation standards in the no-new-standards case in 2029. DOE estimates liquid-immersed distribution transformer manufacturers would spend approximately $118 million in product conversion costs to redesign transformers and approximately $69 million in capital conversion costs as a portion of liquid-immersed distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 3, the shipment weighted average MPC for liquid-immersed distribution transformers increases by 2.6 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $187 million in conversion costs estimated at TSL 3, ultimately results in a moderately negative change in INPV at TSL 3 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 2.6 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $187 million in conversion costs incurred by manufacturers cause a moderately negative change in INPV at TSL 3 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 2, DOE estimates the impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$77 million to −$58 million, corresponding to a change in INPV of −4.3 percent to −3.2 percent. At TSL 2, industry free cash flow is estimated to decrease by approximately 32 percent to $82 million, compared to the no-new-standard case value of $121 million in 2028, the year before the compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all liquid-immersed distribution transformer representative units, except for representative units 15 and 16, which are set at baseline. DOE estimates that approximately 4.0 percent of shipments would meet or exceed these energy conservation standards in the no-new-standards case in 2029. DOE estimates liquid-immersed distribution transformer manufacturers would spend approximately $101 million in product conversion costs to redesign transformers and approximately $6 million in capital conversion costs as almost all liquid-immersed distribution transformer cores manufactured are expected to continue to use GOES steel.
At TSL 2, the shipment weighted average MPC for liquid-immersed distribution transformers increases slightly by 1.5 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes a slight increase in manufacturers' free cash flow. However, the $107 million in conversion costs estimated at TSL 2, ultimately results in a slightly negative change in INPV at TSL 2 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 1.5 percent increase in the shipment weighted average MPC results in a slight reduction in the margin after the compliance year. This slight reduction in the manufacturer margin and the $107 million in conversion costs incurred by manufacturers cause a slightly negative change in INPV at TSL 2 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 1, DOE estimates the impacts on INPV for liquid-immersed distribution transformer manufacturers to range from −$66 million to −$62 million, corresponding to a change in INPV of −3.7 percent to −3.5 percent. At TSL 1, industry free cash flow is estimated to decrease by approximately 30 percent to $84 million, compared to the no-new-standard case value of $121 million in 2028, the year before the compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all liquid-immersed distribution transformer representative units, except for representative units 15 and 16, which are set at baseline. DOE estimates that approximately 13.3 percent of shipments would meet or exceed these energy conservation standards in the no-new-standards case in 2029. DOE estimates liquid-immersed distribution transformer manufacturers would spend approximately $100 million in product conversion costs to redesign transformers and approximately $2 million in capital conversion costs as almost all liquid-immersed distribution transformer cores manufactured are expected to continue to use GOES steel.
At TSL 1, the shipment weighted average MPC for liquid-immersed distribution transformers increases slightly by 0.3 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes a slight increase in manufacturers' free cash flow. However, the $102 million in conversion costs estimated at TSL 1, ultimately results in a slightly negative change in INPV at TSL 1 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 0.3 percent increase in the shipment weighted average MPC results in a slight reduction in the margin after the compliance year. This slight reduction in the manufacturer margin and the $102 million in conversion costs incurred by manufacturers cause a slightly negative change in INPV at TSL 1 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.

Low-Voltage Dry-Type Distribution Transformers
At TSL 5, DOE estimates the impacts on INPV for LVDT distribution transformer manufacturers to range from −$68.4 million to −$54.0 million, corresponding to a change in INPV of −32.3 percent to −25.5 percent. At TSL 5, industry free cash flow is estimated to decrease by approximately 183.6 percent to −$17.5 million, compared to the no-new-standard case value of $20.9 million in 2028, the year before the compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech, for all LVDT distribution transformers. DOE estimates that no shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates LVDT distribution transformer manufacturers would spend approximately $31.0 million in product conversion costs to redesign transformers and approximately $60.8 million in capital conversion costs as all LVDT distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 5, the shipment weighted average MPC for LVDT distribution transformers increases by 11.1 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $91.8 million in conversion costs estimated at TSL 5, ultimately results in a moderately negative change in INPV at TSL 5 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 11.1 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $91.8 million in conversion costs incurred by manufacturers cause a significantly negative change in INPV at TSL 5 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 4, DOE estimates the impacts on INPV for LVDT distribution transformer manufacturers to range from −$62.9 million to −$52.2 million, corresponding to a change in INPV of −29.7 percent to −24.7 percent. At TSL 4, industry free cash flow is estimated to decrease by approximately 173.0 percent to −$15.2 million, compared to the no-new-standard case value of $20.9 million in 2028, the year before the compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all LVDT distribution transformers. DOE estimates that no shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates LVDT distribution transformer manufacturers would spend approximately $30.3 million in product conversion costs to redesign transformers and approximately $56.4 million in capital conversion costs as almost all LVDT distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 4, the shipment weighted average MPC for LVDT distribution transformers increases by 8.2 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $86.7 million in conversion costs estimated at TSL 4, ultimately results in a moderately negative change in INPV at TSL 4 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 8.2 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $86.7 million in conversion costs incurred by manufacturers cause a moderately negative change in INPV at TSL 4 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 3, DOE estimates the impacts on INPV for LVDT distribution transformer manufacturers to range from −$27.1 million to −$18.9 million, corresponding to a change in INPV of −12.8 percent to −8.9 percent. At TSL 3, industry free cash flow is estimated to decrease by approximately 68.8 percent to $6.5 million, compared to the no-new-standard case value of $20.9 million in 2028, the year before the compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all LVDT distribution transformers. DOE estimates that less than one percent of shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates LVDT distribution transformer manufacturers would spend approximately $19.9 million in product conversion costs to redesign transformers and approximately $16.3 million in capital conversion costs as a portion of LVDT distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 3, the shipment weighted average MPC for LVDT distribution transformers increases by 6.3 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $36.1 million in conversion costs estimated at TSL 3, ultimately results in a moderately negative change in INPV at TSL 3 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 6.3 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $36.1 million in conversion costs incurred by manufacturers cause a moderately negative change in INPV at TSL 3 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 2, DOE estimates the impacts on INPV for LVDT distribution transformer manufacturers to range from −$10.4 million to −$9.6 million, corresponding to a change in INPV of −4.9 percent to −4.5 percent. At TSL 2, industry free cash flow is estimated to decrease by approximately 30.1 percent to $14.6 million, compared to the no-new-standard case value of $20.9 million in 2028, the year before the compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all LVDT distribution transformers. DOE estimates that approximately 3.7 percent of shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates LVDT distribution transformer manufacturers would spend approximately $15.9 million in product conversion costs to redesign transformers and approximately $1.4 million in capital conversion costs as almost all LVDT distribution transformer cores manufactured are expected to continue to use GOES steel.
At TSL 2, the shipment weighted average MPC for LVDT distribution transformers increases by 0.6 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $17.3 million in conversion costs estimated at TSL 2, ultimately results in a slightly negative change in INPV at TSL 2 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 0.6 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $17.3 million in conversion costs incurred by manufacturers cause a slightly negative change in INPV at TSL 2 in the preservation of operating profit scenario. This represents the lower- bound, or most severe impact, on manufacturer profitability.
At TSL 1, DOE estimates the impacts on INPV for LVDT distribution transformer manufacturers to range from −$8.9 million to −$8.5 million, corresponding to a change in INPV of −4.2 percent to −4.0 percent. At TSL 1, industry free cash flow is estimated to decrease by approximately 26.4 percent to $15.4 million, compared to the no-new-standard case value of $20.9 million in 2028, the year before the compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all LVDT distribution transformers. DOE estimates that approximately 24.5 percent of shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates LVDT distribution transformer manufacturers would spend approximately $15.5 million in product conversion costs to redesign transformers.
At TSL 1, the shipment weighted average MPC for LVDT distribution transformers deceases slightly by 0.3 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In both manufacturer markup scenarios, this slight decrease in manufacturer markup does not have a significant impact on manufacturers' free cash flow. However, in both manufacturer markup scenarios, the $15.5 million in conversion costs estimated at TSL 1, results in a slightly negative change in INPV at TSL 1.

Medium-Voltage Dry-Type Distribution Transformers
At TSL 5, DOE estimates the impacts on INPV for MVDT distribution transformer manufacturers to range from −$33.2 million to −$16.3 million, corresponding to a change in INPV of −34.9 percent to −17.1 percent. At TSL 5, industry free cash flow is estimated to decrease by approximately 200.3 percent to −$7.7 million, compared to the no-new-standard case value of $7.7 million in 2028, the year before the compliance date.
TSL 5 would set the energy conservation standard at EL 5, max-tech, for all MVDT distribution transformers. DOE estimates that no shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates MVDT distribution transformer manufacturers would spend approximately $10.1 million in product conversion costs to redesign transformers and approximately $26.2 million in capital conversion costs as all MVDT distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 5, the shipment weighted average MPC for LVDT distribution transformers significantly increases by 26.3 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $36.2 million in conversion costs estimated at TSL 5, ultimately results in a moderately negative change in INPV at TSL 5 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 26.3 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $36.2 million in conversion costs incurred by manufacturers cause a significantly negative change in INPV at TSL 5 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 4, DOE estimates the impacts on INPV for MVDT distribution transformer manufacturers to range from −$29.5 million to −$18.6 million, corresponding to a change in INPV of −31.0 percent to −19.5 percent. At TSL 4, industry free cash flow is estimated to decrease by approximately 191.7 percent to −$7.0 million, compared to the no-new-standard case value of $7.7 million in 2028, the year before the compliance date.
TSL 4 would set the energy conservation standard at EL 4 for all MVDT distribution transformers. DOE estimates that no shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates LVDT distribution transformer manufacturers would spend approximately $10.1 million in product conversion costs to redesign transformers and approximately $24.7 million in capital conversion costs as all MVDT distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 4, the shipment weighted average MPC for MVDT distribution transformers increases by 17.0 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $34.8 million in conversion costs estimated at TSL 4, ultimately results in a moderately negative change in INPV at TSL 4 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 17.0 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $34.8 million in conversion costs incurred by manufacturers cause a significantly negative change in INPV at TSL 4 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 3, DOE estimates the impacts on INPV for MVDT distribution transformer manufacturers to range from −$26.4 million to −$19.1 million, corresponding to a change in INPV of −27.8 percent to −20.1 percent. At TSL 3, industry free cash flow is estimated to decrease by approximately 179.9 percent to −$6.1 million, compared to the no-new-standard case value of $7.7 million in 2028, the year before the compliance date.
TSL 3 would set the energy conservation standard at EL 3 for all MVDT distribution transformers. DOE estimates that no shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates MVDT distribution transformer manufacturers would spend approximately $9.8 million in product conversion costs to redesign transformers and approximately $22.9 million in capital conversion costs as the majority of MVDT distribution transformer cores manufactured are expected to use amorphous steel.
At TSL 3, the shipment weighted average MPC for MVDT distribution transformers increases by 11.3 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $32.7 million in conversion costs estimated at TSL 3, ultimately results in a moderately negative change in INPV at TSL 3 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 11.3 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $32.7 million in conversion costs incurred by manufacturers cause a moderately negative change in INPV at TSL 3 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 2, DOE estimates the impacts on INPV for MVDT distribution transformer manufacturers to range from −$4.4 million to −$2.3 million, corresponding to a change in INPV of −4.7 percent to −2.5 percent. At TSL 2, industry free cash flow is estimated to decrease by approximately 27.2 percent to $5.6 million, compared to the no-new-standard case value of $7.7 million in 2028, the year before the compliance date.
TSL 2 would set the energy conservation standard at EL 2 for all MVDT distribution transformers. DOE estimates that approximately 3.8 percent of shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates MVDT distribution transformer manufacturers would spend approximately $5.2 million in product conversion costs to redesign transformers and approximately $0.5 million in capital conversion costs as almost all MVDT distribution transformer cores manufactured are expected to continue to use GOES steel.
At TSL 2, the shipment weighted average MPC for MVDT distribution transformers increases by 3.2 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In the preservation of gross margin scenario, manufacturers can fully pass along this cost increase, which causes an increase in manufacturers' free cash flow. However, the $5.7 million in conversion costs estimated at TSL 2, ultimately results in a slightly negative change in INPV at TSL 2 under the preservation of gross margin scenario.
Under the preservation of operating profit scenario, manufacturers earn the same per-unit operating profit as would be earned in the no-new-standards case, but manufacturers do not earn additional profit from their investments or potentially higher MPCs. In this scenario, the 3.2 percent increase in the shipment weighted average MPC results in a reduction in the margin after the compliance year. This reduction in the manufacturer margin and the $5.7 million in conversion costs incurred by manufacturers cause a slightly negative change in INPV at TSL 2 in the preservation of operating profit scenario. This represents the lower-bound, or most severe impact, on manufacturer profitability.
At TSL 1, DOE estimates the impacts on INPV for MVDT distribution transformer manufacturers to range from −$3.5 million to −$2.7 million, corresponding to a change in INPV of −3.6 percent to −2.8 percent. At TSL 1, industry free cash flow is estimated to decrease by approximately 23.4 percent to $5.9 million, compared to the no-new-standard case value of $7.7 million in 2028, the year before the compliance date.
TSL 1 would set the energy conservation standard at EL 1 for all MVDT distribution transformers. DOE estimates that approximately 21.7 percent of shipments would meet these energy conservation standards in the no-new-standards case in 2029. DOE estimates MVDT distribution transformer manufacturers would spend approximately $5.0 million in product conversion costs to redesign transformers.
At TSL 1, the shipment weighted average MPC for MVDT distribution transformers deceases slightly by 1.2 percent relative to the no-new-standards case shipment weighted average MPC in 2029. In both manufacturer markup scenarios, this slight decrease in manufacturer markup does not have a significant impact on manufacturers' free cash flow. However, in both manufacturer markup scenarios, the $5.0 million in conversion costs estimated at TSL 1, results in a slightly negative change in INPV at TSL 1.

b. Direct Impacts on Employment
To quantitatively assess the potential impacts of amended energy conservation standards on direct employment in the distribution transformer industry, DOE used the GRIM to estimate the domestic labor expenditures and number of direct employees in the no-new-standards case and in each of the standards cases during the analysis period.
Production employees are those who are directly involved in fabricating and assembling equipment within a manufacturer facility. Workers performing services that are closely associated with production operations, such as materials handling tasks using forklifts, are included as production labor, as well as line supervisors.
DOE used the GRIM to calculate the number of production employees from labor expenditures. DOE used statistical data from the U.S. Census Bureau's 2021 Annual Survey of Manufacturers (ASM) and the results of the engineering analysis to calculate industry-wide labor expenditures. Labor expenditures related to equipment manufacturing depend on the labor intensity of the product, the sales volume, and an assumption that wages remain fixed in real terms over time. The total labor expenditures in the GRIM were then converted to domestic production employment levels by dividing production labor expenditures by the annual payment per production worker.
Non-production employees account for those workers that are not directly engaged in the manufacturing of the covered equipment. This could include sales, human resources, engineering, and management. DOE estimated non-production employment levels by multiplying the number of distribution transformer workers by a scaling factor. The scaling factor is calculated by taking the ratio of the total number of employees, and the total production workers associated with the industry NAICS code 335311, which covers power, distribution, and specialty transformer manufacturing.
Using data from manufacturer interviews and estimated market share data, DOE estimates that approximately 85 percent of all liquid-immersed distribution transformer manufacturing; 15 percent of all LVDT distribution transformer manufacturing; and 75 percent of all MVDT distribution transformer manufacturing takes place domestically.
Several interested parties commented on the direct employment analysis in the January 2023 NOPR. Some interested parties commented that the standards proposed in the January 2023 NOPR would result in a decrease in domestic employment. UAW commented that it expects mass layoffs as a result of the standards proposed in the January 2023 NOPR since 70 percent of the electrical steel that UAW members produce for Cleveland Cliffs is used in distribution transformer cores. (UAW, No. 90 at P. 2) UAW also commented that currently 90 percent of distribution transformers are made with GOES. Without this demand for GOES, the continued production of all GOES in the United States could be placed in jeopardy. ( Id. ) UAW urged DOE to consider the potential loss of electrical steel jobs as a result of any adopted standards for distribution transformers. ( Id. ) Similarly, UAW Locals commented that the standards proposed in the January 2023 NOPR would make Cleveland Cliffs electrical steel plants uneconomic, which could jeopardize nearly 1,500 steel manufacturing jobs. (UAW Locals, No. 91 at p. 1)
NAHB commented that DOE must consider the possibility that requiring a new manufacturing process to make distribution transformers more efficient may actually require fewer workers. (NAHB, No. 106 at pp. 11-12) Prolec GE commented that any standards that required a shift from GOES production to amorphous steel production would affect domestic employment as currently most of the core manufacturing using GOES is done in-house, and it would need to be shifted to outsourced finished amorphous metal cores where most of the production capacity is not domestic. (Prolec GE, No. 120 at p. 13) Lastly, Cliffs commented that DOE underestimated the required number amount of labor to convert to amorphous production in the January 2023 NOPR and the actual additional number of employees to meet the standards proposed in the January 2023 NOPR will lead to increased offshoring. (Cliffs, No. 105 at pp. 14-15)
Other interested parties comments that the standards proposed in the January 2023 NOPR would result in an increase in domestic employment. Eaton commented that it expects an increase in labor content to meet the standards proposed in the January 2023 NOPR. (Eaton, No. 137 at p. 29) Howard commented that they would need to add 1,000-2,000 employees (which corresponds to a 25-50 percent increase in their current employment levels) to meet the standards proposed in the January 2023 NOPR. (Howard, No. 116 at p. 2) Howard stated they estimate the entire industry could need an additional 5,500 to 6,000 employees to meet the standards proposed in the January 2023 NOPR. (Howard, No. 116 at p. 2) Additionally, Howard commented that in addition to distribution transformer manufacturers adding employees, electrical steel manufacturers would have to add employees as well, which will be difficult given the 3-year compliance period used in the January 2023 NOPR and the current labor market, which lacks available personnel. (Howard, No. 116 at pp. 2-3) Metglas commented that it estimated that amorphous production would require 600 to 900 new U.S. jobs to meet the standards proposed in the January 2023 NOPR. (Metglas, No. 125 at p. 7) Efficiency advocates commented that the expansion of amorphous production capacity would be expected to add hundreds of electrical steel manufacturing jobs. (Efficiency advocates, No. 121 at pp. 4-5) Efficiency advocates additionally stated that producers of GOES would be well positioned to transition production capacity to NOES to preserve manufacturing jobs. ( Id. )
DOE's direct employment analysis conducted in the January 2023 NOPR presented a range of impacts to employment. As some interested parties commented, manufacturing distribution transformers with amorphous cores will likely require additional employees. However, DOE also recognizes that currently many amorphous core manufacturing locations are outside the U.S., as some interested parties commented. DOE continues to present a range of domestic employment impacts in this final rule that show the likely range in domestic employment given that manufacturing more efficient distribution transformers will likely result in an increase in production employees; however, some manufacturers may shift current domestic production to non-domestic locations to fulfill this additional labor demand. The range of potential impacts displayed in Table V.37, Table V.38, and Table V.39 present the most likely range of potential impacts to domestic employment for the analyzed TSLs.

Liquid-Immersed Distribution Transformers
Using the estimated labor content from the GRIM combined with data from the 2021 ASM, DOE estimates that there would be approximately 6,561 domestic production workers, and 2,721 domestic non-production workers involved in liquid-immersed distribution transformer manufacturing in 2029 in the absence of amended energy conservation standards. Table V.37 shows the range of the impacts of energy conservation standards on U.S. production on liquid-immersed distribution transformers.
Amorphous core production is more labor intensive and would require additional labor expenditures. The upper range of the “Potential Change in Total Domestic Employment in 2029” displayed in Table V.37, assumes that all domestic liquid-immersed distribution transformer manufacturing remains in the U.S. For this scenario, the additional labor expenditures associated with amorphous core production result in the number of total direct employees to increase due to energy conservation standards. At higher TSLs, the estimated number of amorphous cores used in liquid-immersed distribution transformers increases, which causes the number of direct employees to also increase. The lower range of the “Potential Change in Total Domestic Employment in 2029” displayed in Table V.37, assumes that as more amorphous cores are used to meet higher energy conservation standards, either the amorphous core production is outsourced to core only manufacturers (manufacturers that specialize in manufacturing cores used in distribution transformers, but do not actually manufacture entire distribution transformers) which may be located in foreign countries, or distribution transformer manufacturing is re-located to foreign countries. This lower range assumes that 30 percent of distribution transformers using amorphous cores are re-located to foreign countries due to energy conservation standards. DOE acknowledges that each distribution transformer manufacturer would individually make a business decision to either make the substantial investments to add or increase their own amorphous core production capabilities and continue to manufacturer their own cores in-house; outsource their amorphous core production to another distribution core manufacturer, which may or may not be located in the U.S.; or re-locate some or all of their distribution transformer manufacturing to a foreign country. DOE acknowledges there is a wide range of potential domestic employment impacts due to energy conservation standards, especially at the higher TSLs. The ranges in potential employment impacts displayed in Table V.37 at each TSL attempt to provide a reasonable upper and lower bound to how liquid-immersed distribution transformer manufacturers may respond to potential energy conservation standards.

Low-Voltage Dry-Type Distribution Transformers
Using the estimated labor content from the GRIM combined with data from the 2021 ASM, DOE estimates that there would be approximately 185 domestic production workers, and 77 domestic non-production workers involved in LVDT distribution transformer manufacturing in 2029 in the absence of amended energy conservation standards. Table V.38 shows the range of the impacts of energy conservation standards on U.S. production on LVDT distribution transformers.
DOE used the same methodology to estimate the potential impacts to domestic employment for LVDT distribution transformer manufacturing that was used for liquid-immersed distribution transformer manufacturing. The upper range of the “Potential Change in Total Domestic Employment in 2029” displayed in Table V.38, assumes that all LVDT distribution transformer manufacturing remains in the U.S. The lower range of the “Potential Change in Total Domestic Employment in 2029”, assumes that 30 percent of distribution transformers using amorphous cores are re-located to foreign countries, either due to amorphous core production that is outsourced to core only manufacturers located in foreign countries or LVDT distribution transformer manufacturers re-locating their distribution transformer production to foreign countries.

Medium-Voltage Dry-Type Distribution Transformers
Using the estimated labor content from the GRIM combined with data from the 2021 ASM, DOE estimates that there would be approximately 300 domestic production workers, and 125 domestic non-production workers involved in MVDT distribution transformer manufacturing in 2029 in the absence of amended energy conservation standards. Table V.39 shows the range of the impacts of energy conservation standards on U.S. production on MVDT distribution transformers.
DOE used the same methodology to estimate the potential impacts to domestic employment for MVDT distribution transformer manufacturing that was used for liquid-immersed distribution transformer manufacturing. The upper range of the “Potential Change in Total Domestic Employment in 2029” displayed in Table V.39, assumes that all MVDT distribution transformer manufacturing remains in the U.S. The lower range of the “Potential Change in Total Domestic Employment in 2029”, assumes that 30 percent of distribution transformers using amorphous cores are re-located to foreign countries, either due to amorphous core production that is outsourced to core only manufacturers located in foreign countries or MVDT distribution transformer manufacturers re-locating their distribution transformer production to foreign countries.

c. Impacts on Manufacturing Capacity
The prices of raw materials currently used in distribution transformers, such as GOES, copper, and aluminum, have all experienced a significant increase in price starting at the beginning of 2021. The availability of these commodities remains a significant concern with distribution transformer manufacturers. As previously stated in the January 2023 NOPR, GOES investment from steel producers is competing with NOES investment suited for electric vehicle production. This competing investment, combined with demand growth supporting other electrification trends has led to a substantial global increase in GOES. However, amorphous alloys have not seen the same significant increase in price as GOES.
The availability of amorphous material is a concern for many distribution transformer manufacturers. Based on information received during manufacturer interviews, some distribution transformer manufacturers suggested that there would not be enough amorphous steel available to be used in all or even most distribution transformers currently sold in the U.S. Other distribution transformer manufacturers and steel suppliers interviewed stated that, while the current capacity of amorphous steel does not exist to supply the majority of the steel used in distribution transformer cores, steel manufacturers are capable of significantly increasing their amorphous steel production if there is sufficient market demand for amorphous steel.
Cliffs commented that the January 2023 NOPR did not accurately account for the supply chain constraints associated with ramping up production of amorphous steel in addition to the tremendous increased demands linked to greater market penetration of electric vehicles and other decarbonization efforts that the steel industry is facing. (Cliffs., No, 105 at p. 15) Cliffs continued stating the increased costs associated with all distribution transformers using amorphous cores, which currently constitutes about three percent of the market for distribution transformers, will be massive and stretch the limits of existing supply chains beyond their breaking point. ( Id. ) Eaton commented that changing the current supply of GOES that used in almost all distribution transformer cores today to having almost all distribution transformers using amorphous cores would disrupt the supply of cores and/or core steel to a massive extent and would likely to be accompanied by some unexpected outcomes. (Eaton, No. 137 at p. 26)
While the availability of both GOES and amorphous steel is a concern for many distribution transformer manufacturers, steel suppliers should be able to meet the market demand for amorphous steel for all TSLs analyzed given the 5-year compliance period for distribution transformers. Steel manufacturers should be able to significantly increase their supply of amorphous steel if they know there will be an increase in the demand for this material due to energy conservation standards for distribution transformers. See section V.C for a more detailed discussion of the expected core materials needed to meet amended standards.
Additionally, in response to the January 2023 NOPR, Howard commented that the standards proposed in the January 2023 NOPR would require them to redesign 8,000—10,000 distribution transformers, which ordinarily would be done over a 5-year period. (Howard, No. 116 at p. 3) Howard also commented that they estimate that facility and equipment additions alone will take 5 years and Howard will need to begin production of new units prior to the actual compliance deadline to ensure all raw materials are used. ( Id. ) In the January 2023 NOPR, DOE used a 3-year compliance period. For this final rule, DOE is adopting a 5-year compliance period. While DOE acknowledges that manufacturers will be required to make significant changes to their manufacturing facilities to be able to produce distribution transformers that use amorphous cores, this is not anticipated to cause manufacturing capacity constraints given the 5-year compliance period. Further, DOE notes that the adopted standards in this final rule require substantially less manufacturer investment than those proposed in the January 2023 NOPR.

d. Impacts on Subgroups of Manufacturers
As discussed in section IV.J.1 of this document, using average cost assumptions to develop an industry cash flow estimate may not be adequate for assessing differential impacts among manufacturer subgroups. Small manufacturers, niche manufacturers, and manufacturers exhibiting a cost structure substantially different from the industry average could be affected disproportionately. DOE used the results of the industry characterization to group manufacturers exhibiting similar characteristics. Consequently, DOE considered four manufacturer subgroups in the MIA: liquid-immersed, LVDT, MVDT, and small manufacturers as a subgroup for a separate impact analysis. DOE discussed the potential impacts on liquid-immersed, LVDT, and MVDT distribution transformer manufacturers separately in sections V.B.2.a and V.B.2.b of this document.
For the small business subgroup analysis, DOE applied the small business size standards published by the Small Business Administration (SBA) to determine whether a company is considered a small business. The size standards are codified at 13 CFR part 121. To be categorized as a small business under NAICS code 335311, “power, distribution, and specialty transformer manufacturing,” a distribution transformer manufacturer and its affiliates may employ a maximum of 800 employees. The 800-employee threshold includes all employees in a business's parent company and any other subsidiaries. For a discussion of the impacts on the small manufacturer subgroup, see the Regulatory Flexibility Analysis in section VI.B of this document.

e. Cumulative Regulatory Burden
One aspect of assessing manufacturer burden involves looking at the cumulative impact of multiple DOE standards and the regulatory actions of other Federal agencies and States that affect the manufacturers of a covered product or equipment. While any one regulation may not impose a significant burden on manufacturers, the combined effects of several existing or impending regulations may have serious consequences for some manufacturers, groups of manufacturers, or an entire industry. Multiple regulations affecting the same manufacturer can strain profits and lead companies to abandon product lines or markets with lower expected future returns than competing products. For these reasons, DOE conducts an analysis of cumulative regulatory burden as part of its rulemakings pertaining to appliance efficiency.
DOE evaluates product-specific regulations that will take effect approximately 3 years before or after the estimated 2029 compliance date of any amended energy conservation standards for distribution transformers. This information is presented in Table V.40.

3. National Impact Analysis
This section presents DOE's estimates of the national energy savings and the NPV of consumer benefits that would result from each of the TSLs considered as potential amended standards.

a. National Energy Savings
To estimate the energy savings attributable to potential amended standards for distribution transformers, DOE compared their energy consumption under the no-new-standards case to their anticipated energy consumption under each TSL. The savings are measured over the entire lifetime of products purchased in the 30-year period that begins in the year of anticipated compliance with amended standards 2029-2058. Table V.41 presents DOE's projections of the national energy savings for each TSL considered for distribution transformers, the results showing DOE's amended standards are in bold. The savings were calculated using the approach described in section IV.H of this document.
OMB Circular A-4 ^{195} requires agencies to present analytical results, including separate schedules of the monetized benefits and costs that show the type and timing of benefits and costs. Circular A-4 also directs agencies to consider the variability of key elements underlying the estimates of benefits and costs. For this rulemaking, DOE undertook a sensitivity analysis using 9 years, rather than 30 years, of product shipments. The choice of a 9-year period is a proxy for the timeline in EPCA for the review of certain energy conservation standards and potential revision of and compliance with such revised standards. ^{196} The review timeframe established in EPCA is generally not synchronized with the product lifetime, product manufacturing cycles, or other factors specific to distribution transformers. Thus, such results are presented for informational purposes only and are not indicative of any change in DOE's analytical methodology. The NES sensitivity analysis results based on a 9-year analytical period are presented in Table V.42. The impacts are counted over the lifetime of distribution transformers purchased during the period 2029-2058, the results showing DOE's amended standards are in bold.
^{195} U.S. Office of Management and Budget. Circular A-4: Regulatory Analysis. Available at www.whitehouse.gov/omb/information-for-agencies/circulars (last accessed January 19, 2024). DOE used the prior version of Circular A-4 (September 17, 2003) in accordance with the effective date of the November 9, 2023 version.
^{196} EPCA requires DOE to review its standards at least once every 6 years, and requires, for certain products, a 3-year period after any new standard is promulgated before compliance is required, except that in no case may any new standards be required within 6 years of the compliance date of the previous standards. (42 U.S.C. 6316(a); 42 U.S.C. 6295(m)) While adding a 6-year review to the 3-year compliance period adds up to 9 years, DOE notes that it may undertake reviews at any time within the 6-year period and that the 3-year compliance date may yield to the 6-year backstop. A 9-year analysis period may not be appropriate given the variability that occurs in the timing of standards reviews and the fact that for some products, the compliance period is 5 years rather than 3 years.

b. Net Present Value of Consumer Costs and Benefits
DOE estimated the cumulative NPV of the total costs and savings for consumers that would result from the TSLs considered for distribution transformers. In accordance with OMB's guidelines on regulatory analysis, ^{197} DOE calculated NPV using both a 7-percent and a 3-percent real discount rate. Table V.43 shows the consumer NPV results with impacts counted over the lifetime of products purchased during the period 2029-2058.
^{197} U.S. Office of Management and Budget. Circular A-4: Regulatory Analysis. September 17, 2003. https://www.whitehouse.gov/wp-content/uploads/legacy_drupal_files/omb/circulars/A4/a-4.pdf#page=33.
The NPV results based on the aforementioned 9-year analytical period are presented in Table V.44. The impacts are counted over the lifetime of products purchased during the period 2029-2037. As mentioned previously, such results are presented for informational purposes only and are not indicative of any change in DOE's analytical methodology or decision criteria.
The previous results reflect the use of a default trend to estimate the change in price for distribution transformers over the analysis period ( see section IV.H.3 of this document). DOE also conducted a sensitivity analysis that considered one scenario with a lower rate of price decline than the reference case and one scenario with a higher rate of price decline than the reference case. The results of these alternative cases are presented in appendix 10C of the final rule TSD. In the high-price-decline case, the NPV of consumer benefits is higher than in the default case. In the low-price-decline case, the NPV of consumer benefits is lower than in the default case.

c. Indirect Impacts on Employment
DOE estimates that amended energy conservation standards for distribution transformers will reduce energy expenditures for consumers of those products, with the resulting net savings being redirected to other forms of economic activity. These expected shifts in spending and economic activity could affect the demand for labor. As described in section IV.N of this document, DOE used an input/output model of the U.S. economy to estimate indirect employment impacts of the TSLs that DOE considered. There are uncertainties involved in projecting employment impacts, especially changes in the later years of the analysis. Therefore, DOE generated results for near-term timeframes (2029-2034), where these uncertainties are reduced.
The results suggest that the adopted standards are likely to have a negligible impact on the net demand for labor in the economy. The net change in jobs is so small that it would be imperceptible in national labor statistics and might be offset by other, unanticipated effects on employment. Chapter 16 of the final rule TSD presents detailed results regarding anticipated indirect employment impacts.

4. Impact on Utility or Performance of Products
As discussed in section IV.C.1.b of this document, DOE has concluded that the standards adopted in this final rule will not lessen the utility or performance of the distribution transformers under consideration in this rulemaking. Manufacturers of these products currently offer units that meet or exceed the adopted standards.

5. Impact of Any Lessening of Competition
DOE considered any lessening of competition that would be likely to result from new or amended standards. As discussed in section III.F.1.e of this document, EPCA directs the Attorney General of the United States (“Attorney General”) to determine the impact, if any, of any lessening of competition likely to result from a proposed standard and to transmit such determination in writing to the Secretary within 60 days of the publication of a proposed rule, together with an analysis of the nature and extent of the impact. To assist the Attorney General in making this determination, DOE provided the Department of Justice (DOJ) with copies of the NOPR and the TSD for review. In its assessment letter responding to DOE, DOJ concluded that the proposed energy conservation standards for distribution transformers are unlikely to have a significant adverse impact on competition. DOE is publishing the Attorney General's assessment at the end of this final rule.

6. Need of the Nation to Conserve Energy
Enhanced energy efficiency, where economically justified, improves the Nation's energy security, strengthens the economy, and reduces the environmental impacts (costs) of energy production. Reduced electricity demand due to energy conservation standards is also likely to reduce the cost of maintaining the reliability of the electricity system, particularly during peak-load periods. Chapter 15 in the final rule TSD presents the estimated impacts on electricity generating capacity, relative to the no-new-standards case, for the TSLs that DOE considered in this rulemaking.
Energy conservation resulting from potential energy conservation standards for distribution transformers is expected to yield environmental benefits in the form of reduced emissions of certain air pollutants and greenhouse gases. Table V.45 through Table V.48 provides DOE's estimate of cumulative emissions reductions expected to result from the TSLs considered in this rulemaking. The emissions were calculated using the multipliers discussed in section IV.K of this document. DOE reports annual emissions reductions for each TSL in chapter 13 of the final rule TSD.
As part of the analysis for this rule, DOE estimated monetary benefits likely to result from the reduced emissions of CO 2 that DOE estimated for each of the considered TSLs for distribution transformers. Section IV.L.1.a of this document discusses the estimated SC-CO 2 values that DOE used. Table V.49 presents the value of CO 2 emissions reduction at each TSL for each of the SC-CO 2 cases. The time-series of annual values is presented for the selected TSL in chapter 14 of the final rule TSD.
As discussed in section IV.L.2 of this document, DOE estimated the climate benefits likely to result from the reduced emissions of methane and N 2 O that DOE estimated for each of the considered TSLs for distribution transformers. Table V.50 presents the value of the CH 4 emissions reduction at each TSL, and Table V.51 presents the value of the N 2 O emissions reduction at each TSL. The time-series of annual values is presented for the selected TSL in chapter 14 of the final rule TSD.
DOE is well aware that scientific and economic knowledge about the contribution of CO 2 and other GHG emissions to changes in the future global climate and the potential resulting damages to the global and U.S. economy continues to evolve rapidly. DOE, together with other Federal agencies, will continue to review methodologies for estimating the monetary value of reductions in CO 2 and other GHG emissions. This ongoing review will consider the comments on this subject that are part of the public record for this and other rulemakings, as well as other methodological assumptions and issues. DOE notes, however, that the adopted standards would be economically justified even without inclusion of monetized benefits of reduced GHG emissions.
DOE also estimated the monetary value of the economic benefits associated with NO X and SO 2 emissions reductions anticipated to result from the considered TSLs for distribution transformers. The dollar-per-ton values that DOE used are discussed in section IV.L of this document. Table V.52 presents the present value for NO X emissions reduction for each TSL calculated using 7-percent and 3-percent discount rates, and Table V.53 presents similar results for SO 2 emissions reductions. The results in these tables reflect application of EPA's low dollar-per-ton values, which DOE used to be conservative. The time-series of annual values is presented for the selected TSL in chapter 14 of the final rule TSD.
Not all the public health and environmental benefits from the reduction of greenhouse gases, NO X , and SO 2 are captured in the values above, and additional unquantified benefits from the reductions of those pollutants as well as from the reduction of direct PM and other co-pollutants may be significant. DOE has not included monetary benefits of the reduction of Hg emissions because the amount of reduction is very small.

7. Other Factors
The Secretary of Energy, in determining whether a standard is economically justified, may consider any other factors that the Secretary deems to be relevant. (42 U.S.C. 6295(o)(2)(B)(i)(VII)) In this final rule, DOE considered the near-term impact of amended standards on existing distribution transformer shortages, on the domestic electrical steel supply, and on projected changes to the transformer market to support electrification.

8. Summary of Economic Impacts
Table V.54 presents the NPV values that result from adding the estimates of the economic benefits resulting from reduced GHG and NO X and SO 2 emissions to the NPV of consumer benefits calculated for each TSL considered in this rulemaking. The consumer benefits are domestic U.S. monetary savings that occur as a result of purchasing the covered equipment and are measured for the lifetime of products shipped during the period 2029-2058. The climate benefits associated with reduced GHG emissions resulting from the adopted standards are global benefits and are also calculated based on the lifetime of distribution transformers shipped during the period 2029-2058.

C. Conclusion
When considering new or amended energy conservation standards, the standards that DOE adopts for any type (or class) of covered equipment must be designed to achieve the maximum improvement in energy efficiency that the Secretary determines is technologically feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)) In determining whether a standard is economically justified, the Secretary must determine whether the benefits of the standard exceed its burdens by, to the greatest extent practicable, considering the seven statutory factors discussed previously. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(B)(i)) The new or amended standard must also result in significant conservation of energy. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3)(B))
For this final rule, DOE considered the impacts of amended standards for distribution transformers at each TSL, beginning with the maximum technologically feasible level, to determine whether that level was economically justified. Where the max-tech level was not justified, DOE then considered the next most efficient level and undertook the same evaluation until it reached the highest efficiency level that is both technologically feasible and economically justified and saves a significant amount of energy.
To aid the reader as DOE discusses the benefits and/or burdens of each TSL, tables in this section present a summary of the results of DOE's quantitative analysis for each TSL. In addition to the quantitative results presented in the tables, DOE also considers other burdens and benefits that affect economic justification. These include the impacts on identifiable subgroups of consumers who may be disproportionately affected by a national standard and impacts on employment.
DOE also notes that the economics literature provides a wide-ranging discussion of how consumers trade off upfront costs and energy savings in the absence of government intervention. Much of this literature attempts to explain why consumers appear to undervalue energy efficiency improvements. There is evidence that consumers undervalue future energy savings as a result of: (1) a lack of information; (2) a lack of sufficient salience of the long-term or aggregate benefits; (3) a lack of sufficient savings to warrant delaying or altering purchases; (4) excessive focus on the short term, in the form of inconsistent weighting of future energy cost savings relative to available returns on other investments; (5) computational or other difficulties associated with the evaluation of relevant tradeoffs; and (6) a divergence in incentives (for example, between renters and owners, or builders and purchasers). Having less than perfect foresight and a high degree of uncertainty about the future, consumers may trade off these varieties of investments at a higher-than-expected rate between current consumption and uncertain future energy cost savings.

1. Benefits and Burdens of TSLs Considered for Liquid-Immersed Distribution Transformer Standards
Table V.55 and Table V.56 summarize the quantitative impacts estimated for each TSL for liquid-immersed distribution transformers. The national impacts are measured over the lifetime of distribution transformers purchased in the 30-year period that begins in the anticipated year of compliance with amended standards (2029-2058). The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. DOE is presenting monetized benefits of GHG emissions reductions in accordance with the applicable Executive Orders, and DOE would reach the same conclusion presented in this notice in the absence of the social cost of greenhouse gases, including the Interim Estimates presented by the Interagency Working Group. The efficiency levels contained in each TSL are described in section V.A of this document.
DOE first considered TSL 5, which represents the max-tech efficiency levels across all product classes of liquid-immersed distribution transformers essentially requiring the shift to the most-efficient electrical steel for core fabrication and larger and heavier distribution transformers as more material is needed to support the efficiency gains. TSL 5 would save an estimated 10.91 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer benefit would be −$7.39 billion using a discount rate of 7 percent, and −$3.57 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 204.96 Mt of CO 2 , 49.0 thousand tons of SO 2 , 358.5 thousand tons of NO X , 0.3 tons of Hg, 1,660.6 thousand tons of CH 4 , and 1.6 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 5 is $7.37 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 5 is $4.42 billion using a 7-percent discount rate and $14.81 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 5 is $4.40 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 5 is $18.61 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a standard level is economically justified.
At TSL 5, the average LCC impact ranges from -$2,977 for equipment class 2B to $770 for equipment class 12. The median PBP ranges from 14.8 years for equipment class 12 to 42.1 years for equipment class 1A. The fraction of consumers experiencing a net LCC cost ranges from 28.7 percent for equipment class 2A to 89.0 percent for equipment class 1A.
At TSL 5, the projected change in INPV ranges from a decrease of $686 million to a decrease of $338 million, which corresponds to decreases of 38.3 percent and 18.8 percent, respectively. This decrease is primarily driven by the investments needed to move the entire liquid-immersed distribution transformer market to the most-efficient designs, including converting their production facilities to produce and accommodate amorphous core technology. DOE estimates that industry must invest $697 million to comply with standards set at TSL 5.
The Secretary concludes that at TSL 5 for liquid-immersed distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers as indicated by lengthy PBPs, the percentage of customers who would experience LCC increases, negative consumer NPV at both 3- and 7-percent discount rates, and the capital and engineering costs that would result in a reduction in INPV for manufacturers. At TSL 5, the LCC savings are negative for most liquid-immersed distribution transformers, indicating there is a substantial risk that a disproportionate number of consumers will incur increased costs; these costs are also reflected in simple PBP estimates that approach average transformer lifetimes for some equipment. NPVs are calculated for equipment shipped over the period of 2029 through 2058 (see section IV.H.3 of this document). Distribution transformers are durable equipment with a maximum lifetime estimated at 60 years (see section IV.F.8), accruing operating cost savings through 2117. When considered over this time period, the discounted value of the incremental equipment costs outweighs the discounted value of the operating costs savings. Incremental equipment costs are incurred in the first year of equipment life, while operating cost savings occur throughout the equipment lifetime, with later years heavily discounted. Further, there is risk of greater reduction in INPV at max-tech if manufacturers maintain their operating profit in the presence of amended efficiency standards on account of having higher costs but similar profits. The benefits of max-tech efficiency levels for liquid-immersed distribution transformers do not outweigh the negative impacts to consumers and manufacturers. Consequently, the Secretary has concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4, a level at which DOE estimates a likely shift in the electrical steel used for distribution transformer cores for liquid-immersed distribution transformers. TSL 4 would save an estimated 10.67 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer benefit would be $2.82 billion using a discount rate of 7 percent, and $13.01 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 201.15 Mt of CO 2 , 48.0 thousand tons of SO 2 , 350.8 thousand tons of NO X , 0.3 tons of Hg, 1,624.0 thousand tons of CH 4 , and 1.5 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 4 is $7.23 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 4 is $4.33 billion using a 7-percent discount rate and $14.50 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 4 is $14.38 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 4 is $34.74 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a standard level is economically justified.
At TSL 4, the average LCC impact ranges from $317 for equipment class 1B to $5,301 for equipment class 2B. The median PBP ranges from 7.4 years for equipment class 1B to 10.7 years for equipment class 1A. The fraction of consumers experiencing a net LCC cost ranges from 7.1percent for equipment classes 1B and 2A to 27.5 percent for equipment class 1A.
At TSL 4, the projected change in INPV ranges from a decrease of $476 million to a decrease of $388 million, which corresponds to decreases of 26.6 percent and 21.6 percent, respectively. These estimates are driven by DOE's estimate that liquid-immersed distribution transformer manufacturers will need to invest $587 million to comply with standards set at TSL 4 to produce or accommodate amorphous core technology.
The energy savings under TSL 4 are primarily achievable by using amorphous cores and DOE believes manufacturers will likely choose this technology pathway in order to meet TSL 4 efficiency levels due to the relative cost of meeting these levels with amorphous and GOES cores. In the present market, distribution transformers are primarily designed using GOES cores and the production equipment used for GOES core distribution transformer manufacturing is not the same. While DOE understands that amorphous core distribution transformers are technically feasible for liquid-immersed, DOE also understands that current domestic supply would need to ramp up significantly for amorphous steel to support this market.
The transition to amorphous cores is constrained in two important ways. First, amorphous cores require amorphous steel. Supply of amorphous steel for transformer cores is not inherently constrained. Supply, including domestic supply, could increase in the face of increased demand.
For example, both global and domestic annual production capacity of amorphous ribbon is greater now than it was leading up to the April 2013 Standards Final Rule, with global annual production capacity of amorphous ribbon (estimated to be approximately 150,000-250,000 metric tons) approximately equal to the U.S. annual demand for core steel in distribution transformer applications (estimated to be approximately 225,000 metric tons). While additional amorphous ribbon capacity would be required to serve the entirety of the U.S. distribution transformer market, in addition to existing global applications, it is likely that supply would increase quickly in response to increased demand from standards. Following the April 2013 Standards Final Rule, amorphous ribbon capacity grew, although amorphous ribbon demand did not grow in-kind. As such, excess amorphous ribbon capacity already exists that could be utilized to serve a larger portion of the distribution transformer market, if demand were to increase. Further, the response of amorphous ribbon manufacturers following the April 2013 Standards Final Rule, as well as public announcements of development in amorphous core production capacity since the January 2023 NOPR, demonstrate that amorphous ribbon and core capacity can be added quickly if suppliers anticipate demand. As such, the supply of amorphous metal would likely increase in response to amended standards that favored amorphous ribbon as the optimal design option. Stakeholders have expressed a willingness to increase supply to match any potential demand created by an amended efficiency standard. As noted, in the current market, sales of amorphous ribbon are limited by demand for amorphous cores rather than any constraints on production capacity. Therefore, in the presence of an amended standard, it is expected that amorphous ribbon capacity would quickly rise to meet demand before the effective date of any amended energy conservation standards.
However, and secondly, demand for amorphous steel is constrained by distribution transformer manufacturers' willingness and ability to invest in in the capital equipment required to produce and process amorphous metal cores. The production pathway for both amorphous core and GOES core transformers is similar once this investment in the equipment has been made. However, the transition from production of GOES cores to production of amorphous cores would require significant investment by distribution transformer manufacturers that produce their own cores. At TSL 4, most existing core production equipment, which is predominantly set up to produce GOES cores, would need to be replaced with amorphous core production equipment. Given existing supply challenges and long lead times for distribution transformers, it is unclear if most manufacturers would have the capacity to complete the necessary investments in amorphous core production equipment within the 5-year compliance period and maintain their existing GOES production lines to supply the current market demand without increasing near-term distribution transformer lead times. If manufacturers anticipate requiring more than 5 years to fully convert production or add production of amorphous cores, they may prioritize maintaining lead times by continuing to produce transformers with GOES cores. If GOES cores are used to meet TSL 4, the resulting designs are substantially larger and more expensive than amorphous core designs, with some size capacities in DOE's modelling unable to meet TSL 4 at all with GOES. Conversely, if manufacturers prioritize a transition to amorphous cores over maintaining lead times, they may prioritize investing in replacing existing production equipment, rather than in new additive capacity. This could inhibit manufacturers' abilities to invest in necessary capacity upgrades to help resolve the existing transformer shortages.
In addition to the production equipment and investments needed to support a TSL 4 transition by distribution transformers, DOE understands that the current workforce supporting the distribution transformer manufacturer is also limited in their experience with amorphous core production. DOE understands from the many stakeholder comments that current workforce challenges within the distribution transformer industry may be exacerbated in the short-term if a full transition to TSL 4 is required. While DOE understands most manufacturers currently can produce liquid-immersed transformers at TSL 4 efficiencies, DOE also understand that due to the lower volume of amorphous cores in the market today many production facilities outsource amorphous core production but produce GOES cores in-house. DOE believes that if TSL 4 efficiencies were required for liquid-immersed distribution transformers the sourcing decisions on core fabrication would not largely change from what they are today as these are inherent business decisions that balance quality, control, and lead-times. Therefore, despite offering liquid-immersed transformers at TSL 4 efficiencies, manufacturers do not yet have a lot of experience fabricating amorphous cores and will take significant training and time in order to support a transition of this magnitude. Some manufacturers raised questions in comments about their ability to invest in both the capital as well as the workforce in the time provided to transition to TSL 4, while maintaining their supply needs for GOES transformers in the near-term.
DOE notes that while the January 2023 NOPR proposed standards at TSL 4, distribution transformer shortages persisted throughout 2023. DOE further notes that hundreds of millions of dollars in investments have been announced by distribution transformer manufacturers to add capacity to resolve the existing transformer shortages and those investments are currently undergoing the design, permitting, engineering, and construction process needed to begin production with scheduled completions typically targeting 24 to 36 months. DOE updated its analysis of conversion costs in this final rule based on stakeholder feedback and are the costs are now greater than the costs analyzed in the January 2023 NOPR. Investing in conversion costs and workforce training, in addition to manufacturers investments to increase capacity, without offering flexibility for manufacturers to add amorphous capacity in an additive manner has led DOE to conclude that TSL 4 offers substantial risk that could extend current transformer shortages longer they otherwise would be.
The Secretary concludes that at TSL 4 for liquid-immersed distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the significant impact to manufacturers (a loss in INPV of up to 26.6 percent, conversion costs of approximately $587 million, and a free cash flow of −$125 million in the year leading up to the compliance year) and the risks that manufacturers would not be able to scale up amorphous core production capacity within the compliance period without significantly increasing distribution transformer lead times or maintaining very large and costly GOES core transformers after the compliance period. In addition, DOE has concerns about distribution transformer manufacturer's ability to maintain their existing GOES lines in the near-term, while training their workforce to become comfortable with producing transformers cores with amorphous ribbon. Further, as discussed in section IV.C.2.a, an inability of suppliers of amorphous ribbon to scale production and manufacturers to retool production lines for amorphous cores within the compliance period could lead to market uncertainty and disruption during a critical time. Several stakeholders have noted that given existing supply challenges, a total conversion to amorphous is not feasible in the near term. While this final rule considers a longer compliance period, the impacts of shortages are substantial, which may have an impact on grid reliability. Therefore, the risks of scale-up and compliance taking slightly longer, due to any number of unforeseen challenges, could have substantial impacts. The benefits of TSL 4 for liquid-immersed distribution transformer do not outweigh the risks when considering the potential impacts to the broader distribution transformer supply chain. Consequently, the Secretary has concluded that TSL 4 is not economically justified.
Next, DOE considered TSL 3. TSL 3 would save an estimated 2.73 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer benefit would be $0.56 billion using a discount rate of 7 percent, and $3.41 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 51.40 Mt of CO 2 , 12.3 thousand tons of SO 2 , 89.9 thousand tons of NO X , 0.1 tons of Hg, 416.2 thousand tons of CH 4 , and 0.4 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 3 is $1.85 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 3 is $1.11 billion using a 7-percent discount rate and $3.71 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 3 is $3.52 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 3 is $9.97 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a standard level is economically justified.
At TSL 3, the average LCC impact ranges from $48 for equipment class 1B to $851 for equipment class 2A. The median PBP ranges from 9.2 years for equipment class 2A to 19.5 years for equipment class 1B. The fraction of consumers experiencing a net LCC cost ranges from 7.1 percent for equipment class 2A to 39.6 percent for equipment class 2B.
At TSL 3, the projected change in INPV ranges from a decrease of $145 million to a decrease of $111 million, which corresponds to decreases of 8.1 percent and 6.2 percent, respectively. DOE estimates that industry must invest $187 million to comply with standards set at TSL 3.
After considering the analysis and weighing the benefits and burdens, the Secretary has concluded that a standard set at TSL 3 for liquid-immersed distribution transformers would be economically justified. Notably, the benefits to consumers outweigh the cost to manufacturers. At TSL 3, the average LCC savings are positive across all equipment classes. An estimated 29 percent of liquid-immersed distribution transformer consumers experience a net cost. DOE notes that if the shipments equipment classes 1B and 2B transition to amorphous cores from DOE's assumed rate of 3 percent to 10, or 25 percent, the maximum number of consumers experiencing a net cost decreases to 25 and 21 percent, respectively. ^{198} The FFC national energy savings are significant and the NPV of consumer benefits is positive using both a 3-percent and 7-percent discount rate when considered for all liquid-immersed distribution transformers subject to amended standards. When examined as individual equipment classes the NPV at 7 percent is positive for most equipment classes; with the exception of equipment class 2B, where the NPV at a 7 percent discount rate is negative: −$0.05 billion (see Table V.43). When equipment class 2B is considered with the addition of its associated health benefits of $0.22 billion at TSL 3 (see Table V.51 and Table V.52) the impacts become positive, with a net benefit of $0.17 billion. At TSL 3, the NPV of consumer benefits, even measured at the more conservative discount rate of 7 percent is larger than the maximum estimated manufacturers' loss in INPV. The standard levels at TSL 3 are economically justified even without weighing the estimated monetary value of emissions reductions. When those emissions reductions are included—representing $1.85 billion in climate benefits (associated with the average SC-GHG at a 3-percent discount rate), and $3.71 billion (using a 3-percent discount rate) or $1.11 billion (using a 7-percent discount rate) in health benefits—the rationale becomes stronger still.
^{198} See: Appendix 8D of the final rule TSD for DOE's scenario examining the impacts resulting from increased amorphous adoption.
Notably, the standards under TSL 3 would not pose the same near-term risks to distribution transformer availability. As compared to TSL 4, for which the energy savings are primarily achievable via amorphous cores, the energy savings under TSL 3 are achieved by using a mix of amorphous cores and GOES cores. Under TSL 3, DOE estimates that equipment class 1A and 2A will meet efficiency standards by transitioning to amorphous cores. If the unit sizes represented by these equipment classes shift entirely to amorphous, DOE estimates that approximately 48,000 metric tons of amorphous ribbon would be consumed, which is approximately equal to the current domestic amorphous ribbon production capacity (45,000 metric tons of domestic amorphous today). Under TSL 3, DOE estimates that the vast majority of liquid-immersed distribution transformers shipments (89 percent of units) could be met with GOES cores.
As noted, the transition from GOES cores to amorphous cores requires significant investment on the part of distribution transformer manufacturers that produce their own cores. However, core production equipment is somewhat flexible in that a given piece of equipment can produce a range of core sizes corresponding to a range of transformer kVA sizes. Given existing supply challenges facing the distribution transformer market, DOE assumes that manufacturers would prioritize maintaining lead times by continuing to produce transformers with GOES cores for transformer sizes where costs are approximately equal, even if a transformer with an amorphous core may be slightly less expensive to produce. Under TSL 3, DOE evaluated a higher efficiency level for Equipment Class 1A and 2A and a lower efficiency level for Equipment Class 1B and 2B. As such, manufacturers would have significant flexibility to invest in new capacity to meet efficiency standards while allowing for the continued use of current production equipment to ensure a robust short- to medium-term supply of distribution transformers.
TSL 3 results in positive LCCs for all equipment classes, whether expected to remain predominantly GOES-based (Equipment Class 1B and 2B) or predominantly amorphous-based (Equipment Class 1A and 2A).
Because only a portion of the market is expected to transition to amorphous at TSL 3 and because existing GOES production equipment can produce a variety of kVA sizes, manufacturers may invest in amorphous production equipment as additive capacity to serve those portions of the market where amorphous is most competitive. As such, manufacturers would have the flexibility of using existing GOES production equipment to serve the rest of the market, while adding additional amorphous production equipment that may help resolve the existing transformer shortages. Public statements from major liquid-immersed distribution transformer core manufacturers suggest that some have already begun investing in additive amorphous capacity in response to the January 2023 NOPR. 199 200 201
^{199} Yahoo Finance, Howard Industries cuts ribbon on Quitman plant, November 3, 2023, Available online at: https://finance.yahoo.com/news/howard-industries-cuts-ribbon-quitman-035900515.html .
^{200} JFE Shoji Power, “What Got Us Here Won't Get Us to Where We Want to Go”, You Will Be an Embarrassment to the Company, Nov. 2023. https://www.amazon.in/What-Here-Wont-Where-Want/dp/B0CMD84HRW .
^{201} Worthington Steel, Investor Day, Oct. 2023, Transcript. Available online at: worthington-steel-investor-day-transcript-final-10-11-23.pdf ( worthingtonenterprises.com .)
Amorphous cores are expected to be the most cost-effective option for meeting efficiency levels for equipment class 1A and 2A. This suggests a future demand for amorphous ribbon and encourages both existing amorphous producers to increase supply and potential new producers to enter the market.
DOE expects manufacturers would prioritize amorphous core capital investments at the kVA ranges ( i.e., equipment class 1A and 2A), where amorphous cores are expected to be most cost competitive. However, if excess amorphous ribbon and amorphous core capacity exists, amorphous is also a cost-effective option for many of the other kVA ratings. While DOE has modeled equipment class 1B and 2B as meeting amended standards using exclusively GOES in its base analysis at TSL 3, DOE has included additional sensitivities in which amorphous core usage increases to a maximum of 25 percent at equipment class 1B and 2B. These scenarios further increase consumer benefits (see appendix 8G of the TSD).
DOE expects manufacturers would maintain some amount of GOES core production equipment and some amount of amorphous core production equipment, thereby ensuring the U.S. distribution transformer market continues to be served by at least two domestic electrical steel providers, one producing GOES and one producing amorphous. This may support balanced supply chain for distribution transformers through a more diversified core steel supply, which is presently served predominantly by GOES production for which there is only one domestic supplier.
As stated, DOE conducts the walk-down analysis to determine the TSL that represents the maximum improvement in energy efficiency that is technologically feasible and economically justified as required under EPCA. The walk-down is not a comparative analysis, as a comparative analysis would result in the maximization of net benefits instead of energy savings that are technologically feasible and economically justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE has not conducted a comparative analysis to select the new energy conservation standards, DOE notes that TSL 3 ensures capacity for amorphous ribbon increases, on account of anticipated future demand, while leaving a considerable portion of the market at efficiency levels wherein GOES would remain cost competitive. As a result, this ensures that near-term shortages can be resolved and that overall U.S. electrification trends and support for domestic electrical steel industries are not compromised. As noted by numerous stakeholders, distribution transformers are crucial to supporting U.S. infrastructure, grid resiliency, and electrification goals. TSL 3 allows for efficiency standards to be met by additive capacity, which can help renormalize distribution transformer lead times. TSL 4 and TSL 5 did not include the same possibility for stakeholders to invest in an additive capacity to meet efficiency standards, thereby creating risks to the short- and medium-term supply of distribution transformers.
Although DOE considered amended standard levels for distribution transformers by grouping the efficiency levels for each equipment category into TSLs, DOE evaluates all analyzed efficiency levels in its analysis. The TSLs constructed by DOE to examine the impacts of amended energy efficiency standards for liquid-immersed distribution transformers align with the corresponding ELs defined in the engineering analysis, which the exception of TSL 3 which seeks to consider electrical steel capacity and demand growth limitations. For the ELs above baseline that compose TSL 3, DOE finds that LCC savings are positive for all equipment classes, with simple paybacks well below the average equipment lifetimes. DOE also finds that the estimated fraction of consumers who would be negatively impacted from a standard at TSL 3 to be 29.2 percent for all equipment classes. Importantly, DOE expects TSL 3 to be achievable with additive distribution transformer capacity in addition to capital conversion costs, thereby reducing both transformer and larger grid supply concerns.
Therefore, based on the previous considerations, DOE adopts the energy conservation standards for liquid-immersed distribution transformers at TSL 3. The amended energy conservation standards for distribution transformers, which are expressed as percentage efficiency at 50 percent PUL, are shown in Table V.57.

2. Benefits and Burdens of TSLs Considered for Low-Voltage Dry-Type Distribution Transformer Standards
Table V.58 and Table V.59 summarize the quantitative impacts estimated for each TSL for low-voltage dry-type distribution transformers. The national impacts are measured over the lifetime of distribution transformers purchased in the 30-year period that begins in the anticipated year of compliance with amended standards (2029-2058). The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. DOE is presenting monetized benefits of GHG emissions reductions in accordance with the applicable Executive Orders, and DOE would reach the same conclusion presented in this notice in the absence of the social cost of greenhouse gases, including the Interim Estimates presented by the Interagency Working Group. The efficiency levels contained in each TSL are described in section V.A of this document.
DOE first considered TSL 5, which represents the max-tech efficiency levels. TSL 5 would save an estimated 2.53 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer benefit would be $3.00 billion using a discount rate of 7 percent, and $9.86 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 46.20 Mt of CO 2 , 11.1 thousand tons of SO 2 , 82.7 thousand tons of NO X , 0.1 tons of Hg, 384.4 thousand tons of CH 4 , and 0.4 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 5 is $1.81 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 5 is $1.12 billion using a 7-percent discount rate and $3.58 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 5 is $5.93 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 5 is $15.25 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a proposed standard level is economically justified.
At TSL 5, the average LCC impact ranges from $517 for equipment class 3 to $1,044 for equipment class 4. The median PBP ranges from 4.8 years for equipment class 4 to 8.9 years for equipment class 3. The fraction of consumers experiencing a net LCC cost ranges from 3 percent for equipment class 4 to 18 percent for equipment class 3.
At TSL 5, the projected change in INPV ranges from a decrease of $68.4 million to a decrease of $54.0 million, which corresponds to decreases of 32.3 percent and 25.5 percent, respectively. DOE estimates that industry must invest $91.8 million to comply with standards set at TSL 5.
The energy savings under TSL 5 are primarily achievable by using amorphous cores. The transition from GOES cores to amorphous cores requires significant investment on the part of the distribution transformer manufacturer if they produce their own cores. At TSL 5, most existing core production equipment would need to be replaced with amorphous core production equipment. Most LVDT manufacturers have little or no experience producing transformer designs with amorphous cores and little experience as to potential modifications that may need to be made to new protective equipment. Further, LVDT manufacturers tend to have considerably lower transformer core volumes than liquid-immersed manufacturers. As such, electrical steel manufacturers tend to prioritize service to liquid-immersed manufacturers over dry-type distribution transformer manufacturers. This creates a risk that, given the quantity of amorphous ribbon expected to be used within the liquid-immersed distribution transformer market, there may be considerable competition for amorphous ribbon that may hamper LVDT manufacturers' ability to develop experience with amorphous cores in the near-term, which would lead to considerable supply chain disruptions in the compliance year.
DOE notes that while the January 2023 NOPR proposed standards at TSL 5, distribution transformer shortages have persisted throughout 2023. DOE further notes that hundreds of millions of dollars in investments have been announced by distribution transformer manufacturers to add capacity to resolve the existing transformer shortages and those investments are currently undergoing the design, permitting, engineering, and construction process needed to begin production with scheduled completions typically targeting 24 to 36 months. DOE updated its analysis of conversion costs in this final rule based on stakeholder feedback and are the costs are now greater than the costs analyzed in the January 2023 NOPR. Investing in conversion costs, in addition to manufacturers investments to increase capacity, without offering flexibility for manufacturers to add amorphous capacity in an additive manner has led DOE to conclude that TSL 5 offers substantial risk that could extend current transformer shortages longer they otherwise would be.
The Secretary concludes that at TSL 5 for low-voltage dry-type distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the risks that manufacturers would not be able to scale up amorphous core production within the compliance period without significantly increasing distribution transformer lead times. The benefits of TSL 5 for low-voltage dry-type distribution transformers do not outweigh the risks of significant impacts to the distribution transformer supply chain, particularly when considered in conjunction with the expected demand for core materials in the liquid-immersed distribution transformer market. Consequently, the Secretary has concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4. TSL 4 would save an estimated 2.38 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer benefit would be $3.20 billion using a discount rate of 7 percent, and $10.14 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 43.56 Mt of CO 2 , 10.4 thousand tons of SO 2 , 77.9 thousand tons of NO X , 0.1 tons of Hg, 362.3 thousand tons of CH 4 , and 0.3 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 4 is $1.71 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 4 is $1.06 billion using a 7-percent discount rate and $3.38 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 4 is $5.97 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 4 is $15.23 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a proposed standard level is economically justified.
At TSL 4, the average LCC impact ranges from $551 for equipment class 3 to $1,068 for equipment class 4. The median PBP ranges from 3.4 years for equipment class 4 to 7.4 years for equipment class 3. The fraction of consumers experiencing a net LCC cost ranges from 2 percent for equipment class 4 to 14 percent for equipment class 3.
At TSL 4, the projected change in INPV ranges from a decrease of $62.9 million to a decrease of $52.2 million, which corresponds to decreases of 29.7 percent and 24.7 percent, respectively. DOE estimates that industry must invest $86.7 million to comply with standards set at TSL 4.
The energy savings under TSL 4 are primarily achievable by using amorphous cores. As noted, LVDT manufacturers have little or no experience producing transformer designs with amorphous cores and little experience as to potential modifications that may need to be made to new protective equipment. DOE is concerned that given the large quantity of amorphous ribbon expected to be used within the liquid-immersed distribution transformer market, there may be considerable competition for amorphous ribbon that may hamper LVDT manufacturers' ability to develop experience with amorphous cores in the near-term, which would lead to considerable supply chain disruptions in the compliance year.
The Secretary concludes that at TSL 4 for low-voltage dry-type distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the risks that manufacturers would not be able to scale up amorphous core production within the compliance period without significantly increasing distribution transformer lead times. Further, as discussed in section IV.C.2.a of this document, an inability of suppliers of amorphous ribbon to scale production and manufacturers to retool production lines for amorphous cores within the compliance period could lead to market uncertainty and disruption during a critical time. Several stakeholders have noted that given existing supply challenges, a total conversion to amorphous is not feasible in the near term. While this final rule considers a longer compliance period, the impacts of shortages are substantial, which may have an impact on grid reliability. Therefore, the risks of scale-up and compliance taking slightly longer, due to any number of unforeseen challenges, could have substantial impacts. The benefits of TSL 4 for low-voltage dry-type distribution transformer do not outweigh the risks of significant impacts to the distribution transformer supply chain, particularly when considered in conjunction with the expected demand for core materials in the liquid-immersed distribution transformer market. Consequently, the Secretary has concluded that TSL 4 is not economically justified.
Next, DOE considered TSL 3. TSL 3 would save an estimated 1.71 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer benefit would be $2.08 billion using a discount rate of 7 percent, and $6.68 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 31.28 Mt of CO 2 , 7.5 thousand tons of SO 2 , 55.9 thousand tons of NO X , 0.1 tons of Hg, 260.0 thousand tons of CH 4 , and 0.2 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 3 is $1.23 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 3 is $0.76 billion using a 7-percent discount rate and $2.42 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 3 is $4.07 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 3 is $10.33 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a standard level is economically justified.
At TSL 3, the average LCC impact ranges from $321 for equipment class 3 to $765 for equipment class 4. The median PBP ranges from 3.6 years for equipment class 4 to 7.4 years for equipment class 3—well below the estimated average lifetime of 32 years. The fraction of consumers experiencing a net LCC cost ranges from 9 percent for equipment class 4 to 28 percent for equipment class 3.
At TSL 3, the projected change in INPV ranges from a decrease of $27.1 million to a decrease of $18.9 million, which corresponds to decreases of 12.8 percent and 8.9 percent, respectively. DOE estimates that industry must invest $36.1 million to comply with standards set at TSL 3.
After considering the analysis and weighing the benefits and burdens, the Secretary has concluded that a standard set at TSL 3 for low-voltage dry-type distribution transformers would be economically justified. Notably, the benefits to consumers outweigh the cost to manufacturers. At this TSL, the average LCC savings are positive across all equipment classes. An estimated 11 percent of low-voltage dry-type distribution transformer consumers experience a net cost. The FFC national energy savings are significant and the NPV of consumer benefits is positive using both a 3-percent and 7-percent discount rate. At TSL 3, the NPV of consumer benefits, even measured at the more conservative discount rate of 7 percent, is larger than the maximum estimated manufacturers' loss in INPV. The standard levels at TSL 3 are economically justified even without weighing the estimated monetary value of emissions reductions. When those emissions reductions are included—representing $1.23 billion in climate benefits (associated with the average SC-GHG at a 3-percent discount rate), and $2.42 billion (using a 3-percent discount rate) or $0.76 billion (using a 7-percent discount rate) in health benefits—the rationale becomes stronger still.
Notably, the energy savings under TSL 3 do not carry the same risks to distribution transformer supply chains as TSL 4 and TSL 5. The energy savings under TSL 3 are primarily achieved using lower-loss GOES cores with some shipments using amorphous cores where it is most cost-competitive. DOE notes that at TSL 3, both amorphous and GOES cores are cost-competitive with regard to which core steel produces the lowest first-cost unit, allowing manufacturers flexibility in establishing supply chains and redesigning transformers to meet amended standards based on their specific needs.
As stated, DOE conducts the walk-down analysis to determine the TSL that represents the maximum improvement in energy efficiency that is technologically feasible and economically justified as required under EPCA. The walk-down is not a comparative analysis, as a comparative analysis would result in the maximization of net benefits instead of energy savings that are technologically feasible and economically justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE has not conducted a comparative analysis to select the new energy conservation standards, DOE notes that TSL 3 has considerably lower manufacturer impacts than TSL 4 and TSL 5. Further, TSL 3 allows both GOES and amorphous cores to compete, ensuring a diverse supply of materials can serve the LVDT market.
Although DOE considered amended standard levels for distribution transformers by grouping the efficiency levels for each equipment category into TSLs, DOE evaluates all analyzed efficiency levels in its analysis. The TSLs constructed by DOE to examine the impacts of amended energy efficiency standards for low-voltage dry-type distribution transformers align with the corresponding ELs defined in the engineering analysis. For the ELs above baseline that compose TSL 3, DOE finds that LCC savings are positive for all equipment classes, with simple paybacks well below the average equipment lifetimes. DOE also finds that the estimated fraction of consumers who would be negatively impacted from a standard at TSL 3 to be 11 percent for all equipment classes. Importantly, DOE expects TSL 3 to be achievable with both amorphous and GOES core materials.
Therefore, based on the previous considerations, DOE adopts the energy conservation standards for LVDT distribution transformers at TSL 3. The amended energy conservation standards for distribution transformers, which are expressed as percentage efficiency at 35 percent PUL, are shown in Table V.60.

3. Benefits and Burdens of TSLs Considered for Medium-Voltage Dry-Type Distribution Transformer Standards
Table V.61 and Table V.62 summarize the quantitative impacts estimated for each TSL for medium-voltage dry-type distribution transformers. The national impacts are measured over the lifetime of distribution transformers purchased in the 30-year period that begins in the anticipated year of compliance with amended standards (2029-2058). The energy savings, emissions reductions, and value of emissions reductions refer to full-fuel-cycle results. DOE is presenting monetized benefits of GHG emissions reductions in accordance with the applicable Executive Orders, and DOE would reach the same conclusion presented in this notice in the absence of the social cost of greenhouse gases, including the Interim Estimates presented by the Interagency Working Group. The efficiency levels contained in each TSL are described in section V.A of this document.
DOE first considered TSL 5. TSL 5 would save an estimated 0.65 quads of energy, an amount DOE considers significant. Under TSL 5, the NPV of consumer benefit would be $-0.08 billion using a discount rate of 7 percent, and $0.72 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 5 are 11.72 Mt of CO 2 , 2.8 thousand tons of SO 2 , 21.2 thousand tons of NO X , 0.02 tons of Hg, 98.6 thousand tons of CH 4 , and 0.1 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 5 is $0.46 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 5 is $0.29 billion using a 7-percent discount rate and $0.92 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 5 is $0.67 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 5 is $2.10 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a standard level is economically justified.
At TSL 5, the average LCC impact ranges from $-6,239 for equipment class 10 to $136 for equipment class 6. The median PBP ranges from 5.0 years for equipment class 6 to 10.5 years for equipment class 10. The fraction of consumers experiencing a net LCC cost ranges from 47 percent for equipment class 6 to 85 percent for equipment class 10.
At TSL 5, the projected change in INPV ranges from a decrease of $33.2 million to a decrease of $16.3 million, which corresponds to decreases of 34.9 percent and 17.1 percent, respectively. DOE estimates that industry must invest $36.2 million to comply with standards set at TSL 5.
The Secretary concludes that at TSL 5 for medium-voltage dry-type distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers as indicated by the negative LCCs for many equipment classes, the percentage of customers who would experience LCC increases, and the capital and engineering costs that could result in a reduction in INPV for manufacturers. At TSL 5 DOE is estimating negative benefits for a disproportionate fraction of consumers—a shipment weighted average of 68 percent. Further DOE estimates that there is a substantial risk to consumers, with a shipment weighted LCC savings for all MVDT equipment of -$3,178. Consequently, the Secretary has concluded that TSL 5 is not economically justified.
Next, DOE considered TSL 4. TSL 4 would save an estimated 0.55 quads of energy, an amount DOE considers significant. Under TSL 4, the NPV of consumer benefit would be $0.18 billion using a discount rate of 7 percent, and $1.14 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 4 are 9.85 Mt of CO 2 , 2.4 thousand tons of SO 2 , 17.8 thousand tons of NO X , 0.02 tons of Hg, 82.9 thousand tons of CH 4 , and 0.1 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 4 is $0.39 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 4 is $0.24 billion using a 7-percent discount rate and $0.77 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 4 is $0.81 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 4 is $2.30 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a proposed standard level is economically justified.
At TSL 4, the average LCC impact ranges from $-2,569 for equipment class 10 to $2,882 for equipment class 8. The median PBP ranges from 4.2 years for equipment class 8 to 9.2 years for equipment class 10. The fraction of consumers experiencing a net LCC cost ranges from 29 percent for equipment class 8 to 67 percent for equipment class 10.
At TSL 4, the projected change in INPV ranges from a decrease of $29.5 million to a decrease of $18.6 million, which corresponds to decreases of 31.0 percent and 19.5 percent, respectively. DOE estimates that industry must invest $34.8 million to comply with standards set at TSL 4.
The Secretary concludes that at TSL 4 for medium-voltage dry-type distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers as indicated by the negative LCCs for many equipment classes, the percentage of customers who would experience LCC increases, and the capital and engineering costs that could result in a reduction in INPV for manufacturers. At TSL 4 DOE is estimating negative benefits for a disproportionate fraction of consumers—a shipment weighted average of 45 percent. Consequently, the Secretary has concluded that TSL 4 is not economically justified.
Next, DOE considered TSL 3. TSL 3 would save an estimated 0.42 quads of energy, an amount DOE considers significant. Under TSL 3, the NPV of consumer benefit would be $0.25 billion using a discount rate of 7 percent, and $1.15 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 3 are 7.55 Mt of CO 2 , 1.8 thousand tons of SO 2 , 13.6 thousand tons of NO X , 0.01 tons of Hg, 63.5 thousand tons of CH 4 , and 0.1 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 3 is $0.30 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 3 is $0.19 billion using a 7-percent discount rate and $0.59 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 3 is $0.73 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 3 is $2.04 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a proposed standard level is economically justified. At TSL 3, the average LCC impact ranges from $-2,788 for equipment class 10 to $3,418 for equipment class 8. The median PBP ranges from 3.5 years for equipment class 6 to 10.0 years for equipment class 10. The fraction of consumers experiencing a net LCC cost ranges from 29 percent for equipment class 8 to 63 percent for equipment class 10.
At TSL 3, the projected change in INPV ranges from a decrease of $26.4 million to a decrease of $19.1 million, which corresponds to decreases of 27.8 percent and 20.1 percent, respectively. DOE estimates that industry must invest $32.7 million to comply with standards set at TSL 3.
The Secretary concludes that at TSL 3 for medium-voltage dry-type distribution transformers, the benefits of energy savings, emission reductions, and the estimated monetary value of the emissions reductions would be outweighed by the economic burden on many consumers as indicated by the negative LCCs for many equipment classes, the percentage of customers who would experience LCC increases, and the capital and engineering costs that could result in a reduction in INPV for manufacturers. At TSL 3, DOE estimates negative benefits for a disproportionate fraction of consumers—a shipment weighted average of 41 percent. Consequently, the Secretary has concluded that TSL 3 is not economically justified.
Next, DOE considered TSL 2. TSL 2 would save an estimated 0.14 quads of energy, an amount DOE considers significant. Under TSL 2, the NPV of consumer benefit would be $0.03 billion using a discount rate of 7 percent, and $0.22 billion using a discount rate of 3 percent.
The cumulative emissions reductions at TSL 2 are 2.59 Mt of CO 2 , 0.6 thousand tons of SO 2 , 4.7 thousand tons of NO X , 0.0 tons of Hg, 21.9 thousand tons of CH 4 , and 0.0 thousand tons of N 2 O. The estimated monetary value of the climate benefits from reduced GHG emissions (associated with the average SC-GHG at a 3-percent discount rate) at TSL 2 is $0.10 billion. The estimated monetary value of the health benefits from reduced SO 2 and NO X emissions at TSL 2 is $0.06 billion using a 7-percent discount rate and $0.20 billion using a 3-percent discount rate.
Using a 7-percent discount rate for consumer benefits and costs, health benefits from reduced SO 2 and NO X emissions, and the 3-percent discount rate case for climate benefits from reduced GHG emissions, the estimated total NPV at TSL 2 is $0.20 billion. Using a 3-percent discount rate for all benefits and costs, the estimated total NPV at TSL 2 is $0.52 billion. The estimated total NPV is provided for additional information, however DOE primarily relies upon the NPV of consumer benefits when determining whether a proposed standard level is economically justified.
At TSL 2, the average LCC impact ranges from $−1,438 for equipment class 10 to $3,794 for equipment class 8. The median PBP ranges from 0.5 years for equipment class 8 to 10.1 years for equipment class 10. The fraction of consumers experiencing a net LCC cost ranges from 10 percent for equipment class 6 to 77 percent for equipment class 10.
At TSL 2, the projected change in INPV ranges from a decrease of $4.4 million to a decrease of $2.3 million, which corresponds to decreases of 4.7 percent and 2.5 percent, respectively. DOE estimates that industry must invest $5.7 million to comply with standards set at TSL 2.
After considering the analysis and weighing the benefits and burdens, the Secretary has concluded that at a standard set at TSL 2 for medium-voltage distribution transformers would be economically justified. At this TSL, the average LCC savings are positive across all equipment classes except for equipment class 10, with a shipment weighed average LCC for all medium-voltage dry-type distribution transformers of $1,738. An estimated 10 percent of equipment class 6 to 77 percent of equipment class 10 medium-voltage dry-type distribution transformer consumers experience a net cost, while the shipment weighted average of consumers who experience a net cost is 33 percent. The FFC national energy savings are significant and the NPV of consumer benefits is positive using both a 3-percent and 7-percent discount rate. Notably, the benefits to consumers outweigh the cost to manufacturers. At TSL 2, the NPV of consumer benefits, even measured at the more conservative discount rate of 7 percent is over 6 times higher than the maximum estimated manufacturers' loss in INPV. The standard levels at TSL 2 are economically justified even without weighing the estimated monetary value of emissions reductions. When those emissions reductions are included—representing $0.10 billion in climate benefits (associated with the average SC-GHG at a 3-percent discount rate), and $0.20 billion (using a 3-percent discount rate) or $0.06 billion (using a 7-percent discount rate) in health benefits—the rationale becomes stronger still.
As stated, DOE conducts the walk-down analysis to determine the TSL that represents the maximum improvement in energy efficiency that is technologically feasible and economically justified as required under EPCA. The walk-down is not a comparative analysis, as a comparative analysis would result in the maximization of net benefits instead of energy savings that are technologically feasible and economically justified, which would be contrary to the statute. 86 FR 70892, 70908.
Although DOE considered amended standard levels for distribution transformers by grouping the efficiency levels for each equipment category into TSLs, DOE evaluates all analyzed efficiency levels in its analysis. For medium-voltage dry-type distribution transformer the TSL 2 maps directly to EL 2 for all equipment classes. EL 2 represents a 10 percent reduction in losses over the current standard. While the consumer benefits for equipment class 10 are negative at EL 2 at -$1,438, they are positive for all other equipment representing 67 percent of all MVDT units shipped, additionally the consumer benefits at EL 2, excluding equipment class 10, increases from $1,738 to $2,217 in LCC savings Further, the EL 2 represent an improvement in efficiency where the FFC national energy savings is maximized, with positive NPVs at both 3 and 7 percent, and the shipment weighted average consumer benefit at EL 2 is positive. The shipment weighted consumer benefits for TSL, and EL 2 are shown in Table V.63.
As discussed previously, at the max-tech efficiency levels (TSL 5), TSL 4, and TSL 3 for all medium-voltage dry-type distribution transformers there is a substantial risk to consumers due to negative LCC savings for some equipment, with a shipment weighted average consumer benefit of -$3,178, $754, and $1,036, respectively, while at TSL 2 it is $1,738. Therefore, DOE has concluded that the efficiency levels above TSL 2 are not justified. Additionally, at the examined efficiency levels greater than TSL 2 DOE is estimating that a disproportionate fraction of consumers would be negatively impacted by these efficiency levels. DOE estimates that shipment weighted fraction of negatively impacted consumers for TSL 3, TSL 4, and TSL 5 (max-tech) to be 68, 45, and 41 percent, respectively.
Therefore, based on the previous considerations, DOE adopts the energy conservation standards for distribution transformers at TSL 2. The amended energy conservation standards for MVDT distribution transformers, which are expressed as percentage efficiency at 50 percent PUL, are shown in Table V.63.

4. Annualized Benefits and Costs of the Adopted Standards for Liquid-Immersed Distribution Transformers
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The annualized net benefit is (1) the annualized national economic value (expressed in 2022$) of the benefits from operating products that meet the adopted standards (consisting primarily of operating cost savings from using less energy), minus increases in product purchase costs, and (2) the annualized monetary value of the climate and health benefits.
Table V.64 shows the annualized values for liquid-immersed distribution transformers under TSL 3, expressed in 2022$. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NOx and SO 2 reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for liquid-immersed distribution transformers is $151.1 million per year in increased equipment installed costs, while the estimated annual benefits are $210.2 million from reduced equipment operating costs, $106.1 million in GHG reductions, and $117.0 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $282.3 million per year.
Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for liquid-immersed distribution transformers is $152.6 million per year in increased equipment costs, while the estimated annual benefits are $348.3 million in reduced operating costs, $106.1 million from GHG reductions, and $213.2 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $515.1 million per year.

5. Annualized Benefits and Costs of the Adopted Standards for Low-Voltage Dry-Type Distribution Transformers
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The annualized net benefit is (1) the annualized national economic value (expressed in 2022$) of the benefits from operating products that meet the adopted standards (consisting primarily of operating cost savings from using less energy), minus increases in product purchase costs, and (2) the annualized monetary value of the climate and health benefits.
Table V.65 shows the annualized values for low-voltage dry-type under TSL 3, expressed in 2022$. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NOx and SO 2 reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for low-voltage dry-type is $66.6 million per year in increased equipment installed costs, while the estimated annual benefits are $286.8 million from reduced equipment operating costs, $70.4 million in GHG reductions, and $80.3 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $370.8 million per year.
Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for low-voltage dry-type is $67.4 million per year in increased equipment costs, while the estimated annual benefits are $450.9 million in reduced operating costs, $70.4 million from GHG reductions, and $139.1 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $593.0 million per year.

6. Annualized Benefits and Costs of the Adopted Standards for Medium-Voltage Dry-Type Distribution Transformers
The benefits and costs of the adopted standards can also be expressed in terms of annualized values. The annualized net benefit is (1) the annualized national economic value (expressed in 2022$) of the benefits from operating products that meet the adopted standards (consisting primarily of operating cost savings from using less energy), minus increases in product purchase costs, and (2) the annualized monetary value of the climate and health benefits.
Table V.66 shows the annualized values for medium-voltage dry-type under TSL 2, expressed in 2022$. The results under the primary estimate are as follows.
Using a 7-percent discount rate for consumer benefits and costs and NOx and SO 2 reductions, and the 3-percent discount rate case for GHG social costs, the estimated cost of the adopted standards for medium-voltage dry-type is $12.5 million per year in increased equipment installed costs, while the estimated annual benefits are $15.9 million from reduced equipment operating costs, $5.9 million in GHG reductions, and $6.7 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $16.0 million per year.
Using a 3-percent discount rate for all benefits and costs, the estimated cost of the adopted standards for medium-voltage dry-type is $12.7 million per year in increased equipment costs, while the estimated annual benefits are $25.1 million in reduced operating costs, $5.9 million from GHG reductions, and $11.7 million from reduced NO X and SO 2 emissions. In this case, the net benefit amounts to $29.9 million per year.

7. Benefits and Costs of the Proposed Standards for All Considered Distribution Transformers
As described in sections V.C.1 through V.C.3, for this final rule DOE is adopting TSL 3 for liquid-immersed, TSL 3 for low-voltage dry-type, and TSL 2 for medium-voltage dry-type distribution transformers. Table V.67 shows the combined cumulative benefits, and Table V.68 shows the combined annualized benefits for the proposed levels for all distribution transformers.

8. Severability
Finally, DOE added a new paragraph (e) to 10 CFR 431.196 to provide that each energy conservation standard for each distribution transformer category (liquid immersed, LVDT, MDVT) is separate and severable from one another, and that if any energy conservation standard for any category is stayed or determined to be invalid by a court of competent jurisdiction, the remaining energy conservation standards for the other categories shall continue in effect. This severability clause is intended to clearly express the Department's intent that should an energy conservation standard for any category be stayed or invalidated, energy conservation standards for the other categories shall continue to remain in full force and legal effect.

VI. Procedural Issues and Regulatory Review

A. Review Under Executive Orders 12866, 13563, and 14094
Executive Order (E.O.) 12866, “Regulatory Planning and Review,” as supplemented and reaffirmed by E.O. 13563, “Improving Regulation and Regulatory Review,” 76 FR 3821 (Jan. 21, 2011) and amended by E.O. 14094, “Modernizing Regulatory Review,” 88 FR 21879 (April 11, 2023), requires agencies, to the extent permitted by law, to (1) propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor regulations to impose the least burden on society, consistent with obtaining regulatory objectives, taking into account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) select, in choosing among alternative regulatory approaches, those approaches that maximize net benefits (including potential economic, environmental, public health and safety, and other advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance objectives, rather than specifying the behavior or manner of compliance that regulated entities must adopt; and (5) identify and assess available alternatives to direct regulation, including providing economic incentives to encourage the desired behavior, such as user fees or marketable permits, or providing information upon which choices can be made by the public. DOE emphasizes as well that E.O. 13563 requires agencies to use the best available techniques to quantify anticipated present and future benefits and costs as accurately as possible. In its guidance, the Office of Information and Regulatory Affairs (OIRA) in the Office of Management and Budget (OMB) has emphasized that such techniques may include identifying changing future compliance costs that might result from technological innovation or anticipated behavioral changes. For the reasons stated in the preamble, this final regulatory action is consistent with these principles.
Section 6(a) of E.O. 12866 also requires agencies to submit “significant regulatory actions” to OIRA for review. OIRA has determined that this final regulatory action constitutes a “significant regulatory action” within the scope of section 3(f)(1) of E.O. 12866. Accordingly, pursuant to section 6(a)(3)(C) of E.O. 12866, DOE has provided to OIRA an assessment, including the underlying analysis, of benefits and costs anticipated from the final regulatory action, together with, to the extent feasible, a quantification of those costs; and an assessment, including the underlying analysis, of costs and benefits of potentially effective and reasonably feasible alternatives to the planned regulation, and an explanation why the planned regulatory action is preferable to the identified potential alternatives. These assessments are summarized in this preamble and further detail can be found in the technical support document for this rulemaking.

B. Review Under the Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) requires preparation of an initial regulatory flexibility analysis (IRFA) and a final regulatory flexibility analysis (FRFA) for any rule that by law must be proposed for public comment, unless the agency certifies that the rule, if promulgated, will not have a significant economic impact on a substantial number of small entities. As required by E.O. 13272, “Proper Consideration of Small Entities in Agency Rulemaking,” 67 FR 53461 (Aug. 16, 2002), DOE published procedures and policies on February 19, 2003, to ensure that the potential impacts of its rules on small entities are properly considered during the rulemaking process. 68 FR 7990. DOE has made its procedures and policies available on the Office of the General Counsel's website ( www.energy.gov/gc/office-general-counsel ). DOE has prepared the following FRFA for the products that are the subject of this rulemaking.
For manufacturers of distribution transformers, the SBA has set a size threshold, which defines those entities classified as “small businesses” for the purposes of the statute. DOE used the SBA's small business size standards to determine whether any small entities would be subject to the requirements of the rule. (See 13 CFR part 121.) The size standards are listed by NAICS code and industry description and are available at www.sba.gov/document/support-table-size-standards . Manufacturing of distribution transformers is classified under NAICS 335311, “Power, Distribution, and Specialty Transformer Manufacturing”. The SBA sets a threshold of 800 employees or fewer for an entity to be considered as a small business for this category.

1. Need for, and Objectives of, Rule
EPCA authorizes DOE to regulate the energy efficiency of a number of consumer products and certain industrial equipment. Title III, Part B of EPCA established the Energy Conservation Program for Consumer Products Other Than Automobiles. (42 U.S.C. 6291-6309) Title III, Part C of EPCA, added by Public Law 95-619, Title IV, section 411(a), established the Energy Conservation Program for Certain Industrial Equipment. The Energy Policy Act of 1992, Public Law 102-486, amended EPCA and directed DOE to prescribe energy conservation standards for those distribution transformers for which DOE determines such standards would be technologically feasible, economically justified, and would result in significant energy savings. (42 U.S.C. 6317(a)) The Energy Policy Act of 2005, Public Law 109-58, amended EPCA to establish energy conservation standards for low-voltage dry-type distribution transformers. (42 U.S.C. 6295(y))
EPCA further provides that, not later than six years after the issuance of any final rule establishing or amending a standard, DOE must publish either a notice of determination that standards for the product do not need to be amended, or a NOPR including new proposed energy conservation standards (proceeding to a final rule, as appropriate). (42 U.S.C. 6316(a); 42 U.S.C. 6295(m)(1))
DOE must follow specific statutory criteria for prescribing new or amended standards for covered equipment, including distribution transformers. Any new or amended standard for a covered product must be designed to achieve the maximum improvement in energy efficiency that the Secretary of Energy determines is technologically feasible and economically justified. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(2)(A)) Furthermore, DOE may not adopt any standard that would not result in the significant conservation of energy. (42 U.S.C. 6316(a); 42 U.S.C. 6295(o)(3))

2. Significant Issues Raised by Public Comments in Response to the IRFA
APPA commented that some small manufacturers will not be able to retool in sufficient time and will further worsen supply chain concerns. (APPA, No. 103 at p. 6) Powersmiths commented that using amorphous steel for LVDT distribution transformers requires an overhaul of the manufacturing production process. (Powersmiths, No. 112 at p. 6) Powersmiths commented that small manufacturers may not be able to make this transition due to the complexity and novelty of amorphous steel, along with the need for qualified designers, significant retooling costs, new manufacturing processes, and other additional resources. ( Id. ) Additionally, Powersmiths commented that even if LVDT small manufacturers could make this transition to amorphous steel they will need more than the 3-year compliance period proposed in the January 2023 NOPR. ( Id. )
DOE understands that distribution transformer manufacturers, including small businesses, will incur conversion costs, which include retooling production facilities, in order to comply with standards. DOE estimates the impacts to the distribution transformer industry at each TSL in section V.B.2.a of this document and specifically estimates the impact to small businesses as part of this FRFA. Additionally, in the January 2023 NOPR DOE proposed a 3-year compliance period for manufacturers to meet the proposed standards. DOE is adopting a 5-year compliance period for this final rule. This additional time should allow for manufacturers, including small manufacturers, to retool their production facilities and make the necessary equipment additions that manufacturers will have to make to manufacture compliant distribution transformers. DOE also notes that the expanded compliance date provides greater time for core steel manufacturers, both GOES and amorphous, to meet expected demand.
NAHB commented that most home builders are considered a small business based on SBA's small business definition and expressed concern that DOE has not considered these home builders and other small businesses that rely on a consistent supply of distribution transformers that might be impacted by this rulemaking. (NAHB, No. 106 at p. 5) As stated in section IV.A.5 of this document, DOE notes that the standards amended in this rule will allow distribution transformers to cost-competitively utilize existing GOES capacity across many kVA ratings. Additionally, DOE notes that the compliance period for amended standards has been extended, from the 3-year compliance period proposed in the January 2023 NOPR to a 5-year compliance period adopted in this final rule. The additional time provided to redesign distribution transformers and build capacity will further mitigate any risk of disrupting production to meet current demand. Additionally, as stated in section V.B.2.c of this document, DOE does not anticipate that there will be a significant disruption in the supply of distribution transformers due to the adopted standards to home builders or any other distribution transformer markets.

3. Description and Estimated Number of Small Entities Affected
DOE conducted a more focused inquiry of the companies that could be small businesses that manufacture distribution transformers covered by this rulemaking. DOE used publicly available information to identify potential small businesses. DOE's research involved industry trade association membership directories (including NEMA), ^{202} DOE's publicly available Compliance Certification Database ^{203} (CCD), California Energy Commission's Modernized Appliance Efficiency Database System ^{204} (MAEDBS) to create a list of companies that manufacture or sell distribution transformers covered by this rulemaking. DOE also asked stakeholders and industry representatives if they were aware of any other small businesses during manufacturer interviews. DOE contacted select companies on its list, as necessary, to determine whether they met the SBA's definition of a small business that manufacturers distribution transformers covered by this rulemaking. DOE screened out companies that did not offer products covered by this rulemaking, did not meet the definition of a “small business,” or are foreign owned and operated.
^{202} See: www.nema.org/membership/manufacturers .
^{203} See: www.regulations.doe.gov/certification-data .
^{204} See: cacertappliances.energy.ca.gov .
DOE's analysis identified 36 companies that sell or manufacture distribution transformers coved by this rulemaking in the U.S. market. At least two of these companies are not the original equipment manufacturers (OEM) and instead privately label distribution transformers that are manufactured by another distribution transformer manufacturer. Of the 34 companies that are OEMs, DOE identified nine companies that have fewer than 800 total employees and are not entirely foreign owned and operated. There are three small businesses that manufacture liquid-immersed distribution transformers; there are three small businesses that manufacture LVDT and MVDT distribution transformers; and there are three small businesses that only manufacture LVDT distribution transformers. ^{205}
^{205} Therefore, there are a total of six small businesses that manufacture LVDT distribution transformers. Three that exclusively manufacture LVDT distribution transformers and three that manufacture both LVDT and MVDT distribution transformers.

Liquid-Immersed Distribution Transformer Small Businesses
Liquid-immersed distribution transformers account for over 80 percent of all distribution transformer shipments covered by this rulemaking. Seven major manufacturers supply more than 80 percent of the market for liquid-immersed distribution transformers covered by this rulemaking. None of these seven major manufacturers of liquid-immersed distribution transformers are small businesses. Most liquid-immersed distribution transformers are manufactured domestically. Electric utilities compose the customer base and typically buy on a first-cost basis. Many small manufacturers position themselves towards the higher end of the market or in particular product niches, such as network transformers or harmonic mitigating transformers, but, in general, competition is based on price after a given unit's specs are prescribed by a customer. None of the three small businesses have a market share larger than five percent of the liquid-immersed distribution transformer market.

Low-Voltage Dry-Type Distribution Transformer Small Businesses
LVDT distribution transformers account for approximately 16 percent of all distribution shipments covered by this rulemaking. Eleven major manufacturers supply more than 80 percent of the market for LVDT distribution transformers covered by this rulemaking. Two of these 11 major LVDT distribution transformer manufacturers are small businesses. The majority of LVDT distribution transformers are manufactured outside the U.S., mostly in Canada and Mexico. The customer base rarely purchases on efficiency and is very first-cost conscious, which, in turn, places a premium on economies of scale in manufacturing. However, there are universities and other buildings that purchase LVDT based on efficiency as more and more organizations are striving to get to reduced or net-zero emission targets.
In the LVDT market, lower volume manufacturers typically do not compete directly with larger volume manufacturers, as these lower volume manufacturers are frequently not able to compete on a first cost basis. However, there are lower volume manufactures that do serve customers that purchase more efficient LVDT distribution transformers. Lastly, there are some smaller firms that focus on the engineering and design of LVDT distribution transformers and source the production of some parts of the distribution transformer, most frequently the cores, to another company that manufactures those components.

Medium-Voltage Dry-Type Distribution Transformer Small Businesses
MVDT distribution transformers account for less than one percent of all distribution transformer shipments covered by this rulemaking. Eight major manufacturers supply more than 80 percent of the market for MVDT distribution transformers covered by this rulemaking. Two of the eight major MVDT distribution transformer manufacturers are small businesses. The rest of MVDT distribution transformer market is served by a mix of large and small manufactures. Most MVDT distribution transformers are manufactured domestically. Electric utilities and industrial users make up most of the customer base and typically buy on first-cost or features other than efficiency.

4. Description of Reporting, Recordkeeping, and Other Compliance Requirements

Liquid-Immersed Distribution Transformers
DOE is adopting energy conservation standards at TSL 3 for liquid-immersed distribution transformers. For liquid-immersed distribution transformers, TSL 3 is a combination of EL 2 and EL 4 for most liquid-immersed distribution transformer equipment classes.
Based on the LCC consumer choice model, DOE anticipates that most liquid-immersed distribution transformer manufacturers would use primarily grain-oriented with amorphous cores at select kVA ranges in their distribution transformers to meet these adopted energy conservation standards. While DOE anticipates that several large liquid-immersed distribution transformer manufacturers would make significant capital investments to accommodate the production of amorphous cores, DOE does not anticipate that any small businesses will make these capital investments to be able to produce their own amorphous cores, based on the large capital investments needed to be able to make amorphous cores and the limited ability for small businesses to access large capital investments. Based on manufacturer interviews and market research, DOE was not able to identify any liquid-immersed small businesses that manufacture their own cores. Therefore, DOE anticipates that all liquid-immersed small manufacturers would continue to outsource their production of distribution transformer cores. However, instead of outsourcing exclusively GOES cores they will now outsource a combination of GOES cores and amorphous cores for most of the liquid-immersed distribution transformers that they manufacture in order to comply with the adopted energy conservation standard for liquid-immersed distribution transformers.
DOE acknowledges that there is uncertainty if these small businesses will be able to find core manufacturers that will supply them with amorphous cores in order to comply with the adopted energy conservation standards for liquid-immersed distribution transformers. DOE anticipates that there will be an increase in the number of large liquid-immersed distribution transformer manufacturers that will outsource the production of their cores to core manufacturers capable of producing amorphous cores. This could increase the competition for small businesses to procure amorphous cores for their distribution transformers. Small businesses manufacturing liquid-immersed distribution transformers must be able to procure amorphous cores suitable for their distribution transformers at a cost that allows them to continue to be competitive in the market.
Based on feedback received during manufacturer interviews, DOE does not anticipate that liquid-immersed small businesses that are currently not producing their own cores would have to make a significant capital investment in their production lines to be able to use amorphous cores, that are purchased from a core manufacturer, in the distribution transformers that they manufacture. There will be some additional product conversion costs, in the form of additional R&D and testing, that will need to be incurred by small businesses that manufacture liquid-immersed distribution transformers, even if they do not manufacture their own cores. The methodology used to calculate product conversion costs, described in section IV.J.2.c of this document, estimates that manufacturers would incur approximately one and a half additional years of R&D expenditure to redesign their distribution transformers to be capable of accommodating the use of an amorphous core. Based on the financial parameters used in the GRIM, DOE estimated that the normal annual R&D is approximately 3.0 percent of annual revenue. Therefore, liquid-immersed small businesses would incur an additional 4.5 percent of annual revenue to redesign their distribution transformers to be able to accommodate using amorphous cores that were purchased from core manufacturers.

Low-Voltage Dry-Type Distribution Transformers
DOE is adopting amended energy conservation standards to be at TSL 3 for LVDT distribution transformers. For LVDT distribution transformers, TSL 3 corresponds to EL 3 for all LVDT distribution transformer equipment classes.
Based on the LCC consumer choice model, DOE anticipates that approximately 30 percent of LVDT distribution transformer manufacturers would use amorphous cores in their distribution transformers to meet these adopted energy conservation standards. Based on manufacturer interviews and market research, DOE was able to identify one LVDT small business that manufactures their own cores. The one LVDT small business that is currently manufacturing their own cores would have to make a business decision to either continue making GOES cores that they currently manufacture, make a large capital investment to be able to manufacture amorphous cores, or to outsource the production of amorphous cores. Outsourcing the production of their cores would be a significant change in their production process and could result in a reduction in this small business' market share in the LVDT distribution transformer market.
The other LVDT small businesses that are currently outsourcing their cores will continue to outsource their cores. These LVDT small businesses will have to make a business decision either to continue outsourcing GOES cores that they currently use in their LVDT distribution transformers or to find a core manufacturer that is capable of producing amorphous cores and outsource the production of amorphous cores.
DOE acknowledges that there is uncertainty if these small businesses will be able to find core manufacturers that will supply them with amorphous cores in order to comply with the adopted energy conservation standards for LVDT distribution transformers. DOE anticipates that there will be an increase in the number of large LVDT distribution transformer manufacturers that will outsource the production of their cores to core manufacturers capable of producing amorphous cores. This could increase the competition for small businesses to procure amorphous cores for their LVDT distribution transformers. However, small businesses manufacturing LVDT distribution transformers will still be able to meet the adopted energy conservation standards using GOES cores.
Based on feedback received during manufacturer interviews, DOE does not anticipate that small businesses that are currently not producing their own cores would have to make a significant capital investment in their production lines to be able to meet the adopted energy conservation standards for LVDT distribution transformers. There will be some additional product conversion costs, in the form of additional R&D and testing, that will need to be incurred by small businesses that manufacture LVDT distribution transformers, even if they do not manufacture their own cores. The methodology used to calculate product conversion costs, described in section IV.J.2.c estimates that manufacturers would incur approximately one and a half additional years of R&D expenditure to redesign their distribution transformers to be capable of accommodating the use of an amorphous core and 75 percent of annual R&D expenditures to redesign their distribution transformers that continue to use GOES cores. Based on the financial parameters used in the GRIM, DOE estimated that the normal annual R&D is approximately 3.0 percent of annual revenue. Therefore, LVDT small businesses would incur an additional 2.25 to 4.5 percent of annual revenue to redesign their distribution transformers, depending on if they choose to continue to use GOES cores or amorphous cores, to meet the adopted energy conservation standard for LVDT distribution transformers, which are set at TSL 3.

Medium-Voltage Dry-Type Distribution Transformers
DOE is adopting energy conservation standards to be at TSL 2 for MVDT distribution transformers. This corresponds to EL 2 for all MVDT distribution transformer equipment classes. Based on the LCC consumer choice model, DOE only anticipates that approximately 12 percent of MVDT distribution transformer manufacturers would use amorphous cores in their MVDT distribution transformers to meet these adopted energy conservation standards. DOE does not anticipate that MVDT distribution transformer manufacturers would make significant investments to either be able to produce cores capable of meeting these adopted amended energy conservation standards or be able to integrate more efficient purchased cores from core manufacturers. There will be some additional product conversion costs, in the form of additional R&D and testing, that will need to be incurred by small businesses that manufacture MVDT distribution transformers, even if they do not manufacture their own cores. The methodology used to calculate product conversion costs, described in section IV.J.2.c of this document, estimates that manufacturers would incur approximately 75 percent of additional R&D expenditure to redesign their distribution transformers to higher efficiency levels, when continuing to use GOES cores. Based on the financial parameters used in the GRIM, DOE estimated that the normal annual R&D is approximately 3.0 percent of annual revenue. Therefore, MVDT small businesses would include an additional 2.25 percent of annual revenue to redesign, MVDT distribution transformers to higher efficiency levels that could be met without using amorphous cores.

5. Significant Alternatives Considered and Steps Taken To Minimize Significant Economic Impacts on Small Entities
The discussion in the previous section analyzes impacts on small businesses that would result from DOE's proposed rule, represented by TSL 3 for liquid-immersed distribution transformer equipment classes; TSL 3 for LVDT equipment classes; and TSL 2 for MVDT equipment classes. In reviewing alternatives to the proposed rule, DOE examined energy conservation standards set at lower efficiency levels. While lower TSLs would reduce the impacts on small business manufacturers, it would come at the expense of a reduction in energy savings. For liquid-immersed equipment classes TSL 1 achieves 84 percent lower energy savings compared to the energy savings at TSL 3; and TSL 2 achieves 58 percent lower energy savings compared to the energy savings at TSL 3. For LVDT equipment classes TSL 1 achieves 77 percent lower energy savings compared to the energy savings at TSL 3; and TSL 2 achieves 65 percent lower energy savings compared to the energy savings at TSL 3. For MVDT equipment classes TSL 1 achieves 29 percent lower energy savings compared to the energy savings at TSL 2.
Establishing standards at TSL 3 for liquid-immersed equipment classes and LVDT equipment classes and TSL 2 for MVDT equipment classes balances the benefits of the energy savings at the adopted TSLs with the potential burdens placed on distribution transformer manufacturers, including small business manufacturers. Accordingly, DOE is not adopting one of the other TSLs considered in the analysis, or the other policy alternatives examined as part of the regulatory impact analysis and included in chapter 17 of the final rule TSD.
Additional compliance flexibilities may be available through other means. Manufacturers subject to DOE's energy efficiency standards may apply to DOE's Office of Hearings and Appeals for exception relief under certain circumstances. Manufacturers should refer to 10 CFR part 430, subpart E, and 10 CFR part 1003 for additional details.

C. Review Under the Paperwork Reduction Act
Manufacturers of distribution transformers must certify to DOE that their products comply with any applicable energy conservation standards. In certifying compliance, manufacturers must test their products according to the DOE test procedures for distribution transformers, including any amendments adopted for those test procedures. DOE has established regulations for the certification and recordkeeping requirements for all covered consumer products and commercial equipment, including distribution transformers. ( See generally 10 CFR part 429). The collection-of-information requirement for the certification and recordkeeping is subject to review and approval by OMB under the Paperwork Reduction Act (PRA). This requirement has been approved by OMB under OMB Control Number 1910-1400. Public reporting burden for the certification is estimated to average 35 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information.
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB Control Number.

D. Review Under the National Environmental Policy Act of 1969
Pursuant to the National Environmental Policy Act of 1969 (NEPA), DOE has analyzed this rule in accordance with NEPA and DOE's NEPA implementing regulations (10 CFR part 1021). DOE has determined that this rule qualifies for categorical exclusion under 10 CFR part 1021, subpart D, appendix B5.1 because it is a rulemaking that establishes energy conservation standards for consumer products or industrial equipment, none of the exceptions identified in B5.1(b) apply, no extraordinary circumstances exist that require further environmental analysis, and it meets the requirements for application of a categorical exclusion. See 10 CFR 1021.410. Therefore, DOE has determined that promulgation of this rule is not a major Federal action significantly affecting the quality of the human environment within the meaning of NEPA, and does not require an environmental assessment or an environmental impact statement.

E. Review Under Executive Order 13132
E.O. 13132, “Federalism,” 64 FR 43255 (Aug. 10, 1999), imposes certain requirements on Federal agencies formulating and implementing policies or regulations that preempt State law or that have federalism implications. The Executive order requires agencies to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States and to carefully assess the necessity for such actions. The Executive order also requires agencies to have an accountable process to ensure meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications. On March 14, 2000, DOE published a statement of policy describing the intergovernmental consultation process it will follow in the development of such regulations. 65 FR 13735. DOE has examined this rule and has determined that it would not have a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. EPCA governs and prescribes Federal preemption of State regulations as to energy conservation for the equipment that is the subject of this final rule. States can petition DOE for exemption from such preemption to the extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6316(a) and (b); 42 U.S.C. 6297) Therefore, no further action is required by Executive Order 13132.

F. Review Under Executive Order 12988
With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of E.O. 12988, “Civil Justice Reform,” imposes on Federal agencies the general duty to adhere to the following requirements: (1) eliminate drafting errors and ambiguity, (2) write regulations to minimize litigation, (3) provide a clear legal standard for affected conduct rather than a general standard, and (4) promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Regarding the review required by section 3(a), section 3(b) of E.O. 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation (1) clearly specifies the preemptive effect, if any, (2) clearly specifies any effect on existing Federal law or regulation, (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction, (4) specifies the retroactive effect, if any, (5) adequately defines key terms, and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of E.O. 12988 requires Executive agencies to review regulations in light of applicable standards in section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to meet one or more of them. DOE has completed the required review and determined that, to the extent permitted by law, this final rule meets the relevant standards of E.O. 12988.

G. Review Under the Unfunded Mandates Reform Act of 1995
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA) requires each Federal agency to assess the effects of Federal regulatory actions on State, local, and Tribal governments and the private sector. Public Law 104-4, sec. 201 (codified at 2 U.S.C. 1531). For a regulatory action likely to result in a rule that may cause the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year (adjusted annually for inflation), section 202 of UMRA requires a Federal agency to publish a written statement that estimates the resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to develop an effective process to permit timely input by elected officers of State, local, and Tribal governments on a “significant intergovernmental mandate,” and requires an agency plan for giving notice and opportunity for timely input to potentially affected small governments before establishing any requirements that might significantly or uniquely affect them. On March 18, 1997, DOE published a statement of policy on its process for intergovernmental consultation under UMRA. 62 FR 12820. DOE's policy statement is also available at www.energy.gov/sites/prod/files/gcprod/documents/umra_97.pdf.
DOE has concluded that this final rule may require expenditures of $100 million or more in any one year by the private sector. Such expenditures may include (1) investment in research and development and in capital expenditures by distribution transformer manufacturers in the years between the final rule and the compliance date for the new standards and (2) incremental additional expenditures by consumers to purchase higher-efficiency distribution transformers, starting at the compliance date for the applicable standard.
Section 202 of UMRA authorizes a Federal agency to respond to the content requirements of UMRA in any other statement or analysis that accompanies the final rule. (2 U.S.C. 1532(c)) The content requirements of section 202(b) of UMRA relevant to a private sector mandate substantially overlap the economic analysis requirements that apply under section 325(o) of EPCA and Executive Order 12866. The SUPPLEMENTARY INFORMATION section of this document and the TSD for this final rule respond to those requirements.
Under section 205 of UMRA, DOE is obligated to identify and consider a reasonable number of regulatory alternatives before promulgating a rule for which a written statement under section 202 is required. (2 U.S.C. 1535(a)) DOE is required to select from those alternatives the most cost effective and least burdensome alternative that achieves the objectives of the rule unless DOE publishes an explanation for doing otherwise, or the selection of such an alternative is inconsistent with law. As required by 42 U.S.C. 6316(a) and 42 U.S.C. 6295(m)(1), this final rule establishes amended energy conservation standards for distribution transformers that are designed to achieve the maximum improvement in energy efficiency that DOE has determined to be both technologically feasible and economically justified, as required by 42 U.S.C. 6316(a); 6295(o)(2)(A) and 6295(o)(3)(B). A full discussion of the alternatives considered by DOE is presented in chapter 17 of the TSD for this final rule.

H. Review Under the Treasury and General Government Appropriations Act, 1999
Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family Policymaking Assessment for any proposed rule or policy that may affect family well-being. Although this final rule would not have any impact on the autonomy or integrity of the family as an institution as defined, this final rule could impact a family's well-being. When developing a Family Policymaking Assessment, agencies must assess whether: (1) the action strengthens or erodes the stability or safety of the family and, particularly, the marital commitment; (2) the action strengthens or erodes the authority and rights of parents in the education, nurture, and supervision of their children; (3) the action helps the family perform its functions, or substitutes governmental activity for the function; (4) the action increases or decreases disposable income or poverty of families and children; (5) the proposed benefits of the action justify the financial impact on the family; (6) the action may be carried out by State or local government or by the family; and whether (7) the action establishes an implicit or explicit policy concerning the relationship between the behavior and personal responsibility of youth, and the norms of society.
DOE has considered how the benefits of this final rule compare to the possible financial impact on a family (the only factor listed that is relevant to this proposed rule). As part of its rulemaking process, DOE must determine whether the energy conservation standards enacted in this final rule are economically justified. As discussed in sections V.C.1 through V.C.3 of this document, DOE has determined that the standards enacted in this final rule are economically justified because the benefits to consumers would far outweigh the costs to manufacturers. Moreover, as discussed further in section V.B.1 of this document, DOE has determined that for utilities who serve low population densities, average LCC savings and PBP at the considered efficiency levels are not substantially different, and are often improved ( i.e., higher LCC savings and lower PBP), as compared to the average for all utilities. Further, the standards will also result in climate and health benefits for families.

I. Review Under Executive Order 12630
Pursuant to E.O. 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights,” 53 FR 8859 (March 18, 1988), DOE has determined that this rule would not result in any takings that might require compensation under the Fifth Amendment to the U.S. Constitution.

J. Review Under the Treasury and General Government Appropriations Act, 2001
Section 515 of the Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516, note) provides for Federal agencies to review most disseminations of information to the public under information quality guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR 62446 (Oct. 7, 2002). Pursuant to OMB Memorandum M-19-15, Improving Implementation of the Information Quality Act (April 24, 2019), DOE published updated guidelines which are available at www.energy.gov/sites/prod/files/2019/12/f70/DOE%20Final%20Updated%20IQA%20Guidelines%20Dec%202019.pdf. DOE has reviewed this final rule under the OMB and DOE guidelines and has concluded that it is consistent with applicable policies in those guidelines.

K. Review Under Executive Order 13211
E.O. 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use,” 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to OIRA at OMB, a Statement of Energy Effects for any significant energy action. A “significant energy action” is defined as any action by an agency that promulgates or is expected to lead to promulgation of a final rule, and that (1) is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a significant energy action. For any significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution, or use should the proposal be implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution, and use.
DOE has concluded that this regulatory action, which sets forth amended energy conservation standards for distribution transformers, is not a significant energy action because the standards are not likely to have a significant adverse effect on the supply, distribution, or use of energy, nor has it been designated as such by the Administrator at OIRA. Accordingly, DOE has not prepared a Statement of Energy Effects on this final rule.

L. Information Quality
On December 16, 2004, OMB, in consultation with the Office of Science and Technology Policy (OSTP), issued its Final Information Quality Bulletin for Peer Review (“the Bulletin”). 70 FR 2664 (Jan. 14, 2005). The Bulletin establishes that certain scientific information shall be peer reviewed by qualified specialists before it is disseminated by the Federal Government, including influential scientific information related to agency regulatory actions. The purpose of the Bulletin is to enhance the quality and credibility of the Government's scientific information. Under the Bulletin, the energy conservation standards rulemaking analyses are “influential scientific information,” which the Bulletin defines as “scientific information the agency reasonably can determine will have, or does have, a clear and substantial impact on important public policies or private sector decisions.” 70 FR 2664, 2667.
In response to OMB's Bulletin, DOE conducted formal peer reviews of the energy conservation standards development process and the analyses that are typically used and prepared a report describing that peer review. ^{206} Generation of this report involved a rigorous, formal, and documented evaluation using objective criteria and qualified and independent reviewers to make a judgment as to the technical/scientific/business merit, the actual or anticipated results, and the productivity and management effectiveness of programs and/or projects. Because available data, models, and technological understanding have changed since 2007, DOE has engaged with the National Academy of Sciences to review DOE's analytical methodologies to ascertain whether modifications are needed to improve DOE's analyses. DOE is in the process of evaluating the resulting report. ^{207}
^{206} The 2007 “Energy Conservation Standards Rulemaking Peer Review Report” is available at the following website: energy.gov/eere/buildings/downloads/energy-conservation-standards-rulemaking-peer-review-report-0 (last accessed Jan. 16, 2024).
^{207} The report is available at www.nationalacademies.org/our-work/review-of-methods-for-setting-building-and-equipment-performance-standards.

M. Congressional Notification
As required by 5 U.S.C. 801, DOE will report to Congress on the promulgation of this rule prior to its effective date. The report will state that the Office of Information and Regulatory Affairs has determined that the rule meets the criteria set forth in 5 U.S.C. 804(2).).

VII. Approval of the Office of the Secretary
The Secretary of Energy has approved publication of this final rule.

List of Subjects in 10 CFR Part 431
Administrative practice and procedure, Confidential business information, Energy conservation test procedures, Reporting and recordkeeping requirements.

Signing Authority
This document of the Department of Energy was signed on April 3, 2024, by Jeffrey Marootian, Principal Deputy Assistant Secretary for Energy Efficiency and Renewable Energy, pursuant to delegated authority from the Secretary of Energy. That document with the original signature and date is maintained by DOE. For administrative purposes only, and in compliance with requirements of the Office of the Federal Register, the undersigned DOE Federal Register Liaison Officer has been authorized to sign and submit the document in electronic format for publication, as an official document of the Department of Energy. This administrative process in no way alters the legal effect of this document upon publication in the Federal Register .
Signed in Washington, DC, on April 4, 2024.
Treena V. Garrett,

Federal Register Liaison Officer, U.S. Department of Energy.
For the reasons set forth in the preamble, DOE amends part 431 of chapter II, of title 10 of the Code of Federal Regulations, as set forth below:

PART 431—ENERGY EFFICIENCY PROGRAM FOR CERTAIN COMMERCIAL AND INDUSTRIAL EQUIPMENT
1. The authority citation for part 431 continues to read as follows:

Authority:
42 U.S.C. 6291-6317; 28 U.S.C. 2461 note.
2. Amend § 431.192 by:
a. Revising the definitions for “Distribution transformer”, “Drive (isolation) transformer”, “Nonventilated transformer”, “Sealed transformer”, and “Special-impedance transformer”;
b. Adding in alphabetical order a definition for “Submersible distribution transformer”; and
c. Revising the definitions for “Transformer with a tap range of 20 percent or more” and “Uninterruptible power supply transformer”.
The revisions and addition read as follows:
§ 431.192
Definitions.
* * * * *
Distribution transformer means a transformer that—
(1) Has an input line voltage of 34.5 kV or less;
(2) Has an output line voltage of 600 V or less;
(3) Is rated for operation at a frequency of 60 Hz; and
(4) Has a capacity of 10 kVA to 5000 kVA for liquid-immersed units and 15 kVA to 5000 kVA for dry-type units; but
(5) The term “distribution transformer” does not include a transformer that is an—
(i) Autotransformer;
(ii) Drive (isolation) transformer;
(iii) Grounding transformer;
(iv) Machine-tool (control) transformer;
(v) Nonventilated transformer;
(vi) Rectifier transformer;
(vii) Regulating transformer;
(viii) Sealed transformer;
(ix) Special-impedance transformer;
(x) Testing transformer;
(xi) Transformer with tap range of 20 percent or more;
(xii) Uninterruptible power supply transformer; or
(xiii) Welding transformer.
Drive (isolation) transformer means a transformer that:
(1) Isolates an electric motor from the line;
(2) Accommodates the added loads of drive-created harmonics;
(3) Is designed to withstand the additional mechanical stresses resulting from an alternating current adjustable frequency motor drive or a direct current motor drive; and
(4) Has a rated output voltage that is neither “208Y/120” nor “480Y/277”.
* * * * *
Nonventilated transformer means a dry-type transformer constructed so as to prevent external air circulation through the coils of the transformer while operating at zero gauge pressure.
* * * * *
Sealed transformer means a dry-type transformer designed to remain hermetically sealed under specified conditions of temperature and pressure.
Special-impedance transformer means a transformer built to operate at an impedance outside of the normal impedance range for that transformer's kVA rating. The normal impedance range for each kVA rating for liquid-immersed and dry-type transformers is shown in Tables 1 and 2, respectively.
Table 1 to the Definition o “Special-Impedance Transformer”—Normal Impedance Ranges for Liquid-Immersed Transformers
Single-phase transformers | kVA | Impedance (%) | Three-phase transformers | kVA | Impedance (%)
10 <= kVA < 50 | 1.0-4.5 | 15 <= kVA < 75 | 1.0-4.5
50 <= kVA < 250 | 1.5-4.5 | 75 <= kVA < 112.5 | 1.0-5.0
250 <= kVA < 500 | 1.5-6.0 | 112.5 <= kVA < 500 | 1.2-6.0
500 <= kVA < 667 | 1.5-7.0 | 500 <= kVA < 750 | 1.5-7.0
667 <= kVA <= 833 | 5.0-7.5 | 750 <= kVA <= 5000 | 5.0-7.5
Table 2 to the Definition o “Special-Impedance Transformer”—Normal Impedance Ranges for Dry-Type Transformers
Single-phase transformers | kVA | Impedance (%) | Three-phase transformers | kVA | Impedance (%)
10 <= kVA < 50 | 1.0-4.5 | 15 <= kVA < 75 | 1.0-4.5
50 <= kVA < 250 | 1.5-4.5 | 75 <= kVA < 112.5 | 1.0-5.0
250 <= kVA < 500 | 1.5-6.0 | 112.5 <= kVA < 500 | 1.2-6.0
500 <= kVA < 667 | 1.5-7.0 | 500 <= kVA < 750 | 1.5-7.0
667 <= kVA <= 833 | 5.0-7.5 | 750 <= kVA <= 5000 | 5.0-7.5
Submersible distribution transformer means a liquid-immersed distribution transformer, so constructed as to be operable when fully or partially submerged in water including the following features—
(1) Has sealed-tank construction; and
(2) Has the tank, cover, and all external appurtenances made of corrosion-resistant material or with appropriate corrosion resistant surface treatment to induce the components surface to be corrosion resistant.
* * * * *
Transformer with tap range of 20 percent or more means a transformer with multiple voltage taps, each capable of operating at full, rated capacity (kVA), whose range, defined as the difference between the highest voltage tap and the lowest voltage tap, is 20 percent or more of the highest voltage tap.
Uninterruptible power supply transformer means a transformer that is used within an uninterruptible power system, which in turn supplies power to loads that are sensitive to power failure, power sages, over voltage, switching transients, line notice, and other power quality factors. It does not include distribution transformers at the input, output, or by-pass of an uninterruptible power system.
* * * * *
3. Amend § 431.196 by:
a. Revising paragraph (a)(2) and adding paragraph (a)(3);
b. Revising paragraph (b)(2) and adding paragraphs (b)(3) and (4);
c. Revising paragraph (c)(2) and adding paragraph (c)(3); and
d. Adding paragraph (e).
The revisions and additions read as follows:
§ 431.196
Energy conservation standards and their effective dates.
(a) * * *
(2) The efficiency of a low-voltage, dry-type distribution transformer manufactured on or after January 1, 2016, but before April 23, 2029, shall be no less than that required for the applicable kVA rating in the following table. Low-voltage dry-type distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 2 to Paragraph ( a )(1)
Single-phase | kVA | | Three-phase | kVA |
15 | 97.70 | 15 | 97.89
25 | 98.00 | 30 | 98.23
37.5 | 98.20 | 45 | 98.40
50 | 98.30 | 75 | 98.60
75 | 98.50 | 112.5 | 98.74
100 | 98.60 | 150 | 98.83
167 | 98.70 | 225 | 98.94
250 | 98.80 | 300 | 99.02
333 | 98.90 | 500 | 99.14
| | 750 | 99.23
| | 1000 | 99.28
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to this subpart K.
(3) The efficiency of a low-voltage dry-type distribution transformer manufactured on or after April 23, 2029, shall be no less than that required for their kVA rating in the following table. Low-voltage dry-type distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 3 to Paragraph ( a )(3)
Single-phase | kVA | Efficiency (%) | Three-phase | kVA | Efficiency (%)
15 | 98.39 | 15 | 98.31
25 | 98.60 | 30 | 98.58
37.5 | 98.74 | 45 | 98.72
50 | 98.81 | 75 | 98.88
75 | 98.95 | 112.5 | 98.99
100 | 99.02 | 150 | 99.06
167 | 99.09 | 225 | 99.15
250 | 99.16 | 300 | 99.22
333 | 99.23 | 500 | 99.31
| | 750 | 99.38
| | 1000 | 99.42
Note: All efficiency values are at 35 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to this subpart K.
(b) * * *
(2) The efficiency of a liquid-immersed distribution transformer, including submersible distribution transformers, manufactured on or after January 1, 2016, but before April 23, 2029, shall be no less than that required for their kVA rating in the following table. Liquid-immersed distribution transformers, including submersible distribution transformers, with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 5 to Paragraph ( b )(2)
Single-phase | kVA | Efficiency (%) | Three-phase | kVA | Efficiency (%)
10 | 98.70 | 15 | 98.65
15 | 98.82 | 30 | 98.83
25 | 98.95 | 45 | 98.92
37.5 | 99.05 | 75 | 99.03
50 | 99.11 | 112.5 | 99.11
75 | 99.19 | 150 | 99.16
100 | 99.25 | 225 | 99.23
167 | 99.33 | 300 | 99.27
250 | 99.39 | 500 | 99.35
333 | 99.43 | 750 | 99.40
500 | 99.49 | 1000 | 99.43
667 | 99.52 | 1500 | 99.48
833 | 99.55 | 2000 | 99.51
| | 2500 | 99.53
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test—Procedure, appendix A to this subpart K.
(3) The efficiency of a liquid-immersed distribution transformer, that is not a submersible distribution transformer, manufactured on or after April 23, 2029, shall be no less than that required for their kVA rating in the following table. Liquid-immersed distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 6 to Paragraph ( b )(3)
Single-phase | kVA | Efficiency (%) | Three-phase | kVA | Efficiency (%)
10 | 98.77 | 15 | 98.92
15 | 98.88 | 30 | 99.06
25 | 99.00 | 45 | 99.14
37.5 | 99.10 | 75 | 99.22
50 | 99.15 | 112.5 | 99.29
75 | 99.23 | 150 | 99.33
100 | 99.29 | 225 | 99.38
167 | 99.46 | 300 | 99.42
250 | 99.51 | 500 | 99.38
333 | 99.54 | 750 | 99.43
500 | 99.59 | 1000 | 99.46
667 | 99.62 | 1500 | 99.51
833 | 99.64 | 2000 | 99.53
| | 2500 | 99.55
| | 3750 | 99.54
| | 5000 | 99.53
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to this subpart K.
(4) The efficiency of a submersible distribution transformer, manufactured on or after April 23, 2029, shall be no less than that required for their kVA rating in the following table. Submersible distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 7 to Paragraph ( b )(4)
Single-phase | kVA | Efficiency (%) | Three-phase | kVA | Efficiency (%)
10 | 98.70 | 15 | 98.65
15 | 98.82 | 30 | 98.83
25 | 98.95 | 45 | 98.92
37.5 | 99.05 | 75 | 99.03
| 50 | 99.11 | 112.5 | 99.11
75 | 99.19 | 150 | 99.16
100 | 99.25 | 225 | 99.23
167 | 99.33 | 300 | 99.27
250 | 99.39 | 500 | 99.35
333 | 99.43 | 750 | 99.40
500 | 99.49 | 1000 | 99.43
667 | 99.52 | 1500 | 99.48
833 | 99.55 | 2000 | 99.51
| | 2500 | 99.53
Note: All efficiency values are at 50 percent of nameplate-rated load, determined according to the DOE Test—Procedure, appendix A to this subpart K.
(c) * * *
(2) The efficiency of a medium-voltage dry-type distribution transformer manufactured on or after January 1, 2016, but before April 23, 2029, shall be no less than that required for their kVA and BIL rating in the following table. Medium-voltage dry-type distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 9 to Paragraph ( c )(2)
kVA | Single-phase | BIL ^1 | 20-45 kV | Efficiency (%) | 46-95 kV | Efficiency (%) | ≥96 kV | Efficiency (%) | kVA | Three-phase | BIL | 20-45 kV | Efficiency (%) | 46-95 kV | Efficiency (%) | ≥96 kV | Efficiency (%)
15 | 98.10 | 97.86 | | 15 | 97.50 | 97.18 |
25 | 98.33 | 98.12 | | 30 | 97.90 | 97.63 |
37.5 | 98.49 | 98.30 | | 45 | 98.10 | 97.86 |
50 | 98.60 | 98.42 | | 75 | 98.33 | 98.13 |
75 | 98.73 | 98.57 | 98.53 | 112.5 | 98.52 | 98.36 |
100 | 98.82 | 98.67 | 98.63 | 150 | 98.65 | 98.51 |
167 | 98.96 | 98.83 | 98.80 | 225 | 98.82 | 98.69 | 98.57
250 | 99.07 | 98.95 | 98.91 | 300 | 98.93 | 98.81 | 98.69
333 | 99.14 | 99.03 | 98.99 | 500 | 99.09 | 98.99 | 98.89
500 | 99.22 | 99.12 | 99.09 | 750 | 99.21 | 99.12 | 99.02
667 | 99.27 | 99.18 | 99.15 | 1000 | 99.28 | 99.20 | 99.11
833 | 99.31 | 99.23 | 99.20 | 1500 | 99.37 | 99.30 | 99.21
| | | | 2000 | 99.43 | 99.36 | 99.28
| | | | 2500 | 99.47 | 99.41 | 99.33
^1 BIL means basic impulse insulation level.
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to this subpart K.
(3) The efficiency of a medium-voltage dry-type distribution transformer manufactured on or after April 23, 2029, shall be no less than that required for their kVA and BIL rating in the following table. Medium-voltage dry-type distribution transformers with kVA ratings not appearing in the table shall have their minimum efficiency level determined by linear interpolation of the kVA and efficiency values immediately above and below that kVA rating.
Table 10 to Paragraph ( c )(3)
kVA | Single-phase | BIL ^1 | 20-45 kV | Efficiency (%) | 46-95 kV | Efficiency (%) | ≥96 kV | Efficiency (%) | kVA | Three-phase | BIL | 20-45 kV | Efficiency (%) | 46-95 kV | Efficiency (%) | ≥96 kV | Efficiency (%)
15 | 98.29 | 98.07 | | 15 | 97.75 | 97.46 |
| 25 | 98.50 | 98.31 | | 30 | 98.11 | 97.87 |
37.5 | 98.64 | 98.47 | | 45 | 98.29 | 98.07 |
50 | 98.74 | 98.58 | | 75 | 98.50 | 98.32 |
75 | 98.86 | 98.71 | 98.68 | 112.5 | 98.67 | 98.52 |
100 | 98.94 | 98.80 | 98.77 | 150 | 98.79 | 98.66 |
167 | 99.06 | 98.95 | 98.92 | 225 | 98.94 | 98.82 | 98.71
250 | 99.16 | 99.06 | 99.02 | 300 | 99.04 | 98.93 | 98.82
333 | 99.23 | 99.13 | 99.09 | 500 | 99.18 | 99.09 | 99.00
500 | 99.30 | 99.21 | 99.18 | 750 | 99.29 | 99.21 | 99.12
667 | 99.34 | 99.26 | 99.24 | 1000 | 99.35 | 99.28 | 99.20
833 | 99.38 | 99.31 | 99.28 | 1500 | 99.43 | 99.37 | 99.29
| | | | 2000 | 99.49 | 99.42 | 99.35
| | | | 2500 | 99.52 | 99.47 | 99.40
| | | | 3750 | 99.50 | 99.44 | 99.40
| | | | 5000 | 99.48 | 99.43 | 99.39
^1 BIL means basic impulse insulation level/
Note: All efficiency values are at 50 percent of nameplate rated load, determined according to the DOE Test Method for Measuring the Energy Consumption of Distribution Transformers under appendix A to this subpart K.
* * * * *
(e) Severability. The provisions of paragraphs (a) through (d) of this section are separate and severable from one another. Should a court of competent jurisdiction hold any provision(s) of this section to be stayed or invalid, such action shall not affect any other provision of this section.

Note:
The following letter will not appear in the Code of Federal Regulations.
U.S. DEPARTMENT OF JUSTICE
Antitrust Division
RFK Main Justice Building
950 Pennsylvania Avenue NW
Washington, DC 20530-0001
March 20, 2023
Ami Grace-Tardy
Assistant General Counsel for Legislation, Regulation and Energy Efficiency
U.S. Department of Energy
Washington, DC 20585
Ami.Grace-Tardy@hw.doe.gov
Re: Energy Conservation Standards for Distribution Transformers, DOE Docket No. EERE-2019-BT-STD-0018
Dear Assistant General Counsel Grace-Tardy:
I am responding to your January 19, 2023 letter seeking the views of the Attorney General about the potential impact on competition of proposed energy conservation standards for distribution transformers.
Your request was submitted under Section 325(o)(2)(B)(i)(V) of the Energy Policy and Conservation Act, as amended (ECPA), 42 U.S.C. 6295(o)(2)(B)(i)(V), which requires the Attorney General to make a determination of the impact of any lessening of competition that is likely to result from the imposition of proposed energy conservation standards. The Attorney General's responsibility for responding to requests from other departments about the effect of a program on competition has been delegated to the Assistant Attorney General for the Antitrust Division in 28 CFR 0.40(g). The Assistant Attorney General for the Antitrust Division has authorized me, as the Policy Director for the Antitrust Division, to provide the Antitrust Division's views regarding the potential impact on competition of proposed energy conservation standards on his behalf.
In conducting its analysis, the Antitrust Division examines whether a proposed standard may lessen competition, for example, by substantially limiting consumer choice, by placing certain manufacturers at an unjustified competitive disadvantage, or by inducing avoidable inefficiencies in production or distribution of particular products. A lessening of competition could result in higher prices to manufacturers and consumers.
We have reviewed the proposed standards contained in the Notice of proposed rulemaking and request for comment (88 FR 1722, January 11, 2023) and the related Technical Support Document. We have also reviewed public comments and information presented at the Webinar of the Public Meetings held on September 29, 2021 and February 16, 2023.
Based on this review, our conclusion is that the proposed energy conservation standards for distribution transformers are unlikely to have a significant adverse impact on competition.
Sincerely,
David G.B. Lawrence,
Policy Director.
89
78
Monday, April 22, 2024
Rules and Regulations
Part IV
Office of Management and Budget
2 CFR Parts 1, 25, 170, et al.

Guidance for Federal Financial Assistance; Final Rule
OFFICE OF MANAGEMENT AND BUDGET
2 CFR Parts 1, 25, 170, 175, 180, 182, 183, 184, 200
Guidance for Federal Financial Assistance

AGENCY:
Office of Federal Financial Management, Office of Management and Budget

ACTION:
Final rule; notification of final guidance.

SUMMARY:
The Office of Management and Budget (OMB) is revising the OMB Guidance for Grants and Agreements, which is now called the OMB Guidance for Federal Financial Assistance. The final guidance reflects public comments received in response to the OMB Notification of Proposed Guidance published in October 2023 and comments received from Federal agencies. In response to comments, OMB is revising and updating the guidance to incorporate recent OMB policy priorities related to Federal financial assistance and to reduce agency and recipient burden. OMB is also incorporating certain statutory requirements and clarifying certain sections of the prior version of the guidance that recipients or agencies have interpreted in different ways. OMB is also making revisions to use plain language, improve flow, and address inconsistent use of terms within the guidance text. Finally, OMB is making revisions to improve Federal financial assistance management, transparency, and oversight through more accessible and readily comprehensible guidance.

DATES:
The effective date for the final guidance is October 1, 2024. Federal agencies may elect to apply the final guidance to Federal awards issued prior to October 1, 2024, but they are not required to do so. For agencies applying the final guidance before October 1, 2024, the effective date of the final guidance must be no earlier than June 21, 2024.

FOR FURTHER INFORMATION CONTACT:
Andrew Reisig or Steven Mackey at the OMB Office of Federal Financial Management via email at MBX.OMB.Grants@OMB.eop.gov .

SUPPLEMENTARY INFORMATION:

Executive Summary
The Office of Management and Budget (OMB) is revising several parts of the OMB Guidance for Grants and Agreements, now called the OMB Guidance for Federal Financial Assistance, located in title 2 of the Code of Federal Regulations (CFR). These revisions provide clarity and updated guidance to Federal agencies regarding the consistent and efficient use of Federal financial assistance. This document includes revisions to Part 1 (About Title 2 of the Code of Federal Regulations and Subtitle A); Part 25 (Unique Entity Identifier and System for Award Management); Part 170 (Reporting Subaward and Executive Compensation Information), Part 175 (Award Term for Trafficking in Persons); Part 180 (OMB Guidelines to Agencies on Government-Wide Debarment and Suspension (Non-procurement); Part 182 (Government-Wide Requirements for Drug-Free Workplace (Financial Assistance); Part 183 (Never Contract with the Enemy); Part 184 (Buy America Preferences for Infrastructure Projects); and Part 200 (Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards).
As explained in further detail below, OMB is revising its guidance in 2 CFR for the purpose of: (1) incorporating statutory requirements and administration priorities; (2) reducing agency and recipient burden; (3) clarifying sections that recipients or agencies have interpreted in different ways; and (4) rewriting applicable sections in plain language, improving flow, and addressing inconsistent use of terms within the guidance. OMB's revisions are intended to improve Federal financial assistance management, transparency, and oversight through more accessible and easily understandable guidance.
OMB summarizes its policy changes in this document below. OMB also explains its general methodology for plain language revisions. OMB sought to maintain the existing structure of the 2 CFR guidance, which remains generally intact and mostly consistent with earlier iterations of the guidance in this final version. For example, OMB generally maintained the structure of parts, subparts, and sections of the guidance. Except in cases where OMB made policy changes or other edits for consistency with statutory requirements, OMB also generally sought to maintain the existing content of the 2 CFR guidance. In many cases throughout the guidance, however, OMB included plain language revisions to simplify the guidance text, avoid or reduce technical jargon where feasible, provide greater consistency, and make the text more succinct.
The revisions align with OMB's authority to: (i) issue guidance promoting consistent and efficient use of Federal financial assistance instruments; and (ii) provide overall direction and leadership to Federal agencies on policies and requirements related to Federal financial assistance. See 31 U.S.C. 6307 and 31 U.S.C. 503(a)(2). Additional authorities for the revisions are set forth below. Many of OMB's proposed revisions reflected comments received from Federal agencies and those received from the public in response to the OMB Notice of Request for Information published in the Federal Register in February 2023. See 88 FR 8480 (Feb. 9, 2023). In the final revisions provided through this document, OMB responds to public comments received in response to the OMB Notification of Proposed Guidance published in the Federal Register in October 2023. See 88 FR 69390 (Oct. 5, 2023).

Background
Between 2012 and 2013, OMB worked with Federal agencies to revise and streamline existing guidance to develop the Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards (Uniform Guidance) located in part 200 of 2 CFR. 79 FR 78589 (Dec. 26, 2013). This effort was intended to assist programs in delivering better outcomes on behalf of the American people while simultaneously reducing administrative burden and the risk of fraud, waste, and abuse. The Uniform Guidance in part 200, which OMB established in 2013, consolidated, streamlined, and superseded requirements from several earlier OMB Circulars and guidance documents related to Federal financial assistance management and implementation of the Single Audit Act. OMB explained in 2013 that its guidance intended to improve both the clarity and accessibility of these requirements across the Federal government. Federal award-making agencies implemented the Uniform Guidance through an interim final rule, which became effective on December 26, 2014. 79 FR 75867 (Dec. 19, 2014).
OMB periodically reviews the Uniform Guidance in accordance with 2 CFR 200.109. For example, OMB made further revisions to the Uniform Guidance in 2020. 85 FR 49506 (Aug. 13, 2020). The 2020 revisions addressed topics including program development and design, as well as measuring recipient performance to assist Federal awarding agencies and non-Federal entities to improve program goals and objectives, share lessons learned, and adopt promising performance practices.
On February 9, 2023, OMB issued a Notice of Request for Information in the Federal Register , which explained that OMB was beginning the process of seeking public input for its proposed revisions to OMB's guidance in 2 CFR. See 88 FR 8480 (Feb. 9, 2023).
On October 5, 2023, OMB issued a Notification of Proposed Guidance in the Federal Register , which explained that OMB was proposing revisions to parts 1, 25, 170, 175, 180, 182, 183, and 200 in 2 CFR, subtitle A. 88 FR 69390 (Oct. 5, 2023). OMB established these parts of the 2 CFR guidance at different times in the last 20 years. See, for example, 69 FR 26276 (May, 11, 2004) (establishing 2 CFR for guidance on grants and other financial assistance and nonprocurement agreements); 70 FR 51863 (Aug. 31, 2005) (establishing part 180); 75 FR 55671 (Sep. 14, 2010) (establishing part 25); and 75 FR 55663 (Sep. 14, 2010) (establishing part 170).
Based on OMB's review of the many public comments received and ongoing engagement with Federal agencies, OMB finds that revisions are warranted to subtitle A of 2 CFR—including parts 1, 25, 170, 175, 180, 182, 183, 184, and 200—to further streamline, clarify, and update the guidance, including raising certain thresholds, where permissible under law, in recognition of inflation and other contributing factors. Further information on OMB's objectives for the revisions is provided below.

OMB Objectives
OMB's objectives for the current round of revisions to several parts of subtitle A of 2 CFR include: (1) incorporating statutory requirements and administration priorities; (2) reducing agency and recipient burden; (3) clarifying sections that recipients or agencies have interpreted in different ways; and (4) rewriting applicable sections in plain language, improving flow, and addressing inconsistent use of terms.
The revisions to the Uniform Guidance in part 200 and other parts of 2 CFR generally support these four objectives. In support of objective (1)—incorporating statutory requirements and administration priorities—OMB made changes throughout the Uniform Guidance and other parts of 2 CFR to ensure consistency with statutory authorities. For example, OMB revised Parts 25, 170, and 175 to ensure its guidance properly aligns with underlying statutes, as amended. These revisions further align OMB's guidance with the authorizing statutes to ensure proper implementation. OMB also made several structural changes to individual parts within Chapter I to provide further structural consistency throughout OMB's guidance in 2 CFR.
In support of objective (2)—reducing agency and recipient burden—OMB increased several monetary thresholds that have not been updated for many years. For example, OMB increased the single audit threshold from $750,000 to $1,000,000 and also increased the threshold for determining items that are considered to be equipment from $5,000 to $10,000. OMB reviewed previous increases to the thresholds and considered current economic data in making these determinations. In further support of reducing burden, OMB provided a complete revision to the template text for a Notice of Funding Opportunity (NOFO) located in Appendix I of the Uniform Guidance in part 200. With this revision, OMB intends to reduce administrative burden and unnecessary obstacles to applying for Federal financial assistance.
In support of objective (3)—clarifying sections that recipients or agencies have interpreted in different ways—OMB made revisions to 2 CFR to clarify areas of misinterpretation. Many of these clarifications do not represent a change in policy but are intended to eliminate ambiguity and clarify the intent of specific sections of the Uniform Guidance in part 200, and other parts in 2 CFR. In issuing its proposed revisions, OMB had incorporated feedback from Federal agencies and the public stating that Federal agencies and the recipient community interpret many sections inconsistently. After reviewing comments received in response to its proposed revisions, OMB is now implementing many of these changes.
In support of objective (4)—rewriting applicable sections in plain language, improving flow, and addressing inconsistent use of terms—OMB revised the guidance to better follow plain language principles. OMB focused on using simple words and phrases, avoiding jargon, using terms consistently, and being concise.
As a result, throughout subparts A through E of part 200, OMB now uses the terms “recipient,” “subrecipient,” or both in place of “non-Federal entity.” OMB found that using the term “non-Federal entity” in subparts A through E of the prior version of part 200 presented challenges to readers and made it difficult to quickly understand which entity was being addressed, especially in situations in which Federal agencies apply part 200 to Federal agencies, for-profit organizations, foreign public entities, or foreign organizations under 2 CFR 200.101. In the revisions to part 200, OMB now uses the term “non-Federal entity,” as defined in section 200.1, only when that entity is specifically intended, such as in subpart F implementing the Single Audit Act. In many cases in part 200, OMB replaced “non-Federal entity” with either “recipient and subrecipient” or “recipient or subrecipient.” In cases where the guidance in part 200 relates specifically to only either “recipients” or “subrecipients,” but not both, OMB refers specifically to the applicable entity.
Revisions in the final guidance relating to use of the terms “non-Federal entity,” “recipient,” and “subrecipient” do not change the existing scope or applicability of the guidance. The applicability provision for part 200, at section 200.101, continues to provide Federal agencies discretion on whether to apply subparts A through E of part 200 to Federal agencies, for-profit entities, foreign public entities, or foreign organizations. In the same section, the final guidance encourages Federal agencies to apply the requirements in subparts A to E of part 200 to all recipients in a consistent and equitable manner, but does not require them to do so. In cases in which Federal agencies apply part 200 to such entities, OMB's final guidance now further clarifies how the guidance applies to those entities as either recipients or subrecipients.
Another example of plain language revisions is replacing the use of the general term “OMB designated governmentwide systems” with more specific terms to reduce ambiguity for those unfamiliar with the Uniform Guidance. In the final guidance OMB now specifically mentions the appropriate system, such as SAM.gov, USASpending.gov, the Contractor Performance Assessment Reporting System (CPARS), or Grants.gov .
The overall goal of OMB's plain language revisions was to make the Uniform Guidance more accessible to the general public and ensure more equitable access to Federal funding opportunities by making the guidance easier to understand. OMB does not specifically discuss each plain language revision in this preamble unless a revision represents a material change to the Uniform Guidance or is otherwise connected to OMB's response to a public comment.

Statutory Authority for OMB Guidance for Grants and Agreements
The Director of OMB is authorized under 31 U.S.C. 6307 to “issue supplementary interpretative guidelines to promote consistent and efficient use of . . . grant agreements . . . and cooperative agreements.” The Deputy Director for Management of OMB is authorized under 31 U.S.C. 503 to, among other things, provide “overall direction and leadership to the executive branch on financial management matters by establishing financial management policies and requirements.” 31 U.S.C. 503(a)(2).
OMB also relies on authorities including the Single Audit Act Amendments of 1996 (Pub. L. 104-156, as amended, codified at 31 U.S.C. 7501-7507) (the Single Audit Act); the Federal Funding Accountability and Transparency Act of 2006 (FFATA or the Transparency Act) ^1 (Pub. L. 109-282), as amended (31 U.S.C. 6101 note); the Digital Accountability and Transparency Act of 2014 (DATA Act of 2014) (Pub. L. 113-101), as amended; the Federal Program Information Act (Pub. L. 95-220 and Pub. L. 98-169, as amended, codified at 31 U.S.C. 6101-6106); the Federal Grant and Cooperative Agreement Act of 1977 (Pub. L. 95-224, as amended, codified at 31 U.S.C. 6301-6309); the Office of Federal Procurement Policy Act (codified at 41 U.S.C. 1101-1131); the Budget and Accounting Procedures Act of 1950, as amended (codified at 31 U.S.C. 1101-1126); the Chief Financial Officers Act of 1990 (codified at 31 U.S.C. 503-504); the Trafficking Victims Protection Act of 2000 (TVPA), as amended (codified at 22 U.S.C. 7101-7115); and Executive Order 11541, “Prescribing the Duties of the Office of Management and Budget and the Domestic Policy Council in the Executive Office of the President.”
^1 All references to FFATA or the Transparency Act in this document refer to the Act as most recently amended by the Congressional Budget Justification Transparency Act of 2021 (Pub. L. 117-40).

Summary of Comments
On October 5, 2023, OMB solicited feedback from the public through proposed guidance published in the Federal Register . See 88 FR 69390 (Oct. 5, 2023). The period for public comments closed on December 4, 2023. OMB received comments via Regulations.gov at Docket No. OMB-2023-0017. OMB received approximately 829 public comments from a broad range of interested stakeholders, such as States, local governments, Indian Tribes, labor organizations, industry associations, nonprofit organizations, for-profit organizations, colleges, universities, and individuals.

Section-by-Section Discussion
OMB developed the revisions for this final guidance following review and consideration of comments received on the notification of proposed guidance published in October 2023. In this document, OMB summarizes significant comments received in response to its proposal and substantive changes made to each section of the final guidance. Generally, minor changes to the language of the guidance—such as minor plain language revisions—are not discussed. Sections of the guidance that OMB did not propose to revise in significant ways are also not discussed in many cases, except in response to commenters. For sections where no substantive changes or comments are discussed, the guidance from the notification of proposed guidance was adopted.

2 CFR Subtitle A—General
In the proposed guidance, OMB proposed revising the headings of: (i) title 2 of CFR; (ii) subtitle A of 2 CFR; and (iii) chapter I of subtitle A of 2 CFR. In the case of each heading, OMB proposed to replace “Grants and Agreements” with “Federal Financial Assistance.” OMB explained that this revision would help to ensure that 2 CFR is understood to be applicable beyond just grants and cooperative agreements—unless provided otherwise in the applicability provisions in the body of the guidance, such as section 200.101.
OMB received one comment questioning the proposal to revise the headings. The commenter stated that the reference to grants in the original heading was important to preserve the distinction between grants and contracts. OMB also received several comments supporting the revised headings. One commenter also questioned the inconsistent use of “government-wide” versus “governmentwide.”
OMB Response: OMB finds that revising the headings to reference “Federal financial assistance” will not cause undue confusion or change the specific applicability of parts and sections of the guidance. The headings merely reflect the overall scope of 2 CFR. The specific applicability of parts and sections of the guidance is addressed within the body of the guidance, such as at 2 CFR 200.101. OMB made several revisions in the final guidance to change “governmentwide” to “government-wide” for consistency.

Part 1—About Title 2 of The Code of Federal Regulations and Subtitle A

Section 1.200—Purpose of Chapters I and II
OMB proposed to revise section 1.200 to remove paragraphs (b) and (c), which are no longer accurate. When OMB first established part 1 in 2004, see 69 FR 26276 (May, 11, 2004), it implemented the Federal Financial Assistance Management Improvement Act of 1999 (Pub. L. 106-107). That legislation ceased to be effective on November 20, 2007 based on a sunset date included in the law. In addition, chapter II of subtitle A in 2 CFR, which now contains part 200, was initially intended to contain OMB guidance in its “initial form” before it was “finalized.” That statement no longer accurately reflects the structure of subtitle A of 2 CFR nor the status of the OMB guidance in part 200. OMB did not receive significant comments on this section and included the proposed revisions in the final version.

Section 1.205—Applicability to Federal Financial Assistance
OMB did not propose significant revisions to section 1.205. OMB received two comments indicating that paragraph (b) contained an error regarding applicability to procurements under Federal awards. OMB also received one comment inquiring if section 1.205 means that agencies using Other Transaction Authority (OTA) instruments are permitted to make an award to a de-barred or suspended entity.
OMB Response: In the final guidance, OMB removed both paragraphs (a) and (b) from section 1.205. The applicability of specific parts and sections of the guidance are best addressed in the relevant areas of the guidance—such as in Part 180 and at 200.101. Paragraphs (a) and (b) only provided a partial list of examples of the applicability of specific parts of 2 CFR. OMB finds that the remaining text in the introductory paragraph sufficiently addresses the topic of applicability overall, with more specific information provided in relevant parts and sections. The two examples in this section are not necessary.
The guidance in part 200 does not specifically address OTA instruments. Federal agencies using such authority are in the best position to answer questions and provide guidance on what specific requirements apply to OTA instruments—and under what circumstances any parts, subparts, or sections of 2 CFR may apply. The commenter seeking information on the applicability of 2 CFR part 180 to OTA instruments may also consider the definition of “nonprocurment transaction” at 2 CFR 180.970.

Section 1.215—Relationship to Previous Issuances
OMB proposed to provide a more succinct statement in section 1.215 explaining that some of the guidance was organized differently within previous OMB Circulars or other guidance documents, before the establishment of title 2 of the CFR. Because 2 CFR has now existed for almost 20 years in its current format and location, OMB did not find it necessary to continue to include the table showing earlier sources of certain elements of the OMB guidance in 2 CFR. The Federal Register notice establishing 2 CFR in 2004, see 69 FR 26276 (May, 11, 2004), and other subsequent Federal Register notices establishing and revising particular parts and provisions of subtitle A in 2 CFR, include that information. For example, the Federal Register notice establishing part 200 in 2013 explained that it superseded and streamlined requirements from OMB Circulars A-21, A-87, A-110, and A-122; Circulars A-89, A-102, and A-133; and the guidance in Circular A-50 on Single Audit Act follow-up. See 78 FR 78590 (Dec. 26, 2013). OMB did not receive significant comments on this section and incorporated the proposed revisions.

Section—1.220 Federal Agency Implementation of This Subtitle
OMB did not propose significant revisions to section 1.220. OMB received one comment seeking clarification on the implementation of the 2 CFR revisions by Federal agencies, particularly in situations when a Federal agency has not specifically referenced the OMB 2 CFR guidance in the terms and conditions of a Federal award.
OMB Response: OMB did not make substantial changes to the long-standing structure of agency implementation of OMB's 2 CFR guidance. OMB did not find it necessary to make additional revisions, but is issuing a memorandum to Federal agencies with implementation guidance concurrently with this document. OMB also provides some additional responsive information in other parts of the guidance text and within this preamble. In the case of individual Federal awards, the Federal agency making the award is the best source of information on agency implementation of 2 CFR and applicable agency regulations and requirements. Federal agencies are responsible for implementing the guidance for their Federal awards. The government-wide effective date of the final guidance is October 1, 2024, but Federal agencies may also elect to apply the final guidance to their Federal awards issued prior to October 1, 2024. For agencies applying the final guidance before October 1, 2024, the effective date must be no earlier than 60 days from the date of publication in the Federal Register —as specified above.

Section 1.231—Severability
OMB proposed to add section 1.231 to clarify its intent that if any provision of the final guidance were held to be invalid or unenforceable, such provision, or combination of provisions, are severable from the remaining provisions of the guidance. OMB did not receive significant comments on this section and made the change in the final guidance. OMB made a minor revision to replace the word “part” with “subtitle” in the final sentence of this section, which is consistent with other language in this section as both proposed and finalized. This change reflects how OMB intends this provision to apply.
In the final guidance provided through this document, OMB adopts a unified scheme addressing how Federal agencies will consistently and efficiently use Federal financial assistance in their programs across the Federal government. While the final guidance best serves OMB's objectives if left intact as adopted by OMB, the benefits of the guidance related to coordination across the Federal government do not hinge on any single provision. Accordingly, OMB considers individual provisions adopted in the final guidance to be separate and severable from one another. In the event of a stay or invalidation of any provision, or any provision as it applies to a particular person or circumstance, OMB's intent is to otherwise preserve the final guidance to the fullest possible extent. The provisions that remain in effect will continue to provide essential guidance and information to Federal agencies on consistently applying requirements for Federal financial assistance across the Federal government.

Section 1.300—OMB Responsibilities
OMB did not propose significant revisions to section 1.300. OMB received a comment requesting that OMB establish a policy and process for pass-through entities to submit questions to OMB. Another comment requested additional technical assistance in support of Federal financial assistance.
OMB Response: Pass-through entities should direct all comments and questions pertaining to the implementation of specific Federal awards to the appropriate Federal agency making the award. Federal agencies are the best resource for questions related to specific Federal awards.

Section 1.305—Federal Agency Responsibilities
OMB proposed to revise section 1.305 to further clarify Federal agency responsibilities, such as coordinating with the Council on Federal Financial Assistance (see OMB Memorandum M-23-19), the Grants Quality Service Management Office (QSMO), and other governance committees.
OMB received one comment expressing support for the proposed revisions, such as including reference to the QSMO. OMB received another comment suggesting OMB require Federal agencies to report on subawards under their Federal awards. Another commenter recommended the inclusion of additional language with respect to tribal sovereignty and self-determination in this section.
OMB Response: In response to comments, the pass-through entity, not the Federal agency, is responsible for subaward reporting. See 2 CFR part 170, appendix A. OMB does not consider section 1.305, on Federal agency responsibilities, to be an appropriate place to address issues related to tribal sovereignty. Guidance related to tribal rights is included in other sections of the 2 CFR guidance such as section 200.101(d). OMB incorporated the proposed revisions in this section without additional changes.

Part 25—Unique Entity Identifier and System for Award Management
Part 25 of 2 CFR provides guidance on requirements for applicants, recipients, and subrecipients to obtain a unique entity identifier (UEI), as required by statute in the Transparency Act, and for applicants and recipients to register in the System for Award Management ( SAM.gov ) website of the General Services Administration, which is the repository for standard information about applicants and recipients of Federal awards. OMB proposed to revise part 25 to ensure it properly aligns with the authorizing statutes, as amended, including the Transparency Act and the DATA Act of 2014. OMB also proposed to revise the title of part 25 to replace “universal identifier” with “unique entity identifier.” OMB received no significant comments on these proposals. OMB incorporated these changes in the final guidance.

Part 25—General Comments
OMB received several general comments on 2 CFR part 25 that did not apply to a specific section. One commenter recommended that the U.S. government develop a national strategy on the use of persistent identifiers (PIDs) to articulate how they can be leveraged in the U.S. research ecosystem and globally to support American science leadership. Another commenter remarked that clarification is needed under part 25 that pass-through entities and others should not require a UEI of second-tier contractors. Another commenter asked OMB to remove barriers to access for newer and smaller organizations for low-dollar subawards, such as by removing UEI requirements.
OMB Response: The suggestion to develop a national strategy on the use of PIDs is beyond the scope of OMB's proposed revisions. Section 25.300 requires a UEI for first-tier subrecipients receiving a subaward from a recipient, as defined at section 25.400, but does not impose a requirement for a second-tier subrecipient to obtain a UEI before receiving a subaward from a subrecipient. OMB finds that additional clarification is not needed within the text of the guidance on this point.
On the final comment regarding removing additional barriers for newer and smaller organizations: statutory requirements under the Transparency Act and other laws put firm limits on OMB's ability to provide additional flexibility. The exceptions provided in section 25.110 generally reflect the flexibilities permitted under controlling statutory law.

Subpart A—General

Section 25.100—Purposes of This Part
OMB proposed only minor plain language revisions to section 25.100. One commenter asked OMB to align the terminology used to describe “direct” subawards in 2 CFR part 25 with the “first-tier” subaward terminology used in 2 CFR part 170 Appendix A. Specifically, the commenter asked OMB to amend this section by replacing “direct subrecipients” with “first-tier subrecipients.” The commenter also asked OMB to change the reference to “subawards” at section 170.100 to “first-tier subawards.”
OMB Response: In response to comments, OMB added first-tier subrecipients in a parenthetical following direct subrecipients. OMB otherwise made changes in this section as proposed.

Section 25.105—Applicability
In this section OMB proposed to clarify that the requirement to obtain a UEI does not apply to second-tier subrecipients or contractors. OMB also proposed to clarify that recipients of loan guarantees must obtain a UEI and register in SAM.gov. OMB also proposed to state that a Federal agency may use discretion when determining to apply the requirements to beneficiary borrowers.
In response to OMB's proposed changes, some commenters expressed concern that not requiring second-tier subrecipients to obtain a UEI could potentially put certain recipients at risk because those recipients have ultimate responsibility for monitoring all subrecipients. Some commenters stated that obtaining a UEI should be a universal requirement for subrecipients at any tier. OMB also received multiple comments expressing concern that the new proposed language, while exempting second-tier subrecipients from obtaining an UEI, did not address audit requirements, which a commenter stated may require subrecipients to have a UEI for submission. Other commenters also asked OMB to further clarify language in this section.
OMB Response: In response to comments asking OMB to make obtaining a UEI a universal requirement for all tiers of subrecipients, OMB disagrees and did not make a change. The requirements for obtaining a UEI do not flow down beyond the first-tier subawards of a Federal award. This is consistent with prior OMB guidance on this topic in the “2 CFR Frequently Asked Questions” (2 CFR FAQ) published on May 3, 2021.
In response to the comment regarding audit requirements: OMB is not requiring second-tier subrecipients to obtain a UEI under this section of the final guidance, but if a UEI is needed or likely to be needed for other purposes, second-tier subrecipients may still obtain one. If second-tier subrecipients are likely to need a UEI for other purposes, it would be best to obtain a UEI at the very start of the Federal award process. It may be infeasible to retroactively apply a UEI to awards made prior to obtaining one. After consideration of other comments requesting further clarification in this section, OMB did not make additional changes. OMB finds that this section, as revised, is sufficiently clear.

Section 25.110—Exceptions to This Part
In section 25.110, OMB proposed to clarify that, even if an exception is granted, a Federal agency remains responsible for reporting data to comply with the Transparency Act, except that it may use a generic entity identifier in the circumstances described.
Although not included in the text of the proposed revisions, OMB also stated in the preamble that it was considering other ways of reducing the administrative burden associated with obtaining a UEI and registering in SAM.gov for foreign organizations or foreign public entities. OMB described two potential revisions allowing expanded exceptions for these entities. The first expanded exception would have allowed an agency to grant a one-time exception from the requirement to obtain a UEI, register in SAM.gov, or both for foreign organizations or foreign public entities applying for or receiving an award between $25,000 and $250,000 for a project or program performed outside the U.S. This would have increased the threshold in use under the prior version of the guidance for this exception. The second exception would have expanded the existing exigent circumstances exception to provide recipients with additional time to obtain a UEI and complete SAM.gov registration if exigent circumstances persisted beyond 30 days. Specifically, OMB proposed to allow Federal agencies with the option to provide recipients an additional 90 days if exigent circumstances persisted. For both proposed exceptions, the preamble explained that the exceptions would only be finalized in a way that would allow agencies to continue following Transparency Act reporting requirements.
OMB received many comments in response to the proposed changes in this section. One commenter simply noted that the process to obtain a UEI number and maintain active SAM.gov registration is excessively complicated. Another commenter recommended that OMB grant Federal agencies the authority to exempt subrecipients from the requirement to obtain a UEI under this section. Another commenter requested OMB to allow recipients, rather than the Federal agencies, to make determinations on providing exceptions for subrecipients. Other commenters noted that obtaining a UEI and registering in SAM.gov are major barriers for many foreign entities.
OMB also received many comments supporting the modified exceptions for obtaining a UEI and registering in SAM.gov described in the preamble to the proposed guidance. In general, commenters were supportive of both the modified exception that would have allowed a higher threshold of $250,000 for a project or program performed outside the U.S., and the proposed expansion of the “exigent circumstances” exception, which would have allowed recipients additional time beyond 30 days.
Commenters also provided many alternative suggestions related to raising the threshold for an exception above $25,000. For example, some commenters requested clarification on why a threshold of $25,000 is established in this section while a threshold of $30,000 is used in 2 CFR part 170 for reporting subawards. Some commenters suggested using a threshold of $30,000 for subawards in both parts for consistency. Many commenters also requested a blanket or class exemption to the UEI requirement for all entities receiving an award or subaward valued under a specified amount, with many citing $30,000 as the appropriate amount. Other commenters suggested increasing the threshold for subawards to $50,000, which they stated was the applicable threshold for subawards in certain programs under the American Rescue Plan Act of 2021 (Pub. L. 117-2).
Other commenters also requested a variety of minor clarifications and revisions to this section. For example, one commenter requested a citation be changed from “25.110(a)(2)(ii)(A)(5)” to “25.110(a)(2)(ii)(A)(4).” Another commenter requested certain language to be further clarified in paragraph (a)(1)(i). A different commenter suggested adding “by section 6202 of Public Law 110-252” after “as amended” in paragraph (a)(1)(i) to provide more information to readers. One commenter requested clarification that the requirement to obtain a UEI does not apply to contractors that have a procurement relationship with a recipient.
Lastly, a commenter asked for a complete exception from obtaining a UEI for all foreign organizations or foreign public entities applying for or receiving a subaward below the Transparency Act threshold of $25,000 for a project or program performed outside the U.S. The commenter explained that establishing a SAM.gov user account and requesting a UEI is often extremely challenging for small foreign organizations with limited internet access or limited English proficiency.
OMB Response: In response to these comments, OMB policy on this topic is constrained by the Transparency Act, which limits what exceptions and deviations OMB can allow regarding the requirement to obtain a UEI and the timeframe in which a UEI must be obtained. In the final guidance, OMB allowed exceptions only within the parameters permitted under the statute.
Within these statutory limits, OMB made some adjustments to the proposed guidance in this section. First, OMB agrees with the comment asking OMB to allow Federal agencies to exempt subrecipients from the requirement to obtain a UEI in the circumstances described in paragraph (a)(2). Recognizing that OMB already refers to subawards in the proposed text at paragraph (a)(2)(ii), OMB made this revision to the introductory paragraph. The exceptions in this section are based on the statutory exceptions and other limited flexibilities under the Transparency Act, which generally applies in similar ways to awards and subawards.
Regarding the request to allow recipients rather than Federal agencies to make determinations on granting exceptions under this section, OMB did not make this change. OMB finds that Federal agencies are able to apply a risk-based approach more consistently across their programs when evaluating exceptions.
In response to comments requesting clarification on why a threshold of $25,000 is used in this section for obtaining a UEI, while a threshold of $30,000 is used in part 170 for reporting subawards, OMB previously increased the reporting threshold for subawards under part 170 to $30,000 based on the pilot authority in section 5(b) of the Transparency Act, as amended by the Data Act of 2014. See Public Law 113-101; see also 85 FR 49506 (Aug. 13, 2020); 2 CFR 170.220. However, when OMB used that limited pilot authority in 2020 to revise part 170, it did not alter the separate requirement for subrecipients to obtain a UEI under section 25.300. The part 25 UEI requirement continues to use the baseline threshold for a Federal award from the Transparency Act of $25,000. The pilot authority used in part 170 is no longer active and OMB did not identify alternative statutory authority that would allow increasing the threshold above $25,000 in part 25 in the final guidance. Thus, subrecipients receiving subawards of $25,000 or more must continue to obtain a UEI before receiving an award.
In response to the many comments about UEI and SAM.gov registration being a barrier to foreign organizations and foreign public entities, OMB cannot allow all of the requested exceptions related to UEIs. OMB must ensure that part 25 remains aligned with statutory requirements in the Transparency Act, which place limits on what exceptions are allowable. Section 2(b) of the Transparency Act requires a unique identifier or UEI for any entity receiving a Federal award above $25,000. To comply with Section 2(c) of the Transparency Act, the UEI must be obtained, at the latest, within 30 days of the Federal award. Thus, the final guidance does not allow expanded UEI exceptions for foreign organizations beyond those that appeared in the text of the proposed guidance in October 2023. OMB did not finalize either of the expanded exceptions described in the preamble to the proposed guidance because OMB has not found a way for the exceptions to be implemented consistently with the Transparency Act. The Federal award threshold in paragraph (a)(2)(ii) remains $25,000 and OMB does not expand the “exigent circumstances” exception to provide recipients additional time beyond 30 days. The “exigent circumstances” exception was paragraph (a)(2)(iii) in the proposed guidance and is now paragraph (a)(2)(iv) in the final guidance.
OMB also did not provide a complete exception from obtaining a UEI for all foreign organizations or foreign public entities applying for or receiving a subaward below the Transparency Act threshold of $25,000 for a project or program performed outside the U.S. OMB maintains the existing level of transparency for this class of Federal awards and disagrees with the commenter's suggestion. Federal agencies are provided flexibility in this section to provide UEI exceptions for these organizations in specifically defined circumstances.
For SAM.gov registration only, which is not specifically required by the Transparency Act, OMB provided an expanded exception applicable to foreign organizations and foreign public entities in the final guidance at paragraph (a)(2)(iii). This new exception provides that, for applicants or recipients, the Federal agency may exempt foreign organizations or foreign public entities from completing full registration in SAM.gov for a Federal award less than $500,000 that will be performed outside the U.S. Similar to the exception at paragraph (a)(2)(ii), this exception may be used when the Federal agency deems it impractical for the entity to comply with the requirement for completing full registration in SAM.gov . Foreign organizations or foreign public entities exempted from registering in SAM.gov under this provision must still obtain a UEI. In addition, Federal agencies remain responsible for reporting under the Transparency Act in connection with the award. The Federal agency must determine this exemption on a case-by-case basis while utilizing a risk-based approach. Only OMB has authority to provide class exceptions under part 25. See 2 CFR 25.110(b) (as revised). To help ensure continued alignment with the Clean Contracting Act of 2008 (codified at 41 U.S.C. 2313), OMB uses a threshold of $500,000 for this exception. This exception narrows the exception proposed by OMB in the October 2023 preamble to only include SAM.gov registration, but increases the maximum threshold from $250,000 as initially proposed.
Regarding comments requesting that OMB allow UEI exceptions granted under part 25 to apply to subaward reporting requirements under part 170: the fact that a subrecipient is not required to obtain a UEI under part 25, does not necessarily affect reporting requirements under part 170, except that section 25.110 may allow use of a generic identifier for that reporting in certain circumstances. The ability to report using a generic identifier does not mean that reporting is not required. Specifically, section 25.110(a)(i) explains that if a Federal agency grants an exception, the Federal agency must use a generic entity identifier in the data it reports to USAspending.gov if reporting is required by the Transparency Act. The same principle would apply to required subaward reporting in circumstances in which an exception is granted to a subrecipient. Granting an exception under part 25 does not impact responsibility for reporting under the Transparency Act, except that a generic entity identifier may be used in the circumstances described.
The Transparency Act, at section 7 (Classified and Protected Information), provides that the Act does not “require the disclosure to the public” of information that would be exempt from disclosure under the Freedom of Information Act (codified at 5 U.S.C. 552) or protected under the Privacy Act (codified at 5 U.S.C. 552a) or section 6103 of the Internal Revenue Code of 1986 (codified at 26 U.S.C. 6103). See 31 U.S.C. 6101, statutory note. In cases of direct conflict between OMB's guidance and section 7 of the Transparency Act, the statutory text in the Transparency Act would prevail. See, for example, 2 CFR 25.105(a) and 170.105(a).
OMB did not find it necessary to explicitly state in part 25 that contractors with a procurement relationship with a recipient are not required to obtain UEI. The applicability section at 25.105 explains what entities must obtain a UEI. See also 2 CFR 25.200(b) and 25.300.
OMB accepted the suggestion to renumber paragraph (a)(2)(ii)(A)(5) as paragraph (a)(2)(ii)(A)(4). OMB made minor clarifying edits in paragraph (a)(1)(i). OMB did not find it necessary to specify which act amended the Transparency Act, which has been amended multiple times. Lastly, OMB renumbered paragraphs in this section based on the addition of a new exception at paragraph (a)(2)(iii) as discussed above. Except as noted, OMB otherwise included revisions in this section as proposed.

Subpart B—Policy

Section 25.200—Requirements for Notice of Funding Opportunities, Regulations, and Application Instructions
OMB did not propose significant updates to section 25.200. OMB rearranged some language to provide clarity and made plain language revisions. OMB received a comment requesting clarification on whether the requirement that a recipient be registered in SAM.gov prior to application is passed through to sub-recipients. This commenter also stated that sub-recipients need to register in SAM.gov to allow States and territories to complete reporting for Transparency Act purposes. Another commenter asked OMB to provide guidance that low-risk auditees only need to update their SAM.gov registrations once every three years, instead of annually, unless there is a material change that causes the auditee's SAM.gov registration to become outdated or otherwise inaccurate.
OMB also received comments requesting other minor clarifying edits in paragraph (c), which caused confusion for some commenters as initially proposed by OMB. For example, OMB received a recommendation to delete the first sentence of paragraph (c) and strike certain language from the second sentence.
OMB Response: Regarding comments requesting clarification on applicability to subrecipients, OMB finds that revisions are not needed in the guidance text. As a subrecipient does not directly apply to a Federal agency for an award, it is sufficiently clear that this provision is not addressing subrecipients. A subrecipient must only provide a UEI to the recipient in accordance with subpart C. Next, OMB does not agree with the comment stating that updating SAM.gov registration on an annual basis presents excessive burden and made no change to this policy. Finally, OMB agrees with commenters that paragraph (c) should be clarified. OMB made minor edits in the guidance text to clarify intent.

Section 25.205—Effect of Noncompliance With a Requirement To Obtain a UEI or Register in SAM.gov
OMB made plain language revisions and minor clarifications to this section in the proposed guidance. Specifically, OMB explained that the requirement to have an active UEI does not apply to amendments to terminate or close a Federal award. OMB received a comment requesting clarification on whether the annual SAM.gov registration requirement is through project closeout or the record retention period.
OMB Response: OMB finds that additional clarification is not needed in the guidance text. Section 25.200 explains that the registration requirement applies while a Federal award is “active” or “an application [is] under consideration by a Federal agency.” OMB added clarifying language unrelated to the comment received, but otherwise made revisions in the final guidance as proposed.

Section 25.215—Requirements for Agency Information Systems
OMB made plain language revisions to this section and updated citations to other 2 CFR sections. OMB received a comment recommending that OMB and Federal agencies ensure that the UEI required by part 25 can be linked with global registries for PIDs.
OMB Response: OMB did not link UEIs with PIDs at this time. To do so would go beyond the scope of the changes proposed and is not necessary for this update.

Subpart C—Recipient Requirements of Subrecipients

Section 25.300—Requirement for Recipients To Ensure Subrecipients Have a Unique Entity Identifier
OMB made plain language revisions to this section in the proposed guidance. OMB received several comments on section 25.300. First, a commenter requested OMB define “full registration” in paragraph (a), stating that there is confusion over levels of registration. Next, OMB received multiple comments on the notification requirement in paragraph (b) and Appendix A. For example, one commenter stated that the requirement that recipients must notify any potential subrecipients that the recipient cannot make a subaward unless the subrecipient obtains and provides a UEI to the recipient, is unnecessary given the requirements of paragraph (a). The commenter stated this requirement imposed an unnecessary administrative burden on recipients. OMB also received a comment stating that paragraph (b) is unclear regarding whether this notification requirement applies during both the pre-award and post-award phases and to whom the notification should be provided in each case.
OMB Response: On the comment regarding defining “full registration” in paragraph (a), OMB did not find it necessary to further define this term in this update. With the exception of minor plain language revisions, this section remains similar to guidance as it existed before this update and OMB finds the meaning is sufficiently clear. The paragraph explains that subrecipients must obtain a UEI prior to receiving a subaward, but are not required to register in SAM.gov. Similarly, on the comments regarding the notification requirement in paragraph (b), this section remains similar to guidance as it existed before this update. OMB did not find it unclear or overly burdensome.

Subpart D—Definitions

Section 25.400—Definitions
In the proposed October 2023 revisions, OMB combined definitions from multiple sections within a single section at 25.400. OMB provided a definition for entity, updated and removed several other definitions, and made additional clarifying and plain language edits. Many of the revisions to this section aimed to more closely follow statutory language in the Transparency Act. OMB received comments requesting clarification on the definitions of “entity” and “Federal financial assistance.” For the definition of entity, commenters specifically raised questions about the applicability of the definition to tribes, consortium organizations, and individual recipients of Federal financial assistance. Another commenter asked OMB to add a definition for “internal recipient” for situations where a government recipient, such as a State, passes funds to another agency within the government recipient. OMB also received questions asking about this section's applicability to fixed award amounts and OTA instruments. Finally, a commenter suggested that OMB consider combining the definition sections for parts 25 and part 200.
OMB Response: OMB made minor revisions to the definition of the term “entity” to more closely align with the statutory definition in the Transparency Act. Specifically, at paragraph (1)(x), OMB added “any subcontractor or subgrantee that is not excluded by paragraph (2).” Section 2 of the Transparency Act provides that this element of the definition applies on and after January 1, 2009. Other guidance in part 25 provides more specific information on which entities must obtain UEIs or register in SAM.gov in the context of this part, including the provisions at sections 25.105, 25.200(b), and 25.300. OMB also made minor technical edits to the definition of the term “entity” in the final guidance.
OMB did not add a definition for the term “internal recipient.” This is beyond the scope of OMB's proposed changes for this version of the guidance, but Federal agencies may be able to provide further guidance on this question in the context of specific awards if appropriate. On the question about applicability to fixed amounts awards: a fixed amount award is a form of Federal financial assistance and subject to this part.
OMB did not combine the definitions from section 25.400 and section 200.1. Some of the definitions in section 25.400 are specifically tailored to align with the Transparency Act, while some definitions in part 200 have a broader range of applications. Regarding the definition of Federal financial assistance, OMB did not find it necessary to explicitly address whether section 25.400 applies to OTA instruments. As discussed above, Federal agencies using such authority are in the best position to answer questions and provide guidance on what specific requirements apply to OTA instruments used by that agency—including to address whether part 25 applies to them. OTA instruments, and the authorities for such instruments, provide for unique flexibilities that might not be the same across all Federal agencies.

Appendix A to Part 25—Award Term
OMB proposed plain language revisions and minor clarifying edits to Appendix A to Part 25. Multiple commenters questioned OMB's usage of second-person pronouns (“you”) and second-person possessive adjectives (“your”) in the Appendix.
OMB Response: OMB agrees with the commenters that further clarifying edits should be made to Appendix A. Because “you” and “your” generally referred to the award recipient in the proposed Appendix, OMB now uses the term “recipient” in place of both. OMB also made other conforming edits as necessary in the final guidance. OMB is also correcting a citation for the definition of entity.

Part 170—Reporting Subaward and Executive Compensation Information
In the proposed revisions, OMB proposed to revise the guidance in this part to ensure it properly aligns with authorizing statutes including the Transparency Act and the DATA Act of 2014. OMB proposed to clarify the specific Federal agency reporting requirements and to revise the award term to resolve issues related to which entities the award term applies to. OMB also proposed to revise certain sections to clarify their intended meaning. For example, OMB proposed to move certain requirements currently contained in section 170.110 to section 170.105, which OMB proposed to rename “Applicability.”

Part 170—General Comments
OMB received multiple comments on this part that did not focus on a particular section. First, OMB received comments stating that reporting requirements should be clarified to distinguish between reporting the amount obligated by a single award, which was referred to as an “action” in Appendix A, and the new total obligated amount. Second, another commenter noted certain difficulties encountered with the FFATA Subaward Reporting System (FSRS).
OMB Response: Regarding the first comment, OMB added language in Appendix A to clarify that the total subaward amount under a Federal award must be reported for all reported subawards. Regarding the second comment, OMB can only update policy on reporting requirements in this part. OMB did not propose changes to FSRS through this update. This guidance is not the appropriate vehicle to address system challenges with FSRS or make changes to that system.

Subpart A—General

Section 170.100—Purpose of This Part
OMB proposed plain language revisions and minor technical edits to this section. OMB did not receive any significant comments. In the final guidance, OMB made a minor technical edit, but otherwise updated the guidance as proposed.

Section 170.105—Applicability
OMB proposed to move certain requirements contained in section 170.110 to section 170.105, which OMB proposed to rename “Applicability.” OMB also proposed plain language revisions and other clarifying edits. OMB further updated citations to other sections within the 2 CFR guidance.
OMB received multiple comments requesting that the guidance explicitly allow exceptions to the UEI requirement granted under 2 CFR part 25 to apply to first-tier subaward reporting requirements under 2 CFR part 170. The commenters stated that any exception to the requirement for a subrecipient to obtain a UEI under part 25 should equate to an exception to report under part 170. Similarly, OMB received a comment requesting the addition of an exception in 2 CFR part 25 for awards and subawards less than $30,000, which would align with the threshold for first-tier subaward reporting under 2 CFR part 170.
OMB Response: Regarding comments requesting OMB to allow UEI exceptions granted under part 25 to apply to subaward reporting requirements under part 170: OMB's response is provided in the section of the preamble on part 25 above. In general, the fact that a recipient or subrecipient is not required to obtain a UEI under part 25 does not necessarily affect reporting requirements under part 170, except that generic identifiers may be used in defined circumstances. Certain disclosure exceptions may also be available under the statutory text of the Transparency Act, which are discussed above. See 31 U.S.C. 6101, statutory note. In cases of direct conflict between OMB's guidance and section 7 of the Transparency Act, the statutory text would prevail. Paragraph (a) of section 170.105 recognizes that such statutory exemptions for subaward reporting may be available in some circumstances. For example, when information is formally classified under criteria established by an Executive Order, 5 U.S.C. 552(b)(1), the statutory authority in section 7 of the Transparency Act would warrant withholding publication of information under part 170.
Regarding comments requesting that OMB create an exception in part 25 for awards and subawards less than $30,000, see discussion in this preamble above. OMB did not identify statutory authority that would allow increasing the threshold above $25,000 in part 25 in the final guidance.

Subpart B—Policy

Section 170.200—Federal Agency Reporting Requirements
OMB proposed plain language revisions to this section and other clarifying edits. OMB did not receive any comments on this section. In the final guidance, OMB updated the prior reference to the DATA Act Information Model Schema (DAIMS). The revised reference is to the Government-wide Spending Data Model (GSDM).

Section 170.210—Requirements for Notices of Funding Opportunities, Regulations, and Application Instructions
OMB proposed plain language revisions to this section and added a definition for “notice of funding opportunity.” OMB did not receive any comments on this section and revised the guidance as proposed.

Section 170.220—Use of Award Term
OMB proposed plain language revisions to this section and added certain clarifying language. A commenter suggested that it would be helpful to insert an example to illustrate the revised language in this subsection.
OMB Response: OMB made changes to clarify that the total subaward amount must be reported. OMB otherwise revised the guidance as proposed.

Subpart C—Definitions

Section 170.300—Definitions
In the proposed October 2023 revisions, OMB combined definitions from multiple sections within a single section at 170.300. OMB also proposed plain language revisions within this section, added the definition of entity, and updated or removed other definitions from the prior version of the guidance. OMB received a comment that the CFR citation in the definition for “Total Compensation” was incorrect.
OMB Response: OMB corrected the citation in the definition for “Total Compensation.” OMB otherwise revised the guidance in this section as proposed.

Appendix A to Part 170—Award Term
In Appendix A to Part 170, OMB proposed changes including reordering text, revising for plain language, removing definitions or citing to relevant 2 CFR sections, and adding the definition of entity. OMB received multiple comments on the Appendix. One commenter requested that OMB provide clear guidance on certain inconsistencies the commenter perceived between the FSRS system and USAspending.gov. Another commenter suggested that rather than subrecipients reporting executive compensation to and through the pass-through entity, when applicable, the subrecipient report this data directly into FSRS.
Another commenter noted this Appendix requires reporting executive total compensation of first-tier subrecipients unless the subrecipient is exempt as provided in Section I, paragraph (d). The commenter stated that this exemption—using a threshold of $300,000 in gross income—is not necessary because a higher threshold is established elsewhere in the Appendix. Specifically, the commenter pointed to Section I, paragraph (c)(1)(ii)(B), which uses a threshold of $25,000,000 or more in annual gross revenues in the subrecipient's preceding fiscal year. The commenter further noted Section I, paragraph (d), addresses the reader directly as “you,” which is inconsistent with paragraphs (b) and (c) being applicable to both recipients and subrecipients. Lastly, this commenter suggested that in Section I, paragraph (d), if OMB continues to apply the exemption to subrecipients, it should modify the language to clarify that it applies to both recipients and first-tier subrecipients.
Next, another commenter suggested adding an example to the Appendix for clarity. A commenter also requested clarification on what specific action triggers the requirement for Transparency Act subaward reporting, which requires the recipient to report a subaward action. OMB received another comment requesting a clearer definition of subaward to recognize different reporting timeframes. An additional commenter suggested that there is a lack of clarity about the amount of time recipients have to report a subrecipient's compensation information to FSRS and stated that this may lead to recipients issuing unsigned subawards.
One commenter requested further clarification in Section I, paragraph (d), noting that the proposed language appeared to indicate that the prime recipient and the first-tier subrecipient are exempt from reporting executive compensation if their gross income from all sources is under $300,000. However, the commenter noted that paragraph (d) is referring to the reporting of subawards and executive compensation.
OMB also received a question on the significance of the changes regarding reporting subawards. The commenter noted that the current version of the Award Term required reporting “each obligating action” or “obligation” that equals or exceeds $30,000, while the proposed Award Term deleted those words and substituted “subaward” in their place.
OMB Response: Throughout Appendix A, in the final guidance OMB replaces “you” and “your” with references to the “recipient” to which the award term is addressed. OMB also made other conforming edits as necessary throughout Appendix A.
OMB also made certain clarifying edits in Section I, paragraph (d) of Appendix A in response to comments. Consistent with the rest of the Appendix, OMB clarifies that “you” refers to the recipient. Consistent with the Transparency Act, OMB also clarified that the relevant period for gross income is “the previous tax year.” OMB did not add an example to this paragraph and finds the revised text is now sufficiently clear.
In response to commenters: first, regarding the question about FSRS and USAspending.gov, instructions on using FSRS are provided on FSRS.gov. Next, the comment about subrecipients reporting executive compensation directly to FSRS is beyond the scope of changes proposed by OMB. OMB did not make this change in the final guidance.
Regarding the comment maintaining that there is a discrepancy between the thresholds in Section I, paragraph (c)(1)(ii)(B) and paragraph (d) for reporting subaward information: the threshold in paragraph (c)(1)(ii)(B) refers to certain annual gross revenues in the subrecipient's preceding fiscal year, while the threshold in paragraph (d) refers to the recipient's gross income in the previous tax year. Because each threshold has a different subject, neither is superfluous. Both thresholds are provided by the Transparency Act.
On the question regarding the trigger for subaward reporting under the Transparency Act, OMB did not make additional changes. OMB finds the clarifying edits made throughout Appendix A sufficient to explain its intent.
On comments regarding specific Federal financial assistance programs, OMB did not make changes in part 170. OMB is unable to accommodate all requests for individual programs. The Federal agencies implementing these programs are in the best position to address program-specific questions and concerns.
Regarding the comment requesting further clarity on the timeframe recipients have to report a subrecipient's compensation information to FSRS, OMB did not make revisions to the guidance text. OMB understands that some variation may exist in the actions by which recipients obligate subawards, and that delays may occur in some circumstances. However, the Transparency Act requires reporting within 30 days of a Federal award. As a result, part 170 sets the expectation on when this information must be submitted. The recipient must determine when an action constituting a legal obligation of the subaward has occurred, which begins the reporting clock.
Finally, in response to questions about the significance of the changes in terminology regarding the reporting of subawards under the Award Term, OMB finds that the references to “subawards” are sufficiently clear when read in the context of this part and other clarifying edits in the Appendix. As noted in the preceding paragraph, recipients must still use some discretion and reasonable judgement to determine when an action constituting a legal obligation of the subaward has occurred. OMB did not find it necessary to specifically address this topic in part 170.

Part 175—Award Term for Trafficking in Persons
OMB proposed to revise the guidance in part 175 to ensure it properly aligns with the authorizing statutes that have been amended since it was published. See the Trafficking Victims Protection Act (TVPA) of 2000, as codified at 22 U.S.C. 7101 to 7115. OMB proposed to update the policy and Award Term to ensure alignment with the current statute and to further align with the format of the guidance. For example, at section 175.105, OMB proposed adding provisions related to a compliance plan and requiring notification to Inspectors Generals under certain circumstances to further align with the TVPA.
Several commenters questioned the inclusion of the compliance plan and annual certification requirements. One commenter noted that the certification threshold is inconsistent with the threshold in the Federal Acquisition Regulation (FAR).
OMB Response: OMB appreciates the comments received on this part. The compliance plan and annual certification requirements are required by law. OMB does not have the same authority in the context of Federal financial assistance as exists under the FAR, in the context of Federal procurement, to increase statutory thresholds. See 41 U.S.C. 1908. OMB retained the certification threshold at $500,000, which is set by statute.
In the final guidance, OMB revised the compliance plan and certification requirements in section 175.105(b) to clarify, consistent with law, that the requirements apply to subrecipients, contractors, and subcontractors. 22 U.S.C. 7104a. OMB also made conforming changes to the notification requirement at section 175.105(b). Next, OMB also revised section 175.105(c)(1) to clarify that a recipient must immediately inform the Federal agency, in addition to the Inspector General of the Federal agency, of any information it receives from any source that alleges credible information that the recipient, or any subrecipient, contractor, or subcontractor of the recipient, has engaged in conduct that is prohibited in this part.
OMB revised section 175.200(b) to clarify that a Federal agency may include the compliance plan and certification requirements in the award term when applicable—or other information consistent with statutory requirements. Finally, OMB also added a reference to the compliance plan and certification requirements in the award term. Federal agencies may decide to expand or relocate this information in the award term in appendix A to part 175 consistent with the guidance in 175.200(b).

Part 180—OMB Guidelines to Agencies on Government-Wide Debarment and Suspension (Nonprocurement)
OMB proposed minimal revisions to this part based on feedback received from the Interagency Suspension and Debarment Committee (ISDC) in accordance with section 180.40. Considering the role of the ISDC in recommending changes, OMB did not propose extensive plain language revisions in part 180. Sections in part 180 that OMB proposed to revise included sections 180.635 and 180.640 to clarify available administrative actions in lieu of debarment. OMB proposed amending section 180.705 to include “other indicators of adequate evidence that may include, but are not limited to, warrants and their accompanying affidavits” for officials to consider before initiating a suspension. OMB proposed additional clarifying edits to sections 180.710, 180.815, and 180.860, including adding text to section 180.860 to address factors influencing a debarment decision. This revision proposed to add text onto “whether your business, technical, or professional license(s) has been suspended, terminated, or revoked.” OMB proposed changes to this part generally in response to an ISDC recommendation to provide additional clarifications to 2 CFR to reflect current practice. OMB did not propose to establish new policy in part 180 that would negatively impact the ability of Federal agencies or recipients to adhere to this guidance.
OMB received a variety of comments and suggestions on part 180. For example, a commenter requested revisions on what individuals may be eligible to serve as “the suspending official or designee” and “the debarring official or designee.” OMB also received requests to modify notice requirements, revise definitions, increase thresholds, expand the list of enumerated causes for debarment, fix references, make grammatical changes, and include other changes in this part.
OMB Response: OMB appreciates the comments it received on this part, but generally considers them beyond the limited scope of the clarifying changes that OMB proposed for this update. More substantive changes will require additional engagement with the ISDC in accordance with section 180.40 to develop appropriate language. At this time, OMB finds that the changes requested by commenters are not necessary to understand the policy under part 180. Except for a minor grammatical change, OMB made revisions in this section as proposed. OMB will consider whether additional changes to Part 180 are warranted in the future, and may consider the comments received in response to the proposed guidance.

Part 182—Government-Wide Requirements for Drug-Free Workplace (Financial Assistance)
OMB proposed limited plain language and technical revisions to this part. A commenter pointed out a minor typographical error, which OMB fixed in the final guidance. Another commenter suggested changes to how workplaces are identified in section 182.230, which OMB did not find it necessary to incorporate at this time. Other than the typographical error, OMB incorporated the proposed revisions in the final guidance.

Part 183—Never Contract With the Enemy
OMB proposed limited plain language and technical revisions to this part. OMB did not receive significant comments regarding the proposed changes. OMB revised its guidance in this part as proposed.

Part 184—Buy America Preferences for Infrastructure Projects
OMB established this part on Buy America preferences for infrastructure projects through a separate process. 88 FR 57750 (Aug. 23, 2023). OMB did not propose changes to part 184 through the proposed guidance. However, in the final guidance, OMB made minor technical edits to align Part 184 with the definitions in Part 200 as revised. Specifically, OMB replaced the term “Federal awarding agency” with “Federal agency.”
OMB received several comments relating to the applicability of the Build America, Buy America Act (BABA), including questions on its application to for-profit recipients. Commenters also raised concerns about the equitable application of Part 184 to different types of entities. As explained in the preamble to OMB's proposed revisions, OMB did not propose any substantive changes to BABA applicability or part 184 through this guidance-making process, and OMB did not make any substantive changes through this update on those topics.
For reasons unrelated to part 184, OMB replaced “non-Federal entity” with “recipients or subrecipients” in the revised definition of Federal financial assistance in section 200.1 discussed below. Section 70912(4) of BABA incorporates the definition of Federal financial assistance from the Uniform Guidance at 2 CFR 200.1 or successor regulations. In cases in which Federal agencies apply subparts A through E of part 200 to for-profit organizations, this revision may provide further clarity on the applicability of BABA to Federal awards made to for-profit organizations. OMB did not materially change the sentence in the applicability section of the Uniform Guidance at 200.101(a)(2) providing Federal agencies with discretion on whether to apply the guidance in part 200 to for-profit organizations. Thus, OMB did not substantively change the status quo on applicability of BABA to for-profit recipients as described in the preamble for the part 184 guidance at 88 FR 57774 and in OMB Memorandum M-24-02, Implementation Guidance on Application of Buy America Preference in Federal Financial Assistance Programs for Infrastructure (Oct. 25, 2023). As explained in Memorandum M-24-02, Federal agencies may consider applying BABA requirements to for-profit entities consistent with their legal authorities, but are not required by OMB to do so. For additional information on BABA and OMB's guidance in 2 CFR part 184, see also 88 FR 55750 (Aug. 23, 2023).

Subpart A—Acronyms and Definitions

Section 200.0—Acronyms
OMB proposed to update section 200.0 to remove acronyms that either appeared only once or were used infrequently in the guidance. At the same time, OMB proposed to add several acronyms that were used more frequently, but have been omitted from this section in past updates, such as UEI. OMB received a few comments that suggested incorporating acronyms excluded from this section in the proposed guidance.
OMB Response: OMB did not find it necessary to expand on the list of acronyms. OMB only included in this section if used in multiple sections throughout the guidance. However, if multiple uses of an acronym were confined to a single section of the guidance, OMB did not find it necessary to include the acronym in this section. With the exception of simplifying the citation for FFATA (the Transparency Act), OMB included acronyms in this section in the final guidance as proposed.

Section 200.1—Definitions
In section 200.1, OMB proposed to remove several definitions that were used only once or on a limited basis and instead moved such definitions to the appropriate section of the guidance where they appear. OMB also proposed deleting the definition of Federal awarding agency, which OMB incorporated within the definition of Federal agency. OMB also proposed adding several new definitions of commonly used terms including continuation funding, for-profit organization, key personnel, participant, and prior approval. OMB also proposed to revise several definitions to incorporate threshold increases referenced in other sections, such as the threshold increase for equipment to $10,000, the threshold for supplies to $10,000, and the definition of modified total direct costs, under which OMB proposed to exclude subaward costs above $50,000, as compared to $25,000 in the prior version of the guidance. OMB also proposed to revise several definitions for other reasons, including cost sharing, Federal agency, Federal award date, Federal financial assistance, financial obligations, improper payment, Indian Tribe, intangible property, participant support costs, period of performance, prior approval, questioned costs, real property, recipient, special purpose equipment, subaward, and termination.
OMB received many comments on the definitions in this section, including some suggestions for new definitions and other potential changes for future updates. OMB also received a few comments recommending the deletion of definitions and moving them to applicable sections of the guidance. Comments received on specific definitions and OMB's responses are provided below. OMB attempted to incorporate public comments where appropriate.
Advance Payment: OMB received one comment suggesting that this definition exclude the reference to subrecipients as a disburser of funds. OMB disagrees with the commenter. Like recipients, subrecipients also disburse funds for program purposes. For example, subrecipients disburse cash for property and services. Accordingly, OMB finds this change is unwarranted and revised the definition as proposed.
Advisory Council: OMB received a suggestion to include a definition for advisory council in this section, which is only defined in section 200.422. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Bad Debt: OMB received a suggestion to include a definition for bad debt in this section, which is only defined in section 200.426. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Beneficiary: OMB received several comments suggesting that OMB define the term beneficiary. OMB did not propose to define the term, the meaning of which can vary widely between Federal agencies as well as within agencies between assistance programs. OMB defers to Federal agencies to determine who is or is not a beneficiary under their respective programs consistent with law. The definition of participant and participant support costs in this guidance is not intended to include beneficiaries. For the reasons summarized here, OMB defers to Federal agencies on the use and meaning of this term consistent with law for their programs.
Cognizant Agency for Audit: One commenter asked OMB to clarify whether there is a list of cognizant agencies for audit. The commenter noted that this information is not available on the Federal Audit Clearinghouse (FAC) website. OMB revised the definition to clarify that the FAC website provides a list of Federal agency Single Audit contacts and not a list of cognizant agencies for audit.
Conditional Title: A commenter asked OMB to include the definition of conditional title in section 200.1, which is currently defined in section 200.313. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Conference: Another commenter asked OMB to define the term conference in section 200.1 because it is only defined in section 200.313. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Construction: OMB received two comments requesting a definition of the term construction. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance. OMB also did not define this term in part 200 because OMB did not want to inadvertently impact the implementation of Buy America requirements under part 184, which incorporate definitions from part 200, but which are not the focus of this update.
Contingency Provisions: One commenter asked OMB to include the definition of contingency provisions or costs in section 200.1. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Continuation Funding: One comment expressed concern that the proposed definition of continuation funding did not adequately capture the distinction between an agency's exercise of its discretion when making an award and subsequent determinations by the agency, pursuant to terms and conditions of the award, to provide funding for additional budget periods for that same award. In the final guidance, OMB revised the definition of continuation funding to simply mean “the second or subsequent budget period within an identified period of performance.” The proposed reference to a “discretionary decision by a Federal agency” is no longer included in the definition. Depending on the assistance program and the terms and conditions of the Federal award, agency discretion may be involved or legally available on whether to provide continuation funding. However, considering the potential for variation among Federal agencies and programs, OMB did not find it necessary to address this topic directly in the final definition of continuation funding.
Contract: OMB made a minor revision to this term to clarify that contracts are utilized for conducting “procurement transactions” in general and are not limited to only purchasing “property and services.”
Conviction: A commenter asked OMB to harmonize the definition of conviction across the guidance. The commenter noted that the definition of this term varies in different sections. For example, different definitions are used in sections 200.435(a)(1), 180.920, and 182.615. OMB did not add a definition for this term in part 200. OMB is limiting the definitions in section 200.1 to those terms used consistently throughout the part 200 guidance. For the purposes of this update, OMB did not find it necessary to provide a single definition of this term applicable across all parts of the OMB guidance in 2 CFR.
Cooperative Agreement: OMB received several comments requesting clarification on the relationship between parties under both grants and cooperative agreements. OMB agrees with commenters that additional clarity is warranted and made minor clarifying revisions in the final guidance.
Cooperative audit resolution: As proposed, OMB moved this definition to section 200.513(c), which outlines Federal agency responsibilities for audits. Considering its limited use in the guidance, OMB found it easier for the reader in this case if the definition is included in the same section where the responsibilities are outlined.
Cost of Idle Facilities: One commenter asked OMB to insert a definition of cost of idle facilities in section 200.1 because a definition is provided in section 200.466(a)(4). OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Cost objective: OMB made a minor revision to this term by removing “((Facilities and Administration (F&A))” after “indirect” cost. The more general term “indirect costs” is not necessarily limited in all cases to the more specific F&A category. The definition of indirect cost now explains that the term facilities and administrative (F&A) cost is often used to refer to indirect costs by Institutions of Higher Education.
Cost sharing: In the proposed guidance, OMB proposed minor revisions to this term, including clarifying that cost sharing includes matching. OMB made changes to the definition as proposed.
Credible Evidence: At least one commenter asked OMB to provide a definition of credible evidence. OMB did not find it necessary to define the term in section 200.1. OMB intends to generally align the meaning of credible evidence under the Uniform Guidance in part 200 with the existing meaning under the FAR. See 73 FR 67064 (Nov. 12, 2008) (explaining reasons for selecting the term “credible evidence” including discussion of alternatives considered). This topic is discussed further in the context of section 200.113 below.
Data Management and Sharing Costs: One commenter asked OMB to add a definition of data management and sharing costs, which appears in section 200.455. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Depreciation: One commenter asked OMB to add a definition of depreciation, which is used in section 200.436(a). OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Disallowed Cost: Six commenters asked OMB to restore the version of disallowed cost under the prior version of the guidance, which is limited to costs determined to be unallowable in accordance with applicable Federal statutes, regulations, or the terms and conditions of the Federal award. OMB agrees with commenters and restored that language in the final guidance.
Encumbrance: Several commenters asked OMB to add a definition of encumbrance in section 200.1 in place of the proposed definitions in sections 200.311, 200.313, and 200.315. OMB discusses this topic further in those sections. Other commenters noted certain deficiencies with OMB's proposed definition included in sections 200.311, 200.313, and 200.315. For example, a commenter asked OMB to address the difference between encumbrances and “pre-existing encumbrances.”
OMB did not add a definition of encumbrance in section 200.1. OMB also removed its proposed definition from the later sections of the preamble. Like the prior version of the guidance, the term “encumbrance” is not formally defined in the final guidance text. OMB's decision was based in part on comments expressing concern that the proposed definition may not fit equally well in all contexts under part 200 in which it could be applied. For the present, OMB did not attempt to revise its definition to effectively address all scenarios and potential concerns.
For future updates, OMB will again consider exploring this topic and providing a definition. OMB may consider providing a single definition of this term or providing separate definitions in the specific sections in which it is used. OMB cautions, however, that its decision not to provide a definition of this term should not be interpreted to indicate any particular policy intent in the sections in which the terms “encumber” or “encumbrance” are used. For example, OMB's decision to remove the proposed definition is not based on any single comment received in response to the proposed guidance. Removing the definition also does not indicate that OMB now disagrees with its proposed definition, which may be reasonable to use in many contexts. OMB will continue to evaluate what definition, if any, should be provided in future updates to the Uniform Guidance.
Equipment: OMB received three comments requesting that the threshold for equipment be raised above $10,000. OMB proposed to raise the threshold to $10,000 in the proposed guidance. OMB finds that an additional increase is not warranted at this time and revised the guidance as proposed.
Expenditures: OMB proposed to revise this definition. One commenter asked OMB to restore a definition closer to the original, including restoring the reference to a “project or program” under a Federal award. OMB agrees with the comment and restored the use of “project or program” to the definition.
Facilities: A commenter asked OMB to include a definition of facilities, which is used in section 200.446(a)(1). OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Federal Agency: OMB received two comments indicating that the new definition of Federal Agency was unclear. OMB agrees with commenters that the structure of the proposed definition could cause confusion. To simplify, OMB now defines the term to mean an “agency” as defined at 5 U.S.C. 551(1) and further clarified by 5 U.S.C. 552(f). The definition further explains that the term generally refers to the agency that provides a Federal award directly to a recipient unless the context indicates otherwise. OMB incorporated these revisions in the final guidance. Based on this change, OMB eliminated the term “Federal awarding agency,” which no longer appears in the guidance text.
Federal Award: One commenter suggested revising paragraphs (1)(i) and (1)(ii) using both the terms recipient and subrecipient, rather than just recipient in (1)(i) and non‐Federal entity in (1)(ii). The commenter stated that this would more clearly identify the types of entities covered as well as provide flexibility should an agency wish to make subparts A through E applicable to other types of entities. OMB disagrees with the commenter that further clarification is needed for paragraph (1)(i) at this time. OMB retained the language from the proposed and prior versions of the guidance, which is widely known and understood in the Federal financial assistance community. OMB also did not further revise paragraph (1)(ii) from the proposed or prior version of the guidance, which refers to a cost-reimbursement contract under the FAR. In this case, OMB retained the original term non-Federal entity.
Another commenter asked OMB to clarify the distinction between a grant and contract based on ambiguity presented in paragraphs (1) and (3). Paragraph (3) of the definition of Federal award refers to contracts that a “Federal agency uses to buy goods or services,” which generally would be governed by the FAR. However, paragraph (1)(ii) of the definition helps to clarify that a cost-reimbursement contract awarded under the FAR to a non-Federal entity may be subject to certain specified provisions under part 200. This is more specifically described in section 200.101, which is referenced in paragraph (1)(ii). This is a long-standing feature of the definition of Federal award and section 200.101, which is not newly proposed by OMB in this update. OMB did not propose changes to this element of the definition and does not make any further changes in the final guidance.
Another commenter recommended that the definitions of Federal award, Federal financial assistance, Federal program, and grant agreement all be revised to specifically exclude funds and activities associated with self-determination compacts between Indian Tribes and the Federal government. The existing definitions do not provide the requested exclusion, nor did OMB propose to add the exclusion in the proposed guidance. OMB may consider this comment for future updates, but made no change in the final guidance. Section 200.101(d) provides that statutes or Federal agency regulations may govern in circumstances where they conflict with the provisions of part 200. This existing provision of the guidance recognizes that the provisions of the Indian Self-Determination and Education and Assistance Act (ISDEAA), as amended (see 25 U.S.C. 5301-5423) may govern in some circumstances.
Federal awarding agency: See discussion of the term Federal agency.
Federal award date: OMB proposed minor revisions to this term, which it mostly included in the final guidance. In the final version, OMB deleted “binding agreement” following the word alternative in recognition that 31 U.S.C. 1501 does not require this in all cases. The relevant alternatives are listed in 31 U.S.C. 1501.
Federal financial assistance: OMB proposed a minor change to the definition of the term “Federal financial assistance.” As with other provisions in subparts A through E, OMB proposed the term to include assistance received or administered by recipients or subrecipients—as compared to assistance received or administered by non-Federal entities in the prior version of the guidance. OMB included this change in the final guidance.
Another commenter recommended that the definitions of Federal award, Federal financial assistance, Federal program, and grant agreement all be revised to specifically exclude funds and activities associated with self-determination compacts between Indian Tribes and the Federal government. See OMB's response above under Federal award.
Federal program: One commenter recommended that the definitions of Federal award, Federal financial assistance, Federal program, and grant agreement all be revised to specifically exclude funds and activities associated with self-determination compacts between Indian Tribes and the Federal government. See OMB's response above under Federal award.
Financial obligations: A commenter asked OMB further clarify the definition of financial obligations by adding a table. OMB did not find this necessary or critical to understand the meaning of this term. In the final guidance, before the word “result,” OMB added the word “will.” This change simply recognizes that expenditures are not always contemporaneous with the financial obligation. Rather, an obligation will often require a future—but not immediate—expenditure or outlay of funds.
Fixed amount award: A commenter asked OMB to incorporate policy requirements for fixed amount awards into the definition. OMB disagrees that this is necessary in the definition section and did not make a change. Specific requirements for fixed amount awards are addressed later in the guidance.
For-profit organization: OMB proposed to add a definition of this term in the proposed guidance. That definition is included in the final guidance.
Fraud: A commenter asked OMB to include the definition of fraud in section 200.1 based on use of that term in 200.435. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
General Support Services: A commenter asked OMB to add a definition for general support services. OMB did not add a definition for this term. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Grant agreement: OMB received a couple of comments requesting further clarity on the relationship between parties under the definitions of grants and cooperative agreements. OMB agrees with the commenters and made minor clarifying revisions in the final guidance.
Another commenter recommended that the definitions of Federal award, Federal financial assistance, Federal program, and grant agreement all be revised to specifically exclude funds and activities associated with self-determination compacts between Indian Tribes and the Federal government. See OMB's response above under Federal award.
Idle Capacity: A commenter suggested including a definition for idle capacity based on its use in 200.446. OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Idle Facilities: A commenter suggested including a definition for idle facilities based on its use in 200.446(a)(2). OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Improper Influence: A commenter suggested including a definition for improper influence based on its use in section 200.450(b). OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Improper payment: A few commenters asked OMB to reinstate the previous definition of improper payment. OMB disagrees. As stated in the preamble for the proposed guidance, OMB proposed to shorten the definition of “improper payment” to ensure better alignment with in Appendix C to OMB Circular A-123, Requirements for Payment Integrity Improvement. OMB made changes to the definition as proposed. See also the definition of questioned costs, in which OMB clarifies that questioned costs are not considered improper until they are confirmed to be improper under A-123.
Indian Tribe: OMB proposed minor revisions to this term. It includes the revised definition in the final guidance.
Indirect cost: In the final guidance, OMB revised the definition of indirect cost to no longer include reference to facilities and administrative (F&A) cost directly in the name of the term itself. OMB's revision to the defined term has no substantive impact on how the term is applied under the final guidance relative to how it was applied under the prior version of the guidance. The term “indirect cost” continues to align with “F&A costs.” OMB explains within the definition that F&A costs and indirect costs are often used interchangeably at Institutions of Higher Education (IHE). OMB received multiple comments requesting this revision. OMB also received one comment that recommended amending the definition of indirect cost to note that the duplication of costs is unallowable. OMB did not find the latter change necessary in the context of this definition. Allowability is addressed later in the guidance.
Indirect cost rate proposal: OMB received three comments that recommended adding “or subrecipient” to the definition of indirect cost rate proposal because indirect costs apply to both recipients and subrecipients. OMB acknowledges that one can be both a recipient and subrecipient and have a Federally negotiated rate. However, only recipients prepare proposals in accordance with the appendices. An organization that is exclusively a subrecipient would not negotiate a rate with a Federal agency under the appendices to this part.
Information technology systems: One commenter requested inclusion of cybersecurity in the definition of information technology systems. Cybersecurity may already be included in the definition if provided through listed items such as software or firmware or a related procedure or service. OMB did not find it necessary to specifically list cybersecurity in this definition.
Initial equity contribution: A commenter asked for a definition of initial equity contribution to be included in section 200.1 based on its use in 200.449(c)(7). OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Intangible property: A commenter expressed concern that the proposed inclusion of data under the definition of intangible property would make data subject to the requirements of section 200.315. OMB responds that data is included as an example under the definition of intangible property. Even under the prior definition, certain data could already have been considered intangible property and subject to section 200.315 if it met the criteria under the guidance. For example, section 200.315 refers to intangible property developed, or for which ownership was acquired, under a Federal award. With the exception of minor edits, OMB revised the definition as proposed.
Key personnel: OMB proposed to add a definition for this term in the proposed guidance. OMB received several comments suggesting that the new definition caused confusion or was unclear. In the final guidance, OMB removes its proposed definition of this term in response to those comments. In section 200.308(f)(2), OMB clarified that, at least in the context of that provision, key personnel includes employees and contractors.
Less-than-arm's-length: One commenter suggested including a definition of less-than-arm's-length in section 200.1 based on its use in 200.465(c). OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Loan: In the final guidance, OMB added “or subrecipient” following recipient to recognize that subrecipients may also receive or administer loans.
Local Partner: One commenter suggested including a definition of local partner. OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Micro-purchase: A commenter asked OMB to revise the definition of a micro-purchase to aggregate the purchase of supplies needed over the life of a Federal award. Another commenter asked OMB to remove the language referring to an individual procurement transaction. OMB found that neither of these changes are necessary and revised the definition as proposed.
Micro-purchase threshold: In the final guidance, OMB revised the definition of this term by revising language on the ceiling for the micro-purchase threshold. OMB received several comments noting that the definition of the micro-purchase threshold failed to recognize different ways of establishing higher rates under section 200.320. OMB agrees with commenters and revised the definition accordingly.
Modified total direct costs (MTDC): A commenter suggested revising the definition to not require exclusion of the portion of each subaward above the threshold. Two commenters asked whether subcontracts would be included in the modified total direct costs definition based on earlier versions of the guidance. Several commenters sought clarification on the intended application of rental costs and patient care costs in the modified total direct cost definition and suggested that OMB define these terms. Another commenter suggested that OMB revise the definition of modified total direct cost to include the threshold amount for each year during the period of performance that the subaward is in effect. Several commenters also asked OMB to increase the threshold for each subaward to above $50,000.
In the final guidance, OMB revised the definition as proposed. Many of the suggestions are beyond the scope of OMB's proposed revision to this definition, which was limited to increasing the threshold for the portion of each subaward that may be included from $25,000 to $50,000. As proposed, OMB retained the exclusion of the portion of each subaward above the threshold. OMB does not include subcontracts in the revised definition, which were removed in earlier versions of the guidance. OMB leaves this policy unchanged.
Under the revised definition, only the first $50,000 of each subaward may be included—regardless of the period of performance of that subaward. OMB disagrees that recipients should be able to apply this threshold on an annual basis for subawards with longer periods of performance. OMB also disagrees with the proposal to further increase the threshold for each subaward. OMB finds that doubling the threshold, as proposed, is an appropriate increase for this update.
Notice of Funding Opportunity: A commenter asked for clarity on what a pass-through entity should call a notice of funding opportunity (NOFO) as the definition does not include pass-through entities. Another commenter stated that the reference to subrecipient in the definition should be removed because Federal agencies do not select subrecipients.
Regarding the first comment: a pass-through entity is not required to call a solicitation of subaward proposals by a specific name. On the second comment, although OMB agrees that Federal agencies do not directly select subrecipients under a NOFO, some NOFOs do provide guidance or information on how recipients should select subrecipients for a particular assistance program. For this reason, OMB retained the reference to subrecipient in the definition. OMB made changes to the definition as proposed.
Participant: OMB proposed to add a definition of participant in the proposed guidance. OMB made a few revisions to the final definition to provide further clarification of its intent. For example, OMB restructured the definition to begin with an affirmative definition of a participant generally, before providing a negative definition of what a participant is not. The order was reversed in the proposed guidance. Other revisions are addressed below.
Initially, the definition of participant cannot account for all variations on how participants are treated or defined by different Federal agencies or under specific assistance programs. For this reason, section 200.456 of the guidance specifies that the recipient must document its policies and procedures for making participant determinations. That section also provides that participant support costs must be treated consistently across all Federal awards. See also participant support costs below.
One commenter suggested changing the reference to “exchange students” in the definition to just “students.” The commenter stated this would be simpler and, in most cases, more appropriate for Federal programs. The reference to exchange students was just one potential example of a participant, but OMB made this change in the final guidance.
Another commenter stated the definition was unclear and overly broad. One commenter specifically pointed to the phrase “playing a role in the overall program activities” as overly broad and confusing. In addition to restructuring the definition, as explained above, OMB attempted to provide further clarity in the final definition. For example, OMB now begins the definition by stating that a participant is an individual participating in or attending program activities—but not an individual responsible for implementing those activities under the Federal award.
Next, a commenter stated the definition should specify that individuals who attend trainings and conferences may be treated as participants. OMB agrees and included such individuals as examples of participants.
Another commenter stated that the definition should exclude project personnel and those who commit effort on the implementation of the Federal award. OMB agrees and revised the definition. Another commenter asked OMB to replace “staff member” in the proposed definition with “employee.” OMB did not find this change was necessary.
One commenter stated the definition should provide that beneficiaries are also participants. OMB disagrees that this would always be true and does not consider the two terms to be equivalent or synonymous. Identification of beneficiaries is at the discretion of the Federal agency making the award to the extent consistent with authorizing law. See also discussion under the term “beneficiary” above, which is discussed in this preamble but not defined in section 200.1.
A commenter also asked OMB to clarify that the examples are provided for illustrative purposes only and that the classification is at the discretion of the recipient. Partially in response to this comment, OMB revised and restructured the definition to better identify where it is providing definitional elements of a participant and where it is just providing examples that may fit those elements. OMB also revised some of the examples provided.
Other commenters asked OMB to provide additional examples of participants within the definition. OMB finds that an exhaustive list of examples is not necessary. For example, although examples such as teachers, scholars, or scientists may be participants in some cases, they could also be employees, consultants, or beneficiaries in others. OMB sought an appropriate balance in the final definition by providing a few illustrative examples but not providing—or attempting to provide—an exhaustive list.
Participant Support Costs: One commenter asked OMB to revert to the prior definition of participant support costs. Another commenter sought clarification on whether the inclusion of stipends as an example in the definition indicates that stipends are considered participant support costs. Another comment asked OMB to provide examples of types of participants, associated with typical participant support costs. Another commenter asked for clarification on the inclusion of temporary dependent care in the participant definition. Specifically, the commenter questioned whether the use in this definition was intended to be synonymous with the use of the same term in section 200.475(c)(1).
OMB finds the proposed text for this definition was sufficiently clear and did not make significant changes. Only stipends paid to participants are considered participant support costs. OMB found that it was not necessary to specifically mention training and conferences in the definition as the costs may also be incurred in other contexts when allowed under the guidance. Participant support costs are any costs that are paid directly to or on behalf of a participant. OMB clarified the reference to “temporary” dependent care. Section 200.475 applies to dependent care for employees, not participants.
Pass-through entity: OMB received several comments indicating that the definitions of recipient, subrecipient, and pass-through entity were unclear. OMB proposed only minor revisions to the definition of pass-through entity and disagrees with commenters that the term is unclear. While traditionally pass-through entity specifically referred to a non-Federal entities under earlier versions of the guidance, other entities may also be considered pass-through entities based on how a Federal agency implements the guidance for its programs.
In the final guidance, to address potential confusion on how the term will be applied, OMB added language to clarify that the authority of the pass-through entity under part 200 flows through the subaward agreement between the pass-through entity and subrecipient. OMB added this language to ensure that a pass-through entity will not erroneously apply the authorities available to the Federal agency under part 200. For example, if a provision in part 200 allows “the Federal agency or pass-through entity” to provide an approval or authorization for a “recipient or subrecipient,” the pass-through entity only has authority to provide the approval or authorization to its subrecipient. In this situation, the pass-through entity cannot provide the approval or authorization to itself, but rather would need to obtain approval or authorization from the Federal agency. For a more specific example, under section 200.343, the pass-through entity is not permitted to authorize its own costs for its own primary Federal award. The pass-through entity may expressly authorize these costs for subawards only.
Performance Based Payment: One commenter asked OMB to include a definition of performance based payment. OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Period of performance: OMB proposed revisions to this term, but now provides a simplified definition in the final guidance. The final definition reinstates some familiar language from the definition in the prior version of the guidance, which OMB had proposed to remove. As now revised, period of performance means the time interval between the start and end date of a Federal award, which may include one or more budget periods. The final definition also recognizes that identification of the period of performance in the Federal award consistent with section 200.211(b)(5) does not commit the Federal agency to fund the award beyond the currently approved budget period. The period of performance is also sometimes referred to by Federal agencies as the performance period.
Personally Identifiable Information (PII): Within the definition of Personally Identifiable Information (PII), in the final guidance OMB deleted the text defining Public PII. The term “Public PII” is never used in the guidance text. OMB seeks to avoid confusion by defining a term in section 200.1 that is never used in the body of the guidance—which could potentially prompt questions on whether Public PII should be treated differently than normal PII. The deletion of this text on Public PII does not represent a substantive change to the policy in the guidance. The remaining text in the definition continues to explain that some PII can be available in public sources.
Post-retirement health plan: One commenter asked OMB to include a definition of post-retirement health plan in section 200.1 based on its use in 200.431(h). OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Prior approval: Several commenters asked OMB to clarify the definition of prior approval by adding the words “obtained in advance.” Some commenters also asked OMB to clarify and specify when ratification (after the fact approval) would be permissible. One comment requested that OMB specify that approval of the project narrative or budget constitutes prior written approval. A different comment requested that the guidance limit Federal agency or pass-through entity review of requests for budget or program revisions to 15 days. Several comments questioned whether the definition may cause misunderstanding for pass-through entities and subrecipients on who can approve which action.
OMB added the words “obtained in advance” to the definition to clarify that, generally, obtaining approval in advance is a definitional element of prior approval, which is required where stated in the guidance. However, this change is not intended to prohibit Federal agencies from using appropriate procedures to retroactively provide prior approval, if necessary, under a Federal award in specific cases. OMB does not directly address this topic in the definition of the term, but Federal agencies may exercise reasonable discretion in providing “after the fact” prior approval when warranted on a case-by-case basis under Federal awards and otherwise consistent with law.
Guidance provided in section 200.308 is already responsive to the comment regarding circumstances in which approval of the project narrative or budget may constitute prior written approval. In response to another commenter, OMB is not establishing a specific timeframe in which an agency should provide prior approval, but may consider the recommendation of a 15-day period in future updates. Regarding commenters expressing confusion on when pass-through entities may provide prior approval, in many instances the guidance text specifically states whether the Federal agency or pass-through entity may provide the approval. In circumstances in which pass-through entities may provide prior approval, they have the same responsibility for monitoring and oversight as a Federal agency does. In some circumstances a change under a subaward will be significant enough to also require a change to the recipient's Federal award, which would also require prior approval by the Federal agency.
Program Evaluation: Two commenters asked OMB to define the term program evaluation to align with OMB Circular A-11. OMB did not add a definition for this term directly in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Program Income: A commenter observed that usage of the phrase “under a Federal award” in the illustrative examples of program income was confusing and needed clarification. The phrase was used for some examples but not others. In response to the comment: the key definitional elements of program income are provided in the first sentence of the definition, including explaining its connection to a Federal award. But the repetition of “Federal award” in certain examples helps to provide context. For example, in relation to certain items, the examples identify program income “acquired” under Federal awards, “fabricated” under a Federal award, and “made with” Federal award funds. Deleting this language would make the examples less clear. Thus, OMB retains reference to “Federal award” in the case of some example, but not all, when it helps to provide context and explain what OMB means by the example.
Protected Personally Identifiable Information (Protected PII): In the final guidance, OMB made minor revisions to the definition of Protected Personally Identifiable Information (Protected PII) to more accurately reflect the meaning of this term.
Questioned Cost: Multiple commenters objected to the deletion of the statement that questioned costs are not improper payments until reviewed and confirmed to be improper payments. No policy change was intended by the deletion. OMB restored the original statement within the definition of questioned cost at paragraph (6).
Two comments expressed concern about situations in which an auditor identifies questioned costs, the auditee locates additional documentation, and the auditor reports the questioned costs without considering the documentation. This comment recommended stating more specifically when adequacy of documentation should be assessed. OMB finds that it is not necessary to specifically address in the guidance the point in time at which this would occur.
Several commenters expressed concern that introducing the concept of “likely questioned costs” could put auditees at risk from speculative or unsubstantiated audit findings. OMB responds that the concept of likely questioned costs is not new. The definition now appearing at section 200.1 is from section 200.516 in prior versions of OMB's guidance. It is also based on AU-C 935.11 in the auditing standards of the American Institute of Certified Public Accountants (AICPA). The requirements associated with this concept are not new, including the requirement for auditors to consider the likely questioned costs in formulating their opinion on compliance. OMB merely moved the existing language from section 200.516 to section 200.1. Speculative or unsubstantiated audit findings would not align with the AICPA's auditing standards.
Several commenters recommended that “known questioned cost,” rather than “questioned cost,” should be the defined term and used as a basis for defining the related term, “likely questioned cost.” OMB is not adopting this recommendation at this time. OMB did not find reason to restructure the definition in this way through this update, but may consider the suggestion in the future.
Several commenters suggested categorizing the compliance requirements in the compliance supplement (see definition in section 200.1) as monetary or non-monetary to facilitate consistent reporting of questioned costs. In paragraph (3)(ii) of the definition, OMB clarified that there is no questioned cost solely because of noncompliance with the “reporting type of compliance requirement” (as described in the compliance supplement) if this noncompliance does not affect the amount expended or received from the Federal award.
Several commenters also suggested clarifying that there is no questioned cost solely because of a misclassification of costs. OMB agrees that in some cases this may be consistent with the intent of paragraph (3)(ii), as revised, but also observes that misclassified costs may sometimes affect the amount expended and thus be considered questioned costs. This may occur, for example, if the misclassification resulted in noncompliance with matching requirements.
Real Property: OMB received a comment on proposed revisions to the definition of real property. The commenter questioned the proposed addition of “legal interests in land.” The commenter stated these would only be considered intangible rights or intangible property, but not real property. In response to the comment, many Federal agency regulations recognize that “real property” may include legal interests in land. ^2 Black's Law Dictionary also recognizes that real property “can be either corporeal (soil and buildings) or incorporeal (easements).” (11th ed. 2019). In the final guidance, OMB decided to retain the reference to “legal interests in land” followed by a short list of examples. Relative to the proposed guidance, OMB only made minor technical edits. As applied to other sections of the guidance, the revised definition clarifies, for example, that if an easement is acquired under a Federal award, the recipient must not dispose of the easement while it is being used for the originally-authorized purpose except as provided by the Federal agency—or as otherwise allowed under relevant sections of the guidance. See 2 CFR 200.311(b). It is possible that not all provisions in the Uniform Guidance that apply to real property will equally apply to all legal interests in land. For example, section 200.310 on insurance coverage may have limited applicability in certain cases if insurance coverage would not ordinarily apply to a particular legal interest in land. Federal agencies may exercise discretion in appropriate application of the revised definition consistent with law.
^2 See, e.g., the General Services Administration (GSA) regulation applicable to GSA's real property policies at 41 CFR 102-71.20 (Real property means “[a]ny interest in land, together with the improvements, structures, and fixtures located thereon . . . and appurtenances thereto . . .”). See also, e.g., 43 CFR 423.2 (“Real property means any legal interest in land . . .”); 23 CFR 710.105 (“Real property . . . means any interest in land and any improvements thereto . . .”); 10 CFR 770.4 (“Real Property means all interest in land . . .”); 25 CFR 900.6 (“Real property means any interest in land together with the improvements, structures, and fixtures and appurtenances thereto”); 25 CFR 170.5 (“Real property means any interest in land together with the improvements, structures, fixtures and appurtenances”); 26 CFR 1.856-10 (identifying “intangible assets that are real property or interests in real property”).
Recipient: Some commenters asked OMB to amend the proposed definition of recipient (and subrecipient) to explain specifically which entities are recipients (or subrecipients). OMB also received requests to further define the word entity in this and other definitions. These changes are not necessary. Applicability of the guidance is addressed separately in section 200.101. Subparts A through F always apply to Federal agencies that make Federal awards to non-Federal entities. Federal agencies may also apply subparts A through E to certain other entities as provided in section 200.101. Because the applicability will not always be the same for all Federal agencies and programs, OMB is not specifically listing which entities are recipients (or subrecipients) within the definition section. More detailed discussion on section 200.101—and the meaning of applying the guidance to certain entities—is provided in this preamble below. OMB disagrees that further definition of the word “entity” is needed to understand the meaning of the terms recipient and subrecipient under part 200. Section 200.101, on applicability, is the appropriate place to find information on the entities to which part 200 may be applied by Federal agencies.
Renewal award: OMB proposed minor revisions to the definition of this term. In the final guidance, OMB revised the definition to remove language specifying that a renewal award is made “after the expiration of” a Federal award. In practice, renewal awards can be executed prior to the actual expiration of the award that they follow. The revised definition explains that the start date for a renewal award is contiguous with, or closely follows, the end of the expiring Federal award. The start date of a renewal award begins a new and distinct period of performance.
Simplified acquisition threshold: A commenter requested clarity on whether the capitalization of this term in sections outside of section 200.1 was intentional and indicated a different meaning. OMB did not intend for capitalization to indicate different meanings for this term within part 200. OMB removed the inconsistent capitalization in other sections of the guidance.
Special Purpose Equipment: OMB received a comment suggesting that the use of “other technical activities” is overly broad and could be interpreted to be overly inclusive of items that would otherwise be considered general purpose equipment. OMB changed the text to read “other similar technical activities.” OMB considered referring to “other unique and specific activities” but decided that language could be too narrow because it would not necessarily apply to the listed examples of special purpose equipment, including microscopes. OMB finds the general definition and listed examples provide the information needed to exercise appropriate discretion on distinguishing between items that constitute “special purpose” and “general purpose” equipment.
Strategic Sourcing: A commenter suggested including a definition of strategic sourcing in section 200.1 because it appears in section 200.318. OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Subaward: A commenter expressed confusion regarding the statement that a subaward “may be provided through any legal agreement, including an agreement the pass-through entity considers a contract.” In the final definition, OMB further clarifies its intent. OMB explains that criteria for distinguishing between subawards and contracts is provided at section 200.331. Some of this language just restored language from the prior version of the guidance.
OMB also received several comments recommending the definition of subaward clarify if payments to beneficiaries that are not individuals are also excluded. OMB agrees the language was potentially misleading and clarified that subawards do “not include payments to a contractor, beneficiary, or participant.”
Subcontract and Subcontractor: Two commenters asked OMB to add definitions for subcontract and subcontractor. OMB did not add a definition for these terms in section 200.1. OMB finds that the terms are clear from the context in which they are used in the guidance and extend logically from the definition of “contract” and “contractor.” Thus, additional definitions are not needed at this time.
Subrecipient: OMB received a request to clarify if only individual beneficiaries are excluded in the term subrecipient. OMB agrees this feature of the definition was potentially confusing and amended the final language to simply explain that the term “does not include a beneficiary or participant.” Consistent with the definition of recipient, OMB did not add further information on the meaning of the word entity. On this topic, see further discussion in this preamble above on the meaning of recipient.
Supply: OMB proposed revisions to this term, including an increased threshold of $10,000. OMB included the revised definition in the final guidance.
Telecommunications cost: A commenter requested OMB to clarify if telecommunications cost includes the cost of using other types of devices including satellites, radio, TV, telegraphs, and others. OMB responds that the examples provided in the guidance are illustrative and not exhaustive. OMB is not adding other examples to the definition, but recognizes that other communication technologies may also fit under the definition.
Temporary dependent care cost: A commenter asked OMB to defined temporary dependent care cost in section 200.1 because it is defined in section 200.475(c)(1). OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Termination: A few commenters asked OMB to further clarify the meaning of “discontinue” and “discontinuing” in the proposed definition of “termination,” which they stated OMB had used in different and conflicting ways. OMB simplified the definition in the final guidance. As now revised, termination means the action a Federal agency or pass-through entity takes to discontinue a Federal award, in whole or in part, at any time before the planned end date of the period of performance. The final guidance also explains that termination does not include discontinuing a Federal award due to a lack of available funds. See also discussion in this preamble below on changes OMB made to the termination provision at section 200.340 in the final guidance.
Third-party in-kind contribution: One commenter asked OMB to revise paragraph (1) of the definition by either removing “Federal award” from the sentence or adding “that is funded by a” before Federal award. Another commenter asked OMB to revise paragraph (1) to state: “Benefit a federally-assisted project or program or Federal award.” OMB revised the definition based on consideration of these comments to clarify its intent.
Total cost: A commenter asked OMB to include a definition of total cost in section 200.1 because it is defined in section 200.402. OMB did not add a definition for this term in section 200.1. OMB is limiting the definitions to those terms used consistently throughout the guidance.
Unliquidated financial obligation: A commenter stated that this definition should be further clarified. OMB agrees and clarified the final sentence addressing reports prepared on an accrual basis. For reports prepared on an accrual basis, the final guidance now clarifies that these are financial obligations incurred by the recipient or subrecipient but for which expenditures have not been recorded.

Subpart B—General Provisions

Section 200.100—Purpose
OMB proposed multiple clarifying and plain language revisions in this section. OMB received multiple comments requesting reinstatement of the word “inconsistent” in paragraph (a) and the “fair share” language in paragraph (c).
OMB Response: OMB does not find the changes requested by these commenters to be necessary in this section. OMB disagrees that the word “inconsistent” is needed to understand its intended policy in paragraph (a)(1). Additional requirements are only allowed as described in this paragraph. The fair share language in paragraph (c) of the prior version of the guidance recognized a general background principle used in the design of the cost principles in subpart E. This language, on its own, did not require agencies to actually take specific actions. By removing this language, OMB did not intend to indicate that Federal awards no longer need to bear their fair share of cost. Rather, OMB decided to simplify the guidance text in this section and allow the more specific and substantive cost principles in subpart E to speak for themselves on this topic. This general principle used in the design of the cost principles does not need to be stated explicitly in subpart B. In paragraph (d) of section 200.100, OMB made a minor edit to change “administering” to “expending.”

Section 200.101—Applicability
In section 200.101, OMB proposed to clarify the applicability of the guidance. In OMB's proposal, all subparts of part 200 continued to apply to Federal agencies that make Federal awards to “non-Federal entities.” Federal agencies also retained discretion under OMB's proposal on whether to apply subparts A through E of part 200 to Federal agencies, for-profit entities, foreign public entities, or foreign organizations—which are not included in the definition of the term “non-Federal entity.” OMB proposed to add language encouraging agencies to apply the requirements in subparts A through E of part 200 to all recipients in a consistent and equitable manner to the extent permitted within applicable statutes, regulations, and policies. Additionally, OMB proposed to convert the applicability table in paragraph (b) of section 200.101 into narrative form.
OMB received several comments that expressed support for proposed changes in this section and a few provided suggestions for future updates. Other commenters provided a variety of suggestions for further revisions to OMB's current update of this section. Two commenters asked whether OMB will list every program considered exempt from the 2 CFR guidance. Additionally, OMB received a comment asking if paragraph (a)(2)—calling for Federal agencies to apply the requirements to all recipients in a consistent and equitable manner—should be revised to also include subrecipients. OMB also received some questions on the application of subparts A through E by an awarding Federal agency to other Federal agencies.
One commenter sought clarification regarding whether subpart E or FAR 31.2 is the primary guide of cost principles for for-profit entities. Another commenter recommended that subpart F should not apply to fixed amount awards based on the commenter's interpretation that subparts C, D, and E do not apply to these awards. OMB received one comment suggesting that some sections should not be applied to foreign public entities or foreign organizations considering that some exemptions from the guidance are necessary for these entities. OMB received a few comments suggesting restoration of an applicability table instead of presenting this information in narrative form.
OMB also received a comment inquiring about FAR contracts and how they would be included within the scope of a single audit under the current guidance. The commenter asked if this point could be clarified in section 200.101. OMB received one comment that requested the movement of the statement, “rules flow down to recipients and subrecipients” to General Applicability instead of Types of Awards. OMB received several questions inquiring as to when agencies should determine exceptions to the guidance and the date for which adoption of the guidance is enforced. OMB received a recommendation to remove the language “and procurement contracts under the FAR and subcontracts under those contracts” in paragraph (b), which the commenter stated could imply that procurement contracts are a type of Federal financial assistance. Another commenter recommended that the 2 CFR guidance be expanded to cover loans and benefits and that the title of references be changed from “Grants and Agreements” to “Federal Financial Assistance.” OMB received one comment inquiring if the guidance is applicable to inter-agency agreements.
OMB Response: In the final guidance, paragraph (a) of section 200.101 generally indicates how the guidance applies to Federal agencies making awards, and paragraph (a)(2) generally indicates which entities those Federal agencies may apply the guidance to. OMB first revised paragraph (a)(1) of section 200.101 to add a sentence clarifying the applicability of the final guidance to Federal agencies making awards. In paragraph (a)(2), OMB added a sentence to clarify the broad applicability of the guidance to non-Federal entities receiving awards. The remainder of paragraph (a)(2), which explains other entities that Federal agencies may apply the guidance to, was mostly included in the final guidance as proposed. OMB did strike one sentence on automatic application of the cost principles under the FAR to for-profit organizations if the Federal agency does not apply the cost principles in subpart E to that entity. This change does not imply that Federal agencies making awards to for-profit organizations do not need to apply cost principles to those awards—or that for-profit organizations are not subject to cost principles in this scenario. Rather, instead of relying on the FAR to apply automatically in this case, the Federal agency will specify which cost principles apply in the terms and conditions of the award.
OMB disagrees that further changes are needed to paragraph (a)(2). A commenter questioned whether the final sentence of that paragraph on consistent and equitable application of the guidance to all recipients should also reference subrecipients. OMB responds that the reference to recipients is sufficient for the purposes of the policy in this paragraph. In general, Federal agencies do not apply requirements in part 200 directly to subrecipients. Although OMB acknowledges Federal agencies apply the guidance indirectly to subrecipients—for example, through information contained in NOFOs, agency regulations or guidance, and the terms and conditions of Federal awards, which flow down to subrecipients—OMB did not find it necessary to include reference to subrecipients in this provision. S ee 2 CFR 200.101(b)(1) (as revised). The requested change could create confusion about the nature of the relationship between Federal agencies and subrecipients.
OMB also received questions on the statement in paragraph (a)(2) that Federal agencies may apply subparts A through E to other Federal agencies. This is an existing feature of the prior version of the guidance, which was added by OMB in 2020. See 85 FR 49506 (Aug. 13, 2020), at 49520. OMB's current plain language revisions throughout subparts A through E of part 200—replacing the term “non-Federal entity” with “recipient,” “subrecipient,” or both—may present additional questions on how specific provisions apply or may apply to Federal agencies.
In response to questions on this topic, OMB first reiterates, as explained above, that the revisions related to the use of the terms “non-Federal entity,” “recipient,” and “subrecipient” do not directly change the existing scope or applicability of the guidance. Section 200.101 continues to provide Federal agencies discretion on whether to apply subparts A through E of part 200 to other Federal agencies. Next, OMB's 2020 preamble did not affirmatively require application of part 200 to Federal agencies; rather, it clarified that the Federal agencies “ may apply the requirements of . . . part 200 to other Federal agencies . . . to the extent permitted by law” and “ as appropriate.” 85 FR 49506 (Aug. 13, 2020), at 49520 (emphasis added). To the extent that applying part 200 as a whole, or a particular provision of part 200, to a Federal agency would conflict with applicable Federal law, those provisions should not be applied to the Federal agency. For example, applying both part 200 and provisions of the FAR would present certain conflicts.
OMB also clarifies that its plain language revisions replacing “non-Federal entity” with “recipient,” “subrecipient,” or both, are not intended to indicate that a Federal agency is a recipient of Federal financial assistance in any formal sense under Federal law when provisions of part 200 are applied to it. ^3 Just as a Federal agency did not become a “non-Federal entity” when the prior version of the guidance was applied to it, a Federal agency does not actually become a recipient of Federal financial assistance when the revised version of the guidance is applied. Unlike other entities—such as non-Federal entities and for-profit organizations—Federal agencies carrying out Federal program activities with Federal funds cannot fairly be described as “recipients” of Federal assistance. ^4
^3 See United States DOT v. Paralyzed Veterans of Am., 477 U.S. 597, 612 (1986) (finding that program “owned and operated” by the United States “is not `federal financial assistance' at all.”). See also Jacobson v. Delta Airlines, 742 F.2d 1202, 1213 (9th Cir. 1984) (air traffic control and national weather service programs are owned and operated by the Federal government and therefore they are not recipients of federal financial assistance).
^4 Paralyzed Veterans, 477 U.S. at 612.
OMB understands commenters' desire to seek additional guidance on the applicability of various section to foreign public entities and foreign organizations. However, the application of the guidance to such entities is at the discretion of Federal agencies.
OMB also added a new paragraph (a)(4) in the final guidance. This new paragraph explains that throughout subparts A through E, when the word “or” is used between the terms “recipient” and “subrecipient,” any requirements or recommendations in the relevant provisions of this part apply to the recipient, the subrecipient, or both, as applicable. The use of “or” between recipient and subrecipient does not mean that applicable requirements or recommendations only apply to one of these entities unless the context clearly indicates otherwise. OMB determined that this change was warranted to clarify its more extensive usage of these terms in part 200 in this update. In final guidance, OMB relocated the proposed paragraph (b)(1) on use of “must,” “should,” and “may,” to a new location as paragraph (a)(3).
Regarding the applicability table in the prior version of the guidance at paragraph (b), OMB disagrees that the table provided greater clarity. OMB made some technical edits to the narrative description of applicability under this section, but did not restore the table from the prior version of the guidance in the final version.
In the final guidance, paragraphs (b) and (c) are now structured to address the applicability of part 200 to Federal financial assistance under paragraph (b) and contracts awarded under the FAR in paragraph (c). In both paragraphs, OMB generally sought to maintain alignment with the content of the prior version of the guidance, but did make some changes to clarify the prior guidance in some cases. The removal of the applicability table from the prior version of the guidance resulted in this restructuring. Paragraph (b) also continues to include language on requirements flowing down to recipients and subrecipients. In response to some commenters, OMB did not find the need to move this language to a different paragraph.
OMB agreed with commenters on making changes to paragraph (b) to eliminate references to procurement contracts under the FAR, which were referenced in the applicability table in the prior version of the guidance. Except on the topic of audits, OMB struck language in paragraph (b) related to procurement contracts under the FAR and relocated this guidance to paragraph (c). Paragraph (c) in the prior version of the guidance already contained cost-reimbursement contracts under the FAR, but OMB now also incorporates the guidance from the applicability table on fixed-price contracts under the FAR in slightly modified form. OMB also clarified and streamlined some of the guidance in this paragraph. The guidance provides that in cases of conflict between the requirements of applicable portions of part 200 and the terms and conditions of the contract, the terms and conditions of the contract and the FAR prevail.
In paragraph (b), OMB added guidance on applicability of the cost principles to fixed amount awards. Section 200.101(b)(4)(ii) now explains that only sections 200.400(g), 200.402 through 200.405, and 200.407(d) from subpart E apply to fixed amount awards. This topic is discussed in more detail below. In response to the comment that subpart F should not apply to fixed amount awards based on applicability of other subparts to these awards, OMB disagrees. The audit requirement under subpart F continue to apply. The commenter's interpretation that subparts C, D, and E do not apply to fixed amount awards is also incorrect—although subpart E only has limited applicability to these awards as explained in the guidance text. Fixed amount awards must comply with applicable Federal statutes (including the Single Audit Act), regulations, and applicable provisions of part 200, as well as with the terms and conditions of the Federal award.
Regarding comments seeking clarification of the applicability of part 200 to specific Federal assistance programs, OMB cannot list every program that may have a statutory exception to the guidance. Federal agencies can provide information to applicants and recipients on this topic.

Section 200.102—Exceptions
In section 200.102, OMB proposed multiple clarifying revisions to improve agency and recipient understanding of the availability and use of exceptions to, or deviations from, OMB's Uniform Guidance in part 200. A few commenters expressed support for the proposed changes.
OMB received a request to explicitly create an exception to the competition requirements and Federal clause requirements for adhesion contracts. Additionally, two commenters noted concern about explicit authority for deviations where there is no statutory prohibition. They suggested that this could make the Federal award process more challenging.
One commenter expressed concern over the removal of the requirement of maximum uniformity. Also, another commenter suggested that OMB clarify that the exception provision does not apply to Project Labor Agreement (PLA) utilization, local hire preferences, scoring methods, organizing efforts, and employee misclassification.
One commenter suggested OMB restore the text for this section from the prior version of the guidance. Another commenter suggested enhancing OMB's authority as the primary oversight entity.
OMB Response: In the proposed guidance, OMB did not intend to change the policy in section 200.102 in a significant way. In the final version of the guidance OMB restored some language from the prior version of the guidance, but did not make a significant change on the policy for exceptions. The final version of the guidance in this section is structured in three paragraphs: OMB class exceptions are addressed in paragraph (a), statutory and regulatory exceptions are addressed in paragraph (b), and Federal agency exceptions are addressed in paragraph (c).
OMB removed references to “deviations” in this section from the final version of the guidance. In the proposed guidance, OMB explained that a deviation would mean applying more or less restrictive requirements to Federal awards, recipients, or subrecipients. In circumstances in which OMB or a Federal agency have authority under this section to allow an exception, they also generally have authority to allow a deviation if otherwise permitted by law. In other words, an exception allowed under section 200.102 can take the form of deviation as OMB used that term—which has no official definition or meaning in the final guidance.

Section 200.103—Authorities
OMB proposed minor changes to this section to clarify authorities for the guidance. OMB revised this section in the final guidance as proposed.

Section 200.104—Supersession
In section 200.104, OMB proposed to provide a more succinct statement that part 200 supersedes previous OMB guidance issued in 2 CFR on topics including cost principles and audits for Federal financial assistance. Because part 200 has now existed for 10 years in its current format and location, OMB did not find it necessary to continue to include the detailed list identifying elements of the Uniform Guidance in part 200 previously contained in OMB Circulars or other parts of 2 CFR, subtitle A, chapter II. A commenter noted that a reference to chapter I should be changed to chapter II. Another commenter requested clarity on the meaning of the revised supersession provision.
OMB Response: In the final guidance, OMB corrected the mistake on the chapter number. OMB also revised the language in this section to clarify that part 200 superseded prior OMB guidance previously found in 2 CFR and OMB Circulars in the past. OMB is not again superseding the already-superseded guidance through this specific update. The supersession occurred through OMB's earlier updates. For example, OMB previously provided guidance in parts 215, 220, 225, and 230 of this title, which were superseded by part 200. See also discussion in section 1.215 in this preamble above.

Section 200.105—Effect on Other Issuances
OMB did not propose significant changes to this section. A commenter asked OMB to prohibit the incorporation of handbooks, manuals, and similar documents that are required to go through the rulemaking process. Another commenter suggested establishing a Research Policy Board at OMB to address implementation challenges of the guidance in 2 CFR and provide the research community with consistent and efficient policies. One commenter requested a change to the phrasing of the paragraph (a) on superseding inconsistent requirements. In particular, the commenter thought use of the words “those subparts” was unclear.
OMB Response: OMB did not significantly change the policy in this section based on the comments. OMB made a minor correction to the language in paragraph (a) to replace “those subparts” with “this part.”

Section 200.106—Agency Implementation
OMB did not propose significant changes to this section. One commenter recommended OMB further emphasize the need for Federal agencies to update their regulations to align with the Uniform Guidance. OMB provided further discussion of agency implementation elsewhere in this preamble, such as under section 1.220 above.

Section 200.107—OMB Responsibilities
OMB did not propose significant changes to this section. OMB received one comment requesting that the role of stakeholder engagement and inclusion be dedicated to either the Research Policy Board or the Council on Federal Financial Assistance. Another commenter suggested establishing a Research Policy Board at OMB to address implementation challenges and provide the research community with consistent and efficient policies. Two commenters recommended OMB include language providing that it would act as a neutral arbitrator to resolve disputes and provide oversight for the research administrative system. Lastly, another commenter suggested that section 200.107 address scenarios when recipients have concerns with agency implementation.
OMB Response: OMB did not make changes to the policy in this section. OMB considered the comments, but found they went beyond the scope of its policy aims for the current update. OMB revised this section as proposed. OMB provided further discussion of agency implementation elsewhere in this preamble, such as under section 1.220 above.

Section 200.108—Inquiries
OMB did not propose significant changes to this section. OMB received two comments regarding challenges for subrecipients in addressing the relevant Federal agency when a dispute arises between a subrecipient and pass-through entity. The comments suggested that OMB could play a more formal role in resolving conflicts between subrecipients and pass-through entities; or between recipients and Federal agencies.
OMB Response: OMB appreciates the concern raised by the commenters. However, OMB finds that establishing a formal role for itself as an arbiter of these types of disputes is not warranted at this time. Federal agencies are better suited to address the concerns raised by the commenters.

Section 200.109—Review Date
OMB did not propose significant changes to this section. OMB received several comments seeking clarification regarding the removal of language indicating that OMB would review the guidance every five years.
OMB Response: OMB's intent is to review and update 2 CFR when changes are warranted, which could be more frequently than every five years depending on the circumstances. OMB finds that inclusion of a specific number of years is not necessary.

Section 200.110—Effective Date
OMB did not propose significant changes to this section. OMB received several comments that generally addressed agency adoption of 2 CFR overall or included specific implementation questions. For example, one commenter proposed that all Federal agencies commit to one date for adoption. Another commenter proposed that agencies be required to develop and make transparent any differences between a Federal agency's and OMB's published guidance.
OMB Response: OMB recognizes challenges potentially impacting Federal financial assistance recipients, including their concerns about the timeliness of implementation of the 2 CFR guidance by Federal agencies and potential variations in their approaches. OMB finds that issuing implementation guidance within this section is not warranted at this time. OMB provided further discussion of agency implementation elsewhere in this preamble, such as under section 1.220 above.

Section 200.111—English Language
In the proposed guidance, OMB proposed to permit Federal agencies to allow a language other than English, when it is appropriate for a specific program or Federal award, for example in program reports, proposals, or official communication. The intent of this policy change was to allow for more flexibility when working in international environments or in communities where English is the not the primary language. OMB received over 30 comments in support of these proposed changes. OMB also received several comments requesting that the guidance not only allow for languages other than English, but rather that agencies be required to translate materials. Another commenter questioned whether translation costs in support of proposals be allowed under a Federal award.
OMB Response: OMB appreciates the numerous comments of support and also understands potential benefits of advancing the policy even further. However, OMB finds that requiring translation more broadly would place an administrative burden on Federal agencies and programs. At this time, allowing Federal agencies discretion is more appropriate. The range of Federal programs, recipient types, and program activities is diverse and not all Federal programs would warrant or benefit from such mandatory translation requirements. Regarding translation costs, OMB did not find it necessary to address these costs in the guidance. Translation costs may be allowable if they are allocable to the Federal award and are reasonable for the effective administration of the award; however, the allowability of such costs may depend upon the program.

Section 200.112—Conflict of Interest
OMB did not propose significant changes to this section. OMB received several comments requesting that the policy be moved to subpart D of part 200. Other commenters noted that the elements of the conflict of interest policy align with those established in the procurement standards.
OMB Response: OMB finds that the conflict of interest section is appropriately located in subpart B. OMB revised this section as proposed.

Section 200.113—Mandatory Disclosures
In the proposed guidance, based on feedback from the oversight community, OMB proposed to revise the section on mandatory disclosure to clarify that recipients and subrecipients must promptly disclose credible evidence of a violation of Federal criminal law potentially affecting the Federal award or a violation of the civil False Claims Act (FCA) (31 U.S.C. 3729-3733). OMB also proposed to revise this section to require recipients and subrecipients to provide written disclosure to the agency's Office of Inspector General. In the proposed guidance, OMB found the proposed “credible evidence” standard more appropriate because it would not require recipients, subrecipients, and applicants to make a firm legal determination that a criminal law had been violated before they were required to make a disclosure of “credible evidence” of such a violation to the Federal agency, pass-through entity (if applicable), and the agency's Office of Inspector General.
OMB received many comments in response to the proposed policy changes. For example, one commenter suggested that no changes should be made and noted that the policy would result in an increased number of frivolous claims. Some commenters suggested that the policy should continue to refer to only a “violation” of law, rather than of “credible evidence of violation.” Other commenters questioned misalignment of the disclosure requirement in this section of part 200 with the parallel disclosure requirement in the FAR applicable to Federal procurement. OMB also received several comments seeking clarification on the responsibility of subrecipients to report such information. For example, a commenter questioned whether a subrecipient has to report to all three entities (Federal agency, pass-through entity, and Office of the Inspector General) or just to the pass-through entity. OMB also received a few comments suggesting the addition of a definition of credible evidence along with examples. Finally, several commenters asked OMB to revert to language from the prior version of the guidance requiring disclosure “in a timely manner,” rather than “promptly.”
OMB Response: In the final guidance, OMB revised this requirement to better align with the disclosure requirement under the FAR. See 48 CFR 3.1003 and 52.203-13. Requiring timely disclosure of “credible evidence” of relevant violations is important to provide assurance of the integrity of applicants for, and recipients and subrecipients of, Federal financial assistance, and to protect the Federal government from fraud, waste, and abuse.
In the final guidance, the revised provision requires an applicant, recipient, or subrecipient of a Federal award to promptly disclose whenever, in connection with the Federal award (including any activities or subawards thereunder), it has credible evidence of the commission of a violation of Federal criminal law involving fraud, conflict of interest, bribery, or gratuity violations found in Title 18 of the United States Code or a violation of the civil False Claims Act (31 U.S.C. 3729-3733). The disclosure must be made in writing to the Federal agency, the agency's Office of Inspector General, and pass-through entity (if applicable).
Based on the existing use of the term “credible evidence” in the FAR, OMB did not find it necessary to provide a definition of this term in part 200. Black's Law Dictionary defines this term to mean evidence “that is worthy of belief; trustworthy evidence.” (11th ed. 2019). When the term was added to the FAR, the FAR Council explained that the “term indicates a higher standard [than reasonable grounds to believe], implying that the contractor will have the opportunity to take some time for preliminary examination of the evidence to determine its credibility before deciding to disclose to the Government.” 73 FR 67064, 67073 (Nov. 12, 2008). OMB intends the meaning of the term in the Uniform Guidance in part 200 to generally align with its meaning in the FAR.
Relatedly, the FAR preamble also provides some additional insight on the timing of disclosure requirements. Applied to the Uniform Guidance, the standard of “credible evidence” implies that the applicant, recipient, or subrecipient “will have the opportunity to take some time for preliminary examination of the evidence to determine its credibility before deciding to disclose to the Government.” Id. at 67074. This does not impose “an obligation to carry out a complex investigation, but only to take reasonable steps that the [applicant, recipient, or subrecipient] considers sufficient to determine that the evidence is credible.” Id. The use of the word “promptly” in the Uniform Guidance indicates that any such preliminary investigation should not be open-ended or extend over a longer period of time than is necessary to make a preliminary assessment of credibility. However, the use of the word “promptly” was not intended to otherwise affect this general principle on timing discussed in the FAR preamble.
Finally, a couple of commenters questioned other ways that OMB's proposed disclosure requirement misaligned with the parallel disclosure requirement in the FAR, such as failing to refer to the “commission” of a crime or specify what OMB intended by a violation “potentially affecting” the Federal award. In the final guidance, in response to such comments, OMB made two additional revisions to better align the disclosure requirement with the disclosure requirement at FAR 52.203-13.
First, OMB added the phrase “the commission of” before “a violation.” Similar to the FAR, on receipt of such evidence, the preliminary examination by an applicant, recipient, or subrecipient will involve a diligent (and reasonably prompt) internal effort to determine whether a violation has, in fact, occurred.
In addition, OMB replaced “potentially affecting the Federal award” with “in connection with the Federal award (including any activities or subawards thereunder).” Like the FAR, the disclosure requirement is broad, but there must be some nexus to the Federal award. The proposed text did not necessarily require disclosure of all criminal laws, as suggested by one commenter, but “violation of a Federal criminal law potentially affecting the Federal award.” The final guidance, in alignment with the FAR, now refers to violations that have a “connection with” a Federal award. In many cases this will encompass relevant violations “potentially affecting the Federal award,” but does not necessarily encompass all such violations with only a tenuous potential effect or connection. The term “activities” in the parenthetical includes, but is not necessarily limited to, activities described throughout OMB's guidance in part 200.
Establishing a specific mechanism for anonymous reporting is beyond the scope of the proposed changes in section 200.113, which places the responsibility on the “applicant, recipient, or subrecipient of a Federal award” to promptly make the disclosure. Anonymous reporting may also be available, but this type of reporting would not necessarily satisfy the mandatory disclosure requirement under this section if the applicant, recipient, or subrecipient could not verify that it made the required disclosure. In the new provision at section 200.217, OMB endeavored to better recognize certain legal protections for whistleblowers.

Subpart C—Pre-Federal Award Requirements and Contents of Federal Awards

Section 200.200—Purpose
One commenter noted that the sections referenced in the proposed guidance did not include the new section 200.217 on whistleblower protections.
OMB Response: OMB modified the final guidance to include reference to the new section 200.117.

Section 200.201—Use of Grants, Cooperative Agreements, Fixed Amount Awards, and Contracts
In the proposed guidance, OMB revised this section to clarify certain requirements for fixed amount awards. For example, OMB clarified that recipients are entitled to any unexpended funds under a fixed amount award if the required activities were completed in accordance with the terms and conditions of the award. OMB also clarified record retention and post award certification requirements. In addition—although no specific language was proposed—OMB sought comments on requiring additional pre-award certifications for fixed amount awards to address the potential increased risk of fraud under fixed amount awards. OMB also invited comments on appropriate pre-award certifications for fixed amount awards and noted that it may include a requirement for such certifications in the final guidance document. OMB also proposed to more specifically identify certain prior approval requirements that specifically relate to fixed amount awards.
OMB received many comments on proposed revisions related to fixed amount awards. Several comments expressed appreciation for the many clarifications OMB proposed in the draft revisions, including the clarification that program income could be generated under a fixed amount award, but would not be subject to the requirements on use of program income specified in section 200.307. Commenters also approved of the clarification that recipients of fixed amount awards are entitled to any unexpended funds if the required activities were completed in accordance with the terms and conditions of the award.
OMB received comments requesting clarification on how budgets for fixed amount awards are negotiated with recipients. A commenter asked for clarification that no review of actual costs incurred by the recipient would be required. The commenter also sought clarification on whether fixed cost awards are subject to audit. Other comments requested clarification of the recordkeeping requirements for fixed amount awards. One commenter questioned the necessity of reporting activities that were not completed at the end of the award.
OMB also received several comments requesting clarification on which subparts and sections of the guidance apply to fixed amount awards. For example, several commenters requested removal of the reference to section 200.403 (on factors affecting allowability of costs) under the certification requirement. Some of these commenters observed that the section 200.101 on applicability stated that subpart E does not apply to fixed amount awards. Commenters stated this requirement in section 200.201 could substantially hinder the use of fixed amount awards and subawards by requiring reimbursement of specific items of cost.
Next, OMB also received several comments requesting clarification on when fixed amount awards may not be used. Specifically, the commenters asked for clarity on the meaning of the statement that “fixed amount awards may not be used for programs with mandatory cost sharing requirements.” OMB also received several comments regarding the applicability of the guidance to OTA instruments.
Other commenters provided a variety of additional suggestions. Some commenters suggested OMB require a tiered risk assessment; that OMB encourage the use of fixed amount awards; that OMB remove the prior approval requirement for fixed amount subawards; and that OMB allow for fixed amount awards when the recipient will make performance-based payments. Clarification of the prior approval requirements was requested by some commenters. Some commenters also requested the guidance maintain the language of on “the level of effort . . . expended” in the final certification requirement.
OMB also received several suggestions for future revisions in response to the preamble of the proposed guidance. Regarding the possibility of requiring additional pre-award certifications for fixed amount awards, one commenter cautioned that risk mitigation measures should be designed not to pose an insurmountable burden on smaller organizations and impede timely award processing. Another commenter noted that pre-award certifications are already completed as part of the UEI registration process and that due diligence is already conducted for a responsibility determination. Rather than another set of certifications, one commenter suggested that OMB should consider explicitly expanding section 200.205, on Federal agency review of risk posed by applicants, to fixed amount awards.
OMB Response: OMB made several changes in the final version of section 200.201. Relative to the proposed guidance, OMB revised paragraph (b)(1) to replace the word “adequate” with “accurate” with respect to cost, historical, or unit pricing data for determining budgets for fixed amount awards. This change was made to provide more specificity as to the quality of information informing the final amounts of fixed amount awards.
Paragraph (b)(1) was also revised in the final guidance to clarify that budgets for fixed amount awards are negotiated with the recipient. The final guidance also clarifies that the total amount of Federal funding is determined using information from the recipient's proposal, pricing data, and subpart E. This new language supplements the first sentence of this paragraph, which had only referenced pricing information and cost principles.
OMB further revised paragraph (b)(1) in the final guidance to clarify that “routine monitoring” of the actual costs incurred is not expected—rather than “no review” as proposed. No “review” may have suggested that fixed amount awards are not subject to audit, which is not accurate.
OMB also revised the final guidance to clarify that recipients and subrecipients of fixed amount awards are subject to record keeping requirements. Paragraph (b)(1) was revised to include additional language emphasizing that records should be maintained and made available for audits. This change clarifies that fixed amount awards do not absolve the recipient of the responsibilities of making records available for review during an audit. Lastly in paragraph (b)(1), OMB added cross references to sections 200.101(b)(4)(ii) and 200.101(b)(5)(i) for clarity on how other subparts in part 200 apply to fixed amount awards, including the cost principles.
Regarding limitations on using fixed amount awards in programs that have mandatory cost sharing, OMB clarified the intent of this statement by removing the word “mandatory” before cost sharing in paragraph (b)(2). The final guidance simply states that fixed amount awards must not be used in programs that require cost sharing. To the extent cost sharing is required, this implies that the Federal agency or pass-through entity would be responsible for monitoring the recipient's or subrecipient's contributions of cost share for the purposes of verification. Therefore, financial reporting would be required, which would conflict with the provisions applicable to fixed amount awards.
OMB revised paragraph (b)(4) to require, upon conclusion of a fixed amount award, the identification of activities that were not completed. This is necessary to reduce the appropriate amount of award funding if the original scope of the project was not completed. Although the recipient is entitled to any remaining funds at the end of the award that were not used to carry out a completed program, if a recipient did not complete certain program activities, the recipient must inform the Federal agency of this. Any funds associated with costs of activities that were not completed must be returned.
OMB revised paragraph (b)(6) to apply additional prior approval requirements for revisions to fixed amount awards with regards to subaward activities and cost sharing. This change was made to more accurately capture the list of prior approvals that should be required for fixed amount awards. OMB also added additional prior approval requirements for fixed amount awards enumerated in section 200.308(f) in response to a comment seeking clarification on this topic.
The prior version of the guidance specified that budgets for fixed amount awards should be negotiated “using the cost principles . . . as a guide.” 2 CFR 200.201(b)(1) (prior version). The final guidance retains the reference to negotiating fixed amount awards using the cost principles in paragraph (b)(1), but also now clarifies in the applicability section that fixed amount awards and expenses under a fixed amount award are subject to certain cost principles in sections 200.400(g), 200.402 through 200.405, and 200.407(d). See 2 CFR 200.101(b)(4)(ii) (as revised). Considering that fixed amount awards are negotiated using the cost principles, unallowable costs should not be included in fixed amount award budgets. In addition, audit requirements in subpart F have always applied to fixed amount awards. See 2 CFR 200.101(b)(5)(i) (as revised; included in “Table 1 to paragraph (b)” in the prior version). The lack of reference to maintaining records in section 200.201 created the false impression for some that the recipient and subrecipient would not be required to maintain records or to make them available during an audit. The final guidance now clarifies that this impression is incorrect in paragraph (b)(1) of section 200.201.
OMB finds that application of some of the basic considerations of the cost principles at sections 200.402 through 200.405—particularly during the budget negotiation process—remains consistent with the use and general meaning of fixed amount awards. For example, one reason the cost principles have not historically applied to fixed amount awards is that various prior approval requirements are contained in the general provisions for selected items of cost. Requiring prior approval for selected items of cost throughout the performance period would interfere with the efficiencies provided by this type of award. OMB did not add such prior approval requirements in the final guidance. Section 200.400(g) of the final guidance also now expressly recognizes that when the required program activities are completed in accordance with the terms and conditions of the fixed amount award, the unexpended funds retained by the recipient or subrecipient are not considered profit. Thus, the final guidance continues to recognize that accountability for fixed amount awards is based primarily on performance and results—as stated directly in the definition of the term.
Many commenters asked OMB to clarify which provisions of part 200 apply—and do not apply—to fixed amount awards. Fixed amount awards, per the definition of that term in section 200.1, are a type of grant or cooperative agreement with a fixed budget. These awards are not subject to all of the same requirements as other grants, such as certain reporting and prior approval requirements, but do not relieve recipients and subrecipients of all compliance requirements. As explained in 200.101, as a type of grant or cooperative agreement, fixed amount awards are subject to multiple subparts of 2 CFR part 200, including subparts A through D. Fixed amount awards are also subject to certain cost principles in subpart E and the audit requirements in subpart F. Section 200.101(b) (as revised) now provides more specific detail. Under section 200.102, Federal agencies also retain flexibility to apply less restrictive requirements when issuing fixed amount awards, except for those requirements imposed by statute or in subpart F related to audit. Thus, certain questions posed by commenters on what requirements apply to fixed amount awards may depend on the implementation of specific Federal financial assistance programs by Federal agencies and the discretion exercised by Federal agencies under section 200.102.
In response to a question from one commenter, procurements standards in subpart D generally apply to fixed amount awards unless a Federal agency applies less restrictive requirements under section 200.102. In response to a question from another commenter: although less restrictive requirements may apply to fixed amount awards, they should not be used for unallowable activities. However, under section 200.400(g) in the final guidance, unexpended funds may be retained after satisfactory completion of the fixed amount award. In addition, under section 200.405(b), unallowable activities may receive an appropriate allocation of indirect costs in some circumstances.
Federal agencies are responsible for determining when a fixed amount award is or is not appropriate, and are also responsible for agency risk assessment procedures. Federal agencies should also exercise proper oversight of pass-through entities. For these reasons, OMB also finds that prior approval of fixed amount subawards remains appropriate. See 2 CFR 200.333 (as revised). In the final guidance, OMB did not completely remove a threshold for fixed amount subawards, but raised the threshold to $500,000. Id. (as revised). See also discussion of fixed amount subawards in section 200.333 below. OMB's policies on UEI and subaward reporting requirements are addressed separately in parts 25 and 170.
Finally, even if performance-based payments are elected, a fixed amount award must only be used if there are measurable goals and objectives and enough data is available to determine costs up front. With regards to amending the certification language to include reference to “level of effort . . . expended,” OMB disagrees that it is necessary to amend the certification in this way relative to the proposed guidance. In the final guidance, the recipient is required to certify, among other things, that it carried out the program activities in accordance with the terms of the award without reference to a specific level of effort.

Section 200.202—Program Planning and Design
In the proposed guidance, OMB expanded section 200.202 on program planning and design. For example, OMB added language encouraging Federal agencies to develop programs in consultation with the communities that will benefit from or be impacted by a program. In section 200.202, OMB underscored that Federal agencies should consider all available data, evidence, and evaluation results from past programs and coordinate with other agencies during program planning and design.
The majority of comments that OMB received requested revisions to section 200.202 that could be more appropriate for Federal agencies to implement and cannot be broadly required or implemented through OMB guidance under this update. For example, these comments requested that OMB further strengthen the policy to address program sustainability, invest in capacity building, promote partnerships, reduce requirements for nonprofits, and support “continuous improvement.” One comment encouraged “participatory grant-making,” which would allow community members to be involved in funding decisions.
OMB also received one comment requesting OMB to require recipients—as opposed to the Federal agency—to engage members of the community that would benefit from a program. OMB received several comments recommending that OMB streamline the grants process for organizations receiving Congressional earmarks. OMB received several additional comments noting that the RESTORE Act already sets forth a program design. One commenter requested that OMB encourage Federal agencies to publish results and performance frameworks and, wherever applicable, pay recipients for achievement of results against them.
OMB Response: The purpose of section 200.202 is to establish key requirements and communicate the principles or best practices associated with proper program design. However, agencies are ultimately responsible for the design, innovation, and long-term development and sustainability of these programs. The final guidance encourages community engagement, but OMB finds it unnecessary to specify one method over another for all Federal agencies and Federal financial assistance programs.
With regard to Congressional earmarks, even though funding is directed by Congress, Federal agencies still have the responsibility to ensure there is proper oversight of taxpayer dollars. Thus, a different approach specific to earmarks is not appropriate. In addition, the intent of part 200 is to provide more uniform requirements. However, OMB acknowledges that specific programs often have specific, statutory requirements. Paragraph (a)(1) recognizes that program design must be “consistent with the Federal authorizing legislation of the program.”
OMB disagrees with the suggestion to require Federal agencies to publish performance results at this time. This proposed agency requirement would require greater coordination across the Federal government prior to OMB implementing a policy change. OMB disagrees with the suggestion to pay recipients specifically for results achieved, as payments under grants and cooperative agreements should only support actual costs incurred and not serve as a reward for achieving results, which would constitute a profit.
OMB revised section 200.202(a)(5) to specify that “applicants,” and not “recipients,” should engage with members of the community when practicable during the design phase to encourage community engagement.
Relative to the proposed guidance, section 202.202(b) was also revised to add that Federal agencies should consider “evidence,” in addition to available data and evaluation results. This change was made to align with the Evidence Act and capture more accurately the relevant considerations during the program design phase.

Section 200.203—Requirement To Provide Public Notice of Federal Financial Assistance Programs
In the proposed guidance, OMB revised section 200.203 on Assistance Listings to reinforce the importance of communicating in plain language and highlighting any program-related customer service initiatives.
OMB received several comments emphasizing the importance of data standards and suggesting the inclusions of data standards in this section in general. OMB also received several comments requesting that OMB require agencies to break out the program description into elements of Project Goals, Project Objectives, and Project Performance Measurements. Another commenter questioned whether “customer service initiatives” differs from “customer service experience initiatives” used elsewhere in Federal programs.
OMB Response: OMB continues to work in concert with Federal agencies on the development of data standards. The guidance in part 200, however, is not an appropriate vehicle for mandating agency adoption of data standards at this time, which is an ongoing and iterative process that requires continued interagency coordination. In addition, section 200.203 provides information that is essential for Assistance Listings, but agencies have the authority to break out the information into more distinct categories if there is a need or benefit in doing so. OMB also revised “customer service initiatives” to “customer service experience initiatives” to align with standard Federal terminology on this topic.

Section 200.204—Notices of Funding Opportunities
In the proposed guidance, OMB revised section 200.204 on NOFOs in a number of ways to encourage Federal agencies to focus more on communicating requirements to the public in an accessible and comprehensible manner. For example, OMB proposed to include an Executive Summary requirement and to encourage agencies to use plain language when publishing opportunities. OMB also stipulated that Federal agencies should communicate program requirements specifically and clearly, as well as limit the length of program announcements. This is particularly important in consideration of applicants with less experience applying for Federal financial assistance, such as applicants from underserved communities.
OMB also revised this section in the proposed guidance by encouraging Federal agencies to identify all eligible applicants in the funding opportunity—for example, by providing greater specificity on different types of nonprofit organizations such as labor unions. In the proposed guidance, OMB sought to make NOFOs more consistent and transparent. OMB aimed to ensure that applicants are not unintentionally excluded from funding opportunities. Additionally, OMB proposed changes in section 200.204, such as encouraging agencies to provide an anticipated award date and providing additional clarifying guidance on the availability period for funding opportunities.
OMB received one comment requesting that agencies assess opportunities to further remove barriers for partnership with tribal entities. For example, OMB received several comments recommending requiring NOFOs to state the anticipated award date and agencies to adhere to the anticipated timeline. OMB also received several comments requesting that OMB break out the program description into elements of Project Goals, Project Objectives, and Project Performance Measurements. Some commenters emphasized the importance and inclusion of data standards in NOFOs as well.
OMB also received several comments regarding the Federal financial assistance application process. For example, several commenters requested that opportunities be available for 90 days rather than 60 days. Some commenters recommended that opportunities that are available for less than 30 days be approved by an agency head or delegate and that NOFOs posted for fewer than 60 days be accompanied by supporting documentation justifying the reason for the abbreviated period. Several commenters recommended that agencies offer technical assistance for the grant application process.
OMB Response: OMB did not revise the guidance substantially in response to comments received. As noted, many comments and suggestions were not entirely applicable to all Federal programs. For example, adding a required “anticipated award date” would not be feasible in all cases. Its feasibility may depend on the funding status and other factors. Federal agencies can break out the information, such as Project Goals and Objectives, if it is necessary for the program, but OMB disagrees that this should be required in all NOFOs at this time.
Beyond establishing the elements of a NOFO, this guidance also does not require any specific application process. While OMB strives to encourage more uniformity and consistency in grants processes, Federal agencies may also identify opportunities to simplify their own agency process.
OMB disagrees that revisions are necessary regarding the time for posting NOFOs and finds that the recommendation of at least 60 days is sufficient. Ultimately, it is the responsibility of the Federal agency to determine its process for approving opportunities that will be available for less than 30 days based on exigent circumstances.
OMB continues to support the removal of barriers for all organizations. The final guidance provides that Federal agencies may offer pre-application technical assistance or provide clarifying information for funding opportunities. Federal agencies must also ensure these resources are made accessible and widely available to all potential applicants. For example, agencies may post answers to questions and requests on Grants.gov.
Relative to the proposed guidance, paragraph (b) of section 202.204 was revised to state that the Federal agency may “modify” the availability period—as opposed to “extend.” This change was made to capture scenarios in which it may be necessary to shorten the availability period of a NOFO.
OMB also revised section 202.204 to add “tribal organizations” as an additional example of potentially eligible applicants. This change is relevant to removing barriers for tribal organizations. See, for example, E.O. 14112, Reforming Federal Funding and Support for Tribal Nations To Better Embrace Our Trust Responsibilities and Promote the Next Era of Tribal Self-Determination. With this change, the final guidance provides that the Federal agency should make every effort to identify in the NOFO all eligible applicants including tribal organizations.

Section 200.205—Federal Agency Review of Merit of Proposals
In section 200.205 of the proposed guidance, OMB clarified that a Federal agency should consider diversity when developing policies and procedures for merit review panels. OMB received several comments on the composition of merit review panels. One comment requested that the requirements of a NOFO and merit review be extended to recipients and not just for Federal peer review panelists. Commenters also suggested that the guidance require agencies to utilize external reviewers when the award involves technology development or acquisition. One commenter requested Federal agencies provide sufficient funding to support equitable merit review processes that truly compensate review panelists for their time and expertise. Finally, OMB received one comment suggesting that OMB require agencies to consider diversity when developing policies and procedures for merit review panels.
OMB Response: Section 200.205 was revised to apply standards more uniformly to merit review panels in general, and not simply to those panels that employ “external peer reviewers.” Therefore, the language limiting some of the guidance in this section to external peer reviewers was removed. Mandating external peer reviewers, as requested by some commenters, would be overly burdensome and not necessarily applicable to all Federal financial assistance programs. Federal agency discretion, consistent with law, will determine when it is appropriate to utilize external reviewers. On requiring compensation for review panelists, OMB disagreed with making this proposed change. The circumstances under which compensation could be provided for this purpose would need to be evaluated by Federal agencies for individual assistance programs. Thus, this decision may vary between Federal agencies and programs. OMB disagrees that this should be a universal requirement.

Section 200.206—Federal Agency Review of Risk Posed by Applicants
In the proposed guidance, in section 200.206 OMB revised the section regarding risk evaluation by using the term risk assessment as a standard term and clarifying agency requirements to appropriately review eligibility qualifications and financial integrity information. OMB also clarified that agency processes may consider any risk criteria pertinent to a program, such as cybersecurity risk or impacts on local jobs and the community. OMB further clarified that an agency may modify its risk assessment at any time during the lifecycle of an award.
One commenter suggested a modification to paragraph (d) that referenced the exclusion of parties from “receiving Federal awards [and] participating in Federal awards.” OMB also received several comments on risk assessment factors in paragraph (b) and whether fraud risks are to be considered. These comments suggested that risk assessments should be limited to determining whether the recipient can adequately manage the award and not include criteria such as impacts on local jobs and communities or history of performance. Other commenters suggested that Federal agencies should be required to consider diversity when developing policies and procedures for conducting risk assessment.
OMB Response: Paragraph (b) of section 202.206 was revised to add “fraud risks” to the list of examples of elements of a risk assessment to expand on the examples provided. OMB also agrees with the suggestion to clarify language in paragraph (d). OMB added a missing “or” to the final sentence, which now states “receiving Federal awards or participating in Federal awards.”
OMB disagrees that section 202.206 should be revised to require agencies to consider diversity when developing policies and procedures for risk assessment. Criteria provided in section 200.206 on job impacts and history of performance are only suggestions of what may be considered and not a comprehensive list of requirements.

Section 200.207—Standard Application Requirements
OMB received several comments that were not relevant to proposed changes in section 200.207. The comments stated that applications often request information that is required on other forms or systems and is therefore redundant. Commenters requested that OMB simplify the application process and make it more inclusive, as well as establish a single online grant application system.
OMB Response: OMB recognizes that there may be need for improvement in the application process for some assistance programs. Generally, this section of the 2 CFR guidance does not specify a particular application process, but only provides information on high-level standard application requirements. OMB added examples of standard forms, such as the SF-424 or the recently approved Biographical Sketch Common Form.
This update to the guidance is not the appropriate place for establishing a unified application system, which would go beyond the scope of OMB's proposed revisions in October 2023, and may not be feasible to implement through this section of part 200. Grants.gov is the primary Federal system to seek funding opportunities, but many Federal agencies, at this point in time, also have unique systems through which applicants may apply.

Section 200.208—Specific Conditions
OMB received several comments inquiring whether the guidance in section 200.208 on determinations that a recipient does not have adequate financial resources only applies if an award has a cost sharing requirement. Some commenters questioned whether financial resources as a condition is too limiting.
OMB Response: A Federal agency may make such a determination and apply specific conditions regardless of whether there is a cost sharing requirement. For example, specific conditions may be necessary to safeguard Federal funds if a recipient does not have sufficient funds to cover unforeseen expenses that are not related to the Federal program. OMB also changed “a determination that a recipient or subrecipient has adequate financial resources” to “a determination of whether a recipient or subrecipient has inadequate financial capability,” to address scenarios that may not be limited to inadequate resources.

Section 200.209—Certifications and Representations
In the proposed guidance, OMB clarified in section 200.209 that those entities who are exempt from the requirements of 2 CFR part 25 must still complete the certifications and representations by submitting the appropriate assurance form. OMB received two comments objecting to the draft language stating that a pass-through entity is authorized to require a subrecipient to submit certifications and representations annually in SAM.gov.
OMB Response: OMB revised section 202.209 to clarify that subrecipients do not submit certifications and representations as part of the award process. Subrecipients are neither required to register in SAM.gov nor submit an SF-424B. OMB agrees with the comments on this point. This was an error and OMB updated the language of the final guidance accordingly. OMB also revised the guidance to reflect that certifications and representations are updated on an annual basis.

Section 200.211—Information Contained in a Federal Award
In the proposed guidance, OMB made plain language and clarifying edits to this section. OMB also added that the archive of previous versions of the general terms and conditions, with effective dates, should be located on the Federal agency's website in the same place where current terms and conditions are available. OMB received several comments requesting that this section include a requirement that agencies provide information in Federal awards for loan and loan guarantee programs that specify whether or not the award has continuing compliance requirements. OMB also received several comments requesting OMB revise sections 200.211 and 200.301 to require Federal agencies to include more information in the Federal award about how performance will be assessed as well as the timing and scope of the expected performance and measurement. One of these commenters requested that OMB add language related to progress and performance as well as the timing and scope of continuing improvement efforts.
OMB Response: OMB revised paragraph (d) of section 200.211 to specify that the terms and conditions of loans and loan guarantee programs must specify whether there are continuing compliance requirements. This change was made to provide more specific information to auditors. OMB agrees that information on continuing compliance requirements in this context is necessary and should be required, as compliance requirements may differ depending on the structure or type of loan.
Regarding comments asking OMB to require more information on how a Federal program will be assessed, paragraph (a) of section 200.211 already provides the basic requirements for what information must be included in a Federal award on performance goals. The topic of performance measurement is addressed further in section 200.301. OMB did not expand the information requirements in section 200.211 at this time, which could potentially increase administrative burden on Federal agencies or their recipients.

Section 200.212—Public Access to Federal Award Information
In the proposed guidance, OMB proposed mostly plain language revisions to section 200.212. In the final guidance, section 200.212 was revised to reflect a change in the name of the DATA Act Information Model Schema (DAIMS) to Government-wide Spending Data Model (GSDM). OMB otherwise made revisions in this section as proposed.

Section 200.213—Reporting a Determination That an Applicant Is Not Qualified for a Federal Award
In the proposed guidance, OMB proposed mostly plain language revisions to section 200.213. OMB received one comment requesting a change to the revised text, noting that the revision implied that the notification in SAM.gov should also include an explanation.
OMB Response: This was not OMB's intent. OMB's policy is that the explanation need only be communicated in the notification to the recipient—not in SAM.gov itself. OMB revised the text to ensure the language aligns with existing policy, which is that the notification from the Federal agency should provide an explanation of the determination.

Section 200.214—Suspension and Debarment
In the proposed guidance, OMB proposed mostly plain language revisions to section 200.214. One commenter observed that OMB used “non-procurement” in this section and “nonprocurement” in 2 CFR part 180.
OMB Response: OMB revised the spelling of “nonprocurement” to align with 2 CFR part 180.

Section 200.215—Never Contract With the Enemy
In the proposed guidance, OMB proposed mostly plain language revisions to section 200.215. OMB also revised the text to explicitly state that this section applies to “subrecipients” as well. OMB received one comment requesting a revision to the applicability of requirements in 2 CFR part 183. The commenter suggested that smaller organizations serving as pass-through entities do not have the capacity to discern which parties actively oppose the U.S.
OMB Response: OMB disagrees that checking the excluded parties list contained in SAM.gov is overly burdensome for subrecipients, especially considering that SAM.gov must be checked in accordance with 2 CFR part 180 to ensure the party is not suspended or debarred. This was not a policy change, but rather a clarification to the existing use of the term “non-Federal entity.”

Section 200.216—Prohibition on Certain Telecommunications and Video Surveillance Equipment or Services
In the proposed guidance, OMB included several additions to section 200.216 on the prohibition of certain telecommunications and video surveillance equipment or services. OMB's proposed revisions expanded the guidance by incorporating additional information from OMB's earlier “2 CFR Frequently Asked Questions” guidance document on this topic. For example, OMB revised the text with the intent of clarifying how the guidance applies to program income, indirect costs, and cost sharing.
OMB received a comment indicating the certification requirement in this section stated that, upon signing an award, a recipient is certifying that funds “were not expended for prohibited costs.” The commenter stated that the certification should read that funds “will not be expended” for that purpose. Some commenters found that newly proposed paragraph (c) imposed a “use” restriction—not just a purchase restriction—on covered telecommunications equipment or services. Commenters requested clarification that covered telecommunications and covered services may be used in program activities as long as they are not procured with Federal funds.
OMB received several comments on paragraph (d). Some commenters said the proposed revision was causing confusion on how the statutory prohibition applies to funds generated as program income, indirect cost recoveries, and funds used to satisfy cost share requirements.
One commenter requested inclusion of guidance on waivers in section 200.216. OMB also received several comments requesting that the guidance include the names of prohibited telecommunication and video surveillance equipment or services.
OMB Response: OMB revised paragraph (a) of section 200.216 to better align with the definition of “covered telecommunications equipment or services” in section 889 of the John S. McCain National Defense Authorization Act (NDAA) for Fiscal Year (FY) 2019 (Pub. L. 115-232). To achieve this, OMB first restored alignment with the prior version of the guidance on the types of Federal financial assistance the prohibition applies to under the statute in paragraph (a). Next, OMB made a few technical and structural changes to provide further clarity. OMB also moved the language on “systems that use covered telecommunications equipment or services” down to a new paragraph (c)—but maintained alignment with the prior version of the guidance on this topic.
In the final guidance, OMB deleted the proposed paragraph (c), which caused concern that OMB was imposing a “use” restriction. This change clarifies that OMB is not imposing a new “use” restriction through the final guidance. Rather, the emphasis of the policy is that such items cannot be purchased with Federal funds. Loan or grant funds may be provided to a recipient that uses the covered telecommunications equipment or services, but the Federal award must not pay for the covered telecommunications equipment or services that the recipient uses. If the Federal agency suspects that the goods or services being procured under the award may in fact be prohibited, it must take appropriate action, consistent with its policies and procedures, and in accordance with the guidance in 2 CFR part 200.
In the final guidance, OMB also removed the proposed paragraph (d). However, by not including this paragraph in the 2 CFR text, OMB is not modifying the policy contained in the earlier 2 CFR FAQ published in May 2021 on this topic. That document established that costs associated with covered telecommunications equipment or services are “unallowable costs” under the Federal award. As such, although not expressly stated in the text of the final guidance, for awards involving loan or grant funds, the prohibition described in the guidance text applies to funds generated as program income. The 2 CFR FAQ also provides further information on application of this provision to indirect cost rates and funds used to satisfy cost share requirements. Because the proposed paragraph (d) was confusing to commenters, and lacked context, OMB finds that the 2 CFR FAQ is a better resource to address these topics.
OMB made a few additional clarifying edits in paragraph (e) in the final guidance in response to comments. For example, that paragraph now states that “funds will not be expended” instead of “were not expended.” OMB also revised this paragraph to clarify that there is no stand-alone certification on the prohibition of telecommunications, but that other certifications that recipients or subrecipients submit throughout the life-cycle of the Federal award will serve as certifications that they understand and accept the ban on the covered telecommunications equipment and services. These existing certifications—such as those made when submitting payment requests and reports—are sufficient.
The subject of waivers is covered in paragraph (d) of section 889 of the NDAA for FY 2019 (Pub. L. 115-232). However, unlike Federal procurement, the statutory prohibition cannot be waived by Federal agencies for Federal financial assistance such as grants and loans. Finally, in response to another comment, the prohibited parties are included in the guidance text. They are also listed as excluded parties in SAM.gov.

Section 200.217—Whistleblower Protections
In the proposed guidance, OMB included a new section 200.217 to expand on the whistleblower protections and requirements recognized in part 200 for recipients of Federal financial assistance, which had previously been referenced in section 200.300. In the final guidance, section 200.217 was revised to add a requirement that recipients and subrecipients must inform their employees in writing of Federal whistleblower protections provided by law.

Subpart D—Post Federal Award Requirements

Section 200.300—Statutory and National Policy Requirements
Section 200.300 has consistently explained that Federal agencies must administer Federal awards consistent with applicable Federal law, including the provisions of the Constitution and Federal statutes and regulations that apply to any given award. Section 200.300 does not impose any new legal obligations. OMB's proposed revisions to section 200.300 were consistent with that longstanding approach. Specifically, OMB proposed to streamline section 200.300 and to reference existing nondiscrimination requirements under applicable law, including in light of the Supreme Court's decision in Bostock v. Clayton County, 140 S. Ct. 1731 (2020).
OMB received numerous comments on the proposed revisions to section 200.300. Many supported OMB's proposal. For example, commenters commended OMB for proposing to maintain section 200.300's guidance that, in administering Federal financial assistance programs, agencies must adhere to applicable legal requirements, including nondiscrimination requirements. Commenters highlighted the importance of applicable nondiscrimination requirements to specific populations, including LGBTQI+ populations, even while emphasizing that all people can experience discrimination. And commenters observed that OMB's proposal was consistent with Executive Order 13988 of January 20, 2021 (Preventing and Combating Discrimination on the Basis of Gender Identity or Sexual Orientation).
Some supportive commenters also recommended additional revisions. For example, commenters recommended that OMB require agencies to specifically enumerate the statutes that prohibit discrimination in implementing OMB's guidance. Others suggested that section 200.300 should clarify that, consistent with Bostock' s reasoning, Federal awards must be implemented in a way that would prohibit discrimination based on sex characteristics, including intersex traits. Finally, commenters urged OMB to ensure that nondiscrimination requirements are maintained uniformly through the performance of all foreign assistance contracts, grants, and cooperative agreements provided by Federal agencies.
OMB also received many comments opposing OMB's proposed revisions to section 200.300. Some commenters maintained that Bostock applies only to employment decisions under Title VII of the Civil Rights Act and does not apply to other laws that prohibit sex discrimination. Another commenter maintained that because the Court in Bostock used the terms “transgender” or “transgender status,” the Court's holding does not extend to “gender identity.” This commenter requested that OMB clarify what constitutes discrimination under section 200.300. Several commenters also disagreed with Bostock.
With respect to proposed section 200.300(c), some commenters observed that the Fourteenth Amendment's Equal Protection Clause does not apply to the Federal government, and maintained that it neither applies to non-governmental actors nor applies heightened constitutional scrutiny to differential treatment based on sexual orientation or gender identity. On this topic, one commenter also asserted that the proposed section 200.300(c) “cherry picks” one constitutional provision and only as it concerns scrutiny with respect to sexual orientation and gender identity.
Some commenters also questioned the authority of OMB and Federal agencies implementing part 200 to impose the policy reflected in section 200.300 as a condition of the Federal award. For example, one commenter questioned whether agencies have legal authority to impose the proposed paragraphs (b) and (c) as a condition in the case of Federal statutes that do not prohibit discrimination on the basis of sexual orientation and gender identity. This commenter also maintained that agencies are prohibited from imposing substantive requirements under the Housekeeping Statute, 5 U.S.C. 301. Another commenter claimed that, under the major questions doctrine, Congress has not clearly delegated authority to OMB to impose nondiscrimination requirements with respect to all Federal financial assistance programs.
OMB also received many comments asserting that the proposed section 200.300 would inadequately protect free speech and religious liberty. For example, commenters criticized OMB for proposing to delete language noting that, among other illustrative examples, in administering Federal awards consistent with applicable law Federal agencies must adhere to laws protecting free speech and religious liberty. One commenter suggested that OMB's proposed revisions were “singling out” or “favoring” only certain constitutional protections. Another maintained that the proposed section 200.300 would “threaten[ ] compulsory speech upon creative professionals.”
On the topic of religious liberty, commenters expressed concern that OMB's proposed revisions may violate the Constitution's First Amendment or the Religious Freedom Restoration Act (RFRA), 42 U.S.C. 2000bb et seq. Related to this concern, commenters noted that Bostock recognized religious liberty protections that can be relevant to claims of sex discrimination under Title VII. Additional commenters suggested that the proposed section 200.300 would make it more difficult for faith-based organizations to receive Federal financial assistance, and others suggested adding a new paragraph to section 200.300 recognizing constitutional protections for religious liberty.
OMB Response: OMB appreciates all of the comments received on the proposed section 200.300 and is finalizing it with clarifying revisions. Because many commenters, supportive and otherwise, misperceived the effect of section 200.300 and the proposed revisions, OMB emphasizes two points at the outset. First, the structure of 2 CFR part 200 generally requires Federal agencies to implement all of its provisions, including section 200.300, consistent with their legal authority and the particular statutes and regulations governing each of their Federal financial assistance programs. See 2 CFR 200.106. 200.101(d); see also 78 FR 78590, 78619 (Dec. 26, 2013). Second, section 200.300 in particular does not impose any new legal requirements. Rather, its scope is limited to explaining that Federal agencies must implement their Federal financial assistance programs consistent with other, existing legal requirements that apply of their own force to the agency's programs. See 88 FR 69395; see also 88 FR 69391. For example, paragraph (a) refers to “ applicable Federal statutes” (emphasis added); paragraph (b) refers to “Federal awards that are subject to Federal statutes prohibiting discrimination based on sex” and to “administer[ing]” programs “in a way that does not unlawfully discriminate based on sexual orientation or gender identity” (emphases added); and paragraph (c) refers to “the heightened constitutional scrutiny that may apply” in certain contexts (emphasis added)—all references to preexisting legal requirements.
The fact that agencies will implement section 200.300 consistent with their authorities and that section 200.300 imposes no new legal requirements is responsive to a wide range of comments, including those urging OMB to revise section 200.300 so as to extend nondiscrimination requirements to foreign assistance; maintaining that OMB lacks legal authority to impose a nondiscrimination policy with respect to all Federal financial assistance programs; requesting that OMB clarify what constitutes discrimination under section 200.300; questioning agencies' authority to impose provisions of section 200.300 as specific conditions in programs that are not subject to a statute prohibiting discrimination based on sexual orientation and gender identity; arguing that agencies may not impose substantive requirements pursuant to the Housekeeping Statute; and asserting that the Constitution does not protect against differential treatment based on sexual orientation or gender identity. All of these comments are premised on the misimpression that section 200.300 creates or imposes new nondiscrimination requirements. It does not. The determination of whether any kind of discrimination is prohibited in any individual Federal financial assistance program depends on the laws applicable to that program, not section 200.300(b), and agencies will make relevant assessments on a program-by-program basis.
Thus, contrary to some comments, section 200.300(b)'s reference to discrimination based on sexual orientation and gender identity does not impose any new nondiscrimination requirements. Section 200.300(b) merely explains that, if a statute prohibits discrimination based on sex, and if the statute's prohibition on sex discrimination encompasses discrimination based on sexual orientation and gender identity consistent with the Supreme Court's reasoning in Bostock, then the Federal agency or pass-through entity must ensure that the award is administered in a way that does not unlawfully discriminate based on sexual orientation and gender identity. OMB has revised section 200.300(b) to make the scope of the section clearer in this respect.
Comments asserting that Bostock was wrongly decided are outside the scope of these revisions, but OMB disagrees with those arguing that Bostock' s reasoning applies only to employment decisions under Title VII, or to “transgender status” and not “gender identity.” Several courts of appeals have held, and the Department of Justice's Civil Rights Division has concluded, that under Bostock' s reasoning a number of sex discrimination statutes prohibit discrimination on the basis of gender identity, sexual orientation, and sex characteristics. ^5 Again, though, given the structure of part 200 and the scope of section 200.300, for any particular Federal financial assistance program subject to a law prohibiting discrimination based on sex, the agency administering the program will assess the law as appropriate to determine whether, consistent with Bostock' s reasoning, the law prohibits discrimination based on gender identity and sexual orientation. In section 200.300, OMB is not purporting to interpret any particular sex discrimination statute.
^5 See, e.g., A.C. by M.C. v. Metro. Sch. Dist. of Martinsville, 75 F.4th 760, 769 (7th Cir. 2023); Grabowski v. Arizona Bd. of Regents, 69 F.4th 1110, 1116-17 (9th Cir. 2023); Doe v. Snyder, 28 F.4th 103, 113-14 (9th Cir. 2022); Grimm v. Gloucester Cnty. Sch. Bd., 972 F.3d 586, 616 (4th Cir. 2020), as amended (Aug. 28, 2020), cert. denied, 141 S. Ct. 2878 (2020) (mem.); Department of Justice, Civil Rights Division, Interpretation of
Bostock v. Clayton County
regarding the nondiscrimination provisions of the Safe Streets Act, the Juvenile Justice and Delinquency Prevention Act, the Victims of Crime Act, and the Violence Against Women Act, (Mar. 10, 2022), https://www.justice.gov/crt/page/file/1481776/download; Department of Justice, Civil Rights Division, Memorandum on Application of
Bostock v. Clayton County
to Title IX of the Education Amendments of 1972 (Mar. 26, 2021), https://www.justice.gov/crt/page/file/1383026/download; Department of Justice, Civil Rights Division, Title IX Legal Manual, https://www.justice.gov/crt/title-ix (Editor's Note). But see, e.g., L.W. by & through
Williams v. Skrmetti, 83 F.4th 460 (6th Cir. 2023); Pelcha v. MW Bancrop, Inc., 988 F.3d 318, 324 (6th Cir. 2021); but cf.
Adams v. School Bd. of St. Johns Cnty, 57 F.4th 791, 811-15 (11th Cir. 2022) (en banc).
Regarding comments observing that OMB proposed to explicitly reference certain protections while removing explicit examples of others, including free speech and religious liberty, OMB intended to streamline and is not deemphasizing laws establishing those latter protections. Rather, paragraph (a) states that Federal financial assistance programs must comply with all applicable Federal laws. Concerns that particular applications of section 200.300 would run afoul of protections for free speech or religious liberty in the Constitution and other Federal laws, including RFRA, cannot be squared with paragraph (a)'s text. But to eliminate any confusion and allay concerns that OMB was singling out certain protections, in paragraph (a) OMB has retained the references to free speech, religious liberty, and other examples of potentially relevant and applicable protections, all of which are illustrative only. Relatedly, with respect to paragraph (b), OMB acknowledges that in Bostock the Court noted that it was not addressing how certain “doctrines protecting religious liberty interact with Title VII,” leaving those questions “for future cases,” 140 S. Ct. at 1754; agencies will apply the law on these issues at it develops. And OMB has revised paragraph (c) to refer to all characteristics that may give rise to heightened constitutional scrutiny under equal protection principles, including race, religion, sex, sexual orientation, gender identity, sex characteristics, and others.
Comments asserting that section 200.300 will make it more difficult for faith-based organizations to receive Federal financial assistance and requesting that OMB provide a mechanism for those organizations to seek religious accommodations are misplaced given the structure of part 200 and scope of section 200.300, as explained above. Because section 200.300 does not impose any new legal obligations, it will not affect faith-based organizations' participation in agencies' Federal financial assistance programs, and any requests for accommodations are appropriately addressed to the agency administering the particular program. As stated in section 200.300(a), awards must be implemented in full accordance with applicable provisions of the Constitution and Federal statutes and regulations, including those protecting religious liberty such as the First Amendment's Free Exercise and Establishment clauses and RFRA.
Finally, in response to comments pointing out that the Fourteenth Amendment's Equal Protection Clause does not apply to the Federal government, OMB has revised section 200.300(c) to confirm that it is referring to the Fifth Amendment's equal protection guarantee, which does apply to the Federal government. See Bolling v. Sharpe, 347 U.S. 497, 499 (1954). Related comments questioning how section 200.300(c) can apply to recipients ignore that part 200 provides guidance to Federal agencies, not recipients. Indeed, section 200.300(c) states what “the Federal agency” must do: in administering awards in accordance with the Constitution, they must take account of heightened scrutiny that may apply.

Section 200.301—Performance Measurement
OMB did not propose significant changes to this section. Many commenters expressed support for OMB's clarification that Federal agencies should not require additional information that is not necessary for measuring program performance. One commenter requested that OMB require Federal agencies to consult with recipients on the proposed measurement, reporting, and evaluation framework and requirements before finalizing them in a Federal award. Another asked OMB to clarify what is meant by “promising practices.” Several commenters requested that OMB reinstate the examples of expected outcomes in paragraph (b). Lastly, some commenters requested that the section be revised to require Federal agencies to include information in the Federal award about how performance will be measured. These commenters also requested OMB to expand the measurement of performance to specifically include measuring the recipient's progress, which they stated may support continuous improvement of the recipient's performance.
OMB Response: OMB did not find it necessary to require Federal agencies to consult with recipients on the proposed measurement, reporting, and evaluation framework before a Federal award is finalized in all cases. This recommendation could be a best practice for agencies to consider, but OMB finds that mandating this practice is not appropriate in part 200 at this time. The term “promising practices” may vary by Federal agency and program.
OMB agrees with the commenters on reinstating the examples of expected outcomes in paragraph (b). These examples are again included in the text of the final guidance. Finally, Federal agencies are already required to include information on how performance will be measured in section 200.211(a). OMB disagrees with the commenters that this section needs to be expanded further through this update.

Section 200.302—Financial Management
OMB did not propose significant changes to this section. One commenter stated that it is not possible to reasonably assess the financial management systems of foreign subrecipients. Another commenter stated that OMB's plain language revisions diluted the requirement to identify all Federal awards. One commenter requested that this section be revised to exclude fixed amount awards. Several commenters stated that the inclusion of the term “Federal award year” was causing confusion.
OMB Response: This section does not directly require recipients to assess the financial management systems of subrecipients, but states the requirements that the subrecipient must meet. OMB agrees with a commenter that the proposed revision in paragraph (b) was confusing. OMB first clarified in the final guidance that the financial management systems of recipients and subrecipients must meet the requirements that follow. OMB also restored more of the language from the prior version of guidance in paragraph (b)(1), which may have been obscured by OMB's proposed revisions. OMB also made minor clarifying edits in paragraph (b)(3) in the final guidance. OMB disagrees with the commenters that this section should not apply to fixed amount awards and did not make a change related to those comments.

Section 200.303—Internal Controls
In the proposed guidance, OMB added a requirement in paragraph (e) of section 200.303 that recipient and subrecipient internal controls include cybersecurity and other measures to safeguard information. OMB also proposed other minor clarifying edits.
OMB received several comments requesting that the guidance specify what constitutes proper documentation of internal controls under paragraph (a). The same commenters also noted that paragraph (a) of section 200.303 indicated that internal controls should “comply” with the listed practices, which the commenter stated was overly prescriptive. Some commenters objected to the inclusion of the requirement to “document” internal controls. Many commenters stated that the guidance should be revised to incorporate the requirements of NIST SP 800-53 or other existing frameworks in paragraph (e) to ensure that the internal control requirements are not onerous and a barrier to participation. Commenters also requested that OMB reinstate the word “reasonable” in paragraph (e).
OMB Response: In section 200.303(a), OMB agrees with commenters that internal controls should “align” rather than “comply” with guidance in the listed standards. The word “align” more accurately reflects OMB's policy intent for this section.
Several commenters also expressed concerns about the addition of the word “document” in paragraph (a). OMB does not consider this a policy change but rather clarification of the existing policy already contained within the guidance. The prior version of the guidance already stated that internal controls should comply with guidance in “Standards for Internal Control in the Federal Government” issued by the Comptroller General of the United States or the “Internal Control Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Both include guidance on documenting internal controls. It is reasonable to expect that if a recipient has established internal controls, some form of written documentation should exist for them. However, it was not OMB's intent to require a specific level of documentation. As recognized in the Standards for Internal Control in the Federal Government, the recipient or subrecipient may use some judgment in determining the extent of documentation that is needed. The level and nature of documentation may vary based on the size of the recipient or subrecipient and the complexity of the operational processes it performs.
For the purposes of this update, OMB disagrees with commenters on requiring a specific framework for cybersecurity and other measures used to safeguard information. OMB did not propose changes to establish a specific framework in the guidance and generally maintains the guidance in paragraph (e) as proposed. However, OMB will continue to evaluate whether to implement a specific framework on a government-wide basis in the future. OMB agrees with commenters that this is a topic worthy of consideration for future updates. In the interim, Federal agencies may consider providing more specific guidance on this topic as appropriate for their Federal financial assistance programs.
OMB did make two minor changes to paragraph (e). First, OMB agrees with commenters to maintain the word “reasonable” from the prior version of the guidance when describing actions necessary to safeguard information. OMB added the word “reasonable” back to the guidance text in place of “as appropriate,” which appeared later in the sentence as proposed. However, OMB does not intend to signal a substantive policy change by this modest revision to restore the word “reasonable” from the prior version of the guidance text as requested by commenters. This merely recognizes, as the guidance text implies, that the recipient and subrecipient have some reasonable discretion on the appropriate framework for safeguarding information as required by this section.
Next in paragraph (e), OMB restored the phrase “and other types of information” following protected PII. This language is consistent with the prior version of the guidance and recognizes that not only protected PII must be safeguarded.

Section 200.304—Bonds
OMB did not propose significant revisions to section 200.304. OMB made a minor change to correct its proposed plain language revision. The word “entity” was removed after “recipient.”

Section 200.305—Federal Payment
In section 200.305 on Federal payment, OMB proposed to provide additional flexibilities for recipients when interest bearing accounts are not accessible in a foreign country; and to provide a specific link for returning funds to the Payment Management System, rather than including the more extensive instructions in the guidance itself.
OMB received several comments requesting that the guidance promote up-front payments. OMB also received one comment regarding paragraph (b)(1) and inquiring what is meant by “minimum amounts needed.” OMB received another comment regarding the use of “may” and “must” in paragraph (b)(4).
Next, OMB also received a comment requesting that subrecipients be removed from the section on advance payments. The same commenter requested that paragraph (b)(2) be revised to state that payments “may be consolidated.” This commenter also requested that the recipient be provided with a 30-day notice before a withholding action is taken due to a debt to the government. The commenter also requested that aspects of the compliance supplement that impact section 200.305 be incorporated in the guidance text. Another commenter also requested that OMB increase the amount of interest a recipient or subrecipient be permitted to retain to $1,000. Other comments requested additional options for recipients and subrecipients to not use interest bearing accounts as a result of conflict or disaster. Finally, OMB received multiple comments about the use of “and” and “or” for recipients and subrecipients.
OMB Response: Regarding comments requesting that the guidance promote up-front payments, the guidance in section 200.305 already recognizes advance payments as the default payment method for recipients and subrecipients, other than States, when the relevant criteria can be met. Paragraph (b)(1) explains that the “recipient or subrecipient must be paid in advance, provided it maintains or demonstrates the willingness to maintain written procedures” meeting the relevant criteria. OMB finds it is appropriate to retain the policy that advance payments must only be for actual, immediate cash requirements in carrying out the purpose of the approved program or project—except as otherwise provided in this paragraph and section of the guidance.
On comments requesting further clarification of paragraph (b) and some of the sub-paragraphs that follow, OMB made some clarifying edits in the final version of the guidance. Some of these edits reincorporate language from the prior version of the guidance, which OMB proposed to remove in the course of its plain language revisions. Upon review, particularly in paragraph (b)(1), OMB found that some of the language proposed for removal provided useful context and clarity on the meaning of the guidance. Thus, OMB restored much of the language in paragraph (b)(1).
Next, for comments on paragraph (b)(2), the prior version of the guidance already provided some flexibility by framing the sentence with “whenever possible.” Thus, advance payment requests by the recipient or subrecipient must be consolidated as described, but some flexibility is allowed if this is not possible under the circumstances.
On the comment regarding the use of “may” and “must” in paragraph (b)(4), OMB finds that these terms are used appropriately. They also remain consistent with the prior version of the guidance.
Regarding Paragraph (b)(6)(ii), OMB disagrees that specifying a timeframe before taking a withholding action is necessary. Reasonable notice is still required but—as in the prior version of the guidance—OMB does not specifically define a standard for what notice is reasonable within the guidance. OMB also made minor revisions to correct confusion caused by OMB's plain language revisions in this paragraph. As proposed, it was not clear which party was supposed to withhold payments, which OMB has now clarified.
Regarding the comment requesting removal of subrecipients from the paragraphs on advance payments: subrecipients were always to be paid in advance if they meet the requirements of this section. Next, on comments requesting OMB increase the amount of interest a recipient or subrecipient is permitted to retain to $1,000, OMB disagrees. For this update, OMB retained the level at $500.
In response to comments asking for additional options other than interest bearing accounts for recipients and subrecipients to use in circumstances involving conflict or disaster, such options may already exist under paragraph (b)(11)(v) depending on the circumstances involved. That provision allows an exception when an interest-bearing account is not readily accessible. The example in the parenthetical is illustrative only. Lastly, OMB reviewed its use of “and” and “or” for recipients and subrecipients. The language in the final guidance reflects OMB's intent on how specific requirements apply. However, OMB added additional clarifying guidance on this topic in section 200.101(a)(4).

Section 200.306—Cost Sharing
OMB proposed to revise section 200.306 on cost sharing, as well as the definition of cost sharing itself, to clarify that “matching” is one category of cost sharing overall—thus eliminating the need to repeat the term “matching” throughout. OMB also proposed to provide additional guidance on voluntary uncommitted cost sharing for institutes of higher education. OMB received several comments expressing support for the proposed changes.
OMB received several comments requesting that OMB maintain the use of the word “matching” throughout, citing for example, that this change would require additional updates to other policies, such as the compliance supplement. OMB also received several comments requesting that the topic of cost share should only be included in the NOFO when cost share is mandated by the program.
Regarding paragraph (a), several commenters suggested that “may” should be changed to “must.” The same commenters suggested that pass-through entities should also be referenced in paragraph (a). Commenters also recommended that OMB revise the policy to state that voluntary committed cost share is not expected in the case of all Federal financial assistance—not just in the case of Federal research grants. Commenters also requested that OMB remove the guidance stating that cost share may be required if permitted by agency regulations and specified in the NOFO.
OMB also received several comments requesting a policy requiring agencies to consider proposed financial matches made by outside investors, philanthropists, corporations, or other organizations to count as a cost share or leverage towards the project. Several comments also inquired about the use of cost sharing over matching. Other commenters asked OMB to discourage or prohibit matching requirements. One commenter asked OMB to amend the guidance to include language that would not require an applicant to have secured commitments for all cost share prior to the Federal award. Another comment recommended paragraphs (d) through (g) be combined to create a single fair market value approach for all items. Another commenter asked OMB to remove paragraph (b)(5) in section 200.306 and paragraph (f) in 200.403. Finally, OMB received several comments requesting clarification and changes to paragraph (k) in section 200.306.
OMB Response: Regarding comments on the elimination of the term “matching,” OMB disagrees and maintains that this change is appropriate. “Matching” is a type of cost share, as provided in the definition in section 200.1. OMB acknowledges that certain supplemental materials, such as the compliance supplement, may need revision to ensure consistency with the updated guidance.
On comments asking OMB to further discourage or prohibit cost sharing for Federal financial assistance in general, cost sharing requirements may vary on a program-by-program basis. For example, mandatory cost sharing requirements may be imposed based on a program's authorizing statute or at the discretion of the Federal agency, consistent with its legal authorities, through a NOFO. OMB did not make significant changes on cost sharing requirements through this update.
In the case of voluntary cost sharing, however, since 2013, paragraph (a) of section 200.306 has already prohibited Federal agencies from using voluntary committed cost sharing as a factor during the merit review of applications or proposals for Federal research grants unless authorized by Federal statutes or agency regulations and specified in the NOFO. See 78 FR 78590 (Dec. 26, 2013). OMB now includes language in the final guidance stating that Federal agencies are also discouraged—but not prohibited—from using voluntary committed cost sharing as a factor during the merit review of applications for other non-research Federal financial assistance programs. While the existing provision on Federal research awards serves to provide a more level playing field in that context—allowing more applicants to compete for research awards—OMB is uncertain of what impact such a prohibition could have on Federal agency practice or other assistance programs if implemented more broadly for non-research awards. Thus, through this update, OMB only discourages the practice of using voluntary cost sharing as a factor during the merit review of applications or proposals for non-research Federal financial assistance programs, but leaves Federal agencies with discretion, consistent with their legal authorities, on this topic. OMB may consider comments on this topic for future updates.
OMB disagrees with commenters that paragraph (a) should be applied to pass-through entities. Based on its references to notices of funding opportunity, the paragraph is structured to apply to Federal agencies, not to pass-through entities, which are not required to conduct the same form of merit reviews.
OMB also did not remove guidance in paragraph (a) stating that voluntary committed cost sharing for research awards may be considered in merit review if permitted by agency regulations and specified in the NOFO. OMB leaves Federal agencies with discretion, consistent with law, on this topic.
On comments regarding paragraph (b), OMB revised the guidance to clarify that a Federal agency or pass-through entity must accept any cost sharing funds—including cash and third-party in-kind contributions, and also including funds committed by the recipient, subrecipient, or third parties—as part of the recipient's or subrecipient's contributions to a program when the funds meet the conditions listed in this paragraph. For the comments asking OMB to require agencies to consider proposed financial matches made by third parties, such matches would be recognized if they meet the conditions in paragraph (b).
Next, regarding the comment suggesting combination of paragraphs (d) through (g), OMB did not propose a policy change to these paragraphs. OMB may consider this suggestion for future updates.
OMB did not agree with the commenter suggesting removal of paragraph (b)(5) in section 200.306 and paragraph (f) in 200.403 through this update. In this final guidance, OMB retained the default restriction on a recipient proposing to use funds from another Federal award as cost share unless the program's authorizing statute specifically allows doing so. OMB may consider this suggestion for future updates.
OMB reverted to the prior version of the guidance in paragraph (f) in section 200.306. The proposed revision inadvertently impacted the policy for this provision, which was not OMB's intent.
On comments requesting changes and clarification to paragraph (k), OMB maintained the reference to voluntary uncommitted cost sharing only with respect to IHEs in alignment with OMB Memorandum M-01-06. The different treatment referenced in both the memorandum and guidance text is related specifically to IHEs. OMB also agrees with commenters that voluntary uncommitted cost sharing consists of more than just faculty donated time and clarified the section to indicate that it includes, but is not limited to, faculty donated time.

Section 200.307—Program Income
OMB proposed to revise section 200.307 on program income by clarifying paragraph (a) regarding the use and expenditure of program income, including allowing the use of program income for certain closeout costs. OMB also proposed to revise and clarify guidance in paragraph (b) for each of the three methods for use of program income. OMB received several comments expressing support for the proposed changes.
OMB received one comment requesting clarification on how program income should be handled if earned after the period of performance. OMB also received several comments questioning the policy that program income be expended prior to requesting additional Federal funds. Commenters questioned whether this policy should continue to be included in the guidance.
Commenters also requested revisions to paragraphs (b) and (b)(2). Commenters stated there was a conflict in the language as to what method should be applied when no program income method is selected by an agency.
OMB also received a comment requesting clarification on whether more than one method of program income may be used under an award. OMB received several comments requesting clarification on what closeout costs may be paid for by program income. OMB also received several comments requesting the guidance to provide agencies with the ability to allow recipients to retain program income balances after the period of performance has ended.
One commenter also requested that the default method for program income be “addition.” The commenter also requested OMB remove the prior approval requirement for calculation of program income based on “net” program income, rather than gross program income. Another commenter asked OMB to change the default program income method from the deduction method to the cost sharing method. Finally, OMB received one comment suggesting that the guidance on program income be removed in its entirety.
OMB Response: OMB disagrees with comments questioning the policy under paragraph (a) that program income be expended prior to requesting additional Federal funds. This is a long-standing feature of section 200.307 on program income, which OMB did not propose to change through this update.
In response to comments requesting that “addition” or “cost sharing” be the default method for program income, the default method in this paragraph is only used when a method is not specified by the Federal agency. Thus, the default method in the final guidance is not necessarily the default method that will be used in practice by all agencies for specific programs or awards. OMB disagrees, however, with changing the default method from the deduction method when an agency does not specify. OMB did not change the policy in paragraph (d) on the cost of generating program income.
Regarding the comment requesting clarity on whether more than one method of program income may be used under an award, OMB made a minor revision in paragraph (b) to clarify that the Federal agency must specify in the terms and conditions what “method(s)” must be followed. This change recognizes that more than one may be used for different aspects of a project or program if specified by the Federal agency.
On comments requesting revisions to paragraphs (b), (b)(2), and (b)(3), OMB revised all three provisions for clarity. The prior approval requirement for using the addition or cost sharing methods is now explained only in the top-level paragraph (b).
On comments requesting clarity on what closeout costs may be paid for by program income, OMB included a reference in paragraph (a) to the guidance on allowable closeout costs in section 200.742(b). On the comment requesting guidance on how program income should be handled if earned after the period of performance: this topic is addressed in paragraph (c).
In response to comments requesting flexibility for Federal agencies to allow recipients to retain program income balances after the period of performance has ended, OMB appreciates the commenters' suggestions. While OMB made no change through this final guidance document, it may consider the suggestion for future updates. Finally, in response to the comments suggesting that the guidance prohibit program income, eliminate certain other provisions on program income OMB retained from the last guidance, or remove the guidance on program income altogether, OMB disagrees that such changes are appropriate.

Section 200.308—Revision of Budget and Program Plans
OMB proposed changes to section 200.308 on revision of budget and program plans by combining the requirements for construction and non-construction awards to provide greater uniformity in the requirements for all award types. OMB proposed to clarify that recipients do not need approval of individual subrecipients under all circumstances, but only when making subawards of programmatic activities not proposed by the recipient in the application for an award. A Federal agency may also require prior approval of subrecipients through the terms and conditions of a Federal award. OMB proposed to further clarify that agencies should not require approval of a change in a proposed subrecipient unless the initial inclusion of a subrecipient was a determining factor in the agency's merit review process. This change was proposed to reinforce the role of the recipient as responsible for the efficient and effective administration of the Federal award including the selection of a qualified and capable subrecipient. OMB also proposed to identify other items requiring prior approval, including requesting additional funds, transferring funds, and no-cost extensions. OMB proposed to clarify that no-cost extensions are different from one-time extensions, which an agency is permitted to authorize a recipient to do without prior approval. OMB received several comments expressing support for the proposed changes.
OMB received several comments requesting separate distinctions be made for construction and non-construction awards and to provide a definition of construction awards. One commenter requested OMB to revise paragraph (a) to reflect the definition of budget in section 200.1. Another commenter asked for clarification of the term deviation in paragraph (b). OMB received a recommendation from several commenters to improve the language of paragraph (c). The same commenters suggested that OMB extend the notification requirement in paragraph (d) from 30 days to 60 days. Another commenter asked that paragraph (e) be clarified.
OMB also received several comments suggesting that the guidance permit an agency to waive all prior approval requirements in 200.308. OMB received another comment requesting clarification that prior approval is not needed for the addition of subrecipient organizations under paragraph (f).
Several comments requested clarity on when a change in key personnel is needed under paragraph (f)(2). OMB received another comment requesting that OMB define key personnel as those named in the Federal award and subaward. Commenters also asked OMB to clarify in paragraph (f)(3) of the guidance if prior approval is necessary for the disengagement of a principal investigator by 25 percent or more than 25 percent. The same commenters also requested that paragraph (f)(3) be revised to state: “Key personnel are not required during a period of no cost time extension to commit additional effort beyond that which was originally approved in an award notice.”
Several commenters asked OMB to clarify paragraph (f)(4). OMB received one comment suggesting that paragraph (f)(4) does not lessen the administrative burden felt by recipients. OMB received one comment requesting that the prior approval for transferring between participant support costs to other budget categories in paragraph (f)(5) be removed.
Other commenters requested OMB clarify the intention of paragraph (f)(6) by this language: “This requirement does not apply to acquiring equipment, supplies, or general support services.” Commenters also requested OMB revise the guidance in paragraph (f)(6) to indicate that, if agencies relied on the subrecipient partner as part of its merit review, the agency should state this in the terms and conditions of the Federal award. OMB received several comments requesting clarification on subaward prior approval under paragraph (f)(6). Several commenters also asked OMB to remove language from section paragraph (f)(6) limiting when prior approval of a change to a subrecipient should be required to circumstances when “the inclusion was a determining factor in the merit review or eligibility process.” OMB received one comment requesting OMB remove aspects of paragraph (f)(6) that enable an agency to approve a different subrecipient partner. A commenter also requested that OMB remove certain language from paragraph (f)(6) regarding whether the “inclusion [of a subrecipient] was a determining factor in the merit review or eligibility process.”
Next, a commenter asked OMB to remove the “total” out of “total approved cost share” in paragraph (f)(7) and revert to the original language. OMB received one comment requesting the guidance clarify the difference between construction and non-construction work in paragraph (f)(9). OMB also received a comment requesting clarity on what is meant by an extension of time that requires no additional funds under paragraph (f)(10). Another comment requested clarity on the parameters of no-cost extensions under paragraphs (f)(10) and (g)(2) and whether the requirements apply to pass-through entities.
OMB received a request to clarify that allowable costs incurred prior to the start of the next budget period are not pre-award costs under paragraph (g)(1). OMB received one comment requesting OMB encourage Federal agencies to simplify and streamline the process for no-cost extension pre-approvals where they are necessary. The commenter also recommended that OMB consider extending the guidance in paragraph (h) to State governments.
Lastly, OMB received one comment requesting that the guidance specify where agencies must indicate that they are restricting transfers in accordance of paragraph (i).
OMB Response: OMB revised paragraph (a) of section 200.308 to clarify that the approved budget may include the Federal share and non-Federal share, or only the Federal share, as determined by the Federal agency or pass-through entity. On this change, OMB agrees with a commenter requesting that paragraph (a) reflect the definition of budget in section 200.1.
OMB revised paragraph (c) to permit Federal agencies to approve alternative formats for receiving budget revisions. OMB also provided some examples of alternative formats, and specified the need to document such alternative forms of request. This broadens the flexibility available under the prior version of the guidance, which only mentioned a letter of request.
OMB disagrees with the comment requesting extension of the notification requirement in paragraph (d) to 60 days. OMB made a revision, however, to indicate the agency or pass-through entity “should” provide notice within 30 days. This change was made to account for conflicts where Federal agency approval is also necessary.
Regarding the comment requesting clarification to paragraph (e), OMB agrees and revised the sentence to more clearly state the policy. OMB revised paragraph (f)(2) to clarify that a change in key personnel is only required for those who are identified in the Federal award. OMB agrees with comments asking for clarity on this point. OMB disagrees with comments asking for a specific definition of key personnel. In the context of this provision, however, OMB provides illustrative examples of key personnel.
On the comments asking for clarity on disengagement by a principal investigator under paragraph (f)(3), the guidance references “a 25 percent reduction in time and effort devoted to the Federal award.” Revising to “more than” 25 percent in this update would make a marginal difference, which OMB did not find necessary. OMB also disagrees with commenters suggesting further revisions to paragraph (f)(3); the current text reflects OMB's policy intent.
OMB revised paragraph (f)(4) to restore text from the prior version of the guidance. OMB was concerned that proposed plain language revisions may have altered the meaning of this provision, and reverted back to the prior text. OMB disagrees with comments suggesting that paragraph (f)(4) may present excessive administrative burden.
In response to a comment, OMB revised paragraph (f)(6) to clarify that the provision does not apply to procurement transactions for goods and services. However, OMB disagrees that further revisions are necessary in response to comments suggesting that the terms and conditions of a Federal award should state whether an agency relied on a subrecipient partner as part of the merit review. In this context, the current language is already responsive to this comment. In response to the comments requesting that OMB remove language from paragraph (f)(6) limiting when prior approval of a change to a subrecipient should be required, this is recommended guidance to Federal agencies to relieve the burden on recipients. In response to another comment on this paragraph, the requirement for prior approval is needed if a portion of the programmatic activities that were to be performed by a recipient will now be performed by a subrecipient. The change in a subrecipient partner, however, is not required unless approval is required in the terms and conditions of the Federal award.
OMB disagrees with the comment suggesting removal of the word “total” from “total approved cost share” in paragraph (f)(7). The inclusion of “total” better reflects the intent of the prior approval requirement. On the comment asking OMB to provide further guidance to differentiate between construction and non-construction work in paragraph (f)(9), this decision is often made at a programmatic level by a Federal agency. Federal agencies may provide further guidance on the categories in the terms and conditions of a Federal award. OMB revised paragraph (f)(10) to clarify that a no-cost extension means an extension of time that does not require the obligation of additional Federal funds.
OMB disagrees with the comment suggesting extension of the guidance in paragraph (h) to State governments. This provision does not apply specifically to any particular recipient group, but rather is based on the nature of the work being conducted—research awards. OMB disagrees with the comment asking OMB to specify where agencies must indicate that they are restricting transfers in accordance of paragraph (i). Federal agencies may elect to include the restriction in the Federal award or their standard terms and conditions.
On the comment requesting clarification on the term deviation under this section, OMB did not find that additional clarification is necessary in the guidance text. It is up to the Federal agency and recipient to ascertain what may or may not be considered an action that departs from the standard course for a given program.
On the comment requesting clarification that prior approval is not needed for the addition of subrecipient organizations, OMB finds that further clarification is unnecessary. It is left to the discretion of the Federal agency to include such a term in the Federal award.
OMB disagrees with the comment requesting that the prior approval for transferring between participant support costs to other budget categories be removed. OMB does not make a change. OMB also disagrees with the comment suggesting that a Federal agency be permitted to waive all prior approval requirements. OMB finds this would not be an appropriate revision.
On the comment asking OMB to encourage Federal agencies to simplify and streamline the process for no-cost extension pre-approval, the process for approvals is not specified by OMB's guidance. OMB did not revise the guidance to address this topic at this time.
On the comment asking OMB to clarify that allowable costs incurred prior to the start of the next budget period are not pre-award costs, OMB finds this clarification is unnecessary. The start of a new budget period does not constitute a new award and therefore would not be considered pre-award costs by definition.
In response to a comment asking for clarity on the parameters of no-cost extensions and whether the requirements apply to pass-through entities, the guidance on no-cost extension applies strictly to Federal agencies. The parameters for no-cost extensions are at the discretion of the agency.

Section 200.309—Modifications to Period of Performance
In section 200.309 on modifications to the period of performance, OMB proposed to provide additional clarification that when an agency decides not to continue an award with multiple budget periods, the period of performance should be amended to end at the completion of the currently authorized budget period. OMB also proposed to incorporate the definition of “renewal award” in this section.
OMB received a comment suggesting that the proposed revision may have the unintended consequence of allowing a Federal agency or pass-through entity to unilaterally extend an award. Another comment suggested that the proposed revisions implied that an agency may terminate an award for convenience.
OMB Response: OMB's proposed revisions in this section were not intended to allow a Federal agency or pass-through entity to unilaterally extend an award. As such, OMB clarified in the final guidance that the role of the Federal agency and pass-through entity is to approve an extension to a Federal award.
In response to the comment suggesting that OMB's proposed revisions to this section would allow a termination by convenience by the Federal agency: the guidance in this section merely provides direction for how to adjust the period of performance based on actions addressed more specifically in other sections of the guidance, such as extending or terminating a Federal award. In the final version, OMB removed proposed text from this section on how to amend the period of performance in circumstances in which a Federal agency decides not to continue a Federal award with multiple budget periods. The final guidance continues to recognize that the start date of a renewal award begins a new and distinct period of performance. OMB's guidance on termination is provided in section 200.340 and discussed in this preamble below.

Section 200.310—Insurance Coverage
OMB did not propose significant changes to this section. One commenter asked OMB to revise this section to indicate that what is required is like treatment of like items, not like treatment of all items.
OMB Response: OMB finds the intent of the guidance is sufficiently clear. A recipient or subrecipient must, at a minimum, provide equivalent insurance coverage for real property and equipment paid for with Federal funds, as they would provide for real property equipment that they purchased with their own funds.

Section 200.311—Real Property
In section 200.311, addressing real property, OMB proposed to include a new paragraph on appraisals to introduce additional guidance on standards for conducting independent appraisals consistent with the Uniform Relocation Assistance and Real Property Acquisition Policies Act of 1970, as amended, (42 U.S.C. 4601-4655) except as provided in the implementing regulations at 49 CFR part 24, “Uniform Relocation Assistance And Real Property Acquisition For Federal And Federally-Assisted Programs.” OMB also proposed to include a definition of the term “encumbrance” in sections 200.311, 200.313, and 200.315.
A commenter asked OMB to allow Indian Tribes to place on-reservation real property acquired in a Federal award in trust for general Tribal governmental purposes and use the property as such during the fee-to-trust process. Other commenters asked for further clarification on what is meant by the statement that “real property must be used for the originally-authorized purpose as long as it is needed for that purpose” and how the guidance applies to various Federal programs. OMB also received several comments requesting the addition of a definition for encumbrance in section 200.1 and the removal of the text from sections 200.311, 200.313, and 200.315. Another comment asked OMB to revise the definition of encumbrance to include that a Federal agency should not require subordination of any pre-existing encumbrance. One commenter asked OMB to revise the guidance to prevent Federal agencies from directing recipients to sell real property even if a recipient prefers to retain the property and compensate the agency. OMB also received a comment suggesting that the real property guidance in this section include additional flexibilities similar to those provided for equipment.
OMB Response: OMB revised paragraph (b) of section 200.311 to remove the proposed definition of encumbrance and clarify that easements that benefit real property are not considered an encumbrance. OMB did not include a specific definition of encumbrance in section 200.1 for the reasons explained in subpart A of this preamble above. OMB finds that the term “encumber” is sufficiently clear in context in which it is used in this section without OMB providing a specific definition. See also discussion of the term “encumbrance” in this preamble above. OMB elected not to define that term in part 200.
A commenter asked OMB to clarify that ordinary and necessary easements in favor of utility, cable and other service providers that benefit the real property will not be deemed an encumbrance. OMB agrees with this suggestion and incorporated similar language in section 200.311 of the final guidance. OMB recognizes that utility related easements are routinely granted, typically enhance rather than diminish the value of property, and may facilitate development for authorized purposes under the Federal award.
OMB revised paragraph (c) of section 200.311 to clarify that the requirements of this provision only apply when an appraisal of real property is required under the Federal award. On the comment regarding real property acquired by Indian Tribes, OMB may consider providing additional guidance on this topic in future updates, but did not propose substantive changes to the policy as it relates to this comment in its proposed revisions.
OMB may also consider providing other additional guidance on, or clarifying edits to, section 200.311 in future updates, but did not make further substantive changes to the policy. For example, the policy that real property must be used for the originally-authorized purpose as long as it is needed for that purpose—which received many comments—remains unchanged. The policy on vesting of real property “acquired improved under a Federal award” also remains the same as it appeared in the proposed revisions. While there may be some variations between Federal agencies and programs in implementation of this section—such as in the context of Federal financial assistance provided in response to disasters—OMB cannot address all possible scenarios in the government-wide guidance, which remains substantially similar to the guidance initially provided in this section in 2013 on this topic.
OMB disagrees with the comment asking OMB to prevent Federal agencies from directing recipients to sell real property in accordance with this section. Such decisions are left to the discretion, consistent with law, of the Federal agency.
OMB did not make a policy change in response to the comment asking for additional flexibilities under this section similar to those in the section on equipment. Although not included in this update, OMB may consider this suggestion for additional updates in the future.

Section 200.312—Federally-Owned and Exempt Property
OMB did not propose significant changes to this section. OMB received one comment requesting that Indian Tribes be allowed to acquire excess Federally-owned property at fair market value.
OMB Response: OMB may consider providing additional guidance on property acquired by Indian Tribes in future updates, but did not include substantive changes to the policy as it relates to the above comment in the final guidance.

Section 200.313—Equipment
In section 200.313, relating to equipment, OMB proposed to increase the threshold value for equipment from $5,000 to $10,000 and to provide additional guidance on the meaning of a “conditional title.” Consistent with proposals in sections 200.311 and 200.315, OMB also proposed a definition of the term “encumbrance.” Consistent with the existing requirements for States, OMB also proposed to allow Indian Tribes to dispose of equipment in accordance with tribal law. OMB also proposed to clarify that agencies may permit the recipient to retain equipment with no further obligation to the Federal government when it is not prohibited by Federal statue or regulation. OMB also proposed to reinforce the responsibility of recipients to maintain updated records regarding equipment. OMB received several comments expressing support for the proposed changes.
OMB received several comments requesting the addition of a definition for encumbrance in section 200.1 and the removal of the text from 200.311, 200.313, and 200.315. One commenter suggested that section 200.313 be revised to include language on leasehold improvements.
One commenter asked OMB to update paragraph (b) to include language regarding subrecipients for consistency with other sections. Another commenter asked OMB to update guidance in paragraph (c)(2) to clarify that Federal agencies should not require the use of equipment on other programs supported by the Federal Government. The commenter stated that additional use would cause additional or accelerated wear and tear. OMB received several comments regarding paragraph (d)(3), including on OMB's use of “must” in that paragraph.
OMB also received several comments requesting that the threshold for equipment in paragraph (e) be raised above $10,000. Another commenter opposed raising the threshold for equipment to $10,000. This commenter requested OMB incorporate usage and accountability requirements for items between $5,000 and $10,00 that are considered “attractive” or subject to misappropriation. One commenter also noted that paragraph (e)(2)—related to proceeds from selling equipment—should be revised to “$1,000” instead of “$1,000 or 10 percent (whichever is less).” Several commenters also asked OMB to expand paragraph (f) to refer to subrecipients.
OMB Response: OMB revised paragraph (a)(2) of section 200.313 to remove the proposed definition of encumbrance. OMB did not include a specific definition of encumbrance in section 200.1 for the reasons explained in subpart A of this preamble above.
OMB revised paragraph (b) to clarify that recipients and subrecipients other than States and Indian Tribes, including subrecipients of a State or Indian Tribe, must follow paragraphs (c) through (e) of section 200.313.
OMB did not revise paragraph (c)(2) relative to what was proposed. On the comment asking about the requirement under paragraph (c)(2) to make equipment available for use on other programs supported by the Federal Government, this requirement is generally implemented at the discretion of the Federal agency, which may assess whether use on other projects would interfere with the purpose for which it was originally acquired.
OMB made no change to paragraph (c)(3). The paragraph already recognizes that a Federal authorizing statute would prevail in cases of conflict. See also 2 CFR 200.101(d) (as revised).
OMB made a minor edit in paragraph (d) to use “replacement equipment” in place of “replacing equipment.” OMB revised paragraph (d)(1) to clarify that a subrecipient is also responsible for maintaining and updating property records. OMB revised paragraph (d)(3) to modify the proposed reporting requirement for equipment loss, damage, or theft that will impact a program to a notification requirement.
OMB did not make changes to paragraph (e)(1). In response to the comments asking OMB to raise the threshold for equipment above $10,000, OMB does not find this warranted at this time and did not make a change. Regarding the comment suggesting additional requirements for equipment valued between $5,000 and $10,000, OMB finds this request would be overly burdensome to recipients. OMB did not make a change.
OMB revised paragraph (e)(2) to clarify that recipients or subrecipients may be permitted to retain, from the Federal share, $1,000 of the proceeds to cover expenses associated with the selling and handling of the equipment. OMB agrees with commenters that “$1,000 or 10 percent (whichever is less)” should be revised to just state “$1,000.” Based on the updated threshold for equipment under paragraph (e), there would not be a circumstance in which 10 percent would be lower than $1,000.
OMB revised paragraph (f) to clarify that Federal agencies may authorize pass-through entities to allow subrecipients to retain equipment. OMB agrees with some of the commenters on this topic. In the final guidance, OMB allows the pass-through entity to receive permission from Federal agencies to allow subrecipients to retain equipment without further obligation. The provision specifies, however, that permission must be included by the Federal agency in the terms and conditions of the award. Thus, a pass-through entity could not exercise this flexibility independently.
In response to the comment requesting the addition of language on leasehold improvements, OMB made no policy change to this section on that topic through this final guidance. OMB may consider the comment for additional updates in the future.

Section 200.314—Supplies
OMB proposed to revise section 200.314 on supplies to raise the threshold from $5,000 to $10,000. OMB also proposed to clarify that the requirements for unused supplies apply to the aggregate value of all supply types, and not just like-item supplies. OMB also proposed to include a definition of “unused supplies” in section 200.314. OMB received several comments expressing support for the proposed changes.
OMB received one comment asking OMB to clarify the meaning of unused supplies that are in new condition. OMB also received several comments requesting that the threshold for equipment and supplies be raised above $10,000. One commenter noted that OMB's guidance on the proceeds for selling unused supplies should be revised to refer to “$1,000” and not “$500 or 10 percent (whichever is less)” to be consistent with the requirements for equipment. Several commenters also asked OMB to revise the guidance to allow for unused supplies to be retained.
OMB Response: OMB revised paragraph (a) of section 200.314 in the final guidance to clarify that recipients or subrecipients may be permitted to retain, from the Federal share, $1,000 of the proceeds to cover expenses associated with the selling and handling of the supplies. OMB agrees with the commenter who recommended revising the guidance this way. OMB also made a minor edit to delete a duplicated word.
On the comment requesting clarity on the meaning of unused supplies that are in new condition, OMB finds the guidance to be sufficiently clear. New condition means not having been used or opened before.
On comments asking OMB to raise the threshold for supplies above $10,000, OMB does not find this warranted in this update. OMB did not make a change at this time.
On comments asking OMB to allow unused supplies to be retained, OMB does not agree that this should be the government-wide default. OMB did not make a change in this update, but may consider this recommendation for future updates. Even under the structure of the current guidance, however, Federal agencies would have authority under section 200.102(c) to exercise reasonable discretion in providing case-by-case exceptions to allow retention of unused supplies.

Section 200.315—Intangible Property
In section 200.315 on intangible property, OMB proposed to reinforce the potential requirement for recipients and subrecipients to make intangible property publicly available on agency-designated websites. Consistent with proposals in sections 200.311 and 200.313, OMB also proposed a definition of the term “encumbrance.”
OMB received several comments requesting the addition of a definition for encumbrance in section 200.1 and the removal of the text from sections 200.311, 200.313, and 200.315.
Commenters also asked OMB to revise guidance in 200.315 to state that copyright in works voluntarily created by a recipient or subrecipient are not considered acquired under a Federal award.
Several commenters also supported OMB's proposed guidance to make intangible property publicly available on agency-designated websites. A few of the commenters requested additional clarification on this topic.
Lastly, several commenters noted that access to Federally funded data is a priority for a variety of reasons, including transparency, regulatory review, impact analysis, and program evaluation. For example, one commenter called for greater data transparency for the purposes of regulatory review of impact analysis; another commenter called for greater access to Federally funded data for the purposes of administrative evaluation and policy development; another commenter drew attention to data quality issues and the need for greater transparency; another commenter emphasized the importance of data gathering program evaluation and transparency; and another commenter stated that agencies sometimes use FOIA and FOIA exemptions to inhibit access to information by outside stakeholders.
OMB Response: OMB revised paragraph (a) of section 200.315 to remove the proposed definition of encumbrance. To avoid any confusion, OMB removed the definition of encumbrance from sections 200.311, 200.313, and 200.315. OMB did not include a specific definition of encumbrance in section 200.1 for the reasons explained in subpart A of this preamble above.
OMB did not revise paragraph (b) of section 200.315 in response to comments requesting recognition of a new category of “voluntarily created works,” which would not be considered “acquired” under a Federal award. The suggestion would create confusion and unnecessary regulatory burden by inserting an unclear distinction between “voluntarily created” works and “acquired” works. It would also be unclear whether title to such “voluntarily created works” would vest in the Federal government, the recipient, the subrecipient, or some other entity. Section 200.315(b) reserves certain rights of the Federal government for works acquired or developed under a Federal award, including “a royalty-free, nonexclusive, and irrevocable right to reproduce, publish, or otherwise use the work for the government's purposes and to authorize others to do so.” This license limits the ability of the recipient or subrecipient to exercise certain rights—which are subject to the Federal government's license against the government or those authorized by the government. Inclusion of the new language proposed by commenters on “voluntarily created works” would create confusion regarding the scope of the government's license, which is a long-standing feature of OMB's government-wide guidance on this topic. OMB did not propose substantial changes to the license through the proposed guidance issued in October 2023 and did not make any such changes in the final guidance.
The term “work” in paragraph (b) is a term of art in copyright. This term is better fitted under paragraph (b), which speaks only to copyright and not all intangible property. Paragraph (b) also refers to works “developed” or “acquired” under a Federal award. This removes the burden of attempting to determine whether a “work” was “voluntarily” created or not.
If commenters' concerns on this topic were based on the newly proposed definition of “encumbrance” in this section, that definition is not included as part of the final guidance text. Although OMB made minor revisions, it generally aimed to preserve the status quo on the government's license and other provisions in paragraphs (a) and (b) relative to the prior version of the guidance.
OMB added a new paragraph (f) in the final guidance in response to comments noting that access to Federally funded data is a priority for a variety of reasons. The new paragraph reminds agencies of their responsibilities to provide public access to research data, possibly through exerting their Federal purpose licenses when needed, with appropriate privacy and confidentiality protections. The new language also reminds agencies to rely on FOIA to provide access only as a last resort. Specifically, the new paragraph (f) states that Federal agencies should work with recipients to maximize public access to Federally funded research results and data in a manner that protects data providers' confidentiality, privacy, and security. The new paragraph also states that agencies should provide guidance to recipients to make restricted-access data available through a variety of mechanisms. Finally, the new paragraph states that FOIA may not be the most appropriate mechanism for providing access to intangible property, including federally funded research results and data.

Section 200.316—Property Trust Relationship
OMB did not propose significant changes to this section. OMB received several comments pertaining to this section. A few commenters requested the section be deleted in full while others requested the section be clarified.
OMB Response: OMB did not make any changes to this section. OMB appreciates the feedback and may consider comments for future updates. Any significant revisions to section 200.316 would go beyond the scope of OMB's proposed update.

Section 200.317—Procurements by States and Indian Tribes
OMB proposed several revisions to the procurement standards in the Uniform Guidance. In recognition of Tribal sovereignty, and consistent with the existing requirements for States, in section 200.317, OMB proposed to allow Indian Tribes to follow their own policies and procedures. OMB received several comments expressing support for the proposed changes in this section.
One commenter requested a revision of the guidance to allow for local governments to follow their own procurement standards, rather than those in section 200.318. Another commenter requested revision of the guidance to acknowledge that some recipients or subrecipients might be subject to the procurement standards of a State or Indian Tribe.
OMB Response: Under the final version of section 200.317, OMB states that, except for States and Indian Tribes, all other recipients and subrecipients, including subrecipients of a State or Indian Tribe, must follow the procurement standards in sections 200.318 through 200.327.
On the comment requesting OMB to allow local governments to follow their own procurement standards, rather than those in section 200.318, OMB did not make a change through this update of the guidance. Beyond extending the provision to Indian Tribes, OMB did not propose a further expansion for public comment.
OMB also disagrees with a commenter suggesting that it was necessary to also permit other recipients and subrecipients, which are not States or Indian Tribes, to apply this provision if subject to procurement standards of a State or Indian Tribe. Recipients and subrecipients subject to procurement standards of a State or Indian Tribe should not, in most cases, be precluded from following them under the general procurement standards in section 200.318 (as revised). If conflicts arise in particular cases, a recipient or subrecipient may request a case-by-case exception from the Federal agency under section 200.102(c) (as revised). OMB declines, however, to further expand the types of recipients and subrecipients that section 200.317 applies to in the way proposed by the commenter. OMB updated this section in the final guidance as proposed.

Section 200.318—General Procurement Standards
OMB also proposed to revise the procurement standards in section 200.318. These proposed revisions included providing additional guidance that contractors appropriately classify employees consistent with the Fair Labor Standards Act. See the Fair Labor Standards Act at 29 U.S.C. chapter 8.
OMB also proposed adding a new paragraph (l) in section 200.318 to clarify that the procurement standards in part 200 do not prohibit recipients or subrecipients from using Project Labor Agreements or similar forms of pre-hire collective bargaining agreements; requiring commitments or goals to hire people residing in high-poverty areas, disadvantaged communities as defined by the Justice40 Initiative OMB Memorandum M-21-28, or high-unemployment census tracts within a region no smaller than the county where a federally funded construction project is located, consistent with the policies and procedures of the recipient or subrecipient, provided that a recipient or subrecipient may not prohibit interstate hiring; requiring commitments or goals to individuals with barriers to employment (as defined in section 3 of the Workforce Innovation and Opportunity Act (29 U.S.C. 3102(24)), including women and people from underserved communities as defined by Executive Order 13985; using agreements intended to ensure uninterrupted delivery of services; using agreements intended to ensure community benefits; or offering employees of a predecessor contractor rights of first refusal under a new contract. The proposed paragraph explains that Federal agencies may consider allowing recipients or subrecipients to use such practices if consistent with the U.S. Constitution, applicable Federal statutes and regulations, the objectives and purposes of the Federal financial assistance program, and other requirements of part 200. For example, OMB explained in its proposal that any hiring preference for a class or groups of persons would be permissible only to the extent that it is consistent with the equal protection requirement of the U.S. Constitution.
OMB received several comments expressing support for the proposed changes in section 200.318. OMB received a few comments requesting that reference to local governments be retained in paragraph (c)(2). Other comments expressed some concerns with paragraph (l) and made suggestions for revisions. Some commenters observed that while the guidance does not prohibit the listed labor practices, the final sentence seems to indicate that use of the practices remains contingent on Federal agencies allowing recipients to use them.
OMB also received several comments requesting numerous changes that were not proposed for public comment. For example, some commenters requested that the guidance include new language stating that it is permissible for recipients to take steps to ensure that employees of contractors are paid a living wage.
OMB Response: OMB revised paragraph (c)(1) to add reference to a “board member” in the context of conflicts of interest. OMB revised paragraph (c)(2) to restore the reference to local governments. OMB agrees with the comments asking OMB to retain the reference from the prior version of the guidance to local governments in this paragraph.
OMB removed the proposed sentence in paragraph (k) stating that proper oversight “does not relieve the recipient or subrecipient of any of its contractual responsibilities.” Commenters suggested that OMB may have changed the meaning of the sentence by introducing the concept of “proper oversight.” OMB recognizes commenters' concerns and reverted to language stating that these “standards do not relieve the recipient or subrecipient of any contractual responsibilities under its contracts.”
OMB revised paragraph (l) of section 200.318 to clarify that recipients and subrecipients “may use” the listed practices if consistent with the U.S. Constitution, applicable Federal statutes and regulations, the objectives and purposes of the applicable Federal financial assistance program, and other requirements of this part. However, OMB's revision is not necessarily intended to prevent Federal agencies from having any role in assessing whether the listed practices are consistent with the standard in what is now paragraph (l)(2). For example, a Federal agency may be in the best position to determine if use of one of the listed practices would be consistent with authorizing laws that apply to that agency's programs or the objectives and purposes of those programs.
Aside from minor edits to fix the structure of the section and other typographical changes, OMB did not make further changes, but appreciates the commenters' additional feedback, which OMB will consider for future revisions. The labor and employment practices listed in paragraph (l) are intended as illustrative examples of practices that are not prohibited by the procurement standards in subpart D. It is not feasible for OMB to provide an exhaustive list of all such practices, but the fact that an alternative practice is not expressly included in the list in paragraph (l) does not necessarily mean that it is prohibited.

Section 200.319—Competition
In section 200.319, OMB proposed to remove the prohibition in the Uniform Guidance on using geographic preference requirements. In the same section, OMB also proposed to state that subpart D does not prohibit recipients and subrecipients from incorporating a scoring mechanism that rewards bidders committing to specific numbers and types of U.S. jobs, as well as certain compensation and benefits. In its proposed guidance, OMB cautioned, however, that any geographic preferences or scoring mechanisms must be consistent with the U.S. Constitution, applicable Federal statutes and regulations, and the terms and conditions of the Federal award. OMB also proposed to clarify that any such scoring mechanism must be consistent with established practices and legal requirements applicable to the recipient or subrecipient. OMB received several comments expressing support for the proposed changes.
One commenter opposed the removal of the prohibition on using geographic preferences. This commenter stated that it may cause confusion among the recipients or subrecipients of the Federal award. The commenter stated that the guidance should retain clear parameters on when geographic preferences may be used.
Similar to section 200.318, OMB also received several comments requesting numerous changes that were not proposed for public comment. For example, some commenters requested that the guidance include new language stating that it is permissible for recipients to take steps to ensure that employees of contractors are paid a living wage. OMB also received several comments questioning removal of the word “develop” and insertion of the word “assist” in paragraph (b).
OMB Response: OMB revised paragraph (b) of section 200.319 to clarify that contractors that “develop or draft” specifications, requirements, statements of work, or invitations for bids must be excluded from competing on those procurements. OMB agrees with comments on this topic and replaced the word “assist” with “develop or draft.”
Relative to the proposed guidance, OMB revised paragraph (c) to replace “examples of requirements” with “examples of situations.” This revision restored the reference to “situations” in the prior version of the guidance.
On the comment opposing the removal of the prohibition on using geographic preferences, section 200.300 is relevant to the commenters' concerns. As discussed above, that section provides that the Federal agency or pass-through entity must manage and administer the Federal award in a manner that ensures implementation in full accordance with the U.S. Constitution and applicable Federal statutes and regulations. Thus, any geographic preferences used under a Federal award must be consistent with governing law outside of part 200. At least in some circumstances, Federal agencies may retain an important role in working with the recipient on reviewing the permissibility of geographic preferences under a Federal award.
OMB did not make any further changes to this section, but appreciates the commenters' additional feedback, which OMB may consider for future revisions.

Section 200.320—Procurement Methods
In section 200.320 on procurement methods, OMB proposed to change “small purchases” to “simplified acquisitions” to further align with standard terminology. In paragraph (a), OMB proposed to clarify that “micro-purchases” and “simplified acquisitions” are types of “informal procurement methods for small purchases.” OMB also proposed to remove the requirements that local and tribal governments must open sealed bids in public. OMB received several comments expressing support for the proposed changes.
Several commenters questioned why OMB removed the requirement for sealed bids to be publicly opened by Indian Tribes but not local governments. One commenter questioned why OMB removed the documentation requirement for micro-purchase awards.
Other comments questioned the changes in terms from “small purchases” to “simplified acquisitions” in the proposed guidance and requested additional clarifications for why the change was made.
OMB Response: OMB revised paragraph (a)(1)(ii) of section 200.320 to clarify that a recipient or subrecipient must maintain documents to support its conclusion when awarding micro-purchase awards without soliciting competitive price or rate quotations. OMB made this change in response to comments questioning why OMB removed the documentation requirement for micro-purchase awards. OMB reinserted language similar to the language used in the prior version of the guidance on documenting the decision.
On comments questioning why OMB proposed to remove the requirement for sealed bids to be opened publicly by Indian Tribes but not local governments, OMB will consider this feedback for future updates. A change of this nature to a long-standing and government-wide public policy warrants an opportunity for public comment and careful review before reversing in the final guidance. OMB sought public comment on this change only for Indian Tribes, but not local governments. At this time, OMB only made the change for Indian Tribes as proposed.
Regarding references to an adequate number of bids in this section, OMB clarified in the guidance text that the recipient or subrecipient may exercise judgment in determining what number is adequate unless specified by a Federal agency. For example, a Federal agency may specify what number is adequate in the terms and conditions of a Federal award.
OMB appreciates the additional comments received on this section and may consider them for future updates.

Section 200.321—Contracting With Small Businesses, Minority Businesses, Women's Business Enterprises, Veteran-Owned Businesses, and Labor Surplus Area Firms
In section 200.321, OMB proposed to add “veteran-owned business” to the types of businesses that recipients and subrecipients are encouraged to consider for procurement contracts under a Federal award. Additionally, OMB proposed plain language and clarifying revisions. OMB received several comments expressing support for the proposed changes. OMB incorporated revisions in the final guidance in this section as proposed.

Section 200.322—Domestic Preferences for Procurements
OMB did not propose significant changes to this section. OMB received several comments on this section requesting additional clarification regarding infrastructure awards. The guidance on this topic can be found in 2 CFR part 184 and the associated preamble for that part. 88 FR 57750 (Aug. 23, 2023). See also OMB Memorandum M-24-02.

Section 200.323—Procurement of Recovered Materials
OMB proposed to add a new paragraph (b) in section 200.323 and proposed minor technical edits in paragraph (a). Regarding the proposed paragraph (b), Executive Order 14057 of December 8, 2021 (“Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability”) established that it is the policy of this Administration to lead by example and pursue a whole-of-government approach on sustainability and expanding American technologies, industries, and jobs that support sustainability and climate resilience. The Executive Order tasks the Federal government with pursuing new strategies to improve the Nation's preparedness and resilience to the effects of a changing climate, including financial management strategies. In support of this policy, OMB proposed to add a new paragraph (b) in section 200.323 encouraging Federal award recipients and subrecipients, to the extent permitted by law, to purchase, acquire, or use products and services that can be reused, refurbished, or recycled; contain recycled content, are biobased, or are energy and water efficient; and are sustainable. OMB received several comments expressing support for the proposed changes.
Other comments requested OMB clarify whether its “encouragement” means that recipients can specify these types of characteristics in Federally-funded procurements and potentially pay more than they would for products that do not meet sustainability specifications.
OMB Response: OMB finds that additional clarification is unnecessary in paragraph (b). The practice in paragraph (b) is encouraged to the greatest extent practicable and consistent with law, but not required. OMB included this paragraph in the final guidance text as proposed.

Section 200.324—Contract Cost and Price
OMB proposed to add additional language to section 200.324 on contract cost and price to establish that the recipient or subrecipient may consider potential workforce impacts in their procurement analysis if the procurement transaction will potentially displace public sector employees. OMB also sought comment on its proposal to delete the existing paragraph (b), requiring the recipient to negotiate profit as a separate element of the price for each contract in which there is no price competition. OMB received several comments expressing support for the proposed changes.
Several commenters asked OMB to permit the use of “cost plus a percentage of cost” and “percentage of construction costs” methods of contracting. Another commenter asked OMB to provide a definition of cost-benefit analysis in this section. Next, a commenter asked OMB to reinstate the provision requiring recipients to negotiate profit as a separate element of the price for each contract in which there is no price competition. Another comment asked for clarification on why the word “independent” was struck in paragraph (a).
OMB Response: OMB revised paragraph (a) of section 200.324 to clarify that the recipient or subrecipient must make independent estimates before receiving bids or proposals. OMB agrees with the commenters that this revision—restoring the term used in the prior version of the guidance—would clarify the proposed language.
OMB also made minor typographical fixes in paragraph (a) and changed “may” to “must” in paragraph (c). OMB otherwise made the revisions in this section as proposed. OMB disagrees with the commenter asking OMB to reinstate the provision requiring recipients to negotiate profit as a separate element of the price for each contract in which there is no price competition. While this practice is no longer expressly required by the guidance, this does not prohibit a recipient from taking such action if deemed necessary in instances when there is no price competition.
OMB did not find it necessary to add a definition of cost-benefit analysis in this section. Instead, OMB decided to reinstate the language from the prior version of the guidance referring to a “cost analysis,” which remains the intended term in this context. OMB also did not permit the use of “cost plus a percentage of cost” and “percentage of construction costs” methods of contracting. OMB concluded that this would not be appropriate and presents both legal and policy concerns. OMB did not make a change in the final guidance.

Section 200.326—Bonding Requirements
OMB did not propose significant changes to this section. OMB received a few comments requesting expansion of this section. Specifically, commenters asked OMB to expand this section to address specific programs such as those authorized under the Robert T. Stafford Disaster Relief and Emergency Assistance Act (Stafford Act).
OMB Response: OMB did not find it warranted at this time to expand this section, as requested by commenters. Some of the suggested revisions may be more appropriate for agency- or program-specific guidance. In any case, before significantly expanding this section, OMB would want to propose revised language for public comment.
Relative to the proposed text, OMB made a minor revision in paragraph (a) of section 200.326 to replace the word “obligations” with “documents,” which restored the policy from the prior version of the guidance. After review, OMB concluded that the prior version of the guidance used the correct term. In the context of this provision, at the point when a bid guarantee is provided, no contract yet exists, and there are no contractual obligations to “execute.” OMB also made a minor revision to fix a typographical error.

Section 200.328—Financial Reporting
In section 200.328, OMB proposed to provide changes to clarify required deadlines for financial reporting to align with progress reporting requirements. OMB received several comments expressing support for the proposed changes.
Several comments suggested that quarterly financial reports should be due 60 days after the close of a quarter. Other comments suggested emphasizing that Federal agencies must not require additional financial reporting data elements, aside from those approved by OMB. Other commenters asked OMB to include a process by which agencies and OMB will both request and approve additional data elements for financial reports. One comment suggested reverting to language in the prior version of the guidance, allowing Federal agencies to require more frequent financial reporting “in unusual circumstances.”
OMB Response: OMB disagrees with comments asking for a process in the guidance by which agencies and OMB will both request and approve additional data elements for financial reports. OMB did not include such a process within this section.
In response to comments suggesting that quarterly financial reports should be due 60 days after the close of a quarter, OMB disagrees and did not make a change. OMB also disagrees that it is necessary to revert back to language in the prior version of this section referring to more frequent reporting in “unusual circumstances.” However, Federal agencies and pass-through entities may require more frequent or detailed financial reporting in accordance with section 200.208 when circumstances warrant and consistent with the guidance.

Section 200.329—Monitoring and Reporting Program Performance
In section 200.329, OMB proposed to revise the reporting of program performance section to remind agencies of the importance of not requiring information in programmatic reports that is not necessary for the effective monitoring of the award. OMB also proposed additional language that emphasizes the importance of measuring customer experience as well as considering evaluation plans when outlining reporting requirements. OMB further proposed to clarify that programmatic reporting may not be required more frequently than quarterly, unless specific conditions have been applied to the award in accordance with section 200.208. OMB received several comments expressing support for the proposed changes.
OMB received several comments requesting that the research performance progress reports be reinserted as an example of an OMB-approved common information collection. Several comments also stated that performance reports should not be collected with financial reports. Commenters observed that often different business areas of an entity are completing the reports.
OMB Response: OMB revised the heading of paragraph (a) of section 200.329 to clarify that it also applies to subrecipients. OMB revised paragraph (b) of section 200.329 to clarify that, to the extent practicable, the Federal agency or pass-through entity should “align the due dates of” performance reports and financial reports. It was not OMB's intent to require that performance reports always be submitted together with the financial reports. The reports do not need to be submitted together in all cases. However, when practicable, Federal agencies should align the due dates. The different reports provide a more comprehensive view of the progress made on a Federal award when reviewed together.
Further, in paragraph (b), OMB also agrees with commenters who suggested reinserting “research performance progress reports” as an example of an OMB-approved common information collection. OMB incorporated this change in the final guidance.
OMB also removed the proposed requirement in paragraph (b) that Federal agencies only require OMB approved government-wide data elements. This provision may have significantly restricted information that could be collected to report performance. It is not feasible to create a data standard for every piece of information collected on performance across all programs, which was not OMB's intent when it originally proposed that language.
Relative to the proposed guidance, in paragraphs (c) through (e), OMB also made minor plain language revisions and other revisions intended to address grammatical problems or further clarify the guidance text. These changes were not intended to substantively change the policy in these paragraphs as proposed—but may provide further clarity on OMB's intent.

Section 200.330—Reporting on Real Property
OMB did not propose significant changes to this section. One commenter noted that plain language revisions may have unintentionally impacted the frequency that reporting is required. The commenter suggested that the revision could be interpreted to result in a change from requiring reports “at least annually” to an “annual report.” Another commenter requested clarification on the information that must be included in real property reports. The same commenter requested that OMB provide an exception for cases where the Federal Government has only a minor interest in real property.
OMB Response: OMB removed the reference to “at least annual” reports in this section and clarified in a separate sentence that such reports “must be submitted at least annually.” It was not OMB's intent to change the meaning of the guidance on this issue. The information included in real property reports should be set by the Federal agency and included on the SF-429 series of forms. OMB did not make a change to this section to provide an exception for cases where the Federal Government has only a minor interest in real property, but appreciates the comment and may consider it for future revisions.

Section 200.331—Subrecipient and Contractor Determinations
In section 200.331 on subrecipient and contractor determinations, OMB proposed additional language emphasizing that Federal agencies do not have a direct legal relationship with subrecipients and contractors of pass-through entities. OMB also proposed to clarify that the characteristics indicative of a subrecipient or contractor determination are not limited to the sample characteristics currently provided in the guidance. OMB received several comments expressing support for the proposed changes.
Several commenters asked OMB to reinstate language from the prior version of the guidance. A commenter asked OMB to clarify that the Federal agency or pass-through entity may require the recipient or subrecipient to comply with additional guidance to make subaward and contractor determinations, provided such guidance does not conflict with this section. Several commenters requested clarity on the proposed language stating that the Federal agency does not have a direct legal relationship with subrecipients or contractors of any tier. OMB also received several comments requesting that section 200.331 include information on beneficiary determinations.
OMB Response: OMB revised section 200.331 to restore language from the prior version of the guidance, which commenters and Federal agencies indicated was important to understand the guidance. For example, OMB revised the introductory paragraph to clarify that the Federal agency “or pass-through entity” may require the recipient or subrecipient to comply with additional guidance to make subaward and contractor determinations “provided such guidance does not conflict with this section.” A commenter raised these points and OMB agrees. Based on another comment, OMB also revised this section to clarify that no single factor or combination of factors contained in this section is necessarily determinative. OMB also restored guidance explaining that the pass-through entity must use judgment in classifying each agreement as a subaward or a procurement contract. Lastly, OMB also revised the introductory paragraph in section 200.331 to clarify that, while a Federal agency does not have a direct legal relationship with subrecipients, the Federal agency is still responsible for monitoring the pass-through entity's oversight of first-tier subrecipients. This revision was not based on text from the prior version of the guidance, but intended to provide further clarity.
OMB disagrees that including information on making beneficiary determinations would be appropriate in this section. The identification of beneficiaries can vary between agencies and even between programs within an agency. OMB did not make a change.

Section 200.332—Requirements for Pass-Through Entities
Based on feedback from the Federal financial assistance community, OMB proposed to include, in section 200.332, the requirement for pass-through entities to confirm that potential subrecipients are not suspended, debarred, or otherwise excluded from receiving Federal funds. OMB received several comments expressing support for the proposed changes.
Several comments noted that the proposed language was inconsistent with language in 2 CFR 180.300. OMB also received several comments opposing the notification requirement in paragraph (d), which would require a pass-through entity to notify the Federal agency if a specific condition is included in a subaward. OMB also received several comments recommending that the guidance ensure appropriate overhead costs of the subrecipient are not unreasonably excluded.
OMB Response: OMB revised paragraph (a) of section 200.332 to clarify that confirming a subrecipient is not excluded in SAM.gov is just one of the verification methods available to pass-through entities under section 180.300. OMB agrees with commenters that the proposed text could be, or appear to be, inconsistent with language in 2 CFR 180.300. OMB revised the text to address these concerns.
OMB revised paragraph (b) of section 200.332 to clarify that a pass-through entity must provide the unavailable information when it is obtained. OMB revised paragraph (c) of section 200.332 to clarify that pass-through entities must evaluate a subrecipient's fraud risk in addition to its risk of noncompliance with a subaward. OMB also revised paragraph (c)(3) to remove the expansion of the existing policy. OMB agrees with commenters that it is not feasible to assess whether a subrecipient has new or substantially changed policies or procedures. Next, OMB revised paragraph (c)(4) of section 200.332 to clarify that pass-through entities should consider the extent and results of any Federal agency monitoring when evaluating subrecipient risk.
OMB disagrees with commenters that the notification provision in paragraph (d) related to specific conditions is overly burdensome. OMB finds this guidance is warranted to allow a Federal agency to conduct effective oversight of the pass-through entity in fulfilling its monitoring responsibilities. OMB fixed a minor grammatical error in paragraph (d).
OMB also clarified in paragraph (e) of section 200.332 that a subrecipient, not a subaward, is the focus in this provision. In response to a comment, OMB also restored the words “as necessary” from the prior version of the guidance. Next, OMB revised paragraph (e)(4) of section 200.332 to use the proper term “cross-cutting audit finding.” The proposed term “cross-cutting finding” is not otherwise used in the guidance.
Lastly, OMB revised paragraph (h) of section 200.332 to use the term “site visits,” which is used throughout the guidance, in place of the term “on site reviews.” OMB finds the guidance already meets the request to ensure appropriate overhead costs of the subrecipient are not unreasonably excluded. The guidance in this section states the methods by which pass-through entities and subrecipients negotiate rates.

Section 200.333—Fixed Amount Subawards
In section 200.333, OMB proposed removing the current simplified acquisition threshold limit for fixed amount subawards to provide agencies and recipients with increased flexibility in making programmatic and budgetary decisions, while still allowing recipients to establish their own award-specific thresholds with the prior written approval of the Federal agency. Under the proposed revision, a recipient's use of fixed amount subawards remains subject to the prior written approval of the Federal agency. OMB received several comments expressing support for the proposed changes. One commenter asked OMB to remove the prior approval requirement for fixed amount subawards.
OMB Response: Upon further analysis, OMB determined that a threshold for fixed amount subawards remains warranted. Instead of removing the threshold entirely, OMB doubled the prior threshold to $500,000. OMB may continue to evaluate what threshold is appropriate in future updates to the guidance. OMB disagrees with commenters requesting removal of the prior approval requirement for fixed amount subawards. OMB finds that prior approval is a necessary oversight function of Federal agencies for these subawards.

Section 200.334—Record Retention Requirements
OMB did not propose significant changes to this section. OMB received several comments requesting clarifications related to OMB's proposed plain language revisions in this section. For example, a commenter stated that the proposed changes gave the appearance that a pass-through entity and subrecipient had the same three-year record retention period.
OMB Response: OMB agrees with commenters that minor clarifying revisions were warranted in this section. Thus, OMB made minor clarifying revisions, including adjusting its use of “and” and “or” between listed entities.

Section 200.336—Methods for Collection, Transmission, and Storage of Information
OMB did not propose significant changes to this section. Several commenters suggested that OMB changed the meaning of the guidance with its plain language revisions. The commenters were specifically concerned about preserving the language in the prior version of the guidance on collecting, transmitting, and storing Federal award-related information in “open and machine-readable formats.”
OMB Response: OMB revised section 200.336 to clarify that Federal award information must be collected, transmitted, and stored in “open and machine-readable formats.” OMB agrees with the commenters on restoring the reference to “open and machine-readable formats” without adding extra language.

Section 200.337—Access to Records
OMB did not propose significant changes to this section. OMB received one comment requesting that the guidance be strengthened to clarify that other PII, beyond simply the names of victims, should also be protected.
OMB Response: OMB did not make a policy change to this section but appreciates the comment and may consider it for future revisions. Other provisions in the guidance—such as sections 200.303 and 200.338—directly address restrictions on PII. As discussed in this preamble above, OMB further clarified the definitions of PII and Protected PII within part 200.

Section 200.338—Restrictions on Public Access to Records
OMB did not propose significant changes to this section. OMB received several comments indicating that proposed plain language revisions in this section may have caused a conflict. Specifically, commenters observed that the guidance was expanded to prevent a pass-through entity from placing restrictions on subrecipients that would limit public access. OMB also removed repeated words.
OMB Response: OMB revised section 200.338 to clarify that it applies to Federal agencies. This change to the proposed guidance is consistent with the prior version of the guidance. OMB recognized the concern from commenters that such a restriction on a pass-through entity might prevent the pass-through entity from enforcing the laws of a State or Indian Tribe. OMB made a change to clarify it is the Federal agency who may not place further restrictions.

Section 200.339—Remedies for Noncompliance
OMB did not propose significant changes to this section. Several commenters requested clarification with regards to the use of “may” and “must” in this section.
OMB Response: The word “may” is used appropriately in this section to convey that a Federal agency or pass-through entity has discretion in both implementing specific conditions or taking any of the actions listed. To avoid confusion, OMB removed the word “must” from paragraph (d) and further revised the sentence to clarify intent. The provision is simply stating that a pass-through entity recommends suspension or debarment to the Federal agency. Only a Federal agency may initiate the suspension or debarment action. OMB does not intend to signal a change in policy by this change.

Section 200.340—Termination
OMB proposed to revise and clarify the guidance pertaining to termination and closeout requirements in sections 200.340 through 200.344. On termination, in section 200.340(a)(2), OMB had proposed to remove language that allows a Federal agency or pass-through entity to terminate an award “if an award no longer effectuates the program goals or agency priorities.” 2 CFR 200.340(a)(2) (prior version). This revision was intended to remove unnecessary language because section 200.340 still allowed agencies to terminate a Federal award according to the terms and conditions of the award. Thus, an agency could specify the conditions upon which an award could be terminated in the terms and conditions of the award, including, for example, when an award no longer effectuates the program goals or agency priorities. The proposed guidance also proposed to change the definition of termination in section 200.1 and provided a new paragraph (e) in 200.340 providing that a Federal agency's determination not to provide continuation funding does not constitute a termination.
Several commenters supported removing paragraph (a)(2) of section 200.340 from the prior version of the guidance. For example, one commenter maintained that its removal would prevent agencies from terminating high-performing projects based on shifting agency priorities. Another commenter stated that removing the prior (a)(2) would eliminate a vague standard for award termination and serve OMB's goal of clarifying a section that could be interpreted in a variety of different ways.
Other commenters asked OMB to reinstate paragraph (a)(2) from the prior version of the guidance. One commenter argued that it was important for pass-through entities to maintain the ability for unilateral termination based on changes in program goals or agency priorities. Another commenter suggested that, even if the prior (a)(2) were deleted, a pass-through entity that included a “termination for convenience” clause in its subaward should still be able to terminate based on that clause.
Other commenters expressed concerns regarding the proposed paragraph (e) and suggested removing it. Proposed paragraph (e) provided that a Federal agency determination to not award continuation funding does not constitute a termination. One commenter observed that an agency decision to not provide continuation funding under a Federal award would have impacts similar to a termination on the recipient or subrecipient, including the need to discontinue program activities and potential financial liabilities. This commenter expressed concerns about a lack of due process for awards discontinued under paragraph (e). The commenter recommended either deleting the proposed paragraph (e) or supplementing it with a requirement for the Federal agency to notify the recipient or subrecipient no less than 6 months in advance of the end of the budget period. On the same topic, another commenter expressed concern that the proposed paragraph (e) may cause confusion with respect to authorizing statutes that have explicit termination provisions, including continuation funding. The same commenter stated that OMB failed to adequately explain the distinction between an agency's exercise of its discretion when making an award and subsequent determinations by the agency, pursuant to terms and conditions of the award, to provide funding for additional budget periods for that same award. For awards discontinued at the end of a budget period in a multi-year award, this commenter questioned what, if any, due process would be provided, such as notice, reasons, or opportunity to correct.
OMB Response: OMB revised paragraph (a)(4) in section 200.340 in the final guidance. The new paragraph (a)(4) continues to provide that a Federal award may be terminated by the Federal agency or pass-through entity pursuant to the terms and conditions of the Federal award. The revised version of paragraph (a)(4) also explains that this may include a term and condition allowing termination by the Federal agency or pass-through entity, to the extent authorized by law, if an award no longer effectuates the program goals or agency priorities. Provided that the language is included in the terms and condition of the award, the revised termination provision at section 200.340 continues to allow Federal agencies and pass-through entities with authority to terminate an award in the circumstances described in paragraph (a)(2) in the prior version of the guidance. The prior version of section 200.340(b) and the proposed version both directed Federal agencies and pass-through entities to clearly and unambiguously specify all termination provisions in the terms and conditions of the award. As such, OMB finds the final version of the guidance provides greater clarity on the policy for termination of awards by the Federal agency or pass-through entity by underscoring the need for agencies and pass-through entities to clearly and unambiguously communicate termination conditions in the terms and conditions of the award.
OMB also removed the proposed paragraph (e) from the final version of the guidance. Other than the change described above in paragraph (a), OMB reverted back to a version of section 200.340 more aligned with the prior version of the guidance. After considering comments, OMB decided not to specifically address the topic of continuation funding in this section, but may evaluate this topic further in future updates. As a result, OMB deleted the proposed sentence in the definition of termination in section 200.1 providing that a determination not to issue continuation funding is not a termination. OMB also made minor technical and grammatical edits in the final version of the guidance in this section.
On comments regarding due process when terminating an award, section 200.342 in the final guidance, discussed below, requires Federal agencies to provide administrative appeal rights for recipients upon initiating a remedy for noncompliance, including in cases in which Federal awards are terminated for that reason. Administrative appeal rights may also be required in other circumstances by applicable statutes or agency regulations. Federal agencies must maintain written procedures for processing objections, hearings, and appeals. The comments OMB received on this topic were generally focused on the proposed paragraph (e), which OMB decided not to include in the final version of the guidance.

Section 200.341—Notification of Termination Requirement
In section 200.341, OMB proposed to clarify requirements that must be included in a notice of termination. One commenter asked OMB to further clarify the requirements of this section. The commenter noted that the section was confusing.
OMB Response: OMB agrees with a commenter that the proposed guidance in this section was potentially confusing—particularly paragraph (b)(3). In the final version of paragraph (b)(3), OMB reverted to the text from the prior version of the guidance. After review, OMB found that the prior version of the guidance more clearly stated the policy for this paragraph than its proposed restatement.

Section 200.342—Opportunities to Object, Hearings, and Appeals
OMB did not propose significant changes to this section. Several commenters noted that OMB's plain language revision expanded the policy of this section to require a pass-through entity to maintain documented procedures for objections, hearings, and appeals, as well as providing subrecipients an opportunity to object to and challenge an action.
OMB Response: OMB revised section 200.342 to clarify that the paragraph applies to Federal agencies. It was not OMB's intent to change the policy in this section in a substantive way. OMB made a few changes to clarify. Consistent with the prior version of the guidance, OMB retained one reference to pass-through entities in the final sentence stating that pass-through entity must comply with any requirements for hearings, appeals, or other administrative proceedings to which the recipient or subrecipient is entitled under any statute or regulation applicable to the action involved. However, the other requirements in this section do not apply to pass-through entities.
The policy in section 200.342 is otherwise unchanged relative to the proposed and prior versions of the guidance. Specifically, it continues to require Federal agencies to provide administrative appeal rights for recipients upon initiating a remedy for noncompliance, and to maintain written procedures for processing objections, hearings, and appeals.

Section 200.344—Closeout
In section 200.344 on closeout, OMB proposed to revise closeout guidance to clarify that recipients must still submit a final financial report even when the recipient does not have a final indirect cost rate; and proposed to clarify that an additional final report must be submitted when the indirect cost rate is finalized. OMB also proposed to provide additional flexibilities for agencies and recipients to closeout Federal awards in a timely manner. OMB proposed to allow an agency and recipient to mutually agree upon a final indirect cost rate for an individual award. This proposed revision was not intended to grant agencies additional authorities to negotiate rates over cognizant agencies for indirect rates; rather, it simply proposed to affirm the Federal agency's right to negotiate with the recipient or subrecipient on a case-by-case basis with the goal of closing out specific awards in a timely manner. OMB received several comments expressing support for the proposed changes.
OMB received one comment opposing the change of the word “promptly” to “immediately” in paragraph (e). Another comment asked OMB to revise this section to reiterate and clarify that both parties must mutually agree to use a provisional indirect rate to support a timely or earlier close-out of an award or subaward, prior to an organization receiving their final NICRA rate. Several other comments requested clarification on when revised final financial reports must be submitted under paragraph (b).
OMB Response: OMB agrees with the commenter questioning the proposed change from “promptly” to “immediately” in paragraph (e). OMB reverted to using the word “promptly” in the final guidance in paragraph (e).
Paragraph (h) of the proposed guidance already addresses situations in which an indirect cost rate has not been finalized. The paragraph states that both parties must “mutually agree” to close an award using the current or most recently negotiated rate. On questions regarding when revised final financial reports must be submitted under paragraph (b), OMB finds the guidance is clear that a revised final financial report must be submitted when all applicable indirect cost rates have been finalized.

Section 200.346—Collection of Amounts Due
OMB did not propose significant changes to this section. One comment stated that the removal of language from the prior guidance that provided an opportunity for Federal agencies to reduce recipient or subrecipient debt would limit the flexibility for Federal agencies to handle such debt on a case-by-case basis. The commenter stated that the proposed change removed the option for Federal agencies to withhold advance payments otherwise due to the non-Federal entity to reduce the debt.
OMB Response: OMB did not intend to limit the flexibility of Federal agencies by removing language in this section. Rather, OMB revised the guidance text to simply refer to the authoritative regulatory source on the administrative collection of debt at 31 CFR part 901. As was already recognized in the prior version of the guidance, Federal agencies will follow those authoritative standards when collecting amounts due.

Subpart E—Cost Principles

Section 200.400—Policy Guide
OMB did not propose significant changes to this section. OMB received several comments suggesting the guidance in section 200.400 include a statement that residual unexpended funds under fixed amount awards is not considered profit. Another comment suggested that OMB require agencies to regularly update their guidance to recipients to enable grantees to leverage new technology and governance approaches that can utilize cost allocation to improve the cost-effectiveness of Federal investments.
OMB Response: OMB revised paragraphs (a) through (d) of section 200.400 to refer to the “recipient and subrecipient” rather than to the “recipient or subrecipient.” This revision further clarifies OMB's intent on how these provisions will be applied.
In paragraph (e), however, OMB clarified that the policy on indirect rates refers to “recipients” and not “subrecipients,” as subrecipients may not always negotiate indirect rates. OMB also made minor clarifying and plain language revisions in paragraph (e) relative to the proposed guidance.
OMB revised paragraph (g) of section 200.400 to add language clarifying that any funds remaining upon conclusion of a fixed amount award is not considered profit. This was added to clarify that the requirements governing the use of fixed amount awards do not conflict with the prohibition on profit contained in 200.400(g). OMB agrees with commenters on this point.
OMB considers the recommendation that OMB require Federal agencies to regularly update their guidance to leverage technology and governance approaches to be outside the scope of the revisions. This was not proposed for public comment, but OMB appreciates the comment and may consider it for future updates.

Section 200.401—Application
In the proposed guidance in section 200.401, OMB clarified that the cost principles in subpart E do not apply to grants and cooperative agreements for food commodities.
OMB received several comments requesting clarification and changes to paragraph (a)(2), which addresses capitation awards to IHEs. One comment requested that the sentence referencing that the cost principles must also be used “as a guide in pricing fixed-price contracts and subcontracts” be revised to read “fixed-price awards and subawards.” OMB also received a comment seeking clarification on the applicability of the cost principles to “food commodities.”
OMB Response: OMB revised paragraph (a)(2) of section 200.401 to include all capitation awards in the applicability section, not only capitation awards to IHEs, in order to be more inclusive of other types of recipients. OMB agrees with the commenters that the cost principles should not apply to capitation awards based on case counts or number of beneficiaries regardless of the type of recipient. OMB revised the guidance to apply this policy to all types of recipients. For example, other types of educational institutions exist that are not strictly IHEs.
OMB revised paragraph (a)(3) of section 200.401 to include a cross-reference to section 200.101, which provides further information on the applicability of the cost principles to fixed amount awards. OMB clarified that the cost principles do not apply to fixed amount awards, except as provided in section 200.101(b). OMB revised paragraph (a)(5) of section 200.401 to clarify that the cost principles do not apply to the specific portion of an award associated with the provision of food commodities themselves. This change was made to recognize that certain awards that issue food commodities also involve other activities ancillary to the food commodities themselves. The cost principles do apply to costs for those other activities under an award beyond the food commodities themselves.

Section 200.403—Factors Affecting Allowability of Costs
In the proposed guidance, OMB revised section 200.403 to add language clarifying when allowable administrative closeout costs may be incurred in paragraph (h).
OMB received several comments pointing out a perceived discrepancy in the policy that, while administrative closeout costs are allowable after the end date of a Federal award, no costs are allowable after the termination of a Federal award. OMB also received several comments on the period of allowability of costs during closeout, with some commenters requesting that certain costs associated with data and compliance be allowable for an undefined period after the final reports are submitted.
OMB received a comment requesting that certain prospective costs—that would occur after the due date of the final report—be allowable. Some commenters requested a policy change to provide additional clarification about how the administrative closeout cost allowability applies to subrecipients. The commenters also requested OMB make the policy retroactive for past programs, to clarify how these costs are impacted by agency rules on obligating funds and agency prior approvals, and to specify that closeout costs cannot “include cost share from other Federal programs.”
OMB Response: The proposed guidance in this section was included in the final revisions, with a minor clarifying edit to paragraph (d). In response to some comments focused on costs associated with termination: these costs are allowable if specified in a termination notice by the agency. Section 200.472(b) addresses the allowability of closeout costs after an award is terminated. The period during which closeout costs can be charged to an award ends on the due date of the final reports. Allowing for a longer period would be inappropriate and could potentially impact the timeline closeout of Federal awards. OMB finds that the revised policy sufficiently provides for the allowability of specific administrative costs during a limited, defined period. OMB did not find the guidance needs to be expanded further.

Section 200.404—Reasonable Costs
OMB did not propose significant changes to this section. OMB received many comments in support of the inclusion of certain administrative costs for closeout activities. OMB received one comment that suggested the phrasing related to determining whether a cost was allowable as related to deviations from written policies and procedures was too vague.
OMB Response: OMB agrees the proposed language left room for differing interpretations and was potentially confusing. To address this, OMB revised paragraph (e) to now call for consideration of “ whether the cost represents a deviation from the recipient's or subrecipient's established written policies and procedures for incurring costs” (emphasis added), instead of “the degree to which” it does so. Section 200.404 contains only a list of factors to consider. OMB did not find that it necessary to specify further.

Section 200.405—Allocable Costs
OMB did not propose significant changes to this section. One commenter took issue with the word “shifting” in relation to costs.
OMB Response: OMB revised paragraph (a) of section 200.405 to reinsert “or other cost objective.” This change was made to recognize costs that are allocable to a particular cost objective as already recognized under the prior guidance, and to retain alignment with usage of this term throughout other sections of subpart E, including sections 200.412, 200.413, and 200.431. OMB finds that “shifting costs” is an adequately understood term when speaking of budget line items. OMB is retaining the language. OMB also made some minor clarifying revisions to paragraph (e).

Section 200.406—Applicable Credits
OMB did not propose significant changes to this section. OMB received several comments requesting that OMB specify the treatment of credits when such credits cannot be identified to a Federal award, suggesting for example, that such credits offset indirect costs.
OMB Response: OMB did not propose policy changes to this section. OMB did not make additional changes to section 200.406 in response to the above comments, which it does not find warrant implementation at this time. Aside from a small grammatical revision, OMB made revisions in this section as proposed.

Section 200.407—Prior Written Approval (Prior Approval)
In the proposed guidance, OMB revised section 200.407 to remove 10 items from the prior written approval requirements to reduce Federal agency and recipient burden. These proposed revisions included no longer requiring prior written approval for certain requirements related to items such as real property, equipment, direct costs, entertainment costs, memberships, participant support costs, selling and marketing costs, and taxes.
OMB received one comment suggesting that OMB remove the remainder of the policy on prior approval contained in section 200.308. OMB also received a comment requesting clarification on whether the inclusion of items in an approved budget still requires separate prior written approval. Some commenters requested clarification on prior approvals for real property and equipment. Finally, OMB received a couple of comments requesting the reinstatement of the of all prior approval requirements OMB proposed to remove.
OMB Response: OMB disagrees with the commenter who suggested that reinstating prior approval requirements that OMB proposed to remove was necessary to address the risk of subsequent disallowance of costs. The commenter stated that reducing burden associated with prior approval would result in elevated risk of later disallowance for the associated costs. OMB did not find that the elevated risk is so great that it must reverse its earlier proposal. OMB cautions, however, that recipients and subrecipients must still follow applicable cost principles under subpart E even in cases in which prior approval is not required. The requirement to apply the cost principles is unaffected by changes to this section.
To further clarify the guidance under this section as it relates to real property and equipment, OMB revised the list of prior approval requirements in section 200.407 to remove reference to the real property and equipment provisions in section 200.311 and 200.313. Other requirements to obtain instructions or approval from the Federal agency—such as requirements to request disposition instructions—remain in place in those sections and are unaffected by the changes to section 200.407. Section 200.439—which remains included in the list of prior written approvals in section 200.407 and is specifically referenced in section 200.313—continues to describe circumstances in which prior written approval is required for allowability of equipment and other capital expenditures. For example, when equipment disposal is directed by a Federal agency under the process described in section 200.313, section 200.439 continues to recognize that this Federal agency action is needed before the costs are allowable. Section 200.439 also describes other circumstances when prior written approval is necessary for the allowability of equipment and capital expenditures, including for general purpose equipment, buildings, and land; and improvements to land, buildings, or equipment that materially increase their value or useful life.
In section 200.407, OMB restored one item to the list from the prior version of the guidance, which it previously proposed to delete. As discussed in more detail below, OMB restored the reference to exchange rates in section 200.440. More information on the specific circumstances in which prior approval is required is generally provided in the sections listed in section 200.407, including in the restored reference to section 200.440 on exchange rates.

Section 200.411—Adjustment of Previously Negotiated Indirect Cost Rates Containing Unallowable Costs
OMB did not propose significant changes to this section. OMB received several comments requesting significant additional information regarding the adjustments of negotiated indirect cost rates. For example, commenters requested that OMB add a new section that speaks to informing stakeholders if unallowable costs are included in indirect rates, determining the legitimacy of the finding in conjunction with OMB, and establishing a different process for reimbursing the Federal government.
OMB Response: OMB did not propose policy changes for section 200.411 and considers the new suggestions received by commenters to be outside of the scope for the final version of the guidance. OMB appreciates the comments and may consider them for future updates. OMB made a minor update to paragraph (a) to remove the word “Federal.”

Section 200.413—Direct Costs
OMB did not propose significant policy changes to this section, but did propose extensive plain language revisions. OMB received one comment of support for the changes in this section. OMB received several comments requesting clarification on the use of the term “procurement transaction” in paragraph (b), which had replaced “goods and services” from the prior version. The same commenters indicated that a change from employee and fringe benefits to “staff” represented a change in policy. OMB received several comments stating that revisions to paragraph (e) changed the standard for unallowable indirect costs and was confusing.
OMB received several comments requesting that paragraph (c) include the following language: “Direct charging of these costs may be appropriate, where unlike circumstances exist, only if they meet all of the following conditions.” Several comments addressed issues related to direct costs, but were not pertinent to any proposed revisions to the guidance, including issues such as how administrative and clerical staff costs are treated, or the need to invest in data infrastructure.
OMB Response: OMB revised paragraph (b) of section 200.413 to improve the accuracy of the statement describing direct costs. OMB retained the statement that the “association of costs with a Federal award” determine their nature, but removed “rather than the nature of the procurement transaction,” which was too limiting, as not all costs in an award are necessarily procurement transactions. OMB agrees with commenters on clarifying this point.
OMB also revised paragraph (b) of section 200.413 to provide a more accurate example of staff costs that are considered direct costs. Rather than simply saying “staff salaries,” OMB revised this to “employee salaries and fringe benefits,” which more accurately reflects all costs associated with paying an employee directly charged to a specific award.
OMB disagrees with commenters that adding “where unlike circumstances exist” is necessary in paragraph (c). OMB made some more clarifying edits to paragraph (d) to improve the readability of the sentence. OMB revised paragraph (d) to replace “minor direct cost” with a “direct cost of a minor amount,” which is the intended meaning. OMB also finds that “for reasons of practicality” more clearly communicates the intended policy in this paragraph than “when it is practical to do so.”
OMB agrees with comments suggesting that proposed revisions to paragraph (e) changed the standard for treatment of unallowable costs in determining indirect cost rates. OMB reverted to the original language from the prior version of the guidance with minor grammatical changes. OMB made other minor clarifying edits to the list of examples in paragraph (f).

Section 200.414—Indirect Costs
In the proposed guidance in section 200.414, OMB revised several aspects of the guidance pertaining to indirect costs. OMB proposed to clarify that recipients and subrecipients may notify OMB of any disputes with regards to a Federal agency's application or acceptance of a federally negotiated indirect cost rate. OMB also proposed to revise the guidance to clarify that pass-through entities must accept all federally negotiated indirect cost rates for subrecipients.
In the same section, in response to feedback from the Federal financial assistance community, OMB proposed to raise the de minimis rate from 10 percent to 15 percent. OMB explained that this change would allow for a more reasonable and realistic recovery of indirect costs, particularly for new or inexperienced organizations that may not have the capacity to undergo a formal rate negotiation, but still deserve to be fully compensated for their overhead costs. OMB also explained that the changes still allow recipients and subrecipients to apply a rate lower than 15 percent at their own discretion. At the same time, the proposed guidance clarified that Federal agencies may not compel recipients and subrecipients to use an indirect rate lower than the proposed 15 percent rate, unless required by statute. OMB also clarified that the de minimis rate may not be applied to cost reimbursement contracts and recipients and subrecipients are not required to use the de minimis rate.
Finally, OMB also proposed to remove the existing requirement in paragraph (h) of section 200.414 for all indirect cost rates to be publicly available on a government-wide website—but noted that this may be revisited when applicable systems are updated to allow for the posting of indirect cost rates. OMB sought comments that include analysis on the advantages and disadvantages of raising the de minimis rate in the way proposed.
OMB received over 250 comments expressing support for the increase in the de minimis rate to 15 percent. Several commenters urged OMB to increase the de minimis rate to 20 percent or more. Another commenter asked OMB to allow a de minimis rate of up to 15 percent over direct labor instead of modified total direct costs. OMB also received several comments objecting to the language that “the recipient or subrecipient is authorized to determine the appropriate rate up to this limit,” suggesting that it could be a barrier for entry for some organizations. Commenters also suggested that the policy could be misinterpreted to imply that the pass-through entity could decide for the subrecipient which percentage would apply.
OMB also received several comments requesting that OMB allow pass-through entities to waive the policy in section paragraph (d) that “pass-through entities are subject to the requirements in 2 CFR 200.332(b) and must accept all active federally negotiated indirect costs rates for subrecipients.” Several comments asked OMB to add a qualifying phrase to allow pass-through entities flexibility on their acceptance of federally negotiated indirect rates such as adding “unless otherwise provided in the grant agreement.” OMB also received several comments indicating that paragraph (f) would require subrecipients to submit indirect cost proposals in accordance with the appropriate Appendix to pass-through entities.
Several commenters voiced concern over Federal agencies' reported refusal to recognize formally negotiated rates. The commenters urged OMB to add language to propose OMB action in the event that Federal agencies refuse to apply or allow recipients or subrecipients to use their federally negotiated indirect cost rate.
There were several comments from the IHE community requesting that OMB retain the use of “F&A” in relation to negotiated indirect rates, stating that this term is “necessary for IHEs” or is widely used and understood. OMB also received comments on certain language proposed in paragraph (f) stating: “A governmental department or agency that receives more than $35 million in direct Federal funding during its fiscal year may not elect to use the de minimis rate (see Appendix VII, paragraph D.1.b.).” OMB also received several comments requesting OMB increase the threshold above $50,000, as proposed, for recovering indirect costs from subawards.
OMB Response: OMB revised paragraph (b) of section 200.414 to improve the accuracy of the statement describing indirect costs of nonprofit organizations. OMB retained the statement that the “association of a cost with a Federal award” determines its nature, but removed “rather than the nature of the procurement transactions,” which was too limiting, as not all costs in an award are necessarily procurement transactions.
OMB revised paragraph (c)(1) to simplify the reference to Federal agencies using a different rate “based on documented justification described in paragraph (c)(3).” OMB replaced the text with “in accordance with paragraph (c)(3).” OMB also moved “in the notice of funding opportunity” from the end of paragraph (c)(4) to the beginning of the same paragraph to make the requirement easier to read and understand.
OMB revised paragraph (f) of section 200.414 to clarify that neither Federal agencies nor pass-through entities may require recipients and subrecipients to use a de minimis rate lower than this standard unless required by Federal statute or regulation. This does not limit the recipient or subrecipient from electing to use a lower rate than the de minimis rate. OMB also removed the reference to recipients and subrecipients submitting cost proposals in accordance with the appropriate appendix if they chose not to use the de minimis rate. Other sections of the guidance adequately explain that recipients and subrecipients have a right to negotiate a rate, rather than using the de minimis rate.
OMB also removed the proposed language from paragraph (f) stating that governmental or department entities receiving more than $35 million are not allowed to use the de minimis rate. Appendix VII to part 200 addresses this topic. It explains that a governmental department or agency receiving more than $35 million in direct Federal funding during its fiscal year must submit its indirect cost rate proposal to its cognizant agency for indirect costs.
Regarding the de minimis rate, in the proposed language OMB referred to the rate as “up to” 15 percent in order to allow flexibility for the recipient or subrecipient to elect to apply a lower rate for their own organizations or if a program statue or agency regulations required a lower rate. The phrasing “up to” is not intended to interfere with recipients or subrecipients applying the 15 percent rate if they are not prohibited by an authorizing statute or agency regulation. Rather, the “up to” language is only intended to reflect the fact that, in some cases, a lower de minimis may be applied.
OMB understands that there have been disagreements over the negotiation of indirect rates, whether related to the length of time taken to finalize them, or the rate that was established. In the proposed guidance, OMB included additional language in section 200.414(c)(2) that recipients or subrecipients may contact OMB in the event of indirect rate disputes. OMB includes that guidance in the final revision. However, OMB did not establish itself as a formal arbiter of indirect cost rate disputes.
The guidance also states in section 200.414(c)(1) that agencies do not have the authority to set their own indirect rates without justification or support in statute or regulation. However, OMB disagrees with the comments requesting OMB waive requirements for pass-through entities. The same requirements that apply to Federal agencies should also apply to pass-through entities in this context. OMB retained the language.
In response to comments on the elimination of “F&A,” the term “F&A” was often used in the guidance in parentheses after the word “indirect” in terms including “indirect cost” and “indirect cost rate.” This implied that “F&A” was generally interchangeable with the word “indirect” in those terms. In practice, the term “F&A” may not in all cases be used interchangeably with the word “indirect” in the context of negotiated indirect cost rates. OMB does not, however, consider there to be a substantial benefit derived from formally maintaining this phrasing for indirect costs and indirect cost rates whenever referenced by repeating “F&A” after “indirect” throughout part 200. The policy that IHEs must classify their indirect costs into these two categories is still in place, and the removal of this term does not impact the use of the term “F&A” throughout the community of IHEs. OMB also discusses this change in the definition of “indirect cost” in subpart A of this preamble above.
In response to commenters urging OMB to increase the de minimis rate to 20 percent or higher: OMB determined to maintain the de minimis rate at 15 percent as proposed. Regarding the increased threshold for calculating modified total direct costs, OMB disagrees that a threshold increase higher than $50,000 was necessary and did not further increase the threshold at this time. OMB also did not create a mechanism allowing a de minimis rate of up to 15 percent over direct labor, but may consider this and other suggestions on the de minimis rate for future updates. OMB also made a few stylistic and clarifying revisions to paragraph (g) in section 200.414.

Section 200.415—Required Certifications
In the proposed guidance, OMB revised section 200.415 to require that subrecipients must certify to pass-through entities that financial information submitted to the pass-through entity is complete and accurate. OMB received one comment of support for this proposed change in policy. OMB also received two comments requesting clarifications that certifications apply to “financial” reports and that indirect cost proposals are not necessarily “annual.”
OMB Response: OMB revised section 200.415 to remove the phrase “and payment requests under federal awards.” OMB removed this phrase because the certification language provided in the section refers only to the certification associated with the financial report. The previous version that applied to payment requests as well was technically inaccurate. The standard payment request form contains a different certification. This section now specifies that only financial reports require the certification that is specified in this text. Additionally, OMB revised paragraph (e) to remove the word “annual.”

Section 200.416—Cost Allocation Plans and Indirect Cost Proposals
OMB did not propose significant changes to this section. OMB received two comments requesting additional examples of centralized service costs to include, for example, computer centers, integrated data systems, central analytics capacity, and cloud computing infrastructure.
OMB Response: OMB did not find it necessary to include additional items of centralized services in this guidance. The types of service costs provided are illustrative only and are not meant to be a comprehensive list.

Section 200.417—Interagency Service
OMB did not propose significant changes to this section. OMB received several comments requesting that OMB increase the indirect rate agencies can apply for interagency services from 10 percent to 15 percent to be consistent with the increase in the de minimis rate.
OMB Response: OMB revised section 200.417 to increase the percentage of costs that an operating department may charge to cover the costs of providing services to another operating department. While the type of rate is different (interagency service versus de minimis ), OMB agrees that aligning these rates is sensible and increased the rate in this section to 15 percent in response to the comments. OMB finds that the de minimis rate for services should align with the increase in the de minimis rate allowed under Federal awards.

Section 200.419—Cost Accounting Standards
In the proposed guidance, based on feedback from both IHEs and Federal agencies, OMB removed the requirement in section 200.419 for an IHE that receives an aggregate total of $50 million or more in Federal awards and instruments subject to subpart E to submit a disclosure statement form (DS-2) containing information on cost accounting standards.
OMB received many comments in support of the removal of the DS-2 requirement, which was required to be submitted to the cognizant agency for indirect costs. OMB also received many comments expressing appreciation for the proposed removal of this requirement and highlighting the reduction in burden it would provide if finalized. In reference to the usefulness of this form to the audit community, some commenters suggested that IHEs could provide the information to the audit entity upon request, if needed, because relevant information contained in the DS-2 is often readily available at IHEs. One comment requested that OMB add language stating that IHEs subject to the DS-2 requirement should continue to submit a DS-2 to their cognizant agency for indirect cost.
OMB Response: In the final guidance, OMB made revisions in this section as proposed. OMB did not make a change to this section in response to the comment requesting OMB to require submission of the DS-2 to the cognizant agency for indirect cost. Removal of the DS-2 requirement was intended to provide more consistent requirements for all types of recipients. The commenter's proposal would not align with that intent.

Section 200.420—Considerations for Selected Items of Cost
In the proposed guidance, OMB made several revisions to the general provisions for items of costs. Specifically, in section 200.420, OMB added further clarifying text explaining that the listed items of cost are not intended to provide a comprehensive list and that failure to mention an item, even as an example, is not intended to imply that it is allowable or unallowable. OMB revised this section as proposed.

Section 200.421—Advertising and Public Relations
OMB did not propose significant changes to this section. OMB received a comment requesting OMB amend paragraph (b)(1) of section 200.421 to clarify the scope of the allowability of recruitment costs to include “project participants” in addition to “personnel.” OMB also received one comment recommending language that specifically includes interpretation and translation of documents, websites, presentations, and recordings in the list of costs.
OMB Response: OMB revised section 200.421 to include “recruiting project participants” as an example of “program outreach.” This change was made for the sake of clarifying that type of activity. OMB agrees that including project participants in the scope of allowable recruitment costs would be a helpful clarification and revised the guidance text accordingly. However, OMB disagrees that adding language to specifically identify costs associated with “language and interpretation” was necessary. The absence of any one cost does not mean it is allowable or unallowable. Rather, the analysis depends on the programmatic need consistent with other principles and provisions under subpart D.

Section 200.422—Advisory Councils
In the proposed guidance, OMB revised section 200.422 to incorporate the definition of an “advisory council or committee.” OMB received two comments asking OMB to clarify the intent of this section, citing that advisory councils can be internal or external to a recipient.
OMB Response: OMB revised section 200.422 in the final guidance to clarify that the term advisory councils is intended to be inclusive of internal and external councils and committees. OMB also made minor clarifying edits.

Section 200.425—Audit Services
OMB did not propose significant changes to this section. OMB received one comment that objected to the removal of “types of” from “Type of Compliance Requirements” so that it reads “Compliance Requirements.” The commenter noted that this would permit pass-through entities to indirectly include other types of compliance requirements for which non-compliance may cause a cost not to be allowable to the award. For example, one commenter stated the section appears to make any costs for audits that are not required by and performed in accordance with the Single Audit Act unallowable. Another commenter objected to the prohibition on a reasonably proportionate share of other audit services.
OMB Response: In paragraphs (a)(1) and (a)(2) of section 200.425, OMB reverted to the original language in the prior version of the guidance. OMB decided that the original language better communicated the requirements and its intent. In paragraph (c)(3) of section 200.425, OMB also reverted to the original language of “types of compliance requirements.”
OMB finds that other commenters raised issues beyond the scope of changes that OMB had proposed or that do not align with its policy intent for the update to this section. OMB appreciates the other comments it received on this section, but was not able to address them in the final version. Lastly, OMB reverted the heading of this section back to “Audit services.”

Section 200.427—Bonding Costs
OMB did not propose significant changes to this section, nor did it receive significant comments. In the final version of section 200.427, OMB added “subrecipient” to make the provision applicable to both recipients and subrecipients. This more accurately conveys the policy intent. OMB also changed “Bonding costs” to “Costs of bonding” in paragraphs (b) and (c). This is a more precise formulation in the context of these provisions.

Section 200.430—Compensation—Personal Services
OMB proposed a variety of plain language and clarifying revisions to this section. Additionally, OMB also proposed to relocate some of the guidance within this section. OMB received a comment indicating that a citation in this section was out of date. Next, OMB received several comments requesting additional clarification on aspects of the guidance in which OMB did not propose a policy change, such as making approximations in allocating actual personnel costs. OMB also received several comments requesting OMB to address the increased costs of complying with overtime pay, which was related to a recently proposed U.S. Department of Labor (DOL) overtime rule. Lastly, OMB also received one comment indicating that the propose guidance does not explicitly permit recipients to provide a living wage.
OMB Response: In paragraph (d)(2) of section 200.430, OMB agrees with the comment stating that 10 U.S.C. 2324(e)(1)(P) was repealed. OMB updated the guidance to reference the recodified statute at 10 U.S.C. 3744(a)(16). ^6
^6 Public Law 116-283 transferred 10 U.S.C. 2324(e)(1)(P) to appear in 10 U.S.C. 3744(a)(16).
In paragraph (i)(7)(ii) OMB restored language from the prior version of the guidance, which was inadvertently muddled by OMB's proposed revisions. OMB also replaced “recipient” with “IHE” in paragraph (i)(8) because the policy contained in paragraph (i) only pertains to IHEs.
In response to requested changes in part 200 to reflect DOL's new rule, the policies in the DOL rule are beyond the scope of proposed changes in OMB's 2 CFR guidance update. OMB did not make changes on this topic in its current update of the 2 CFR text. Regarding the comment on changing the policy to “provide a living wage,” OMB did not propose such a change, and does not have the authority to establish such a government-wide mandate on that topic through this update.

Section 200.431—Compensation—Fringe Benefits
In the proposed guidance, OMB proposed revising section 200.431 on fringe benefits to require recipients and subrecipients to allocate payments for unused leave as general administrative expenses or include them in a fringe benefit rate with cognizant agency approval. Based on feedback from the oversight community, OMB also clarified that recipients and subrecipients may not charge unfunded pension and post-retirement health benefits to an award in a manner that is inconsistent with the allocation principles of Subpart E. Also in section 200.431, OMB proposed additional clarifying guidance on pension plan costs and post-retirement health plans.
OMB received numerous comments expressing significant concerns about additional language that OMB proposed under paragraphs (g) and (h) addressing pension costs and post-retirement health plan costs. Many commenters objected to the potential impacts of this policy change on State and local governments. A number of commenters maintained that the proposed language lacked clarity and could lead to unintended consequences, including inconsistent outcomes as applied in practice and increasing agency and recipient burden. Commenters also suggested that the proposed guidance in these paragraphs would be inconsistent with established pension methodologies and standards. Commenters emphasized that both paragraph (g) on unfunded pension costs and paragraph (h) on post-retirement health plans needed further clarification from OMB in the final guidance.
Some commenters noted that the proposed revisions appeared to limit pension and other postemployment costs charged directly to Federal awards to the normal cost without recognizing the unfunded accrued liability (UAL) component of pension rates. Another commenter noted that use of the term “current pension cost” needed to be further clarified as it could potentially be interpreted as only “normal pension cost” and exclude “unfunded liability amortization.” The commenter noted that this could create an undue burden on State and local governments to fund this additional component. Another commenter noted that State pension systems use a rate that includes both normal pension costs as well the unfunded liability amortization. Some commenters specifically identified the change in paragraph (g)(6)(iii) from “in excess of the actuarily determined amount” to “in excess of the costs calculated using an actuarial cost-based method recognized by GAAP.”
OMB also received a comment requesting removal of the requirement in paragraph (g)(6)(vi) that recipients or subrecipients provide the Federal government an equitable share of any previously allowed pension costs that the recipient or subrecipient receives through a refund, withdrawal, or other credit.
OMB also received several comments on the parenthetical reference in paragraph (a) associated with the cost of leave—(vacation, sick, family, or military). Commenters argued that the cost of fringe benefits in the form of regular compensation paid to employees during periods of authorized absences from the job, such as for annual leave, family-related leave, sick leave, holidays, court leave, military leave, administrative leave, and other similar benefits, are allowable.
In paragraph (b)(3), a couple of commenters asked OMB to further clarify the distinction between subparagraph (i) on the cash basis of accounting versus subparagraph (ii) on the accrual basis, including further clarifying how to determine the basis of accounting. A commenter also requested a definition of general administrative expenses in paragraph (b)(3)(i).
One commenter noted that OMB has not consistently changed the word “family-related” to just “family.” This commenter recommended deleting “-related” after family in paragraph (b).
OMB Response: OMB appreciates all of the comments it received on proposed changes to section 200.431. After carefully reviewing the comments, OMB removed significant portions of the proposed language from paragraph (g) on pension plan costs and paragraph (h) on post-retirement health. In both paragraphs, OMB initially proposed language providing that costs may not exceed the contribution rate of the employee's current pension costs in one case and current health benefit costs in the other. In both paragraphs, OMB also proposed additional approval and notification requirements. OMB's intent for the proposed revisions was only to underscore that pension plan and post-retirement health plan costs cannot be charged to an award for employees that are not associated with the award. OMB removed the additional language from both paragraphs and left only the statement related to allocability. OMB agrees with the commenters that the proposed revisions would potentially result in unintended burden or confusion. Based on careful consideration of the comments on this topic, OMB substantially scaled back its proposed revisions to section 200.431 as further detailed below.
OMB revised paragraph (a) of section 200.431 to remove the parenthetical reference to types of leave. The reference contained only some of the types of leave—family, vacation, sick, or military—whereas paragraph (b) provides a more complete list of types of leave. The reference to “family-related” leave in paragraph (b) is also just an example of types of leave. OMB did not revise this term, but did remove the parenthetical in the preceding paragraph, which may have appeared to use inconsistent terms.
OMB revised paragraph (b)(3)(i) of section 200.431 to remove the requirement that agencies must include certain costs in fringe benefit rates only with the approval of the cognizant agency for indirect costs. OMB recognizes that some recipients might not have a cognizant agency for indirect costs. OMB received numerous comments on this proposed requirement, which is removed from the final guidance. OMB otherwise finds paragraph (b)(3) sufficiently clear and similar to the policy in the prior version of the guidance. In response to comments asking OMB to further clarify the distinction between the cash basis of accounting versus the accrual basis, OMB did not insert additional guidance on this topic. OMB may consider doing so in the future, but was not prepared to do so through this update. OMB also did not find it necessary to provide a definition of general administrative expenses at this time.
OMB revised paragraph (g)(6)(iii) of section 200.431 to revert to the prior language that amounts funded by the recipient or subrecipient in excess of the “actuarially determined amount” for a fiscal year may be used as the recipient's or subrecipient's contribution in future periods. The language included in the draft revisions had inadvertently changed the meaning.
OMB also substantially revised paragraph (g)(6)(v) of section 200.431, which was the focus of many comments, to remove much of the additional language that was proposed. OMB removed guidance stating that “payments for unfunded pension costs may not exceed the contribution rate of the employee's current pension costs” in response to numerous public comments objecting to this change. OMB also removed other newly proposed language following that sentence in response to concerns expressed by commenters. Through the proposed updates, OMB only sought to clarify that payments for unfunded pension costs must be charged in accordance with the allocation principles of subpart E. Specifically, the recipient or subrecipient may not charge unfunded pensions costs directly to a Federal award if they are not allocable to that award. OMB deleted additional proposed guidance on unfunded pension costs that caused significant concern to commenters.
OMB revised paragraph (g)(6)(vi) of section 200.431 to revert to previous language stating that the recipient or subrecipient must provide the Federal Government an equitable share of any previously allowed pension costs “that revert or inure to the recipient or subrecipient.” OMB proposed to refer to pension costs that the recipient or subrecipient “receives.” OMB did not intend to change the meaning and reverted to the prior guidance text.
Under paragraph (h) of section 200.431 on post-retirement health, OMB revised paragraph (h)(3) to revert to the prior language, which stated that amounts “funded by the recipient or subrecipient in excess of the actuarially determined amount for a fiscal year may be used as the recipient's or subrecipient's contribution in future periods.” The language included in the draft revisions inadvertently changed the meaning.
OMB revised paragraph (h)(5) of section 200.431 to remove a significant portion of the newly proposed language. OMB only sought to clarify that payments for unfunded post-retirement health plan (PRHP) costs must be charged in accordance with the allocation principles of subpart E. Specifically, the recipient or subrecipient may not charge unfunded PHRP costs directly to a Federal award if they are not allocable to that award. OMB deleted additional proposed guidance on unfunded PHRP costs that caused significant concern to commenters.
OMB revised paragraph (h)(7) of section 200.431 to revert to the original language stating the recipient must provide the Federal government with an equitable share of costs that “revert or inure” to the recipient, rather than the previous formulation describing costs “received” by the recipient. OMB considers the original language to be more precise and appropriate in this context.
OMB revised paragraph (i)(5) of section 200.431 to clarify circumstances in which severance payments to foreign nationals need approval by the Federal agency. To the extent these payments would be required by foreign law, OMB did not find the Federal agency approval requirement was warranted. However, OMB retained the Federal agency approval requirement for payments under this paragraph deemed “necessary for the performance of Federal programs.” OMB generally retained the language as proposed, but slightly restructured the paragraph to make this distinction clear.
OMB revised paragraph (k) to relocate a clarifying statement to a new paragraph (k)(2). That relocated provision at (k)(2) states that the “allowability of these costs for the IHE does not depend on whether they are recorded in the accounting records of the IHE.”
OMB did not propose any changes related to unused leave in section 200.431. In paragraphs (g)(6)(vi) and (h)(7), OMB disagrees with comments suggesting that the requirement to provide the Federal government with an equitable share of costs should be changed, even if the amount could potentially be small.

Section 200.432—Conferences
In the proposed guidance, OMB clarified the description of conferences in section 200.432 to remove any limitations provided by the specific types of events listed in the guidance currently. OMB also allowed for dependent-care costs associated with participants' attending or partaking in program-related conferences.
OMB received many comments in support of the changes to this section, in particular noting that the proposal to allow for dependent-care costs associated with participants' attending or participating in program-related conferences in particular would enable more employees of lesser means to participate in educational programming that will benefit their performance. OMB received one comment requesting the guidance in 200.432 to also specifically include costs for attending conferences as allowable costs.
OMB Response: OMB revised section 200.432 to remove language specifying that allowable conference costs may only include those paid by the recipient or subrecipient as a sponsor of the conference. OMB recognizes that some program activities include conference costs sponsored by another party. OMB also clarified that these costs can include attendance fees.

Section 200.433—Contingency Provisions
OMB did not propose significant changes to this section. In the final guidance, section 200.433 was revised to change contingency “costs” to contingency “amounts.” This better reflects that the policy relates not to the “costs” themselves, but rather to the “amount” of costs. OMB also clarified that the costs for major project scope changes, unforeseen risks, or extraordinary events “must not be included in the proposed budget estimates for a Federal award,” even if they are in fact allowable should they arise.

Section 200.434—Contributions and Donations
OMB did not propose significant changes to this section. OMB received one comment requesting that the guidance clarify that the value of the donations of personal property and use of space may be used to meet cost sharing of nonprofit corporations. Another comment requested that OMB remove the stipulation for nonprofits that the cost of volunteer services often “must be allocated a proportionate share of applicable indirect costs.”
OMB Response: OMB revised paragraph (g)(2) of section 200.434 to clarify that the value of donation of “personal property and use of space” are allowable as cost share. This clarifies that the guidance does not mean the value of donations in general.
OMB did not propose a change to the policy in paragraph (e) applicable to nonprofit organizations. OMB considers the comment on this provision out of scope relative to the proposed changes to the guidance. OMB finds that the requested change to the “proportionate share” requirement is not warranted in this update.

Section 200.435—Defense and Prosecution of Criminal and Civil Proceedings, Claims, Appeals and Patent Infringements
OMB did not propose significant changes to this section. In the final guidance, OMB made some minor clarifying and grammatical edits in this section, including correcting a paragraph heading. In paragraph (a)(2), OMB also revised the definition of “costs” applicable in section 200.435. The revised definition explains earlier in the paragraph that costs “include the services that bear a direct relationship to a judicial or administrative proceeding.” OMB finds this change clarifies the policy in this section.

Section 200.438—Entertainment and Prizes
In the proposed guidance, OMB included prizes in this section. Guidance on prizes was located in subpart B in the prior version of the guidance despite the fact that prizes are an item of cost. OMB received several comments expressing support for the proposed revisions made to section 200.438. Several commenters also requested that OMB incorporate language from OMB Memorandum M-10-11, Guidance on the Use of Challenges and Prizes to Promote Open Government, into the guidance.
OMB Response: With minor edits, OMB otherwise incorporated the revisions in this section as proposed. OMB agrees, however, that OMB Memorandum M-10-11, as referenced by commenters, remains a relevant source of information providing additional guidance to Federal agencies on this topic.

Section 200.439—Equipment and Other Capital Expenditures
In the proposed guidance, OMB revised paragraph (b)(2) of section 200.439 to adjust the dollar value for special purpose equipment requiring prior approval from $5,000 to $10,000. Other sections of the guidance provide that equipment refers to items over $10,000. In the final guidance, OMB made additional clarifying edits—including replacing “direct charges” with “direct costs” in two places—but otherwise made changes in this section as proposed.

Section 200.440—Exchange Rates
In the proposed guidance, OMB removed the requirement for prior approval of fluctuations of exchange rates. OMB explained that while a recipient or subrecipient would still need prior approval for additional Federal funding, no approval is required because an exchange rate has fluctuated and resulted in a necessary charge to available funding. OMB received one comment supporting this change.
OMB Response: In the final guidance, OMB reverted to the prior version of the guidance on exchange rates. The circumstances when prior written approval is needed in relation to fluctuations in exchange rates are narrowly defined within the prior version of the guidance in section 200.440—which OMB restored. Prior approval is only needed when the change results in the need for additional Federal funding, or the increased costs result in the need to significantly reduce the scope of the project. Because prior approval remained necessary in these circumstances in both the prior and proposed versions of the guidance, OMB decided it would clarify the policy to retain the reference to this provision in section 200.407 and continue to explain circumstances in which prior approval is needed within section 200.440.

Section 200.442—Fund Raising and Investment Management Costs
OMB did not propose significant changes to this section. OMB received one comment recommending that OMB revert to the prior language of OMB Circular A-122.
OMB Response: OMB disagrees that a change was necessary. OMB finds that the suggestion to revert to the earlier circular was out of scope relative to the proposed revisions to the final guidance. In the final guidance, OMB included revisions in this section as proposed.

Section 200.443—Gains and Losses on the Disposition of Depreciable Assets
OMB did not propose any significant changes to this section. In the final guidance, OMB made a minor change from “individual basis” to “case-by-case basis.”

Section 200.445—Goods or Services for Personal Use
OMB revised section 200.445(b) to clarify that the housing costs refer to those costs as associated with a recipient's or subrecipient's employees. In addition, OMB removed the reference to the costs being allowable “regardless of whether [they are] reported as taxable income to the employees.” Upon further review, OMB considered this to be an unnecessary clarification. It is sufficient to state that such costs are only allowable as direct costs and must be approved by the Federal agency.

Section 200.447—Insurance and Indemnification
OMB did not propose significant changes to this section. OMB received one comment that suggested OMB incorporate additional guidance on medical liability insurance and include “general liability” as an example of contributions to a self-insurance program. The commenter also requested a change to the title of section 200.447.
OMB Response: OMB did not make changes to section 200.447 in response to the comment. The additional policy on medical liability insurance suggested by a commenter fell outside the scope of OMB's proposed changes. OMB also decided that providing the additional example of “general liability” was unnecessary.
OMB made a minor revision to paragraph (d)(3)(ii) of section 200.447 to insert “levels described in paragraph (d)(3)(i)” in place of the “above-mentioned value.” OMB found the revised text to be more precise. OMB also removed the header on paragraph (b)(6) and added a clarification to that paragraph. Lastly, OMB made a typographical fix to paragraph (d)(1).

Section 200.448—Intellectual Property
OMB did not propose significant changes to this section. OMB received one comment requesting changes to address royalties received on a patent or copyright.
OMB Response: OMB did not make any policy changes to this section. OMB considered the comment on royalties to be out of scope of its proposed revisions for this update and did not make a change.

Section 200.452—Maintenance and Repair Costs
OMB did not propose significant changes to this section. OMB received several comments asking OMB to clarify allowability of maintenance warranties. The commenters noted that this section specifically states that costs intended to keep buildings and equipment in efficient operation are allowable, but does not address warranties.
OMB Response: OMB disagrees that costs related to maintenance warrantees and other related costs need to be included in this section. This would constitute a significant policy change and such changes were not proposed for comment.

Section 200.454—Memberships, Subscriptions, and Professional Activity Costs
In the proposed guidance, OMB revised section 200.454 to remove prior approval requirements for the cost of membership in any civic or community organization. OMB updated the final guidance as proposed.

Section 200.455—Organization Costs
In the proposed guidance, OMB revised section 200.455 to clarify that any costs associated with either persuading or dissuading employees from collective bargaining and related activities are not allowable under Federal awards. OMB also added clarifying language that certain costs related to data, evaluation, and other related organization costs are allowable.
OMB received a number of comments expressing appreciation for the increased clarity for allowable organization costs. However, some commenters requested the inclusions of many additional types of activities—and even new subsections—related to organization costs. Examples of these activities included community engagement, outreach activities, personnel, materials, cloud-based services, and cyber security measures related to effectively building and using evidence and evaluation for program design, administration, or improvement.
One comment objected to the inclusion of new language related to costs associated with either persuading or dissuading employees from collective bargaining and related activities, citing that it is redundant as it is already covered under the National Labor Relations Act (NLRA). OMB received one comment that section 200.455(b) was difficult to understand the way it was presented.
OMB Response: OMB made a minor revision to paragraph (b) of section 200.455 by moving the phrase the “costs of any of the following activities are unallowable” to the beginning of the paragraph. OMB made this change to improve readability in response to a comment.
OMB revised paragraph (c) of section 200.455 to clarify that some of the proposed language addressed data costs. OMB's revisions to the final guidance now provide additional information on evaluation costs.
In response to comments, OMB observes that various costs related to program design, monitoring, and evaluation can be allowable costs. OMB disagrees, however, that this section should include all of the additions suggested by commenters. In applying the cost principles in subpart D, the absence of any particular costs in the general provisions for selected items of cost does not imply that such costs are necessarily unallowable. See 2 CFR 200.420(b). OMB also disagrees that referencing the NLRA was redundant and retained the language. It is helpful to clarify for both agencies and recipients.

Section 200.456—Participant Support Costs
In the proposed guidance, OMB removed from section 200.456 the prior approval requirement of participant support costs. OMB received several comments in support of the proposed changes to section 200.456. OMB also received one comment requesting additional clarity on whether written policies and procedures needed to be developed on the subject of participant support costs.
OMB Response: OMB disagrees that it was necessary to establish any specific format or requirements for policies and procedures regarding participant support costs. For this update, OMB decided that establishing additional requirements was not necessary.

Section 200.458—Pre-Award Costs
OMB did not propose significant changes to this section. OMB received several comments objecting to the policy requiring prior written approval for pre-award costs, noting that this would constitute a possibly unintended policy change. OMB also received several specific comments regarding pre-award costs—requesting, for example, that OMB expand the pre-award costs description to specifically state that the recipient or subrecipient would be allowed to “achieve outcomes” prior to the award dates. Another commenter requested that OMB state affirmatively that pre-award costs apply to all types of assistance, including discretionary grants.
OMB Response: OMB agrees with the comment pointing out that the requirement for “prior written approval” could constitute an unintended policy change. OMB removed the word “prior” in the final text. OMB emphasizes, however, that written approval is still required for pre-award costs. OMB did not incorporate additional policy changes in response to the comments relating to specific costs, activities, or award types. The description of pre-award costs only provides general guidance on the allowability of and general process for such costs.

Section 200.460—Proposal Costs
OMB did not propose significant changes to this section. OMB received one comment requesting that OMB provide guidance to agencies, including elaborating on the need for Federal agencies to make efforts to reduce requirements requested at the proposal development stage.
OMB Response: OMB did not revise the guidance in response to this comment. Generally, OMB considers this to be an agency-specific issue that is not appropriate for resolution through policy guidance in this section.

Section 200.461—Publication and Printing Costs
In the proposed guidance, OMB revised section 200.461 to add additional clarifying guidance on publication and printing costs by adding reference to “article processing charges” or “similar open access fees.”
OMB received one comment supporting the proposed revisions. OMB received several comments requesting that section 200.461 refer to article publishing charges (APCs) and not “processing charges.” The same commenters also requested that OMB change the policy regarding how charges are levied by a journal. Several other commenters submitted recommendations to make additional changes that would be out of scope of the proposed changes, or were deemed unnecessary. For example, OMB received comments underscoring that researchers are permitted to budget for the costs of managing and sharing research data, software, code, and other open science outputs resulting from a Federal award; or addressing costs related to the making available of software or data and the curation, metadata tagging, hosting, preservation, and other charges related to open science. Finally, one comment recommended replacing “developed under a Federal award” with “resulting from research performed under a Federal award” for clarification.
OMB Response: OMB revised paragraph (b) of section 200.461 to refer to “similar fees such as open access fees,” rather than “similar open access fees.” The prior formulation was revised because it implied that the preceding terms, such as “page charges,” were “open access fees.” OMB also clarified that these charges can be “resulting from a Federal award,” as opposed to “developed under” a Federal award. OMB recognizes that, in some cases, it may be possible for charges to result from a Federal award, but not necessarily be developed under the award.
OMB did not make substantial changes to this section to include multiple examples of costs but appreciated the comments for future consideration.

Section 200.463—Recruiting Costs
OMB revised Paragraph (d) of section 200.463 to restructure the sentence on short-term visa costs for the sake of clarity. OMB considers the revised language to flow better than the previously proposed language.

Section 200.465—Rental Costs of Real Property and Equipment
OMB did not propose significant changes to this section. OMB received one comment requesting that OMB remove the word “workspace” from the reference to “right-of-use operating lease asset,” citing that it is unclear what would be considered an “operating lease workspace asset” as opposed to what would be considered an “operating lease asset.” Further, one comment requested that OMB reinstate the term “FASB standards” in relation to leases, since both the financial reporting frameworks of the “GASB” and “FASB” are considered generally accepted accounting principles (GAAP). One commenter requested language pertaining to the application of the cost principles for Subscription Based Information Technology Arrangements be included.
OMB Response: OMB revised paragraph (c)(2) of section 200.465 to clarify that the arms-length leases under common control refer to those between a recipient or subrecipient “and another entity” and not between the recipient and subrecipient.
OMB revised paragraphs (d) and (e) of section 200.465 to revert to the existing language that referenced FASB standards instead of GAAP standards. OMB also revised paragraph (e) to remove “workspace” before “asset.” OMB considered the comment on Subscription Based Information Technology Arrangements to be out of the scope of this update.

Section 200.466—Scholarships, Student Aid Costs, and Tuition Remission
OMB did not propose significant changes to this section. OMB received one comment requesting that OMB divide paragraph (a) into two paragraphs to address “tuition remission” separately. The commenter also asked OMB to revise the title to include mention of tuition remission, which the commenter stated would better reflect the current policy. OMB also received multiple comments requesting clarification as to whether various restrictions that apply to IHE's should also apply to other comparable degree issuing organizations.
OMB Response: In response to the comment on tuition remission, OMB restructured the first paragraph to break it in two. OMB also added “tuition remission” to the section header. OMB did not make revisions in response to the other comments received on this section. OMB finds the section presents policy on scholarships and student aid costs adequately and appropriately. While OMB is not proposing a change at this time to address the application of policy to other degree-issuing organizations, OMB appreciates the comments for future consideration.

Section 200.467—Selling and Marketing Costs
In the proposed guidance, OMB removed the prior approval option for selling and marketing costs, clarifying selling and marketing costs are unallowable unless they meet the requirements in section 200.421 and are required to meet the requirements of the award. OMB included revisions to this section as proposed in the final guidance.

Section 200.468—Specialized Service Facilities
OMB did not propose significant changes to this section. OMB received one comment requesting clarification that the costs of services include the acquisition cost of necessary equipment and also to add to the additional examples of the types of facilities. Another commenter also requested that OMB address other service facilities.
OMB Response: The “acquisition cost of necessary equipment” is not in the same category as a “cost of service.” Additionally, the types of facilities provided are merely examples of facilities and intended to be illustrative. OMB did not find these suggestions warranted changes at this time and did not make additional revisions. OMB did not propose to expand the information in section 200.468 to address other types of service facilities and is not revising the guidance in response to this comment.

Section 200.470—Taxes (Including Value Added Tax)
OMB did not propose significant changes to this section. OMB received one comment requesting that OMB clarify that these costs include payments made by tax exempt institutions to local governments to offset the loss of taxes and that are commensurate with the local government services received.
OMB Response: OMB did not agree that a clarification was necessary and did not make a change to this section based on this comment.

Section 200.472—Termination and Standard Closeout Costs
OMB proposed to revise the section on termination costs at section 200.472 to include closeout costs. Specifically, OMB proposed to include guidance for recipients and subrecipients to charge administrative costs specifically associated with the closeout of a Federal award.
OMB received many comments supporting the clarification that specific administrative closeout costs are allowable. OMB received feedback from the Federal financial assistance community that the exclusion of closeout costs in the Uniform Guidance has been problematic as recipients and subrecipients have been unable to charge actual costs associated with closeout actions, such as certain administrative or staff costs not covered through indirect cost recoveries. OMB received several comments requesting specific clarifications, as well as suggesting modification to existing policy. For example, OMB received one comment seeking clarification on the allowability of indirect costs. OMB received several comments suggesting that closeout costs have a longer liquidation period than the 120 days provided by OMB guidance and that costs should therefore be covered beyond the period of the due date of the final report. Finally, OMB received one comment requesting that we specify that termination is “prior to its stated expiration date” and requesting that OMB qualify that closeout costs refer to “normal closeout costs.” The commenter also requested that OMB add “data management and sharing” and “compliance” costs.
OMB Response: OMB revised paragraph (a)(4) of section 200.472 to restructure the paragraph in refence to rental costs. Specifically, the phrase “less the residual value of such leases” and the sentence referring to costs of alteration and restoration were moved for clarity.
OMB revised paragraph (b) of section 200.472 to include indirect costs in examples of allowable administrative close-out costs. This change was intended to clarify that indirect costs are often associated with the closeout activity. For example, they may include administrative staff expenses.
The list of closeout costs provided in paragraph (b) are only examples and not exhaustive of all types of closeout activities. OMB thus elected not to expand this paragraph further with terms such as “data management and sharing.”
In response to the comments requesting a longer liquidation period, OMB disagrees that a longer liquidation period is necessary. OMB did not revise the guidance to accommodate comments on this topic in this section. In the final guidance, sections 200.328(d) and 200.344(b) continue to recognize a period of 120 days.
Finally, in response to the comment suggesting that OMB clarify that termination occurs before the stated expiration date, a termination date is always before the stated expiration date of the award. In response to the request to clarify that standard closeout costs are “normal closeout costs,” the title of the section itself refers to “standard closeout costs.” OMB considers it critical that closeout costs under this section be specifically related to the closeout of the award—and not compliance or other activities, which are not “standard” or normal closeout costs. OMB finds that the text of the guidance is sufficiently clear on this point and does not make a change.

Section 200.475—Travel Costs
OMB did not propose significant changes to this section. OMB received one comment that requested OMB incorporate government travel regulations into section 200.475.
OMB Response: OMB did not make a change in response to this comment. It is beyond the scope of the proposed changes to section 200.475. Recipients are ultimately responsible for adhering to the cost principles of this subpart, but not necessarily to the government travel regulations. OMB made certain clarifying edits to paragraph (c) of section 200.475.

Subpart F—Audit Requirements

General Comments on Subpart F
Specific proposed changes to subpart F are discussed section-by-section below; however, some commenters provided comments on the subpart generally. Several commenters asked OMB to revise this subpart to use the terms “recipient” and “subrecipient” in the same way that OMB had proposed revisions in other subparts. Other comments recommended expanding subpart F to explicitly apply to for-profit organizations.
OMB Response: OMB must ensure that its guidance throughout part 200 is consistent with authorizing statutes. The Single Audit Act, as amended, only applies to non-Federal entities as that term is defined in the Act and section 200.1 of OMB's guidance. OMB finds using the terms “recipient” and “subrecipient” throughout OMB's implementing guidance for the Single Audit Act in subpart F of part 200 would create unnecessary confusion on the applicability of the Act. OMB does not have authority to expand the applicability of the statute. OMB appreciates the commenters' suggestions on developing separate audit requirements applicable to for-profit organizations and will consider these recommendations for future updates to OMB's guidance. This could potentially involve establishing a separate subpart with audit requirements applicable to for-profit organizations or a separate division of subpart F, which would not impact OMB's implementation of the Single Audit Act for non-Federal entities. In the final guidance, OMB continues to only apply subpart F to “non-Federal entities.”

Section 200.501—Audit Requirements
In this section, OMB proposed to raise the audit threshold from $750,000 to $1,000,000. Every two years, the Director of OMB is authorized to adjust the dollar amount of this threshold consistent with the purposes of the Single Audit Act, provided the Director does not make such adjustments below $300,000. 31 U.S.C. 7502.
OMB received numerous comments supporting the increase in the threshold to $1,000,000. A few commenters also opposed the change. They stated that the increase posed a significant risk to the oversight of Federal awards that would outweigh any benefits. Other commenters stated that the increase would place a greater burden on pass-through entities to monitor subrecipients. Conversely, several comments suggested that OMB should increase the audit threshold even higher than $1,000,000.
A few commenters requested further clarification in paragraph (h)—explaining circumstances in which the auditee is responsible for ensuring compliance for procurement transactions. Commenters observed that OMB's use of passive voice in this provision caused confusion on which party OMB intended to be responsible for program compliance. One commenter stated that OMB should revise paragraph (g) of section 200.501 to clarify that Federal awards expended as a recipient or subrecipient may not be subject to subpart F if there is a statutory exemption. Multiple commenters stated that this section should be revised to state that payments received as a beneficiary are not subject to subpart F.
OMB Response: OMB appreciates all of the comments received on its proposed increase to the audit threshold from $750,000 to $1,000,000. As discussed above, numerous comments expressed strong support for the increase, but other commenters explained some concerns. In determining the appropriate increase, OMB evaluated the number of entities that would benefit from the increase in connection with the types of auditor opinions issued and the number of questioned costs. OMB disagrees with the comments suggesting that the increase in the threshold poses a significant risk to oversight. The increase in the threshold should not materially increase the burden related to monitoring subrecipients; the requirement to have an audit conducted is not a substitute for proper monitoring. Regardless of whether audit requirements apply, pass-through entities should monitor subrecipients consistent with requirements in part 200. The increased threshold represents the smallest percentage increase to the threshold to date. The increase also aligns closely with the Consumer Price Index since the last increase in 2014. OMB appreciates commenters' concerns but has decided to maintain the proposed increase to the audit threshold.
After updating the threshold in paragraph (a), OMB also revised paragraph (b) of subpart F to clarify that Single Audit requirements apply to a non-Federal entity “that expends $1,000,000 or more in Federal awards during the non-Federal entity's fiscal year.”
OMB revised paragraph (g) of section 200.501 to clarify that Federal awards expended as a recipient or a subrecipient are subject to audit under subpart F unless a program is exempted by a Federal statute. OMB agrees with the request from commenters to provide this clarification in the guidance text.
In the final guidance, OMB revised paragraph (h), which explains circumstances in which the auditee is responsible for ensuring compliance for procurement transactions. OMB's proposed revisions to this paragraph prompted questions from commenters. In the final guidance, OMB explains that, for procurement transactions in which the contractor is made responsible for meeting program requirements, the auditee must ensure those requirements are met, including by clearly stating the contractor's responsibilities within the contract and reviewing the contractor's records to determine compliance. In other words, an auditee may not simply rely on procurement transactions to achieve program compliance—or outsource the function of complying with a Federal program requirement to a third-party contractor without monitoring the activities of the contractor to ensure compliance. The responsibility for program compliance continues to belong to the auditee. In the final guidance, OMB also included cross-references between sections 200.318(b) and 200.501(h), as requested by a commenter.
OMB received some questions on possible misalignment between the subject heading and first sentence of paragraph (i). Although the subject heading and subsequent text in the paragraph refer to for-profit subrecipients, the first sentence more broadly states that subpart F does not apply to for-profit organizations. OMB considered revising the sentence to only refer to for-profit subrecipients, but did not want to create confusion on whether the subpart applies to other for-profit organizations such as recipients. Thus, although the remainder of the paragraph discusses for-profit subrecipients, OMB retained the original statement that the subpart does not apply to for-profit organizations in general, which is also accurate.
OMB reviewed comments requesting clarification on whether or not subpart F applies to program beneficiaries. As explained above in this preamble in the context of definitions in section 200.1, OMB did not provide a government-wide definition of the term “beneficiary” through this update. The meaning of the term beneficiary can vary widely between Federal agencies and even within agencies between assistance programs. Many Federal programs may have different definitions and requirements applicable to beneficiaries in their authorizing statutes or agency regulations and guidance. For these reasons, OMB does not provide government-wide guidance on the applicability of subpart F to beneficiaries, which is not a defined term in part 200. Individual Federal agencies may provide further guidance on this topic for their assistance programs provided that any such guidance is consistent with the statutory requirements in the Single Audit Act. Federal agencies should also include information in their compliance supplement drafts on whether or not payments received as a beneficiary are subject to audit requirements.

Section 200.502—Basis for Determining Federal Awards Expended
In section 200.502, OMB proposed to clarify that, in determining Federal awards expended, loan and loan guarantees retain their Federal character through the end of the Federal award period of performance, unless otherwise specified in statute or Federal agency regulations. Multiple commenters stated that the proposed language could cause confusion. The comments suggested that some individuals may interpret the language to mean that there are always continuing compliance requirements. OMB also received a question on language in the preamble to the proposed guidance discussing proposed changes to the schedule of expenditures of Federal Awards immediately after discussion of proposed changes to section 200.502. OMB's final guidance on the schedule of expenditures of Federal Awards is discussed and clarified under section 200.510 below, not under section 200.502.
OMB Response: OMB revised paragraph (b) of section 200.502 to avoid potential confusion. OMB removed the proposed language stating that loans and loan guarantees retain their Federal character through the end of the period of performance. While the statement is accurate, it is not essential to include within the guidance in this paragraph on calculating the value of Federal awards expended under loan programs. Inclusion of this statement in this paragraph of the guidance is also not essential in determining whether or not a loan or loan guarantee has continuing compliance requirements.

Section 200.504—Frequency of Audits
OMB did not propose significant changes to this section. One commenter asked OMB to address situations that result in partial audit periods. For example, partial audit periods could result from a fiscal year change or mergers and acquisitions. Another commenter questioned whether the dates associated with biennial audits are still necessary.
OMB Response: OMB revised section 200.504 to clarify that annual audits are required unless biennial audits are permitted under paragraphs (a) or (b). OMB also clarified that biennial audits must cover both fiscal years within the biennial period. The ability to conduct biennial audits is recognized in certain circumstances under the Single Audit Act. Relevant provisions of the Single Audit Act as codified at 31 U.S.C. 7502 and OMB's implementing guidance in this section explain the circumstances in which biennial audits are permitted.
OMB did not find it necessary to specify how partial audit periods should be handled through this update. The circumstances of a merger or acquisition, or change in fiscal year, can present many variations, which OMB is not prepared to address at this time. Under section 200.513(a)(4)(x), it is the responsibility of the cognizant agency for audit to provide guidance on changes in the fiscal year. Under section 200.513(a)(4)(i), the cognizant agency for audit may also provide technical audit advice and liaison assistance on other variations, which should be addressed in a manner consistent with the framework provided by subpart F.

Section 200.505—Remedies for Audit Noncompliance
OMB did not propose significant changes to the content of this section, but proposed changing its heading from “Sanctions” to “Remedies for noncompliance.” One commenter observed that, based on this proposed change, both sections 200.505 and 200.339 in the proposed guidance had the same heading. The commenter suggested changing the heading for this section to “remedies for not being audited.”
OMB Response: In response to comments, OMB revised the heading of section 200.505 from “Remedies for noncompliance” to “Remedies for audit noncompliance” (emphasis added).

Section 200.507—Program-Specific Audits
OMB did not propose significant changes to this section. One commenter recommended several revisions to this section, such as changing the type of engagement for program-specific audits to a compliance examination engagement.
OMB Response: While OMB did not propose a change for public comment, OMB appreciates the comments received and may consider them for future updates. Some of the requests would require further analysis to determine whether they would be consistent with authorizing law and OMB policy. Other than minor grammatical fixes, OMB did not make a change at this time. OMB made minor clarifying edits to the header of paragraph (c)(1) to ensure proper alignment with the content of the paragraph. OMB also made other minor clarifying edits in this section, such as updating references to the submission and reporting package.

Section 200.508—Auditee Responsibilities
OMB did not propose significant changes to this section. One commenter asked OMB to revise this section to add the auditee's responsibility to prepare the auditee sections of the data collection form and to make the submission to the Federal Audit Clearinghouse (FAC).
OMB Response: Section 200.508(a) states that an auditee is required to ensure the audit is properly submitted in accordance with section 200.512. In the final guidance, OMB included the minor changes to this section as proposed. OMB did not make any further edits to this section in the final guidance.

Section 200.509—Auditor Selection
OMB did not propose significant changes to this section. One commenter stated that OMB should consider easing the restriction on selecting an auditor who prepares the indirect cost proposal or cost allocation plan. Another commenter suggested that auditees should be allowed to procure an auditor using their own procurement policy, instead of the existing requirements.
OMB Response: While OMB did not propose a change to the policy, OMB appreciates the comments on this section. OMB did not make a change to the threshold to restrict certain auditors from being selected to perform an audit. OMB finds the threshold is appropriate and a critical safeguard to ensure there are no conflicts of interest. OMB understands the commenter's concerns regarding the method of procurement of an auditor. However, even though the Federal Government does not directly procure the Single Audit, it is required by Federal law and paid for with Federal funds. OMB finds the existing requirements are appropriate.

Section 200.510—Financial Statements
In section 200.510, at paragraph (b), OMB proposed additional guidance explaining that, for audits covering multiple recipients (such as departments, agencies, IHEs, and other organizational units), the schedule of expenditures must identify the recipient of the Federal award. Several commenters opposed this change. They indicated that it would be overly burdensome and that it added extraneous information, which is not necessary for the users of the Schedule of Federal Expenditures (SEFA).
OMB Response: OMB removed the proposed language in paragraph (b)(2) from the final guidance. OMB intends to look for alternative means of making the information available in a manner that would be less burdensome for auditees and auditors. OMB renumbered the subparagraphs in the final guidance appropriately.

Section 200.511—Audit Findings Follow-Up
OMB did not propose significant changes to this section. Several commenters stated that OMB should revise the guidance to clarify that corrective action plans must be on auditee letterhead and that OMB require a specific timeframe for corrective action completion and verification.
OMB Response: The guidance does not require a corrective action plan on auditee letterhead. This confusion results from a frequently asked questions document, which OMB may address separately outside of this guidance-making process. OMB did not find it necessary to establish a specific timeframe for completing corrective action because the nature and degree of audit findings and the corrective action required can vary significantly. It is the responsibility of the auditee to promptly take corrective action. See 2 CFR 200.508(c) (as revised). The auditee is also responsible for establishing an anticipated completion date. See 2 CFR 200.511(c) (as revised). OMB did not make any changes based on these comments, but made minor clarifying edits to this section in the final guidance.

Section 200.512—Report Submission
OMB proposed some clarifying revisions to this section. Several commenters suggested OMB specify how the FAC should follow up with known auditees that have not submitted the required data collection form and reporting packages. One commenter stated that OMB should remove the requirement that auditees make copies available for public inspection. Next, another commenter stated that a revision made to paragraph (a)(1) made it appear that the data collection form is a part of the audit itself. That same commenter stated that the required statements do not align with the required certifications in the FAC.
OMB Response: OMB revised paragraph (a) of section 200.512 to more accurately reflect the provisions of the Single Audit Act with respect to the report submission deadline. This paragraph now recognizes that a cognizant agency for audit or oversight agency for audit (in the absence of a cognizant agency for audit) may authorize extensions for Single Audit submissions when the nine-month timeframe would place an undue burden on the auditee. OMB also made a few clarifying and plain language revisions in paragraphs (a), (b), (e), and (g) of section 200.512 unrelated to authorizing extensions of the report submission deadline.
OMB did not add procedures on how the FAC follows up with known auditees. In response to another comment, the requirement for auditees to make copies of an audit available for public inspection is essential to Federal funding transparency. OMB understands the commenter's concerns about redundancy. However, the public may not be aware of the existence of the FAC and OMB finds it is still necessary for auditees to make copies available for public inspection. Lastly, OMB finds that the auditee and auditor certification statements are appropriately aligned to the guidance.

Section 200.513—Responsibilities
In section 200.513, OMB proposed to revise the responsibilities of Federal agencies. Specifically, OMB proposed to encourage Federal agencies to engage with external audit stakeholders and the Federal agency's Office of Inspector General, and the National Single Audit Coordinator (NSAC) prior to submitting compliance supplement drafts to OMB. In the same section OMB also proposed to clarify that a Federal agency's key management single audit liaison must also coordinate with the agency's Office of Inspector General and the NSAC, when appropriate.
OMB received many comments supporting the proposed revisions to this section. A few commenters also recommended that the guidance not just recommend but affirmatively require Federal agencies to engage with external stakeholders. One commenter requested that OMB reinstate language providing that OMB would conduct a government-wide audit analysis every six years. Other commenters stated that the change from “higher-risk” to “high-risk” in paragraph (c)(6)(ii) changed the meaning of the responsibility. One commenter asked OMB to revise the guidance to change the meaning of cross-cutting audit findings from findings that affect all Federal awards to those that “may affect a large proportion of all Federal awards.”
OMB Response: OMB revised paragraph (a)(4)(i) of section 200.513 to correct an unintended plain language revision. The word “liaison” was restored to the guidance text. Cognizant agencies for audit must provide technical advice and liaison assistance to auditees and auditors. Removing the word liaison was not intended to expand or otherwise alter the scope of cognizant agency responsibility.
In paragraph (a)(4)(iii) of section 200.513, OMB disagrees that the government-wide analysis requires a fixed interval. Instead, OMB finds that the government-wide analysis should be conducted on an as-warranted basis at intervals determined by OMB. OMB made clarifying edits to paragraph (a)(4)(viii) of section 200.513. OMB also provided an example of a cross-cutting audit finding.
OMB revised paragraph (c)(4) of section 200.513 to clarify that agencies “should” engage with external stakeholders, the Federal agency's Office of Inspector General (OIG), and the National Single Audit Coordinator (NSAC) prior to submitting compliance supplement drafts to OMB. OMB's edits also clarify that coordination with NSAC is not included within coordination with the agency's OIG; they are distinct items in the list. OMB understands the commenters' desire to require Federal agencies to engage with external stakeholders when submitting compliance supplement drafts. However, this may not be appropriate or feasible in all circumstances. OMB replaced “are encouraged to engage” with “should engage,” but generally maintained the proposed language on this topic. In the final guidance, OMB does not require engagement or specifically define what this engagement should involve.
OMB made a change at paragraph (c)(6)(ii). OMB agrees with the commenters that the proposed revision unintentionally changed the meaning of the guidance. OMB restored the reference to “higher risk” non-Federal entities.
OMB revised paragraph (c)(6)(vi) of section 200.513 to correct an unintended policy change made during OMB's plain language rewrite. The liaison is not responsible for managing a Federal agency's process for following up on cross-cutting audit findings. Rather, the liaison is responsible for ensuring the agency fulfills its responsibilities to coordinate a management decision for cross-cutting audit findings. In the final guidance, OMB also made other minor clarifying revisions in paragraphs (a) and (c) of this section.
OMB disagrees with commenters on changing the meaning of cross-cutting audit findings at this stage. This proposal would require further analysis to determine if a change could have unintended consequences. For example, OMB would need to evaluate further whether any such change could impact OMB's implementation of the Single Audit Act under this subpart.

Section 200.514—Standards and Scope of Audit
In section 200.514, on standards and scope of audit, OMB proposed to revise compliance requirements to specify that compliance testing must include a test of transactions and other auditing procedures necessary to provide the auditor with sufficient evidence to support an opinion on compliance.
One commenter stated that paragraph (b) should be revised because the Uniform Guidance does not set a basis of accounting for the financial statements prepared by the auditee. Several commenters stated that paragraph (d)(4) should be revised to remove the requirement that compliance testing include a test of transactions, as this may not be the most appropriate or effective methodology for every situation and compliance requirement. Another comment recommended that “sufficient audit evidence” be revised to “sufficient appropriate audit evidence” to better align with terminology used by the audit community.
OMB Response: OMB agrees with a comment on paragraph (b) of section 200.514 maintaining that part 200 does not set a basis of accounting for the financial statements prepared by the auditee. To recognize this, OMB added a parenthetical to paragraph (b) stating: “or a special purpose framework such as cash, modified cash, or regulatory as required by State law.”
OMB also agrees with commenters that testing of transactions may not always be the most appropriate method for every situation. Thus, OMB revised paragraph (d)(4) to state that compliance testing must include a test of transactions “or” other necessary auditing procedures. Lastly, OMB revised paragraph (d)(4) to reference “sufficient appropriate audit evidence” as requested by a commenter.

Section 200.516—Audit Findings
In section 200.516, based on feedback OMB received from the Federal financial assistance community, OMB proposed to revise the definitions of known questioned costs and likely questioned costs and provide further clarity on how they are identified in an audit report.
Several commenters submitted comments regarding these proposed definitions.
OMB Response: OMB addressed comments regarding definitions under subpart A of this preamble. OMB made only minor clarifying edits in the final guidance in section 200.516.

Section 200.517—Audit Documentation

Section 200.518—Major Program Determination
OMB did not propose significant changes to this section. Several commenters questioned whether OMB should revise the table for Type A thresholds in light of the increase to the Single Audit threshold.
OMB Response: OMB revised paragraph (b)(1) of section 200.518 to adjust the thresholds for determining Type A programs. OMB increased the threshold to $1,000,000 for non-Federal entities with total Federal awards expended that are equal to or exceed $1,000,000 but less than $34 million. OMB also made minor clarifications to paragraphs (b)(3) and (c).

Section 200.519—Criteria for Federal Program Risk

Section 200.520—Criteria for a Low-Risk Auditee
OMB did not propose significant changes to this section. OMB received several comments suggesting that plain language revisions to paragraph (b) of section 200.520 changed the meaning of the policy.
OMB Response: OMB agrees with some of the comments on paragraph (b) and reverted the language to be more consistent with the policy in the prior version of the guidance. OMB also clarified that the financial statements should be prepared in accordance with GAAP “or a special purpose framework such as cash, modified cash, or regulatory as required by State law.” This addition was made to ensure consistency throughout the subpart including with sections 200.514 and 200.515.

Section 200.521—Management Decisions
OMB did not propose significant changes to this section. A few commenters asked OMB to revise the guidance to clarify that a corrective action plan will be considered accepted without exception if an agency does not issue a management decision within six months. Another commenter asked OMB to correct a cross-reference in this section from 200.332(d) to 200.332(e). This commenter also asked OMB to add an exception to paragraph 200.521(c) on the pass-through entity's responsibility for issuing a management decision in this section. The commenter requested an exception for findings that are of a cross-cutting or systemic nature such that they will be resolved by the cognizant agency for audit.
OMB Response: While OMB did not propose a change for public comment, OMB considered and appreciates the comments expressing concerns about Federal agencies issuing timely management decisions. OMB may consider these comments for future updates. In response to the other commenter, OMB corrected the cross-reference in this section to reference the correct provision at section 200.332(e). OMB may also consider the suggestion to add an exception for findings that are of a cross-cutting or systemic nature for future updates, but did not include that language in the final guidance. OMB recognizes the exception available under the prior version of the guidance at section 200.332(e)(4). See 85 FR 49506, 49519 (Nov. 12, 2020). OMB did not propose to modify that exception, which remains available in the final version of the guidance. The relevant paragraph of section 200.332 is now referenced in section 200.521. OMB finds that it would be useful to obtain further information on how the existing exception works in certain circumstances before making additional changes to the guidance on this topic outside of section 200.332.

Appendix I to Part 200—Full Text of Notice of Funding Opportunity

General Comments on Appendix I
OMB proposed to revise this appendix in its entirety in support of the goal of simplifying and clarifying the grant solicitation and application process, which is a key objective under Executive Order 14058 on Transforming Federal Customer Experience and Service Delivery to Rebuild Trust in Government. The proposed changes to the NOFO in Appendix I were intended to improve the quality and accessibility of funding opportunities. Specifically, the proposed revisions to Appendix I intend to: (1) follow plain language principles; (2) group similar items together to streamline content; (3) align sections more closely to the application process; (4) include basic information at the top of a funding opportunity so that applicants can more easily make decisions about whether or not to apply; (5) clearly define what must be included in a section of the funding opportunity versus what is at an agency's discretion; and (6) provide flexibility to agencies while also giving applicants a common way to find information in every funding opportunity.
A significant number of commenters supported the proposed changes. Other commenters recommended that OMB maintain the existing language in Appendix I to Part 200. Several other commenters requested that OMB revise paragraph (b)(6)(ii)(A)( 4 ), which they stated was in conflict with section 200.306. Several commenters also requested that certain sections be renamed or provide further examples for illustrative purposes.
OMB Response: OMB appreciates the comments and support for the proposed changes to Appendix I. OMB disagrees with the comments recommending OMB maintain the existing text of the appendix. OMB finds the proposed revisions will simplify NOFOs in alignment with OMB's stated intent for the proposed revisions.
OMB revised paragraph (b)(3)(ii) of Appendix I to add a new paragraph (C). The new paragraph states that the program description section may also include, for infrastructure projects subject to Build America, Buy America requirements, “information on key items anticipated to be purchased under the program, and any related domestic sourcing concerns based on market research.”
Based on the final version of section 200.306, OMB disagrees with comments suggesting that paragraph (b)(6)(ii)(A)( 4 ) conflicts with section 200.306. Thus, OMB maintains this paragraph in Appendix I permitting a Federal agency to consider proposed cost sharing in the review process even if it is not an eligibility criterion. However, the Federal agency may only include such language in a NOFO if consistent with the current guidance provided by OMB in section 200.306.
OMB appreciates the comments suggesting ideas for renaming paragraphs in the appendix and providing additional examples. The appendix is only a template that outlines basic requirements for uniformity. Federal agencies retain discretion in certain areas to include additional information as necessary for a particular Federal financial assistance program. In the final guidance, OMB also made other minor clarifying edits in this appendix.

Appendix III to Part 200—Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Institutions of Higher Education (IHEs)
OMB proposed to update this appendix to adjust the exclusion threshold of subawards from $25,000 to $50,000 for modified total direct costs. OMB did not receive any substantive comments regarding the proposed change. OMB did not make significant changes to Appendix III to Part 200 relative to the proposed guidance.

Appendix IV to Part 200—Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Nonprofit Organizations
OMB proposed to update this appendix to adjust the exclusion threshold of subawards from $25,000 to $50,000 for modified total direct costs. OMB also proposed to clarify that under the direct cost allocation method, joint costs include costs for information technology. One commenter stated that there should be no exclusion for subawards unless it distorts the modified total direct cost base. The commenter also stated that recipients should be permitted to take a de minimis rate of 10 percent on all subawards to reduce administrative costs and to appropriately reimburse prime recipients for the appropriate costs required to manage and monitor subawards.
OMB Response: OMB disagrees with the commenter and finds the proposed increase is appropriate. OMB did not make significant changes to Appendix IV to Part 200 relative to the proposed guidance. In the final guidance, OMB did clarify that the Federal agency's review should be limited to ensuring the proposal is consistent with the principles of this part.

Appendix VII to Part 200—States and Local Government and Indian Tribe Indirect Cost Proposals
OMB proposed to update this appendix to adjust the exclusion threshold of subawards from $25,000 to $50,000 under modified total direct costs. OMB also proposed to clarify the meaning of “department or agency” for State and local governments.
OMB also proposed a revision to underscore that Federal agencies must accept indirect cost proposals developed by State or local departments or agencies receiving less than $35 million in their fiscal year. The proposed revision to this appendix also provides that Federal agencies cannot compel these State or local governmental departments or agencies to accept the de minimis rate, or any other rate established by the Federal agency, in place of their indirect cost proposals. In the preamble to the proposed guidance, OMB emphasized, however, that any such indirect cost proposals must be developed in accordance with the requirements of part 200 and maintained for audit—along with related supporting documentation.
One commenter asked OMB to revise and clarify the guidance to permit an awarding Federal agency to request that a governmental department or agency that receives $35 million or less in direct Federal funding during its fiscal year submit its indirect cost proposal for review.
OMB Response: OMB agrees with the comment described above. OMB revised paragraph (D)(1)(c) of Appendix VII to clarify that an awarding Federal agency may request that a governmental department or agency that receives $35 million or less in direct Federal funding during its fiscal year submit its indirect cost proposal for review. OMB also added language explaining that the Federal agency's review should be limited to ensuring the proposal is consistent with the principles of part 200.

Appendix X to Part 200—Data Collection Form
OMB proposed to revise this appendix to clarify where audit submission instructions are located. OMB did not receive any substantive comments regarding the proposed change. OMB made minor changes to Appendix X to revise the heading and incorporate minor clarifications.

Appendix XII to Part 200—Award Term and Condition for Recipient Integrity and Performance Matters
OMB proposed to revise this award term to be consistent with the statutory obligation and to reflect the appropriate location (responsibility and qualification records) in SAM.gov for reporting integrity and performance matters. OMB proposed to renumber the award term to align to the requirements of the standard organization of the CFR. OMB did not receive any substantive comments regarding the proposed change. OMB did not make significant changes to Appendix XII to Part 200 relative to the proposed guidance. OMB made changes in the final version of this appendix as proposed.

General Comments on 2 CFR
Several commenters requested that OMB simplify the process for organizations and service providers to apply for U.S. government funding. Other commenters asked OMB to center funding around what communities say they need and reduce recipient burden so that recipients of government grants can focus more on driving long-term impact. Commenters also asked OMB to make it easier for Federal officials to issue awards that deliver results, rather than focus on specific activities.
Some comments expressed appreciation for OMB's proposed use of terms such as “Federal agency,” “pass-through entity,” “recipient,” and “subrecipient.” Other commenters noted their appreciation of OMB's more specific use of connectors such as “and” and “or” to provide specificity on application of the policies in the guidance to Federal agencies, pass-through entities, applicants, recipients, and subrecipients. Conversely, some commenters opposed these changes and preferred the use of “non-Federal entity” throughout the prior version of the guidance.
Other comments discussed the need for more flexibility on indirect cost rates and for specific entities, such as Indian Tribes. Other commenters requested more training, webinars, FAQs, checklists, templates, and technical assistance. Other comments discussed the need for improved metrics, more access to data, rural impact analysis, supporting capacity building, and increased collaboration with organizations and among Federal agencies.
Lastly, OMB also received many comments offering general support for the proposed updates to 2 CFR without providing specific details on what the commenter supported. OMB also received some comments generally opposing the proposed changes without specifically indicating what the commenter opposed.
OMB Response: OMB appreciates the general feedback submitted on the revisions to 2 CFR. OMB will strive to continue to support the proper implementation and oversight of Federal financial assistance, including potentially through additional training, guidance, and supporting information. However, it is also incumbent on Federal agencies to address specific processes, data sharing, and coordination for their respective Federal financial assistance programs, as applicable. Federal agencies provide regulations, processes, and guidance documents, which are specific to their agencies and programs. While OMB strives to improve consistency across Federal programs, there are inherent limitations to the extent to which all processes can be uniform—such as variations in authorizing statutes.

Comments on 2 CFR Related to Process and Implementation
OMB received several comments on agency processes for implementing the final guidance. For example, some commenters questioned when the guidance would be applied to specific Federal agency programs. Other commenters had specific recommendations for the effective date of the final guidance and processes by which OMB and Federal agencies should work to implement it. OMB also received several questions on whether recipients may independently adopt or apply certain provisions of the guidance earlier than the guidance's effective date or prior to implementation by Federal agencies. A few commenters also requested either an extended comment period on OMB's proposed revisions or an opportunity to comment on OMB's final revisions.
Other commenters suggested that indirect cost rates could be affected by the increases in thresholds in the final guidance. Some of these commenters requested additional guidance on options for revising or renegotiating indirect cost rates to align with the final guidance.
Another commenter argued that OMB should have characterized the revision of the 2 CFR guidance as a significant regulatory action under Executive Order 12866 and accordingly undertaken a regulatory impact analysis. The commenter acknowledged that the guidance would be implemented by Federal agencies, but noted that implementation would occur government-wide.
OMB Response: OMB appreciates the comments suggesting specific processes for implementation and information provided by commenters on the potential effects of implementation processes. As discussed above in the preamble on sections of the OMB guidance related to its implementation, OMB did not make substantial changes to the long-standing structure of agency implementation of OMB's guidance in 2 CFR. Federal agencies are responsible for implementing the guidance for their Federal awards. See, e.g., 2 CFR 1.105(c), 1.110, 1.220, 200.106. Concurrently with the final guidance, OMB is issuing a memorandum to agencies with implementation guidance. OMB is not providing any additional guidance in relation to indirect cost rates beyond that already provided in the preamble above or the text of the final guidance. OMB also did not provide an additional or secondary comment period. OMB provided a 60-day comment period on the proposed guidance even though it was not required to do so by the Administrative Procedure Act, and commenters did not adequately explain why that was insufficient. And although OMB is not inviting comments on the final guidance at this time, OMB will consult with stakeholders as appropriate in considering any further revisions to it. Finally, because Federal agencies are responsible for implementing the guidance, the guidance itself is not significant regulatory action within the meaning of E.O. 12866 section 3(f). E.O. 12866's requirements regarding a regulatory impact analysis do not apply.

Commenter Suggestions for Future Updates
In the preamble to the proposed guidance, OMB shared that it may consider additional revisions for potential future updates. Specifically, OMB sought additional comments from the public on potential future revisions to the guidance currently under consideration. The topics OMB mentioned in this context included:
• Establishing specific audit requirements for for-profit entities, which are not subject to the requirements of Subpart F;
• Incorporating the requirements of National Security Presidential Management (NSPM)-33 on research security requirements;
• Providing additional guidance in 2 CFR concerning the relationship of specific aspects of the guidance to loans and loan guarantees;
• Establishing mechanisms to automatically adjust certain thresholds due to inflation or other triggering events (where permitted by law);
• Removing additional prior approval requirements;
• Challenges related to negotiating indirect costs, working with cognizant agencies, or any other topics related to indirect costs that could be addressed in future updates; and
• Expanding the guidance in Subpart F to include more specific requirements on the scope of an audit (“proper perspective”) so that agencies have additional contextual information to guide them in resolving audit findings.
OMB received approximately 60 comments reacting to these general proposals under consideration. Many commenters stated that additional policy changes were needed to improve the process of negotiating indirect cost rates. Some commenters requested more information on the actual process for indirect cost rate negotiations, while other commenters recommended that OMB consider changes to improve the process and timeliness associated with negotiating rates. Specifically, one commenter shared that indirect cost rate delays negatively impact organizations. The commenter also suggested that recipients might be able to pay a fee to ensure that agencies have the appropriate resources for the timely negotiation of rates. A few comments spoke to specific issues, such as eliminating the 26 percent cap on rates for IHEs.
Difficulties with obtaining a UEI and registering in SAM.gov received considerable feedback as well. Several commenters expressed support for providing recipients with additional time to obtain a UEI and complete SAM.gov registration if exigent circumstances persist beyond 30 days. Other comments suggested allowing additional exemptions for certain applicants including foreign organizations, in particular. Other comments recommended allowing certain thresholds to be increased automatically to account for inflation.
OMB received several comments concerning audits. For example, several commenters suggested clarifying that the auditor “may” report likely questioned costs to help provide proper perspective for known questioned costs, and several commenters suggested clarifying whether the auditor “is expected” to do so. OMB also received several comments requesting that the guidance be expanded in sections that apply to IHEs to also apply to nonprofit degree-granting research institutions. Some comments also suggested OMB provide additional guidance on the treatment of loan and loan guarantees in a single audit; and defining “continuing compliance requirements.”
OMB also received many additional comments on various topics such as pre-award certification for Fixed Amount Awards. Some comments indicated that pre-award certifications are already completed as part of the UEI registration process. Other commenters objected to the increased burden that pre-award certification for Fixed Amount Awards would place on recipients. Several comments underscored the importance of increasing thresholds and recommended continued attention to this topic by OMB in the future. Other commenters requested specific changes to Appendix II and III, including, for example, listing specifically which contract provisions should be included in contracts under Federal financial assistance. Some commenters requested that OMB remove additional prior approval requirements; continue to reduce administrative burden; and define more terms such as “base period” and “infrastructure costs.”
OMB Response: OMB greatly appreciates the many suggestions for potential future revisions to 2 CFR. OMB will explore these comments further in the context of future updates. There are certain legal limitations on threshold increases. Some thresholds are expressly provided in statutory law. OMB will also consider additional changes in response to the feedback on audits, including in response to comments on “proper perspective” and potential audit or compliance requirements applicable to for-profit organizations.

Executive Order 12866 (Regulatory Planning and Review), Executive Order 13563 (Improving Regulation and Regulatory Review), and Executive Order 14094 (Modernizing Regulatory Review)
Executive Orders (EOs) 12866, 13563, and 14094 direct agencies to assess all costs and benefits of available regulatory alternatives, and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). The OMB Guidance for Federal Financial Assistance published in subtitle A of 2 CFR is guidance to Federal agencies and not regulation. 2 CFR 1.100(b). OMB thus determined that the revision of 2 CFR is not a significant regulatory action under E.O. 12866, as amended.

Regulatory Flexibility Act
This guidance is exempt from the notice and comment requirements of the Administrative Procedure Act (APA), 5 U.S.C. 553(b), because it is guidance to Federal agencies and not regulation. Moreover, even if this guidance were otherwise subject to 5 U.S.C. 553, it would be exempt from the notice and comment requirement as a matter related to grants. See 5 U.S.C. 553(a)(2). OMB nonetheless provided the following information for the public in the proposed guidance, which it restates here. For a rule subject to the notice-and-comment provisions of the APA, the Regulatory Flexibility Act 5 U.S.C. 601, et seq., requires that an agency provide a final regulatory flexibility analysis or to certify that the rule will not have a significant economic impact on a substantial number of small entities. Based on the nature of the revisions in this document, OMB does not expect this guidance to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act. There are some revisions that may impose a non-significant burden; however, there are more revisions that reduce burden to small entities. When reviewing all revisions, the burden that will be reduced for recipients is much greater than the burden imposed.

Unfunded Mandates Reform Act of 1995
The guidance will not impose unfunded mandates as defined by the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4, 109 Stat. 48). The revisions to the guidance will not result in the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector, of $168 million or more in any one year (2 U.S.C. 1532).

Executive Order 13132 (Federalism Assessment)
This guidance has been analyzed in accordance with the principles and criteria contained in E.O. 13132, “Federalism,” 64 FR 43255 (Aug. 10, 1999). OMB has determined that this guidance will not have sufficient federalism implications to warrant the preparation of a federalism assessment. The guidance in 2 CFR is inherently national in scope and significance. Regardless, in accordance with section 4(d) of E.O. 13132, OMB consulted with appropriate State and local officials that may be affected by Federal agencies' implementation of OMB's final guidance by means of posting the RFI prior to proposing revisions and requesting comments on proposed changes. OMB weighed carefully the interests of those who submitted comments in response to the RFI and proposed guidance in finalizing revisions to the guidance, which balances the State interests with the need to provide Federal agencies with consistent, uniform, efficient, and transparent guidance, which is consistent with authorizing law.

Paperwork Reduction Act
This guidance does not contain a new requirement for information collection. Rather, it streamlines requirements in specific sections. Thus, the Paperwork Reduction Act does not apply.

Executive Order 13175 (Tribal Consultation)
OMB has analyzed this guidance in accordance with the principles and criteria contained in E.O. 13175, “Consultation and Coordination with Indian Tribal Governments” 65 FR 67249 (Nov. 9, 2000). On March 7, 2023, OMB held a two-hour Tribal consultation to solicit feedback from Tribal representatives. OMB provides greater flexibility to Tribal governments in the final guidance centered on procurement standards and disposition of equipment. OMB also clarifies the definition of Indian Tribes.

List of Subjects
2 CFR Part 1
Administration of Federal financial assistance; Administrative practice and procedure; Federal financial assistance programs.
2 CFR Part 25
Administrative practice and procedure; Grant programs; Grants administration; Loan programs.
2 CFR Part 170
Colleges and universities; Grant programs; Hospitals; International organizations; Loan programs; Reporting and recordkeeping requirements.
2 CFR Part 175
Administrative practice and procedures; Grant programs; Indians-tribal government; Nonprofit organizations; State and local governments.
2 CFR Part 180
Administrative practice and procedure; Grant programs; Loan programs; Reporting and recordkeeping requirements.
2 CFR Part 182
Administrative practice and procedure; Drug abuse; Grant programs; Reporting and recordkeeping requirements.
2 CFR Part 183
Foreign aid; Grants administration; Grant programs; International organizations; Reporting and recordkeeping requirements.
2 CFR Part 184
Administration of Federal financial assistance; Administrative practice and procedure; Federal financial assistance programs.
2 CFR Part 200
Administration of Federal financial assistance; Administrative practice and procedure; Federal financial assistance programs.
For the reasons stated in the preamble, the Office of Management and Budget amends title 2, subtitle A, part 1, and chapters I and II of the Code of Federal Regulations as follows:
1. Revise the heading of title 2 to read as follows:

Title 2—Federal Financial Assistance
2. Revise the heading of subtitle A of title 2 to read as follows:

Subtitle A—Office of Management and Budget Guidance for Federal Financial Assistance
3. Revise part 1, consisting of §§ 1.100 through 1.305, to read as follows:

PART 1—ABOUT TITLE 2 OF THE CODE OF FEDERAL REGULATIONS AND SUBTITLE A
Sec.

Subpart A—Introduction to Title 2 of the CFR
1.100
Content of this title.
1.105
Organization and subtitle content.
1.110
Issuing authorities.

Subpart B—Introduction to Subtitle A
1.200
Purpose of chapters I and II.
1.205
Applicability to Federal financial assistance.
1.210
Applicability to Federal agencies and others.
1.215
Relationship to previous issuances.
1.220
Federal agency implementation of this subtitle.
1.230
Maintenance of this subtitle.
1.231
Severability.

Subpart C—Responsibilities of OMB and Federal Agencies
1.300
OMB responsibilities.
1.305
Federal agency responsibilities.

Authority:
31 U.S.C. 503; 31 U.S.C. 1111; 31 U.S.C. 6307; 41 U.S.C. 1121; Reorganization Plan No. 2 of 1970; E.O. 11541, 35 FR 10737.

Subpart A—Introduction to Title 2 of the CFR
§ 1.100
Content of this title.
This title contains:
(a) Office of Management and Budget (OMB) guidance to Federal agencies on government-wide policies for the award and administration of Federal financial assistance; and
(b) Federal agency regulations implementing that OMB guidance.
§ 1.105
Organization and subtitle content.
(a) This title is organized into two subtitles.
(b) The OMB guidance described in § 1.100(a) is published in subtitle A. Publication of the OMB guidance in the CFR does not change its nature—it is guidance, not regulation.
(c) Each Federal agency that awards Federal financial assistance has a chapter in subtitle B in which it issues those regulations. The Federal agency regulations in subtitle B differ in nature from the OMB guidance in subtitle A because the OMB guidance is not regulatory. Federal agency regulations in subtitle B may give regulatory effect to the OMB guidance, to the extent that the agency regulations require compliance with all or portions of the OMB guidance. See also § 1.220.
§ 1.110
Issuing authorities.
OMB issues this subtitle. Each Federal agency that has a chapter in subtitle B of this title issues that chapter.

Subpart B—Introduction to Subtitle A
§ 1.200
Purpose of chapters I and II.
Chapters I and II of subtitle A provide OMB guidance to Federal agencies that helps ensure consistent and uniform government-wide policies and procedures for the management of the agencies' Federal financial assistance.
§ 1.205
Applicability to Federal financial assistance.
The types of instruments that are subject to the guidance in this subtitle vary from one portion of the guidance to another. All portions of the guidance apply to grants and cooperative agreements, and some portions also apply to other types of Federal financial assistance.
§ 1.210
Applicability to Federal agencies and others.
(a) This subtitle contains guidance that directly applies only to Federal agencies.
(b) The guidance in this subtitle may affect other entities through each Federal agency's implementation of the guidance, portions of which may apply to:
(1) The agency's awarding or administering officials;
(2) Recipients and subrecipients that receive or apply for the agency's Federal financial assistance or receive subawards under grants or cooperative agreements; or
(3) Any other entities involved in agency transactions subject to the guidance in this chapter.
§ 1.215
Relationship to previous issuances.
Although some of the guidance was organized differently within OMB circulars or other documents, much of the guidance in this subtitle existed prior to the establishment of title 2 of the CFR.
§ 1.220
Federal agency implementation of this subtitle.
A Federal agency that awards Federal financial assistance subject to the OMB guidance in this subtitle implements the guidance in agency regulations in subtitle B of this title and in guidance documents, policy documents, and procedural issuances, such as internal instructions to the agency's awarding and administering officials. An applicant, recipient, or subrecipient would see the effect of that implementation in the organization and content of the agency's announcements of funding opportunities and in its award terms and conditions.
§ 1.230
Maintenance of this subtitle.
OMB issues guidance in this subtitle after publication in the Federal Register . Any portion of the guidance that has a potential impact on the public is published with an opportunity for public comment.
§ 1.231
Severability.
The provisions of this subtitle are separate and severable from one another. If any provision of this subtitle is held invalid or unenforceable as applied to a particular person or circumstance, the provision should be construed so as to continue to give the maximum effect permitted by law as applied to other persons not similarly situated or to dissimilar circumstances. If any provision is determined to be wholly invalid and unenforceable, it should be severed from the remaining provisions of this subtitle, which should remain in effect.

Subpart C—Responsibilities of OMB and Federal Agencies
§ 1.300
OMB responsibilities.
OMB is responsible for:
(a) Issuing and maintaining the guidance in this subtitle, as described in § 1.230;
(b) Interpreting the policy requirements in this subtitle;
(c) Reviewing Federal agency regulations implementing the requirements of this subtitle, as required by Executive Order 12866;
(d) Conducting broad oversight of government-wide compliance with the guidance in this subtitle; and
(e) Performing other OMB functions specified in this subtitle.
§ 1.305
Federal agency responsibilities.
The head of each Federal agency that awards and administers Federal financial assistance subject to the guidance in this subtitle is responsible for:
(a) Implementing the guidance in this subtitle;
(b) Ensuring that the Federal agency complies with their implementation of the guidance;
(c) Coordinating with the Council on Federal Financial Assistance, the Grants Quality Service Management Office, and other governance committees as appropriate; and
(d) Performing other functions specified in this subtitle.
4. Revise the heading of chapter I of subtitle A of title 2 to read as follows:

CHAPTER I—OFFICE OF MANAGEMENT AND BUDGET GOVERNMENT-WIDE GUIDANCE FOR FEDERAL FINANCIAL ASSISTANCE
5. Revise part 25, consisting of § 25.100 through appendix A to part 25, to read as follows:

PART 25—UNIQUE ENTITY IDENTIFIER AND SYSTEM FOR AWARD MANAGEMENT
Sec.

Subpart A—General
25.100
Purpose of this part.
25.105
Applicability.
25.110
Exceptions to this part.

Subpart B—Policy
25.200
Requirements for notice of funding opportunities, regulations, and application instructions.
25.205
Effect of noncompliance with a requirement to obtain a UEI or register in SAM.gov .
25.210
Authority to modify agency application forms or formats.
25.215
Requirements for agency information systems.
25.220
Use of award term.

Subpart C—Recipient Requirements of Subrecipients
25.300
Requirement for recipients to ensure subrecipients have a unique entity identifier.

Subpart D—Definitions.
25.400
Definitions
Appendix A to Part 25
Award Term

Authority:
31 U.S.C. 503; 31 U.S.C. 6101 note; 31 U.S.C. 6102; 31 U.S.C. 6307; 41 U.S.C. 2313; Pub. L. 109-282; Pub. L. 110-252; Pub. L. 113-101; Pub. L. 117-40.

Subpart A—General
§ 25.100
Purpose of this part.
This part provides guidance to Federal agencies that:
(a) The unique entity identifier (UEI) is the universal identifier for Federal financial assistance applicants, as well as recipients and their direct subrecipients (first-tier subrecipients), and;
(b) The System for Award Management ( SAM.gov ) is the repository for standard information about applicants and recipients.
§ 25.105
Applicability.
(a) This part applies to a Federal agency's Federal financial assistance as defined in § 25.400. This part applies to all applicants for and recipients of Federal financial assistance unless exempted by Federal statute or § 25.110.
(b) Subrecipients are required to obtain a UEI in accordance with subpart C. This part does not apply to subrecipients of subrecipients (second-tier subrecipients) or contractors under Federal awards.
(c) This part does not apply to an individual who applies for or receives Federal financial assistance as a natural person (unrelated to any business or nonprofit organization an individual owns or operates).
(d) Because this part applies to loan guarantees and other guaranteed programs, recipients of the guarantee from the Federal agency (for example, lenders of guaranteed loans) are required to complete entity validations and acquire a UEI. Additionally, at the Federal agency's discretion, non-individual beneficiary borrowers (for example, small businesses or corporations) may be required by the Federal agency to obtain a UEI or register in SAM.gov.
§ 25.110
Exceptions to this part.
(a) General exceptions. (1) Under a condition identified in paragraph (a)(2) of this section, a Federal agency may exempt an applicant or recipient of Federal financial assistance from the requirement to obtain a UEI, register in SAM.gov , or both.
(i) If a Federal agency grants an exception under paragraph (a)(2) of this section, the Federal agency must use a generic entity identifier in the data it reports to USAspending.gov if reporting for a prime award of Federal financial assistance to the recipient is required by the Federal Funding Accountability and Transparency Act (Pub. L. 109-282, as amended, hereafter cited as “Transparency Act”). Granting an exception under paragraph (a)(2) of this section does not impact a Federal agency's responsibility for reporting under the Transparency Act, except that it may use a generic entity identifier in the circumstances described.
(ii) Federal agencies should use generic entity identifiers rarely as it prevents recipients from fulfilling reporting requirements such as subaward or executive compensation reporting required by the Transparency Act.
(2) A Federal agency may exempt an applicant, recipient, or subrecipient when:
(i) The Federal agency determines that it must protect information about the entity from disclosure in the national security or foreign policy interests of the United States or to avoid jeopardizing the personal safety of the entity's staff, partners, beneficiaries, and participants;
(ii)(A) All of the following conditions are met:
( 1 ) The entity is a foreign organization or foreign public entity;
( 2 ) The Federal award or subaward will be performed outside the United States;
( 3 ) The Federal award or subaward will be less than $25,000; and
( 4 ) The Federal agency deems it to be impractical for the entity to comply with the requirements of this part.
(B) The Federal agency must determine this exemption on a case-by-case basis while utilizing a risk-based approach;
(iii) For applicants or recipients, the Federal agency may exempt foreign organizations or foreign public entities from completing full registration in SAM.gov for a Federal award less than $500,000 that will be performed outside the United States. Foreign organizations or foreign public entities exempted from registering in SAM.gov under this provision must still obtain a UEI. The Federal agency must determine this exemption on a case-by-case basis while utilizing a risk-based approach; or
(iv) For applicants, the Federal agency determines that there are exigent circumstances that prohibit the applicant from receiving a UEI and registering in SAM.gov before receiving a Federal award. In these instances, Federal agencies must require the recipient to obtain a UEI and complete registration in SAM.gov within 30 days of the Federal award date.
(b) Class exceptions. OMB may approve additional exceptions for classes of Federal awards, applicants, or recipients subject to the requirements of this part when exceptions are not prohibited by statute.

Subpart B—Policy
§ 25.200
Requirements for notice of funding opportunities, regulations, and application instructions.
(a) A Federal agency that issues Federal financial assistance (see § 25.400) must include the requirements of paragraph (b) of this section in each notice of funding opportunity, regulation, or other issuance containing instructions for applicants that is issued on or after the effective date of this guidance. A notice of funding opportunity is any paper or electronic issuance that a Federal agency uses to announce a funding opportunity, whether it is called a “program announcement,” “notice of funding availability,” “broad agency announcement,” “research announcement,” “solicitation,” or any other term.
(b) The notice of funding opportunity, regulation, or other issuance must require each applicant that does not have an exemption under § 25.110 to:
(1) Be registered in SAM.gov before submitting an application;
(2) Maintain a current and active registration in SAM.gov at all times during which it has an active Federal award as a recipient or an application under consideration by a Federal agency. The applicant or recipient must review and update its information in SAM.gov annually from the date of initial registration or subsequent updates to ensure it is current, accurate, and complete. If applicable, this includes identifying the applicant's or recipient's immediate and highest-level owner and subsidiaries, as well as providing information on all predecessors that have received a Federal award or contract within the last three years; and
(3) Include its UEI in each application it submits to the Federal agency.
(c) For the purposes of this policy, the applicant must meet the Federal agency's eligibility criteria and have the legal authority to apply for and receive the Federal award. For example, if a consortium applies for a Federal award to be made to the consortium as the recipient, the consortium must have a UEI. If a consortium is eligible to receive funding under a Federal agency program, but the agency's policy is to make the Federal award to a lead entity for the consortium, the UEI of the lead applicant must be used.
§ 25.205
Effect of noncompliance with a requirement to obtain a UEI or register in SAM.gov .
(a) Unless an entity is exempt under § 25.110, a Federal agency may not issue a Federal award or amend an existing Federal award to provide additional Federal funds if the entity is not in compliance with the requirements of this part. This does not apply to amendments to terminate or close out a Federal award.
(b) At the time a Federal agency is ready to make a Federal award, if the intended recipient has not complied with the requirements to obtain a UEI and maintain an active registration in SAM.gov with current information, the Federal agency may make a Federal award to another applicant.
§ 25.210
Authority to modify agency application forms or formats.
To implement the policies in §§ 25.200 and 25.205, a Federal agency may add a UEI field to information collections previously approved by OMB, with no further approval required.
§ 25.215
Requirements for agency information systems.
Each Federal agency that awards Federal financial assistance (see § 25.400) must ensure that its information systems are able to both accept and transmit the UEI as the universal identifier for Federal financial assistance applicants and recipients.
§ 25.220
Use of award term.
(a) A Federal agency must include the award term in Appendix A in all Federal financial assistance agreements (see § 25.400) to accomplish the purpose of § 25.100.
(b) A Federal agency may use different letters and numbers than those in Appendix A to designate the paragraphs of the award term.

Subpart C—Recipient Requirements of Subrecipients
§ 25.300
Requirement for recipients to ensure subrecipients have a unique entity identifier.
(a) A recipient may not make a subaward to a subrecipient that has not obtained a UEI and provided it to the recipient. Subrecipients are not required to complete full registration in SAM.gov to obtain a UEI.
(b) A recipient must notify any potential subrecipients that the recipient cannot make a subaward unless the subrecipient obtains and provides a UEI to the recipient.

Subpart D—Definitions
§ 25.400
Definitions.
Terms not defined in this part have the same meaning as provided in 2 CFR part 200, subpart A. As used in this part:
Applicant means any entity that applies for a Federal award directly to a Federal agency.
Entity includes:
(1) Whether for profit or nonprofit:
(i) A corporation;
(ii) An association;
(iii) A partnership;
(iv) A limited liability company;
(v) A limited liability partnership;
(vi) A sole proprietorship;
(vii) Any other legal business entity;
(viii) Any other grantee or contractor that is not excluded by paragraph (2);
(ix) Any State or locality; and
(x) any subcontractor or subgrantee that is not excluded by paragraph (2);
(2) Does not include:
(i) An individual recipient of Federal financial assistance; or
(ii) A Federal employee.
Federal Award means an award of Federal financial assistance that an entity receives from a Federal agency.
Federal financial assistance means:
(1) Assistance that entities receive or administer in the form of a:
(i) Grant;
(ii) Cooperative agreement (which does not include a cooperative research and development agreement pursuant to the Federal Technology Transfer Act of 1986, as amended (15 U.S.C. 3710a);
(iii) Loan;
(iv) Loan guarantee;
(v) Subsidy;
(vi) Insurance;
(vii) Food commodity;
(viii) Direct appropriation;
(ix) Assessed or voluntary contribution; or
(x) Any other financial assistance transaction that authorizes the entity's expenditure of Federal funds.
(2) For the purposes of this part, the term “Federal financial assistance” does not include:
(i) Technical assistance that provides services in lieu of money; and
(ii) A transfer of title to federally-owned property provided in lieu of money, even if the award is called a grant.
Recipient means an entity that receives or administers a Federal Award directly from a Federal agency.
System for Award Management (SAM.gov) means the Federal repository into which an entity must provide the information required for the conduct of business as a recipient.
Unique entity identifier means the universal identifier assigned by SAM.gov to uniquely identify an entity.

Appendix A to Part 25—Award Term

I. System for Award Management (SAM.gov) and Universal Identifier Requirements
(a) Requirement for System for Award Management. (1) Unless exempt from this requirement under 2 CFR 25.110, the recipient must maintain a current and active registration in SAM.gov . The recipient's registration must always be current and active until the recipient submits all final reports required under this Federal award or receives the final payment, whichever is later. The recipient must review and update its information in SAM.gov at least annually from the date of its initial registration or any subsequent updates to ensure it is current, accurate, and complete. If applicable, this includes identifying the recipient's immediate and highest-level owner and subsidiaries and providing information about the recipient's predecessors that have received a Federal award or contract within the last three years.
(b) Requirement for Unique Entity Identifier (UEI). (1) If the recipient is authorized to make subawards under this Federal award, the recipient:
(i) Must notify potential subrecipients that no entity may receive a subaward until the entity has provided its UEI to the recipient.
(ii) Must not make a subaward to an entity unless the entity has provided its UEI to the recipient. Subrecipients are not required to complete full registration in SAM.gov to obtain a UEI.
(c) Definitions. For the purposes of this award term:
System for Award Management (SAM.gov) means the Federal repository into which a recipient must provide the information required for the conduct of business as a recipient. Additional information about registration procedures may be found in SAM.gov (currently at https://www.sam.gov ).
Unique entity identifier means the universal identifier assigned by SAM.gov to uniquely identify an entity.
Entity is defined at 2 CFR 25.400 and includes all of the following types as defined in 2 CFR 200.1:
(1) Non-Federal entity;
(2) Foreign organization;
(3) Foreign public entity;
(4) Domestic for-profit organization; and
(5) Federal agency.
Subaward has the meaning given in 2 CFR 200.1.
Subrecipient has the meaning given in 2 CFR 200.1.
6. Revise part 170 to read as follows:

PART 170—REPORTING SUBAWARD AND EXECUTIVE COMPENSATION INFORMATION
Sec.

Subpart A—General
170.100
Purpose of this part.
170.105
Applicability.

Subpart B—Policy
170.200
Federal agency reporting requirements.
170.210
Requirements for notices of funding opportunities, regulations, and application instructions.
170.220
Use of award term.

Subpart C—Definitions
170.300
Definitions.

Appendix A to Part 170
Award term

Authority:
31 U.S.C. 503; 31 U.S.C. 6102; 31 U.S.C. 6307; Pub. L. 109-282; Pub. L. 110-252, Pub. L. 113-101, Pub. L. 117-40.

Subpart A—General
§ 170.100
Purpose of this part.
This part provides guidance to Federal agencies on establishing requirements for recipients of Federal awards to report information on subawards and executive total compensation, as required by the Federal Funding Accountability and Transparency Act of 2006 (Pub. L. 109-282), as amended by the Digital Accountability and Transparency Act of 2014 (Pub. L. 113-101) and other Public Laws, hereafter referred to as the “Transparency Act.”
§ 170.105
Applicability.
(a) Applicability in general. This part applies to a Federal agency's Federal financial assistance as defined in § 170.300. This part applies to all recipients and subrecipients of Federal awards who meet the reporting requirements of paragraph (c) of this section, unless exempt under Federal statute or by paragraph (d) of this section.
(b) Non-applicability to individuals. This part does not apply to an individual who applies for or receives Federal financial assistance as a natural person (that is, unrelated to any business or nonprofit organization an individual owns or operates).
(c) Reporting Requirements. (1) The names and total compensation of an entity's five most highly compensated executives must be reported if:
(i) In the entity's preceding fiscal year, it received:
(A) 80 percent or more of its annual gross revenue in Federal procurement contracts (and subcontracts) and Federal awards (and subawards) subject to the Transparency Act, as defined at § 170.300; and
(B) $25,000,000 or more in annual gross revenue from Federal procurement contracts (and subcontracts) and Federal awards (and subawards) subject to the Transparency Act, as defined at § 170.300; and
(ii) The public does not have access to information about the compensation of senior executives of the entity through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986.
(2) [Reserved]
(d) Class exceptions. OMB may approve additional exceptions for classes of Federal awards or recipients when not prohibited by Federal statute.

Subpart B—Policy
§ 170.200
Federal agency reporting requirements.
(a) Federal agencies must publicly report Federal awards that equal or exceed the micro-purchase threshold (see 2 CFR 200.1). Federal agencies must publish the required Federal award information on USAspending.gov in accordance with the guidance provided by OMB and the U.S. Department of the Treasury's Government-wide Spending Data Model (GSDM).
(b) Federal agencies should ensure that their agency-specific requirements do not require recipients to submit data that is the same as or similar to data required by the Transparency Act during a given reporting period.
§ 170.210
Requirements for notices of funding opportunities, regulations, and application instructions.
(a) A Federal agency that makes Federal awards subject to the Transparency Act must include the requirements of paragraph (b) of this section in each notice of funding opportunity, regulation, or other issuance containing instructions for applicants under which Federal awards may be made that are subject to Transparency Act reporting requirements. A notice of funding opportunity is any paper or electronic issuance that a Federal agency uses to announce a funding opportunity, whether it is called a “program announcement,” “notice of funding availability,” “broad agency announcement,” “research announcement,” “solicitation,” or any other term.
(b) The notice of funding opportunity, regulation, or other issuance must require each applicant, to which this part applies, to have the necessary processes and systems in place to comply with this part if they receive a Federal award.
§ 170.220
Use of award term.
(a) A Federal agency must include the award term in Appendix A to this part in each Federal award to a recipient under which the total funding is anticipated to equal or exceed $30,000 in Federal funding.
(b) Consistent with paragraph (a) of this section, a Federal agency is not required to include the award term in Appendix A of this part if the total amount of Federal funding under the Federal award will not equal or exceed $30,000. However, the Federal agency must subsequently add the award term if increases to the Federal funding result in the award equaling or exceeding $30,000.
(c) A Federal agency may use different letters and numbers than those in Appendix A to designate the paragraphs of the award term.

Subpart C—Definitions
§ 170.300
Definitions
Terms not defined in this part have the same meaning as provided in 2 CFR part 200, subpart A. As used in this part:
Applicant means any entity that applies for a Federal award directly from a Federal agency.
Entity includes:
(1) Whether for profit or nonprofit:
(i) A corporation;
(ii) An association;
(iii) A partnership;
(iv) A limited liability company;
(v) A limited liability partnership;
(vi) A sole proprietorship;
(vii) Any other legal business entity;
(viii) Another grantee or contractor that is not excluded by subparagraph (2) or (3); and
(ix) Any State or locality;
(2) Does not include:
(i) An individual recipient of Federal financial assistance; or
(ii) A Federal employee.
Federal Award means an award of Federal financial assistance that an entity receives from a Federal agency.
Executive means an officer, managing partner, or any other employee holding a management position.
Federal financial assistance:
(1) Means assistance that entities receive or administer in the form of a:
(i) Grant;
(ii) Cooperative agreement (which does not include a cooperative research and development agreement pursuant to the Federal Technology Transfer Act of 1986, as amended (15 U.S.C. 3710a);
(iii) Loan;
(iv) Loan guarantee;
(v) Subsidy;
(vi) Insurance;
(vii) Food commodity;
(viii) Direct appropriation;
(ix) Assessed or voluntary contribution; or
(x) Any other financial assistance transaction that authorizes the entity's expenditure of Federal funds.
(2) For the purposes of this part, the term “Federal financial assistance” does not include:
(i) Technical assistance that provides services in lieu of money;
(ii) A transfer of title to federally-owned property provided in lieu of money, even if the award is called a grant;
(iii) Any classified Federal award; or
(iv) Any award funded in whole or in part with Recovery funds, as defined in section 1512 of the American Recovery and Reinvestment Act of 2009 (Pub. L. 111-5).
Recipient means an entity that receives or administers a Federal Award directly from a Federal agency.
Total Compensation means the cash and noncash dollar value an executive earns during an entity's preceding fiscal year. This includes all items of compensation as prescribed in 17 CFR 229.402(c)(2).

Appendix A to Part 170—Award Term

I. Reporting Subawards and Executive Compensation
(a) Reporting of first-tier subawards —(1) Applicability. Unless the recipient is exempt as provided in paragraph (d) of this award term, the recipient must report each subaward that equals or exceeds $30,000 in Federal funds for a subaward to an entity or Federal agency. The recipient must also report a subaward if a modification increases the Federal funding to an amount that equals or exceeds $30,000. All reported subawards should reflect the total amount of the subaward.
(2) Reporting Requirements. (i) The entity or Federal agency must report each subaward described in paragraph (a)(1) of this award term to the Federal Funding Accountability and Transparency Act Subaward Reporting System (FSRS) at http://www.fsrs.gov.
(ii) For subaward information, report no later than the end of the month following the month in which the subaward was issued. (For example, if the subaward was made on November 7, 2025, the subaward must be reported by no later than December 31, 2025).
(b) Reporting total compensation of recipient executives for entities —(1) Applicability. The recipient must report the total compensation for each of the recipient's five most highly compensated executives for the preceding completed fiscal year if:
(i) The total Federal funding authorized to date under this Federal award equals or exceeds $30,000;
(ii) in the preceding fiscal year, the recipient received:
(A) 80 percent or more of the recipient's annual gross revenues from Federal procurement contracts (and subcontracts) and Federal awards (and subawards) subject to the Transparency Act; and
(B) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts) and Federal awards (and subawards) subject to the Transparency Act; and,
(iii) The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986 after receiving this subaward. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at http://www.sec.gov/answers/execomp.htm. )
(2) Reporting Requirements. The recipient must report executive total compensation described in paragraph (b)(1) of this appendix:
(i) As part of the recipient's registration profile at https://www.sam.gov.
(ii) No later than the month following the month in which this Federal award is made, and annually after that. (For example, if this Federal award was made on November 7, 2025, the executive total compensation must be reported by no later than December 31, 2025.)
(c) Reporting of total compensation of subrecipient executives— (1) Applicability. Unless a first-tier subrecipient is exempt as provided in paragraph (d) of this appendix, the recipient must report the executive total compensation of each of the subrecipient's five most highly compensated executives for the subrecipient's preceding completed fiscal year, if:
(i) The total Federal funding authorized to date under the subaward equals or exceeds $30,000;
(ii) In the subrecipient's preceding fiscal year, the subrecipient received:
(A) 80 percent or more of its annual gross revenues from Federal procurement contracts (and subcontracts) and Federal awards (and subawards) subject to the Transparency Act; and,
(B) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts), and Federal awards (and subawards) subject to the Transparency Act; and
(iii) The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986after receiving this subaward. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at http://www.sec.gov/answers/execomp.htm. )
(2) Reporting Requirements. Subrecipients must report to the recipient their executive total compensation described in paragraph (c)(1) of this appendix. The recipient is required to submit this information to the Federal Funding Accountability and Transparency Act Subaward Reporting System (FSRS) at http://www.fsrs.gov no later than the end of the month following the month in which the subaward was made. (For example, if the subaward was made on November 7, 2025, the subaward must be reported by no later than December 31, 2025).
(d) Exemptions. (1) A recipient with gross income under $300,000 in the previous tax year is exempt from the requirements to report:
(i) Subawards, and
(ii) The total compensation of the five most highly compensated executives of any subrecipient.
(e) Definitions.
For purposes of this award term:
Entity includes:
(1) Whether for profit or nonprofit:
(i) A corporation;
(ii) An association;
(iii) A partnership;
(iv) A limited liability company;
(v) A limited liability partnership;
(vi) A sole proprietorship;
(vii) Any other legal business entity;
(viii) Another grantee or contractor that is not excluded by subparagraph (2); and
(ix) Any State or locality;
(2) Does not include:
(i) An individual recipient of Federal financial assistance; or
(ii) A Federal employee.
Executive means an officer, managing partner, or any other employee holding a management position.
Subaward has the meaning given in 2 CFR 200.1.
Subrecipient has the meaning given in 2 CFR 200.1.
Total Compensation means the cash and noncash dollar value an executive earns during an entity's preceding fiscal year. This includes all items of compensation as prescribed in 17 CFR 229.402(c)(2).
7. Revise part 175 to read as follows:

PART 175—AWARD TERM FOR TRAFFICKING IN PERSONS
Sec.

Subpart A—General
175.100
Purpose of this part.
175.105
Statutory requirement.

Subpart B—Guidance
175.200
Use of award term.
175.205
Referral.

Subpart C—Definitions
175.300
Definitions.

Appendix A to Part 175
Award term

Authority:
22 U.S.C. 7104(g); 22 U.S.C. 7104a; 22 U.S.C. 7104b; 22 U.S.C. 7104c; 31 U.S.C. 503; 31 U.S.C. 6307; 31 U.S.C. 1111; 41 U.S.C. 1121; Reorganization Plan No. 2 of 1970; E.O. 11541, 35 FR 10737.

Subpart A—General
§ 175.100
Purpose of this part.
This part establishes a Federal award term for grants and cooperative agreements to implement the requirements in 22 U.S.C. 7104(g); 22 U.S.C. 7104a; 22 U.S.C. 7104b; and 22 U.S.C. 7104c.
§ 175.105
Statutory requirement.
(a) Federal agencies are required to include in each Federal grant or cooperative agreement a condition that authorizes the Federal agency to terminate the award or take any remedial actions authorized by 22 U.S.C. 7104b(c), without penalty, if a private entity receiving funds under the award as a recipient or subrecipient engages in:
(1) Severe forms of trafficking in persons;
(2) The procurement of a commercial sex act during the period of time that the grant or cooperative agreement is in effect;
(3) The use of forced labor in the performance of the grant or cooperative agreement; or
(4) Acts that directly support or advance trafficking in persons, including the following acts:
(i) Destroying, concealing, removing, confiscating, or otherwise denying an employee access to that employee's identity or immigration documents;
(ii) Failing to provide return transportation or pay for return transportation costs to an employee from a country outside the United States to the country from which the employee was recruited upon the end of employment if requested by the employee, unless:
(A) exempted from the requirement to provide or pay for such return transportation by the Federal department or agency providing or entering into the grant or cooperative agreement; or
(B) the employee is a victim of human trafficking seeking victim services or legal redress in the country of employment or a witness in a human trafficking enforcement action;
(iii) Soliciting a person for the purpose of employment, or offering employment, by means of materially false or fraudulent pretenses, representations, or promises regarding that employment;
(iv) Charging recruited employees a placement or recruitment fee; or
(v) Providing or arranging housing that fails to meet the host country's housing and safety standards.
(b) Compliance plan and certification requirement:
(1) Certification. Prior to receiving a grant or cooperative agreement, if the estimated value of services required to be performed under the grant or cooperative agreement outside the United States exceeds $500,000, a recipient must certify that:
(i) The recipient has implemented a plan to prevent the activities described in paragraph (a) of this section, and is in compliance with this plan;
(ii) The recipient has implemented procedures to prevent any activities described in paragraph (a) of this section and to monitor, detect, and terminate any subrecipient, contractor, subcontractor, or employee of the recipient engaging in any activities described in paragraph (a) of this section; and
(iii) To the best of the recipient's knowledge, neither the recipient, nor any subrecipient, contractor, or subcontractor of the recipient or any agent of the recipient or of such a subrecipient, contractor, or subcontractor, is engaged in any of the activities described in paragraph (a) of this section.
(2) Annual certification. The recipient must submit an annual certification consistent with paragraph (b)(1) of this section for each year the award is in effect.
(3) Compliance plan. Any plan or procedures implemented pursuant to paragraph (b) must be appropriate to the size and complexity of the grant or cooperative agreement and to the nature and scope of its activities, including the number of non-United States citizens expected to be employed.
(4) Copies of the compliance plan. The recipient must provide a copy of the plan to the grant officer upon request, and as appropriate, must post the useful and relevant contents of the plan or related materials on its website and at the workplace.
(5) Minimum requirements of the compliance plan. The compliance plan must include, at a minimum, the following:
(i) An awareness program to inform recipient employees about the Government's policy prohibiting trafficking-related activities described in paragraph (a) of this section, the activities prohibited, and the actions that will be taken against the employee for violations. Additional information about Trafficking in Persons and examples of awareness programs can be found at the website for the Department of State's Office to Monitor and Combat Trafficking in Persons at http://www.state.gov/j/tip/.
(ii) A process for employees to report, without fear of retaliation, activity inconsistent with the policy prohibiting trafficking in persons.
(iii) A recruitment and wage plan that only permits the use of recruitment companies with trained employees, prohibits charging recruitment fees to the employees or potential employees and ensures that wages meet applicable host-country legal requirements or explains any variance.
(iv) A housing plan, if the recipient, subrecipient, contractor, or subcontractor intends to provide or arrange housing, that ensures that the housing meets host-country housing and safety standards.
(v) Procedures to prevent agents, subrecipients, contractors, or subcontractors at any tier and at any dollar value from engaging in trafficking in persons, including activities in paragraph (a) of this section, and to monitor, detect, and terminate any agents, subgrants, or subrecipient, contractor, or subcontractor employees that have engaged in such activities.
(c) Notification to Inspectors General and cooperation with government. The head of a Federal agency making or awarding a grant or cooperative agreement must require that the recipient of the grant or cooperative agreement:
(1) Immediately inform the Federal agency and Inspector General of the Federal agency of any information it receives from any source that alleges credible information that the recipient, any subrecipient, contractor, or subcontractor of the recipient, or any agent of the recipient or of such a subrecipient, contractor, or subcontractor, has engaged in conduct described in paragraph (a) of this section; and
(2) Fully cooperate with any Federal agencies responsible for audits, investigations, or corrective actions relating to trafficking in persons.

Subpart B—Guidance
§ 175.200
Use of award term.
(a) To implement the requirements of 22 U.S.C. 7104(g) a Federal agency must include the award term in Appendix A of this part for the following Federal awards:
(1) A grant or cooperative agreement to a private entity, as defined in § 175.300; and
(2) A grant or cooperative agreement to a State, local government, Indian Tribe, foreign public entity, or any other recipient if funding under the award could be provided to a subrecipient that is a private entity.
(b) A Federal agency may use different letters and numbers than those in Appendix A to designate the paragraphs of the award term. A Federal agency may also include additional information in the award term, consistent with the statutory authority of this part, such as further information on the compliance plan and certification requirements in § 175.105(b).
§ 175.205
Referral.
A Federal agency official should inform the agency's suspension and debarment official if an award is terminated based on a violation of a prohibition in the award term under Appendix A.

Subpart C—Definitions
§ 175.300
Definitions.
Terms not defined in this part have the same meaning as provided in 2 CFR part 200, subpart A. As used in this part:
Abuse or threatened abuse of law or legal process means the use or threatened use of a law or legal process, whether administrative, civil, or criminal, in any manner or for any purpose for which the law was not designed, in order to exert pressure on another person to cause that person to take some action or refrain from taking some action.
Coercion means:
(1) Threats of serious harm to or physical restraint against any person;
(2) Any scheme, plan, or pattern intended to cause a person to believe that failure to perform an act would result in serious harm to or physical restraint against any person; or
(3) The abuse or threatened abuse of the legal process.
Commercial sex act means any sex act on account of which anything of value is given to or received by any person.
Debt bondage means the status or condition of a debtor arising from a pledge by the debtor of his or her personal services or of those of a person under his or her control as a security for debt, if the value of those services as reasonably assessed is not applied toward the liquidation of the debt or the length and nature of those services are not respectively limited and defined.
Involuntary servitude includes a condition of servitude induced by means of:
(1) Any scheme, plan, or pattern intended to cause a person to believe that, if the person did not enter into or continue in such condition, that person or another person would suffer serious harm or physical restraint; or
(2) The abuse or threatened abuse of the legal process.
Private Entity means any entity, including for-profit organizations, nonprofit organizations, institutes of higher education, and hospitals. The term does not include foreign public entities, Indian Tribes, local governments, or states as defined in 2 CFR 200.1.
Recruitment Fee means fees of any type, including charges, costs, assessments, or other financial obligations, that are associated with the recruiting process, regardless of the time, manner, or location of imposition or collection of the fee.
(1) Recruitment fees include, but are not limited to, the following fees (when they are associated with the recruiting process) for:
(i) Advertising;
(ii) Obtaining permanent or temporary labor certification, including any associated fees;
(iii) Processing applications and petitions;
(iv) Acquiring visas, including any associated fees;
(v) Acquiring photographs and identity or immigration documents, such as passports, including any associated fees;
(vi) Accessing the job opportunity, including required medical examinations and immunizations; background, reference, and security clearance checks and examinations; and additional certifications;
(vii) An employer's recruiters, agents or attorneys, or other notary or legal fees;
(viii) Language interpretation or translation, arranging for or accompanying on travel, or providing other advice to employees or potential employees;
(ix) Government-mandated fees, such as border crossing fees, levies, or worker welfare fund;
(x) Transportation and subsistence costs:
(A) While in transit, including, but not limited to, airfare or costs of other modes of transportation, terminal fees, and travel taxes associated with travel from the country of origin to the country of performance and the return journey upon the end of employment; and
(B) From the airport or disembarkation point to the worksite;
(xi) Security deposits, bonds, and insurance; and
(xii) Equipment charges.
(2) A recruitment fee, as described in the introductory text of this definition, is a recruitment fee, regardless of whether the payment is:
(i) Paid in property or money;
(ii) Deducted from wages;
(iii) Paid back in wage or benefit concessions;
(iv) Paid back as a kickback, bribe, in-kind payment, free labor, tip, or tribute; or
(v) Collected by an employer or a third party, whether licensed or unlicensed, including, but not limited to:
(A) Agents;
(B) Labor brokers;
(C) Recruiters;
(D) Staffing firms (including private employment and placement firms);
(E) Subsidiaries/affiliates of the employer;
(F) Any agent or employee of such entities; and
(G) Subcontractors at all tiers.
Severe forms of trafficking in persons means:
(1) Sex trafficking in which a commercial sex act is induced by force, fraud, or coercion or in which the person induced to perform such act has not attained 18 years of age; or
(2) The recruitment, harboring, transportation, provision, or obtaining of a person for labor or services, through the use of force, fraud, or coercion for the purpose of subjection to involuntary servitude, peonage, debt bondage or slavery.
Sex trafficking means the recruitment, harboring, transportation, provision, obtaining, patronizing, or soliciting of a person for the purpose of a commercial sex act.

Appendix A to Part 175—Award Term

I. Trafficking in Persons
(a) Provisions applicable to a recipient that is a private entity. (1) Under this award, the recipient, its employees, subrecipients under this award, and subrecipient's employees must not engage in:
(i) Severe forms of trafficking in persons;
(ii) The procurement of a commercial sex act during the period of time that this award or any subaward is in effect;
(iii) The use of forced labor in the performance of this award or any subaward; or
(iv) Acts that directly support or advance trafficking in persons, including the following acts:
(A) Destroying, concealing, removing, confiscating, or otherwise denying an employee access to that employee's identity or immigration documents;
(B) Failing to provide return transportation or pay for return transportation costs to an employee from a country outside the United States to the country from which the employee was recruited upon the end of employment if requested by the employee, unless:
(1) Exempted from the requirement to provide or pay for such return transportation by the Federal department or agency providing or entering into the grant or cooperative agreement; or
(2) The employee is a victim of human trafficking seeking victim services or legal redress in the country of employment or a witness in a human trafficking enforcement action;
(C) Soliciting a person for the purpose of employment, or offering employment, by means of materially false or fraudulent pretenses, representations, or promises regarding that employment;
(D) Charging recruited employees a placement or recruitment fee; or
(E) Providing or arranging housing that fails to meet the host country's housing and safety standards.
(2) The Federal agency may unilaterally terminate this award or take any remedial actions authorized by 22 U.S.C. 7104b(c), without penalty, if any private entity under this award:
(i) Is determined to have violated a prohibition in paragraph (a)(1) of this appendix; or
(ii) Has an employee that is determined to have violated a prohibition in paragraph (a)(1) of this this appendix through conduct that is either:
(A) Associated with the performance under this award; or
(B) Imputed to the recipient or the subrecipient using the standards and due process for imputing the conduct of an individual to an organization that are provided in 2 CFR part 180, “OMB Guidelines to Agencies on Government-wide Debarment and Suspension (Nonprocurement),” as implemented by our agency at [agency must insert reference here to its regulatory implementation of the OMB guidelines in 2 CFR part 180 (for example, “2 CFR part XX”)].
(b) Provision applicable to a recipient other than a private entity. (1) The Federal agency may unilaterally terminate this award or take any remedial actions authorized by 22 U.S.C. 7104b(c), without penalty, if a subrecipient that is a private entity under this award:
(i) Is determined to have violated a prohibition in paragraph (a)(1) of this appendix; or
(ii) Has an employee that is determined to have violated a prohibition in paragraph (a)(1) of this appendix through conduct that is either:
(A) Associated with the performance under this award; or
(B) Imputed to the subrecipient using the standards and due process for imputing the conduct of an individual to an organization that are provided in 2 CFR part 180, “OMB Guidelines to Agencies on Government-wide Debarment and Suspension (Nonprocurement),” as implemented by our agency at [agency must insert reference here to its regulatory implementation of the OMB guidelines in 2 CFR part 180 (for example, “2 CFR part XX”)].
(c) Provisions applicable to any recipient. (1) The recipient must inform the Federal agency and the Inspector General of the Federal agency immediately of any information you receive from any source alleging a violation of a prohibition in paragraph (a)(1) of this appendix.
(2) The Federal agency's right to unilaterally terminate this award as described in paragraphs (a)(2) or (b)(1) of this appendix:
(i) Implements the requirements of 22 U.S.C. 78, and
(ii) Is in addition to all other remedies for noncompliance that are available to the Federal agency under this award.
(3) The recipient must include the requirements of paragraph (a)(1) of this award term in any subaward it makes to a private entity.
(4) If applicable, the recipient must also comply with the compliance plan and certification requirements in 2 CFR 175.105(b).
(d) Definitions. For purposes of this award term:
Employee means either:
(1) An individual employed by the recipient or a subrecipient who is engaged in the performance of the project or program under this award; or
(2) Another person engaged in the performance of the project or program under this award and not compensated by the recipient including, but not limited to, a volunteer or individual whose services are contributed by a third party as an in-kind contribution toward cost sharing requirements.
Private Entity means any entity, including for-profit organizations, nonprofit organizations, institutions of higher education, and hospitals. The term does not include foreign public entities, Indian Tribes, local governments, or states as defined in 2 CFR 200.1.
The terms “severe forms of trafficking in persons,” “commercial sex act,” “sex trafficking,” “Abuse or threatened abuse of law or legal process,” “coercion,” “debt bondage,” and “involuntary servitude” have the meanings given at section 103 of the TVPA, as amended (22 U.S.C. 7102).
8. Revise part 180 to read as follows:

PART 180—OMB GUIDELINES TO AGENCIES ON GOVERNMENT-WIDE DEBARMENT AND SUSPENSION (NONPROCUREMENT)
Sec.
180.5
What does this part do?
180.10
How is this part organized?
180.15
To whom does the guidance apply?
180.20
What must a Federal agency do to implement these guidelines?
180.25
What must a Federal agency address in its implementation of the guidance?
180.30
Where does a Federal agency implement these guidelines?
180.40
How are these guidelines maintained?
180.45
Do these guidelines cover persons who are disqualified, as well as those who are excluded from nonprocurement transactions?

Subpart A—General
180.100
How are subparts A through I organized?
180.105
How is this part written?
180.110
Do terms in this part have special meanings?
180.115
What do subparts A through I of this part do?
180.120
Do subparts A through I of this part apply to me?
180.125
What is the purpose of the nonprocurement debarment and suspension system?
180.130
How does an exclusion restrict a person's involvement in covered transactions?
180.135
May a Federal agency grant an exception to let an excluded person participate in a covered transaction?
180.140
Does an exclusion under the nonprocurement system affect a person's eligibility for Federal procurement contracts?
180.145
Does an exclusion under the Federal procurement system affect a person's eligibility to participate in nonprocurement transactions?
180.150
Against whom may a Federal agency take an exclusion action?
180.155
How do I know if a person is excluded?

Subpart B—Covered Transactions
180.200
What is a covered transaction?
180.205
Why is it important if a particular transaction is a covered transaction?
180.210
Which nonprocurement transactions are covered transactions?
180.215
Which nonprocurement transactions are not covered transactions?
180.220
Are any procurement contracts included as covered transactions?
180.225
How do I know if a transaction in which I may participate is a covered transaction?

Subpart C—Responsibilities of Participants Regarding Transactions Doing Business With Other Persons
180.300
What must I do before I enter into a covered transaction with another person at the next lower tier?
180.305
May I enter into a covered transaction with an excluded or disqualified person?
180.310
What must I do if a Federal agency excludes a person with whom I am already doing business in a covered transaction?
180.315
May I use the services of an excluded person as a principal under a covered transaction?
180.320
Must I verify that principals of my covered transactions are eligible to participate?
180.325
What happens if I do business with an excluded person in a covered transaction?
180.330
What requirements must I pass down to persons at lower tiers with whom I intend to do business?

Disclosing Information—Primary Tier Participants
180.335
What information must I provide before entering into a covered transaction with a Federal agency?
180.340
If I disclose unfavorable information required under § 180.335, will I be prevented from participating in the transaction?
180.345
What happens if I fail to disclose information required under § 180.335?
180.350
What must I do if I learn of information required under § 180.335 after entering into a covered transaction with a Federal agency?

Disclosing Information—Lower Tier Participants
180.355
What information must I provide to a higher tier participant before entering into a covered transaction with that participant?
180.360
What happens if I fail to disclose information required under § 180.355?
180.365
What must I do if I learn of information required under § 180.355 after entering into a covered transaction with a higher tier participant?

Subpart D—Responsibilities of Federal Agency Officials Regarding Transactions
180.400
May I enter into a transaction with an excluded or disqualified person?
180.405
May I enter into a covered transaction with a participant if a principal of the transaction is excluded?
180.410
May I approve a participant's use of the services of an excluded person?
180.415
What must I do if a Federal agency excludes the participant or a principal after I enter into a covered transaction?
180.420
May I approve a transaction with an excluded or disqualified person at a lower tier?
180.425
When do I check to see if a person is excluded or disqualified?
180.430
How do I check to see if a person is excluded or disqualified?
180.435
What must I require of a primary tier participant?
180.440
What action may I take if a primary tier participant knowingly does business with an excluded or disqualified person?
180.445
What action may I take if a primary tier participant fails to disclose the information required under § 180.335?
180.450
What action may I take if a lower tier participant fails to disclose the information required under § 180.355 to the next higher tier?

Subpart E—System for Award Management (SAM.gov) Exclusions
180.500
What is the purpose of the System for Award Management (SAM.gov) Exclusions?
180.505
Who uses SAM.gov Exclusions?
180.510
Who maintains SAM.gov Exclusions?
180.515
What specific information is in SAM.gov Exclusions?
180.520
Who places the information into SAM.gov Exclusions?
180.525
Whom do I ask if I have questions about a person in SAM.gov Exclusions?
180.530
Where can I find SAM.gov Exclusions?

Subpart F—General Principles Relating to Suspension and Debarment Actions
180.600
How do suspension and debarment actions start?
180.605
How does suspension differ from debarment?
180.610
What procedures does a Federal agency use in suspension and debarment actions?
180.615
How does a Federal agency notify a person of a suspension or debarment action?
180.620
Do Federal agencies coordinate suspension and debarment actions?
180.625
What is the scope of a suspension or debarment?
180.630
May a Federal agency impute the conduct of one person to another?
180.635
May a Federal agency resolve an administrative action in lieu of debarment or suspension?
180.640
May a settlement include a voluntary exclusion?
180.645
Do other Federal agencies know if an agency agrees to a voluntary exclusion?
180.650
May an administrative agreement be the result of a settlement?
180.655
How will other Federal awarding agencies know about an administrative agreement that is the result of a settlement?
180.660
Will administrative agreement information about me in SAM.gov be corrected or updated?

Subpart G—Suspension
180.700
When may the suspending official issue a suspension?
180.705
What does the suspending official consider in issuing a suspension?
180.710
When does a suspension take effect?
180.715
What notice does the suspending official give me if I am suspended?
180.720
How may I contest a suspension?
180.725
How much time do I have to contest a suspension?
180.730
What information must I provide to the suspending official if I contest the suspension?
180.735
Under what conditions do I get an additional opportunity to challenge the facts on which the suspension is based?
180.740
Are suspension proceedings formal?
180.745
How is fact-finding conducted?
180.750
What does the suspending official consider in deciding whether to continue or terminate my suspension?
180.755
When will I know whether the suspension is continued or terminated?
180.760
How long may my suspension last?

Subpart H—Debarment
180.800
What are the causes for debarment?
180.805
What notice does the debarring official give me if I am proposed for debarment?
180.810
When does a debarment take effect?
180.815
How may I contest a proposed debarment?
180.820
How much time do I have to contest a proposed debarment?
180.825
What information must I provide to the debarring official if I contest the proposed debarment?
180.830
Under what conditions do I get an additional opportunity to challenge the facts on which the proposed debarment is based?
180.835
Are debarment proceedings formal?
180.840
How is fact-finding conducted?
180.845
What does the debarring official consider in deciding whether to debar me?
180.850
What is the standard of proof in a debarment action?
180.855
Who has the burden of proof in a debarment action?
180.860
What factors may influence the debarring official's decision?
180.865
How long may my debarment last?
180.870
When do I know if the debarring official debars me?
180.875
May I ask the debarring official to reconsider a decision to debar me?
180.880
What factors may influence the debarring official during reconsideration?
180.885
May the debarring official extend a debarment?

Subpart I—Definitions
180.900
Adequate evidence.
180.905
Affiliate.
180.910
Agent or representative.
180.915
Civil judgment.
180.920
Conviction.
180.925
Debarment.
180.930
Debarring official.
180.935
Disqualified.
180.940
Excluded or exclusion.
180.945
System for Award Management Exclusions (SAM.gov) Exclusions.
180.950
Federal agency.
180.955
Indictment.
180.960
Ineligible or ineligibility.
180.965
Legal proceedings.
180.970
Nonprocurement transaction.
180.975
Notice.
180.980
Participant.
180.985
Person.
180.990
Preponderance of the evidence.
180.995
Principal.
180.1000
Respondent.
180.1005
State.
180.1010
Suspending official.
180.1015
Suspension.
180.1020
Voluntary exclusion or voluntarily excluded.

Appendix A to Part 180—Covered Transactions

Authority:
31 U.S.C. 503; 31 U.S.C. 6102; 31 U.S.C. 6307; Pub. L. 103-355; Pub. L. 109-282; Pub. L. 110-252; Pub. L. 111-84; Pub. L. 113-101Pub. L. 115-232; Pub. L. 117-40; E.O. 12549; E.O. 12689.
§ 180.5
What does this part do?
This part provides guidance for Federal agencies on how to implement the government-wide debarment and suspension system for nonprocurement programs and activities.
§ 180.10
How is this part organized?
This part is organized into two segments.
(a) Sections 180.5 through 180.45 contain general policy direction for Federal agencies' use of the standards in subparts A through I.
(b) Subparts A through I contain uniform government-wide standards that Federal agencies are to use to specify:
(1) The types of transactions that are covered by the nonprocurement debarment and suspension system;
(2) The effects of an exclusion under that nonprocurement system, including reciprocal effects with the government-wide debarment and suspension system for procurement;
(3) The criteria and minimum due process to be used in nonprocurement debarment and suspension actions; and
(4) Related policies and procedures to ensure the effectiveness of those actions.
§ 180.15
To whom does the guidance apply?
This part provides guidance to Federal agencies. Publication of this guidance in the Code of Federal Regulations (CFR) does not change its nature—it is guidance and not regulation. Federal agencies' implementation of this guidance governs the rights and responsibilities of other persons affected by the nonprocurement debarment and suspension system.
§ 180.20
What must a Federal agency do to implement these guidelines?
As Section 3 of Executive Order 12549 requires, each Federal agency with nonprocurement programs and activities covered by subparts A through I of the guidance must issue regulations consistent with those subparts.
§ 180.25
What must a Federal agency address in its implementation of the guidance?
Each Federal agency's implementing regulation:
(a) Must establish policies and procedures for that Federal agency's nonprocurement debarment and suspension programs and activities consistent with this guidance. When adopted by a Federal agency, the provisions of the guidance have a regulatory effect on that Federal agency's programs and activities.
(b) Must address some matters for which these guidelines give each Federal agency some discretion. Specifically, the regulation must:
(1) Identify either the Federal agency head or the title of the designated official who is authorized to grant exceptions under § 180.135 to let an excluded person participate in a covered transaction.
(2) State whether the Federal agency includes as covered transactions an additional tier of contracts awarded under covered nonprocurement transactions, as permitted under § 180.220(c).
(3) Identify the method(s) a Federal agency official may use when entering into a covered transaction with a primary tier participant to communicate to the participant the requirements described in § 180.435. Examples of methods are an award term that requires compliance as a condition of the award, an assurance of compliance obtained at the time of application, or a certification.
(4) State whether the Federal agency specifies a particular method that participants must use to communicate compliance requirements to lower tier participants, as described in § 180.330(a). If there is a specified method, the regulation must require Federal agency officials to communicate that requirement when entering into covered transactions with primary tier participants.
(c) May also, at the Federal agency's option:
(1) Identify any specific types of transactions the Federal agency includes as “nonprocurement transactions” in addition to the examples provided in § 180.970.
(2) Identify any types of nonprocurement transactions that the Federal agency exempts from coverage under these guidelines, as authorized under § 180.215(g)(2).
(3) Identify specific examples of types of individuals who would be “principals” under the Federal agency's nonprocurement programs and transactions, in addition to the types of individuals described in § 180.995.
(4) Specify the Federal agency's procedures, if any, by which a respondent may appeal a suspension or debarment decision.
(5) Identify by title the officials designated by the Federal agency head as debarring officials under § 180.930 or suspending officials under § 180.1010.
(6) Include a subpart covering disqualifications, as authorized in § 180.45.
(7) Include any provisions authorized by OMB.
§ 180.30
Where does a Federal agency implement these guidelines?
Each Federal agency that participates in the government-wide nonprocurement debarment and suspension system must issue a regulation implementing these guidelines within its chapter in subtitle B of this title.
§ 180.40
How are these guidelines maintained?
The Interagency Committee on Debarment and Suspension, established by section 4 of Executive Order 12549, recommends to the OMB any needed revisions to the guidelines in this part. The OMB publishes proposed changes to the guidelines in the Federal Register for public comment, considers comments with the help of the Interagency Committee on Debarment and Suspension, and issues the final guidelines.
§ 180.45
Do these guidelines cover persons who are disqualified, as well as those who are excluded from nonprocurement transactions?
A Federal agency may add a subpart covering disqualifications to its regulation implementing these guidelines, but the guidelines in subparts A through I:
(a) Address disqualified persons only to:
(1) Provide for their inclusion in the System for Award Management (SAM.gov) Exclusions; and
(2) State the responsibilities of Federal agencies and participants to check for disqualified persons before entering into covered transactions.
(b) Do not specify the:
(1) Transactions for which a disqualified person is ineligible. Those transactions vary on a case-by-case basis because they depend on the language of the specific statute, Executive order, or regulation that caused the disqualification;
(2) Entities to which a disqualification applies; or
(3) Process that a Federal agency uses to disqualify a person. Unlike exclusion under subparts A through I of this part, disqualification is frequently not a discretionary action that a Federal agency takes and may include special procedures.

Subpart A—General
§ 180.100
How are subparts A through I organized?
(a) Each subpart contains information related to a broad topic or specific audience with special responsibilities, as shown in table 1:
Table 1 to Paragraph ( a )
In subpart . . . | You will find provisions related to . . .
A | general information about Subparts A through I.
B | the types of transactions that are covered by the government-wide nonprocurement suspension and debarment system.
C | the responsibilities of persons who participate in covered transactions.
D | the responsibilities of Federal agency officials who are authorized to enter into covered transactions.
E | the responsibilities of Federal agencies for entering information into SAM.gov Exclusions.
F | the general principles governing suspension, debarment, voluntary exclusion and settlement.
G | suspension actions.
H | debarment actions.
I | definitions of terms used in this part.
(b) Table 2 shows which subparts may be of special interest to you, depending on who you are:
Table 2 to Paragraph ( b )
If you are . . . | See Subpart(s) . . .
(1) a participant or principal in a nonprocurement transaction | A, B, C and I.
(2) a respondent in a suspension action | A, B, F, G and I.
(3) a respondent in a debarment action | A, B, F, H and I.
(4) a suspending official | A, B, E, F, G and I.
(5) a debarring official | A, B, D, F, H and I.
(6) a Federal agency official authorized to enter into a covered transaction | A, B, D, E and I.
§ 180.105
How is this part written?
(a) This part uses a “plain language” format to make it easier for the general public and business community. The section headings and text must be read together, as they are often in the form of questions and answers.
(b) Pronouns used within this part, such as “I” and “you,” change from subpart to subpart depending on the audience being addressed.
(c) The “Covered Transactions” diagram in the appendix to this part shows the levels or “tiers” at which a Federal agency may enforce an exclusion.
§ 180.110
Do terms in this part have special meanings?
This part uses terms throughout the text that have special meanings. Those terms are defined in subpart I. For example, three important terms are:
(a) Exclusion or excluded, which refers only to discretionary actions taken by a suspending or debarring official under Executive Order 12549 and Executive Order 12689 or under the Federal Acquisition Regulations (48 CFR part 9, subpart 9.4);
(b) Disqualification or disqualified, which refers to prohibitions under specific statutes, executive orders (other than Executive Order 12549 and Executive Order 12689), or other authorities. Disqualifications frequently are not subject to the discretion of a Federal agency official, may have a different scope than exclusions, or have special conditions that apply to the disqualification; and
(c) Ineligibility or ineligible, which generally refers to a person who is either excluded or disqualified.
§ 180.115
What do subparts A through I of this part do?
Subparts A through I provide for the reciprocal exclusion of persons who have been excluded under the Federal Acquisition Regulations and provide for the consolidated listing of all persons who are excluded, or disqualified by statute, executive order or other legal authority.
§ 180.120
Do subparts A through I of this part apply to me?
Portions of subparts A through I (see table at § 180.100(b)) apply to you if you are a:
(a) Person who has been, is, or may reasonably be expected to be, a participant or principal in a covered transaction;
(b) Respondent (a person against whom a Federal agency has initiated a debarment for suspension action);
(c) Federal agency debarring or suspending official; or
(d) Federal agency official who is authorized to enter into covered transactions with non-Federal parties.
§ 180.125
What is the purpose of the nonprocurement debarment and suspension system?
(a) To protect the public interest, the Federal Government ensures the integrity of Federal programs by conducting business only with responsible persons.
(b) A Federal agency uses the nonprocurement debarment and suspension system to exclude persons who are not presently responsible from Federal programs.
(c) An exclusion is a serious action that a Federal agency may take only to protect the public interest. A Federal agency may not exclude a person or commodity for the purposes of punishment.
§ 180.130
How does an exclusion restrict a person's involvement in covered transactions?
With the exceptions stated in §§ 180.135, 315, and 420, a person who is excluded by any Federal agency may not:
(a) Be a participant in a Federal agency transaction that is a covered transaction; or
(b) Act as a principal of a person participating in one of those covered transactions.
§ 180.135
May a Federal agency grant an exception to let an excluded person participate in a covered transaction?
(a) A Federal agency head or designee may grant an exception permitting an excluded person to participate in a particular covered transaction. If the Federal agency head or designee grants an exception, the exception must be in writing and state the reason(s) for deviating from the government-wide policy in Executive Order 12549.
(b) An exception granted by one Federal agency for an excluded person does not extend to the covered transactions of another Federal agency.
§ 180.140
Does an exclusion under the nonprocurement system affect a person's eligibility for Federal procurement contracts?
When a Federal agency excludes a person under Executive Order 12549 or Executive Order 12689 on or after August 25, 1995, the excluded person is also ineligible for Federal procurement transactions under the Federal Acquisition Regulations. Therefore, an exclusion under this part has a reciprocal effect on Federal procurement transactions.
§ 180.145
Does an exclusion under the Federal procurement system affect a person's eligibility to participate in nonprocurement transactions?
When a Federal agency excludes a person under the Federal Acquisition Regulations (FAR) on or after August 25, 1995, the excluded person is also ineligible to participate in Federal agencies' nonprocurement covered transactions. Therefore, an exclusion under the FAR has a reciprocal effect on Federal nonprocurement transactions.
§ 180.150
Against whom may a Federal agency take an exclusion action?
Given a cause that justifies an exclusion under this part, a Federal agency may exclude any person who has been, is, or may reasonably be expected to be a participant or principal in a covered transaction.
§ 180.155
How do I know if a person is excluded?
Check the System for Award Management ( SAM.gov ) Exclusions to determine whether a person is excluded. The General Services Administration (GSA) maintains SAM.gov Exclusions and makes it available, as detailed in subpart E. When a Federal agency takes action to exclude a person under the nonprocurement or procurement debarment and suspension system, the agency enters the information about the excluded person into SAM.gov Exclusions.

Subpart B—Covered Transactions
§ 180.200
What is a covered transaction?
A covered transaction is a nonprocurement or procurement transaction subject to this part's prohibitions. It may be a transaction at:
(a) The primary tier, between a Federal agency and a person (see Appendix to this part); or
(b) A lower tier between a participant in a covered transaction and another person.
§ 180.205
Why is it important if a particular transaction is a covered transaction?
The importance of whether a transaction is a covered transaction depends upon who you are.
(a) As a participant in the transaction, you have the responsibilities laid out in subpart C of this part. Those include responsibilities to the person or Federal agency at the next higher tier from whom you received the transaction, if any. They also include responsibilities if you subsequently enter into other covered transactions with persons at the next lower tier.
(b) As a Federal official who enters into a primary tier transaction, you have the responsibilities laid out in subpart D of this part.
(c) As an excluded person, you may not be a participant or principal in the transaction unless:
(1) The person who entered into the transaction with you allows you to continue your involvement in a transaction that predates your exclusion, as permitted under § 180.310 or § 180.415; or
(2) A Federal agency official obtains an exception from the agency head or designee to allow you to be involved in the transaction, as permitted under § 180.135.
§ 180.210
Which nonprocurement transactions are covered transactions?
All nonprocurement transactions, as defined in § 180.970, are covered transactions unless listed in the exemptions under § 180.215.
§ 180.215
Which nonprocurement transactions are not covered transactions?
The following types of nonprocurement transactions are not covered transactions:
(a) A direct award to:
(1) A foreign government or foreign governmental entity;
(2) A public international organization;
(3) An entity owned (in whole or in part) or controlled by a foreign government; or
(4) Any other entity consisting wholly or partially of one or more foreign governments or foreign governmental entities.
(b) A benefit to an individual as a personal entitlement without regard to the individual's present responsibility (but benefits received in an individual's business capacity are not excepted). For example, when a person receives social security benefits under the Supplemental Security Income provisions of the Social Security Act, 42 U.S.C. 1301 et seq., those benefits are not covered transactions and, therefore, are not affected if the person is excluded.
(c) Federal employment.
(d) A transaction that a Federal agency needs to respond to a national or agency recognized emergency or disaster.
(e) A permit, license, certificate, or similar instrument issued as a means to regulate public health, safety, or the environment, unless a Federal agency specifically designates it to be a covered transaction.
(f) An incidental benefit that results from ordinary governmental operations.
(g) Any other transaction if:
(1) The application of an exclusion to the transaction is prohibited by law; or
(2) A Federal agency's regulation exempts it from coverage under this part.
(h) Notwithstanding paragraph (a) of this section, covered transactions must include non-procurement and procurement transactions involving entities engaged in activity that contributed to or is a significant factor in a country's non-compliance with its obligations under arms control, nonproliferation or disarmament agreements, or commitments with the United States. Federal agencies and primary tier non-procurement recipients must not award, renew, or extend a non-procurement transaction or procurement transaction, regardless of amount or tier, with any entity listed in SAM.gov Exclusions on the basis of involvement in activities that violate arms control, nonproliferation or disarmament agreements, or commitments with the United States (see section 1290 of the National Defense Authorization Act for Fiscal Year 2017). The head of a Federal agency may grant an exception to this requirement under 2 CFR 180.135 and with the concurrence of the OMB Director.
§ 180.220
Are any procurement contracts included as covered transactions?
(a) Covered transactions under this part:
(1) Do not include any procurement contracts awarded directly by a Federal agency; but
(2) Do include some procurement contracts awarded under nonprocurement covered transactions.
(b) Specifically, a contract for goods or services is a covered transaction if any of the following applies:
(1) The contract is awarded by a participant in a nonprocurement transaction covered under § 180.210, and the contract amount is expected to equal or exceed $25,000.
(2) The contract requires the consent of an official of a Federal agency. In that case, the contract is always a covered transaction regardless of the amount or who awarded it. For example, it could be a subcontract awarded by a contractor at a tier below a nonprocurement transaction, as shown in the Appendix to this part.
(3) The contract is for Federally required audit services.
(c) A subcontract also is a covered transaction if:
(1) It is awarded by a participant in a procurement transaction under a nonprocurement transaction of a Federal agency that extends the coverage of paragraph (b)(1) of this section to additional tiers of contracts (see the diagram in the Appendix to this part showing that optional lower tier coverage); and
(2) The value of the subcontract is expected to equal or exceed $25,000.
§ 180.225
How do I know if a transaction in which I may participate is a covered transaction?
As a participant in a transaction, you will know that it is a covered transaction because of the Federal agency regulations governing the transaction. The appropriate Federal agency official or participant at the next higher tier who enters into the transaction with you will tell you that you must comply with applicable portions of this part.

Subpart C—Responsibilities of Participants Regarding Transactions Doing Business With Other Persons
§ 180.300
What must I do before I enter into a covered transaction with another person at the next lower tier?
When you enter into a covered transaction with another person at the next lower tier, you must verify that the person with whom you intend to do business is not excluded or disqualified. You do this by:
(a) Checking SAM.gov Exclusions; or
(b) Collecting a certification from that person; or
(c) Adding a clause or condition to the covered transaction with that person.
§ 180.305
May I enter into a covered transaction with an excluded or disqualified person?
(a) As a participant, you may not enter into a covered transaction with an excluded person unless the Federal agency responsible for the transaction grants an exception under § 180.135.
(b) You may not enter into any transaction with a person who is disqualified from that transaction unless you have obtained an exception under the disqualifying statute, Executive Order, or regulation.
§ 180.310
What must I do if a Federal agency excludes a person with whom I am already doing business in a covered transaction?
(a) As a participant, you may continue covered transactions with an excluded person if the transactions were in existence when the Federal agency excluded the person. However, you are not required to continue the transactions, and you may consider termination. You should decide whether to terminate and the type of termination action, if any, only after a thorough review to ensure that the action is proper and appropriate.
(b) You may not renew or extend covered transactions (other than no-cost time extensions) with any excluded person unless the Federal agency responsible for the transaction grants an exception under § 180.135.
§ 180.315
May I use the services of an excluded person as a principal under a covered transaction?
(a) As a participant, you may continue to use the services of an excluded person as a principal under a covered transaction if you were using that person's services in the transaction before the person was excluded. However, you are not required to continue using that person's services as a principal. You should decide whether to discontinue that person's services only after a thorough review to ensure that the action is proper and appropriate.
(b) You may not begin to use the services of an excluded person as a principal under a covered transaction unless the Federal agency responsible for the transaction grants an exception under § 180.135.
§ 180.320
Must I verify that principals of my covered transactions are eligible to participate?
(a) Yes. As a participant, you are responsible for determining whether your principals of your covered transactions are excluded or disqualified from participating in the transaction.
(b) You may decide the method and frequency by which you do so. You may, but are not required to check SAM.gov Exclusions.
§ 180.325
What happens if I do business with an excluded person in a covered transaction?
As a participant, if you knowingly do business with an excluded person, the Federal agency responsible for your transaction may disallow costs, annul or terminate the transaction, issue a stop work order, debar or suspend you, or take other remedies as appropriate.
§ 180.330
What requirements must I pass down to persons at lower tiers with whom I intend to do business?
Before entering into a covered transaction with a participant at the next lower tier, you must require that participant to:
(a) Comply with this subpart as a condition of participating in the transaction. You may do so using any method(s) unless the regulation of the Federal agency responsible for the transaction requires you to use specific methods.
(b) Pass the requirement to comply with this subpart to each person the participant enters into a covered transaction at the next lower tier.

Disclosing Information—Primary Tier Participants
§ 180.335
What information must I provide before entering into a covered transaction with a Federal agency?
Before you enter into a covered transaction at the primary tier, you, as the participant, must notify the Federal agency office that is entering into the transaction with you if you know that you or any of the principals for that covered transaction:
(a) Are presently excluded or disqualified;
(b) Have been convicted within the preceding three years of any of the offenses listed in § 180.800(a) or had a civil judgment rendered against you for one of those offenses within that time period;
(c) Are presently indicted for or otherwise criminally or civilly charged by a governmental entity (Federal, State, or local) with the commission of any of the offenses listed in § 180.800(a); or
(d) Have had one or more public transactions (Federal, State, or local) terminated within the preceding three years for cause or default.
§ 180.340
If I disclose unfavorable information required under § 180.335, will I be prevented from participating in the transaction?
As a primary tier participant, disclosing unfavorable information about yourself or a principal under § 180.335 will not necessarily cause a Federal agency to deny your participation in the covered transaction. The Federal agency will consider the information when determining whether to enter into the covered transaction. The Federal agency will also consider any additional information or explanation you elect to submit with the disclosed information.
§ 180.345
What happens if I fail to disclose information required under § 180.335?
If a Federal agency later determines that you failed to disclose information under § 180.335 that you knew at the time you entered into the covered transaction, the Federal agency may:
(a) Terminate the transaction for material failure to comply with the terms and conditions of the transaction; or
(b) Pursue any other available remedies, including suspension and debarment.
§ 180.350
What must I do if I learn of information required under § 180.335 after entering into a covered transaction with a Federal agency?
At any time after you enter into a covered transaction, you must give immediate written notice to the Federal agency office with which you entered into the transaction if you learn either that:
(a) You failed to disclose information earlier, as required by § 180.335; or
(b) Due to changed circumstances, you or any of the principals for the transaction now meet any of the criteria in § 180.335.

Disclosing Information—Lower Tier Participants
§ 180.355
What information must I provide to a higher tier participant before entering into a covered transaction with that participant?
Before you enter into a covered transaction with a person at the next higher tier, you, as a lower tier participant, must notify that person if you know that you or any of the principals are presently excluded or disqualified.
§ 180.360
What happens if I fail to disclose information required under § 180.355?
When a Federal agency later determines that you failed to tell the person at the higher tier that you were excluded or disqualified at the time you entered into the covered transaction with that person, the agency may pursue any available remedies, including suspension and debarment.
§ 180.365
What must I do if I learn of information required under § 180.355 after entering into a covered transaction with a higher tier participant?
At any time after you enter into a lower tier covered transaction with a person at a higher tier, you must provide immediate written notice to that person if you learn either that:
(a) You failed to disclose information earlier, as required by § 180.355; or
(b) Due to changed circumstances, you or any of the principals for the transaction now meet any of the criteria in § 180.355.

Subpart D—Responsibilities of Federal Agency Officials Regarding Transactions
§ 180.400
May I enter into a transaction with an excluded or disqualified person?
(a) As a Federal agency official, you may not enter into a covered transaction with an excluded person unless you obtain an exception under § 180.135.
(b) You may not enter into any transaction with a person disqualified from that transaction unless you obtain a waiver or exception under the statute, Executive Order, or regulation that is the basis for the person's disqualification.
§ 180.405
May I enter into a covered transaction with a participant if a principal of the transaction is excluded?
As a Federal agency official, you may not enter into a covered transaction with a participant if you know that a principal of the transaction is excluded unless you obtain an exception under § 180.135.
§ 180.410
May I approve a participant's use of the services of an excluded person?
After entering into a covered transaction with a participant, you, as a Federal agency official, may not approve a participant's use of an excluded person as a principal under that transaction unless you obtain an exception under § 180.135.
§ 180.415
What must I do if a Federal agency excludes the participant or a principal after I enter into a covered transaction?
(a) As a Federal agency official, you may continue covered transactions with an excluded person or under which an excluded person is a principal if the transactions were in existence when the person was excluded. However, you are not required to continue the transactions, and you may consider termination. You should decide whether to terminate and the type of termination action, if any, only after a thorough review to ensure that the action is proper and appropriate.
(b) You may not renew or extend covered transactions (other than no-cost time extensions) with any excluded person or under which an excluded person is a principal unless you obtain an exception under § 180.135.
§ 180.420
May I approve a transaction with an excluded or disqualified person at a lower tier?
If a transaction at a lower tier is subject to your approval, you, as a Federal agency official, may not approve:
(a) A covered transaction with a person who is currently excluded unless you obtain an exception under § 180.135; or
(b) A transaction with a person who is disqualified from that transaction unless you obtain a waiver or exception under the statute, Executive Order, or regulation that is the basis for the person's disqualification.
§ 180.425
When do I check to see if a person is excluded or disqualified?
As a Federal agency official, you must check to see if a person is excluded or disqualified before you:
(a) Enter into a primary tier covered transaction;
(b) Approve a principal in a primary tier covered transaction;
(c) Approve a lower tier participant if your Federal agency's approval of the lower tier participant is required; or
(d) Approve a principal in connection with a lower tier transaction if your Federal agency's approval of the principal is required.
§ 180.430
How do I check to see if a person is excluded or disqualified?
You check to see if a person is excluded or disqualified in two ways:
(a) As a Federal agency official, you must check SAM.gov Exclusions when you take any action listed in § 180.425.
(b) You must review the information that a participant gives you, as required by § 180.335, about its status or the status of the principals of a transaction.
§ 180.435
What must I require of a primary tier participant?
As a Federal agency official, you must require each participant in a primary tier covered transaction to:
(a) Comply with subpart C as a condition of participation in the transaction; and
(b) Communicate the requirement to comply with subpart C to persons at the next lower tier with whom the primary tier participant enters into covered transactions.
§ 180.440
What action may I take if a primary tier participant knowingly does business with an excluded or disqualified person?
If a participant knowingly does business with an excluded or disqualified person, you, as a Federal agency official, may refer the matter for suspension and debarment consideration. You may also disallow costs, annul or terminate the transaction, issue a stop work order, or take any other appropriate remedy.
§ 180.445
What action may I take if a primary tier participant fails to disclose the information required under § 180.335?
As a Federal agency official, if you determine that a participant failed to disclose information, as required by § 180.335, at the time it entered into a covered transaction with you, you may:
(a) Terminate the transaction for material failure to comply with the terms and conditions of the transaction; or
(b) Pursue any other available remedies, including suspension and debarment.
§ 180.450
What action may I take if a lower tier participant fails to disclose the information required under § 180.355 to the next higher tier?
As a Federal agency official, if you determine that a lower tier participant failed to disclose information, as required by § 180.355, at the time it entered into a covered transaction with a participant at the next higher tier, you may pursue any remedies available to you, including the initiation of a suspension or debarment action.

Subpart E—System for Award Management (SAM.gov) Exclusions
§ 180.500
What is the purpose of the System for Award Management (SAM.gov) Exclusions?
The SAM.gov Exclusions is a widely available source of the most current information about persons who are excluded or disqualified from covered transactions.
§ 180.505
Who uses SAM.gov Exclusions?
(a) Federal agency officials use SAM.gov Exclusions to determine whether to enter into a transaction with a person, as required under § 180.430.
(b) Participants also may, but are not required to, use SAM.gov Exclusions to determine if:
(1) Principals of their transactions are excluded or disqualified, as required under § 180.320; or
(2) Persons with whom they are entering into covered transactions at the next lower tier are excluded or disqualified.
(c) The SAM.gov Exclusions are available to the general public.
§ 180.510
Who maintains SAM.gov Exclusions?
GSA maintains SAM.gov Exclusions. When a Federal agency takes an action to exclude a person under the nonprocurement or procurement debarment and suspension system, the agency enters the information about the excluded person into SAM.gov Exclusions.
§ 180.515
What specific information is in SAM.gov Exclusions?
(a) At a minimum, SAM.gov Exclusions indicate:
(1) The full name (where available) and address of each excluded and disqualified person, in alphabetical order, with cross-references if more than one name is involved in a single action;
(2) The type of action;
(3) The cause for the action;
(4) The scope of the action;
(5) Any termination date for the action;
(6) The Federal agency and name and telephone number of the agency point of contact for the action; and
(7) The unique entity identifier approved by the GSA of the excluded or disqualified person, if available.
(b)(1) The SAM.gov Exclusions includes a field for the Taxpayer Identification Number (TIN), or the social security number (SSN) for an individual, of an excluded or disqualified person.
(2) Agencies disclose an individual's SSN to verify an individual's identity only if permitted under the Privacy Act of 1974 and, if appropriate, the Computer Matching and Privacy Protection Act of 1988, as codified in 5 U.S.C. 552(a).
§ 180.520
Who places the information into SAM.gov Exclusions?
Federal agency officials who take actions to exclude persons under this part or officials who are responsible for identifying disqualified persons must enter the following information about those persons into SAM.gov Exclusions:
(a) Information required by § 180.515(a);
(b) The Taxpayer Identification Number (TIN) of the excluded or disqualified person, including the social security number (SSN) for an individual, if the number is available and may be disclosed under the law;
(c) Information about an excluded or disqualified person, within three business days, after:
(1) Taking an exclusion action;
(2) Modifying or rescinding an exclusion action;
(3) Finding that a person is disqualified; or
(4) Finding that there has been a change in the status of a person who is listed as disqualified.
§ 180.525
Whom do I ask if I have questions about a person in SAM.gov Exclusions?
If you have questions about a listed person in SAM.gov Exclusions, ask the point of contact for the Federal agency that placed the person's name into SAM.gov Exclusions. You may find the Federal agency point of contact from SAM.gov Exclusions.
§ 180.530
Where can I find SAM.gov Exclusions?
You may access SAM.gov Exclusions through the internet, currently at https://www.sam.gov.

Subpart F—General Principles Relating to Suspension and Debarment Actions
§ 180.600
How do suspension and debarment actions start?
When Federal agency officials receive information from any source concerning a cause for suspension or debarment, they will promptly report it, and the agency will investigate. The officials refer the question of whether to suspend or debar you to their suspending or debarring official for consideration, if appropriate.
§ 180.605
How does suspension differ from debarment?
Suspension differs from debarment in that:
A suspending official . . . | A debarring official . . .
(a) Imposes suspension as a temporary status of ineligibility for procurement and nonprocurement transactions, pending completion of an investigation or legal or debarment proceeding | Imposes debarment for a specified period as a final determination that a person is not presently responsible.
(b) Must: |
(1) Have adequate evidence that there may be a cause for debarment of a person; and |
(2) Conclude that immediate action is necessary to protect the Federal interest | Must conclude, based on a preponderance of the evidence, that the person has engaged in conduct that warrants debarment.
(c) Usually imposes the suspension first, and then promptly notifies the suspended person, giving the person an opportunity to contest the suspension and have it lifted | Imposes debarment after giving the respondent notice of the action and an opportunity to contest the proposed debarment.
§ 180.610
What procedures does a Federal agency use in suspension and debarment actions?
In deciding whether to suspend or debar you, a Federal agency handles the actions as informally as practicable, consistent with principles of fundamental fairness.
(a) For suspension actions, a Federal agency uses the procedures in this subpart and subpart G.
(b) For debarment actions, a Federal agency uses the procedures in this subpart and subpart H.
§ 180.615
How does a Federal agency notify a person of a suspension or debarment action?
(a) The suspending or debarring official sends a written notice to the last known street address, facsimile number, or email address of:
(1) You or your identified counsel; or
(2) Your agent for service of process, or any of your partners, officers, directors, owners, or joint venturers.
(b) The notice is effective if sent to any of these persons.
§ 180.620
Do Federal agencies coordinate suspension and debarment actions?
Yes, when more than one Federal agency has an interest in a suspension or debarment, the agencies may consider designating one Federal agency as the lead agency for making the decision. Agencies are encouraged to establish methods and procedures for coordinating their suspension and debarment actions.
§ 180.625
What is the scope of a suspension or debarment?
If you are suspended or debarred, the suspension or debarment is effective as follows:
(a) Your suspension or debarment constitutes suspension or debarment of all of your divisions and other organizational elements from all covered transactions unless the suspension or debarment decision is limited:
(1) By its terms to one or more specifically identified individuals, divisions, or other organizational elements; or
(2) To specific types of transactions.
(b) Any affiliate of a participant may be included in a suspension or debarment action if the suspending or debarring official:
(1) Officially names the affiliate in the notice; and
(2) Gives the affiliate an opportunity to contest the action.
§ 180.630
May a Federal agency impute the conduct of one person to another?
For purposes of actions taken under this part, a Federal agency may impute conduct as follows:
(a) Conduct imputed from an individual to an organization. A Federal agency may impute the fraudulent, criminal, or other improper conduct of any officer, director, shareholder, partner, employee, or other individual associated with an organization to that organization when the improper conduct occurred in connection with the individual's performance of duties for or on behalf of that organization, or with the organization's knowledge, approval or acquiescence. The organization's acceptance of the benefits derived from the conduct is evidence of knowledge, approval, or acquiescence.
(b) Conduct imputed from an organization to an individual or between individuals. A Federal agency may impute the fraudulent, criminal, or other improper conduct of any organization to an individual, or from one individual to another individual, if the individual to whom the improper conduct is imputed either participated in, had knowledge of, or reason to know of the improper conduct.
(c) Conduct imputed from one organization to another organization. A Federal agency may impute the fraudulent, criminal, or other improper conduct of one organization to another organization when the improper conduct occurred in connection with a partnership, joint venture, joint application, association, corporation, company, or similar arrangement or with the organization's knowledge, approval, or acquiescence, or when the organization to whom the improper conduct is imputed has the power to direct, manage, control or influence the activities of the organization responsible for the improper conduct. Acceptance of the benefits derived from the conduct is evidence of knowledge, approval, or acquiescence.
§ 180.635
May a Federal agency resolve an administrative action in lieu of debarment or suspension?
Yes. A Federal agency may resolve an administrative action in lieu of debarment or suspension by entering into an agreement at any time if it is in the Federal Government's best interest.
§ 180.640
May an agreement to resolve an administrative action include a voluntary exclusion?
Yes. If a Federal agency enters into an agreement to resolve an administrative action with you in which you agree to be excluded, it is called a voluntary exclusion and has a government-wide effect.
§ 180.645
Do other Federal agencies know if an agency agrees to a voluntary exclusion?
(a) Yes. The Federal agency agreeing to the voluntary exclusion enters information about it into SAM.gov Exclusions.
(b) Also, any agency or person may contact the Federal agency that agreed to the voluntary exclusion to find out the details of the voluntary exclusion.
§ 180.650
May an administrative agreement be the result of a settlement?
Yes. A Federal agency may enter into an administrative agreement with you as part of the settlement of a debarment or suspension action.
§ 180.655
How will other Federal awarding agencies know about an administrative agreement that is the result of a settlement?
The suspending or debarring official who enters into an administrative agreement with you must report information about the agreement in SAM.gov within three business days after entering into the agreement. The suspending and debarring official must use the Contractor Performance Assessment Reporting System (CPARS) to enter or amend information in SAM.gov . This information is required by section 872 of the Duncan Hunter National Defense Authorization Act for Fiscal Year 2009 (41 U.S.C. 2313).
§ 180.660
Will administrative agreement information about me in SAM.gov be corrected or updated?
Yes. The suspending or debarring official who entered information into SAM.gov about an administrative agreement with you:
(a) Must correct the information within three business days if the official subsequently learn that any information is erroneous.
(b) Must correct in SAM.gov , within three business days, the ending date of the period during which the agreement is in effect if the agreement is amended to extend that period.
(c) Must report any other modification to the administrative agreement in SAM.gov within three business days.
(d) Is strongly encouraged to amend the information in SAM.gov in a timely way to incorporate any update that the official obtains and that could be helpful to Federal agencies who must use the system.

Subpart G—Suspension
§ 180.700
When may the suspending official issue a suspension?
Suspension is a serious action. Using the procedures of this subpart and subpart F of this part, the suspending official may impose suspension only when that official determines that:
(a) There exists an indictment for, or other adequate evidence to suspect, an offense listed under § 180.800(a), or
(b) There exists adequate evidence to suspect any other cause for debarment listed under § 180.800(b) through (d); and
(c) Immediate action is necessary to protect the public interest.
§ 180.705
What does the suspending official consider in issuing a suspension?
(a) In determining the adequacy of the evidence to support the suspension, the suspending official considers how much information is available, how credible it is given the circumstances, whether or not important allegations are corroborated, and what inferences can reasonably be drawn as a result.
(b) In making this determination, the suspending official may examine:
(1) The basic documents, including grants, cooperative agreements, loan authorizations, contracts, and other relevant documents;
(2) An indictment, criminal information, conviction, civil judgment, or other official findings by Federal, State, or local bodies that determine factual or legal matters constitutes adequate evidence for purposes of suspension actions; and
(3) Other indicators of adequate evidence that may include, but are not limited to, warrants and their accompanying affidavits.
(c) In deciding whether immediate action is needed to protect the public interest, the suspending official has wide discretion. For example, the suspending official may infer the necessity for immediate action to protect the public interest either from the nature of the circumstances giving rise to a cause for suspension or from potential business relationships or involvement with a program of the Federal Government.
§ 180.710
When does a suspension take effect?
A suspension is effective when the suspending official signs the decision to suspend.
§ 180.715
What notice does the suspending official give me if I am suspended?
After deciding to suspend you, the suspending official promptly sends you a Notice of Suspension advising you:
(a) That you have been suspended;
(b) That your suspension is based on:
(1) An indictment;
(2) A criminal information;
(3) A conviction;
(4) A civil judgment;
(5) Other adequate evidence that you have committed irregularities that seriously reflect on the propriety of further Federal Government dealings with you; or
(6) Conduct of another person that has been imputed to you or your affiliation with a suspended or debarred person;
(c) Of any other irregularities supporting your suspension in terms sufficient to put you on notice without disclosing certain evidence in the Federal Government's pending or contemplated legal proceedings;
(d) Of the cause(s) upon which the suspending official relied under § 180.700 for imposing suspension;
(e) That your suspension is for a temporary period pending the completion of an investigation or resulting legal or debarment proceedings;
(f) Of the applicable provisions of this subpart, subpart F of this part, and any other Federal agency procedures governing suspension decision-making; and
(g) Of the government-wide effect of your suspension from procurement and nonprocurement programs and activities.
§ 180.720
How may I contest a suspension?
As a respondent, if you wish to contest a suspension, you or your representative must provide the suspending official with information in opposition to the suspension. You may do this orally or in writing. While oral statements may be a part of the official record, any information provided orally that you consider important must also be submitted in writing for the official record.
§ 180.725
How much time do I have to contest a suspension?
(a) As a respondent, you or your representative must either send or make arrangements to appear and present the information and argument to the suspending official within 30 days after you receive the Notice of Suspension.
(b) The Federal agency taking the action considers the notice to be received by you:
(1) When delivered, if the Federal agency mails the notice to the last known street address, or five days after the agency sends it if the letter is undeliverable;
(2) When sent, if the Federal agency sends the notice by facsimile or five days after the agency sends it if the facsimile is undeliverable; or
(3) When delivered, if the Federal agency sends the notice by email or five days after the agency sends it if the email is undeliverable.
§ 180.730
What information must I provide to the suspending official if I contest the suspension?
(a) In addition to any information and argument in opposition, as a respondent, your submission to the suspending official must identify:
(1) Specific facts that contradict the statements contained in the Notice of Suspension. A general denial is insufficient to raise a genuine dispute over facts material to the suspension;
(2) All existing, proposed, or prior exclusions under regulations implementing Executive Order 12549 and all similar actions taken by Federal, State, or local agencies, including administrative agreements that affect only those agencies;
(3) All criminal and civil proceedings not included in the Notice of Suspension that grew out of facts relevant to the cause(s) stated in the notice; and
(4) All of your affiliates.
(b) Your submission must also identify any of the paragraphs in § 180.730(a) that do not apply to you.
(c) If you fail to disclose this information or provide false information, the Federal agency taking the action may seek further criminal, civil, or administrative action against you, as appropriate.
§ 180.735
Under what conditions do I get an additional opportunity to challenge the facts on which the suspension is based?
(a) As a respondent, you will not have an additional opportunity to challenge the facts if the suspending official determines that:
(1) Your suspension is based upon an indictment, conviction, civil judgment, or other findings by a Federal, State, or local body for which an opportunity to contest the facts was provided;
(2) Your presentation in opposition contains only general denials to the information contained in the Notice of Suspension;
(3) The issues raised in your presentation in opposition to the suspension are not factual in nature, or are not material to the suspending official's initial decision to suspend, or the official's decision whether to continue the suspension; or
(4) On the basis of advice from the Department of Justice, an office of the United States Attorney, a State attorney general's office, or a State or local prosecutor's office, that substantial interests of the government in pending or contemplated legal proceedings based on the same facts as the suspension would be prejudiced by conducting fact-finding.
(b) You will have an opportunity to challenge the facts if the suspending official determines that:
(1) The conditions in paragraph (a) of this section do not exist; and
(2) Your presentation in opposition raises a genuine dispute over facts material to the suspension.
(c) If you have an opportunity to challenge disputed material facts under this section, the suspending official or designee must conduct additional proceedings to resolve those facts.
§ 180.740
Are suspension proceedings formal?
(a) Suspension proceedings are conducted in a fair and informal manner. The suspending official may use flexible procedures to allow you to present matters in opposition. In so doing, the suspending official is not required to follow formal rules of evidence or procedure in creating an official record upon which the official will base a final suspension decision.
(b) As a respondent, you or your representative must submit any documentary evidence you want the suspending official to consider.
§ 180.745
How is fact-finding conducted?
(a) If fact-finding is conducted:
(1) You may present witnesses and other evidence and confront any witness presented; and
(2) The factfinder must prepare written findings of fact for the record.
(b) A transcribed record of fact-finding proceedings must be made, unless you, as a respondent, and the Federal agency agree to waive it in advance. If you want a copy of the transcribed record, you may purchase it.
§ 180.750
What does the suspending official consider in deciding whether to continue or terminate my suspension?
(a) The suspending official bases the decision on all information contained in the official record. The record includes:
(1) All information in support of the suspending official's initial decision to suspend you;
(2) Any further information and argument presented in support of, or opposition to, the suspension; and
(3) Any transcribed record of fact-finding proceedings.
(b) The suspending official may refer disputed material facts to another official for findings of fact. The suspending official may reject any resulting findings, in whole or in part, only after specifically determining them to be arbitrary, capricious, or clearly erroneous.
§ 180.755
When will I know whether the suspension is continued or terminated?
The suspending official must make a written decision whether to continue, modify, or terminate your suspension within 45 days of closing the official record. The official record closes upon the suspending official's receipt of final submissions, information, and findings of fact, if any. The suspending official may extend that period for good cause.
§ 180.760
How long may my suspension last?
(a) If legal or debarment proceedings are initiated at the time of or during your suspension, the suspension may continue until the conclusion of those proceedings. However, a suspension may not exceed 12 months if proceedings are not initiated.
(b) The suspending official may extend the 12-month limit under paragraph (a) of this section for an additional 6 months if an office of a U.S. Assistant Attorney General, U.S. Attorney, or other Federal, State, or local responsible prosecuting official requests an extension in writing. In no event may a suspension exceed 18 months without initiating proceedings under paragraph (a) of this section.
(c) The suspending official must notify the appropriate officials under paragraph (b) of this section of an impending termination of a suspension at least 30 days before the 12-month period expires to allow the officials an opportunity to request an extension.

Subpart H—Debarment
§ 180.800
What are the causes for debarment?
A Federal agency may debar a person for:
(a) Conviction of or civil judgment for:
(1) Commission of fraud or a criminal offense in connection with obtaining, attempting to obtain, or performing a public or private agreement or transaction;
(2) Violation of Federal or State antitrust statutes, including those proscribing price fixing between competitors, allocation of customers between competitors, and bid rigging;
(3) Commission of embezzlement, theft, forgery, bribery, falsification, or destruction of records, making false statements, violating Federal criminal tax laws, receiving stolen property, making false claims, or obstruction of justice; or
(4) Commission of any other offense indicating a lack of business integrity or business honesty that seriously and directly affects your present responsibility;
(b) Violation of the terms of a public agreement or transaction so serious as to affect the integrity of a Federal agency program, such as:
(1) A willful failure to perform in accordance with the terms of one or more public agreements or transactions;
(2) A history of failure to perform or of unsatisfactory performance of one or more public agreements or transactions; or
(3) A willful violation of a statutory or regulatory provision or requirement applicable to a public agreement or transaction;
(c) Any of the following causes:
(1) A nonprocurement debarment by any Federal agency taken before October 1, 1988, or a procurement debarment by any Federal agency taken pursuant to 48 CFR part 9, subpart 9.4, before August 25, 1995;
(2) Knowingly doing business with an ineligible person, except as permitted under § 180.135;
(3) Failure to pay a single substantial debt, or a number of outstanding debts (including disallowed costs and overpayments, but not including sums owed the Federal Government under the Internal Revenue Code) owed to any Federal agency or instrumentality, provided the debt is uncontested by the debtor or, if contested, provided that the debtor's legal and administrative remedies have been exhausted;
(4) Violation of a material provision of a voluntary exclusion agreement entered into under § 180.640 or of any other agreement that resolves a debarment or suspension action; or
(5) Violation of the provisions of the Drug-Free Workplace Act of 1988 (41 U.S.C. 701); or
(d) Any other cause that is so serious or compelling in nature that it affects your present responsibility.
§ 180.805
What notice does the debarring official give me if I am proposed for debarment?
After consideration of the causes in § 180.800, if the debarring official proposes to debar you, the official sends you a Notice of Proposed Debarment, pursuant to § 180.615, advising you:
(a) That the debarring official is considering debarring you;
(b) The reasons for proposing to debar you in terms sufficient to put you on notice of the conduct or transactions upon which the proposed debarment is based;
(c) The cause(s) under § 180.800 upon which the debarring official relied for proposing your debarment;
(d) The applicable provisions of this subpart, subpart F of this part, and any other Federal agency procedures governing debarment; and
(e) The government-wide effect of a debarment from procurement and nonprocurement programs and activities.
§ 180.810
When does a debarment take effect?
Unlike a suspension, a debarment is not effective until the debarring official issues a decision. The debarring official does not issue a decision until the respondent has had an opportunity to contest the proposed debarment.
§ 180.815
How may I contest a proposed debarment?
As a respondent, if you wish to contest a proposed debarment, you or your representative must provide the debarring official with information in opposition to the proposed debarment. You may do this orally or in writing. While oral statements may be a part of the official record, any information provided orally that you consider important must also be submitted in writing for the official record.
§ 180.820
How much time do I have to contest a proposed debarment?
(a) As a respondent, you or your representative must either send or make arrangements to appear and present the information and argument to the debarring official within 30 days after you receive the Notice of Proposed Debarment.
(b) The Federal agency taking the action considers the Notice of Proposed Debarment to be received by you:
(1) When delivered, if the Federal agency mails the notice to the last known street address, or five days after the agency sends it if the letter is undeliverable;
(2) When sent, if the Federal agency sends the notice by facsimile or five days after the agency sends it if the facsimile is undeliverable; or
(3) When delivered, if the Federal agency sends the notice by email or five days after the agency sends it if the email is undeliverable.
§ 180.825
What information must I provide to the debarring official if I contest the proposed debarment?
(a) In addition to any information and argument in opposition, as a respondent, your submission to the debarring official must identify:
(1) Specific facts that contradict the statements contained in the Notice of Proposed Debarment. Include any information about any of the factors listed in § 180.860. A general denial is insufficient to raise a genuine dispute over facts material to the debarment;
(2) All existing, proposed, or prior exclusions under regulations implementing Executive Order 12549 and all similar actions taken by Federal, State, or local agencies, including administrative agreements that affect only those agencies;
(3) All criminal and civil proceedings not included in the Notice of Proposed Debarment that grew out of facts relevant to the cause(s) stated in the notice; and
(4) All of your affiliates.
(b) If you fail to disclose this information or provide false information, the Federal agency taking the action may seek further criminal, civil, or administrative action against you, as appropriate.
§ 180.830
Under what conditions do I get an additional opportunity to challenge the facts on which the proposed debarment is based?
(a) As a respondent, you will not have an additional opportunity to challenge the facts if the debarring official determines that:
(1) Your debarment is based upon a conviction or civil judgment;
(2) Your presentation in opposition contains only general denials to the information contained in the Notice of Proposed Debarment; or
(3) The issues raised in your presentation in opposition to the proposed debarment are not factual in nature, or are not material to the debarring official's decision whether to debar.
(b) You will have an additional opportunity to challenge the facts if the debarring official determines that:
(1) The conditions in paragraph (a) of this section do not exist; and
(2) Your presentation in opposition raises a genuine dispute over facts material to the proposed debarment.
(c) If you have an opportunity to challenge disputed material facts under this section, the debarring official or designee must conduct additional proceedings to resolve those facts.
§ 180.835
Are debarment proceedings formal?
(a) Debarment proceedings are conducted in a fair and informal manner. The debarring official may use flexible procedures to allow you, as a respondent, to present matters in opposition. In so doing, the debarring official is not required to follow formal rules of evidence or procedure in creating an official record upon which the official will base the decision on whether to debar.
(b) You or your representative must submit any documentary evidence you want the debarring official to consider.
§ 180.840
How is fact-finding conducted?
(a) If fact-finding is conducted:
(1) You may present witnesses and other evidence and confront any witness presented; and
(2) The factfinder must prepare written findings of fact for the record.
(b) A transcribed record of fact-finding proceedings must be made unless you, as a respondent, and the Federal agency agree to waive it in advance. If you want a copy of the transcribed record, you may purchase it.
§ 180.845
What does the debarring official consider in deciding whether to debar me?
(a) The debarring official may debar you for any of the causes in § 180.800. However, the official need not debar you even if a cause for debarment exists. The official may consider the seriousness of your acts or omissions and the mitigating or aggravating factors set forth at § 180.860.
(b) The debarring official bases the decision on all information contained in the official record. The record includes:
(1) All information in support of the debarring official's proposed debarment;
(2) Any further information and argument presented in support of, or in opposition to, the proposed debarment; and
(3) Any transcribed record of fact-finding proceedings.
(c) The debarring official may refer disputed material facts to another official for findings of fact. The debarring official may reject any resultant findings, in whole or in part, only after specifically determining them to be arbitrary, capricious, or clearly erroneous.
§ 180.850
What is the standard of proof in a debarment action?
(a) In any debarment action, the Federal agency must establish the cause for debarment by a preponderance of the evidence.
(b) If the proposed debarment is based upon a conviction or civil judgment, the standard of proof is met.
§ 180.855
Who has the burden of proof in a debarment action?
(a) The Federal agency has the burden to prove that a cause for debarment exists.
(b) Once a cause for debarment is established, you as a respondent have the burden of demonstrating to the satisfaction of the debarring official that you are presently responsible and that debarment is not necessary.
§ 180.860
What factors may influence the debarring official's decision?
This section lists the mitigating and aggravating factors that the debarring official may consider in determining whether to debar you and the length of your debarment period. The debarring official may consider other factors if appropriate in light of the circumstances of a particular case. The existence or nonexistence of any factor, such as one of those set forth in this section, is not necessarily determinative of your present responsibility. In making a debarment decision, the debarring official may consider the following factors:
(a) The actual or potential harm or impact that results or may result from the wrongdoing.
(b) The frequency of incidents or duration of the wrongdoing.
(c) Whether there is a pattern or prior history of wrongdoing. For example, if you have been found by another Federal agency or a State agency to have engaged in wrongdoing similar to that found in the debarment action, the existence of this fact may be used by the debarring official in determining that you have a pattern or prior history of wrongdoing.
(d) Whether you are or have been excluded or disqualified by an agency of the Federal Government or have not been allowed to participate in State or local contracts or assistance agreements on a basis of conduct similar to one or more of the causes for debarment specified in this part.
(e) Whether you have entered into an administrative agreement with a Federal agency or a State or local government that is not government-wide but is based on conduct similar to one or more of the causes for debarment specified in this part.
(f) Whether and to what extent you planned, initiated, or carried out the wrongdoing.
(g) Whether you have accepted responsibility for the wrongdoing and recognize the seriousness of the misconduct that led to the cause for debarment.
(h) Whether you have paid or agreed to pay all criminal, civil, and administrative liabilities for the improper activity, including any investigative or administrative costs incurred by the government, and have made or agreed to make full restitution.
(i) Whether you have cooperated fully with the government agencies during the investigation and any court or administrative action. In determining the extent of cooperation, the debarring official may consider when the cooperation began and whether you disclosed all pertinent information known to you.
(j) Whether the wrongdoing was pervasive within your organization.
(k) The kind of positions held by the individuals involved in the wrongdoing.
(l) Whether your organization took appropriate corrective action or implemented remedial or protective measures in the form of procedures, policies, and programs to effectively address the activity cited as a basis for the debarment.
(m) Whether your principals tolerated the offense.
(n) Whether you brought the activity cited as a basis for the debarment to the attention of the appropriate government agency in a timely manner.
(o) Whether you have fully investigated the circumstances surrounding the cause for debarment and, if so, made the result of the investigation available to the debarring official.
(p) Whether you had effective standards of conduct and internal control systems in place at the time the questioned conduct occurred.
(q) Whether you have taken appropriate disciplinary action against the individuals responsible for the activity which constitutes the cause for debarment.
(r) Whether you have had adequate time to eliminate the circumstances within your organization that led to the cause for the debarment.
(s) Whether your business, technical, or professional license(s) has been suspended, terminated, or revoked.
(t) Other factors that are appropriate to the circumstances of a particular case.
§ 180.865
How long may my debarment last?
(a) If the debarring official decides to debar you, your period of debarment will be based on the seriousness of the cause(s) upon which your debarment is based. Generally, debarment should not exceed three years. However, if circumstances warrant, the debarring official may impose a longer period of debarment.
(b) In determining the period of debarment, the debarring official may consider the factors in § 180.860. If a suspension has preceded your debarment, the debarring official must consider the time you were suspended.
(c) If the debarment is for a violation of the provisions of the Drug-Free Workplace Act of 1988, your period of debarment may not exceed five years.
§ 180.870
When do I know if the debarring official debars me?
(a) The debarring official must make a written decision whether to debar within 45 days of closing the official record. The official record closes upon the debarring official's receipt of final submissions, information, and findings of fact, if any. The debarring official may extend that period for good cause.
(b) The debarring official sends you written notice, pursuant to § 180.615, that the official decided either:
(1) Not to debar you; or
(2) To debar you. In this event, the notice:
(i) Refers to the Notice of Proposed Debarment;
(ii) Specifies the reasons for your debarment;
(iii) States the period of your debarment, including the effective dates; and
(iv) Advises you that your debarment is effective for covered transactions and contracts that are subject to the Federal Acquisition Regulations (48 CFR chapter 1) throughout the executive branch of the Federal Government unless an agency head or an authorized designee grants an exception.
§ 180.875
May I ask the debarring official to reconsider a decision to debar me?
Yes. As a debarred person, you may ask the debarring official to reconsider the debarment decision or to reduce the time period or scope of the debarment. However, you must submit your request in writing and support it with documentation.
§ 180.880
What factors may influence the debarring official during reconsideration?
The debarring official may reduce or terminate your debarment based on:
(a) Newly discovered material evidence;
(b) A reversal of the conviction or civil judgment upon which your debarment was based;
(c) A bona fide change in ownership or management;
(d) Elimination of other causes for which the debarment was imposed; or
(e) Other reasons the debarring official finds appropriate.
§ 180.885
May the debarring official extend a debarment?
(a) Yes. The debarring official may extend a debarment for an additional period if that official determines that an extension is necessary to protect the public interest.
(b) However, the debarring official may not extend a debarment solely on the basis of the facts and circumstances upon which the initial debarment action was based.
(c) If the debarring official decides that a debarment for an additional period is necessary, the debarring official must follow the applicable procedures in this subpart, and subpart F, to extend the debarment.

Subpart I—Definitions
§ 180.900
Adequate evidence.
Adequate evidence means information sufficient to support the reasonable belief that a particular act or omission has occurred.
§ 180.905
Affiliate.
Persons are affiliates of each other if, directly or indirectly, either one controls or has the power to control the other or a third person controls or has the power to control both. The ways a Federal agency may determine control include, but are not limited to:
(a) Interlocking management or ownership;
(b) Identity of interests among family members;
(c) Shared facilities and equipment;
(d) Common use of employees; or
(e) A business entity organized following the exclusion of a person with the same or similar management, ownership, or principal employees as the excluded person.
§ 180.910
Agent or representative.
Agent or representative means any person who acts on behalf of or who is authorized to commit a participant in a covered transaction.
§ 180.915
Civil judgment.
Civil judgment means the disposition of a civil action by any court of competent jurisdiction, whether by verdict, decision, settlement, stipulation, or other disposition which creates a civil liability for the complained of wrongful acts or a final determination of liability under the Program Fraud Civil Remedies Act of 1986 (31 U.S.C. 3801-3812).
§ 180.920
Conviction.
Conviction means:
(a) A judgment or any other determination of guilt of a criminal offense by any court of competent jurisdiction, whether entered upon a verdict or plea, including a plea of nolo contendere; or
(b) Any other resolution that is the functional equivalent of a judgment, including probation before judgment and deferred prosecution. A disposition without the participation of the court is the functional equivalent of a judgment only if it includes an admission of guilt.
§ 180.925
Debarment.
Debarment means an action taken by a debarring official under subpart H of this part to exclude a person from participating in covered transactions and transactions covered under the Federal Acquisition Regulations (48 CFR chapter 1). A person so excluded is debarred.
§ 180.930
Debarring official.
Debarring official means a Federal agency official who is authorized to impose debarment. A debarring official is either:
(a) The agency head; or
(b) An official designated by the agency head.
§ 180.935
Disqualified.
Disqualified means that a person is prohibited from participating in specified Federal procurement or nonprocurement transactions as required under a statute, Executive order (other than Executive Orders 12549 and 12689), or other authority. Examples of disqualifications include persons prohibited under—
(a) The Davis-Bacon Act (40 U.S.C. 3142);
(b) The equal employment opportunity acts and Executive orders; or
(c) The Clean Air Act (42 U.S.C. 7606), Clean Water Act (33 U.S.C. 1368), and Executive Order 11738 (38 FR 25161).
§ 180.940
Excluded or exclusion.
Excluded or exclusion means:
(a) That a person or commodity is prohibited from being a participant in covered transactions, whether the person has been suspended; debarred; proposed for debarment under 48 CFR part 9, subpart 9.4; voluntarily excluded; or
(b) The act of excluding a person.
§ 180.945
System for Award Management (SAM.gov) Exclusions.
System for Award Management (SAM.gov) Exclusions means the list maintained and disseminated by the General Services Administration (GSA) containing the names and other information about ineligible persons.
§ 180.950
Federal agency.
Federal agency means any United States executive department, military department, defense agency, or any other executive branch agency. For the purposes of this part, other agencies of the Federal Government are not considered “agencies” unless they issue regulations adopting the government-wide Debarment and Suspension system under Executive Orders 12549 and 12689.
§ 180.955
Indictment.
Indictment means an indictment for a criminal offense. A presentment, information, or other filing by a competent authority charging a criminal offense will be given the same effect as an indictment.
§ 180.960
Ineligible or ineligibility.
Ineligible or ineligibility means that a person or commodity is prohibited from covered transactions because of an exclusion or disqualification.
§ 180.965
Legal proceedings.
Legal proceeding means any criminal proceeding or any civil judicial proceeding, including a proceeding under the Program Fraud Civil Remedies Act of 1986 (31 U.S.C. 3801- 3812), to which the Federal Government or a State or local government or quasi-governmental authority is a party. The term also includes appeals from those proceedings.
§ 180.970
Nonprocurement transaction.
(a) Nonprocurement transaction means any transaction, regardless of type (except procurement contracts), including, but not limited to, the following:
(1) Grants;
(2) Cooperative agreements;
(3) Scholarships;
(4) Fellowships;
(5) Contracts of assistance;
(6) Loans;
(7) Loan guarantees;
(8) Subsidies;
(9) Insurances;
(10) Payments for specified uses; and
(11) Donation agreements.
(b) A nonprocurement transaction at any tier does not require the transfer of Federal funds.
§ 180.975
Notice.
Notice means a written communication served in person, sent by certified mail or its equivalent, or sent electronically by email or facsimile. (See § 180.615.)
§ 180.980
Participant.
Participant means any person who submits a proposal for or enters into a covered transaction, including an agent or representative of a participant.
§ 180.985
Person.
Person means any individual, corporation, partnership, association, unit of government, or legal entity, regardless of how organized.
§ 180.990
Preponderance of the evidence.
Preponderance of the evidence means proof by information that, compared with information opposing it, leads to the conclusion that the fact at issue is more probably true than not.
§ 180.995
Principal.
Principal means:
(a) An officer, director, owner, partner, principal investigator, or another person within a participant with management or supervisory responsibilities related to a covered transaction; or
(b) A consultant or other person, whether or not employed by the participant or paid with Federal funds, who:
(1) Is in a position to handle Federal funds;
(2) Is in a position to influence or control the use of those funds; or,
(3) Occupies a technical or professional position capable of substantially influencing the development or outcome of an activity required to perform the covered transaction.
§ 180.1000
Respondent.
Respondent means a person against whom a Federal agency has initiated a debarment or suspension action.
§ 180.1005
State.
(a) State means:
(1) Any of the states of the United States;
(2) The District of Columbia;
(3) The Commonwealth of Puerto Rico;
(4) Any territory or possession of the United States; or
(5) Any agency or instrumentality of a State.
(b) For purposes of this part, State does not include institutions of higher education, hospitals, or units of local government.
§ 180.1010
Suspending official.
(a) Suspending official means a Federal agency official authorized to impose suspension. The suspending official is either:
(1) The agency head; or
(2) An official designated by the agency head.
§ 180.1015
Suspension.
Suspension is an action taken by a suspending official under subpart G of this part that immediately prohibits a person from participating in covered transactions and transactions covered under the Federal Acquisition Regulations (48 CFR chapter 1) for a temporary period, pending completion of a Federal agency investigation and any judicial or administrative proceedings that may ensue. A person so excluded is suspended.
§ 180.1020
Voluntary exclusion or voluntarily excluded.
(a) Voluntary exclusion means a person's agreement to be excluded under the terms of a settlement between the person and one or more agencies. Voluntary exclusion must have a government-wide effect.
(b) Voluntarily excluded means the status of a person who has agreed to a voluntary exclusion.

Appendix A to Part 180—Covered Transactions
9. Revise part 182 to read as follows:

PART 182—GOVERNMENT-WIDE REQUIREMENTS FOR DRUG-FREE WORKPLACE (FINANCIAL ASSISTANCE)
Sec.
182.5
What does this part do?
182.10
How is this part organized?
182.15
To whom does the guidance apply?
182.20
What must a Federal agency do to implement the guidance?
182.25
What must a Federal agency address in its implementation of the guidance?
182.30
Where does a Federal agency implement the guidance?
182.40
How is the guidance maintained?

Subpart A—Purpose and Coverage
182.100
How is this part written?
182.105
Do terms in this part have special meanings?
182.110
What do subparts A through F of this part do?
182.115
Does this part apply to me?
182.120
Are any of my Federal assistance awards exempt from this part?
182.125
Does this part affect the Federal contracts that I receive?

Subpart B—Requirements for Recipients Other Than Individuals
182.200
What must I do to comply with this part?
182.205
What must I include in my drug-free workplace statement?
182.210
To whom must I distribute my drug-free workplace statement?
182.215
What must I include in my drug-free awareness program?
182.220
By when must I publish my drug-free workplace statement and establish my drug-free awareness program?
182.225
What actions must I take concerning employees who are convicted of drug violations in the workplace?
182.230
How and when must I identify workplaces?

Subpart C—Requirements for Recipients Who Are Individuals
182.300
What must I do to comply with this part if I am an individual recipient?

Subpart D—Responsibilities of Agency Awarding Officials
182.400
What are my responsibilities as an agency awarding official?

Subpart E—Violations of This Part and Consequences
182.500
How are violations of this part determined for recipients other than individuals?
182.505
How are violations of this part determined for recipients who are individuals?
182.510
What actions will the Federal Government take against a recipient determined to have violated this part?
182.515
Are there any exceptions to those actions?

Subpart F—Definitions
182.605
Award.
182.610
Controlled substance.
182.615
Conviction.
182.620
Cooperative agreement.
182.625
Criminal drug statute.
182.630
Debarment.
182.635
Drug-free workplace.
182.640
Employee.
182.645
Federal agency or agency.
182.650
Grant.
182.655
Individual.
182.660
Recipient.
182.665
State.
182.670
Suspension.

Authority:
41 U.S.C. 8101-8106; 31 U.S.C. 503; 31 U.S.C. 6307.
§ 182.5
What does this part do?
This part provides guidance for Federal agencies on the portion of the Drug-Free Workplace Act of 1988 (41 U.S.C. 8101-8106, as amended) that applies to grants. It also applies the provisions of the Act to cooperative agreements and other financial assistance awards, as a matter of Federal Government policy.
§ 182.10
How is this part organized?
This part is organized into two segments.
(a) Sections 182.5 through 182.40 contain general policy direction for Federal agencies' use of the uniform policies and procedures in subparts A through F.
(b) Subparts A through F contain uniform government-wide policies and procedures for Federal agency use to specify the:
(1) Types of awards that are covered by drug-free workplace requirements;
(2) Drug-free workplace requirements with which a recipient must comply;
(3) Actions required of a Federal agency awarding official; and
(4) Consequences of a violation of drug-free workplace requirements.
§ 182.15
To whom does the guidance apply?
This part provides guidance to Federal agencies. Publication of this guidance in the Code of Federal Regulations (CFR) does not change its nature—it is guidance and not regulation. Federal agencies' implementation of this guidance governs the rights and responsibilities of other persons affected by the drug-free workplace requirements.
§ 182.20
What must a Federal agency do to implement the guidance?
To comply with the requirement in 41 U.S.C. 8106 for government-wide regulations, each Federal agency that awards grants or cooperative agreements or makes other financial assistance awards that are subject to the drug-free workplace requirements in subparts A through F of the guidance must issue a regulation consistent with those subparts.
§ 182.25
What must a Federal agency address in its implementation of the guidance?
Each Federal agency's implementing regulation:
(a) Must establish drug-free workplace policies and procedures for that Federal agency's Federal awards consistent with this guidance. When adopted by a Federal agency, the provisions of the guidance have a regulatory effect on that Federal agency's awards.
(b) Must address some matters for which the guidance in this part gives the Federal agency discretion. Specifically, the regulation must:
(1) State whether the Federal agency:
(i) Has a central point to which a recipient may send the notification of a conviction that is required under § 182.225(a) or § 182.300(b); or
(ii) Requires the recipient to send the notification to the Federal agency awarding official or their designee for each Federal award.
(2) Either:
(i) State that the Federal agency head is the official authorized to determine under § 182.500 or § 182.505 that a recipient has violated the drug-free workplace requirements; or
(ii) Provide the title of the official designated to make that determination.
(c) May also, at the Federal agency's option, identify any specific types of financial assistance awards, in addition to grants and cooperative agreements, to which the Federal agency makes this guidance applicable.
§ 182.30
Where does a Federal agency implement the guidance?
Each Federal agency that awards grants or cooperative agreements or makes other financial assistance awards that are subject to the drug-free workplace guidance in this part must issue a regulation implementing the guidance within its chapter in subtitle B of this title of the Code of Federal Regulations.
§ 182.40
How is the guidance maintained?
The OMB publishes proposed changes to the guidance in the Federal Register for public comment, considers comments with the help of appropriate interagency working groups, and then issues any changes to the guidance in final form.

Subpart A—Purpose and Coverage
§ 182.100
How is this part written?
(a) This part uses a “plain language” format to make it easier for the general public and business community to use and understand. The section headings and text must be read together, as they are often in the form of questions and answers.
(b) Pronouns used within this part, such as “I” and “you,” change from subpart to subpart depending on the audience being addressed.
§ 182.105
Do terms in this part have special meanings?
This part uses terms that have special meanings. Those terms are defined in subpart F.
§ 182.110
What do subparts A through F of this part do?
Subparts A through F specify standard policies and procedures to carry out the Drug-Free Workplace Act of 1988 for financial assistance awards.
§ 182.115
Does this part apply to me?
(a) Portions of this part apply to you if you are either:
(1) A recipient of a Federal assistance award (see definitions of award and recipient in §§ 182.605 and 182.660, respectively); or
(2) A Federal agency awarding official.
(b) The following table shows the subparts that apply to you:
If you are * * * | See subparts * * *
(1) a recipient who is not an individual | A, B and E.
(2) a recipient who is an individual | A, C and E.
(3) a Federal agency awarding official | A, D and E.
§ 182.120
Are any of my Federal assistance awards exempt from this part?
This part does not apply to any award to which the Federal agency head, or their designee, determines that the application of this part would be inconsistent with the international obligations of the United States or the laws or regulations of a foreign government.
§ 182.125
Does this part affect the Federal contracts that I receive?
This part will affect future contract awards indirectly if you are debarred or suspended for a violation of the requirements of this part, as described in § 182.510(c). However, this part does not apply directly to procurement contracts. The portion of the Drug-Free Workplace Act of 1988 that applies to Federal procurement contracts is carried out through the Federal Acquisition Regulation in Chapter 1 of Title 48 of the Code of Federal Regulations (the drug-free workplace coverage currently is in 48 CFR part 23, subpart 23.5).

Subpart B—Requirements for Recipients Other Than Individuals
§ 182.200
What must I do to comply with this part?
There are two general requirements if you are a recipient other than an individual.
(a) First, you must make a good faith effort, on a continuing basis, to maintain a drug-free workplace. You must agree to do so as a condition for receiving any award covered by this part. The specific measures that you must take in this regard are described in more detail in subsequent sections of this subpart. Briefly, those measures are to:
(1) Publish a drug-free workplace statement and establish a drug-free awareness program for your employees (see §§ 182.205 through 182.220); and
(2) Take actions concerning employees convicted of violating drug statutes in the workplace (see § 182.225).
(b) Second, you must identify all known workplaces under your Federal awards (see § 182.230).
§ 182.205
What must I include in my drug-free workplace statement?
You must publish a statement that—
(a) Tells your employees that the unlawful manufacture, distribution, dispensing, possession, or use of a controlled substance is prohibited in your workplace;
(b) Specifies the actions that you will take against employees for violating that prohibition; and
(c) Lets each employee know that, as a condition of employment under any award, the employee:
(1) Will abide by the terms of the statement; and
(2) Must notify you in writing if the employee is convicted for a violation of a criminal drug statute occurring in the workplace and must do so no more than five calendar days after the conviction.
§ 182.210
To whom must I distribute my drug-free workplace statement?
You must require that a copy of the statement described in § 182.205 be given to each employee who will be engaged in the performance of any Federal award.
§ 182.215
What must I include in my drug-free awareness program?
You must establish an ongoing drug-free awareness program to inform employees about:
(a) The dangers of drug abuse in the workplace;
(b) Your policy of maintaining a drug-free workplace;
(c) Any available drug counseling, rehabilitation, and employee assistance programs; and
(d) The penalties that you may impose upon them for drug abuse violations occurring in the workplace.
§ 182.220
By when must I publish my drug-free workplace statement and establish my drug-free awareness program?
If you are a new recipient that does not already have a policy statement as described in § 182.205 and an ongoing awareness program as described in § 182.215, you must publish the statement and establish the program by the time given in the following table:
If * * * | Then you * * *
(a) The performance period of the award is less than 30 days | Must have the policy statement and program in place as soon as possible, but before the date on which performance is expected to be completed.
(b) The performance period of the award is 30 days or more | Must have the policy statement and program in place within 30 days after award.
(c) You believe there are extraordinary circumstances that will require more than 30 days for you to publish the policy statement and establish the awareness program | May ask the Federal agency awarding official to give you more time to do so. The amount of additional time, if any, to be given is at the discretion of the Federal agency awarding official.
§ 182.225
What actions must I take concerning employees who are convicted of drug violations in the workplace?
There are two actions you must take if an employee is convicted of a drug violation in the workplace:
(a) First, you must notify Federal agencies if an employee who is engaged in the performance of an award informs you about a conviction, as required by § 182.205(c)(2), or you otherwise learn of the conviction. Your notification to the Federal agencies must:
(1) Be in writing;
(2) Include the employee's position title;
(3) Include the identification number(s) of each affected award;
(4) Be sent within ten calendar days after you learn of the conviction; and
(5) Be sent to every Federal agency on whose award the convicted employee was working. It must be sent to every Federal agency awarding official or their designee, unless the Federal agency has specified a central point for the receipt of the notices.
(b) Second, within 30 calendar days of learning about an employee's conviction, you must either:
(1) Take appropriate personnel action against the employee, up to and including termination, consistent with the requirements of the Rehabilitation Act of 1973 (29 U.S.C. 794), as amended; or
(2) Require the employee to participate satisfactorily in a drug abuse assistance or rehabilitation program approved for these purposes by a Federal, State, or local health, law enforcement, or another appropriate agency.
§ 182.230
How and when must I identify workplaces?
(a) You must identify all known workplaces under each Federal agency award. A failure to do so is a violation of your drug-free workplace requirements. You may identify the workplaces:
(1) To the Federal agency awarding official that is making the Federal award, either at the time of application or upon award; or
(2) In documents that you keep on file in your offices during the performance of the Federal award, in which case you must make the information available for inspection upon request by agency officials or their designated representatives.
(b) Your workplace identification for a Federal award must include the actual address of buildings (or parts of buildings) or other sites where work under the award takes place. Categorical descriptions may be used (for example, all vehicles of a mass transit authority or State highway department while in operation, State employees in each local unemployment office, performers in concert halls or radio studios).
(c) If you identified workplaces to the Federal agency awarding official at the time of application or award, as described in paragraph (a)(1) of this section, and any workplace that you identified changes during the performance of the Federal award, you must inform the Federal agency awarding official.

Subpart C—Requirements for Recipients Who Are Individuals
§ 182.300
What must I do to comply with this part if I am an individual recipient?
As a condition of receiving a Federal award, if you are an individual recipient, you must agree that:
(a) You will not engage in the unlawful manufacture, distribution, dispensing, possession, or use of a controlled substance in conducting any activity related to the Federal award; and
(b) If you are convicted of a criminal drug offense resulting from a violation occurring during the conduct of any Federal award activity, you will report the conviction:
(1) In writing.
(2) Within 10 calendar days of the conviction.
(3) To the Federal agency awarding official or their designee for each Federal award that you currently have, unless the agency designates a central point for the receipt of the notices, either in the award document or its regulation implementing the guidance in this part. When notice is made to a central point, it must include the identification number(s) of each affected Federal award.

Subpart D—Responsibilities of Federal Agency Awarding Officials
§ 182.400
What are my responsibilities as a Federal agency awarding official?
As a Federal agency awarding official, you must obtain each recipient's agreement, as a condition of the award, to comply with the requirements in:
(a) Subpart B of this part, if the recipient is not an individual; or
(b) Subpart C of this part, if the recipient is an individual.

Subpart E—Violations of This Part and Consequences
§ 182.500
How are violations of this part determined for recipients other than individuals?
A recipient other than an individual is in violation of the requirements of this part if the Federal agency head or their designee determines, in writing, that:
(a) The recipient has violated the requirements of subpart B; or
(b) The number of convictions of the recipient's employees for violating criminal drug statutes in the workplace is large enough to indicate that the recipient has failed to make a good-faith effort to provide a drug-free workplace.
§ 182.505
How are violations of this part determined for recipients who are individuals?
A recipient who is an individual is in violation of the requirements of this part if the Federal agency head or their designee determines, in writing, that:
(a) The recipient has violated the requirements of subpart C of this part; or
(b) The recipient is convicted of a criminal drug offense resulting from a violation occurring during the conduct of any award activity.
§ 182.510
What actions will the Federal Government take against a recipient determined to have violated this part?
If a recipient is determined to have violated this part, as described in § 182.500 or § 182.505, the Federal agency may take one or more of the following actions:
(a) Suspension of payments under the award;
(b) Suspension or termination of the award; and
(c) Suspension or debarment of the recipient under the Federal agency's regulation implementing the OMB guidance on nonprocurement debarment and suspension (2 CFR part 180) for a period not to exceed five years.
§ 182.515
Are there any exceptions to those actions?
For a particular award, the Federal agency head may waive, in writing, a suspension of payments under an award, suspension or termination of an award, or suspension or debarment of a recipient if the agency head determines that such a waiver would be in the public interest. This exception authority cannot be delegated to any other official.

Subpart F—Definitions
§ 182.605
Award.
Award means an award of financial assistance by a Federal agency directly to a recipient.
(a) The term award includes:
(1) A Federal grant or cooperative agreement, in the form of money or property in lieu of money.
(2) A block grant or a grant in an entitlement program, whether or not the grant is exempted from coverage under the government-wide rule that implements OMB Circular A-102 (for availability of OMB circulars, see 5 CFR 1310.3) and specifies uniform administrative requirements.
(b) The term award does not include:
(1) Technical assistance that provides services instead of money.
(2) Loans.
(3) Loan guarantees.
(4) Interest subsidies.
(5) Insurance.
(6) Direct appropriations.
(7) Veterans' benefits to individuals (that is, any benefit to veterans, their families, or survivors by virtue of the service of a veteran in the Armed Forces of the United States).
§ 182.610
Controlled substance.
Controlled substance means a controlled substance in schedules I through V of the Controlled Substances Act (21 U.S.C. 812), and as further defined by regulation at 21 CFR 1308.11 through 1308.15.
§ 182.615
Conviction.
Conviction means a finding of guilt (including a plea of nolo contendere) or imposition of sentence, or both, by any judicial body charged with the responsibility to determine violations of the Federal or State criminal drug statutes.
§ 182.620
Cooperative agreement.
Cooperative agreement means an award of financial assistance that, consistent with 31 U.S.C. 6305, is used to enter into the same kind of relationship as a grant (see definition of grant in § 182.650), except that substantial involvement is expected between the Federal agency and the recipient when carrying out the activity contemplated by the award. The term does not include cooperative research and development agreements as defined in 15 U.S.C. 3710a.
§ 182.625
Criminal drug statute.
Criminal drug statute means a Federal or non-Federal criminal statute involving the manufacture, distribution, dispensing, use, or possession of any controlled substance.
§ 182.630
Debarment.
Debarment means an action taken by a Federal agency to prohibit a recipient from participating in Federal Government procurement contracts and covered nonprocurement transactions. A recipient so prohibited is debarred, in accordance with the Federal Acquisition Regulation for procurement contracts (48 CFR part 9, subpart 9.4) and Federal agency regulations implementing the OMB guidance on nonprocurement debarment and suspension (2 CFR part 180, which implements Executive Orders 12549 and 12689).
§ 182.635
Drug-free workplace.
Drug-free workplace means a site for the performance of work done in connection with a specific award at which employees of the recipient are prohibited from engaging in the unlawful manufacture, distribution, dispensing, possession, or use of a controlled substance.
§ 182.640
Employee.
(a) Employee means the employee of a recipient directly engaged in the performance of work under the award, including:
(1) All direct charge employees;
(2) All indirect charge employees, unless their impact or involvement in the performance of work under the award is insignificant to the performance of the award; and
(3) Temporary personnel and consultants who are directly engaged in the performance of work under the award and who are on the recipient's payroll.
(b) This definition does not include workers not on the payroll of the recipient (for example, volunteers, even if used to meet a cost sharing requirement; consultants or independent contractors not on the payroll; or employees of subrecipients or subcontractors in covered workplaces).
§ 182.645
Federal agency or agency.
Federal agency or agency means any United States executive department, military department, government corporation, government-controlled corporation, any other establishment in the executive branch (including the Executive Office of the President), or any independent regulatory agency.
§ 182.650
Grant.
Grant means an award of financial assistance that, consistent with 31 U.S.C. 6304, is used to enter into a relationship:
(a) The principal purpose of which is to transfer a thing of value to the recipient to carry out a public purpose of support or stimulation authorized by a law of the United States rather than to acquire property or services for the Federal Government's direct benefit or use; and
(b) In which substantial involvement is not expected between the Federal agency and the recipient when carrying out the activity contemplated by the award.
§ 182.655
Individual.
Individual means a natural person.
§ 182.660
Recipient.
Recipient means any individual, corporation, partnership, association, unit of government (except a Federal agency), or legal entity, regardless of how it is organized, that receives an award directly from a Federal agency.
§ 182.665
State.
State means any of the States of the United States, the District of Columbia, the Commonwealth of Puerto Rico, or any territory or possession of the United States.
§ 182.670
Suspension.
Suspension means an action taken by a Federal agency that immediately prohibits a recipient from participating in Federal Government procurement contracts and covered nonprocurement transactions for a temporary period, pending completion of an investigation and any judicial or administrative proceedings that may ensue. A recipient so prohibited is suspended in accordance with the Federal Acquisition Regulation for procurement contracts (48 CFR part 9, subpart 9.4) and Federal agency regulations implementing the OMB guidance on nonprocurement debarment and suspension (2 CFR part 180, which implements Executive Orders 12549 and 12689). Suspension of a recipient is a distinct and separate action from suspension of an award or suspension of payments under an award.
10. Revise part 183 to read as follows:

PART 183—NEVER CONTRACT WITH THE ENEMY
Sec.
183.5
Purpose of this part.
183.10
Applicability.
183.15
Responsibilities of Federal agencies.
183.20
Reporting responsibilities of Federal agencies.
183.25
Responsibilities of recipients.
183.30
Access to records.
183.35
Definitions.
Appendix A to Part 183
183.35
Award Terms for Never Contract with the Enemy

Authority:
Pub. L. 113-291, as amended by Pub. L. 115-232, Pub. L. 116-92, Pub. L. 116-283, Pub. L. 117-263; 31 U.S.C. 503; 31 U.S.C. 6307.
§ 183.5
Purpose of this part.
This part provides guidance to Federal agencies on the implementation of the Never Contract with the Enemy requirements applicable to certain grants and cooperative agreements, as specified in subtitle E, title VIII of the National Defense Authorization Act (NDAA) for Fiscal Year (FY) 2015 (Pub. L. 113-291), as amended by Sec. 820 of the National Defense Authorization Act for Fiscal Year 2023 (Pub. L. 117-263), hereafter cited as “Never Contract with the Enemy”).
§ 183.10
Applicability.
(a) This part applies only to grants and cooperative agreements that are expected to exceed $50,000 and that are performed outside the United States, including U.S. territories, and that are in support of a contingency operation in which members of the Armed Forces are actively engaged in hostilities. It does not apply to the authorized intelligence or law enforcement activities of the Federal Government.
(b) All elements of this part are applicable until the date of expiration as provided in law.
§ 183.15
Responsibilities of Federal agencies.
(a) Prior to making an award for a covered grant or cooperative agreement (see also § 183.35), the Federal agency must check the current list of prohibited or restricted persons or entities in the System for Award Management ( SAM.gov ) Exclusions.
(b) The Federal agency may include the award term provided in appendix A in all covered grant and cooperative agreement awards in accordance with Never Contract with the Enemy.
(c) A Federal agency may become aware of a person or entity that:
(1) Provides funds, including goods and services, received under a covered grant or cooperative agreement of an executive agency directly or indirectly to covered persons or entities; or
(2) Fails to exercise due diligence to ensure that no funds, including goods and services, received under an executive agency's covered grant or cooperative agreement are provided directly or indirectly to covered persons or entities.
(d) When a Federal agency becomes aware of such a person or entity, it may do any of the following actions:
(1) Restrict the future award of all Federal contracts, grants, and cooperative agreements to the person or entity based upon concerns that Federal awards to the entity would provide grant funds directly or indirectly to a covered person or entity.
(2) Terminate any grant, cooperative agreement, or contract to a covered person or entity upon becoming aware that the recipient has failed to exercise due diligence to ensure that no award funds are provided directly or indirectly to a covered person or entity.
(3) Void in whole or in part any grant, cooperative agreement, or contracts of the executive agency concerned upon a written determination by the head of contracting activity or another appropriate official that the grant or cooperative agreement provides funds directly or indirectly to a covered person or entity.
(e) The Federal agency must notify recipients in writing regarding its decision to restrict all future awards, terminate or void a grant or cooperative agreement, or both. The agency must also notify the recipient in writing about the recipient's right to request an administrative review (using the agency's procedures) of the restriction, termination, or void of the grant or cooperative agreement within 30 days of receiving notification.
§ 183.20
Reporting responsibilities of Federal agencies.
(a) If a Federal agency restricts all future awards to a covered person or entity, it must enter information on the ineligible person or entity into SAM.gov Exclusions as a prohibited or restricted source pursuant to Never Contract with the Enemy.
(b) When a Federal agency terminates or voids a grant or cooperative agreement due to Never Contract with the Enemy, it must report the action as a termination for material failure to comply in SAM.gov . Federal agencies must use the Contractor Performance Assessment Reporting System (CPARS) to enter or amend information in SAM.gov.
(c) The Federal agency must document and report to the head of the executive agency concerned (or the designee of such head) and the commander of the covered combatant command concerned (or specific deputies):
(1) Any action to restrict all future awards or to terminate or void an award with a covered person or entity.
(2) Any decision not to restrict all future awards, terminate, or void an award along with the agency's reasoning for not taking one of these actions after the agency became aware that a person or entity is a prohibited or restricted source.
(d) Each report referenced in paragraph (c)(1) of this section must include the following:
(1) The executive agency taking such action.
(2) An explanation of the basis for the action taken.
(3) The value of the terminated or voided grant or cooperative agreement.
(4) The value of all grants and cooperative agreements of the executive agency with the person or entity concerned at the time the grant or cooperative agreement was terminated or voided.
(e) Each report referenced in paragraph (c)(2) of this section must include the following:
(1) The executive agency concerned.
(2) An explanation of the basis for not taking the action.
(f) For each instance in which an executive agency exercised the additional authority to examine recipient and lower tier entity (for example, subrecipient or contractor) records, the agency must report in writing to the head of the executive agency concerned (or the designee of such head) and the commander of the covered combatant command concerned (or specific deputies) the following:
(1) An explanation of the basis for the action taken; and
(2) A summary of the results of any examination of records.
§ 183.25
Responsibilities of recipients.
(a) Recipients of covered grants or cooperative agreements must fulfill the requirements outlined in the award term provided in Appendix A to this part.
(b) Recipients must also flow down the provisions in award terms covered in Appendix A to this part to all contracts and subawards under the award.
§ 183.30
Access to records.
In addition to any other existing examination-of-records authority, the Federal Government is authorized to examine any records of the recipient and its subawards, to the extent necessary, to ensure that funds, including supplies and services, received under a covered grant or cooperative agreement (see § 183.35) are not provided directly or indirectly to a covered person or entity in accordance with Never Contract with the Enemy. The Federal agency may only exercise this authority upon a written determination by the Federal agency that relies on a finding by the commander of a covered combatant command that there is reason to believe that funds, including supplies and services, received under the grant or cooperative agreement may have been provided directly or indirectly to a covered person or entity.
§ 183.35
Definitions.
Terms used in this part are defined as follows:
Contingency operation, as defined in 10 U.S.C. 101(a)(13), means a military operation that:
(1) Is designated by the Secretary of Defense as an operation in which members of the armed forces are or may become involved in military actions, operations, or hostilities against an enemy of the United States or against an opposing military force; or
(2) Results in the call or order to, or retention on, active duty of members of the uniformed services under 10 U.S.C. 688, 12301(a), 12302, 12304, 12304a, 12305, 12406 of 10 U.S.C. chapter 15, 14 U.S.C. 3713 or any other provision of law during a war or during a national emergency declared by the President or Congress.
Covered combatant command means the following:
(1) The United States Africa Command.
(2) The United States Central Command.
(3) The United States European Command.
(4) The United States Pacific Command.
(5) The United States Southern Command.
(6) The United States Transportation Command.
Covered grant or cooperative agreement means a grant or cooperative agreement, as defined in 2 CFR 200.1 with an estimated value in excess of $50,000 that is performed outside the United States, including its possessions and territories, in support of a contingency operation in which members of the Armed Forces are actively engaged in hostilities. Except for U.S. Department of Defense grants and cooperative agreements that were awarded on or before December 19, 2017, that will be performed in the United States Central Command, where the estimated value is in excess of $100,000.
Covered person or entity means a person or entity that is actively opposing United States or coalition forces involved in a contingency operation in which members of the Armed Forces are actively engaged in hostilities.

Appendix A to Part 183—Award Terms for Never Contract With the Enemy
Federal agencies may include the following award terms in all awards for covered grants and cooperative agreements in accordance with Never Contract with the Enemy:

I. Term 1—Prohibition on Providing Funds to the Enemy
(a) You must:
(1) Exercise due diligence to ensure that no funds, including supplies and services, received under this grant or cooperative agreement are provided directly or indirectly (including through subawards or contracts) to a person or entity who is actively opposing the United States or coalition forces involved in a contingency operation in which members of the Armed Forces are actively engaged in hostilities, which must be completed through 2 CFR 180.300 prior to issuing a subaward or contract and;
(2) Terminate or void in whole or in part any subaward or contract with a person or entity listed in the System for Award Management ( SAM.gov ) as a prohibited or restricted source pursuant to subtitle E of Title VIII of the NDAA for FY 2015, unless the Federal agency provides written approval to continue the subaward or contract.
(b) You may include the substance of this clause, including paragraph (a) of this clause, in subawards under this grant or cooperative agreement that have an estimated value over $50,000 and will be performed outside the United States, including its outlying areas.
(c) The Federal agency has the authority to terminate or void this grant or cooperative agreement, in whole or in part, if the Federal agency becomes aware that you have failed to exercise due diligence as required by paragraph (a) of this clause or if the Federal agency becomes aware that any funds received under this grant or cooperative agreement have been provided directly or indirectly to a person or entity who is actively opposing coalition forces involved in a contingency operation in which members of the Armed Forces are actively engaged in hostilities.
(End of term)

II. Term 2—Additional Access to Recipient Records
(a) In addition to any other existing examination-of-records authority, the Federal Government is authorized to examine any of your records and the records of your subawards or contracts to the extent necessary to ensure that funds, including supplies and services, available under this grant or cooperative agreement are not provided, directly or indirectly, to a person or entity that is actively opposing the United States or coalition forces involved in a contingency operation in which members of the Armed Forces are actively engaged in hostilities, except for awards awarded by the Department of Defense on or before Dec 19, 2017, that will be performed in the United States Central Command (USCENTCOM) theater of operations.
(b) The substance of this clause, including this paragraph (b), must be included in subawards or contracts under this grant or cooperative agreement that have an estimated value over $50,000 and will be performed outside the United States, including its outlying areas.
(End of term)

PART 184—[Amended]
11. Amend part 184 by:
a. Removing remove the text “Federal awarding agency” and “Federal Awarding Agency”, wherever it appears, and adding, in its place, the text “Federal agency”; and
b. Removing the text “Federal awarding agencies”, wherever it appears, and adding, in its place, the text “Federal agencies”.

PART 200—UNIFORM ADMINISTRATIVE REQUIREMENTS, COST PRINCIPLES, AND AUDIT REQUIREMENTS FOR FEDERAL AWARDS
13. Revise the authority citation for part 200 to read as follows:

Authority:
31 U.S.C. 503; 31 U.S.C. 6101-6106; 31 U.S.C. 6307; 31 U.S.C. 7501-7507.
14. Amend part 200 by revising subparts A through F to read as follows:

Subpart A—Acronyms and Definitions

Acronyms
Sec.
200.0
Acronyms.
200.1
Definitions.

Subpart B—General Provisions
200.100
Purpose.
200.101
Applicability.
200.102
Exceptions.
200.103
Authorities.
200.104
Supersession.
200.105
Effect on other issuances.
200.106
Agency implementation.
200.107
OMB responsibilities.
200.108
Inquiries.
200.109
Review date.
200.110
Effective date.
200.111
English language.
200.112
Conflict of interest.
200.113
Mandatory disclosures.

Subpart C—Pre-Federal Award Requirements and Contents of Federal Awards
Sec.
200.200
Purpose.
200.201
Use of grants, cooperative agreements, fixed amount awards, and contracts.
200.202
Program planning and design.
200.203
Requirement to provide public notice of Federal financial assistance programs.
200.204
Notices of funding opportunities.
200.205
Federal agency review of merit of proposals.
200.206
Federal agency review of risk posed by applicants.
200.207
Standard application requirements.
200.208
Specific conditions.
200.209
Certifications and representations.
200.210
Pre-award costs.
200.211
Information contained in a Federal award.
200.212
Public access to Federal award information.
200.213
Reporting a determination that an applicant is not qualified for a Federal award.
200.214
Suspension and debarment.
200.215
Never contract with the enemy.
200.216
Prohibition on certain telecommunications and video surveillance equipment or services.
200.217
Whistleblower protections

Subpart D—Post Federal Award Requirements
200.300
Statutory and national policy requirements.
200.301
Performance measurement.
200.302
Financial management.
200.303
Internal controls.
200.304
Bonds.
200.305
Federal payment.
200.306
Cost sharing.
200.307
Program income.
200.308
Revision of budget and program plans.
200.309
Modifications to Period of Performance.

Property Standards
200.310
Insurance coverage.
200.311
Real property.
200.312
Federally owned and exempt property.
200.313
Equipment.
200.314
Supplies.
200.315
Intangible property.
200.316
Property trust relationship.

Procurement Standards
200.317
Procurements by states and Indian Tribes.
200.318
General procurement standards.
200.319
Competition.
200.320
Procurement methods.
200.321
Contracting with small businesses, minority businesses, women's business enterprises, veteran-owned businesses, and labor surplus area firms.
200.322
Domestic preferences for procurements.
200.323
Procurement of recovered materials.
200.324
Contract cost and price.
200.325
Federal agency or pass-through entity review.
200.326
Bonding requirements.
200.327
Contract provisions.

Performance and Financial Monitoring and Reporting
200.328
Financial reporting.
200.329
Monitoring and reporting program performance.
200.330
Reporting on real property.

Subrecipient Monitoring and Management
200.331
Subrecipient and contractor determinations.
200.332
Requirements for pass-through entities.
200.333
Fixed amount subawards.

Record Retention and Access
200.334
Record retention requirements.
200.335
Requests for transfer of records.
200.336
Methods for collection, transmission, and storage of information.
200.337
Access to records.
200.338
Restrictions on public access to records.

Remedies for Noncompliance
200.339
Remedies for noncompliance.
200.340
Termination.
200.341
Notification of termination requirement.
200.342
Opportunities to object, hearings, and appeals.
200.343
Effects of suspension and termination.

Closeout
200.344
Closeout.

Post-Closeout Adjustments and Continuing Responsibilities
200.345
Post-closeout adjustments and continuing responsibilities.

Collection of Amounts Due
200.346
Collection of amounts due.

Subpart E—Cost Principles

General Provisions
200.400
Policy guide.
200.401
Application.

Basic Considerations
200.402
Composition of costs.
200.403
Factors affecting allowability of costs.
200.404
Reasonable costs.
200.405
Allocable costs.
200.406
Applicable credits.
200.407
Prior written approval (prior approval).
200.408
Limitation on allowance of costs.
200.409
Special considerations.
200.410
Collection of unallowable costs.
200.411
Adjustment of previously negotiated indirect cost rates containing unallowable costs.

Direct and Indirect Costs
200.412
Classification of costs.
200.413
Direct costs.
200.414
Indirect costs.
200.415
Required certifications.

Special Considerations for States, Local Governments and Indian Tribes
200.416
Cost allocation plans and indirect cost proposals.
200.417
Interagency service.

Special Considerations for Institutions of Higher Education
200.418
Costs incurred by states and local governments.
200.419
Cost accounting standards.

General Provisions for Selected Items of Cost
200.420
Considerations for selected items of cost.
200.421
Advertising and public relations.
200.422
Advisory councils.
200.423
Alcoholic beverages.
200.424
Alumni activities.
200.425
Audit services.
200.426
Bad debts.
200.427
Bonding costs.
200.428
Collections of improper payments.
200.429
Commencement and convocation costs.
200.430
Compensation—personal services.
200.431
Compensation—fringe benefits.
200.432
Conferences.
200.433
Contingency provisions.
200.434
Contributions and donations.
200.435
Defense and prosecution of criminal and civil proceedings, claims, appeals and patent infringements.
200.436
Depreciation.
200.437
Employee health and welfare costs.
200.438
Entertainment and prizes.
200.439
Equipment and other capital expenditures.
200.440
Exchange rates.
200.441
Fines, penalties, damages and other settlements.
200.442
Fundraising and investment management costs.
200.443
Gains and losses on the disposition of depreciable assets.
200.444
General costs of government.
200.445
Goods or services for personal use.
200.446
Idle facilities and idle capacity.
200.447
Insurance and indemnification.
200.448
Intellectual property.
200.449
Interest.
200.450
Lobbying.
200.451
Losses on other awards or contracts.
200.452
Maintenance and repair costs.
200.453
Materials and supplies costs, including costs of computing devices.
200.454
Memberships, subscriptions, and professional activity costs.
200.455
Organization costs.
200.456
Participant support costs.
200.457
Plant and security costs.
200.458
Pre-award costs.
200.459
Professional service costs.
200.460
Proposal costs.
200.461
Publication and printing costs.
200.462
Rearrangement and reconversion costs.
200.463
Recruiting costs.
200.464
Relocation costs of employees.
200.465
Rental costs of real property and equipment.
200.466
Scholarships, student aid costs, and tuition remission.
200.467
Selling and marketing costs.
200.468
Specialized service facilities.
200.469
Student activity costs.
200.470
Taxes (including Value Added Tax).
200.471
Telecommunication and video surveillance costs.
200.472
Termination and standard closeout costs.
200.473
Training and education costs.
200.474
Transportation costs.
200.475
Travel costs.
200.476
Trustees.

Subpart F—Audit Requirements General
200.500
Purpose.

Audits
200.501
Audit requirements.
200.502
Basis for determining Federal awards expended.
200.503
Relation to other audit requirements.
200.504
Frequency of audits.
200.505
Remedies for audit noncompliance.
200.506
Audit costs.
200.507
Program-specific audits.

Auditees
200.508
Auditee responsibilities.
200.509
Auditor selection.
200.510
Financial statements.
200.511
Audit findings follow-up.
200.512
Report submission.

Federal Agencies
200.513
Responsibilities.

Auditors
200.514
Standards and scope of audit.
200.515
Audit reporting.
200.516
Audit findings.
200.517
Audit documentation.
200.518
Major program determination.
200.519
Criteria for Federal program risk.
200.520
Criteria for a low-risk auditee.

Management Decisions
200.521
Management decisions.

Subpart A—Acronyms and Definitions

Acronyms
§ 200.0
Acronyms.
(a) CAS Cost Accounting Standards
(b) CFR Code of Federal Regulations
(c) F&A Facilities and Administration
(d) FAC Federal Audit Clearinghouse
(e) FAIN Federal Award Identification Number
(f) FAR Federal Acquisition Regulation
(g) FASB Financial Accounting Standards Board
(h) FFATA Federal Funding Accountability and Transparency Act of 2006 or Transparency Act, Public Law 109-282, as amended (See 31 U.S.C. 6101, statutory note)
(i) FOIA Freedom of Information Act
(j) FR Federal Register
(k) GAAP Generally Accepted Accounting Principles
(l) GAGAS Generally Accepted Government Auditing Standards
(m) GASB Government Accounting Standards Board
(n) GAO Government Accountability Office
(o) GSA General Services Administration
(p) IBS Institutional Base Salary
(q) IHE Institutions of Higher Education
(r) IRC Internal Revenue Code
(s) ISDEAA Indian Self-Determination and Education and Assistance Act
(t) MTC Modified Total Cost
(u) MTDC Modified Total Direct Cost
(v) NFE Non-Federal Entity
(w) NOFO Notice of Funding Opportunity
(x) OMB Office of Management and Budget
(y) PII Personally Identifiable Information
(z) PMS Payment Management System
(aa) SAM System for Award Management ( SAM.gov )
(bb) UEI Unique Entity Identifier
(cc) U.S.C. United States Code
(dd) VAT Value Added Tax
§ 200.1
Definitions.
The following is a list of definitions of key terms frequently used in 2 CFR part 200. Definitions found in Federal statutes or regulations that apply to particular programs take precedence over the following definitions. However, where the following definitions implement specific statutory requirements that apply government-wide, such as the Single Audit Act, the following definitions take precedence over Federal regulations. For purposes of this part, the following definitions apply:
Acquisition cost means the (total) cost of the asset including the cost to ready the asset for its intended use. For example, acquisition cost for equipment means the net invoice price of the equipment, including the cost of any modifications, attachments, accessories, or auxiliary apparatus necessary to make it usable for the purpose for which it is acquired. Acquisition costs for software include those development costs capitalized in accordance with generally accepted accounting principles (GAAP). Ancillary charges such as taxes, duty, protective in transit insurance, freight, and installation may be included in or excluded from the acquisition cost in accordance with the recipient's or subrecipient's regular accounting practices.
Advance payment means a payment that a Federal agency or pass-through entity makes by any appropriate payment mechanism and payment method before the recipient or subrecipient disburses the funds for program purposes.
Allocation means the process of assigning a cost, or a group of costs, to one or more cost objective(s), in reasonable proportion to the benefit provided or other equitable relationship. The process may entail assigning a cost(s) directly to a final cost objective or through one or more intermediate cost objectives.
Assistance Listings refer to the publicly available listing of Federal assistance programs managed and administered by the General Services Administration (GSA) at SAM.gov .
Assistance Listing number means a unique number assigned to identify an Assistance Listing.
Assistance Listing program title means the title that corresponds to the Assistance Listing number.
Audit finding means deficiencies which the auditor is required to report in the schedule of findings and questioned costs. (See § 200.516(a))
Auditee means any non-Federal entity that must be audited under this part. (See § 200.501)
Auditor means an auditor who is a public accountant or a Federal, State, local government, or Indian Tribe audit organization that meets the general standards specified for external auditors in generally accepted government auditing standards (GAGAS). The term auditor does not include internal auditors of nonprofit organizations.
Budget means the financial plan for the Federal award that the Federal agency or pass-through entity approves during the Federal award process or in subsequent amendments to the Federal award. It may include the Federal and non-Federal share or only the Federal share, as determined by the Federal agency or pass-through entity.
Budget period means the time interval from the start date of a funded portion of an award to the end date of that funded portion, during which recipients and subrecipients are authorized to incur financial obligations of the funds awarded, including any funds carried forward or other revisions pursuant to § 200.308.
Capital assets means:
(1) Tangible or intangible assets used in operations having a useful life of more than one year which are capitalized in accordance with GAAP. Capital assets include:
(i) Land, buildings (facilities), equipment, and intellectual property (including software), whether acquired by purchase, construction, manufacture, exchange, or through a lease accounted for as financed purchase under Government Accounting Standards Board (GASB) standards or a finance lease under Financial Accounting Standards Board (FASB) standards; and
(ii) Additions, improvements, modifications, replacements, rearrangements, reinstallations, renovations, or alterations to capital assets that materially increase their value or useful life (not ordinary repairs and maintenance).
(2) For purpose of this part, capital assets do not include intangible right-to-use assets (per GASB) and right-to-use operating lease assets (per FASB). For example, assets capitalized that recognize a lessee's right to control the use of property or equipment for a period of time under a lease contract. See § 200.465.
Capital expenditures means expenditures to acquire capital assets or expenditures to make additions, improvements, modifications, replacements, rearrangements, reinstallations, renovations, or alterations to capital assets that materially increase their value or useful life.
Central service cost allocation plan means the documentation identifying, accumulating, and allocating or developing billing rates based on the allowable costs of services provided by a State, local government, or Indian Tribe to its departments and agencies on a centralized basis. The costs of these services may be allocated or billed to users.
Claim means, depending on the context, either:
(1) A written demand or assertion by one of the parties to a Federal award seeking as a matter of right:
(i) The payment of money;
(ii) The adjustment or interpretation of the terms and conditions of the Federal award; or
(iii) Other relief arising under or relating to a Federal award.
(2) A request for payment not in dispute when submitted.
Class of Federal awards means a group of Federal awards either awarded under a specific program or group of programs or to a specific type of recipient or group of recipients to which specific provisions or exceptions may apply.
Closeout means the process by which the Federal agency or pass-through entity determines that all applicable administrative actions and all required work of the Federal award have been completed and takes actions as described in § 200.344.
Cluster of programs means a grouping of closely related programs that share common compliance requirements. The types of clusters of programs are research and development (R&D), student financial aid (SFA), and other clusters. “Other clusters” are defined by OMB in the compliance supplement or designated by a State for Federal awards the State provides to its subrecipients that meet the definition of a cluster of programs. When designating “other clusters,” a State must identify the Federal awards included in the cluster and advise the subrecipients of compliance requirements applicable to the cluster, consistent with § 200.332. A cluster of programs must be considered one program when determining major programs as described in § 200.518, and with the exception of R&D as described in § 200.501(d), whether a program-specific audit may be elected.
Cognizant agency for audit means the Federal agency designated to carry out the responsibilities described in § 200.513(a). The cognizant agency for audit is not necessarily the same as the cognizant agency for indirect costs. A list of Federal agency Single Audit contacts can be found on the Federal Audit Clearinghouse (FAC) website.
Cognizant agency for indirect costs means the Federal agency responsible for reviewing, negotiating and approving cost allocation plans or indirect cost proposals on behalf of all Federal agencies. The cognizant agency for indirect cost is not necessarily the same as the cognizant agency for audit. For assignments of cognizant agencies, see the following:
(1) For Institutions of Higher Education (IHEs): Appendix III, paragraph C.11.
(2) For nonprofit organizations: Appendix IV, paragraph C.2.a.
(3) For State and local governments: Appendix V, paragraph F.1.
(4) For Indian Tribes: Appendix VII, paragraph D.1.
Compliance supplement means an annually updated authoritative source of information for auditors that identifies existing important compliance requirements that the Federal Government expects to be considered as part of an audit. Auditors use it to understand the Federal program's objectives, procedures, and compliance requirements, as well as audit objectives and suggested audit procedures for determining compliance with the relevant Federal program.
Computing devices means machines that acquire, store, analyze, process, and publish data and other information electronically, including accessories (or “peripherals”) for printing, transmitting and receiving, or storing electronic information. See also the definitions of supplies and information technology systems in this section.
Contract means, for the purpose of Federal financial assistance, a legal instrument by which a recipient or subrecipient conducts procurement transactions under a Federal award. For additional information on subrecipient and contractor determinations, see § 200.331. See also the definition of subaward in this section.
Contractor means an entity that receives a contract.
Continuation funding means the second or subsequent budget period within an identified period of performance.
Cooperative agreement means a legal instrument of financial assistance between a Federal agency and a recipient or between a pass-through entity and subrecipient, consistent with 31 U.S.C. 6302-6305:
(1) Is used to enter into a relationship the principal purpose of which is to transfer anything of value to carry out a public purpose authorized by a law of the United States (see 31 U.S.C. 6101(3)); and not to acquire property or services for the Federal Government or pass-through entity's direct benefit or use;
(2) Is distinguished from a grant in that it provides for substantial involvement of the Federal agency or pass-through entity in carrying out the activity contemplated by the Federal award.
(3) The term does not include:
(i) A cooperative research and development agreement as defined in 15 U.S.C. 3710a; or
(ii) An agreement that provides only:
(A) Direct United States Government cash assistance to an individual;
(B) A subsidy;
(C) A loan;
(D) A loan guarantee; or
(E) Insurance.
Corrective action means action taken by the auditee that:
(1) Corrects identified deficiencies;
(2) Produces recommended improvements; or
(3) Demonstrates that audit findings are either invalid or do not warrant auditee action.
Cost allocation plan means a central service or public assistance cost allocation plan.
Cost objective means a program, function, activity, award, organizational subdivision, contract, or work unit for which cost data are desired and for which provision is made to accumulate and measure the cost of processes, products, jobs, and capital projects. A cost objective may be a major function of the recipient or subrecipient, a particular service or project, a Federal award, or an indirect cost activity, as described in subpart E. See also the definitions of final cost objective and intermediate cost objective in this section.
Cost sharing means the portion of project costs not paid by Federal funds or contributions (unless authorized by Federal statute). This term includes matching, which refers to required levels of cost share that must be provided. See § 200.306.
Disallowed cost means charges to a Federal award that the Federal agency or pass-through entity determines to be unallowable in accordance with applicable Federal statutes, regulations, the provisions of this part, or the terms and conditions of the Federal award.
Discretionary award means an award in which the Federal agency, in keeping with specific statutory authority that enables the agency to exercise judgment (“discretion”), selects the recipient or the amount of Federal funding awarded through a competitive process or based on merit of proposals. A discretionary award may be selected on a non-competitive basis, as appropriate.
Equipment means tangible personal property (including information technology systems) having a useful life of more than one year and a per-unit acquisition cost that equals or exceeds the lesser of the capitalization level established by the recipient or subrecipient for financial statement purposes, or $10,000. See the definitions of capital assets, computing devices, general purpose equipment, information technology systems, special purpose equipment, and supplies in this section.
Expenditures means charges made by a recipient or subrecipient to a project or program for which a Federal award is received.
(1) The charges may be reported on a cash or accrual basis as long as the methodology is disclosed and consistently applied.
(2) For reports prepared on a cash basis, expenditures are the sum of:
(i) Cash disbursements for direct charges for property and services;
(ii) The amount of indirect expense charged;
(iii) The value of third-party in-kind contributions applied; and
(iv) The amount of cash advance payments and payments made to subrecipients.
(3) For reports prepared on an accrual basis, expenditures are the sum of:
(i) Cash disbursements for direct charges for property and services;
(ii) The amount of indirect expense incurred;
(iii) The value of third-party in-kind contributions applied; and
(iv) The net increase or decrease in the amounts owed by the recipient or subrecipient for:
(A) Goods and other property received;
(B) Services performed by employees, contractors, subrecipients, and other payees; and
(C) Programs for which no current services or performance are required, such as annuities, insurance claims, or other benefit payments.
Federal agency means an “agency” as defined at 5 U.S.C. 551(1) and further clarified by 5 U.S.C. 552(f). The term generally refers to the agency that provides a Federal award directly to a recipient unless the context indicates otherwise. See also definitions of Federal award and recipient.
Federal Audit Clearinghouse (FAC) means the repository of record designated by OMB where non-Federal entities must transmit the information required by subpart F.
Federal award has the meaning, depending on the context, in either paragraph (1) or (2) of this definition:
(1)(i) The Federal financial assistance that a recipient receives directly from a Federal agency or indirectly from a pass-through entity, as described in § 200.101; or
(ii) The cost-reimbursement contract under the Federal Acquisition Regulation that a non-Federal entity receives directly from a Federal agency or indirectly from a pass-through entity, as described in § 200.101.
(2) The instrument setting forth the terms and conditions. The instrument is the grant agreement, cooperative agreement, other agreement for assistance covered in paragraph (2) of the definition of Federal financial assistance in this section, or the cost-reimbursement contract awarded under the Federal Acquisition Regulations.
(3) Federal award does not include other contracts that a Federal agency uses to buy goods or services from a contractor or a contract to operate government-owned, contractor- operated (GOCO) facilities.
(4) See also definitions of Federal financial assistance, grant agreement, and cooperative agreement.
Federal award date means the date when the authorized official of the Federal agency signed (physically or digitally) the Federal award or when an alternative, consistent with the requirements of 31 U.S.C. 1501, is reached with the recipient.
Federal financial assistance means:
(1) Assistance that recipients or subrecipients receive or administer in the form of:
(i) Grants;
(ii) Cooperative agreements;
(iii) Non-cash contributions or donations of property (including donated surplus property);
(iv) Direct appropriations;
(v) Food commodities; and
(vi) Other financial assistance (except assistance listed in paragraph (2) of this definition).
(2) For § 200.203 and subpart F of this part, Federal financial assistance also includes assistance that recipients or subrecipients receive or administer in the form of:
(i) Loans;
(ii) Loan Guarantees;
(iii) Interest subsidies; and
(iv) Insurance.
(3) For § 200.216, Federal financial assistance includes assistance that recipients or subrecipients receive or administer in the form of:
(i) Grants;
(ii) Cooperative agreements;
(iii) Loans; and
(iv) Loan Guarantees.
(4) Federal financial assistance does not include amounts received as reimbursement for services rendered to individuals as described in § 200.502(h) and (i).
Federal interest means, for purposes of § 200.330 or when used in connection with the acquisition or improvement of real property, equipment, or supplies under a Federal award, the dollar amount that is the product of the:
(1) The percentage of Federal participation in the total cost of the real property, equipment, or supplies; and
(2) Current fair market value of the property, improvements, or both, to the extent the costs of acquiring or improving the property were included as project costs.
Federal program means:
(1) All Federal awards which are assigned a single Assistance Listings Number.
(2) When no Assistance Listings Number is assigned, all Federal awards from the same agency made for the same purpose must be combined and considered one program.
(3) Notwithstanding paragraphs (1) and (2) of this definition, a cluster of programs. The types of clusters of programs are:
(i) Research and development (R&D);
(ii) Student financial aid (SFA); and
(iii) “Other clusters,” as described in the definition of cluster of programs in this section. Federal share means the portion of the Federal award costs paid using Federal funds.
Final cost objective means a cost objective that has allocated to it both direct and indirect costs and, in the recipient's or subrecipient's accumulation system, is one of the final accumulation points, such as a particular award, internal project, or other direct activity of a recipient or subrecipient. See also the definitions of cost objective and intermediate cost objective in this section.
Financial obligations means orders placed for property and services, contracts and subawards made, and similar transactions that require payment by a recipient or subrecipient under a Federal award that will result in expenditures by a recipient or subrecipient under a Federal award.
Fixed amount award means a type of grant or cooperative agreement pursuant to which the Federal agency or pass-through entity provides a specific amount of funding without regard to actual costs incurred under the Federal award. This type of Federal award reduces some of the administrative burden and record-keeping requirements for both the recipient or subrecipient and the Federal agency or pass-through entity. Accountability is based primarily on performance and results. See §§ 200.102(c), 200.101(b), 200.201(b), and 200.333.
For-profit organization generally means an organization or entity organized for the purpose of earning a profit. The term includes but is not limited to:
(1) An “S corporation” incorporated under subchapter S of the Internal Revenue Code;
(2) A corporation incorporated under another authority;
(3) A partnership;
(4) A limited liability company or partnership; and
(5) A sole proprietorship.
Foreign organization means an entity that is:
(1) A public or private organization located in a country other than the United States and its territories that is subject to the laws of the country in which it is located, irrespective of the citizenship of project staff or place of performance;
(2) A private nongovernmental organization located in a country other than the United States that solicits and receives cash contributions from the general public;
(3) A charitable organization located in a country other than the United States that is nonprofit and tax-exempt under the laws of the country where it is registered and is not a university, college, accredited degree-granting institution of education, private foundation, hospital, an organization engaged exclusively in research or scientific activities, church, synagogue, mosque or other similar entities organized primarily for religious purposes; or
(4) An organization located in a country other than the United States not recognized as a foreign public entity.
Foreign public entity means:
(1) A foreign government or foreign governmental entity;
(2) A public international organization, which is an organization entitled to enjoy privileges, exemptions, and immunities as an international organization under the International Organizations Immunities Act (22 U.S.C. 288-288f);
(3) An entity owned (in whole or in part) or controlled by a foreign government; or
(4) Any other entity consisting wholly or partially of one or more foreign governments or foreign governmental entities.
General purpose equipment means equipment that is not limited to research, medical, scientific, or other technical activities. Examples include office equipment and furnishings, modular offices, telephone networks, information technology equipment and systems, air conditioning equipment, reproduction and printing equipment, and motor vehicles. See also the definitions of equipment and special purpose equipment in this section.
Generally accepted accounting principles (GAAP) has the meaning specified in accounting standards issued by the Government Accounting Standards Board (GASB) and the Financial Accounting Standards Board (FASB).
Generally accepted government auditing standards (GAGAS), also known as the Yellow Book, means generally accepted government auditing standards issued by the Comptroller General of the United States, which apply to financial audits.
Grant agreement or grant means a legal instrument of financial assistance between a Federal agency and a recipient or between a pass-through entity and a subrecipient, consistent with 31 U.S.C. 6302, 6304:
(1) Is used to enter into a relationship, the principal purpose of which is to transfer anything of value to carry out a public purpose authorized by a law of the United States (see 31 U.S.C. 6101(3)); and not to acquire property or services for the Federal agency or pass-through entity's direct benefit or use;
(2) Is distinguished from a cooperative agreement in that it does not provide for substantial involvement of the Federal agency in carrying out the activity contemplated by the Federal award.
(3) Does not include an agreement that provides only:
(i) Direct United States Government cash assistance to an individual;
(ii) A subsidy;
(iii) A loan;
(vi) A loan guarantee; or
(v) Insurance.
Highest-level owner means the entity that owns or controls an immediate owner of an applicant or that owns or controls one or more entities that control an immediate owner of an applicant. No entity owns or exercises control of the highest-level owner as defined in the Federal Acquisition Regulations (FAR) (48 CFR 52.204-17).
Hospital means a facility licensed as a hospital under the law of any State or a facility operated as a hospital by the United States, a State, or a subdivision of a State.
Improper payment means a payment that should not have been made or that was made in an incorrect amount under statutory, contractual, administrative, or other legally applicable requirements. The term improper payment includes: any payment to an ineligible recipient; any payment for an ineligible good or service; any duplicate payment; any payment for a good or service not received, except for those payments where authorized by law; any payment that is not authorized by law; and any payment that does not account for credit for applicable discounts. See OMB Circular A-123 Appendix C, Requirements for Payment Integrity Improvement for additional definitions and guidance on the requirements for payment integrity.
Indian Tribe means any Indian Tribe, band, nation, or other organized group or community, including any Alaska Native village or regional or village corporation as defined in or established pursuant to the Alaska Native Claims Settlement Act (43 U.S.C. Chapter 33), which is recognized as eligible for the special programs and services provided by the United States to Indians because of their status as Indians. See 25 U.S.C. 5304(e). This includes any Indian Tribe identified in the annually published Bureau of Indian Affairs list of “ Indian Entities Recognized and Eligible to Receive Services” and other entities that qualify as an Alaska Native village or regional village corporation as defined in or established pursuant to the Alaska Native Claims Settlement Act.
Indirect cost means those costs incurred for a common or joint purpose benefitting more than one cost objective and not readily assignable to the cost objectives specifically benefitted, without effort disproportionate to the results achieved. It may be necessary to establish multiple pools of indirect costs to facilitate equitable distribution of indirect expenses to the cost objectives served. Indirect cost pools must be distributed to benefitted cost objectives on basis that will produce an equitable result in consideration of relative benefits derived. For Institutions of Higher Education (IHE), the term facilities and administrative (F&A) cost is often used to refer to indirect costs.
Indirect cost rate proposal means the documentation prepared by a recipient to substantiate its request to establish an indirect cost rate as described in appendices III through VII and appendix IX to this part.
Information technology systems means computing devices, ancillary equipment, software, firmware, and related procedures, services (including support services), and resources. See also the definitions of computing devices and equipment in this section.
Institution of Higher Education (IHE) is defined at 20 U.S.C. 1001.
Intangible property means property having no physical existence, such as trademarks, copyrights, data (including data licenses), websites, IP licenses, trade secrets, patents, patent applications, and property such as loans, notes and other debt instruments, lease agreements, stocks and other instruments of property ownership of either tangible or intangible property, such as intellectual property, software, or software subscriptions or licenses. Intermediate cost objective means a cost objective that is used to accumulate indirect costs or service center costs that are subsequently allocated to one or more indirect cost pools or final cost objectives. See this section's definitions of cost objective and final cost objective.
Internal control for recipients and subrecipients means processes designed and implemented by recipients and subrecipients to provide reasonable assurance regarding the achievement of objectives in the following categories:
(1) Effectiveness and efficiency of operations;
(2) Reliability of reporting for internal and external use; and
(3) Compliance with applicable laws and regulations.
Loan means a Federal loan or loan guarantee received or administered by a recipient or subrecipient, except as used in this section's definition of program income.
(1) The term “direct loan” means a disbursement of funds by the Federal Government to a non-Federal borrower under a contract that requires the repayment of such funds with or without interest. The term includes the purchase of, or participation in, a loan made by another lender and financing arrangements that defer payment for more than 90 days, including the sale of a Federal Government asset on credit terms. The term does not include the acquisition of a federally guaranteed loan in satisfaction of default claims or the price support loans of the Commodity Credit Corporation.
(2) The term “direct loan obligation” means a binding agreement by a Federal agency to make a direct loan when specified conditions are fulfilled by the borrower.
(3) The term “loan guarantee” means any Federal Government guarantee, insurance, or other pledges for the payment of all or a part of the principal or interest on any debt obligation of a non-Federal borrower to a non-Federal lender but does not include the insurance of deposits, shares, or other withdrawable accounts in financial institutions.
(4) The term “loan guarantee commitment” means a binding agreement by a Federal agency to make a loan guarantee when specified conditions are fulfilled by the borrower, the lender, or any other party to the guarantee agreement.
Local government means any unit of government within a State, including a:
(1) County;
(2) Borough;
(3) Municipality;
(4) City;
(5) Town;
(6) Township;
(7) Parish;
(8) Local public authority, including any public housing agency under the United States Housing Act of 1937;
(9) Special district;
(10) School district;
(11) Intrastate district;
(12) Council of governments, whether or not incorporated as a nonprofit corporation under State law; and
(13) Any other agency or instrumentality of a multi-, regional, or intra-State or local government.
Major program means a Federal program determined by the auditor to be a major program in accordance with § 200.518 or a program identified as a major program by a Federal agency or pass-through entity in accordance with § 200.503(e).
Management decision means the Federal agency's or pass-through entity's written determination, provided to the auditee, of the adequacy of the auditee's proposed corrective actions to address the findings based on its evaluation of the audit findings and proposed corrective actions.
Micro-purchase means an individual procurement transaction for supplies or services, the aggregate amount of which does not exceed the micro-purchase threshold. Micro-purchases comprise a subset of a recipient's or subrecipient's small purchases using informal procurement methods as set forth in § 200.320.
Micro-purchase threshold means the dollar amount at or below which a recipient or subrecipient may purchase property, or services using micro-purchase procedures (see § 200.320). Generally, except as provided in § 200.320, the micro-purchase threshold for procurement activities administered under Federal awards is not to exceed the amount set by the FAR at 48 CFR part 2, subpart 2.1, unless a higher threshold is requested by the recipient or subrecipient and approved by the cognizant agency for indirect costs.
Modified Total Direct Cost (MTDC) means all direct salaries and wages, applicable fringe benefits, materials and supplies, services, travel, and up to the first $50,000 of each subaward (regardless of the period of performance of the subawards under the award). MTDC excludes equipment, capital expenditures, charges for patient care, rental costs, tuition remission, scholarships and fellowships, participant support costs, and the portion of each subaward in excess of $50,000. Other items may only be excluded when necessary to avoid a serious inequity in the distribution of indirect costs and with the approval of the cognizant agency for indirect costs.
Non-discretionary award means an award made by the Federal agency to specific recipients in accordance with statutory, eligibility, and compliance requirements, such that in keeping with specific statutory authority, the Federal agency cannot exercise judgment (“discretion”). A non-discretionary award amount could be specifically determined or by formula.
Non-Federal entity (NFE) means a State, local government, Indian Tribe, Institution of Higher Education (IHE), or nonprofit organization that carries out a Federal award as a recipient or subrecipient.
Nonprofit organization means any organization that:
(1) Is operated primarily for scientific, educational, service, charitable, or similar purposes in the public interest;
(2) Is not organized primarily for profit;
(3) Uses net proceeds to maintain, improve, or expand the organization's operations; and
(4) Is not an IHE.
Notice of funding opportunity means a formal announcement of the availability of Federal funding through a financial assistance program from a Federal agency. The notice of funding opportunity provides information on the award, such as who is eligible to apply, the evaluation criteria for selecting a recipient or subrecipient, the required components of an application, and how to submit the application. The notice of funding opportunity is any paper or electronic issuance that an agency uses to announce a funding opportunity, whether it is called a “program announcement,” “notice of funding availability,” “broad agency announcement,” “research announcement,” “solicitation,” or some other term.
Office of Management and Budget (OMB) means the Executive Office of the President, Office of Management and Budget.
Oversight agency for audit means the Federal agency that provides the predominant amount of funding directly (direct funding) (as listed on the schedule of expenditures of Federal awards, see § 200.510(b)) to a recipient or subrecipient unless OMB designates a specific cognizant agency for audit. When the direct funding represents less than 25 percent of the total Federal expenditures (as direct and sub-awards) by the recipient or subrecipient, then the Federal agency with the predominant amount of total funding is the designated oversight agency for audit. When there is no direct funding, the Federal agency that is the predominant source of pass-through funding must assume the oversight responsibilities. The duties of the oversight agency for audit and the process for any reassignments are described in § 200.513(b).
Participant generally means an individual participating in or attending program activities under a Federal award, such as trainings or conferences, but who is not responsible for implementation of the Federal award. Individuals committing effort to the development or delivery of program activities under a Federal award (such as consultants, project personnel, or staff members of a recipient or subrecipient) are not participants. Examples of participants may include community members participating in a community outreach program, members of the public whose perspectives or input are sought as part of a program, students, or conference attendees.
Participant support costs means direct costs that support participants (see definition for Participant in § 200.1) and their involvement in a Federal award, such as stipends, subsistence allowances, travel allowances, registration fees, temporary dependent care, and per diem paid directly to or on behalf of participants.
Pass-through entity means a recipient or subrecipient that provides a subaward to a subrecipient (including lower tier subrecipients) to carry out part of a Federal program. The authority of the pass-through entity under this part flows through the subaward agreement between the pass-through entity and subrecipient.
Performance goal means a measurable target level of performance expressed as a tangible, measurable objective, against which actual achievement can be compared, including a goal expressed as a quantitative standard, value, or rate. In some instances (for example, discretionary research awards), this may be limited to the requirement to submit technical performance reports (to be evaluated in accordance with agency policy).
Period of performance means the time interval between the start and end date of a Federal award, which may include one or more budget periods. Identification of the period of performance in the Federal award consistent with § 200.211(b)(5) does not commit the Federal agency to fund the award beyond the currently approved budget period.
Personal property means property other than real property. It may be tangible or intangible.
Personally Identifiable Information (PII) means information that can be used to distinguish or trace an individual's identity, either alone or when combined with other personal or identifying information that is linked or linkable to a specific individual. Some PII is available in public sources such as telephone books, websites, and university listings. The definition of PII is not attached to any single category of information or technology. Instead, it requires a case-by-case assessment of the specific risk that an individual can be identified. Non-PII can become PII whenever additional information is made publicly available, in any medium and from any source, that could be used to identify an individual when combined with other available information.
Prior approval means the written approval obtained in advance by an authorized official of a Federal agency or pass-through entity of certain costs or programmatic decisions.
Program income means gross income earned by the recipient or subrecipient that is directly generated by a supported activity or earned as a result of the Federal award during the period of performance except as provided in § 200.307(c). Program income includes but is not limited to income from fees for services performed, the use or rental of real or personal property acquired under Federal awards, the sale of commodities or items fabricated under a Federal award, license fees, and royalties on patents and copyrights, and principal and interest on loans made with Federal award funds. Interest earned on advances of Federal funds is not program income. Except as otherwise provided in Federal statutes, regulations, or the terms and conditions of the Federal award, program income does not include rebates, credits, discounts, and interest earned on any of them. See § 200.407. See also 35 U.S.C. 200-212 “Disposition of Rights in Educational Awards,” which applies to inventions made under Federal awards.
Project cost means total allowable costs incurred under a Federal award and all cost sharing, including third-party contributions.
Property means real property or personal property. See this section's definitions of real property and personal property.
Protected Personally Identifiable Information (Protected PII) means PII (see definition in this section), except for PII that must be disclosed by law. Examples of PII include, but are not limited to, social security number; passport number; credit card numbers; clearances, bank numbers; biometrics; date and place of birth; mother's maiden name; criminal, medical and financial records; and educational transcripts.
Questioned cost has the meaning given in paragraphs (1) through (3).
(1) Questioned cost means an amount, expended or received from a Federal award, that in the auditor's judgment:
(i) Is noncompliant or suspected noncompliant with Federal statutes, regulations, or the terms and conditions of the Federal award;
(ii) At the time of the audit, lacked adequate documentation to support compliance; or
(iii) Appeared unreasonable and did not reflect the actions a prudent person would take in the circumstances.
(2) The questioned cost amount under (1)(ii) is calculated as if the portion of a transaction that lacked adequate documentation were confirmed noncompliant.
(3) There is no questioned cost solely because of:
(i) Deficiencies in internal control; or
(ii) Noncompliance with the reporting type of compliance requirement (described in the compliance supplement) if this noncompliance does not affect the amount expended or received from the Federal award.
(4) Known questioned cost means a questioned cost specifically identified by the auditor. Known questioned costs are a subset of likely questioned costs.
(5) Likely questioned cost means the auditor's best estimate of total questioned costs, not just the known questioned costs. Likely questioned costs are developed by extrapolating from audit evidence obtained, for example, by projecting known questioned costs identified in an audit sample to the entire population from which the sample was drawn. In evaluating the effect of questioned costs on the opinion on compliance, the auditor considers the likely questioned costs, not just the known questioned costs.
(6) Questioned costs are not improper payments until reviewed and confirmed to be improper payments as defined in OMB Circular A-123 Appendix C.
Real property means land, including land improvements, structures, and appurtenances thereto, and legal interests in land, including fee interest, licenses, rights of way, and easements. Real property excludes moveable machinery and equipment.
Recipient means an entity that receives a Federal award directly from a Federal agency to carry out an activity under a Federal program. The term recipient does not include subrecipients or individuals that are participants or beneficiaries of the award.
Renewal award means a Federal award for which the start date is contiguous with, or closely follows, the end of the expiring Federal award. The start date of a renewal award begins a new and distinct period of performance.
Research and Development (R&D) means all basic and applied research activities and all development activities performed by a recipient or subrecipient. The term research also includes activities involving the training of individuals in research techniques where such activities use the same facilities as other research and development activities and where such activities are not included in the instruction function. “Research” is the systematic study directed toward fuller scientific knowledge or understanding of the subject studied. “Development” is the systematic use of knowledge and understanding gained from research to produce useful materials, devices, systems, or methods, including designing and developing prototypes and processes.
Simplified acquisition threshold means the dollar amount below which a recipient or subrecipient may purchase property or services using small purchase methods (see § 200.320). Recipients and subrecipients adopt small purchase procedures to expedite the purchase of items at or below the simplified acquisition threshold. The simplified acquisition threshold set in the FAR at 48 CFR part 2, subpart 2.1 is used in this part as the simplified acquisition threshold for secondary procurement activities administered under Federal awards. The recipient or subrecipient is responsible for determining an appropriate simplified acquisition threshold, which is less than or equal to the dollar value established in the FAR, based on internal controls, an evaluation of risk, and its documented procurement procedures. Recipients and subrecipients should also determine if local government purchasing laws apply. This threshold must never exceed the dollar value established in the FAR.
Special purpose equipment means equipment that is used only for research, medical, scientific, or other similar technical activities. Examples of special purpose equipment include microscopes, x-ray machines, surgical instruments, spectrometers, and associated software. See also the definitions of equipment and general purpose equipment in this section.
State means any State of the United States, the District of Columbia, the Commonwealth of Puerto Rico, U.S. Virgin Islands, Guam, American Samoa, the Commonwealth of the Northern Mariana Islands, and any agency or instrumentality thereof exclusive of local governments.
Student Financial Aid (SFA) means Federal awards under those programs of general student assistance, such as those authorized by Title IV of the Higher Education Act of 1965, as amended (20 U.S.C. 1070-1099d), which the U.S. Department of Education administers, and similar programs provided by other Federal agencies. It does not include Federal awards under programs that provide fellowships or similar Federal awards to students on a competitive basis or for specified studies or research.
Subaward means an award provided by a pass-through entity to a subrecipient for the subrecipient to contribute to the goals and objectives of the project by carrying out part of a Federal award received by the pass-through entity. It does not include payments to a contractor, beneficiary, or participant. A subaward may be provided through any form of legal agreement consistent with criteria in with § 200.331, including an agreement the pass-through entity considers a contract.
Subrecipient means an entity that receives a subaward from a pass-through entity to carry out part of a Federal award. The term subrecipient does not include a beneficiary or participant. A subrecipient may also be a recipient of other Federal awards directly from a Federal agency.
Subsidiary means an entity in which more than 50 percent of the entity is owned or controlled directly by a parent corporation or through another subsidiary of a parent corporation.
Supply means all tangible personal property other than those described in the equipment definition. A computing device is a supply if the acquisition cost is below the lesser of the capitalization level established by the recipient or subrecipient for financial statement purposes or $10,000, regardless of the length of its useful life. See this section's definitions of computing devices and equipment.
Telecommunications cost means the cost of using communication technologies such as mobile phones, landlines, and the internet.
Termination means the action a Federal agency or pass-through entity takes to discontinue a Federal award, in whole or in part, at any time before the planned end date of the period of performance. Termination does not include discontinuing a Federal award due to a lack of available funds.
Third-party in-kind contributions means the value of non-cash contributions ( meaning, property or services) that:
(1) Benefit a project or program funded by a Federal award; and
(2) Are contributed by non-Federal third parties, without charge, to a recipient or subrecipient under a Federal award.
Unliquidated financial obligation means financial obligations incurred by the recipient or subrecipient but not paid (liquidated) for financial reports prepared on a cash basis. For reports prepared on an accrual basis, these are financial obligations incurred by the recipient or subrecipient but for which expenditures have not been recorded.
Unobligated balance means the amount of funds under a Federal award that the recipient or subrecipient has not obligated. The amount is computed by subtracting the cumulative amount of the recipient's or subrecipient's unliquidated financial obligations and expenditures under the Federal award from the cumulative amount of funds the Federal agency or pass-through entity authorized the recipient or subrecipient to obligate.
Voluntary committed cost sharing means cost sharing specifically pledged voluntarily in the proposal's budget on the part of the recipient or subrecipient, which becomes a binding requirement of the Federal award. See § 200.306.

Subpart B—General Provisions
§ 200.100
Purpose.
(a) Purpose. (1) This part establishes uniform administrative requirements, cost principles, and audit requirements for Federal awards. Federal agencies must not impose additional requirements except as allowed in §§ 200.102, 200.211, or unless specifically required by Federal statute, regulation, or Executive order.
(2) This part provides Federal agencies with the policy for collecting and submitting information on all Federal financial assistance programs to the Office of Management and Budget (OMB) and communicating this information to the public. It also establishes Federal policies related to the delivery of this information to the public, including through the use of electronic media. It also sets forth how the General Services Administration (GSA), OMB, and Federal agencies implement the Federal Program Information Act (31 U.S.C. 6101-6106).
(b) Administrative requirements. Subparts B through D set forth the uniform administrative requirements for Federal financial assistance. This includes establishing requirements for Federal agencies management of Federal financial assistance programs before a Federal award is made, and requirements that Federal agencies may impose on recipients and subrecipients throughout the lifecycle of a Federal award.
(c) Cost principles. Subpart E establishes principles for determining allowable costs incurred by recipients and subrecipients under Federal awards. These principles are for the purpose of cost determination. They do not address the circumstances nor dictate the extent of Federal Government funding of a particular program or project.
(d) Single Audit Requirements and Audit Follow-up. Subpart F is issued pursuant to the Single Audit Act Amendments of 1996 (31 U.S.C. 7501-7507). Subpart F sets forth the standards for achieving consistency and uniformity among Federal agencies for the audit of non-Federal entities expending Federal awards. Subpart F also provides the policies and procedures for Federal agencies or pass-through entities when using the results of these audits.
§ 200.101
Applicability.
(a) General applicability to Federal agencies. (1) Subparts A through F apply to Federal agencies that make Federal awards to non-Federal entities. As provided in paragraph (a)(2), subparts A through E may also apply to Federal agencies that make Federal awards to other entities.
(2) Federal agencies must apply subparts A though F of this part to non-Federal entities unless a particular section of this part or Federal statute provides otherwise. Federal agencies may apply subparts A through E of this part to Federal agencies, for-profit organizations, foreign public entities, or foreign organizations as permitted in agency regulations or program statutes, except when a Federal agency determines that the application of these subparts would be inconsistent with the international responsibilities of the United States or the laws of a foreign government. Subpart F only applies to non-Federal entities as defined in the Single Audit Act Amendments of 1996 (31 U.S.C. 7501-7507). Federal agencies should apply the requirements to all recipients in a consistent and equitable manner to the extent permitted within applicable statutes, regulations, and policies.
(3) Throughout subparts A through F, the word “must” indicates a requirement. The words “should” or “may” indicate a recommended approach and permit discretion.
(4) Throughout subparts A through E, when the word “or” is used between the terms “recipient” and “subrecipient,” any requirements or recommendations in the relevant provisions of this part apply to the recipient, the subrecipient, or both, as applicable. The use of “or” between recipient and subrecipient does not mean that applicable requirements or recommendations only apply to one of these entities unless the context clearly indicates otherwise.
(b) Applicability to Federal financial assistance. (1) Paragraphs (b)(2) through (b)(5) of this section describe what portions of this part apply to specific types of Federal financial assistance. Paragraphs (d) and (e) of this section explain additional exceptions related to governing provisions and Federal program applicability. The terms and conditions of Federal awards (including this part) flow down to subawards to subrecipients unless a particular section of this part or the terms and conditions of the Federal award specifically indicate otherwise. Pass-through entities must comply with the requirements described in subpart D, §§ 200.331 through 200.333, and any other sections of this part addressing pass-through entities.
(2) Subpart A (Acronyms and Definitions) and subpart B (General Provisions) apply to all Federal financial assistance, except that §§ 200.111 (English language), 200.112 (Conflict of interest), and 200.113 (Mandatory disclosures) do not apply to agreements for loans, loan guarantees, interest subsidies, and insurance.
(3) Subpart C (Pre-Federal Award Requirements and Contents of Federal Awards) and subpart D (Post Federal Award Requirements) only apply to grants and cooperative agreements with the following exceptions:
(i) Section 200.203 (Requirement to provide public notice of Federal financial assistance programs) also applies to agreements for loans, loan guarantees, interest subsidies, and insurance;
(ii) Section 200.216 (Prohibition on certain telecommunications and video surveillance equipment or services) applies to loans and grants (see Pub. L. 115-232, Div. A, Title VIII, § 889, as amended); and
(iii) Sections 200.303 (Internal controls) and 200.331 through 200.333 (Subrecipient monitoring and management) also apply to all types of Federal financial assistance.
(4) Subpart E (Cost Principles) applies to grants and cooperative agreements, but does not apply to the following:
(i) Food commodities provided through grants and cooperative agreements;
(ii) Fixed amount awards, except for §§ 200.400(g), 200.402 through 200.405, and 200.407(d), which do apply;
(iii) Agreements for loans, loan guarantees, interest subsidies, and insurance; and
(iv) Federal awards to hospitals (see Appendix IX—Hospital Cost Principles).
(5) Subpart F (Audit Requirements) only applies to the following items when awarded to a non-Federal entity:
(i) Grants and cooperative agreements (including fixed amount awards);
(ii) Contracts and subcontracts awarded under the FAR (except for fixed price contracts and subcontracts);
(iii) Agreements for loans, loan guarantees, interest subsidies, and insurance; and
(iv) Any other form of Federal financial assistance as defined by the Single Audit Act Amendment of 1996 (codified at 31 U.S.C. 7501-7507).
(c) Applicability to different types of contracts and subcontracts awarded by a Federal agency to a non-Federal entity under the Federal Acquisition Regulations (FAR). (1) Paragraphs (c)(2) and (c)(3) of this section describe what portions of this part apply to specific types of contracts and subcontracts awarded by a Federal agency to a non-Federal entity. See also paragraph (b)(5)(ii) on audit requirements. For both paragraphs (c)(2) and (c)(3):
(i) In cases of conflict between the requirements of applicable portions of this part and the terms and conditions of the contract, the terms and conditions of the contract and the FAR prevail.
(ii) When the Cost Accounting Standards (CAS) are applicable to the contract or subcontract, they also take precedence over this part.
(iii) In addition, costs that are identified as unallowable under 41 U.S.C. 4304(a) and as stated in the FAR (48 CFR part 31, subpart 31.2, and 48 CFR 31.603) are always unallowable.
(2) Cost-reimbursement contract under the FAR awarded to a non-Federal entity. When a non-Federal entity is awarded a cost-reimbursement contract under the FAR, only subpart D, §§ 200.331 through 200.333, and subparts E and F are applicable.
(3) Fixed-price contract or subcontract under the FAR awarded to a non-Federal entity. When a non-Federal entity is awarded a fixed-price contract or subcontract under the FAR, only subpart A, subpart B (except for §§ 200.111, 200.112, and 200.113), subpart D (only at § 200.303 and §§ 200.331 through 200.333), and subpart E are applicable to the contract, except that subpart E is not applicable to fixed-price contracts and subcontracts that are not negotiated.
(d) Governing provisions. With the exception of subpart F, which is required by the Single Audit Act, Federal statutes or regulations govern in any circumstances where they conflict with the provisions of this part. For agreements with Indian Tribes, this includes the provisions of the Indian Self-Determination and Education and Assistance Act (ISDEAA), as amended (see 25 U.S.C. 5301-5423).
(e) Program applicability. Except for §§ 200.203, 200.216, and 200.331 through 200.333, the requirements in subparts C, D, and E do not apply to the following programs:
(1) The block grant awards authorized by the Omnibus Budget Reconciliation Act of 1981 (including Community Services), except to the extent that subpart E apply to subrecipients of Community Services Block Grant funds pursuant to 42 U.S.C. 9916(a)(1)(B);
(2) Federal awards to local education agencies under 20 U.S.C. 7702-7703b, (portions of the Impact Aid program);
(3) Payments under the Department of Veterans Affairs' State Home Per Diem Program (38 U.S.C. 1741); and
(4) Federal awards authorized under the Child Care and Development Block Grant Act of 1990, as amended:
(i) Child Care and Development Block Grant (42 U.S.C. 9858).
(ii) Child Care Mandatory and Matching Funds of the Child Care and Development Fund (42 U.S.C. 9858).
(f) Additional program applicability. Except for §§ 200.203 and 200.216, the guidance in subpart C does not apply to the following programs:
(1) Entitlement Federal awards to carry out the following programs of the Social Security Act:
(i) Temporary Assistance for Needy Families (Title IV-A of the Social Security Act, 42 U.S.C. 601-619);
(ii) Child Support Enforcement and Establishment of Paternity (Title IV-D of the Social Security Act, 42 U.S.C. 651-669b);
(iii) Federal Payments for Foster Care, Prevention, and Permanency (Title IV-E of the Act, 42 U.S.C. 670-679c);
(iv) Aid to the Aged, Blind, and Disabled (Titles I, X, XIV, and XVI-AABD of the Act, as amended);
(v) Medical Assistance (Medicaid) (Title XIX of the Act, 42 U.S.C. 1396-1396w-5) not including the State Medicaid Fraud Control program authorized by Section 1903(a)(6)(B) of the Social Security Act (42 U.S.C. 1396b(a)(6)(B)); and
(vi) Children's Health Insurance Program (Title XXI of the Act, 42 U.S.C. 1397aa-1397mm).
(2) A Federal award for an experimental, pilot, or demonstration project that is also supported by a Federal award listed in paragraph (f)(1) of this section.
(3) Federal awards under subsection 412(e) of the Immigration and Nationality Act and subsection 501(a) of the Refugee Education Assistance Act of 1980 (Pub. L. 96-422, 94 Stat. 1809), for cash assistance, medical assistance, and supplemental security income benefits to refugees and entrants and the administrative costs of providing the assistance and benefits (8 U.S.C. 1522(e)).
(4) Entitlement awards under the following programs of The National School Lunch Act:
(i) National School Lunch Program (Section 4 of the Act, 42 U.S.C. 1753);
(ii) Commodity Assistance (Section 6 of the Act, 42 U.S.C. 1755);
(iii) Special Meal Assistance (Section 11 of the Act, 42 U.S.C. 1759a);
(iv) Summer Food Service Program for Children (Section 13 of the Act, 42 U.S.C. 1761); and
(v) Child and Adult Care Food Program (Section 17 of the Act, 42 U.S.C. 1766).
(5) Entitlement awards under the following programs of The Child Nutrition Act of 1966:
(i) Special Milk Program (Section 3 of the Act, 42 U.S.C. 1772);
(ii) School Breakfast Program (Section 4 of the Act, 42 U.S.C. 1773); and
(iii) State Administrative Expenses (Section 7 of the Act, 42 U.S.C. 1776).
(6) Entitlement awards for State Administrative Expenses under The Food and Nutrition Act of 2008 (Section 16 of the Act, 7 U.S.C. 2025).
(7) Non-discretionary Federal awards under the following non-entitlement programs:
(i) Special Supplemental Nutrition Program for Women, Infants and Children (Section 17 of the Child Nutrition Act of 1966) 42 U.S.C. 1786;
(ii) The Emergency Food Assistance Programs (Emergency Food Assistance Act of 1983) 7 U.S.C. 7501 note; and
(iii) Commodity Supplemental Food Program (Section 5 of the Agriculture and Consumer Protection Act of 1973) 7 U.S.C. 612c note.
§ 200.102
Exceptions.
(a) OMB class exceptions. Except for subpart F, OMB may allow exceptions from requirements of this part for classes of Federal awards, recipients, or subrecipients when the exceptions are not prohibited by statute. For example, Federal agencies may request exceptions in support of innovative program designs that apply a risk-based, data-driven framework to alleviate select compliance requirements and hold recipients accountable for good performance. See also § 200.206. Federal agencies may also request exceptions in emergency situations. When OMB allows an exception to requirements of this part, the Federal agency remains responsible for ensuring the exception is applied to Federal awards in a manner consistent with Federal statutes and regulations.
(b) Statutory and regulatory exceptions. A Federal agency may adjust requirements to a class of Federal awards, recipients, or subrecipients when required by Federal statutes or regulations, except for the requirements in subpart F. Except for provisions in subpart F, when a Federal statute requires exceptions to requirements of this part for a class of Federal awards, recipients, or subrecipients, a Federal agency does not need OMB approval to allow those exceptions. See also § 200.106.
(c) Federal agency exceptions. Federal agencies may allow exceptions to requirements of this part on a case-by-case basis for individual Federal awards, recipients, or subrecipients, except when the exceptions are prohibited by law or other approval is expressly required by this part. Only the cognizant agency for indirect costs may authorize exceptions related to cost allocation plans or indirect cost rate proposals. A Federal agency may also apply less restrictive requirements when issuing fixed amount awards (see § 200.1), except for those requirements imposed by statute or in subpart F.
§ 200.103
Authorities.
This part is issued under the following authorities.
(a) Subparts B through D are authorized under 31 U.S.C. 503 (the Chief Financial Officers Act, Functions of the Deputy Director for Management); the Federal Program Information Act (Pub, L. 95-220 and Pub. L. 98-169, as amended, codified at 31 U.S.C. 6101-6106); the Federal Grant and Cooperative Agreement Act of 1977 (Pub. L. 95-224, as amended, codified at 31 U.S.C. 6301-6309); 41 U.S.C. 1101-1131 (the Office of Federal Procurement Policy Act); Reorganization Plan No. 2 of 1970 and Executive Order 11541 (“Prescribing the Duties of the Office of Management and Budget and the Domestic Policy Council in the Executive Office of the President”); and the Single Audit Act Amendments of 1996 (31 U.S.C. 7501-7507).
(b) Subpart E is authorized under the Budget and Accounting Act of 1921, as amended; the Budget and Accounting Procedures Act of 1950, as amended (31 U.S.C. 1101-1126); the Chief Financial Officers Act of 1990 (31 U.S.C. 503-504); Reorganization Plan No. 2 of 1970; and Executive Order 11541, “Prescribing the Duties of the Office of Management and Budget and the Domestic Policy Council in the Executive Office of the President.” OMB also relies on authority under 31 U.S.C. 503 and 31 U.S.C. 6307.
(c) Subpart F is authorized under the Single Audit Act Amendments of 1996 (codified at 31 U.S.C. 7501-7507). OMB also relies on authority under 31 U.S.C. 503 and 31 U.S.C. 6307.
§ 200.104
Supersession.
This part superseded previous OMB guidance issued under Title 2, subtitle A, chapter II of the Code of Federal Regulations and certain OMB circulars related to uniform administrative requirements, cost principles, and audit requirements for Federal awards.
§ 200.105
Effect on other issuances.
(a) Superseding inconsistent requirements. For Federal awards made subject to this part by a Federal agency, this part takes precedence over any administrative requirements, program manuals, handbooks, and other non-regulatory materials that are inconsistent with the requirements of this part upon implementation by the Federal agency, except to the extent that they are required by statute or authorized in accordance with § 200.102.
(b) Imposition of requirements on recipients. Agencies may only impose legally binding requirements on recipients and subrecipients through:
(1) Notice and public comment procedures through an approved agency process, including as authorized by this part, other statutes, or regulations; or
(2) Incorporating requirements into the terms and conditions of a Federal award as permitted by Federal statute, regulation, or this part.
§ 200.106
Agency implementation.
The specific requirements and responsibilities of Federal agencies, non-Federal entities, recipients, and subrecipients are set forth in this part. Federal agencies making Federal awards to non-Federal entities must implement the language in subparts C through F of this part in codified regulations unless different provisions are required by Federal statute or are approved by OMB.
§ 200.107 OMB
responsibilities.
OMB will review Federal agency regulations and implementation of this part. OMB will provide interpretations of policy requirements and assistance to ensure effective, efficient, and consistent implementation. Any exceptions will be subject to approval by OMB and only with adequate justification from the Federal agency.
§ 200.108
Inquiries.
Inquiries from Federal agencies concerning this part may be directed to OMB. Inquiries from recipients or subrecipients should be addressed to the Federal agency, the cognizant agency for indirect costs, the cognizant agency for audit, or the pass-through entity as appropriate.
§ 200.109
Review date.
OMB will review this part periodically.
§ 200.110
Effective date.
(a) The standards set forth in this part affecting the administration of Federal awards by Federal agencies become effective once implemented by Federal agencies or when any future amendment to this part becomes final.
(b) Existing negotiated indirect cost rates will remain in place until they expire. The effective date of changes to indirect cost rates must be based upon the date a newly re-negotiated rate goes into effect for the recipient's or subrecipient's fiscal year. Therefore, for indirect cost rates and cost allocation plans, the revisions to this part (as of the publication date for revisions to this guidance) become effective in generating proposals and negotiating a new rate (when the rate is re-negotiated).
§ 200.111
English language.
(a) All Federal financial assistance announcements, applications, and Federal award information should be in the English language and must be in terms of U.S. dollars. However, Federal agencies, recipients, and subrecipients may issue or translate a Federal award or other documents into another language. A Federal agency may translate formal or informal announcements of the availability of Federal funding through a financial assistance program, such as a notice of funding opportunity, when translations may serve to increase the pool of applicants or the participation of a specific community (for example, programs administered in foreign countries where the primary language is not English). Federal agencies must maintain an official controlling English version of the Federal financial assistance announcement and the Federal award, including the terms and conditions.(b) Applications, reports, and official correspondence may be submitted in languages other than English if specified in the notice of funding opportunity or the terms and conditions of the Federal award.
(c) In the event of inconsistency between English and another language, the English language meaning will control. When a significant portion of the recipient's or subrecipient's employees administering a Federal award are not fluent in English, the Federal award should be provided in English and the language(s) with which employees are more familiar.
§ 200.112
Conflict of interest.
Federal agencies must establish conflict of interest policies for Federal awards. A recipient or subrecipient must disclose in writing any potential conflict of interest to the Federal agency or pass-through entity in accordance with the established Federal agency policies.
§ 200.113
Mandatory disclosures.
An applicant, recipient, or subrecipient of a Federal award must promptly disclose whenever, in connection with the Federal award (including any activities or subawards thereunder), it has credible evidence of the commission of a violation of Federal criminal law involving fraud, conflict of interest, bribery, or gratuity violations found in Title 18 of the United States Code or a violation of the civil False Claims Act (31 U.S.C. 3729-3733). The disclosure must be made in writing to the Federal agency, the agency's Office of Inspector General, and pass-through entity (if applicable). Recipients and subrecipients are also required to report matters related to recipient integrity and performance in accordance with Appendix XII of this part. Failure to make required disclosures can result in any of the remedies described in § 200.339. (See also 2 CFR part 180, 31 U.S.C. 3321, and 41 U.S.C. 2313.)

Subpart C—Pre-Federal Award Requirements and Contents of Federal Awards
§ 200.200
Purpose.
Sections 200.201 through 200.217 prescribe instructions and other pre-award matters to be used by Federal agencies in the program planning, announcement, application, and award processes.
§ 200.201
Use of grants, cooperative agreements, fixed amount awards, and contracts.
(a) Federal awards. The Federal agency or pass-through entity must decide on the appropriate type of agreement for a Federal award (for example, a grant, cooperative agreement, subaward, or contract) in accordance with this guidance. See the Federal Grant and Cooperative Agreement Act (31 U.S.C. 6301-6309).
(b) Fixed amount awards. The Federal agency or pass-through entity (see § 200.333) may use fixed amount awards (see the definition of fixed amount awards in § 200.1) for which the following conditions apply:
(1) The Federal award amount is negotiated using the cost principles (or other pricing information) as a guide. See § 200.101(b)(4)(ii) for further information on which provisions in subpart E (cost principles) apply to fixed amount awards. The Federal agency or pass-through entity may use fixed amount awards if the project scope has measurable goals and objectives and if accurate cost, historical, or unit pricing data is available to establish a fixed budget based on a reasonable estimate of actual costs. Budgets for fixed amount awards are negotiated with the recipient or subrecipient and the total amount of Federal funding is determined in accordance with the recipient's or subrecipient's proposal, available pricing data, and subpart E. Accountability must be based on performance and results, which can be communicated in performance reports or through routine monitoring. There is no expected routine monitoring of the actual costs incurred by the recipient or subrecipient under the Federal award. Therefore, no financial reporting is required. This does not absolve the recipient or subrecipient from the record retention requirements contained in §§ 200.334 through 200.338; nor does it absolve the recipient or subrecipient of the responsibilities of making records available for review during an audit. See § 200.101(b)(5)(i). Payments must be based on meeting specific requirements of the Federal award. Some of the ways in which the Federal award may be paid include, but are not limited to:
(i) In several partial payments. The amount of each payment as well as the “milestone” or event triggering the payment, should be agreed to in advance and included in the Federal award;
(ii) On a unit price basis. The defined unit(s) or price(s) should be agreed to in advance and included in the Federal award; or
(iii) In one payment at the completion of the Federal award.
(2) A fixed amount award must not be used in programs that require cost sharing.
(3) A fixed amount award may generate and use program income in accordance with the terms and conditions of the Federal award; however, the requirements of § 200.307 do not apply.
(4) At the end of a fixed amount award, the recipient or subrecipient must certify in writing to the Federal agency or pass-through entity that the project was completed as agreed to in the Federal award, or identify those activities that were not completed, and that all expenditures were incurred in accordance with § 200.403. When the required activities were not carried out, including fixed amount awards paid on a unit price basis under 200.201(b)(1)(ii), the amount of the Federal award must be reduced by the amount that reflects the activities that were not completed in accordance with the Federal award. When the required activities were completed in accordance with the terms and conditions of the Federal award, the recipient or subrecipient is entitled to any unexpended funds.
(5) Periodic reports may be established for fixed amount awards.
(6) Prior approval requirements that apply to fixed amount awards are § 200.308(f) (paragraphs 1 through 3, 6 through 8, and 10) and § 200.333.
§ 200.202
Program planning and design.
(a) The Federal agency must design a program and create an Assistance Listing before announcing the Notice of Funding Opportunity. A program must be designed:
(1) With clear goals and objectives that provide meaningful results and be consistent with the Federal authorizing legislation of the program;
(2) To measure performance based on the goals and objectives developed during program planning and design. Performance measures may differ depending on the type of program. See § 200.301 for more information on performance measurement;
(3) To align with the strategic goals and objectives within the Federal agency's performance plan and support the Federal agency's performance measurement, management, customer service initiatives, and reporting as required by Part 6 of OMB Circular A-11 (Preparation, Submission, and Execution of the Budget);
(4) To align with the Program Management Improvement Accountability Act (Pub. L. 114-264) as well as the Foundations for Evidence-Based Policymaking Act (Pub. L. 115-435), as applicable; and
(5) To encourage applicants to engage, when practicable, during the design phase, members of the community that will benefit from or be impacted by a program.
(b) Federal agencies should develop programs in consultation with communities benefiting from or impacted by the program. In addition, Federal agencies should consider available data, evidence, and evaluation results from past programs and make every effort to extend eligibility requirements to all potential applicants. Federal agencies are encouraged to coordinate with other agencies during program planning and design, particularly when the goals and objectives of a program or project align with those of other agencies.
§ 200.203
Requirement to provide public notice of Federal financial assistance programs.
(a) The Federal agency must maintain an accurate list of Federal programs in the Assistance Listings maintained by the General Services Administration (GSA) at SAM.gov.
(1) The Assistance Listings is the comprehensive government-wide source of Federal financial assistance program information produced by the executive branch of the Federal Government.
(2) The information that the Federal agency must submit to GSA for approval by OMB is listed in paragraph (b). GSA must prescribe the format for the submission in coordination with OMB.
(3) The Federal agency must assign the appropriate Assistance Listing before making the Federal award unless exigent circumstances require otherwise (for example, timing requirements imposed by a Federal statute).
(b) To the extent practicable, the Federal agency must create, update, and manage Assistance Listing entries based on the authorizing statute for the program and comply with additional guidance provided by GSA (in consultation with OMB) to ensure consistent and accurate information is available to prospective applicants. Assistance Listings should be communicated to the public in plain language. Accordingly, Federal agencies must submit the following information to GSA when creating an Assistance Listing:
(1) Program Description, Purpose, Goals, and Measurement. A brief summary of the statutory or regulatory requirements of the program and its intended outcome. Where appropriate, the program description, purpose, goals, and performance measurement should align with the strategic goals and objectives within the Federal agency's performance plan and should support the Federal agency's performance measurement, management, customer experience initiatives, and reporting as required by Part 6 of OMB Circular A-11;
(2) Identification. Identification of whether the program will issue Federal awards on a discretionary or non-discretionary basis;
(3) Projected total amount of funds available for the program. Estimates based on previous year funding are acceptable if current appropriations are not available at the time of the submission;
(4) Anticipated source of available funds. The statutory authority for funding the program and the agency, sub-agency, or specific program unit that will issue the Federal awards (to the extent possible) and associated funding identifier (for example, Treasury Account Symbol(s));
(5) General eligibility requirements. The statutory, regulatory, or other eligibility factors or considerations that determine the applicant's qualification for Federal awards under the program (for example, type of recipient); and
(6) Applicability of Single Audit Requirements. Applicability of Single Audit Requirements as required by subpart F.
§ 200.204
Notices of funding opportunities.
The Federal agency must announce specific funding opportunities for Federal financial assistance that will be openly competed. The term openly competed means opportunities that are not directed to one or more specifically identified applicants. To the extent possible, the Federal agency should communicate opportunities to the public in plain language to ensure the announcement is accessible to diverse communities of eligible applicants, including underserved communities. The Federal agency should also make efforts to limit the length and complexity of the announcement and only include the information that is necessary for the effective communication of the program objectives. Federal agencies may offer pre-application technical assistance or provide clarifying information for funding opportunities. However, Federal agencies must ensure these resources are made accessible and widely available to all potential applicants (for example, by posting answers to questions and requests on Grants.gov ). The Federal agency should make every effort to identify in the NOFO all eligible applicants (for example, different types of nonprofit organizations such as labor unions and tribal organizations). The following information must be provided in a public notice:
(a) Summary information in notices of funding opportunities. The Federal agency must display the following information on Grants.gov, in a location preceding the full text of the announcement:
(1) Federal Agency Name;
(2) Funding Opportunity Title;
(3) Announcement Type (whether the funding opportunity is the initial announcement or a modification of a previously announced opportunity);
(4) Funding Opportunity Number (required, if the Federal agency has assigned a number to the funding opportunity announcement);
(5) Assistance Listing Number(s);
(6) Funding Details. To the extent appropriate, the total amount of funding that the Federal agency expects to award, the anticipated number of awards, and the expected dollar values of individual awards, which may be a range or average;
(7) Key Dates. Key dates include due dates for submitting applications or Executive Order 12372 submissions, as well as for any letters of intent or preapplications. For any announcement issued before a program's application materials are available, key dates also include the date on which those materials will be released; and any other additional information, as deemed applicable by the Federal agency. If possible, the Federal agency should provide an anticipated award date. If the NOFO states that applications will be evaluated on a “rolling” basis (that is, at different points during a specified period of time), the Federal agency should provide an estimate of the time needed to process an application and notify the applicant of the Federal agency's decision;
(8) Executive Summary. A brief description that is written in plain language and summarizes the goals and objectives of the program, the target audience, and eligible applicants. The text of the executive summary should not exceed 500 words; and
(9) Agency contact information.
(b) Availability period. The Federal agency should make all funding opportunities available for application for at least 60 calendar days. However, the Federal agency may modify the availability period of an opportunity as needed. For example, extending the period may be necessary to provide technical assistance to an applicant pool that was not anticipated when the announcement was made or has less experience with applying for Federal financial assistance. The Federal agency may also determine that an availability period of less than 60 days is sufficient for a particular funding opportunity. However, no funding opportunity should be available for less than 30 calendar days unless the Federal agency determines that exigent circumstances justify this.
(c) Full text of funding opportunities. (1) The Federal agency must include the information in Appendix I for every funding opportunity.
(2) Federal agencies should ensure that funding opportunities are written using plain language. To the extent possible Federal agencies must streamline opportunities to make them accessible, particularly for funding opportunities that are new, targeted to underserved communities, or intended to reach inexperienced applicants.
(3) To reduce application burden, Federal agencies should consider whether programmatic or administrative requirements specific to the agency, program, or funding opportunity must be met at the time of application or as a requirement of receiving a Federal award.
§ 200.205
Federal agency review of merit of proposals.
Unless prohibited by Federal statute, the Federal agency must design and execute a merit review process of applications for discretionary Federal awards. The objective of a merit review process is to select recipients most likely to be successful in delivering results based on the program objectives as outlined in section § 200.202. A merit review is an objective process of evaluating Federal award applications in accordance with the written standards of the Federal agency. These standards should identify the number of people the agency requires to participate in the merit review process and provide opportunities for a diverse group of participants, including those representing underserved communities. The merit review process explained in this section must be described or incorporated by reference in the applicable funding opportunity. See appendix I to this part. See also § 200.204. The Federal agency must also periodically review its merit review process.
§ 200.206
Federal agency review of risk posed by applicants.
(a) Review of OMB-designated repositories of government-wide data. (1) Prior to making a Federal award, the Federal agency is required to review eligibility information for applicants and financial integrity information for applicants available in OMB-designated databases per the Payment Integrity Information Act of 2019 (Pub. L. 116-117), the “Do Not Pay Initiative” (31 U.S.C. 3354), and 41 U.S.C. 2313.
(2) The Federal agency is required to review the responsibility and qualification records available in the non-public segment of the System for Award Management ( SAM.gov ) prior to making a Federal award where the Federal share is expected to exceed the simplified acquisition threshold, defined at 41 U.S.C. 134, over the period of performance. See 41 U.S.C. 2313. The Federal agency must consider all of the information available in SAM.gov with regard to the applicant and any immediate highest-level owner, predecessor (meaning, an organization that is replaced by a successor), or subsidiary, identified for that applicant in SAM.gov . See Public Law 112-239, National Defense Authorization Act for Fiscal Year 2013; 41 U.S.C. 2313(d). The information in the system for a prior recipient of a Federal award must demonstrate a satisfactory record of administering programs or activities under Federal financial assistance or procurement awards, and integrity and business ethics. The Federal agency may make a Federal award to a recipient that does not fully meet these standards if it is determined that the information is not relevant to the Federal award under consideration or there are specific conditions that can appropriately mitigate the risk associated with the recipient in accordance with § 200.208.
(b) Risk Assessment. (1) The Federal agency must establish and maintain policies and procedures for conducting a risk assessment to evaluate the risks posed by applicants before issuing Federal awards. This assessment helps identify risks that may affect the advancement toward or the achievement of a project's goals and objectives. Risk assessments assist Federal managers in determining appropriate resources and time to devote to project oversight and monitor recipient progress. This assessment may incorporate elements such as the quality of the application, award amount, risk associated with the program, cybersecurity risks, fraud risks, and impacts on local jobs and the community. If the Federal agency determines that the Federal award will be made, specific conditions that address the assessed risk may be implemented in the Federal award. The risk criteria to be evaluated must be described in the announcement of the funding opportunity described in § 200.204.
(2) In evaluating risks posed by applicants, the Federal agency should consider the following items:
(i) Financial stability. The applicant's record of effectively managing financial risks, assets, and resources;
(ii) Management systems and standards. Quality of management systems and ability to meet the management standards prescribed in this part;
(iii) History of performance. The applicant's record of managing previous and current Federal awards, including compliance with reporting requirements and conformance to the terms and conditions of Federal awards, if applicable;
(iv) Audit reports and findings. Reports and findings from audits performed under subpart F or the reports and findings of any other available audits, if applicable; and
(v) Ability to effectively implement requirements. The applicant's ability to effectively implement statutory, regulatory, or other requirements imposed on recipients of Federal awards.
(c) Adjustments to the Risk Assessment. The Federal agency may modify the risk assessment at any time during the period of performance, which may justify changes to the terms and conditions of the Federal award. See § 200.208.
(d) Suspension and debarment compliance. The Federal agency must comply with the government-wide suspension and debarment guidance in 2 CFR part 180 and individual Federal agency suspension and debarment requirements in title 2 of the Code of Federal Regulations. Federal agencies must also require recipients to comply with these requirements. These requirements restrict making Federal awards, subawards, and contracts with certain parties that are debarred, suspended, or otherwise excluded from receiving Federal awards or participating in Federal awards.
§ 200.207
Standard application requirements.
(a) Paperwork clearances. The Federal agency may only use application information collections approved by OMB under the Paperwork Reduction Act of 1995 and OMB's implementing regulations in 5 CFR part 1320 and in alignment with OMB-approved, government-wide data elements available from the OMB-designated standards lead. Examples of application information collections approved by OMB include the Standard Forms 424 (SF-424), which is available on Grants.gov , and the Biographical Sketch Common Form (OMB Control Number 3145-0279), which Federal agencies should use to collect biographical sketches and other disclosure information from award applicants. OMB will authorize additional information collections only on a limited basis and consistent with these requirements.
(b) Information collection. The Federal agency may inform applicants that they do not need to provide certain information already being collected through other means.
§ 200.208
Specific conditions.
(a) Federal agencies are responsible for ensuring that specific Federal award conditions and performance expectations are consistent with the program design (See § 200.202 and § 200.301).
(b) The Federal agency or pass-through entity may adjust specific conditions in the Federal award based on an analysis of the following factors:
(1) Review of OMB-designated repositories of government-wide data (for example, SAM.gov ) or review of its risk assessment (See § 200.206);
(2) The recipient's or subrecipient's history of compliance with the terms and conditions of Federal awards;
(3) The recipient's or subrecipient's ability to meet expected performance goals as described in § 200.211; or
(4) A determination of whether a recipient or subrecipient has inadequate financial capability to perform the Federal award.
(c) Specific conditions may include the following:
(1) Requiring payments as reimbursements rather than advance payments;
(2) Withholding authority to proceed to the next phase until receipt of evidence of acceptable performance;
(3) Requiring additional or more detailed financial reports;
(4) Requiring additional project monitoring;
(5) Requiring the recipient or subrecipient to obtain technical or management assistance; or
(6) Establishing additional prior approvals.
(d) Prior to imposing specific conditions, the Federal agency or pass-through entity must notify the recipient or subrecipient as to:
(1) The nature of the specific condition(s);
(2) The reason why the specific condition(s) is being imposed;
(3) The nature of the action needed to remove the specific condition(s);
(4) The time allowed for completing the actions; and
(5) The method for requesting the Federal agency or pass-through entity to reconsider imposing a specific condition.
(e) Any specific conditions must be promptly removed once the conditions that prompted them have been satisfied.
§ 200.209
Certifications and representations.
Unless prohibited by the U.S. Constitution, Federal statutes, or regulations, a Federal agency or pass-through entity is authorized to require a recipient to submit annual certifications and representations. Submission may be required more frequently if a recipient or subrecipient fails to meet a requirement of a Federal award. When a recipient is provided an exception to the requirements of 2 CFR 25.110, the recipient must submit the appropriate assurance form (for example, SF-424B).
§ 200.210
Pre-award costs.
For requirements on costs incurred by the applicant prior to the start date of the period of performance of the Federal award, see § 200.458.
§ 200.211
Information contained in a Federal award.
The Federal award must include the following information:
(a) Federal award performance goals. Where applicable, performance goals, indicators, targets, and baseline data must be included in the Federal award. The Federal agency must also specify in the terms and conditions of the Federal award how performance will be assessed, including the timing and scope of expected performance. See §§ 200.202 and 200.301 for more information on Federal award performance goals.
(b) General Federal award information. The Federal agency must include the following information in each Federal award:
(1) Recipient Name (which must match the name associated with its unique entity identifier as defined at 2 CFR 25.400);
(2) Recipient's Unique Entity Identifier;
(3) Unique Federal Award Identification Number (FAIN);
(4) Federal Award Date (see Federal award date in § 200.1);
(5) Period of Performance Start and End Date;
(6) Budget Period Start and End Date;
(7) Amount of Federal Funds Obligated by this Action;
(8) Total Amount of Federal Funds Obligated;
(9) Total Approved Cost Sharing, where applicable;
(10) Total Amount of the Federal Award including approved Cost Sharing;
(11) Budget Approved by the Federal Agency;
(12) Federal Award Description (to comply with statutory requirements (for example, FFATA));
(13) Name of the Federal agency (including contact information for the awarding official);
(14) Assistance Listings Number and Title;
(15) Identification of whether the Award is R&D; and
(16) Indirect Cost Rate for the Federal award (including if the de minimis rate is charged per § 200.414).
(c) General terms and conditions. (1) Federal agencies must incorporate the following general terms and conditions either in the Federal award or by reference, as applicable:
(i) Administrative requirements. Administrative requirements implemented by the Federal agency as specified in this part.
(ii) National policy requirements. These include statutory, executive order, other Presidential directive, or regulatory requirements that apply by specific reference and are not program-specific. See § 200.300 Statutory and national policy requirements.
(iii) Recipient integrity and performance matters. When the total Federal share of the Federal award may include more than $500,000 over the period of performance, the Federal agency must include the terms and conditions available in Appendix XII. See also § 200.113.
(iv) Future budget periods. When it is anticipated that the period of performance will include multiple budget periods, the Federal agency must indicate that subsequent budget periods are subject to the availability of funds, program authority, satisfactory performance, and compliance with the terms and conditions of the Federal award.
(v) Termination provisions. Federal agencies must inform recipients of the termination provisions in § 200.340, including the applicable termination provisions in the Federal agency's regulations or terms and conditions of the Federal award.
(2) The Federal award must incorporate, by reference, all general terms and conditions of the Federal award, which must be maintained on the Federal agency's website.
(3) The Federal agency must provide a copy of the full text of the general terms and conditions if a recipient requests it.
(4) The Federal agency must maintain an archive of previous versions of the general terms and conditions, with effective dates, for use by a recipient, auditors, or others. The archive should be located on the Federal agency's website in the same place where current terms and conditions are available.
(d) Federal award specific terms and conditions. The Federal agency must include in each Federal award any specific terms and conditions that are in addition to the general terms and conditions. See also § 200.208. For loan and loan guarantee programs, the Federal agency must specify whether or not the Federal award has continuing compliance requirements. Whenever practicable, these specific terms and conditions should also be available on the Federal agency's website and in notices of funding opportunities (as outlined in § 200.204).
(e) Federal agency requirements. Any other information required by the Federal agency.
§ 200.212
Public access to Federal award information.
(a) Except as noted in paragraph (c) of this section, the Federal agency must publish the required Federal award information on USAspending.gov in accordance with the guidance provided by OMB and the U.S. Department of the Treasury's Government-wide Spending Data Model (GSDM).
(b) All responsibility and qualification records posted in SAM.gov will be publicly available after a waiting period of 14 calendar days, except for:
(1) Past performance reviews required by Federal Government contractors (See Federal Acquisition Regulation (FAR) 48 CFR part 42, subpart 42.15);
(2) Information that was entered prior to April 15, 2011; or
(3) Information that is withdrawn during the 14-calendar day waiting period by a Federal agency.
(c) Nothing in this section may be construed as requiring the publication of information otherwise exempt under the Freedom of Information Act (5 U.S.C. 552), or controlled unclassified information pursuant to Executive Order 13556.
§ 200.213
Reporting a determination that an applicant is not qualified for a Federal award.
(a) The Federal agency must report in SAM.gov if it does not make a Federal award to an applicant because it determines that the applicant does not meet the minimum qualification standards as described in § 200.206(a)(2). The Federal agency must report that determination only if all of the following apply:
(1) The only basis for the determination is the applicant's prior record of performance on administering Federal awards or its record of integrity and business ethics, as described in § 200.206(a)(2) (meaning, the applicant was determined to be qualified based on all factors other than those two standards); and
(2) The total Federal share of the Federal award was expected to exceed the simplified acquisition threshold over the period of performance.
(b) The Federal agency is not required to report a determination that an applicant is not qualified for a Federal award if they issue the Federal award in accordance with the requirements of § 200.208.
(c) If the Federal agency reports a determination that an applicant is not qualified for a Federal award, the Federal agency also must notify the applicant that:
(1) The determination was made and reported in SAM.gov . The notification from the Federal agency to the applicant should also provide a brief explanation for the determination;
(2) The information will be kept in the system for a period of five years from the date of the determination and then archived (See section 872 of Public Law 110-417, as amended, codified at 41 U.S.C. 2313);
(3) Each Federal agency that considers making a Federal award to the applicant during that five-year period will consider that information in determining the applicant's qualification to receive a Federal award when the total Federal share of a Federal award is expected to exceed the simplified acquisition threshold over the period of performance;
(4) The applicant may review the responsibility and qualification records accessible in SAM.gov and comment on any information the system contains about the applicant; and
(5) Federal agencies must consider the applicant's comments in determining whether the applicant is qualified for a future Federal award.
(d) If the Federal agency enters information into SAM.gov about a determination that an applicant is not qualified for a Federal award and subsequently:
(1) Learns that any of that information is erroneous, the Federal agency must correct the information in the system within three business days; and
(2) Obtains an update to that information that could be helpful to other Federal agencies, the Federal agency should amend the information in the system within 30 days.
(e) Federal agencies must not post any information that will be made publicly available in the non-public segment of the responsibility and qualification records that is covered by a disclosure exemption under the Freedom of Information Act. If a recipient asserts within seven calendar days to a Federal agency that some or all of the publicly available information is covered by a disclosure exemption under the Freedom of Information Act, the Federal agency that posted the information must remove the posting within seven calendar days of receiving the assertion. Prior to reposting the releasable information, the Federal agency must resolve the issue in accordance with the agency's Freedom of Information Act procedures.
§ 200.214
Suspension and debarment.
Recipients and subrecipients are subject to the nonprocurement debarment and suspension regulations implementing Executive Orders 12549 and 12689, as well as 2 CFR part 180. The regulations in 2 CFR part 180 restrict making Federal awards, subawards, and contracts with certain parties that are debarred, suspended, or otherwise excluded from receiving or participating in Federal awards.
§ 200.215
Never contract with the enemy.
Federal agencies, recipients, and subrecipients are subject to the guidance implementing Never Contract with the Enemy in 2 CFR part 183. The guidance in 2 CFR part 183 affects covered contracts, grants, and cooperative agreements that are expected to exceed $50,000 during the period of performance, are performed outside the United States and its territories, and are in support of a contingency operation in which members of the Armed Forces are actively engaged in hostilities.
§ 200.216
Prohibition on certain telecommunications and video surveillance equipment or services.
(a) Recipients and subrecipients are prohibited from obligating or expending loan or grant funds to:
(1) Procure or obtain covered telecommunications equipment or services;
(2) Extend or renew a contract to procure or obtain covered telecommunications equipment or services; or
(3) Enter into a contract (or extend or renew a contract) to procure or obtain covered telecommunications equipment or services.
(b) As described in section 889 of Public Law 115-232, “covered telecommunications equipment or services” means any of the following:
(1) Telecommunications equipment produced by Huawei Technologies Company or ZTE Corporation (or any subsidiary or affiliate of such entities);
(2) For the purpose of public safety, security of government facilities, physical security surveillance of critical infrastructure, and other national security purposes, video surveillance and telecommunications equipment produced by Hytera Communications Corporation, Hangzhou Hikvision Digital Technology Company, or Dahua Technology Company (or any subsidiary or affiliate of such entities);
(3) Telecommunications or video surveillance services provided by such entities or using such equipment;
(4) Telecommunications or video surveillance equipment or services produced or provided by an entity that the Secretary of Defense, in consultation with the Director of the National Intelligence or the Director of the Federal Bureau of Investigation, reasonably believes to be an entity owned or controlled by, or otherwise connected to, the government of a covered foreign country;
(c) For the purposes of this section, “covered telecommunications equipment or services” also include systems that use covered telecommunications equipment or services as a substantial or essential component of any system, or as critical technology as part of any system.
(d) In implementing the prohibition under section 889 of Public Law 115-232, heads of executive agencies administering loan, grant, or subsidy programs must prioritize available funding and technical support to assist affected businesses, institutions, and organizations as is reasonably necessary for those affected entities to transition from covered telecommunications equipment or services, to procure replacement equipment or services, and to ensure that communications service to users and customers is sustained.
(e) When the recipient or subrecipient accepts a loan or grant, it is certifying that it will comply with the prohibition on covered telecommunications equipment and services in this section. The recipient or subrecipient is not required to certify that funds will not be expended on covered telecommunications equipment or services beyond the certification provided upon accepting the loan or grant and those provided upon submitting payment requests and financial reports.
(f) For additional information, see section 889 of Public Law 115-232 and § 200.471.
§ 200.217
Whistleblower protections.
An employee of a recipient or subrecipient must not be discharged, demoted, or otherwise discriminated against as a reprisal for disclosing to a person or body described in paragraph (a)(2) of 41 U.S.C. 4712 information that the employee reasonably believes is evidence of gross mismanagement of a Federal contract or grant, a gross waste of Federal funds, an abuse of authority relating to a Federal contract or grant, a substantial and specific danger to public health or safety, or a violation of law, rule, or regulation related to a Federal contract (including the competition for or negotiation of a contract) or grant. The recipient and subrecipient must inform their employees in writing of employee whistleblower rights and protections under 41 U.S.C. 4712. See statutory requirements for whistleblower protections at 10 U.S.C. 4701, 41 U.S.C. 4712, 41 U.S.C. 4304, and 10 U.S.C. 4310.

Subpart D—Post Federal Award Requirements
§ 200.300
Statutory and national policy requirements.
(a) The Federal agency or pass-through entity must manage and administer the Federal award in a manner so as to ensure that Federal funding is expended and associated programs are implemented in full accordance with the U.S. Constitution, applicable Federal statutes and regulations—including provisions protecting free speech, religious liberty, public welfare, and the environment, and those prohibiting discrimination—and the requirements of this part. The Federal agency or pass-through entity must communicate to a recipient or subrecipient all relevant requirements, including those contained in general appropriations provisions, and incorporate them directly or by reference in the terms and conditions of the Federal award.
(b) In administering Federal awards that are subject to a Federal statute prohibiting discrimination based on sex, the Federal agency or pass-through entity must ensure that the award is administered in a way that does not unlawfully discriminate based on sexual orientation or gender identity if the statute's prohibition on sex discrimination encompasses discrimination based on sexual orientation and gender identity consistent with the Supreme Court's reasoning in Bostock v. Clayton County, 140 S. Ct. 1731 (2020).
(c) In administering awards in accordance with the U.S. Constitution, the Federal agency must take account of the heightened constitutional scrutiny that may apply under the Constitution's Equal Protection guarantee for government action that provides differential treatment based on protected characteristics.
§ 200.301
Performance measurement.
(a) The Federal agency must measure the recipient's performance to show achievement of program goals and objectives, share lessons learned, improve program outcomes, and foster the adoption of promising practices. The Federal agency should establish program goals and objectives during program planning and design (see § 200.202). The Federal agency should clearly communicate the specific program goals and objectives in the Federal award, including how the Federal agency will measure the achievement of the goals and objectives, the expected timeline, and information on how the recipient must report the achievement of program goals and objectives. The Federal agency should also clearly communicate in the Federal award any expected outcomes (such as outputs, service performance, or public impacts of any of these), indicators, targets, baseline data, or data collections that the recipient is responsible for measuring and reporting. The Federal agency must ensure all requirements for measuring performance align with the Federal agency's strategic goals, strategic objectives, or performance goals relevant to a program (see OMB Circular A-11, Preparation, Submission, and Execution of the Budget Part 6).
(b) When establishing performance reporting frequency and content, the Federal agency should consider what information will be necessary to measure the recipient's progress, to identify promising practices of recipients, and build the evidence upon which the Federal agency makes program and performance decisions. The Federal agency should not require additional information that is not necessary for measuring program performance and evaluation. See § 200.329 for more information on reporting program performance.
(c) The Federal agency should also specify in the Federal award any requirements of the recipients' participation in federally funded evaluations.
§ 200.302
Financial management.
(a) Each State must expend and account for the Federal award in accordance with State laws and procedures for expending and accounting for the State's funds. All recipient and subrecipient financial management systems, including records documenting compliance with Federal statutes, regulations, and the terms and conditions of the Federal award, must be sufficient to permit the preparation of reports required by the terms and conditions; and tracking expenditures to establish that funds have been used in accordance with Federal statutes, regulations, and the terms and conditions of the Federal award. See § 200.450.
(b) The recipient's and subrecipient's financial management system must provide for the following (see §§ 200.334, 200.335, 200.336, and 200.337):
(1) Identification of all Federal awards received and expended and the Federal programs under which they were received. Federal program and Federal award identification must include, as applicable, the Assistance Listings title and number, Federal award identification number, year the Federal award was issued, and name of the Federal agency or pass-through entity.
(2) Accurate, current, and complete disclosure of the financial results of each Federal award or program in accordance with the reporting requirements in §§ 200.328 and 200.329. When a Federal agency or pass-through entity requires reporting on an accrual basis from a recipient or subrecipient that maintains its records other than on an accrual basis, the recipient or subrecipient must not be required to establish an accrual accounting system. This recipient or subrecipient may develop accrual data for its reports based on an analysis of the documentation on hand.
(3) Maintaining records that sufficiently identify the amount, source, and expenditure of Federal funds for Federal awards. These records must contain information necessary to identify Federal awards, authorizations, financial obligations, unobligated balances, as well as assets, expenditures, income, and interest. All records must be supported by source documentation.
(4) Effective control over and accountability for all funds, property, and assets. The recipient or subrecipient must safeguard all assets and ensure they are used solely for authorized purposes. See § 200.303.
(5) Comparison of expenditures with budget amounts for each Federal award.
(6) Written procedures to implement the requirements of § 200.305.
(7) Written procedures for determining the allowability of costs in accordance with subpart E and the terms and conditions of the Federal award.
§ 200.303
Internal controls.
The recipient and subrecipient must:
(a) Establish, document, and maintain effective internal control over the Federal award that provides reasonable assurance that the recipient or subrecipient is managing the Federal award in compliance with Federal statutes, regulations, and the terms and conditions of the Federal award. These internal controls should align with the guidance in “Standards for Internal Control in the Federal Government” issued by the Comptroller General of the United States or the “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
(b) Comply with the U.S. Constitution, Federal statutes, regulations, and the terms and conditions of the Federal award.
(c) Evaluate and monitor the recipient's or subrecipient's compliance with statutes, regulations, and the terms and conditions of Federal awards.
(d) Take prompt action when instances of noncompliance are identified.
(e) Take reasonable cybersecurity and other measures to safeguard information including protected personally identifiable information (PII) and other types of information. This also includes information the Federal agency or pass-through entity designates as sensitive or other information the recipient or subrecipient considers sensitive and is consistent with applicable Federal, State, local, and tribal laws regarding privacy and responsibility over confidentiality.
§ 200.304
Bonds.
(a) Where the Federal Government guarantees or insures the repayment of money borrowed by the recipient, the Federal agency may require adequate bonding and insurance if the bonding and insurance requirements of the recipient are not deemed adequate to protect the interest of the Federal Government.
(b) The Federal agency may require adequate fidelity bond coverage where the recipient lacks coverage to protect the interest of the Federal Government.
(c) Where bonds, insurance, or both are required in the situations described above, the bonds and insurance must be obtained from companies holding certificates of authority issued by the U.S. Department of Treasury (see 31 CFR part 223).
§ 200.305
Federal payment.
(a) Payments for States. Payments for States are governed by Treasury-State Cash Management Improvement Act (CMIA) agreements and default procedures codified at 31 CFR part 205 and Treasury Financial Manual (TFM) 4A-2000, “Overall Disbursing Rules for All Federal Agencies.”
(b) Payments for recipients and subrecipients other than States. For recipients and subrecipients other than States, payment methods must minimize the time elapsing between the transfer of funds from the Federal agency or the pass-through entity and the disbursement of funds by the recipient or subrecipient regardless of whether the payment is made by electronic funds transfer or by other means. See § 200.302(b)(6). Except as noted in this part, the Federal agency must require recipients to use only OMB-approved, government-wide information collections to request payment.
(1) The recipient or subrecipient must be paid in advance, provided it maintains or demonstrates the willingness to maintain both written procedures that minimize the time elapsing between the transfer of funds and disbursement by the recipient or subrecipient, and financial management systems that meet the standards for fund control and accountability as established in this part. Advance payments to a recipient or subrecipient must be limited to the minimum amounts needed and be timed with actual, immediate cash requirements of the recipient or subrecipient in carrying out the purpose of the approved program or project. The timing and amount of advance payments must be as close as is administratively feasible to the actual disbursements by the recipient or subrecipient for direct program or project costs and the proportionate share of any allowable indirect costs. The recipient or subrecipient must make timely payments to contractors in accordance with the contract provisions.
(2) Whenever possible, advance payment requests by the recipient or subrecipient must be consolidated to cover anticipated cash needs for all Federal awards received by the recipient from the awarding Federal agency or pass-through entity.
(i) Advance payment mechanisms must comply with 31 CFR part 208 and include, but are not limited to, Treasury checks and electronic funds transfers.
(ii) Recipients and subrecipients must be authorized to submit payment requests as often as necessary when electronic fund transfers are used or at least monthly when electronic transfers are not used. See Electronic Fund Transfer Act (15 U.S.C. 1693-1693r).
(3) Reimbursement is preferred when the requirements in paragraph (b) cannot be met, when the Federal agency or pass-through entity sets a specific condition per § 200.208, when requested by the recipient or subrecipient, when a Federal award is for construction, or when a significant portion of the construction project is accomplished through private market financing or Federal loans and the Federal award constitutes a minor portion of the project. When the reimbursement method is used, the Federal agency or pass-through entity must make payment within 30 calendar days after receipt of the payment request unless the Federal agency or pass-through entity reasonably believes the request to be improper.
(4) If the recipient or subrecipient cannot meet the criteria for advance payments and the Federal agency or pass-through entity has determined that reimbursement is not feasible because the recipient or subrecipient lacks sufficient working capital, the Federal agency or pass-through entity may provide cash on a working capital advance basis. Under this procedure, the Federal agency or pass-through entity must advance cash payments to the recipient or subrecipient to cover its estimated disbursement needs for an initial period generally aligned to the recipient's or subrecipient's disbursing cycle. After that, the Federal agency or pass-through entity must reimburse the recipient or subrecipient for its actual cash disbursements. Use of the working capital advance payment method requires that the pass-through entity provide timely advance payments to any subrecipients to meet the subrecipient's actual cash disbursements. The pass-through entity must not use the working capital advance method of payment if the reason for using this method is the unwillingness or inability of the pass-through entity to provide timely advance payments to the subrecipient to meet the subrecipient's actual cash disbursements.
(5) If available, the recipient or subrecipient must disburse funds available from program income (including repayments to a revolving fund), rebates, refunds, contract settlements, audit recoveries, and interest earned on Federal funds before requesting additional cash payments.
(6) Payments for allowable costs must not be withheld at any time during the period of performance unless required by Federal statute, regulations, or in one of the following instances:
(i) The recipient or subrecipient has failed to comply with the terms and conditions of the Federal award; or
(ii) The recipient or subrecipient is delinquent in a debt to the United States as defined in OMB Circular A-129, “Policies for Federal Credit Programs and Non-Tax Receivables.” Under such conditions, the Federal agency or pass-through entity may, after providing reasonable notice, withhold payments to the recipient or subrecipient for financial obligations incurred after a specified date until the conditions are corrected or the debt is repaid to the Federal Government.
(7) A payment withheld for failure to comply with the terms and conditions of the Federal award must be released to the recipient or subrecipient upon subsequent compliance. When a Federal award is suspended, payment adjustments must be made in accordance with § 200.343.
(8) A payment must not be made to a recipient or subrecipient for amounts that the recipient or subrecipient withholds from contractors to assure satisfactory completion of work. Payment must be made when the recipient or subrecipient disburses the withheld funds to the contractors or to escrow accounts established to ensure satisfactory completion of work.
(9) The Federal agency or pass-through entity must not require separate depository accounts for funds provided to the recipient or subrecipient or establish any eligibility requirements for depositories. However, the recipient or subrecipient must be able to account for all Federal funds received, obligated, and expended.
(10) Advance payments of Federal funds must be deposited and maintained in insured accounts whenever possible.
(11) The recipient or subrecipient must maintain advance payments of Federal funds in interest-bearing accounts unless one of the following applies:
(i) The recipient or subrecipient receives less than $250,000 in Federal funding per year;
(ii) The best available interest-bearing account would not reasonably be expected to earn interest in excess of $500 per year on Federal cash balances;
(iii) The depository would require an average or minimum balance so high that it would not be feasible with the expected Federal and non-Federal cash resources;
(iv) A foreign government or banking system prohibits or precludes interest-bearing accounts; or
(v) An interest-bearing account is not readily accessible (for example, due to public or political unrest in a foreign country).
(12) The recipient or subrecipient may retain up to $500 per year of interest earned on Federal funds to use for administrative expenses of the recipient or subrecipient. Any additional interest earned on Federal funds must be returned annually to the Department of Health and Human Services Payment Management System (PMS) through either the Automated Clearing House (ACH) network or a Fedwire Funds Service payment. All interest in excess of $500 per year must be returned to PMS regardless of whether the recipient or subrecipient was paid through PMS. Instructions for returning interest can be found at https://pms.psc.gov/grant-recipients/returning-funds-interest.html.
(13) All other Federal funds must be returned to the payment system of the Federal agency. Returns should follow the instructions provided by the Federal agency. All returns to PMS should follow the instructions provided at https://pms.psc.gov/grant-recipients/returning-funds-interest.html.
§ 200.306
Cost sharing.
(a) Voluntary committed cost sharing is not expected under Federal research grants. The Federal agency may not use voluntary committed cost sharing as a factor during the merit review of applications or proposals for Federal research grants unless authorized by Federal statutes or agency regulations and specified in the notice of funding opportunity. Federal agencies are also discouraged from using voluntary committed cost sharing as a factor during the merit review of applications for other Federal financial assistance programs. If voluntary committed cost sharing is used for this purpose for other programs, the notice of funding opportunity must specify how an applicant's proposed cost sharing will be considered. See §§ 200.414, 200.204, and Appendix I.
(b) For all Federal awards, the Federal agency or pass-through entity must accept any cost sharing funds (including cash and third-party in-kind contributions, and also including funds committed by the recipient, subrecipient, or third parties) as part of the recipient's or subrecipient's contributions to a program when the funds:
(1) Are verifiable in the recipient's or subrecipient's records;
(2) Are not included as contributions for any other Federal award;
(3) Are necessary and reasonable for achieving the objectives of the Federal award;
(4) Are allowable under subpart E;
(5) Are not paid by the Federal Government under another Federal award, except where the program's Federal authorizing statute specifically provides that Federal funds made available for the program can be applied to cost sharing requirements of other Federal programs;
(6) Are provided for in the approved budget when required by the Federal agency; and
(7) Conform to other applicable provisions of this part.
(c) Unrecovered indirect costs, including indirect costs on cost sharing, may be included as part of cost sharing with the prior approval of the Federal agency or pass-through entity. Unrecovered indirect cost means the difference between the amount charged to the Federal award and the amount which could have been charged to the Federal award under the recipient's or subrecipient's approved indirect cost rate.
(d) Values for recipient or subrecipient contributions of services and property must be established in accordance with the cost principles in subpart E. When a Federal agency or pass-through entity authorizes the recipient or subrecipient to donate buildings or land for construction/facilities acquisition projects or long-term use, the value of the donated property for cost sharing must be the lesser of paragraph (d)(1) or (2) below.
(1) The value of the remaining life of the property recorded in the recipient's or subrecipient's accounting records at the time of donation.
(2) The current fair market value. However, when there is sufficient justification, the Federal agency or pass-through may approve using the current fair market value of the donated property, even if it exceeds the value described in paragraph (d)(1) at the time of donation.
(e) Volunteer services furnished by third-party professional and technical personnel, consultants, and other labor may be counted as cost sharing if the service is necessary for the program. Rates for third-party volunteer services must be consistent with those paid for similar work by the recipient or subrecipient. When the required skills are not found in the recipient's or subrecipient's workforce, rates must be consistent with those paid for similar work in the labor market where the recipient or subrecipient competes for the services involved. In either case, fringe benefits that are allowable, allocable, and reasonable may be included in the valuation.
(f) When a third-party organization furnishes the services of an employee, these services must be valued at the employee's regular rate of pay plus an amount of fringe benefits that is reasonable, necessary, allocable, and otherwise allowable, and indirect costs at either the third-party organization's approved federally-negotiated indirect cost rate or, a rate in accordance with § 200.414(d) provided these services employ the same skill(s) for which the employee is normally paid. Where donated services are treated as indirect costs, indirect cost rates will separate the value of the donated services so that reimbursement for the donated services will not be made.
(g) Donated property from third parties may include items such as equipment, office supplies, laboratory supplies, or workshop and classroom supplies. The assessed value of donated property included as cost sharing must not exceed the property's fair market value at the time of the donation.
(h) The method used for determining the value of donated equipment, buildings, and land for which title passes to the recipient or subrecipient may differ according to the following:
(1) If the purpose of the Federal award is to assist the recipient or subrecipient in acquiring equipment, buildings, or land, the aggregate value of the donated property may be claimed as cost sharing.
(2) If the purpose of the Federal award is to support activities that require the use of equipment, buildings, or land, only depreciation charges for equipment and buildings may be made. However, the fair market value of equipment or other capital assets and fair rental charges for land may be allowed if provided in the terms and conditions of the Federal award. See § 200.420.
(i) The value of donated property must be determined in accordance with the accounting policies of the recipient or subrecipient with the following qualifications:
(1) The value of donated land and buildings must not exceed its fair market value at the time of donation to the recipient or subrecipient as established by an independent appraiser (for example, certified real property appraiser or General Services Administration representative) and certified by a responsible official of the recipient or subrecipient as required by the Uniform Relocation Assistance and Real Property Acquisition Policies Act of 1970, as amended, (42 U.S.C. 4601-4655) except as provided in the implementing regulations at 49 CFR part 24, “Uniform Relocation Assistance And Real Property Acquisition For Federal And Federally-Assisted Programs.”
(2) The value of donated equipment must not exceed the fair market value at the time of donation.
(3) The value of donated space must not exceed the fair rental value of comparable space as established by an independent appraisal of comparable space and facilities in a privately-owned building in the same locality.
(4) The value of loaned equipment must not exceed its fair rental value.
(j) The fair market value of third-party in-kind contributions must be documented and, to the extent feasible, supported by the same methods used internally by the recipient or subrecipient.
(k) For institutions of higher education (IHE), voluntary uncommitted cost sharing should be treated differently from mandatory or voluntary committed cost sharing. Voluntary uncommitted cost sharing should not be included in the organized research base for computing the indirect cost rate or reflected in any allocation of indirect costs. Voluntary uncommitted cost sharing includes faculty-donated additional time above that agreed to as part of the award. See OMB memorandum M-01-06, dated January 5, 2001, Clarification of OMB A-21 Treatment of Voluntary Uncommitted Cost Sharing and Tuition Remission Costs.
§ 200.307
Program income.
(a) General. The recipient or subrecipient is encouraged to earn income to defray program costs when appropriate. Program income must be used for the original purpose of the Federal award. Program income earned during the period of performance may only be used for costs incurred during the period of performance or allowable closeout costs. See § 200.472(b). Program income must be expended prior to requesting additional Federal funds. Program income exceeding amounts specified in the Federal award may be added to or deducted from the total allowable costs in accordance with the terms and conditions of the Federal award.
(b) Use of program income. There are three methods of applying program income: deduction; addition; and cost-sharing. The Federal agency should specify what program income method(s) will be used in the terms and conditions of the Federal award. The deduction method will be used if the Federal agency does not specify a method for applying program income. When no program income method is specified in the Federal award, prior approval is required to use the addition or cost sharing methods. However, the addition method will be used when no method is specified for awards made to institutions of higher education (IHE) and nonprofit research institutions. In specifying alternatives to the deduction and addition methods, the Federal agency may distinguish between income earned by the recipient and income earned by subrecipients as well as between the sources, kinds, or amounts of income.
(1) Deduction. Program income is deducted from the total allowable costs, reducing the overall total amount of the Federal award.
(2) Addition. Program income is added to the total allowable costs, increasing the overall total amount of the Federal award.
(3) Cost sharing. Program income is used to meet the Federal award's cost sharing requirement.
(c) Income after the period of performance. There are no requirements governing the disposition of program income earned after the end of the period of performance of the Federal award unless stipulated in the Federal agency regulations or the terms and conditions of the Federal award. The Federal agency may negotiate agreements with recipients regarding appropriate uses of income earned after the end of the period of performance as part of the closeout process. See § 200.344.
(d) Cost of generating program income. If authorized by Federal regulations or the Federal award, costs incidental to generating program income may be deducted from gross income to determine program income, provided these costs have not been charged to the Federal award.
(e) Not considered program income. The following are not considered program income unless specified in Federal statutes, regulations, or the terms and conditions of the Federal award:
(1) Governmental revenues. Taxes, special assessments, levies, fines, and similar revenues the recipient or subrecipient raised.
(2) Property. Proceeds from the sale of real property, equipment, or supplies. The proceeds must be handled in accordance with the requirements of the Property Standards of §§ 200.311, 200.313, 200.314, or as explicitly identified in Federal statutes, regulations, or the terms and conditions of the Federal award.
(3) License fees and royalties. License fees and royalties for copyrighted material, patents, patent applications, trademarks, and inventions made under the Federal award subject to 37 CFR part 401.
§ 200.308
Revision of budget and program plans.
(a) Approved budget in general. The approved budget for the Federal award summarizes the financial aspects of the project or program as approved during the Federal award process. It may include the Federal share and non-Federal share or only the Federal share, as determined by the Federal agency or pass-through entity.
(b) Deviations from approved budget. The recipient or subrecipient must report deviations from the approved budget, project or program scope, or objective(s) in accordance with § 200.329. The recipient or subrecipient must request prior approvals from the Federal agency or pass-through entity for budget and program plan revisions in accordance with this section.
(c) Requesting approval for budget revisions. When requesting approval for budget revisions, the recipient or subrecipient must use the same format for budget information that was used in their application, except if the Federal agency has approved an alternative format. Alternative formats may include the use of electronic systems, email, or other agency-approved mechanisms that document the request.
(d) Federal agency or pass-through entity review. The Federal agency or pass-through entity must review the request for budget or program plan revision and should notify the recipient or subrecipient whether the revisions have been approved within 30 days of receipt of the request. The Federal agency or pass-through entity must inform the recipient or subrecipient in writing when a decision can be expected if more than 30 days is required for a review.
(e) Limitation on other prior approval requirements. Unless specified in this guidance, the Federal agency must not impose additional prior approval requirements without OMB approval. See also §§ 200.102 and 200.407.
(f) Revisions Requiring Prior Approval. A recipient or subrecipient must request prior written approval from the Federal agency or pass-through entity for the following program and budget-related reasons:
(1) Change in the scope or the objective of the project or program (even if there is no associated budget revision requiring prior written approval).
(2) Change in key personnel (including employees and contractors) that are identified by name or position in the Federal award.
(3) The disengagement from a project for more than three months, or a 25 percent reduction in time and effort devoted to the Federal award over the course of the period of performance, by the approved project director or principal investigator.
(4) The inclusion, unless waived by the Federal agency, of costs that require prior approval in accordance with subpart E as applicable.
(5) The transfer of funds budgeted for participant support costs to other budget categories.
(6) Subaward activities not proposed in the application and approved in the Federal award. A change of subrecipient only requires prior approval if the Federal agency or pass-through entity includes the requirement in the terms and conditions of the Federal award. In general, a Federal agency or pass-through entity should not require prior approval of a change of subrecipient unless the inclusion was a determining factor in the merit review or eligibility process. This requirement does not apply to procurement transactions for goods and services.
(7) Changes in the total approved cost-sharing amount.
(8) The need arises for additional Federal funds to complete the project. Before providing approval, the Federal agency must ensure that adequate funds are available to avoid a violation of the Antideficiency Act.
(9) Transferring funds between the construction and non-construction work under a Federal award.
(10) A no-cost extension (meaning, an extension of time that does not require the obligation of additional Federal funds) of the period of performance, other than any one-time extension authorized by the Federal agency in accordance with paragraph (g)(2). All requests for no-cost extensions should be submitted at least 10 calendar days before the conclusion of the period of performance. The Federal agency may approve multiple no-cost extensions under a Federal award if not prohibited by Federal statute or regulation.
(g) Waiver of certain prior approvals. Except for the requirements listed in paragraphs (f)(1) through (10), the Federal agency is authorized to waive other cost-related and administrative prior written approval requirements contained in subparts D and E. Such waivers may include authorizing recipients to do one or more of the following:
(1) Pre-award costs. Incur project costs 90 calendar days before the Federal award date. Expenses incurred more than 90 calendar days before the Federal award date require prior approval of the Federal agency. All costs incurred before the Federal award date are at the recipient's own risk ( for example, the Federal agency is not required to reimburse such costs if the recipient does not receive the Federal award or if the Federal award is less than anticipated and inadequate to cover such costs). Pre-award costs must be charged to the initial budget period of the Federal award unless otherwise specified by the Federal agency. See also § 200.458.
(2) One-time extensions. Initiate a one-time extension of the period of performance by up to 12 months unless one or more of the conditions outlined in paragraphs (g)(2)(i) through (iii) of this section apply. Prior approval is not required if a recipient is authorized in the terms and conditions of the Federal award to initiate a one-time extension. However, the recipient must notify the Federal agency in writing with the supporting justification and a revised period of performance at least 10 calendar days before the conclusion of the period of performance. A one-time extension may not be exercised for the sole purpose of using unobligated balances. This paragraph does not preclude the Federal agency from approving further no-cost extensions to the Federal award. One-time extensions require prior approval from the Federal agency when:
(i) The terms and conditions of the Federal award prohibit the extension;
(ii) The extension requires additional Federal funds; or
(iii) The extension involves any change in the approved scope of the project.
(3) Unobligated Balances. Carry forward unobligated balances to subsequent budget periods.
(h) Prior approvals for research awards. The prior approval requirements for the actions described in paragraph (g) of this section are automatically waived for Federal awards that support research unless stipulated in the Federal agency's regulations or terms and conditions of the Federal award. However, one-time extensions require the Federal agency's prior approval when one of the conditions in paragraph (g)(2) of this section applies.
(i) Transfer of funds. The Federal agency must not permit a transfer of funds that would cause any Federal appropriation to be used for purposes other than those consistent with the appropriation. The Federal agency may also, at its option, restrict the transfer of funds among direct cost categories (for example, personnel, travel, and supplies) or programs, functions, and activities when:
(1) The Federal share of the Federal award exceeds the simplified acquisition threshold; and
(2) The cumulative amount of a transfer exceeds or is expected to exceed 10 percent of the total budget, including cost share, as last approved by the Federal agency.
§ 200.309
Modifications to Period of Performance.
When the Federal agency or pass-through entity approves an extension to a Federal award, or if a recipient extends under § 200.308(g)(2), the period of performance will be amended to end at the completion of the extension. If termination occurs, the period of performance will be amended to end upon the effective date of termination. The start date of a renewal award begins a new and distinct period of performance.

Property Standards
§ 200.310
Insurance coverage.
The recipient or subrecipient must, at a minimum, provide the equivalent insurance coverage for real property and equipment acquired or improved with Federal funds as provided to property and equipment owned by the recipient or subrecipient. Insurance is not required for Federally owned property unless required by the terms and conditions of the Federal award.
§ 200.311
Real property.
(a) Title. Subject to the requirements and conditions set forth in this section, title to real property acquired or improved under the Federal award will vest upon acquisition in the recipient or subrecipient.
(b) Use. Except as otherwise provided by Federal statutes or the Federal agency, real property must be used for the originally authorized purpose as long as it is needed for that purpose. While the property is being used for the originally authorized purpose, the recipient or subrecipient must not dispose of or encumber its title or other interests except as provided by the Federal agency. Easements for utility, cable, and similar services that benefit the real property and are consistent with the authorized use are not considered an encumbrance.
(c) Appraisals. When an appraisal of real property is required and obtained by the recipient or subrecipient, it must be conducted by an independent appraiser (for example, certified real property appraiser or General Services Administration representative) and certified by a responsible official of the recipient or subrecipient as required by the Uniform Relocation Assistance and Real Property Acquisition Policies Act of 1970, as amended, (42 U.S.C. 4601-4655) except as provided in the implementing regulations at 49 CFR part 24, “Uniform Relocation Assistance And Real Property Acquisition For Federal And Federally-Assisted Programs.”
(d) Disposition. When real property is no longer needed for the originally authorized purpose, the recipient or subrecipient must obtain disposition instructions from the Federal agency or pass-through entity. The instructions must specify one of the following disposition methods:
(1) Retain title after compensating the Federal agency. When the recipient or subrecipient retains title to the property, it must pay the Federal agency an amount calculated by multiplying the percentage of the Federal agency's contribution towards the original purchase (and costs of any improvements) by the current fair market value of the property. However, in situations where the recipient or subrecipient is disposing of real property acquired or improved with the Federal award and acquiring replacement real property under the same Federal award, the net proceeds from the disposition may be used as an offset to the cost of the replacement property.
(2) Sell the property and compensate the Federal agency. When a recipient or subrecipient sells the property, it must pay the Federal agency an amount calculated by multiplying the percentage of the Federal agency's contribution towards the original purchase (and cost of any improvements) by the proceeds of the sale after deducting any actual and reasonable expenses paid to sell or fix up the property for sale. When the Federal award has not been closed out, the net proceeds from the sale may be offset against the original cost of the property. When directed to sell the property, the recipient or subrecipient must sell the property utilizing procedures that provide for competition to the extent practicable and that result in the highest possible return.
(3) Transfer title to the Federal agency or a third party designated/approved by the Federal agency. When a recipient or subrecipient transfers title to the property to a Federal agency or third party designated or approved by the Federal agency, the recipient or subrecipient is entitled to be paid an amount calculated by multiplying the percentage of the recipient's or subrecipient's contribution towards the original purchase of the real property (and cost of any improvements) by the current fair market value of the property.
§ 200.312
Federally owned and exempt property.
(a) Title to Federally owned property remains vested in the Federal Government. The recipient or subrecipient must submit an inventory listing of Federally owned property in its custody to the Federal agency or pass-through entity on an annual basis. The recipient or subrecipient must request disposition instructions from the Federal agency or pass-through entity upon completion of the Federal award or when the property is no longer needed.
(b) If the Federal agency has no further need for the property, it must declare the property excess and report it for disposal to the appropriate Federal disposal authority unless the Federal agency has statutory authority to dispose of the property by alternative methods ( for example, the authority provided by the Federal Technology Transfer Act (15 U.S.C. 3710(i)). The Federal agency or pass-through entity must issue appropriate instructions to the recipient or subrecipient.
(c) Exempt property means property acquired under the Federal award where the Federal agency has chosen to vest title to the property to the recipient or subrecipient without further responsibility to the Federal Government. The Federal agency may only exercise this option when permitted by Federal statute and set forth in the terms and conditions of the Federal award. Absent statutory authority and specific terms and conditions of the Federal award, the title to exempt property acquired under the Federal award remains with the Federal Government.
§ 200.313
Equipment.
See also § 200.439.
(a) Title. Title to equipment acquired under the Federal award will vest upon acquisition in the recipient or subrecipient subject to the conditions of this section. This title must be a conditional title unless a Federal statute specifically authorizes the Federal agency to vest title in the recipient or subrecipient without further responsibility to the Federal Government (and the Federal agency elects to do so). A conditional title means a clear title is withheld by the Federal agency until conditions and requirements specified in the terms and conditions of a Federal award have been fulfilled. Title for equipment vested in a recipient or subrecipient is subject to the following conditions:
(1) Use the equipment for the authorized purposes of the project during the period of performance or until the property is no longer needed for the purposes of the project.
(2) While the equipment is being used for the originally-authorized purpose, the recipient or subrecipient must not dispose of or encumber its title or other interests without the approval of the Federal agency or pass-through entity.
(3) Use and dispose of the property in accordance with paragraphs (b), (c), and (e) of this section.
(b) General. A State must use, manage and dispose of equipment acquired under a Federal award in accordance with State laws and procedures. Indian Tribes must use, manage, and dispose of equipment acquired under a Federal award in accordance with tribal laws and procedures. If such laws and procedures do not exist, Indian Tribes must follow the guidance in this section. Other recipients and subrecipients, including subrecipients of a State or Indian Tribe, must follow paragraphs (c) through (e) of this section.
(c) Use. (1) The recipient or subrecipient must use equipment for the project or program for which it was acquired and for as long as needed, whether or not the project or program continues to be supported by the Federal award. The recipient or subrecipient must not encumber the equipment without prior approval of the Federal agency or pass-through entity. The Federal agency may require the submission of the applicable common forms for reporting on equipment. When no longer needed for the original project or program, the equipment may be used in other activities in the following order of priority:
(i) Activities under other Federal awards from the Federal agency that funded the original program or project; then
(ii) Activities under Federal awards from other Federal agencies. These activities include consolidated equipment for information technology systems.
(2) During the time that equipment is used on the project or program for which it was acquired, the recipient or subrecipient must also make the equipment available for use on other programs or projects supported by the Federal Government, provided that such use will not interfere with the purpose for which it was originally acquired. First preference for other use of the equipment must be given to other programs or projects supported by the Federal agency that financed the equipment. Second preference must be given to programs or projects under Federal awards from other Federal agencies. Use for non-federally-funded projects is also permissible, provided such use will not interfere with the purpose for which it was originally acquired. The recipient or subrecipient should consider charging user fees as appropriate.
(3) Notwithstanding the encouragement in § 200.307 to earn program income, the recipient or subrecipient must not use equipment acquired with the Federal award to provide services for a fee that is less than a private company would charge for similar services unless specifically authorized by Federal statute. This restriction is effective as long as the Federal Government retains an interest in the equipment.
(4) When acquiring replacement equipment, the recipient or subrecipient may either trade-in or sell the equipment and use the proceeds to offset the cost of the replacement equipment.
(d) Management requirements. Regardless of whether equipment is acquired in part or its entirety under the Federal award, the recipient or subrecipient must manage equipment (including replacement equipment) utilizing procedures that meet the following requirements:
(1) Property records must include a description of the property, a serial number or another identification number, the source of funding for the property (including the FAIN), the title holder, the acquisition date, the cost of the property, the percentage of the Federal agency contribution towards the original purchase, the location, use and condition of the property, and any disposition data including the date of disposal and sale price of the property. The recipient and subrecipient are responsible for maintaining and updating property records when there is a change in the status of the property.
(2) A physical inventory of the property must be conducted, and the results must be reconciled with the property records at least once every two years.
(3) A control system must be in place to ensure safeguards for preventing property loss, damage, or theft. Any loss, damage, or theft of equipment must be investigated. The recipient or subrecipient must notify the Federal agency or pass-through entity of any loss, damage, or theft of equipment that will have an impact on the program.
(4) Regular maintenance procedures must be in place to ensure the property is in proper working condition.
(5) If the recipient or subrecipient is authorized or required to sell the property, proper sales procedures must be in place to ensure the highest possible return.
(e) Disposition. When equipment acquired under a Federal award is no longer needed for the original project, program, or for other activities currently or previously supported by a Federal agency, the recipient or subrecipient must request disposition instructions from the Federal agency or pass-through entity if required by the terms and conditions of the Federal award. Disposition of the equipment will be made as follows, in accordance with Federal agency or pass-through entity disposition instructions:
(1) Equipment with a current fair market value of $10,000 or less (per unit) may be retained, sold, or otherwise disposed of with no further responsibility to the Federal agency or pass-through entity.
(2) Except as provided in § 200.312(b), or if the Federal agency or pass-through entity fails to provide requested disposition instructions within 120 days, items of equipment with a current fair market value in excess of $10,000 (per-unit) may be retained or sold by the recipient or subrecipient. However, the Federal agency is entitled to an amount calculated by multiplying the percentage of the Federal agency's contribution towards the original purchase by the current market value or proceeds from the sale. If the equipment is sold, the Federal agency or pass-through entity may permit the recipient or subrecipient to retain, from the Federal share, $1,000 of the proceeds to cover expenses associated with the selling and handling of the equipment.
(3) The recipient or subrecipient may transfer title to the property to the Federal Government or to an eligible third party provided that the recipient or subrecipient must be entitled to compensation for its attributable percentage of the current fair market value of the property.
(4) In cases where a recipient or subrecipient fails to take appropriate disposition actions, the Federal agency or pass-through entity may direct the recipient or subrecipient to take disposition actions.
(f) Equipment retention. When included in the terms and conditions of the Federal award, the Federal agency may permit the recipient to retain equipment, or authorize a pass-through entity to permit the subrecipient to retain equipment, with no further obligation to the Federal Government unless prohibited by Federal statute or regulation.
§ 200.314
Supplies.
See also § 200.453.
(a) Title to supplies acquired under the Federal award will vest upon acquisition in the recipient or subrecipient. When there is a residual inventory of unused supplies exceeding $10,000 in aggregate value at the end of the period of performance, and the supplies are not needed for any other Federal award, the recipient or subrecipient may retain or sell the unused supplies. Unused supplies means supplies that are in new condition, not having been used or opened before. The aggregate value of unused supplies consists of all supply types, not just like-item supplies. The Federal agency or pass-through entity is entitled to compensation in an amount calculated by multiplying the percentage of the Federal agency's or pass-through entity's contribution towards the cost of the original purchase(s) by the current market value or proceeds from the sale. If the supplies are sold, the Federal agency or pass-through entity may permit the recipient or subrecipient to retain, from the Federal share, $1,000 of the proceeds to cover expenses associated with the selling and handling of the supplies.
(b) Unless expressly authorized by Federal statute, the recipient or subrecipient must not use supplies acquired with the Federal award to provide services for a fee that is less than a private company would charge for similar services. This restriction is effective as long as the Federal Government retains an interest in the supplies or as authorized by Federal statute.
§ 200.315
Intangible property.
(a) Title to intangible property acquired under a Federal award vests upon acquisition in the recipient or subrecipient. The recipient or subrecipient must use that intangible property for the originally authorized purpose and must not encumber the property without the approval of the Federal agency or pass-through entity. When no longer needed for the originally authorized purpose, disposition of the intangible property must occur in accordance with the provisions in § 200.313(e).
(b) To the extent permitted by law, the recipient or subrecipient may copyright any work that is subject to copyright and was developed, or for which ownership was acquired, under a Federal award. The Federal agency reserves a royalty-free, nonexclusive, and irrevocable right to reproduce, publish, or otherwise use the work for Federal purposes and to authorize others to do so. This includes the right to require recipients and subrecipients to make such works available through agency-designated public access repositories.
(c) The recipient or subrecipient is subject to applicable regulations governing patents and inventions, including government-wide regulations in 37 CFR part 401.
(d) The Federal Government has the right to:
(1) Obtain, reproduce, publish, or otherwise use the data produced under a Federal award; and
(2) Authorize others to receive, reproduce, publish, or otherwise use the data for Federal purposes.
(e)(1) The recipient or subrecipient must provide research data relating to published research findings produced under the Federal award and that were used by the Federal Government in developing an agency action that has the force and effect of law if requested by the Federal agency in response to a Freedom of Information Act (FOIA) request. When the Federal agency obtains the research data solely in response to a FOIA request, the Federal agency may charge the requester a fee for the cost of obtaining the research data. This fee should reflect the costs incurred by the Federal agency and the recipient or subrecipient. This fee is in addition to any fees the Federal agency may assess under the FOIA (5 U.S.C. 552(a)(4)(A)).
(2) Published research findings mean:
(i) Research findings published in a peer-reviewed scientific or technical journal; or
(ii) Research findings publicly cited by a Federal agency in developing an agency action that has the force and effect of law.
(3) Research data means the recorded factual material commonly accepted in the scientific community as necessary to validate research findings. Research data does not include any of the following:
(i) Preliminary analyses, drafts of scientific papers, plans for future research, peer reviews, or communications with colleagues. This “recorded” material excludes physical objects (for example, laboratory samples).
(ii) Trade secrets, commercial information, materials necessary to be held confidential by a researcher until they are published, or similar information which is protected under law; and
(iii) Personnel, medical, and other personally identifiable information that, if disclosed, would constitute an invasion of personal privacy. Information that could identify a particular person in a research study is not considered research data.
(f) Federal agencies should work with recipients to maximize public access to Federally funded research results and data in a manner that protects data providers' confidentiality, privacy, and security. Agencies should provide guidance to recipients to make restricted-access data available through a variety of mechanisms. FOIA may not be the most appropriate mechanism for providing access to intangible property, including Federally funded research results and data.
§ 200.316
Property trust relationship.
Real property, equipment, and intangible property acquired or improved with the Federal award must be held in trust by the recipient or subrecipient as trustee for the beneficiaries of the project or program under which the property was acquired or improved. The Federal agency or pass-through entity may require the recipient or subrecipient to record liens or other appropriate notices of record to indicate that personal or real property has been acquired or improved with a Federal award and that use and disposition conditions apply to the property.

Procurement Standards
§ 200.317
Procurements by States and Indian Tribes.
When conducting procurement transactions under a Federal award, a State or Indian Tribe must follow the same policies and procedures it uses for procurements with non-Federal funds. If such policies and procedures do not exist, States and Indian Tribes must follow the procurement standards in §§ 200.318 through 200.327. In addition to its own policies and procedures, a State or Indian Tribe must also comply with the following procurement standards: §§ 200.321, 200.322, 200.323, and 200.327. All other recipients and subrecipients, including subrecipients of a State or Indian Tribe, must follow the procurement standards in §§ 200.318 through 200.327.
§ 200.318
General procurement standards.
(a) Documented procurement procedures. The recipient or subrecipient must maintain and use documented procedures for procurement transactions under a Federal award or subaward, including for acquisition of property or services. These documented procurement procedures must be consistent with State, local, and tribal laws and regulations and the standards identified in §§ 200.317 through 200.327.
(b) Oversight of contractors. Recipients and subrecipients must maintain oversight to ensure that contractors perform in accordance with the terms, conditions, and specifications of their contracts or purchase orders. See also § 200.501(h).
(c) Conflicts of interest. (1) The recipient or subrecipient must maintain written standards of conduct covering conflicts of interest and governing the actions of its employees engaged in the selection, award, and administration of contracts. No employee, officer, agent, or board member with a real or apparent conflict of interest may participate in the selection, award, or administration of a contract supported by the Federal award. A conflict of interest includes when the employee, officer, agent, or board member, any member of their immediate family, their partner, or an organization that employs or is about to employ any of the parties indicated herein, has a financial or other interest in or a tangible personal benefit from an entity considered for a contract. An employee, officer, agent, and board member of the recipient or subrecipient may neither solicit nor accept gratuities, favors, or anything of monetary value from contractors. However, the recipient or subrecipient may set standards for situations where the financial interest is not substantial or a gift is an unsolicited item of nominal value. The recipient's or subrecipient's standards of conduct must also provide for disciplinary actions to be applied for violations by its employees, officers, agents, or board members.
(2) If the recipient or subrecipient has a parent, affiliate, or subsidiary organization that is not a State, local government, or Indian Tribe, the recipient or subrecipient must also maintain written standards of conduct covering organizational conflicts of interest. Organizational conflicts of interest mean that because of relationships with a parent company, affiliate, or subsidiary organization, the recipient or subrecipient is unable or appears to be unable to be impartial in conducting a procurement action involving a related organization.
(d) Avoidance of unnecessary or duplicative items. The recipient's or subrecipient's procedures must avoid the acquisition of unnecessary or duplicative items. Consideration should be given to consolidating or breaking out procurements to obtain a more economical purchase. When appropriate, an analysis should be made between leasing and purchasing property or equipment to determine the most economical approach.
(e) Procurement arrangements using strategic sourcing. When appropriate for the procurement or use of common or shared goods and services, recipients and subrecipients are encouraged to enter into State and local intergovernmental agreements or inter-entity agreements for procurement transactions. These or similar procurement arrangements using strategic sourcing may foster greater economy and efficiency. Documented procurement actions of this type (using strategic sourcing, shared services, and other similar procurement arrangements) will meet the competition requirements of this part.
(f) Use of excess and surplus Federal property. The recipient or subrecipient is encouraged to use excess and surplus Federal property instead of purchasing new equipment and property when it is feasible and reduces project costs.
(g) Use of value engineering clauses. When practical, the recipient or subrecipient is encouraged to use value engineering clauses in contracts for construction projects of sufficient size to offer reasonable opportunities for cost reductions. Value engineering means analyzing each contract item or task to ensure its essential function is provided at the overall lowest cost.
(h) Responsible contractors. The recipient or subrecipient must award contracts only to responsible contractors that possess the ability to perform successfully under the terms and conditions of a proposed contract. The recipient or subrecipient must consider contractor integrity, public policy compliance, proper classification of employees (see the Fair Labor Standards Act, 29 U.S.C. 201, chapter 8), past performance record, and financial and technical resources when conducting a procurement transaction. See also § 200.214.
(i) Procurement records. The recipient or subrecipient must maintain records sufficient to detail the history of each procurement transaction. These records must include the rationale for the procurement method, contract type selection, contractor selection or rejection, and the basis for the contract price.
(j) Time-and-materials type contracts. (1) The recipient or subrecipient may use a time-and-materials type contract only after a determination that no other contract is suitable and if the contract includes a ceiling price that the contractor exceeds at its own risk. Time-and-materials type contract means a contract whose cost to a recipient or subrecipient is the sum of:
(i) The actual cost of materials; and
(ii) Direct labor hours charged at fixed hourly rates that reflect wages, general and administrative expenses, and profit.
(2) Because this formula generates an open-ended contract price, a time-and-materials contract provides no positive profit incentive to the contractor for cost control or labor efficiency. Therefore, each contract must set a ceiling price that the contractor exceeds at its own risk. Further, the recipient or subrecipient awarding such a contract must assert a high degree of oversight to obtain reasonable assurance that the contractor is using efficient methods and effective cost controls.
(k) Settlement of contractual and administrative issues. The recipient or subrecipient is responsible for the settlement of all contractual and administrative issues arising out of its procurement transactions. These issues include, but are not limited to, source evaluation, protests, disputes, and claims. These standards do not relieve the recipient or subrecipient of any contractual responsibilities under its contracts. The Federal agency will not substitute its judgment for that of the recipient or subrecipient unless the matter is primarily a Federal concern. The recipient or subrecipient must report violations of law to the Federal, State, or local authority with proper jurisdiction.
(l) Examples of labor and employment practices. (1) The procurement standards in this subpart do not prohibit recipients or subrecipients from:
(i) Using Project Labor Agreements (PLAs) or similar forms of pre-hire collective bargaining agreements;
(ii) Requiring construction contractors to use hiring preferences or goals for people residing in high-poverty areas, disadvantaged communities as defined by the Justice40 Initiative (see OMB Memorandum M-21-28), or high-unemployment census tracts within a region no smaller than the county where a federally funded construction project is located. The hiring preferences or goals should be consistent with the policies and procedures of the recipient or subrecipient, and must not prohibit interstate hiring;
(iii) Requiring a contractor to use hiring preferences or goals for individuals with barriers to employment (as defined in section 3 of the Workforce Innovation and Opportunity Act (29 U.S.C. 3102(24)), including women and people from underserved communities as defined by Executive Order 14091;
(iv) Using agreements intended to ensure uninterrupted delivery of services; using agreements intended to ensure community benefits; or
(v) Offering employees of a predecessor contractor rights of first refusal under a new contract.
(2) Recipients and subrecipients may use the practices listed in paragraph (1) if consistent with the U.S. Constitution, applicable Federal statutes and regulations, the objectives and purposes of the applicable Federal financial assistance program, and other requirements of this part.
§ 200.319
Competition.
(a) All procurement transactions under the Federal award must be conducted in a manner that provides full and open competition and is consistent with the standards of this section and § 200.320.
(b) To ensure objective contractor performance and eliminate unfair competitive advantage, contractors that develop or draft specifications, requirements, statements of work, or invitations for bids must be excluded from competing on those procurements.
(c) Examples of situations that may restrict competition include, but are not limited to:
(1) Placing unreasonable requirements on firms for them to qualify to do business;
(2) Requiring unnecessary experience and excessive bonding;
(3) Noncompetitive pricing practices between firms or between affiliated companies;
(4) Noncompetitive contracts to consultants that are on retainer contracts;
(5) Organizational conflicts of interest;
(6) Specifying only a “brand name” product instead of allowing “an equal” product to be offered and describing the performance or other relevant requirements of the procurement; and
(7) Any arbitrary action in the procurement process.
(d) The recipient or subrecipient must have written procedures for procurement transactions. These procedures must ensure that all solicitations:
(1) Are made in accordance with § 200.319(b);
(2) Incorporate a clear and accurate description of the technical requirements for the property, equipment, or service being procured. The description may include a statement of the qualitative nature of the property, equipment, or service to be procured. When necessary, the description must provide minimum essential characteristics and standards to which the property, equipment, or service must conform. Detailed product specifications should be avoided if at all possible. When it is impractical or uneconomical to clearly and accurately describe the technical requirements, a “brand name or equivalent” description of features may be used to provide procurement requirements. The specific features of the named brand must be clearly stated; and
(3) Identify any additional requirements which the offerors must fulfill and all other factors that will be used in evaluating bids or proposals.
(e) The recipient or subrecipient must ensure that all prequalified lists of persons, firms, or products used in procurement transactions are current and include enough qualified sources to ensure maximum open competition. When establishing or amending prequalified lists, the recipient or subrecipient must consider objective factors that evaluate price and cost to maximize competition. The recipient or subrecipient must not preclude potential bidders from qualifying during the solicitation period.
(f) To the extent consistent with established practices and legal requirements applicable to the recipient or subrecipient, this subpart does not prohibit recipients or subrecipients from developing written procedures for procurement transactions that incorporate a scoring mechanism that rewards bidders that commit to specific numbers and types of U.S. jobs, minimum compensation, benefits, on-the-job-training for employees making work products or providing services on a contract, and other worker protections. This subpart also does not prohibit recipients and subrecipients from making inquiries of bidders about these subjects and assessing the responses. Any scoring mechanism must be consistent with the U.S. Constitution, applicable Federal statutes and regulations, and the terms and conditions of the Federal award.
(g) Noncompetitive procurements can only be awarded in accordance with § 200.320(c).
§ 200.320
Procurement methods.
There are three types of procurement methods described in this section: informal procurement methods (for micro-purchases and simplified acquisitions); formal procurement methods (through sealed bids or proposals); and noncompetitive procurement methods. For any of these methods, the recipient or subrecipient must maintain and use documented procurement procedures, consistent with the standards of this section and §§ 200.317, 200.318, and 200.319.
(a) Informal procurement methods for small purchases. These procurement methods expedite the completion of transactions, minimize administrative burdens, and reduce costs. Informal procurement methods may be used when the value of the procurement transaction under the Federal award does not exceed the simplified acquisition threshold as defined in § 200.1. Recipients and subrecipients may also establish a lower threshold. Informal procurement methods include:
(1) Micro-purchases —(i) Distribution. The aggregate amount of the procurement transaction does not exceed the micro-purchase threshold defined in § 200.1. To the extent practicable, the recipient or subrecipient should distribute micro-purchases equitably among qualified suppliers.
(ii) Micro-purchase awards. Micro-purchases may be awarded without soliciting competitive price or rate quotations if the recipient or subrecipient considers the price reasonable based on research, experience, purchase history, or other information; and maintains documents to support its conclusion. Purchase cards may be used as a method of payment for micro-purchases.
(iii) Micro-purchase thresholds. The recipient or subrecipient is responsible for determining and documenting an appropriate micro-purchase threshold based on internal controls, an evaluation of risk, and its documented procurement procedures. The micro-purchase threshold used by the recipient or subrecipient must be authorized or not prohibited under State, local, or tribal laws or regulations. The recipient or subrecipient may establish a threshold higher than the Federal threshold established in the Federal Acquisition Regulations (FAR) in accordance with paragraphs (a)(1)(iv) and (v) of this section.
(iv) Recipient or subrecipient increase to the micro-purchase threshold up to $50,000. The recipient or subrecipient may establish a threshold higher than the micro-purchase threshold identified in the FAR in accordance with the requirements of this section. The recipient or subrecipient may self-certify a threshold up to $50,000 on an annual basis and must maintain documentation to be made available to the Federal agency or pass-through entity and auditors in accordance with § 200.334. The self-certification must include a justification, clear identification of the threshold, and supporting documentation of any of the following:
(A) A qualification as a low-risk auditee, in accordance with the criteria in § 200.520 for the most recent audit;
(B) An annual internal institutional risk assessment to identify, mitigate, and manage financial risks; or,
(C) For public institutions, a higher threshold is consistent with State law.
(v) Recipient or subrecipient increase to the micro-purchase threshold over $50,000. Micro-purchase thresholds higher than $50,000 must be approved by the cognizant agency for indirect costs. The recipient or subrecipient must submit a request that includes the requirements in paragraph (a)(1)(iv) of this section. The increased threshold is valid until any factor that was relied on in the establishment and rationale of the threshold changes.
(2) Simplified acquisitions— (i) Simplified acquisition procedures. The aggregate dollar amount of the procurement transaction is higher than the micro-purchase threshold but does not exceed the simplified acquisition threshold. If simplified acquisition procedures are used, price or rate quotations must be obtained from an adequate number of qualified sources. Unless specified by the Federal agency, the recipient or subrecipient may exercise judgment in determining what number is adequate.
(ii) Simplified acquisition thresholds. The recipient or subrecipient is responsible for determining an appropriate simplified acquisition threshold based on internal controls, an evaluation of risk, and its documented procurement procedures, which may be lower than, but must not exceed, the threshold established in the FAR.
(b) Formal procurement methods. Formal procurement methods are required when the value of the procurement transaction under a Federal award exceeds the simplified acquisition threshold of the recipient or subrecipient. Formal procurement methods are competitive and require public notice. The following formal methods of procurement are used for procurement transactions above the simplified acquisition threshold determined by the recipient or subrecipient in accordance with paragraph (a)(2)(ii) of this section:
(1) Sealed bids. This is a procurement method in which bids are publicly solicited through an invitation and a firm fixed-price contract (lump sum or unit price) is awarded to the responsible bidder whose bid conforms with all the material terms and conditions of the invitation and is the lowest in price. The sealed bids procurement method is preferred for procuring construction services.
(i) For sealed bidding to be feasible, the following conditions should be present:
(A) A complete, adequate, and realistic specification or purchase description is available; (B) Two or more responsible bidders have been identified as willing and able to compete effectively for the business; and
(C) The procurement lends itself to a firm-fixed-price contract, and the selection of the successful bidder can be made principally based on price.
(ii) If sealed bids are used, the following requirements apply:
(A) Bids must be solicited from an adequate number of qualified sources, providing them with sufficient response time prior to the date set for opening the bids. Unless specified by the Federal agency, the recipient or subrecipient may exercise judgment in determining what number is adequate. For local governments, the invitation for bids must be publicly advertised.
(B) The invitation for bids must define the items or services with specific information, including any required specifications, for the bidder to properly respond;
(C) All bids will be opened at the time and place prescribed in the invitation for bids. For local governments, the bids must be opened publicly.
(D) A firm-fixed-price contract is awarded in writing to the lowest responsive bid and responsible bidder. When specified in the invitation for bids, factors such as discounts, transportation cost, and life-cycle costs must be considered in determining which bid is the lowest. Payment discounts must only be used to determine the low bid when the recipient or subrecipient determines they are a valid factor based on prior experience.
(E) The recipient or subrecipient must document and provide a justification for all bids it rejects.
(2) Proposals. This is a procurement method used when conditions are not appropriate for using sealed bids. This procurement method may result in either a fixed-price or cost-reimbursement contract. They are awarded in accordance with the following requirements:
(i) Requests for proposals require public notice, and all evaluation factors and their relative importance must be identified. Proposals must be solicited from multiple qualified entities. To the maximum extent practicable, any proposals submitted in response to the public notice must be considered.
(ii) The recipient or subrecipient must have written procedures for conducting technical evaluations and making selections.
(iii) Contracts must be awarded to the responsible offeror whose proposal is most advantageous to the recipient or subrecipient considering price and other factors; and
(iv) The recipient or subrecipient may use competitive proposal procedures for qualifications-based procurement of architectural/engineering (A/E) professional services whereby the offeror's qualifications are evaluated, and the most qualified offeror is selected, subject to negotiation of fair and reasonable compensation. The method, where the price is not used as a selection factor, can only be used to procure architectural/engineering (A/E) professional services. The method may not be used to purchase other services provided by A/E firms that are a potential source to perform the proposed effort.
(c) Noncompetitive procurement. There are specific circumstances in which the recipient or subrecipient may use a noncompetitive procurement method. The noncompetitive procurement method may only be used if one of the following circumstances applies:
(1) The aggregate amount of the procurement transaction does not exceed the micro-purchase threshold (see paragraph (a)(1) of this section);
(2) The procurement transaction can only be fulfilled by a single source;
(3) The public exigency or emergency for the requirement will not permit a delay resulting from providing public notice of a competitive solicitation;
(4) The recipient or subrecipient requests in writing to use a noncompetitive procurement method, and the Federal agency or pass-through entity provides written approval; or
(5) After soliciting several sources, competition is determined inadequate.
§ 200.321
Contracting with small businesses, minority businesses, women's business enterprises, veteran-owned businesses, and labor surplus area firms.
(a) When possible, the recipient or subrecipient should ensure that small businesses, minority businesses, women's business enterprises, veteran-owned businesses, and labor surplus area firms (See U.S. Department of Labor's list) are considered as set forth below.
(b) Such consideration means:
(1) These business types are included on solicitation lists;
(2) These business types are solicited whenever they are deemed eligible as potential sources;
(3) Dividing procurement transactions into separate procurements to permit maximum participation by these business types;
(4) Establishing delivery schedules (for example, the percentage of an order to be delivered by a given date of each month) that encourage participation by these business types;
(5) Utilizing organizations such as the Small Business Administration and the Minority Business Development Agency of the Department of Commerce; and
(6) Requiring a contractor under a Federal award to apply this section to subcontracts.
§ 200.322
Domestic preferences for procurements.
(a) The recipient or subrecipient should, to the greatest extent practicable and consistent with law, provide a preference for the purchase, acquisition, or use of goods, products, or materials produced in the United States (including but not limited to iron, aluminum, steel, cement, and other manufactured products). The requirements of this section must be included in all subawards, contracts, and purchase orders under Federal awards.
(b) For purposes of this section:
(1) “Produced in the United States” means, for iron and steel products, that all manufacturing processes, from the initial melting stage through the application of coatings, occurred in the United States.
(2) “Manufactured products” means items and construction materials composed in whole or in part of non-ferrous metals such as aluminum; plastics and polymer-based products such as polyvinyl chloride pipe; aggregates such as concrete; glass, including optical fiber; and lumber.
(c) Federal agencies providing Federal financial assistance for infrastructure projects must implement the Buy America preferences set forth in 2 CFR part 184.
§ 200.323
Procurement of recovered materials.
(a) A recipient or subrecipient that is a State agency or agency of a political subdivision of a State and its contractors must comply with section 6002 of the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 as amended, 42 U.S.C. 6962. The requirements of Section 6002 include procuring only items designated in the guidelines of the Environmental Protection Agency (EPA) at 40 CFR part 247 that contain the highest percentage of recovered materials practicable, consistent with maintaining a satisfactory level of competition, where the purchase price of the item exceeds $10,000 or the value of the quantity acquired during the preceding fiscal year exceeded $10,000; procuring solid waste management services in a manner that maximizes energy and resource recovery; and establishing an affirmative procurement program for procurement of recovered materials identified in the EPA guidelines.
(b) The recipient or subrecipient should, to the greatest extent practicable and consistent with law, purchase, acquire, or use products and services that can be reused, refurbished, or recycled; contain recycled content, are biobased, or are energy and water efficient; and are sustainable. This may include purchasing compostable items and other products and services that reduce the use of single-use plastic products. See Executive Order 14057, section 101, Policy.
§ 200.324
Contract cost and price.
(a) The recipient or subrecipient must perform a cost or price analysis for every procurement transaction, including contract modifications, in excess of the simplified acquisition threshold. The method and degree of analysis conducted depend on the facts surrounding the particular procurement transaction. For example, the recipient or subrecipient should consider potential workforce impacts in their analysis if the procurement transaction will displace public sector employees. However, as a starting point, the recipient or subrecipient must make independent estimates before receiving bids or proposals.
(b) Costs or prices based on estimated costs for contracts under the Federal award are allowable only to the extent that the costs incurred or cost estimates included in negotiated prices would be allowable for the recipient or subrecipient under subpart E of this part. The recipient or subrecipient may reference its own cost principles as long as they comply with subpart E of this part.
(c) The recipient or subrecipient must not use the “cost plus a percentage of cost” and “percentage of construction costs” methods of contracting.
§ 200.325
Federal agency or pass-through entity review.
(a) The Federal agency or pass-through entity may review the technical specifications of proposed procurements under the Federal award if the Federal agency or pass-through entity believes the review is needed to ensure that the item or service specified is the one being proposed for acquisition. The recipient or subrecipient must submit the technical specifications of proposed procurements when requested by the Federal agency or pass-through entity. This review should take place prior to the time the specifications are incorporated into a solicitation document. When the recipient or subrecipient desires to accomplish the review after a solicitation has been developed, the Federal agency or pass-through entity may still review the specifications. In those cases, the review should be limited to the technical aspects of the proposed purchase.
(b) When requested, the recipient or subrecipient must provide procurement documents (such as requests for proposals, invitations for bids, or independent cost estimates) to the Federal agency or pass-through entity for pre-procurement review. The Federal agency or pass-through entity may conduct a pre-procurement review when:
(1) The recipient's or subrecipient's procurement procedures or operation fails to comply with the procurement standards in this part;
(2) The procurement is expected to exceed the simplified acquisition threshold and is to be awarded without competition, or only one bid is expected to be received in response to a solicitation;
(3) The procurement is expected to exceed the simplified acquisition threshold and specifies a “brand name” product;
(4) The procurement is expected to exceed the simplified acquisition threshold, and a sealed bid procurement is to be awarded to an entity other than the apparent low bidder; or
(5) A proposed contract modification changes the scope of a contract or increases the contract amount by more than the simplified acquisition threshold.
(c) The recipient or subrecipient is exempt from the pre-procurement review in paragraph (b) of this section if the Federal agency or pass-through entity determines that its procurement systems comply with the standards of this part.
(1) The recipient or subrecipient may request that the Federal agency or pass-through entity review its procurement system to determine whether it meets these standards for its system to be certified. Generally, these reviews must occur where there is continuous high-dollar funding and third-party contracts are awarded regularly.
(2) The recipient or subrecipient may self-certify its procurement system. However, self-certification does not limit the Federal agency's or pass-through entity's right to review the system. Under a self-certification procedure, the Federal agency or pass-through entity may rely on written assurances from the recipient or subrecipient that it is complying with the standards of this part. The recipient or subrecipient must cite specific policies, procedures, regulations, or standards as complying with these requirements and have its system available for review.
§ 200.326
Bonding requirements.
The Federal agency or pass-through entity may accept the recipient's or subrecipient's bonding policy and requirements for construction or facility improvement contracts or subcontracts exceeding the simplified acquisition threshold. Before doing so, the Federal agency or pass-through entity must determine that the Federal interest is adequately protected. If such a determination has not been made, the minimum requirements must be as follows:
(a) A bid guarantee from each bidder equivalent to five percent of the bid price. The bid guarantee must consist of a firm commitment such as a bid bond, certified check, or other negotiable instrument accompanying a bid as assurance that the bidder will, upon acceptance of the bid, execute any required contractual documents within the specified timeframe.
(b) A performance bond on the contractor's part for 100 percent of the contract price. A performance bond is a bond executed in connection with a contract to secure the fulfillment of all the contractor's requirements under a contract.
(c) A payment bond on the contractor's part for 100 percent of the contract price. A payment bond is a bond executed in connection with a contract to assure payment as required by the law of all persons supplying labor and material in the execution of the work provided for under a contract.
§ 200.327
Contract provisions.
The recipient's or subrecipient's contracts must contain the applicable provisions described in Appendix II of this part.

Performance and Financial Monitoring and Reporting
§ 200.328
Financial reporting.
(a) The Federal agency must require only OMB-approved government-wide data elements on recipient financial reports. At the time of publication, this consists of the Federal Financial Report (SF-425); however, this also applies to any future OMB-approved government-wide data elements available from the OMB-designated standards lead.
(b) The Federal agency or pass-through entity must collect financial reports no less than annually. The Federal agency or pass-through entity may not collect financial reports more frequently than quarterly unless a specific condition has been implemented in accordance with § 200.208. To the extent practicable, the Federal agency or pass-through entity should collect financial reports in coordination with performance reports.
(c) The recipient or subrecipient must submit financial reports as required by the Federal award. Reports submitted annually by the recipient or subrecipient must be due no later than 90 calendar days after the reporting period. Reports submitted quarterly or semiannually must be due no later than 30 calendar days after the reporting period.
(d) The final financial report submitted by the recipient must be due no later than 120 calendar days after the conclusion of the period of performance. A subrecipient must submit a final financial report to a pass-through entity no later than 90 calendar days after the conclusion of the period of performance. See also § 200.344. The Federal agency or pass-through entity may extend the due date for any financial report with justification from the recipient or subrecipient.
§ 200.329
Monitoring and reporting program performance.
(a) Monitoring by the recipient and subrecipient. The recipient and subrecipient are responsible for the oversight of the Federal award. The recipient and subrecipient must monitor their activities under Federal awards to ensure they are compliant with all requirements and meeting performance expectations. Monitoring by the recipient and subrecipient must cover each program, function, or activity. See also § 200.332.
(b) Reporting program performance. The Federal agency must use OMB-approved common information collections (for example, Research Performance Progress Reports) when requesting performance reporting information. The Federal agency or pass-through entity may not collect performance reports more frequently than quarterly unless a specific condition has been implemented in accordance with § 200.208. To the extent practicable, the Federal agency or pass-through entity should align the due dates of performance reports and financial reports. When reporting program performance, the recipient or subrecipient must relate financial data and project or program accomplishments to the performance goals and objectives of the Federal award. Also, the recipient or subrecipient must provide cost information to demonstrate cost-effective practices (for example, through unit cost data) when required by the terms and conditions of the Federal award. In some instances (for example, discretionary research awards), this may be limited to the requirement to submit technical performance reports. Reporting requirements must clearly indicate a standard against which the recipient's or subrecipient's performance can be measured. Reporting requirements should not solicit information from the recipient or subrecipient that is not necessary for the effective monitoring or evaluation of the Federal award. Federal agencies should consult monitoring framework documents such as the agency's Evaluation Plan to make that determination. As noted in OMB Circular A-11, Part 6, Section 280, measures of customer experience are of co-equal importance as traditional measures of financial and operational performance.
(c) Submitting performance reports. (1) The recipient or subrecipient must submit performance reports as required by the Federal award. Intervals must be no less frequent than annually nor more frequent than quarterly except if specific conditions are applied (See § 200.208). Reports submitted annually by the recipient or subrecipient must be due no later than 90 calendar days after the reporting period. Reports submitted quarterly or semiannually must be due no later than 30 calendar days after the reporting period. Alternatively, the Federal agency or pass-through entity may require annual reports before the anniversary dates of multiple-year Federal awards. The final performance report submitted by the recipient must be due no later than 120 calendar days after the period of performance. A subrecipient must submit a final performance report to a pass-through entity no later than 90 calendar days after the conclusion of the period of performance. See also § 200.344. The Federal agency or pass-through entity may extend the due date for any performance report with justification from the recipient or subrecipient.
(2) As applicable, performance reports should contain information on the following:
(i) A comparison of accomplishments to the objectives of the Federal award established for the reporting period (for example, comparing costs to units of accomplishment). Where performance trend data and analysis would be informative to the Federal agency program, the Federal agency should include this as a performance reporting requirement.
(ii) Explanations on why established goals or objectives were not met; and
(iii) Additional information, analysis, and explanation of cost overruns or higher-than-expected unit costs.
(d) Construction performance reports. Federal agencies or pass-through entities rely on on-site technical inspections and certified percentage of completion data to monitor progress under Federal awards for construction. Therefore, the Federal agency or pass-through entity may require additional performance reports when necessary to ensure the goals and objectives of Federal awards are met.
(e) Significant developments. When a significant development that could impact the Federal award occurs between performance reporting due dates, the recipient or subrecipient must notify the Federal agency or pass-through entity. Significant developments include events that enable meeting milestones and objectives sooner or at less cost than anticipated or that produce different beneficial results than originally planned. Significant developments also include problems, delays, or adverse conditions which will impact the recipient's or subrecipient's ability to meet milestones or the objectives of the Federal award. When significant developments occur that negatively impact the Federal Award, the recipient or subrecipient must include information on their plan for corrective action and any assistance needed to resolve the situation.
(f) Site visits. The Federal agency or pass-through entity may conduct in-person or virtual site visits as warranted.
(g) Performance report requirement waiver. The Federal agency may waive any performance report that is not necessary to ensure the goals and objectives of the Federal award are being achieved.
§ 200.330
Reporting on real property.
The Federal agency or pass-through entity must require the recipient or subrecipient to submit reports on the status of real property in which the Federal Government retains an interest. Such reports must be submitted at least annually. In instances where the Federal Government's interest in the real property extends for 15 years or more, the Federal agency or pass-through entity may require the recipient or subrecipient to report at various multi-year frequencies. Reports submitted at multi-year frequencies may not exceed a five-year reporting period. The Federal agency must only require OMB-approved government-wide data elements on recipient real property reports.

Subrecipient Monitoring and Management
§ 200.331
Subrecipient and contractor determinations.
An entity may concurrently receive Federal awards as a recipient, a subrecipient, and a contractor. The pass-through entity is responsible for making case-by-case determinations to determine whether the entity receiving Federal funds is a subrecipient or a contractor. The Federal agency may require the pass-through entity to comply with additional guidance to make these determinations, provided such guidance does not conflict with this section. The Federal agency does not have a direct legal relationship with subrecipients or contractors of any tier; however, the Federal agency is responsible for monitoring the pass-through entity's oversight of first-tier subrecipients. All of the characteristics listed below may not be present in all cases, and some characteristics from both categories may be present at the same time. No single factor or any combination of factors is necessarily determinative. The pass-through entity must use judgment in classifying each agreement as a subaward or a procurement contract. In making this determination, the substance of the relationship is more important than the form of the agreement.
(a) Subrecipients. A subaward is for the purpose of carrying out a portion of the Federal award and creates a Federal financial assistance relationship with a subrecipient. See the definition of Subaward in § 200.1. Characteristics that support the classification of the entity as a subrecipient include, but are not limited to, when the entity:
(1) Determines who is eligible to receive what Federal assistance;
(2) Has its performance measured in relation to whether the objectives of a Federal program were met;
(3) Has responsibility for programmatic decision-making;
(4) Is responsible for adherence to applicable Federal program requirements specified in the Federal award; and
(5) Implements a program for a public purpose specified in authorizing statute, as opposed to providing goods or services for the benefit of the pass-through entity.
(b) Contractors. A contract is for the purpose of obtaining goods and services for the recipient's or subrecipient's use and creates a procurement relationship with a contractor. See the definition of contract in § 200.1. Characteristics that support a procurement relationship between the recipient or subrecipient and a contractor include, but are not limited to, when the contractor:
(1) Provides the goods and services within normal business operations;
(2) Provides similar goods or services to many different purchasers;
(3) Normally operates in a competitive environment;
(4) Provides goods or services that are ancillary to the implementation of a Federal program; and
(5) Is not subject to compliance requirements of a Federal program as a result of the agreement. However, similar requirements may apply for other reasons.
§ 200.332
Requirements for pass-through entities.
A pass-through entity must:
(a) Verify that the subrecipient is not excluded or disqualified in accordance with § 180.300. Verification methods are provided in § 180.300, which include confirming in SAM.gov that a potential subrecipient is not suspended, debarred, or otherwise excluded from receiving Federal funds.
(b) Ensure that every subaward is clearly identified to the subrecipient as a subaward and includes the information provided below. A pass-through entity must provide the best available information when some of the information below is unavailable. A pass-through entity must provide the unavailable information when it is obtained. Required information includes:
(1) Federal award identification.
(i) Subrecipient's name (must match the name associated with its unique entity identifier);
(ii) Subrecipient's unique entity identifier;
(iii) Federal Award Identification Number (FAIN);
(iv) Federal Award Date;
(v) Subaward Period of Performance Start and End Date;
(vi) Subaward Budget Period Start and End Date;
(vii) Amount of Federal Funds Obligated in the subaward;
(viii) Total Amount of Federal Funds Obligated to the subrecipient by the pass-through entity, including the current financial obligation;
(ix) Total Amount of the Federal Award committed to the subrecipient by the pass-through entity;
(x) Federal award project description, as required by the Federal Funding Accountability and Transparency Act (FFATA);
(xi) Name of the Federal agency, pass-through entity, and contact information for awarding official of the pass-through entity;
(xii) Assistance Listings title and number; the pass-through entity must identify the dollar amount made available under each Federal award and the Assistance Listings Number at the time of disbursement;
(xiii) Identification of whether the Federal award is for research and development; and
(xiv) Indirect cost rate for the Federal award (including if the de minimis rate is used in accordance with § 200.414).
(2) All requirements of the subaward, including requirements imposed by Federal statutes, regulations, and the terms and conditions of the Federal award;
(3) Any additional requirements that the pass-through entity imposes on the subrecipient for the pass-through entity to meet its responsibilities under the Federal award. This includes information and certifications (see § 200.415) required for submitting financial and performance reports that the pass-through entity must provide to the Federal agency;
(4) Indirect cost rate:
(i) An approved indirect cost rate negotiated between the subrecipient and the Federal Government. If no approved rate exists, a pass-through entity must determine the appropriate rate in collaboration with the subrecipient. The indirect cost rate may be either:
(A) An indirect cost rate negotiated between the pass-through entity and the subrecipient. These rates may be based on a prior negotiated rate between a different pass-through entity and the subrecipient, in which case the pass-through entity is not required to collect information justifying the rate but may elect to do so; or
(B) The de minimis indirect cost rate.
(ii) The pass-through entity must not require the use of the de minimis indirect cost rate if the subrecipient has an approved indirect cost rate negotiated with the Federal Government. Subrecipients may elect to use the cost allocation method to account for indirect costs in accordance with § 200.405(d).
(5) A requirement that the subrecipient permit the pass-through entity and auditors to access the subrecipient's records and financial statements for the pass-through entity to fulfill its monitoring requirements; and
(6) Appropriate terms and conditions concerning the closeout of the subaward.
(c) Evaluate each subrecipient's fraud risk and risk of noncompliance with a subaward to determine the appropriate subrecipient monitoring described in paragraph (f) of this section. When evaluating a subrecipient's risk, a pass-through entity should consider the following:
(1) The subrecipient's prior experience with the same or similar subawards;
(2) The results of previous audits. This includes considering whether or not the subrecipient receives a Single Audit in accordance with subpart F and the extent to which the same or similar subawards have been audited as a major program;
(3) Whether the subrecipient has new personnel or new or substantially changed systems; and
(4) The extent and results of any Federal agency monitoring (for example, if the subrecipient also receives Federal awards directly from the Federal agency).
(d) If appropriate, consider implementing specific conditions in a subaward as described in § 200.208 and notify the Federal agency of the specific conditions.
(e) Monitor the activities of a subrecipient as necessary to ensure that the subrecipient complies with Federal statutes, regulations, and the terms and conditions of the subaward. The pass-through entity is responsible for monitoring the overall performance of a subrecipient to ensure that the goals and objectives of the subaward are achieved. In monitoring a subrecipient, a pass-through entity must:
(1) Review financial and performance reports.
(2) Ensure that the subrecipient takes corrective action on all significant developments that negatively affect the subaward. Significant developments include Single Audit findings related to the subaward, other audit findings, site visits, and written notifications from a subrecipient of adverse conditions which will impact their ability to meet the milestones or the objectives of a subaward. When significant developments negatively impact the subaward, a subrecipient must provide the pass-through entity with information on their plan for corrective action and any assistance needed to resolve the situation.
(3) Issue a management decision for audit findings pertaining only to the Federal award provided to the subrecipient from the pass-through entity as required by § 200.521.
(4) Resolve audit findings specifically related to the subaward. However, the pass-through entity is not responsible for resolving cross-cutting audit findings that apply to the subaward and other Federal awards or subawards. If a subrecipient has a current Single Audit report and has not been excluded from receiving Federal funding (meaning, has not been debarred or suspended), the pass-through entity may rely on the subrecipient's cognizant agency for audit or oversight agency for audit to perform audit follow-up and make management decisions related to cross-cutting audit findings in accordance with section § 200.513(a)(4)(viii). Such reliance does not eliminate the responsibility of the pass-through entity to issue subawards that conform to agency and award-specific requirements, to manage risk through ongoing subaward monitoring, and to monitor the status of the findings that are specifically related to the subaward.
(f) Depending upon the pass-through entity's assessment of the risk posed by the subrecipient (as described in paragraph (c) of this section), the following monitoring tools may be useful for the pass-through entity to ensure proper accountability and compliance with program requirements and achievement of performance goals:
(1) Providing subrecipients with training and technical assistance on program-related matters;
(2) Performing site visits to review the subrecipient's program operations; and
(3) Arranging for agreed-upon-procedures engagements as described in § 200.425.
(g) Verify that a subrecipient is audited as required by subpart F of this part.
(h) Consider whether the results of a subrecipient's audit, site visits, or other monitoring necessitate adjustments to the pass-through entity's records.
(i) Consider taking enforcement action against noncompliant subrecipients as described in § 200.339 and in program regulations.
§ 200.333
Fixed amount subawards.
With prior written approval from the Federal agency, the recipient may provide subawards based on fixed amounts up to $500,000. Fixed amount subawards must meet the requirements of § 200.201.

Record Retention and Access
§ 200.334
Record retention requirements.
The recipient and subrecipient must retain all Federal award records for three years from the date of submission of their final financial report. For awards that are renewed quarterly or annually, the recipient and subrecipient must retain records for three years from the date of submission of their quarterly or annual financial report, respectively. Records to be retained include but are not limited to, financial records, supporting documentation, and statistical records. Federal agencies or pass-through entities may not impose any other record retention requirements except for the following:
(a) The records must be retained until all litigation, claims, or audit findings involving the records have been resolved and final action taken if any litigation, claim, or audit is started before the expiration of the three-year period.
(b) When the recipient or subrecipient is notified in writing by the Federal agency or pass-through entity, cognizant agency for audit, oversight agency for audit, or cognizant agency for indirect costs to extend the retention period.
(c) The records for property and equipment acquired with the support of Federal funds must be retained for three years after final disposition.
(d) The three-year retention requirement does not apply to the recipient or subrecipient when records are transferred to or maintained by the Federal agency.
(e) The records for program income earned after the period of performance must be retained for three years from the end of the recipient's or subrecipient's fiscal year in which the program income is earned. This only applies if the Federal agency or pass-through entity requires the recipient or subrecipient to report on program income earned after the period of performance in the terms and conditions of the Federal award.
(f) The records for indirect cost rate computations or proposals, cost allocation plans, and any similar accounting computations of the rate at which a particular group of costs is chargeable (such as computer usage chargeback rates or composite fringe benefit rates) must be retained according to the applicable option below:
(1) If submitted for negotiation. When a proposal, plan, or other computation must be submitted to the Federal Government to form the basis for negotiation of an indirect cost rate (or other standard rates), then the three-year retention period for its supporting records starts from the date of submission.
(2) If not submitted for negotiation. When a proposal, plan, or other computation is not required to be submitted to the Federal Government to form the basis for negotiation of an indirect cost rate (or other standard rates), then the three-year retention period for its supporting records starts from the end of the fiscal year (or other accounting period) covered by the proposal, plan, or other computation.
§ 200.335
Requests for transfer of records.
The Federal agency must request the transfer of records to its custody from the recipient or subrecipient when it determines that the records possess long-term retention value. However, the Federal agency may arrange for the recipient or subrecipient to retain the records that have long-term retention value so long as they are continuously available to the Federal Government.
§ 200.336
Methods for collection, transmission, and storage of information.
When practicable, the Federal agency or pass-through entity and the recipient or subrecipient must collect, transmit, and store Federal award information in open and machine-readable formats. A machine-readable format is a format in a standard computer language (not English text) that can be read automatically by a computer system. Upon request, the Federal agency or pass-through entity must always provide or accept paper versions of Federal award information to and from the recipient or subrecipient. The Federal agency or pass-through entity must not require additional copies of Federal award information submitted in paper versions. The recipient or subrecipient does not need to create and retain paper copies when original records are electronic and cannot be altered. In addition, the recipient or subrecipient may substitute electronic versions of original paper records through duplication or other forms of electronic conversion, provided that the procedures are subject to periodic quality control reviews. Quality control reviews must ensure that electronic conversion procedures provide safeguards against the alteration of records and assurance that records remain in a format that is readable by a computer system.
§ 200.337
Access to records.
(a) Records of recipients and subrecipients. The Federal agency or pass-through entity, Inspectors General, the Comptroller General of the United States, or any of their authorized representatives must have the right of access to any records of the recipient or subrecipient pertinent to the Federal award to perform audits, execute site visits, or for any other official use. This right also includes timely and reasonable access to the recipient's or subrecipient's personnel for the purpose of interview and discussion related to such documents or the Federal award in general.
(b) Extraordinary and rare circumstances. The recipient or subrecipient and Federal agency or pass-through entity must take measures to protect the name of victims of a crime when access to the victim's name is necessary. Only under extraordinary and rare circumstances would such access include a review of the true name of victims of a crime. Routine monitoring cannot be considered extraordinary and rare circumstances that would necessitate access to this information. Any such access, other than under a court order or subpoena pursuant to a bona fide confidential investigation, must be approved by the head or delegate of the Federal agency.
(c) Expiration of right of access. The Federal agency's or pass-through entity's rights of access are not limited to the required retention period of this part but last as long as the records are retained. Federal agencies or pass-through entities must not impose any other access requirements upon recipients and subrecipients.
§ 200.338
Restrictions on public access to records.
Federal agencies may not place restrictions on the recipient or subrecipient that limit public access to the records of the recipient or subrecipient pertinent to a Federal award, except for protected personally identifiable information (PII) or other sensitive information when the Federal agency can demonstrate that such records will be kept confidential and would have been exempted from disclosure pursuant to the Freedom of Information Act (5 U.S.C. 552) or controlled unclassified information pursuant to Executive Order 13556 if the records had belonged to the Federal agency. The Freedom of Information Act (5 U.S.C. 552) (FOIA) does not apply to records that remain under the recipient's or subrecipient's control except as required by § 200.315. Unless required by Federal, State, local, or tribal law, recipients and subrecipients are not required to permit public access to their records. The recipient's or subrecipient's records provided to a Federal agency generally will be subject to FOIA and applicable exemptions.

Remedies for Noncompliance
§ 200.339
Remedies for noncompliance.
The Federal agency or pass-through entity may implement specific conditions if the recipient or subrecipient fails to comply with the U.S. Constitution, Federal statutes, regulations, or terms and conditions of the Federal award. See § 200.208 for additional information on specific conditions. When the Federal agency or pass-through entity determines that noncompliance cannot be remedied by imposing specific conditions, the Federal agency or pass-through entity may take one or more of the following actions:
(a) Temporarily withhold payments until the recipient or subrecipient takes corrective action.
(b) Disallow costs for all or part of the activity associated with the noncompliance of the recipient or subrecipient.
(c) Suspend or terminate the Federal award in part or in its entirety.
(d) Initiate suspension or debarment proceedings as authorized in 2 CFR part 180 and the Federal agency's regulations, or for pass-through entities, recommend suspension or debarment proceedings be initiated by the Federal agency.
(e) Withhold further Federal funds (new awards or continuation funding) for the project or program.
(f) Pursue other legally available remedies.
§ 200.340
Termination.
(a) The Federal award may be terminated in part or its entirety as follows:
(1) By the Federal agency or pass-through entity if the recipient or subrecipient fails to comply with the terms and conditions of the Federal award;
(2) By the Federal agency or pass-through entity with the consent of the recipient or subrecipient, in which case the two parties must agree upon the termination conditions. These conditions include the effective date and, in the case of partial termination, the portion to be terminated;
(3) By the recipient or subrecipient upon sending the Federal agency or pass-through entity a written notification of the reasons for such termination, the effective date, and, in the case of partial termination, the portion to be terminated. However, if the Federal agency or pass-through entity determines that the remaining portion of the Federal award will not accomplish the purposes for which the Federal award was made, the Federal agency or pass-through entity may terminate the Federal award in its entirety; or
(4) By the Federal agency or pass-through entity pursuant to the terms and conditions of the Federal award, including, to the extent authorized by law, if an award no longer effectuates the program goals or agency priorities.
(b) The Federal agency or pass-through entity must clearly and unambiguously specify all termination provisions in the terms and conditions of the Federal award.
(c) When the Federal agency terminates the Federal award prior to the end of the period of performance due to the recipient's material failure to comply with the terms and conditions of the Federal award, the Federal agency must report the termination in SAM.gov . A Federal agency must use the Contractor Performance Assessment Reporting System (CPARS) to enter information in SAM.gov .
(1) The information required under paragraph (c) of this section is not to be reported in SAM.gov until the recipient has either:
(i) Exhausted its opportunities to object or challenge the decision (see § 200.342); or
(ii) Has not, within 30 calendar days after being notified of the termination, informed the Federal agency that it intends to appeal the decision to terminate.
(2) If a Federal agency, after entering information about a termination in SAM.gov , subsequently:
(i) Learns that any of that information is erroneous, the Federal agency must correct the information in the system within three business days;
(ii) Obtains an update to that information that could be helpful to other Federal agencies, the Federal agency is strongly encouraged to amend the information in the system to incorporate the update in a timely way.
(3) The Federal agency must not post any information that will be made publicly available in the non-public segment of SAM.gov that is covered by a disclosure exemption under the Freedom of Information Act (FOIA). When the recipient asserts within seven calendar days to the Federal agency which posted the information that a disclosure exemption under FOIA covers some of the information made publicly available, the Federal agency that posted the information must remove the posting within seven calendar days of receiving the assertion. Before reposting the releasable information, the Federal agency must resolve the issue in accordance with the agency's FOIA procedures.
(d) When the Federal award is terminated in part or its entirety, the Federal agency or pass-through entity and recipient or subrecipient remain responsible for compliance with the requirements in §§ 200.344 and 200.345.
§ 200.341
Notification of termination requirement.
(a) The Federal agency or pass-through entity must provide written notice of termination to the recipient or subrecipient. The written notice of termination should include the reasons for termination, the effective date, and the portion of the Federal award to be terminated, if applicable.
(b) If the Federal award is terminated for the recipient's material failure to comply with a Federal award, the notification must state the following:
(1) The termination decision will be reported in SAM.gov ;
(2) The information will be available in SAM.gov for five years from the date of the termination and then archived;
(3) Federal agencies that consider making a Federal award to the recipient during the five year period must consider this information in judging whether the recipient is qualified to receive the Federal award when the Federal share of the Federal award is expected to exceed the simplified acquisition threshold over the period of performance;
(4) The recipient may comment on any information in SAM.gov about the recipient for future consideration by Federal agencies. The recipient may submit comments in SAM.gov .
(5) Federal agencies should consider the recipient's comments when determining whether the recipient is qualified for a Federal award.
(c) Upon termination of the Federal award, the Federal agency must provide the information required by the Federal Funding Accountability and Transparency Act (FFATA) to USAspending.gov. In addition, the Federal agency must update or notify any other relevant government-wide systems or entities of any indications of poor performance as required by 41 U.S.C. 2313 and 31 U.S.C. 3321.
§ 200.342
Opportunities to object, hearings, and appeals.
The Federal agency must maintain written procedures for processing objections, hearings, and appeals. Upon initiating a remedy for noncompliance (for example, disallowed costs, a corrective action plan, or termination), the Federal agency must provide the recipient with an opportunity to object and provide information challenging the action. The Federal agency or pass-through entity must comply with any requirements for hearings, appeals, or other administrative proceedings to which the recipient or subrecipient is entitled under any statute or regulation applicable to the action involved.
§ 200.343
Effects of suspension and termination.
Costs to the recipient or subrecipient resulting from financial obligations incurred by the recipient or subrecipient during a suspension or after the termination of a Federal award are not allowable unless the Federal agency or pass-through entity expressly authorizes them in the notice of suspension or termination or subsequently. However, costs during suspension or after termination are allowable if:
(a) The costs result from financial obligations which were properly incurred by the recipient or subrecipient before the effective date of suspension or termination, and not in anticipation of it; and
(b) The costs would be allowable if the Federal award was not suspended or expired normally at the end of the period of performance in which the termination takes effect.

Closeout
§ 200.344
Closeout.
(a) The Federal agency or pass-through entity must close out the Federal award when it determines that all administrative actions and required work of the Federal award have been completed. When the recipient or subrecipient fails to complete the necessary administrative actions or the required work for an award, the Federal agency or pass-through entity must proceed with closeout based on the information available. This section specifies the administrative actions required at the end of the period of performance.
(b) A recipient must submit all reports (financial, performance, and other reports required by the Federal award) no later than 120 calendar days after the conclusion of the period of performance. A subrecipient must submit all reports (financial, performance, and other reports required by a subaward) to the pass-through entity no later than 90 calendar days after the conclusion of the period of performance of the subaward (or an earlier date as agreed upon by the pass-through entity and subrecipient). When justified, the Federal agency or pass-through entity may approve extensions for the recipient or subrecipient. When the recipient does not have a final indirect cost rate covering the period of performance, a final financial report must still be submitted to fulfill the requirements of this section. The recipient must submit a revised final financial report when all applicable indirect cost rates have been finalized.
(c) The recipient must liquidate all financial obligations incurred under the Federal award no later than 120 calendar days after the conclusion of the period of performance. A subrecipient must liquidate all financial obligations incurred under a subaward no later than 90 calendar days after the conclusion of the period of performance of the subaward (or an earlier date as agreed upon by the pass-through entity and subrecipient). When justified, the Federal agency or pass-through entity may approve extensions for the recipient or subrecipient.
(d) The Federal agency or pass-through entity must not delay payments to the recipient or subrecipient for costs meeting the requirements of subpart E of this part.
(e) The recipient or subrecipient must promptly refund any unobligated funds that the Federal agency or pass-through entity paid and that are not authorized to be retained. See OMB Circular A-129 and § 200.346.
(f) The Federal agency or pass-through entity must make all necessary adjustments to the Federal share of costs after closeout reports are received (for example, to reflect the disallowance of any costs or the deobligation of an unliquidated balance).
(g) The recipient or subrecipient must account for any property acquired with Federal funds or received from the Federal Government in accordance with §§ 200.310 through 200.316 and 200.330.
(h) The Federal agency must make every effort to complete all closeout actions no later than one year after the end of the period of performance. If the indirect cost rate has not been finalized and would delay closeout, the Federal agency is authorized to mutually agree with the recipient to close an award using the current or most recently negotiated rate. However, the recipient is not required to agree to a final rate for a Federal award for the purpose of prompt closeout.
(i) If the recipient does not comply with the requirements of this section, including submitting all final reports, the Federal agency must report the recipient's material failure to comply with the terms and conditions of the Federal award in SAM.gov . A Federal agency must use the Contractor Performance Assessment Reporting System (CPARS) to enter or amend information in SAM.gov . Federal agencies may also pursue other enforcement actions as appropriate. See § 200.339.

Post-Closeout Adjustments and Continuing Responsibilities
§ 200.345
Post-closeout adjustments and continuing responsibilities.
(a) The closeout of the Federal award does not affect any of the following:
(1) The right of the Federal agency or pass-through entity to disallow costs and recover funds on the basis of a later audit or review. However, the Federal agency or pass-through entity must make determinations to disallow costs and notify the recipient or subrecipient within the record retention period.
(2) The recipient's or subrecipient's requirement to return funds or right to receive any remaining and available funds as a result of refunds, corrections, final indirect cost rate adjustments (unless the Federal award in closed in accordance with § 200.344(h)), or other transactions.
(3) The ability of the Federal agency or pass-through entity to make financial adjustments to a previously closed Federal award, such as resolving indirect cost payments and making final payments.
(4) Audit requirements in subpart F of this part.
(5) Property management and disposition requirements in §§ 200.310 through 200.316.
(6) Records retention as required in §§ 200.334 through 200.337.
(b) After the closeout of the Federal award, a relationship created under the Federal award may be modified or ended in whole or in part. This may only be done with the consent of the awarding Federal agency or pass-through entity and the recipient or subrecipient, provided the responsibilities of the recipient or subrecipient referred to in paragraph (a) of this section, including those for property management as applicable, are considered and provisions are made for continuing responsibilities of the recipient or subrecipient, as appropriate.

Collection of Amounts Due
§ 200.346
Collection of amounts due.
Any Federal funds paid to the recipient or subrecipient in excess of the amount that the recipient or subrecipient is determined to be entitled to under the Federal award constitute a debt to the Federal Government. The Federal agency must collect all debts arising out of its Federal awards in accordance with the Standards for the Administrative Collection of Claims (31 CFR part 901).

Subpart E—Cost Principles

General Provisions
§ 200.400
Policy guide.
The application of these cost principles is based on the fundamental premises that:
(a) The recipient and subrecipient are responsible for the efficient and effective administration of the Federal award through sound management practices.
(b) The recipient and subrecipient are responsible for administering Federal funds in a manner consistent with Federal statutes, regulations, and the terms and conditions of the Federal award.
(c) The recipient and subrecipient, in recognition of their unique combination of staff, facilities, and experience, are responsible for employing organization and management techniques necessary to ensure the proper and efficient administration of the Federal award.
(d) The accounting practices of the recipient and subrecipient must be consistent with these cost principles and support the accumulation of costs as required by these cost principles, including maintaining adequate documentation to support costs charged to the Federal award.
(e) When reviewing, negotiating, and approving cost allocation plans or indirect cost proposals, the cognizant agency for indirect costs should ensure that the recipient consistently applies these cost principles. Where wide variations exist in the treatment of a given cost item by the recipient, the reasonableness and equity of such treatments should be fully considered. See the definition of indirect costs in § 200.1.
(f) For recipients and subrecipients that educate and engage students in research, the dual role of students as both trainees and employees (including pre- and post-doctoral staff) contributing to the completion of Federal awards for research must be recognized in the application of these principles.
(g) The recipient or subrecipient must not earn or keep any profit resulting from Federal financial assistance unless explicitly authorized by the terms and conditions of the Federal award. See also § 200.307. When the required activities of a fixed amount award were completed in accordance with the terms and conditions of the award, the unexpended funds retained by the recipient or subrecipient are not considered profit.
§ 200.401
Application.
(a) General. The recipient and subrecipient must apply these principles in determining allowable costs under Federal awards. The recipient and subrecipient must also use these principles as a guide in pricing fixed-price contracts and subcontracts when costs are used in determining the appropriate price. These cost principles do not apply to:
(1) Arrangements under which Federal financing is in the form of loans, scholarships, fellowships, traineeships, or other fixed amounts based on items such as education allowance or published tuition rates and fees.
(2) Capitation awards based on case counts or the number of beneficiaries.
(3) Fixed amount awards, except as provided in § 200.101(b). See also § 200.201.
(4) Federal awards to hospitals (see Appendix IX of this part).
(5) Food commodities provided through grants and cooperative agreements.
(6) Other awards under which the recipient or subrecipient is not required to account for actual costs incurred.
(b) Federal contract. A Federal contract awarded to a recipient is subject to the Cost Accounting Standards (CAS). It must incorporate the applicable CAS requirements per 48 CFR Chapter 99 and 48 CFR part 30 (FAR Part 30). With respect to the allocation of costs, the Cost Accounting Standards at 48 CFR parts 9904 or 9905 take precedence over the cost principles in subpart E. When a contract with a recipient is subject to full CAS coverage, the allowability of certain costs under the cost principles will be affected by the allocation provisions of the Cost Accounting Standards (for example, CAS 414—48 CFR 9904.414—Cost of Money as an Element of the Cost of Facilities Capital, and CAS 417—48 CFR 9904.417—Cost of Money as an Element of the Cost of Capital Assets Under Construction, apply instead of the allowability provisions of § 200.449). For example, the allowability of costs in CAS-covered contracts is determined first by the allocation provisions of the Cost Accounting Standards rather than the allowability provisions in § 200.449 (unless the CAS does not address the specific costs). In complying with those requirements, the recipient's application of cost accounting practices for estimating, accumulating, and reporting costs for Federal awards and CAS-covered contracts must be consistent with 48 CFR. The recipient only needs to maintain one set of accounting records supporting the allocation of costs if the recipient administers both Federal awards and CAS-covered contracts.
(c) Exemptions. Some nonprofit organizations, because of their size and nature of operations, can be considered to be similar to for-profit organizations in terms of the applicability of cost principles. These nonprofit organizations must operate under Federal cost principles that apply to for-profit organizations located at 48 CFR 31.2. Appendix VIII contains a list of these nonprofit organizations. Other organizations may be added to this list if approved by the cognizant agency for indirect costs.

Basic Considerations
§ 200.402
Composition of costs.
The total cost of a Federal award is the sum of the allowable direct and allocable indirect costs minus any applicable credits
§ 200.403
Factors affecting allowability of costs.
Except where otherwise authorized by statute, costs must meet the following criteria to be allowable under Federal awards:
(a) Be necessary and reasonable for the performance of the Federal award and be allocable thereto under these principles.
(b) Conform to any limitations or exclusions set forth in these principles or in the Federal award as to types or amount of cost items.
(c) Be consistent with policies and procedures that apply uniformly to both federally financed and other activities of the recipient or subrecipient.
(d) Be accorded consistent treatment. For example, a cost must not be assigned to a Federal award as a direct cost if any other cost incurred for the same purpose in like circumstances has been allocated to the Federal award as an indirect cost.
(e) Be determined in accordance with generally accepted accounting principles (GAAP), except, for State and local governments and Indian Tribes only, as otherwise provided for in this part.
(f) Not be included as a cost or used to meet cost sharing requirements of any other federally-financed program in either the current or a prior period. See § 200.306(b).
(g) Be adequately documented. See §§ 200.300 through 200.309.
(h) Administrative closeout costs may be incurred until the due date of the final report(s). If incurred, these costs must be liquidated prior to the due date of the final report(s) and charged to the final budget period of the award unless otherwise specified by the Federal agency. All other costs must be incurred during the approved budget period. At its discretion, the Federal agency is authorized to waive prior written approvals to carry forward unobligated balances to subsequent budget periods. See § 200.308(g)(3).
§ 200.404
Reasonable costs.
A cost is reasonable if it does not exceed an amount that a prudent person would incur under the circumstances prevailing when the decision was made to incur the cost. In determining the reasonableness of a given cost, consideration must be given to the following:
(a) Whether the cost is generally recognized as ordinary and necessary for the recipient's or subrecipient's operation or the proper and efficient performance of the Federal award;
(b) The restraints or requirements imposed by such factors as sound business practices; arm's-length bargaining; Federal, State, local, tribal, and other laws and regulations; and terms and conditions of the Federal award;
(c) Market prices for comparable costs for the geographic area;
(d) Whether the individuals concerned acted with prudence in the circumstances considering their responsibilities to the recipient or subrecipient, its employees, its students or membership (if applicable), the public at large, and the Federal Government; and
(e) Whether the cost represents a deviation from the recipient's or subrecipient's established written policies and procedures for incurring costs.
§ 200.405
Allocable costs.
(a) Allocable costs in general. A cost is allocable to a Federal award or other cost objective if the cost is assignable to that Federal award or other cost objective in accordance with the relative benefits received. This standard is met if the cost satisfies any of the following criteria:
(1) Is incurred specifically for the Federal award;
(2) Benefits both the Federal award and other work of the recipient or subrecipient and can be distributed in proportions that may be approximated using reasonable methods; or
(3) Is necessary to the overall operation of the recipient or subrecipient and is assignable in part to the Federal award in accordance with these cost principles.
(b) Allocation of indirect costs. All activities which benefit from the recipient's or subrecipient's indirect cost, including unallowable activities and donated services by the recipient or subrecipient or third parties, will receive an appropriate allocation of indirect costs.
(c) Limitation on charging certain allocable costs to other Federal awards. A cost allocable to a particular Federal award may not be charged to other Federal awards (for example, to overcome fund deficiencies or to avoid restrictions imposed by Federal statutes, regulations, or the terms and conditions of the Federal awards). However, this prohibition would not preclude the recipient or subrecipient from shifting costs that are allowable under two or more Federal awards in accordance with existing Federal statutes, regulations, or the terms and conditions of the Federal awards.
(d) Direct cost allocation principles. If a cost benefits two or more projects or activities in proportions that can be determined without undue effort or cost, the cost must be allocated to the projects based on the proportional benefit However, when those proportions cannot be determined because of the interrelationship of the work involved, then, notwithstanding paragraph (c), the costs may be allocated or transferred to benefitted projects on any reasonable documented basis. Where the purchase of equipment or other capital asset is specifically authorized under a Federal award, the costs are assignable to the Federal award regardless of the use that may be made of the equipment or other capital asset involved, when no longer needed for the purpose for which it was originally required. See also §§ 200.310 through 200.316 and 200.439.
(e) Costs of contracts subject to CAS. If a contract is subject to CAS, costs must be allocated to that contract according to the Cost Accounting Standards, which take precedence over the allocation provisions in this part.
§ 200.406
Applicable credits.
(a) Applicable credits refer to transactions that offset or reduce direct or indirect costs allocable to a Federal award. Examples of such transactions are purchase discounts, rebates or allowances, recoveries or indemnities on losses, insurance refunds or rebates, and adjustments of overpayments or erroneous charges. To the extent that such credits accruing to or received by the recipient or subrecipient relate to allowable costs, they must be credited to the Federal award either as a cost reduction or cash refund, as appropriate.
(b) In some instances, the amounts received from the Federal Government to finance activities or service operations of the recipient or subrecipient should be treated as applicable credits. Specifically, the concept of netting such credit items (including any amounts used to meet cost sharing requirements) must be recognized in determining the rates or amounts to be charged to the Federal award. See §§ 200.436 and 200.468 for potential application areas.
§ 200.407
Prior written approval (prior approval).
The reasonableness and allocability of certain costs under Federal awards may be difficult to determine. To avoid subsequent disallowance or dispute based on unreasonableness or nonallocability, the recipient may seek the prior written approval of the Federal agency (or, for indirect costs, the cognizant agency for indirect costs) before incurring the cost. The absence of prior written approval on any element of cost will not, in itself, affect the reasonableness or allocability of that cost unless prior approval is specifically required for allowability as described under certain circumstances in the following sections:
(a) Section 200.306 Cost sharing;
(b) Section 200.307 Program income;
(c) Section 200.308 Revision of budget and program plans;
(d) Section 200.333 Fixed amount subawards;
(e) Section 200.430 Compensation—personal services, paragraph (h);
(f) Section 200.431 Compensation—fringe benefits;
(g) Section 200.439 Equipment and other capital expenditures;
(h) Section 200.440 Exchange rates;
(i) Section 200.441 Fines, penalties, damages and other settlements;
(j) Section 200.442 Fund raising and investment management costs;
(k) Section 200.445 Goods or services for personal use;
(l) Section 200.447 Insurance and indemnification;
(m) Section 200.455 Organization costs;
(n) Section 200.458 Pre-award costs;
(o) Section 200.462 Rearrangement and reconversion costs;
(p) Section 200.475 Travel costs.
§ 200.408
Limitation on allowance of costs.
Statutory requirements may limit the allowability of costs. Any costs that exceed the maximum amount allowed by statute may not be charged to the Federal award. Only the amount allowable by statute may be charged to the Federal award.
§ 200.409
Special considerations.
Other sections in this part describe special considerations and requirements applicable to states, local governments, Indian Tribes, and IHEs. In addition, certain provisions among the items of cost in this subpart are only applicable to certain types of recipients and subrecipients, as specified in the following sections:
(a) Direct and Indirect Costs (§§ 200.412-200.415);
(b) Special Considerations for States, Local Governments and Indian Tribes (§§ 200.416 and 200.417); and
(c) Special Considerations for Institutions of Higher Education (§§ 200.418 and 200.419).
§ 200.410
Collection of unallowable costs.
Payments made for costs determined to be unallowable by either the awarding Federal agency, cognizant agency for indirect costs, or pass-through entity must be refunded with interest to the Federal Government. Unless directed by Federal statute or regulation, repayments must be made in accordance with the instructions provided by the Federal agency or pass-through entity that made the allowability determination. See §§ 200.300 through 200.309, and § 200.346.
§ 200.411
Adjustment of previously negotiated indirect cost rates containing unallowable costs.
(a) Negotiated indirect cost rates based on a proposal later found to have included costs that:
(1) Are unallowable as specified by Federal statutes, regulations or the terms and conditions of a Federal award; or
(2) Are unallowable because they are not allocable to the Federal award(s), must be adjusted, or a refund must be made in accordance with the requirements of this section. These adjustments or refunds are intended to correct the proposals used to establish the rates and do not constitute a reopening of the rate negotiation. The adjustments or refunds must be made regardless of the type of rate negotiated (predetermined, final, fixed, or provisional).
(b) For rates covering a future fiscal year of the recipient or subrecipient, the unallowable costs must be removed from the indirect cost pools and the rates must be adjusted.
(c) For rates covering a past period, the Federal share of the unallowable costs must be computed for each year involved, and a cash refund (including interest) must be made to the Federal Government in accordance with the directions provided by the cognizant agency for indirect costs. When cash refunds are made for past periods covered by provisional or fixed rates, appropriate adjustments must be made when the rates are finalized to avoid duplicate recovery of the unallowable costs.
(d) For rates covering the current period, either a rate adjustment or a refund, as described in paragraphs (b) and (c) of this section, must be required by the cognizant agency for indirect costs. The choice of method must be at the discretion of the cognizant agency for indirect costs, based on its judgment as to which method would be most practical.
(e) The amount or proportion of unallowable costs included in each year's rate will be assumed to be the same as the amount or proportion of unallowable costs included in the base year proposal used to establish the rate.

Direct and Indirect Costs
§ 200.412
Classification of costs.
There is no universal rule for classifying certain costs as direct or indirect costs. A cost may be direct for some specific service or function but indirect for the Federal award or other final cost objective. Therefore, each cost incurred for the same purpose in like circumstances must be treated consistently either as a direct or an indirect cost to avoid possible double-charging of Federal awards. Guidelines for determining direct and indirect costs charged to Federal awards are provided in this subpart.
§ 200.413
Direct costs.
(a) General. Direct costs are those costs that can be identified specifically with a particular final cost objective, such as a Federal award, or other internally or externally funded activity, or that can be directly assigned to such activities relatively easily with a high degree of accuracy. Costs incurred for the same purpose in like circumstances must be treated consistently as direct or indirect costs. See § 200.405.
(b) Application to Federal awards. The association of costs with a Federal award determines whether costs are direct or indirect. Costs charged directly to a Federal award are typically incurred specifically for that Federal award (including, for example, supplies needed to achieve the award's objectives and the proportion of employee compensation and fringe benefits expended in relation to that specific award). Costs that otherwise would be treated as indirect costs may also be considered direct costs if they are directly related to a specific award (including, for example, extraordinary utility consumption, the cost of materials supplied from stock or services rendered by specialized facilities, cybersecurity, integrated data systems, asset management systems, performance management costs, program evaluation costs, or other institutional service operations).
(c) Administrative and clerical staff salaries. Administrative and clerical staff salaries should normally be treated as indirect costs. Direct charging of these costs may be appropriate only if they meet all of the following conditions:
(1) The administrative or clerical services are integral to a Federal award;
(2) Individuals involved can be specifically identified with a Federal award; and
(3) The costs are not also recovered as indirect costs.
(d) Minor items. A direct cost of a minor amount may be treated as an indirect cost, for reasons of practicality, provided that it is treated consistently for all Federal and non-Federal purposes.
(e) Treatment of unallowable costs in determining indirect cost rates. The costs of certain activities are not allowable as charges to Federal awards. Even though these costs are unallowable, they must be treated as direct costs for purposes of determining indirect cost rates and be allocated their equitable share of the recipient's or subrecipient's indirect costs if they represent activities which:
(1) Include the salaries of personnel;
(2) Occupy space; and
(3) Benefit from the recipient's or subrecipient's indirect costs.
(f) Treatment of certain costs for nonprofit organizations. For nonprofit organizations, the costs of activities performed by the nonprofit organization primarily as a service to members, clients, or the general public when significant and necessary to the organization's mission must be treated as direct costs whether or not allowable, and be allocated an equitable share of indirect costs. Some examples of these types of activities include:
(1) Maintenance of membership rolls, subscriptions, publications, and related functions. See § 200.454.
(2) Providing services and information to members, the government, or the public. See §§ 200.454 and 200.450.
(3) Promotion, lobbying, and other forms of public relations. See §§ 200.421 and 200.450.
(4) Conferences (except those held to conduct the general administration of the recipient or subrecipient). See also § 200.432.
(5) Maintenance, protection, and investment of special funds not used in the recipient's or subrecipient's operation. See also § 200.442.
(6) Administration of group benefits on behalf of members or clients, including life and hospital insurance, annuity or retirement plans, and financial aid. See also § 200.431.
§ 200.414
Indirect costs.
(a) Facilities and administration classification. For major Institutions of Higher Education (IHE) and major nonprofit organizations, indirect costs must be classified within two broad categories: “Facilities” and “Administration.” “Facilities” is defined as depreciation on buildings, equipment and capital improvements, interest on debt associated with certain buildings, equipment and capital improvements, and operations and maintenance expenses. “Administration” is defined as general administration and general expenses such as the director's office, accounting, personnel, and all other types of expenditures not listed specifically under one of the subcategories of “Facilities” (including cross allocations from other pools, where applicable). For nonprofit organizations, library expenses are included in the “Administration” category; for IHEs, they are included in the “Facilities” category. Major IHEs are defined as those required to use the Standard Format for Submission as noted in Appendix III. Major nonprofit organizations are those which receive more than $10 million in direct Federal funding.
(b) Diversity of nonprofit organizations. It is not always possible to specify the types of costs that may be classified as indirect costs for nonprofit organizations due to the diversity of their accounting practices. The association of a cost with a Federal award is the determining factor in distinguishing direct from indirect costs. However, typical examples of indirect cost for many nonprofit organizations may include depreciation on buildings and equipment, the costs of operating and maintaining facilities, and general administration and general expenses, such as the salaries and expenses of executive officers, personnel administration, and accounting.
(c) Federal Agency Acceptance of Negotiated Indirect Cost Rates. (See § 200.306.)
(1) Negotiated indirect cost rates must be accepted by all Federal agencies. A Federal agency may use a rate different from the negotiated rate for either a class of Federal awards or a single Federal award only when required by Federal statute or regulation, or when approved by the awarding Federal agency in accordance with paragraph (c)(3) of this section.
(2) The Federal agency must notify OMB of any approved deviations. The recipient or subrecipient may notify OMB of any disputes with Federal agencies regarding the application of a federally negotiated indirect cost rate.
(3) The Federal agency must implement, and make publicly available, the policies, procedures and general decision-making criteria that their programs will follow to seek and justify deviations from negotiated rates.
(4) The Federal agency must include, in the notice of funding opportunity, the policies relating to indirect cost rate reimbursement or cost share as approved under paragraph (e). As appropriate, the Federal agency should incorporate discussion of these policies into its outreach activities with applicants before posting a notice of funding opportunity. See § 200.204.
(d) Pass-through entities. Pass-through entities are subject to the requirements in § 200.332(b)(4) and must accept all federally negotiated indirect costs rates for subrecipients.
(e) Appendices. Requirements for development and submission of indirect cost rate proposals and cost allocation plans are contained in the following Appendices:
(1) Appendix III to Part 200—Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Institutions of Higher Education (IHEs);
(2) Appendix IV to Part 200—Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Nonprofit Organizations;
(3) Appendix V to Part 200—State/Local Government-wide Central Service Cost Allocation Plans;
(4) Appendix VI to Part 200—Public Assistance Cost Allocation Plans;
(5) Appendix VII to Part 200—States and Local Government and Indian Tribe Indirect Cost Proposals; and
(6) Appendix IX to Part 200—Hospital Cost Principles.
(f) De minimis rate. Recipients and subrecipients that do not have a current Federal negotiated indirect cost rate (including provisional rate) may elect to charge a de minimis rate of up to 15 percent of modified total direct costs (MTDC). The recipient or subrecipient is authorized to determine the appropriate rate up to this limit. Federal agencies and pass-through entities may not require recipients and subrecipients to use a de minimis rate lower than the negotiated indirect cost rate or the rate elected pursuant to this subsection unless required by Federal statute or regulation. The de minimis rate must not be applied to cost reimbursement contracts issued directly by the Federal Government in accordance with the FAR. Recipients and subrecipients are not required to use the de minimis rate. When applying the de minimis rate, costs must be consistently charged as either direct or indirect costs and may not be double charged or inconsistently charged as both. The de minimis rate does not require documentation to justify its use and may be used indefinitely. Once elected, the recipient or subrecipient must use the de minimis rate for all Federal awards until the recipient or subrecipient chooses to receive a negotiated rate.
(g) One-time extension of indirect rates. A recipient or subrecipient with a current Federal negotiated indirect cost rate may apply for a one-time extension of that agreement for up to four years. This extension will be subject to review and approval by the cognizant agency for indirect costs. If this extension is granted, the recipient or subrecipient may not request a rate review until the extension period ends. The recipient or subrecipient must re-apply to negotiate a new rate when the extension ends. After a new rate has been negotiated, the recipient or subrecipient may again apply for a one-time extension of the new rate in accordance with this paragraph.
§ 200.415
Required certifications.
(a) Financial reports must include a certification, signed by an official who is authorized to legally bind the recipient, which reads as follows: “By signing this report, I certify to the best of my knowledge and belief that the report is true, complete, and accurate, and the expenditures, disbursements and cash receipts are for the purposes and objectives set forth in the terms and conditions of the Federal award. I am aware that any false, fictitious, or fraudulent information, or the omission of any material fact, may subject me to criminal, civil or administrative penalties for fraud, false statements, false claims or otherwise. (U.S. Code Title 18, Section 1001 and Title 31, Sections 3729-3730 and 3801-3812).”
(b) Subrecipients under the Federal award must certify to the pass-through entity whenever applying for funds, requesting payment, and submitting financial reports: “I certify to the best of my knowledge and belief that the information provided herein is true, complete, and accurate. I am aware that the provision of false, fictitious, or fraudulent information, or the omission of any material fact, may subject me to criminal, civil, or administrative consequences including, but not limited to violations of U.S. Code Title 18, Sections 2, 1001, 1343 and Title 31, Sections 3729-3730 and 3801-3812.” Each such certification must be maintained pursuant to the requirements of § 200.334. This paragraph applies to all tiers of subrecipients.
(c) Certification of cost allocation plan or indirect cost rate proposal. Each cost allocation plan or indirect cost rate proposal must comply with the following:
(1) A proposal to establish a cost allocation plan or an indirect cost rate, whether submitted to a Federal cognizant agency for indirect costs or maintained on file by the recipient, must be certified by the recipient using the Certificate of Cost Allocation Plan or Certificate of Indirect Costs as set forth in appendices III through VII, and IX of this part. The certificate must be signed on behalf of the recipient by an individual at a level no lower than the vice president or chief financial officer of the recipient that submits the proposal.
(2) The Federal Government may either disallow all indirect costs or unilaterally establish an indirect cost rate when the recipient fails to submit a certified proposal for establishing a rate. This rate should be based upon audited historical data or other data furnished to the cognizant agency for indirect costs and for which it can be demonstrated that all unallowable costs have been excluded. The rate established must ensure that potentially unallowable costs are not reimbursed. Alternatively, the recipient may use the de minimis indirect cost rate. See § 200.414(f).
(d) Nonprofit organizations must certify that they did not meet the definition of a major nonprofit organization as defined in § 200.414(a), if applicable.
(e) The recipient must certify that the requirements and standards for lobbying (see § 200.450) have been met when submitting its indirect cost rate proposal.

Special Considerations for States, Local Governments and Indian Tribes
§ 200.416
Cost allocation plans and indirect cost proposals.
(a) Awards to states, local governments, and Indian Tribes are often implemented at the level of department within the State, local government, or Indian Tribe. A central service cost allocation plan is established to allow such department to claim a portion of centralized service costs that are incurred in proportion to the award's activities. Examples of centralized service costs may include motor pools, computer centers, purchasing, and accounting. Since Federal awards are performed within the individual operating agencies, there needs to be a process whereby these central service costs can be identified and assigned to benefitted activities on a reasonable and consistent basis. The central service cost allocation plan establishes this process.
(b) Individual departments typically charge Federal awards for indirect costs through an indirect cost rate. A separate indirect cost rate proposal for each operating department is usually necessary to claim indirect costs under Federal awards. Indirect costs include:
(1) The indirect costs originating in each operating department of the State, local government, or Indian Tribe carrying out Federal awards; and
(2) The costs of central governmental services distributed through the central service cost allocation plan and not otherwise treated as direct costs.
(c) The requirements for developing and submitting cost allocation plans (for central service costs and public assistance programs) and indirect cost rate proposals are contained in appendices V, VI, and VII of this part.
§ 200.417
Interagency service.
An operating department may provide services to another operating department of the same State, local government, or Indian Tribe. In these instances, the cost of services provided may include allowable direct costs of the service plus a pro-rated share of indirect costs. A standard indirect cost rate equal to 15 percent of the direct salaries and wages for providing the service (excluding overtime, shift premiums, and fringe benefits) may be used instead of determining the actual indirect costs of the service. These services do not include centralized services that are included in central service cost allocation plans described in Appendix V of this part.

Special Considerations for Institutions of Higher Education
§ 200.418
Costs incurred by states and local governments.
Costs incurred or paid by a State or local government on behalf of and in direct benefit to its IHEs are allowable. These costs include but are not limited to fringe benefit programs such as pension costs and Federal Insurance Contributions Act (FICA) costs. These costs are allowable regardless of whether they are recorded in the accounting records of the institutions, subject to the following conditions:
(a) The costs meet the requirements of § 200.402-200.411;
(b) The costs are properly supported by approved cost allocation plans in accordance with the applicable cost accounting principles of this part; and
(c) The costs are not otherwise borne directly or indirectly by the Federal Government.
§ 200.419
Cost accounting standards.
An IHE that receive an aggregate total $50 million or more in Federal awards and instruments subject to this subpart (as specified in § 200.101) in its most recently completed fiscal year must comply with the Cost Accounting Standards Board's cost accounting standards located at 48 CFR 9905.501, 9905.502, 9905.505, and 9905.506. CAS-covered contracts and subcontracts awarded to the IHEs are subject to the broader range of CAS requirements at 48 CFR 9900 through 9999 and 48 CFR part 30 (FAR Part 30).

General Provisions for Selected Items of Cost
§ 200.420
Considerations for selected items of cost.
(a) This section provides principles to be applied in establishing the allowability of certain items involved in determining cost, in addition to other requirements of this subpart. These principles apply whether or not a particular cost item is properly treated as a direct or indirect cost.
(b) The following sections are not intended to be a comprehensive list of potential items of cost encountered under Federal awards. Failure to mention a particular item of cost, including as an example in certain sections, is not intended to imply that it is either allowable or unallowable. When determining the allowability for an item of cost, each case should be based on the treatment provided for similar or related items of cost and based on the principles described in §§ 200.402 through 200.411. In case of a discrepancy between the provisions of a specific Federal award and the provisions below, the Federal award governs. Criteria outlined in § 200.403 must be applied in determining allowability.
§ 200.421
Advertising and public relations.
(a) The term advertising costs means the costs of advertising media and corollary administrative costs. Advertising media includes, but is not limited to, magazines, newspapers, radio and television, direct mail, exhibits, and electronic or computer transmittals.
(b) The only allowable advertising costs are those which are solely for:
(1) The recruitment of personnel required by the recipient or subrecipient for the performance of a Federal award (See also § 200.463);
(2) The procurement of goods and services for the performance of a Federal award;
(3) The disposal of scrap or surplus materials acquired in the performance of a Federal award except when the recipient or subrecipient is reimbursed for disposal costs at a predetermined amount; or
(4) Program outreach (for example, recruiting project participants) and other specific purposes necessary to meet the Federal award requirements.
(c) The term “public relations” includes community relations and means those activities dedicated to maintaining the recipient's or subrecipient's image or maintaining or promoting understanding and favorable relations with the community or public at large or any segment of the public.
(d) The only allowable public relations costs are:
(1) Costs specifically required by the Federal award;
(2) Costs of communicating with the public and press about specific activities or accomplishments which result from the performance of the Federal award (these costs are considered necessary as part of the outreach effort for the Federal award); or
(3) Costs of conducting general liaison with news media and government public relations officers, to the extent that such activities are limited to communication and liaison necessary to keep the public informed on matters of public concern, such as notices of funding opportunities or financial matters.
(e) Unallowable advertising and public relations costs include the following:
(1) All advertising and public relations costs other than as specified in paragraphs (b) and (d) of this section;
(2) Costs of meetings, conventions, conferences, or other events related to other activities of the entity (see also § 200.432), including:
(i) Costs of displays, demonstrations, and exhibits;
(ii) Costs of meeting rooms, hospitality suites, and other special facilities used in conjunction with shows and other special events; and
(iii) Salaries and wages of employees engaged in setting up and displaying exhibits, making demonstrations, and providing briefings;
(3) Costs of promotional items and memorabilia;
(4) Costs of advertising and public relations designed solely to promote the recipient or subrecipient.
§ 200.422
Advisory councils.
An advisory council or committee is a body that provides advice to the management of such entities as corporations, organizations, or foundations. Costs incurred by both internal and external advisory councils or committees are allowable if authorized by statute, the Federal agency, or as an indirect cost where allocable to Federal awards. See § 200.444, which applies to States, local governments, and Indian Tribes.
§ 200.423
Alcoholic beverages.
The cost of alcoholic beverages is unallowable.
§ 200.424
Alumni activities.
Costs incurred by IHEs for, or in support of, alumni activities are unallowable.
§ 200.425
Audit services.
(a) A reasonably proportionate share of the costs of audits required by and performed in accordance with the Single Audit Act Amendments of 1996 (31 U.S.C. 7501-7507), and the requirements of this part are allowable. However, the following audit costs are unallowable:
(1) Any costs when audits required by the Single Audit Act and subpart F of this part have not been conducted, or have been conducted but not in accordance with the requirements; and
(2) Except as provided for in paragraph (c) of this section, any costs of auditing a non-Federal entity that is exempted from having an audit conducted under the Single Audit Act and subpart F of this part because its expenditures under Federal awards are less than $1,000,000 during its fiscal year.”
(b) The costs of a financial statement audit of a recipient or subrecipient that does not currently have a Federal award may be included in the indirect cost pool for a cost allocation plan or indirect cost proposal.
(c) Pass-through entities may charge Federal awards for the cost of agreed-upon procedures engagements to monitor subrecipients (in accordance with §§ 200.331-333) exempt from having an audit conducted under the Single Audit Act and the requirements of this part. This cost is allowable only if the agreed-upon procedures engagements are:
(1) Conducted in accordance with GAGAS or applicable international attestation standards, as appropriate;
(2) Paid for and arranged by the pass-through entity; and
(3) Limited in scope to one or more of the following types of compliance requirements: activities allowed or unallowed; allowable costs/cost principles; eligibility; and reporting.
§ 200.426
Bad debts.
Bad debts (debts determined to be uncollectable), including losses (whether actual or estimated) arising from uncollectable accounts and other claims, are unallowable. Related collection costs, and related legal costs, arising from such debts are also unallowable. See § 200.428.
§ 200.427
Bonding costs.
(a) Bonding costs arise when the Federal agency requires assurance against financial loss to itself or others because of an act or default of the recipient or subrecipient. They also arise when the recipient or subrecipient requires similar assurance, including bonds as bid, performance, payment, advance payment, infringement, and fidelity bonds for employees and officials.
(b) Costs of bonding required under the Federal award's terms and conditions are allowable.
(c) Costs of bonding required by the recipient or subrecipient in the general conduct of its operations are allowable as an indirect cost to the extent that such bonding is in accordance with sound business practice and the rates and premiums are reasonable under the circumstances.
§ 200.428
Collections of improper payments.
The costs incurred by a recipient or subrecipient to recover improper payments, including improper overpayments, are allowable as either direct or indirect costs, as appropriate. The recipient or subrecipient may use the amounts collected in accordance with cash management standards described in § 200.305.
§ 200.429
Commencement and convocation costs.
For IHEs, costs incurred for commencements and convocations are unallowable, except as activity costs provided for in Appendix III, (B)(9) Student Administration and Services.
§ 200.430
Compensation—personal services.
(a) General. Compensation for personal services includes all remuneration, paid currently or accrued, for services of employees rendered during the period of performance under the Federal award, including but not necessarily limited to wages and salaries. Compensation for personal services may also include fringe benefits addressed in § 200.431. Costs of compensation are allowable to the extent that they satisfy the specific requirements of this part and that the total compensation for individual employees:
(1) Is reasonable for the services rendered and conforms to the established written policy of the recipient or subrecipient consistently applied to both Federal and non-Federal activities;
(2) Follows an appointment made in accordance with the recipient's or subrecipient's laws, rules, or written policies and meets the requirements of Federal statute, where applicable; and
(3) Is determined and supported as provided in paragraph (g) of this section, when applicable.
(b) Reasonableness. Compensation for employees engaged in work on Federal awards will be reasonable to the extent that it is consistent with that paid for similar work in other activities of the recipient or subrecipient. In cases where the kinds of employees required for Federal awards are not found in the other activities of the recipient or subrecipient, compensation will be considered reasonable to the extent that it is comparable to that paid for similar work in the labor market in which the recipient or subrecipient competes for the kind of employees involved.
(c) Professional activities outside the recipient or subrecipient. Unless the Federal agency expressly authorizes an arrangement, a recipient or subrecipient must follow its written policies and procedures concerning the permissible extent of professional services that can be provided outside the recipient or subrecipient for non-organizational compensation. Where the recipient or subrecipient does not have written policies or procedures, or they do not adequately define the permissible extent of consulting or other non-organizational activities undertaken for extra outside pay, the Federal Government may require the recipient or subrecipient to allocate the effort of professional staff working on Federal awards between:
(1) Recipient or subrecipient activities, and
(2) Non-organizational professional activities. Appropriate arrangements governing compensation must be negotiated on a case-by-case basis if the Federal agency considers the extent of non-organizational professional effort excessive or inconsistent with the conflicts-of-interest terms and conditions of the Federal award.
(d) Unallowable costs. (1) Costs unallowable under other sections of these principles must not be allowable under this section solely because they constitute personnel compensation.
(2) The allowable compensation for certain employees is subject to a ceiling in accordance with Federal statute. See 10 U.S.C. 3744(a)(16), 41 U.S.C. 1127, and 41 U.S.C. 4304(a)(16) for the ceiling amount, covered compensation subject to the ceiling, covered employees, and other relevant provisions for cost-reimbursement contracts. For other types of Federal awards, other statutory ceilings may apply.
(e) Special considerations. Special considerations in determining the allowability of compensation will be given to any change in a recipient's or subrecipient's compensation policy resulting in a substantial increase in its employees' level of compensation (particularly when the change was concurrent with an increase in the ratio of Federal awards to other activities) or any change in the treatment of allowability of specific types of compensation due to changes in Federal policy.
(f) Incentive compensation. Incentive compensation to employees based on cost reduction, efficient performance, suggestion awards, or safety awards is allowable to the extent that the overall compensation is determined to be reasonable and such costs are paid or accrued according to an agreement entered into in good faith between the recipient or subrecipient and the employees before the services were rendered, or according to an established plan followed by the recipient or subrecipient so consistently as to imply, in effect, an agreement to make such payment.
(g) Standards for Documentation of Personnel Expenses. (1) Charges to Federal awards for salaries and wages must be based on records that accurately reflect the work performed. These records must:
(i) Be supported by a system of internal control that provides reasonable assurance that the charges are accurate, allowable, and properly allocated;
(ii) Be incorporated into the official records of the recipient or subrecipient;
(iii) Reasonably reflect the total activity for which the employee is compensated by the recipient or subrecipient, not exceeding 100 percent of compensated activities (for IHEs, this is the IBS);
(iv) Encompass federally-assisted and all other activities compensated by the recipient or subrecipient on an integrated basis but may include the use of subsidiary records as defined in the recipient's or subrecipient's written policy;
(v) Comply with the established accounting policies and procedures of the recipient or subrecipient (See paragraph (i)(1)(ii) of this section for treatment of incidental work for IHEs.); and
(vi) Support the distribution of the employee's salary or wages among specific activities or cost objectives if the employee works on more than one Federal award; a Federal award and non-Federal award; an indirect cost activity and a direct cost activity; two or more indirect activities allocated using different allocation bases; or an unallowable activity and a direct or indirect cost activity.
(vii) Budget estimates (meaning, estimates determined before the services are performed) alone do not qualify as support for charges to Federal awards, but may be used for interim accounting purposes, provided that:
(A) The system for establishing the estimates produces reasonable approximations of the activity performed;
(B) Significant changes in the related work activity (as defined by the recipient's or subrecipient's written policies) are promptly identified and entered into the records. Short-term (such as one or two months) fluctuations between workload categories do not need to be considered as long as the distribution of salaries and wages is reasonable over the longer term; and
(C) The recipient's or subrecipient's system of internal controls includes processes to perform periodic after-the-fact reviews of interim charges made to a Federal award based on budget estimates. All necessary adjustments must be made so that the final amount charged to the Federal award is accurate, allowable, and properly allocated.
(viii) Because practices vary as to the activity constituting a full workload (for example, the Institutional Base Salary (IBS) for IHEs), records may reflect categories of activities expressed as a percentage distribution of total activities.
(ix) It is recognized that teaching, research, service, and administration are often inextricably intermingled in an academic setting. Therefore, a precise assessment of factors contributing to costs is not required when IHEs record salaries and wages charged to Federal awards.
(2) For records that meet the standards required in paragraph (g)(1) of this section, the recipient or subrecipient is not required to provide additional support or documentation for the work performed other than that referenced in paragraph (g)(3) of this section.
(3) In accordance with Department of Labor regulations implementing the Fair Labor Standards Act (FLSA) (29 CFR part 516), charges for the salaries and wages of nonexempt employees, in addition to the supporting documentation described in this section, must also be supported by records indicating the total number of hours worked each day.
(4) Salaries and wages of employees used in meeting cost sharing requirements on Federal awards must be supported in the same manner as salaries and wages claimed for reimbursement from Federal awards.
(5) States, local governments, and Indian Tribes may use substitute processes or systems for allocating salaries and wages to Federal awards either in place of or in addition to the records described in paragraph (g)(1) of this section if approved by the cognizant agency for indirect cost. Such systems may include, but are not limited to, random moment sampling, “rolling” time studies, case counts, or other quantifiable measures of work performed.
(i) Substitute systems that use sampling methods (primarily for Temporary Assistance for Needy Families (TANF), the Supplemental Nutrition Assistance Program (SNAP), Medicaid, and other public assistance programs) must meet acceptable statistical sampling standards, including:
(A) The sampling universe must include all of the employees whose salaries and wages are to be allocated based on sample results except as provided in paragraph (g)(5)(iii);
(B) The sample must cover the entire period involved; and
(C) The results must be statistically valid and applied to the period being sampled.
(ii) Allocating charges for the sampled employees' supervisors and clerical and support staff, based on the results of the sampled employees, will be acceptable.
(iii) Less than full compliance with the statistical sampling standards noted in paragraph (5)(i) may be accepted by the cognizant agency for indirect costs if it concludes that the amounts allocated to Federal awards will be minimal or if it concludes that the system proposed by the recipient or subrecipient will result in lower costs to Federal awards than a system which complies with the standards.
(6) Cognizant agencies for indirect costs are encouraged to approve alternative proposals based on outcomes and milestones for program performance when these are clearly documented. These plans are acceptable as an alternative to requirements in paragraph (g)(1) of this section when approved by the cognizant agency for indirect costs.
(7) For Federal awards of similar purpose activity or instances of approved blended funding, a recipient or subrecipient may submit performance plans that incorporate funds from multiple Federal awards and account for their combined use based on performance-oriented metrics, provided the plans are approved in advance by all involved Federal agencies. In these instances, the recipient or subrecipient must submit a request for waiver of the requirements based on documentation that describes the method of charging costs, relates the charging of costs to the specific activity that is applicable to all fund sources, and is based on quantifiable measures of the activity in relation to time charged.
(8) For a recipient or subrecipient whose records do not meet the standards described in this section, the Federal Government may require personnel activity reports, including prescribed certifications, or equivalent documentation supporting the records as required in this section.
(h) Nonprofit organizations. This paragraph (h) provides guidance specific to only nonprofit organizations. For compensation to members of nonprofit organizations, trustees, directors, associates, officers, or the immediate families thereof, a determination must be made that the compensation is reasonable for the actual personal services rendered rather than a distribution of earnings above actual costs. Compensation may include director's and executive committee member's fees, incentive awards, off-site or incentive pay, location allowances, hardship pay, and cost-of-living differentials.
(i) Institutions of Higher Education (IHEs). This paragraph provides guidance specific to only IHEs.
(1) Determining allowable personnel costs. Certain conditions require special consideration and possible limitations in determining allowable personnel compensation costs under Federal awards. Among such conditions are the following:
(i) Allowable activities. Charges to Federal awards may include reasonable amounts for activities contributing and directly related to work under an agreement, such as delivering special lectures about specific aspects of the ongoing activity, writing reports and articles, developing and maintaining protocols (human, animals, etcetera), managing substances/chemicals, managing and securing project-specific data, coordinating research subjects, participating in appropriate seminars, consulting with colleagues and graduate students, and attending meetings and conferences.
(ii) Incidental activities. Incidental activities for which supplemental compensation is allowable under the written institutional policy (at a rate not to exceed institutional base salary) do not need to be included in the records described in paragraph (g). To charge payments of incidental activities directly, such activities must either be expressly authorized in the Federal award budget or receive prior written approval by the Federal agency.
(2) Salary basis. Charges for work performed on Federal awards by faculty members during the academic year are allowable at the institutional base salary (IBS) rate. Except as noted in paragraph (i)(1)(ii), in no event will charges to Federal awards, irrespective of the basis of computation, exceed the proportionate share of the IBS for that period. This principle applies to all members of the faculty at an institution. IBS is the annual compensation paid by an IHE for an individual's appointment, whether that individual's time is spent on research, instruction, administration, or other activities. IBS excludes any income an individual earns outside of duties performed for the IHE. Unless there is prior approval by the Federal agency, charges of a faculty member's salary to a Federal award may not exceed the proportionate share of the IBS for the period during which the faculty member worked on the Federal award.
(3) Intra-Institution of Higher Education (IHE) consulting. Intra-IHE consulting by faculty should be undertaken as an IHE responsibility requiring no compensation in addition to IBS. However, in unusual cases where consultation is across departmental lines or involves a separate or remote operation, and the work performed by the faculty members is in addition to their regular responsibilities, any charges for such work representing additional compensation above IBS are allowable provided that such consulting arrangements are expressly authorized in the Federal award or approved in writing by the Federal agency.
(4) Extra service pay. Extra service pay typically represents overload compensation, subject to institutional compensation policies for services above and beyond IBS. Where extra service pay results from Intra-IHE consulting, it is subject to the same requirements of paragraph (b) of this section. It is allowable if all of the following conditions are met:
(i) The IHE establishes consistent written policies which apply uniformly to all faculty members, not just those working on Federal awards.
(ii) The IHE establishes a consistent written definition of work covered by IBS, which is specific enough to determine conclusively when work beyond that level has occurred. This definition may be described in appointment letters or other documentation.
(iii) The supplementation amount paid is commensurate with the IBS pay rate and additional work performed. See paragraph (i)(2) of this section.
(iv) The salaries, as supplemented, fall within the salary structure and pay ranges established by and documented in writing or otherwise applicable to the IHE.
(v) The total salaries charged to Federal awards, including extra service payments, are subject to the standards of documentation as described in paragraph (g).
(5) Periods outside the academic year. (i) Except as specified for teaching activity in paragraph (i)(5)(ii) of this section, charges for work performed by faculty members on Federal awards during periods not included in the base salary period must be at a rate not more than the IBS.
(ii) Charges for teaching activities performed by faculty members on Federal awards during periods not included in IBS period must be based on the written policy of the IHE governing compensation to faculty members for teaching assignments during such periods.
(6) Part-time faculty. Charges for work performed on Federal awards by faculty members having only part-time appointments must be determined at a rate not more than that regularly paid for part-time assignments.
(7) Sabbatical leave costs. Rules for sabbatical leave are as follows:
(i) Costs of leaves of absence by employees for performance of graduate work or sabbatical study, travel, or research are allowable, provided the IHE has a uniform written policy on sabbatical leave for persons engaged in instruction and persons engaged in research. These costs must be allocated equitably among all related activities of the IHE.
(ii) Where sabbatical leave is included in fringe benefits for which a cost is determined for assessment as a direct charge, the aggregate amount of such assessments applicable to all work of the institution during the base period must be reasonable in relation to the IHE's actual experience under its sabbatical leave policy.
(8) Salary rates for non-faculty members. Non-faculty full-time professional personnel may also earn “extra service pay” in accordance with the IHE's written policy and paragraph (i)(1)(i).
§ 200.431
Compensation—fringe benefits.
(a) General. Fringe benefits are allowances and services employers provide to their employees as compensation in addition to regular salaries and wages. Fringe benefits include, but are not limited to, the costs of leave, employee insurance, pensions, and unemployment benefits. Except as provided elsewhere in these principles, the costs of fringe benefits are allowable provided that the benefits are reasonable and are required by law, an organization-employee agreement, or an established policy of the recipient or subrecipient.
(b) Leave. The cost of fringe benefits in the form of regular compensation paid to employees during periods of authorized absences from the job, such as for annual leave, family-related leave, sick leave, holidays, court leave, military leave, administrative leave, and other similar benefits, are allowable if all of the following criteria are met:
(1) They are provided under established written leave policies;
(2) The costs are equitably allocated to all related activities, including Federal awards; and,
(3) The accounting basis (cash or accrual) selected for costing each type of leave is consistently followed by the recipient or subrecipient or a specified grouping of employees.
(i) When a recipient or subrecipient uses the cash basis of accounting, the cost of leave is recognized in the period that the leave is taken and paid for. Payments for unused leave when an employee retires or terminates employment are allowable in the year of payment and must be allocated as a general administrative expense to all activities.
(ii) The accrual basis may be only used for those types of leave for which a liability as defined by GAAP exists when the leave is earned. When a recipient or subrecipient uses the accrual basis of accounting, allowable leave costs are the lesser of the amount accrued or funded.
(c) Fringe benefits. The cost of fringe benefits in the form of employer contributions or expenses for social security; employee life, health, unemployment, and worker's compensation insurance (except as indicated in § 200.447); pension plan costs; and other similar benefits are allowable, provided such benefits are permitted under established written policies. The recipient or subrecipient must allocate fringe benefits to Federal awards and all other activities in a manner consistent with the pattern of benefits attributable to the individuals or group(s) of employees whose salaries and wages are chargeable to such Federal awards and other activities, and charged as direct or indirect costs following the recipient's or subrecipient's accounting practices.
(d) Cost objectives. The recipient or subrecipient may assign fringe benefits to cost objectives by identifying specific benefits to specific individual employees or by allocating them based on entity-wide salaries and wages of the employees receiving the benefits. When the allocation method is used, separate allocations must be made to selective groupings of employees unless the recipient or subrecipient demonstrates that costs in relationship to salaries and wages do not differ significantly for different groups of employees.
(e) Insurance. See also § 200.447(d)(1) and (2).
(1) Provisions for a reserve under a self-insurance program for unemployment compensation or workers' compensation are allowable to the extent that the provisions represent reasonable estimates of the liabilities for such compensation and the types of coverage, the extent of coverage, and rates and premiums would have been allowable had insurance been purchased to cover the risks. However, provisions for self-insured liabilities which do not become payable for more than one year after the provision is made must not exceed the present value of the liability.
(2) Insurance costs on the lives of trustees, officers, or other employees holding positions of similar responsibility are allowable only to the extent that the insurance represents additional compensation. The cost of such insurance is unallowable when the recipient or subrecipient is named as beneficiary.
(3) Actual claims paid to or on behalf of employees or former employees for workers' compensation, unemployment compensation, severance pay, and similar employee benefits ( for example, post-retirement health benefits) are allowable in the year of payment provided that the recipient or subrecipient follows a consistent costing policy.
(f) Automobiles. That portion of automobile costs furnished by the recipient or subrecipient that relates to personal use by employees (including transportation to and from work) is unallowable as a fringe benefit or indirect costs regardless of whether the cost is reported as taxable income to the employees.
(g) Pension plan costs. Pension plan costs incurred in accordance with the established written policies of the recipient or subrecipient are allowable, provided that:
(1) Such policies meet the test of reasonableness.
(2) The methods of cost allocation are not discriminatory.
(3) The cost assigned to each fiscal year should be determined in accordance with GAAP, except for State and local governments.
(4) The costs assigned to a given fiscal year are funded for all plan participants within six months after the end of that year. However, increases to normal and past service pension costs caused by a delay in funding the actuarial liability beyond 30 calendar days after each quarter of the year to which such costs are assignable are unallowable. The recipient or subrecipient may follow the “Cost Accounting Standard for Composition and Measurement of Pension Costs” (48 CFR 9904.412).
(5) Premiums for pension plan termination insurance that are paid according to the Employee Retirement Income Security Act (ERISA) of 1974 (29 U.S.C. 1301-1461) are allowable. Late payment charges on such premiums are unallowable. Excise taxes on accumulated funding deficiencies and other penalties imposed under ERISA are unallowable.
(6) Pension plan costs may be computed using a pay-as-you-go method or an actuarial cost method recognized by GAAP and following the recipient's or subrecipient's established written policies.
(i) For pension plans financed on a pay-as-you-go method, allowable costs will be limited to those representing actual payments to retirees or their beneficiaries.
(ii) Pension costs calculated using an actuarial cost method recognized by GAAP are allowable for a given fiscal year if they are funded for that year within six months after the end of that year. Costs funded after six months (or a later period agreed to by the cognizant agency for indirect costs) are allowable in the year funded. The cognizant agency for indirect costs may agree to an extension if an appropriate adjustment is made to compensate for the timing of the charges to the Federal Government and related Federal reimbursement and the recipient's or subrecipient's contribution to the pension fund. Adjustments may be made by cash refund or other equitable procedures to compensate the Federal Government for the time value of Federal reimbursements in excess of contributions to the pension fund.
(iii) Amounts funded by the recipient or subrecipient in excess of the actuarially determined amount for a fiscal year may be used as the recipient's or subrecipient's contribution in future periods.
(iv) When a recipient or subrecipient establishes or converts to an acceptable actuarial cost method, as defined by GAAP, and funds pension costs in accordance with this method, the unfunded liability at the time of conversion is allowable if amortized over a period of years in accordance with GAAP.
(v) Payments for unfunded pension costs must be charged in accordance with the allocation principles of this subpart. Specifically, the recipient or subrecipient may not charge unfunded pension costs directly to a Federal award if those unfunded pension costs are not allocable to that award.
(vi) The recipient or subrecipient must provide the Federal Government an equitable share of any previously allowed pension costs (including subsequent earnings) that revert or inure to the recipient or subrecipient through a refund, withdrawal, or other credit.
(h) Post-retirement health. A post-retirement health plan (PRHP) refers to the costs of health insurance or health services not included in a pension plan covered by paragraph (g) for retirees and their spouses, dependents, and survivors. PRHP costs may be computed using a pay-as-you-go method or an actuarial cost method recognized by GAAP and following the recipient's or subrecipient's established written policies.
(1) For PRHP financed on a pay-as-you-go method, allowable costs will be limited to those representing actual payments to retirees or their beneficiaries.
(2) PRHP costs calculated using an actuarial cost method recognized by GAAP are allowable for a given fiscal year if they are funded for that year within six months after the end of that year. Costs funded after six months (or a later period agreed to by the cognizant agency for indirect costs) are allowable in the year funded. The cognizant agency for indirect costs may agree to an extension if an appropriate adjustment is made to compensate for the timing of the charges to the Federal Government and related Federal reimbursement and the recipient's or subrecipient's contributions to the PRHP fund. Adjustments may be made by cash refund, reduction in the current year's PRHP costs, or other equitable procedures to compensate the Federal Government for the time value of Federal reimbursements in excess of contributions to the PRHP fund.
(3) Amounts funded by the recipient or subrecipient in excess of the actuarially determined amount for a fiscal year may be used as the recipient's or subrecipient's contribution in future periods.
(4) If a recipient or subrecipient establishes or converts to an actuarial cost method and funds PRHP costs in accordance with this method, the initial unfunded liability attributable to prior years is allowable if amortized over a period of years in accordance with GAAP, or, if no such GAAP period exists, over a period negotiated with the cognizant agency for indirect costs.
(5) Payments for unfunded PRHP costs must be charged in accordance with the allocation principles of this subpart. Specifically, the recipient or subrecipient may not charge unfunded PRHP costs directly to a Federal award if those unfunded PRHP costs are not allocable to that award.
(6) To be allowable in the current year, the PRHP costs must be paid either to:
(i) An insurer or other benefit provider as current year costs or premiums; or
(ii) An insurer or trustee that will maintain a trust fund or reserve for the sole purpose of providing post-retirement benefits to retirees and other beneficiaries.
(7) The recipient or subrecipient must provide the Federal Government an equitable share of any previously allowed post-retirement benefit costs (including subsequent earnings) that revert or inure to the recipient or subrecipient through a refund, withdrawal, or other credit.
(i) Severance pay. (1) Severance pay, also commonly referred to as dismissal wages, is a payment in addition to regular salaries and wages, by recipients and subrecipients to workers whose employment is being terminated. Severance pay is allowable only to the extent that, in each case, it is required by:
(i) Law;
(ii) Employer-employee agreement;
(iii) Established policy that constitutes, in effect, an implied agreement on the recipient's or subrecipient's part; or
(iv) Circumstances of the particular employment.
(2) Costs of severance payments are divided into two categories as follows:
(i) Actual severance payments for normal turnover must be allocated to all activities; or, where the recipient or subrecipient provides for a reserve for normal severances, such method is acceptable if the charge to current operations is reasonable in light of payments made for normal severances over a representative past period, and if amounts charged are allocated to all activities of the recipient or subrecipient.
(ii) Measuring the costs of abnormal or mass severance pay by means of an accrual method will not achieve equity for both parties. Therefore, accruals are not allowable. However, the Federal Government recognizes its responsibility to contribute its fair share toward a specific payment. Prior approval by the Federal agency or cognizant agency for indirect cost, as appropriate, is required.
(3) Costs incurred in severance pay packages that are in excess of the standard severance pay provided by the recipient or subrecipient to an employee upon termination of employment and that are paid to the employee contingent upon a change in management control over, or ownership of, the recipient's or subrecipient's assets, are unallowable.
(4) Severance payments to foreign nationals employed by the recipient or subrecipient outside the United States, to the extent that the amount exceeds the customary or prevailing practices for the recipient or subrecipient in the United States, are unallowable unless they are required by applicable foreign law or necessary for the performance of Federal programs and approved by the Federal agency.
(5) Severance payments to foreign nationals employed by the recipient or subrecipient outside the United States due to the termination of the foreign national as a result of the closing of, or curtailment of activities by, the recipient or subrecipient in that country, are unallowable unless they are either:
(i) Required by applicable foreign law; or
(ii) Necessary for the performance of Federal programs and approved by the Federal agency.
(j) For IHEs only. (1) Fringe benefits in the form of undergraduate and graduate tuition or tuition remission for individual employees are allowable, provided such benefits are granted in accordance with established written policies of the IHE and are distributed to all IHE activities on an equitable basis. Tuition benefits for family members other than the employee are unallowable.
(2) Fringe benefits in the form of undergraduate and graduate tuition or tuition remission for individual employees not employed by the IHE are limited to the tax-free amount allowed by the Internal Revenue Code as amended (26 U.S.C. 127).
(3) IHEs may offer employees tuition waivers or reductions, provided that the benefit does not discriminate in favor of highly compensated employees. Employees can exercise these benefits at other institutions according to institutional policy. See § 200.466, for treatment of tuition remission provided to students.
(k) Fringe benefit programs and other benefit costs. (1) For IHEs whose costs are paid by a State or local government, fringe benefit programs (such as pension costs and FICA) and any other benefits costs incurred specifically on behalf of, and in direct benefit to, the IHE, are allowable, subject to the following:
(i) The costs meet the requirements of Basic Considerations in §§ 200.402 through 200.411;
(ii) The costs are properly supported by approved cost allocation plans in accordance with applicable Federal cost accounting principles; and
(iii) The costs are not otherwise borne directly or indirectly by the Federal Government.
(2) The allowability of these costs for the IHE does not depend on whether they are recorded in the accounting records of the IHE.
§ 200.432
Conferences.
A conference means an event whose primary purpose is to disseminate technical information beyond the recipient or subrecipient and is necessary and reasonable for successful performance under the Federal award. Allowable conference costs may include the rental of facilities, speakers' fees, attendance fees, costs of meals and refreshments, local transportation, and other items incidental to such conferences unless further restricted by the terms and conditions of the Federal award. The costs of identifying and providing locally available dependent-care resources for participants are allowable as needed. Conference hosts/sponsors must exercise discretion and judgment in ensuring that conference costs are appropriate, necessary, and managed to minimize costs to the Federal award. The Federal agency may authorize exceptions for programs including Indian Tribes, children, and the elderly. See also §§ 200.438, 200.456, and 200.475.
§ 200.433
Contingency provisions.
(a) Contingency provisions are part of a budget estimate of future costs (typically of large construction projects, IT systems, or other items approved by the Federal agency) which are associated with possible events or conditions arising from causes for which the precise outcome is indeterminable at the time of estimate and that are likely to result, in the aggregate, in additional costs for the approved activity or project. Contingency amounts for major project scope changes, unforeseen risks, or extraordinary events must not be included in the budget estimates for a Federal award.
(b) It is permissible for contingency amounts other than those excluded in paragraph (a) of this section to be explicitly included in budget estimates to the extent necessary to improve their precision. Contingency amounts must be estimated using broadly-accepted cost estimating methodologies, specified in the budget documentation of the Federal award, and accepted by the Federal agency. As such, contingency amounts are to be included in the Federal award. In order for actual costs incurred to be allowable, they must comply with the cost principles and other requirements of this part (see §§ 200.300 and 200.403), be necessary and reasonable for proper and efficient accomplishment of project or program objectives, and be verifiable from the recipient's or subrecipient's records.
(c) Payments to a recipient's or subrecipient's “contingency reserve” or any similar payment made for events the occurrence of which cannot be foretold with certainty as to the time or intensity, or with an assurance of their happening, are unallowable, except as noted in §§ 200.431 and 200.447.
§ 200.434
Contributions and donations.
(a) Costs of contributions and donations, including cash, property, and services, from the recipient or subrecipient to other entities are unallowable.
(b) The value of services and property donated (that is, in-kind donations) to the recipient or subrecipient may not be charged to the Federal award either as a direct or indirect cost. The value of donated services and property may be used to meet cost sharing requirements (see § 200.306). Depreciation on donated assets is permitted so long as the donated property is not counted towards meeting cost sharing requirements (see § 200.436).
(c) Services donated or volunteered to the recipient or subrecipient may be provided by professional and technical personnel, consultants, and other skilled and unskilled labor. The value of these services may not be charged to the Federal award as a direct or indirect cost. However, the value of donated services may be used to meet cost sharing requirements in accordance with the provisions of § 200.306.
(d) To the extent feasible, services donated to the recipient or subrecipient will be supported by the same methods used to support the allocability of regular personnel services.
(e) The following provisions apply to nonprofit organizations. The value of services donated to a nonprofit organization and used in the performance of a direct cost activity must be considered in the determination of the recipient's or subrecipient's indirect cost rate(s) and, accordingly, must be allocated a proportionate share of applicable indirect costs when the following circumstances exist:
(1) The aggregate value of the services is material;
(2) The services are supported by a significant amount of the indirect costs incurred by the recipient or subrecipient;
(i) In those instances where there is no basis for determining the fair market value of the services rendered, the recipient or subrecipient and the cognizant agency for indirect costs must negotiate an appropriate allocation of indirect cost to the services.
(ii) Where donated services directly benefit a project supported by the Federal award, the indirect costs allocated to the services will be considered as a part of the project's total costs. Such indirect costs may be reimbursed under the Federal award or used to meet cost sharing requirements.
(f) Fair market value of donated services must be computed as described in § 200.306.
(g) Personal property and use of space.
(1) Donated personal property and use of space may be furnished to a recipient or subrecipient. The value of the personal property and space may not be charged to the Federal award either as a direct or indirect cost.
(2) The value of the donations of personal property and use of space may be used to meet cost sharing requirements described in § 200.300. The recipient or subrecipient must value the donations in accordance with § 200.300. Where the recipient or subrecipient treats donations as indirect costs, indirect cost rates must separate the value of the donations so that reimbursement is not made.
§ 200.435
Defense and prosecution of criminal and civil proceedings, claims, appeals and patent infringements.
(a) Definitions for this section —(1) Conviction means a judgment or conviction of a criminal offense by any court of competent jurisdiction, whether entered upon verdict or a plea, including a conviction due to a plea of nolo contendere.
(2) Costs include the services that bear a direct relationship to a judicial or administrative proceeding and provided by in-house or private counsel, accountants, consultants, or others engaged to assist the recipient or subrecipient before, during, or after the commencement of that proceeding.
(3) Fraud means:
(i) Acts of fraud or corruption or attempts to defraud the Federal Government or to corrupt its agents,
(ii) Acts that constitute a cause for debarment or suspension (as specified in agency regulations), and
(iii) Acts that violate the False Claims Act (31 U.S.C. 3729-3732) or the Anti-kickback Act (42 U.S.C. 1320a-7b(b)).
(4) Penalty does not include restitution, reimbursement, or compensatory damages.
(5) Proceeding includes an investigation.
(b) Costs. (1) Except as otherwise described herein, costs incurred in connection with any criminal, civil, or administrative proceeding (including the filing of a false certification) commenced by the Federal Government, a State, local government, or foreign government, or joined by the Federal Government (including a proceeding under the False Claims Act), against the recipient or subrecipient, (or commenced by third parties or a current or former employee of the recipient or subrecipient who submits a whistleblower complaint of reprisal in accordance with 10 U.S.C. 4701 or 41 U.S.C. 4712), are not allowable if the proceeding:
(i) Relates to a violation of, or failure to comply with, a Federal, State, local or foreign statute, regulation, or the terms and conditions of the Federal award by the recipient or subrecipient (including its agents and employees); and
(ii) Results in any of the following dispositions:
(A) In a criminal proceeding, a conviction.
(B) In a civil or administrative proceeding involving an allegation of fraud or similar misconduct, a determination of recipient or subrecipient liability.
(C) In the case of any civil or administrative proceeding, the disallowance of costs, the imposition of a monetary penalty, or an order issued by the Federal agency head or delegate to the recipient or subrecipient to take corrective action under 10 U.S.C. 4701 or 41 U.S.C. 4712.
(D) A final decision by an appropriate Federal official to debar or suspend the recipient or subrecipient, to rescind or void a Federal award, or to terminate a Federal award because of a violation or failure to comply with a statute, regulation, or the terms and conditions of the Federal award.
(E) A disposition by consent or compromise if the action could have resulted in any of the dispositions described in paragraphs (b)(1)(ii)(A) through (D) of this section.
(2) If more than one proceeding involves the same alleged misconduct, the costs of all such proceedings are unallowable if any results in one of the dispositions shown in paragraph (b) of this section.
(c) Allowability of costs for proceeding commenced by Federal Government. If a proceeding referred to in paragraph (b) of this section is commenced by the Federal Government and is resolved by consent or compromise pursuant to an agreement by the recipient or subrecipient and the Federal Government, then the costs incurred may be allowed to the extent expressly authorized in the agreement.
(d) Allowability of costs for proceeding commenced by State, local, or foreign government. If a proceeding referred to in paragraph (b) of this section is commenced by a State, local or foreign government, then the costs incurred may be allowed if the authorized Federal official determines that the costs were incurred as a result of:
(1) A specific term or condition of the Federal award, or
(2) Specific written direction of an authorized official of the Federal agency.
(e) Allowability of costs in general. Costs incurred in connection with proceedings described in paragraph (b), and not made unallowable by that paragraph, may be allowed to the extent that:
(1) The costs are reasonable and necessary for the administration of the Federal award and activities required to deal with the proceeding and the underlying cause of action;
(2) Payment of the reasonable, necessary, allocable and otherwise allowable costs incurred is not prohibited by any other provision(s) of the Federal award;
(3) The costs are not recovered from the Federal Government or a third party, either directly as a result of the proceeding or otherwise; and,
(4) An authorized Federal official has determined the percentage of costs allowed considering the complexity of litigation, generally accepted principles governing the award of legal fees in civil actions involving the United States, and other factors that may be appropriate. This percentage must not exceed 80 percent unless an agreement under paragraph (c) has explicitly considered this limitation and permitted a higher percentage. In that case, the total amount of costs incurred may be allowable.
(f) Major Fraud Act. Costs incurred by the recipient or subrecipient in connection with the defense of suits brought by its employees or ex-employees under section 2 of the Major Fraud Act of 1988 (18 U.S.C. 1031), including the cost of all relief necessary to make the employee whole, where the recipient or subrecipient was found liable or settled, are unallowable.
(g) Un-allowability of costs for prosecuting claims against Federal Government. Costs for prosecuting claims against the Federal Government, including appeals of final Federal agency decisions, are unallowable.
(h) Patent infringement litigation. Costs of legal, accounting, and consultant services, and related costs incurred in connection with patent infringement litigation, are unallowable unless otherwise provided for in the Federal award.
(i) Potentially unallowable costs. Costs that may be unallowable under this section, including directly associated costs, must be segregated and accounted for separately. During the pendency of any proceeding covered by paragraphs (b) and (f) of this section, the Federal Government must generally withhold payment of such costs. However, if in its best interests, the Federal Government may provide for conditional payment upon provision of adequate security, or other adequate assurance, and agreement to repay all unallowable costs, plus interest, if the costs are subsequently determined to be unallowable.
§ 200.436
Depreciation.
(a) Depreciation is the method for allocating the cost of fixed assets to periods benefitting from asset use. The recipient or subrecipient may be compensated for the use of its buildings, capital improvements, equipment, and software projects capitalized in accordance with GAAP provided that they are needed and used in the recipient's or subrecipient's activities and correctly allocated to Federal awards. The compensation must be made by computing the proper depreciation.
(b) The allocation for depreciation must be made in accordance with Appendices III through IX of this part.
(c) Depreciation is computed applying the following rules. The computation of depreciation must be based on the acquisition cost of the assets involved. For an asset donated to the recipient or subrecipient by a third party, its fair market value at the time of the donation must be considered as the acquisition cost. Such assets may be depreciated or claimed as cost sharing but not both. When computing depreciation charges, the acquisition cost will exclude:
(1) The cost of land;
(2) Any portion of the cost of buildings and equipment borne by or donated by the Federal Government, irrespective of where the title was originally vested or is presently located;
(3) Any portion of the cost of buildings and equipment contributed by or for the recipient or subrecipient that is already claimed as cost sharing or where law or agreement prohibits recovery; and
(4) Any asset acquired solely for the performance of a non-Federal award.
(d) When computing depreciation charges, the following must be observed:
(1) The period of useful service or useful life established in each case for usable capital assets must take into consideration such factors as the type of construction, nature of the equipment, technological developments in the particular area, historical data, and the renewal and replacement policies followed for the individual items or classes of assets involved.
(2) The depreciation method used to charge the cost of an asset (or group of assets) to accounting periods must reflect the pattern of consumption of the asset during its useful life. In the absence of clear evidence indicating that the expected consumption of the asset will be significantly greater in the early portions than in the later portions of its useful life, the straight-line method must be presumed to be the appropriate method. Once used, depreciation methods may not be changed unless approved in advance by the cognizant agency for indirect costs. The depreciation methods used to calculate the depreciation amounts for indirect cost rate purposes must be the same methods used by the recipient or subrecipient for its financial statements.
(3) The entire building, including the shell and all components, may be treated as a single asset and depreciated over a single useful life. A building may also be divided into multiple components. Each component may be depreciated over its estimated useful life in this case. The building components must be grouped into three general components: building shell (including construction and design costs), building services systems (for example, elevators, HVAC, and plumbing system), and fixed equipment (for example, sterilizers, casework, fume hoods, cold rooms, and glassware/washers). A cognizant agency for indirect costs may authorize a recipient or subrecipient to use more than these three groupings in exceptional cases. When a recipient or subrecipient elects to depreciate its buildings by their components, the same depreciation method must be used for indirect and financial statements purposes, as described in paragraphs (d)(1) and (2).
(4) No depreciation may be allowed on assets that have outlived their depreciable lives.
(5) Where the depreciation method is introduced to replace the use allowance method, depreciation must be computed as if the asset had been depreciated over its entire life (meaning, from the date the asset was acquired and ready for use to the date of disposal or withdrawal from service). The total amount of use allowance and depreciation for an asset (including imputed depreciation applicable to periods before the conversion from the use allowance method and depreciation after the conversion) may not exceed the total acquisition cost of the asset.
(e) Adequate property records must support depreciation charges, and physical inventories must be taken at least once every two years to ensure that the assets exist and are usable, used, and needed. The recipient or subrecipient may use statistical sampling techniques when taking these inventories. In addition, the recipient or subrecipient must maintain adequate depreciation records showing the amount of depreciation.
§ 200.437
Employee health and welfare costs.
(a) Costs incurred in accordance with the recipient's or subrecipient's established written policies for improving working conditions, employer-employee relations, employee health, and employee performance are allowable.
(b) These costs must be equitably apportioned to all activities of the recipient or subrecipient. Income generated from these activities must be credited to the cost thereof unless such income has been irrevocably sent to employee welfare organizations.
(c) Losses resulting from operating food services are allowable only if the recipient's or subrecipient's objective is to operate food services on a break-even basis. Losses sustained because of operating objectives other than the above are allowable only when:
(1) The recipient or subrecipient can demonstrate unusual circumstances; and
(2) Approved by the cognizant agency for indirect costs.
§ 200.438
Entertainment and prizes.
(a) Entertainment costs. Costs of entertainment, including amusement, diversion, and social activities and any associated costs (such as gifts), are unallowable unless they have a specific and direct programmatic purpose and are included in a Federal award.
(b) Prizes. Costs of prizes or challenges are allowable if they have a specific and direct programmatic purpose and are included in the Federal award. Federal agencies should refer to OMB guidance in M-10-11 “Guidance on the Use of Challenges and Prizes to Promote Open Government,” issued March 8, 2010, or its successor.
§ 200.439
Equipment and other capital expenditures.
(a) See § 200.1 for the definitions of capital expenditures, equipment, special purpose equipment, general purpose equipment, acquisition cost, and capital assets.
(b) The following rules of allowability must apply to equipment and other capital expenditures:
(1) Capital expenditures for general purpose equipment, buildings, and land are allowable as direct costs, but only with the prior written approval of the Federal agency or pass-through entity.
(2) Capital expenditures for special purpose equipment are allowable as direct costs, provided that items with a unit cost of $10,000 or more have the prior written approval of the Federal agency or pass-through entity.
(3) Capital expenditures for improvements to land, buildings, or equipment that materially increase their value or useful life are allowable as a direct cost, but only with the prior written approval of the Federal agency or pass-through entity. See § 200.436 on the allowability of depreciation on buildings, capital improvements, and equipment. See § 200.465 on the allowability of real property and equipment rental costs.
(4) When approved as a direct cost in accordance with paragraphs (b)(1) through (3), capital expenditures must be charged in the period in which the expenditure is incurred or as otherwise determined appropriate and negotiated with the Federal agency.
(5) The recipient or subrecipient may claim the unamortized portion of any equipment written off as a result of a change in capitalization levels by continuing to claim the otherwise allowable depreciation on the equipment or by amortizing the amount to be written off over a period of years negotiated with the cognizant agency for indirect cost.
(6) Cost of equipment disposal. If the Federal agency instructs the recipient or subrecipient to otherwise dispose of or transfer the equipment, the costs of disposal or transfer are allowable.
(7) Equipment and other capital expenditures are unallowable as indirect costs. See § 200.436.
§ 200.440
Exchange rates.
(a) Cost increases for fluctuations in exchange rates are allowable costs subject to the availability of funding. Prior approval of exchange rate fluctuations is required only when the change results in the need for additional Federal funding, or the increased costs result in the need to significantly reduce the scope of the project. Before providing approval, the Federal agency must ensure that adequate funds are available to cover currency fluctuations in order to avoid a violation of the Antideficiency Act.
(b) The recipient or subrecipient is required to make reviews of local currency gains to determine the need for additional Federal funding before the expiration date of the Federal award. Subsequent adjustments for currency increases may be allowable only when the recipient or subrecipient provides the Federal agency with adequate source documentation from a commonly used source in effect at the time the expense was made, and to the extent that sufficient Federal funds are available.
§ 200.441
Fines, penalties, damages and other settlements.
Costs resulting from recipient or subrecipient violations of, alleged violations of, or failure to comply with, Federal, State, local, tribal, or foreign laws and regulations are unallowable, except when incurred as a result of compliance with specific provisions of the Federal award, or with the prior written approval of the Federal agency. See § 200.435.
§ 200.442
Fundraising and investment management costs.
(a) Costs of organized fundraising, including financial campaigns, endowment drives, solicitation of gifts and bequests, and similar expenses incurred to raise capital or obtain contributions, are unallowable. Fundraising costs for meeting the Federal program objectives are allowable with the prior written approval of the Federal agency.
(b) Costs of investment counsel and staff and similar expenses incurred to enhance income from investments are unallowable except when associated with investments covering pension, self-insurance, or other funds, which include Federal participation allowed by this part.
(c) Costs related to the physical custody and control of monies and securities are allowable.
(d) Both allowable and unallowable fundraising and investment activities must be allocated an appropriate share of indirect costs in accordance with § 200.413.
§ 200.443
Gains and losses on the disposition of depreciable assets.
(a) The recipient or subrecipient must include gains and losses on the sale, retirement, or other disposition of depreciable property in the year they occur as credits or charges to the asset cost grouping(s) of the property. The amount of the gain or loss is the difference between the amount realized on the property and the undepreciated basis of the property.
(b) Gains and losses from the disposition of depreciable property must not be recognized as a separate credit or charge under the following conditions:
(1) The gain or loss is processed through a depreciation account and is reflected in the depreciation allowable under §§ 200.436 and 200.439.
(2) The property is given in exchange as part of the purchase price of a similar item, and the gain or loss is taken into account in determining the depreciation cost basis of the new item.
(3) A loss results from failing to maintain proper insurance, except as provided in § 200.447.
(4) Compensation for the use of the property was provided through use allowances instead of depreciation.
(5) Gains and losses arising from extraordinary or bulk sales, retirements, or other dispositions must be considered on a case-by-case basis.
(c) Gains or losses of any nature arising from the sale or exchange of property other than the property covered in paragraph (a) of this section must be excluded in computing Federal award costs.
(d) When assets acquired with Federal funds, in part or wholly, are disposed of, the distribution of the proceeds must be made in accordance with §§ 200.310 through 200.316.
§ 200.444
General costs of government.
(a) For states, local governments, and Indian Tribes, the general costs of government are unallowable except as provided in § 200.475. Unallowable costs include:
(1) Salaries and expenses of the Office of the Governor of a State or the chief executive of a local government or the chief executive of an Indian Tribe;
(2) Salaries and other expenses of a State legislature, tribal council, or similar local governmental body, such as a county supervisor, city council, or school board, whether incurred for purposes of legislation or executive direction;
(3) Costs of the judicial branch of a government;
(4) Costs of prosecutorial activities unless treated as a direct cost to a specific program if authorized by statute or regulation. However, this does not preclude the allowability of other legal activities of the Attorney General as described in § 200.435; and
(5) Costs of other general types of government services normally provided to the general public, such as fire and police, unless provided as a direct cost under a program statute or regulation.
(b) Indian Tribes and Councils of Governments (COGs) (see definition for Local government in § 200.1) may include up to 50 percent of salaries and expenses directly attributable to managing and operating Federal programs by the chief executive and their staff in the indirect cost calculation without documentation.
§ 200.445
Goods or services for personal use.
(a) Costs of goods or services for the personal use of the recipient's or subrecipient's employees are unallowable regardless of whether the cost is reported as taxable income to the employees.
(b) Housing costs (for example, depreciation, maintenance, utilities, furnishings, rent), housing allowances, and personal living expenses for the recipient's or subrecipient's employees are only allowable as direct costs and must be approved in advance by the Federal agency.
§ 200.446
Idle facilities and idle capacity.
(a) Definitions for the purpose of this section:
(1) Facilities means land and buildings or any portion thereof, equipment individually or collectively, or any other tangible capital asset, wherever located, and whether owned or leased by the recipient or subrecipient.
(2) Idle facilities mean completely unused facilities that exceed the recipient's or subrecipient's current needs.
(3) Idle capacity means the unused capacity of partially used facilities. It is the difference between:
(i) That which a facility could achieve under 100 percent operating time on a one-shift basis less operating interruptions resulting from time lost for repairs, setups, unsatisfactory materials, and other normal delays; and
(ii) The extent to which the facility was actually used to meet demands during the accounting period. A multi-shift basis should be used if it can be shown that this amount of usage would normally be expected for the type of facility involved.
(4) Cost of idle facilities or idle capacity means maintenance, repair, housing, rent, and other related costs (for example, insurance, interest, and depreciation). These costs could include the costs of idle public safety emergency facilities, telecommunications, or information technology system capacity that is built to withstand major fluctuations in load (for example, consolidated data centers).
(b) The costs of idle facilities are unallowable except to the extent that:
(1) They are necessary to meet workload requirements which may fluctuate, and are allocated appropriately to all benefiting programs; or
(2) Although not necessary to meet fluctuations in workload, they were necessary when acquired and are now idle because of changes in program requirements, efforts to achieve more economical operations, reorganization, termination, or other causes which could not have been reasonably foreseen. Under this exception, costs of idle facilities are allowable for a reasonable period, ordinarily not to exceed one year, depending on the initiative taken to use, lease, or dispose of such facilities.
(c) The costs of idle capacity are normal costs of doing business and are a factor in the normal fluctuations of usage or indirect cost rates from period to period. These costs are allowable, provided that the capacity is reasonably anticipated to be necessary to carry out the purpose of the Federal award or was originally reasonable and is not subject to reduction or elimination by use on other Federal awards, subletting, renting, or sale, in accordance with sound business, economic, or security practices. Widespread idle capacity throughout an entire facility or among a group of assets having substantially the same function may be considered idle facilities.
§ 200.447
Insurance and indemnification.
(a) Costs of insurance required or approved and maintained by the terms and conditions of the Federal award are allowable.
(b) Costs of other insurance in connection with the general conduct of activities are allowable subject to the following limitations:
(1) The types, extent, and cost of coverage are in accordance with the recipient's or subrecipient's established written policy and sound business practices.
(2) Costs of insurance or contributions to any reserve covering the risk of loss of, or damage to, Federal Government property are unallowable except to the extent that the Federal agency has approved the costs.
(3) Costs allowed for business interruption or other similar insurance must exclude coverage of management fees.
(4) Insurance costs on the lives of trustees, officers, or other employees holding positions of similar responsibilities are allowable only when the insurance represents additional compensation (see § 200.431). This insurance is unallowable when the recipient or subrecipient is identified as the beneficiary.
(5) Insurance costs to correct defects in the recipient's or subrecipient's materials or workmanship are unallowable.
(6) Medical liability (malpractice) insurance is an allowable cost of a Federal research program only when the program involves human subjects or training of participants in research techniques. Medical liability insurance costs must be treated as a direct cost and assigned to individual projects based on how the insurer allocates the risk to the population covered by the insurance.
(c) Actual losses which could have been covered by permissible insurance (through a self-insurance program or otherwise) are unallowable unless expressly authorized in the Federal award. However, costs incurred because of losses not covered under nominal deductible insurance coverage provided in keeping with sound management practice, and minor losses not covered by insurance, such as spoilage, breakage, and disappearance of small hand tools, which occur in the ordinary course of operations, are allowable.
(d) Contributions to a reserve for a self-insurance program, including workers' compensation, unemployment compensation, and severance pay, are allowable subject to the following requirements:
(1) The type, extent, and cost of coverage and the rates and premiums would have been allowed had insurance (including reinsurance) been purchased to cover the risks. However, a provision for known or reasonably estimated self-insured liabilities, which do not become payable for more than one year after the provision is made, must not exceed the discounted present value of the liability. The rate used for discounting the liability must be determined by considering factors such as the recipient's or subrecipient's settlement rate for those liabilities and its investment rate of return.
(2) Earnings or investment income on reserves must be credited to those reserves.
(3)(i) Contributions to reserves must be based on sound actuarial principles using historical experience and reasonable assumptions. Reserve levels must be analyzed and updated at least biennially for each major risk being insured and take into account any reinsurance, coinsurance, and other relevant factors or information. Reserve levels related to employee-related coverages must normally be limited to the value of claims:
(A) Submitted and adjudicated but not paid;
(B) Submitted but not adjudicated; and
(C) Incurred but not submitted.
(ii) Reserve exceeding the levels described in paragraph (d)(3)(i) of this section must be identified and justified in the cost allocation plan or indirect cost rate proposal.
(4) Accounting records, actuarial studies, and cost allocations (or billings) must recognize any significant differences due to the types of insured risk and losses generated by the various insured activities or agencies of the recipient or subrecipient. If individual departments or agencies of the recipient or subrecipient experience significantly different levels of claims for a particular risk, those differences must be recognized by using separate allocations or other techniques resulting in an equitable allocation.
(5) Whenever funds are transferred from a self-insurance reserve to other accounts (for example, general fund or unrestricted account), refunds must be made to the Federal Government for its share of funds transferred, including earned or imputed interest from the date of transfer and debt interest, if applicable, chargeable in accordance with the claims collection regulations of the cognizant agency for indirect cost.
(e) Insurance refunds must be credited against insurance costs in the year the refund is received.
(f) Indemnification includes securing the recipient or subrecipient against liabilities to third persons and other losses not compensated by insurance or otherwise. The Federal Government is obligated to indemnify the recipient or subrecipient only to the extent expressly provided for in the Federal award, except as provided in paragraph (c).
§ 200.448
Intellectual property.
(a) Patent and copyright costs. (1) The following costs related to securing patents and copyrights are allowable:
(i) Costs of preparing disclosures, reports, and other documents required by the Federal award and of searching the art to the extent necessary to make such disclosures;
(ii) Costs of preparing documents and any other patent costs in connection with the filing and prosecution of a United States patent application where the Federal Government requires that a title or a royalty-free license be conveyed to the Federal Government; and
(iii) General counseling services relating to patent and copyright matters, such as advice on patent and copyright laws, regulations, clauses, and employee intellectual property agreements (See § 200.459).
(2) The following costs related to securing patents and copyrights are unallowable:
(i) Costs of preparing disclosures, reports, and other documents and of searching the art to make disclosures not required by the Federal award;
(ii) Costs in connection with filing and prosecuting any foreign patent application, or any United States patent application, where the Federal award does not require conveying title or a royalty-free license to the Federal Government.
(b) Royalties and other costs for the use of patents and copyrights. (1) Royalties on a patent or copyright or amortization of the cost of acquiring by purchase a copyright, patent, or rights thereto, necessary for the proper performance of the Federal award are allowable unless:
(i) The Federal Government already has a license or the right to free use of the patent or copyright.
(ii) The patent or copyright has been adjudicated to be invalid or administratively determined to be invalid.
(iii) The patent or copyright is considered to be unenforceable.
(iv) The patent or copyright is expired.
(2) Special care should be exercised in determining reasonableness when the royalties may have been obtained as a result of less-than-arm's-length bargaining, such as:
(i) Royalties paid to persons, including corporations, affiliated with the recipient or subrecipient.
(ii) Royalties paid to unaffiliated parties, including corporations, under an agreement entered into in contemplation that a Federal award would be made.
(iii) Royalties paid under an agreement entered into after a Federal award is made to a recipient or subrecipient.
(3) In any case involving a patent or copyright formerly owned by the recipient or subrecipient, the amount of royalty allowed must not exceed the cost which would have been allowed had the recipient or subrecipient retained ownership.
§ 200.449
Interest.
(a) General. Costs incurred for interest on borrowed capital, temporary use of endowment funds, or the use of the recipient's or subrecipient's own funds are unallowable. Financing costs (including interest) to acquire, construct, or replace capital assets are allowable, subject to the requirements of this section.
(b) Capital assets. (1) Capital assets is defined in § 200.1. An asset cost includes (as applicable) acquisition costs, construction costs, and other costs capitalized in accordance with GAAP.
(2) For recipient or subrecipient fiscal years beginning on or after January 1, 2016, intangible assets include patents and computer software. For software development projects, only interest attributable to the portion of the project costs capitalized in accordance with GAAP is allowable.
(c) Requirements for all recipients and subrecipients. (1) The recipient or subrecipient uses the capital assets in support of Federal awards;
(2) The allowable asset costs to acquire facilities and equipment are limited to a fair market value available to the recipient or subrecipient from an unrelated (arm's length) third party.
(3) The recipient or subrecipient obtains the financing via an arm's-length transaction (meaning, a transaction with an unrelated third party); or claims reimbursement of actual interest cost at a rate available via such a transaction.
(4) The recipient or subrecipient limits claims for Federal reimbursement of interest costs to the least expensive alternative. For example, a lease contract that transfers ownership by the end of the contract may be determined less costly than purchasing through other types of debt financing, in which case reimbursement must be limited to the amount of interest determined if leasing had been used.
(5) The recipient or subrecipient expenses or capitalizes allowable interest cost in accordance with GAAP.
(6) Earnings generated by the investment of borrowed funds pending their disbursement for the asset costs are used to offset the current period's allowable interest cost, whether that cost is expensed or capitalized. Earnings subject to being reported to the Federal Internal Revenue Service under arbitrage requirements are excludable.
(7) The following conditions must apply to debt arrangements over $1 million to purchase or construct facilities unless the recipient or subrecipient makes an initial equity contribution to the purchase of 25 percent or more. For this purpose, “initial equity contribution” means the amount or value of contributions made by the recipient or subrecipient for the acquisition of facilities prior to occupancy.
(i) The recipient or subrecipient must reduce claims for reimbursement of interest cost by an amount equal to imputed interest earnings on excess cash flow attributable to the portion of the facility used for Federal awards.
(ii) The recipient or subrecipient must impute interest on excess cash flow as follows:
(A) Annually, the recipient or subrecipient must prepare a cumulative (from the project's inception) report of monthly cash inflows and outflows, regardless of the funding source. For this purpose, inflows consist of Federal reimbursement for depreciation, amortization of capitalized construction interest, and annual interest cost. Outflows consist of initial equity contributions, debt principal payments (less the pro-rata share attributable to the cost of land), and interest payments.
(B) To compute monthly cash inflows and outflows, the recipient or subrecipient must divide the above-mentioned annual amounts by the months in the year (usually 12) that the building is in service.
(C) For any month in which cumulative cash inflows exceed cumulative outflows, interest must be calculated on the excess inflows for that month and be treated as a reduction to allowable interest cost. The interest rate to be used must be the three-month Treasury bill closing rate as of the last business day of that month.
(8) Interest attributable to a fully depreciated asset is unallowable.
(d) Additional requirements for states, local governments and Indian Tribes. For interest costs to be allowable for states, local governments, and Indian Tribes, the recipient or subrecipient must have incurred the interest costs for buildings after October 1, 1980, or after September 1, 1995, for land and equipment.
(1) The requirement to offset the interest earned on borrowed funds against allowable interest cost (paragraph (c)(5) of this section) also applies to earnings on debt service reserve funds.
(2) The recipient or subrecipient must negotiate the amount of allowable interest cost related to the acquisition of facilities with asset costs of $1 million or more, as described in paragraph (c)(7) of this section. For this purpose, a recipient or subrecipient must consider only cash inflows and outflows attributable to that portion of the real property used for Federal awards.
(e) Additional requirements for IHEs. For interest costs to be allowable, the IHE must have incurred the interest costs after July 1, 1982, in connection with acquisitions of capital assets that occurred after that date.
(f) Additional requirements for nonprofit organizations. For interest costs to be allowable, the nonprofit organization must have incurred the interest costs after September 29, 1995, in connection with acquisitions of capital assets that occurred after that date.
(g) Requirements for nonprofit organizations subject to full coverage under CAS. The interest allowability provisions of this section do not apply to a nonprofit organization subject to “full coverage” under the Cost Accounting Standards (CAS), as defined at 48 CFR 9903.201-2(a). The nonprofit organization's Federal awards are instead subject to CAS 414 (48 CFR 9904.414), “Cost of Money as an Element of the Cost of Facilities Capital,” and CAS 417 (48 CFR 9904.417), “Cost of Money as an Element of the Cost of Capital Assets Under Construction.”
§ 200.450
Lobbying.
(a) Lobbying costs associated with obtaining Federal assistance awards. The costs of certain influencing activities associated with obtaining grants, cooperative agreements, contracts, or loans are unallowable. Lobbying with respect to certain grants, cooperative agreements, contracts, and loans is governed by relevant statutes, including the provisions of 31 U.S.C. 1352, as well as the common rule, “New Restrictions on Lobbying,” published on February 26, 1990, including definitions, and the Office of Management and Budget “Government-wide Guidance for New Restrictions on Lobbying” and notices published on December 20, 1989, June 15, 1990, January 15, 1992, and January 19, 1996.
(b) Executive lobbying costs. Costs incurred in attempting to improperly influence, either directly or indirectly, an employee or officer of the executive branch of the Federal Government to give consideration or to act regarding a Federal award or a regulatory matter are unallowable. Improper influence means any influence that induces or tends to induce a Federal employee or officer to give consideration or to act regarding a Federal award or regulatory matter on any basis other than the merit.
(c) Restrictions on nonprofit organizations and IHEs. In addition, the following restrictions apply to nonprofit organizations and IHEs:
(1) Costs associated with the following activities are unallowable:
(i) Attempts to influence the outcomes of any Federal, State, or local election, referendum, initiative, or similar procedure through in-kind or cash contributions, endorsements, publicity, or similar activity;
(ii) Establishing, administering, contributing to, or paying the expenses of a political party, campaign, political action committee, or other organization established to influence the outcomes of elections in the United States;
(iii) Any attempt to influence:
(A) The introduction of Federal or State legislation;
(B) The enactment or modification of any pending Federal or State legislation through communication with any member or employee of the Congress or State legislature (including efforts to influence State or local officials to engage in similar lobbying activity);
(C) The enactment or modification of any pending Federal or State legislation by preparing, distributing, or using publicity or propaganda or by urging members of the general public, or any segment thereof, to contribute to or participate in any mass demonstration, march, rally, fundraising drive, lobbying campaign or letter writing or telephone campaign; or
(D) Any government official or employee in connection with a decision to sign or veto enrolled legislation;
(iv) Legislative liaison activities, including attendance at legislative sessions or committee hearings, gathering information regarding legislation, and analyzing the effect of legislation, when such activities are carried on in support of or in knowing preparation for an effort to engage in unallowable lobbying.
(2) The following activities are excepted from the coverage of paragraph (c)(1) of this section:
(i) Technical and factual presentations on topics directly related to the performance of a grant, contract, or other agreement (through hearing testimony, statements, or letters to the Congress or a State legislature, or subdivision, member, or cognizant staff member thereof), in response to a documented request (including a Congressional Record notice requesting testimony or statements for the record at a regularly scheduled hearing) made by the recipient's or subrecipient's member of congress, legislative body, subdivision, or a cognizant staff member thereof, provided such information is readily obtainable and can be readily put in deliverable form, and further provided that costs under this section for travel, lodging or meals are unallowable unless incurred to offer testimony at a regularly scheduled Congressional hearing pursuant to a written request for such presentation made by the Chairman or Ranking Minority Member of the Committee or Subcommittee conducting such hearings;
(ii) Any lobbying made unallowable by paragraph (c)(1)(iii) of this section to influence State legislation to directly reduce the cost, or to avoid material impairment of the recipient's or subrecipient's authority to perform the grant, contract, or other agreement;
(iii) Any activity specifically authorized by statute to be undertaken with funds from the Federal award; or
(iv) Any activity excepted from the definitions of “lobbying” or “influencing legislation” by the Internal Revenue Code provisions that require nonprofit organizations to limit their participation in direct and “grass roots” lobbying activities to retain their charitable deduction status and avoid punitive excise taxes, 26 U.S.C. (I.R.C.) 501(c)(3), 501(h), 4911(a), including:
(A) Nonpartisan analysis, study, or research reports;
(B) Examinations and discussions of broad social, economic, and similar problems; and
(C) Information provided upon request by a legislator for technical advice and assistance, as defined by I.R.C. 4911(d)(2) and 26 CFR 56.4911-2(c)(1) through (c)(3).
(3) When a recipient or subrecipient seeks reimbursement for indirect costs, total lobbying costs must be identified separately in the indirect cost rate proposal and thereafter be treated as other unallowable activity costs in accordance with § 200.413.
(4) The recipient or subrecipient must submit a certification that the requirements and standards of this section have been complied with as part of its annual indirect cost rate proposal. (See § 200.415.)
(5)(i) Time logs, calendars, or similar records are not required to be created for purposes of complying with the record-keeping requirements in § 200.302 with respect to lobbying costs during a particular calendar month when:
(A) The employee engages in lobbying (as defined in paragraphs (c)(1) and (2) of this section) for 25 percent or less of the employee's compensated hours of employment during that calendar month; and
(B) Within the preceding five-year period, the recipient or subrecipient has not materially misstated allowable or unallowable costs of any nature, including legislative lobbying costs.
(ii) When conditions in paragraph (c)(5)(i)(A) and (B) of this section are met, recipients and subrecipients are not required to establish records to support the allowability of claimed costs in addition to records already required or maintained. Also, when conditions in paragraphs (c)(5)(i)(A) and (B) of this section are met, the absence of time logs, calendars, or similar records will not serve as a basis for disallowing costs by contesting estimates of lobbying time spent by employees during a calendar month.
(iii) In consultation with OMB, the Federal agency must establish procedures for resolving, in advance, any significant questions or disagreements concerning the interpretation or application of this section. Any such advance resolutions must be binding in any subsequent settlements, audits, or investigations with respect to that grant or contract for purposes of interpretation of this part, provided, however, that this must not be construed to prevent a contractor or recipient or subrecipient from contesting the lawfulness of such a determination.
§ 200.451
Losses on other awards or contracts.
Any excess costs over income under any other award or contract of any nature is unallowable. This includes, but is not limited to, the recipient's or subrecipient's contributed portion by reason of cost sharing agreements or any under-recoveries through negotiation of flat amounts for indirect costs. Also, any excess of costs over authorized funding levels transferred from any award or contract to another is unallowable. All losses are not allowable indirect costs and must be included in the appropriate indirect cost rate base for allocating indirect costs.
§ 200.452
Maintenance and repair costs.
Costs incurred for utilities, insurance, security, necessary maintenance, janitorial services, repair, or upkeep of buildings and equipment (including Federal property unless otherwise provided for) which neither add to the permanent value of the property nor appreciably prolong its intended life, but keep it in an efficient operating condition, are allowable. Costs incurred for improvements that add to the permanent value of the buildings and equipment or appreciably prolong their intended life must be treated as capital expenditures (see § 200.439). These costs are only allowable to the extent not paid through rental or other agreements.
§ 200.453
Materials and supplies costs, including costs of computing devices.
(a) Costs incurred for materials, supplies, and fabricated parts necessary for the performance of a Federal award are allowable.
(b) Purchased materials and supplies must be charged at their actual prices, net of applicable credits. Withdrawals from general stores or stockrooms must be charged at their actual net cost under any recognized method of pricing inventory withdrawals, consistently applied. Incoming transportation charges are an allowable part of materials and supplies costs.
(c) Materials and supplies used for the performance of a Federal award may be charged as direct costs. Charging computing devices as direct costs is allowable for devices that are essential and allocable, but not solely dedicated, to the performance of a Federal award.
(d) Where Federally-donated or furnished materials are used in performing the Federal award, the materials will be used without charge.
§ 200.454
Memberships, subscriptions, and professional activity costs.
(a) Costs of the recipient's or subrecipient's membership in business, technical, and professional organizations are allowable.
(b) Costs of the recipient's or subrecipient's subscriptions to business, professional, and technical periodicals are allowable.
(c) Costs of membership in any civic or community organization are allowable.
(d) Costs of membership in any country club or social or dining club or organization are unallowable.
(e) Costs of membership in organizations whose primary purpose is lobbying are unallowable. See § 200.450.
§ 200.455
Organization costs.
(a) Costs such as incorporation fees, brokers' fees, fees to promoters, organizers or management consultants, attorneys, accountants, or investment counselors, whether or not employees of the recipient or subrecipient in connection with the establishment or reorganization of an organization, are unallowable except with prior approval of the Federal agency.
(b) The costs of any of the following activities are unallowable: activities undertaken to persuade employees of the recipient or subrecipient, or any other entity, to exercise or not to exercise, or concerning the manner of exercising, the right to organize and bargain collectively through representatives of the employees' own choosing.
(c) The costs related to data and evaluation are allowable. Data costs include (but are not limited to) the expenditures needed to gather, store, track, manage, analyze, disaggregate, secure, share, publish, or otherwise use data to administer or improve the program, such as data systems, personnel, data dashboards, cybersecurity, and related items. Data costs may also include direct or indirect costs associated with building integrated data systems—data systems that link individual-level data from multiple State and local government agencies for purposes of management, research, and evaluation. Evaluation costs include (but are not limited to) evidence reviews, evaluation planning and feasibility assessment, conducting evaluations, sharing evaluation results, and other personnel or materials costs related to the effective building and use of evidence and evaluation for program design, administration, or improvement.
§ 200.456
Participant support costs.
Participant support costs are allowable (see § 200.1 ). The classification of items as participant support costs must be documented in the recipient's or subrecipient's written policies and procedures and treated consistently across all Federal awards.
§ 200.457
Plant and security costs.
Necessary and reasonable expenses incurred for the protection and security of facilities, personnel, and work products are allowable. Such costs include, but are not limited to, wages and uniforms of personnel engaged in security activities; equipment; barriers; protective (non-military) gear, devices, and equipment; contractual security services; and consultants. Capital expenditures for plant security purposes are subject to § 200.439.
§ 200.458
Pre-award costs.
Pre-award costs are those incurred before the start date of the Federal award or subaward directly pursuant to the negotiation and in anticipation of the Federal award where such costs are necessary for efficient and timely performance of the scope of work. These costs are allowable only to the extent that they would have been allowed if incurred after the start date of the Federal award and only with the written approval of the Federal agency. If approved, these costs must be charged to the initial budget period of the Federal award unless otherwise specified by the Federal agency or pass-through entity.
§ 200.459
Professional service costs.
(a) Costs of professional and consultant services rendered by persons who are members of a particular profession or possess a special skill and who are not officers or employees of the recipient or subrecipient are allowable, subject to paragraphs (b) and (c) of this section when reasonable in relation to the services rendered and when not contingent upon recovery of the costs from the Federal Government. In addition, legal and related services are limited under § 200.435.
(b) In determining the allowability of costs in a particular case, no single factor or any combination of factors is necessarily determinative. However, the following factors are relevant:
(1) The nature and scope of the service rendered in relation to the service required.
(2) The necessity of contracting for the service, considering the recipient's or subrecipient's capability in the particular area.
(3) The past pattern of such costs, particularly in the years prior to receiving a Federal award(s).
(4) The impact of Federal awards on the recipient's or subrecipient's business (meaning, what new problems have arisen).
(5) Whether the proportion of Federal work to the recipient's or subrecipient's total business influences the recipient or subrecipient in favor of incurring the cost, particularly where the services rendered are not of a continuing nature and have little relationship to work under Federal awards.
(6) Whether the service can be performed more economically by direct employment rather than contracting.
(7) The qualifications of the individual or entity providing the service and the customary fees charged, especially on non-federally funded activities.
(8) Adequacy of the contractual agreement for the service (for example, description of the service, estimate of the time required, rate of compensation, and termination provisions).
(c) To be allowable, retainer fees must be supported by evidence of bona fide services available or rendered in addition to the factors in paragraph (b) of this section.
§ 200.460
Proposal costs.
Proposal costs are the costs of preparing bids, proposals, or applications on potential Federal and non-Federal awards or projects, including developing data necessary to support the recipient's or subrecipient's bids or proposals. Proposal costs of the current accounting period of both successful and unsuccessful bids and proposals normally should be treated as indirect costs and allocated to all current activities of the recipient or subrecipient. No proposal costs of past accounting periods may be allocated to the current period.
§ 200.461
Publication and printing costs.
(a) Publication costs for electronic and print media, including distribution, promotion, and general handling, are allowable. These costs should be allocated as indirect costs to all benefiting activities of the recipient or subrecipient if they are not identifiable with a particular cost objective.
(b) Page charges, article processing charges (APCs), or similar fees such as open access fees for professional journal publications and other peer-reviewed publications resulting from a Federal award are allowable where:
(1) The publications report work supported by the Federal Government; and
(2) The charges are levied impartially on all items published by the journal, whether or not under a Federal award.
(3) The recipient or subrecipient may charge the Federal award during closeout for the costs of publication or sharing of research results if the costs were not incurred during the period of performance of the Federal award. These costs must be charged to the final budget period of the award unless otherwise specified by the Federal agency.
§ 200.462
Rearrangement and reconversion costs.
(a) Costs incurred for ordinary and normal rearrangement and alteration of facilities are allowable as indirect costs. Special arrangements and alterations are allowable as a direct cost if the costs are incurred specifically for a Federal award and with the prior approval of the Federal agency or pass-through entity.
(b) Costs incurred in restoring or rehabilitating the recipient's or subrecipient's facilities to approximately the same condition existing immediately before the commencement of a Federal award(s), less costs related to normal wear and tear, are allowable.
§ 200.463
Recruiting costs.
(a) Subject to paragraphs (b) and (c) of this section, and provided that the size of the staff recruited and maintained is in keeping with workload requirements, costs of “help wanted” advertising, operating costs of an employment office necessary to secure and maintain adequate staff, costs of operating an aptitude and educational testing program, travel costs of employees while engaged in recruiting personnel, travel costs of applicants for interviews for prospective employment, and relocation costs incurred incident to recruitment of new employees, are allowable to the extent that such costs are incurred pursuant to the recipient's or subrecipient's standard recruitment program. When the recipient or subrecipient uses employment agencies, costs not in excess of standard commercial rates for such services are allowable.
(b) Special emoluments, fringe benefits, and salary allowances incurred to attract professional personnel that do not meet the test of reasonableness or do not conform with the established practices of the recipient or subrecipient, are unallowable.
(c) If relocation costs incurred incident to recruitment of a new employee have been funded in whole or in part by a Federal award, and the newly hired employee resigns for reasons within the employee's control within 12 months after hire, the recipient or subrecipient must refund or credit the Federal Government for its share of those relocation costs. See § 200.464.
(d) Short-term visas (as opposed to longer-term immigration visas) are generally an allowable cost and they may be proposed as a direct cost because they are issued for a specific period and purpose and can be clearly identified as directly connected to work performed on a Federal award. For these costs to be directly charged to a Federal award, they must:
(1) Be critical and necessary for the conduct of the project;
(2) Be allowable under the applicable cost principles;
(3) Be consistent with the recipient's or subrecipient's cost accounting practices and established written policy; and
(4) Meet the definition of “direct cost” as described in the applicable cost principles.
§ 200.464
Relocation costs of employees.
(a) Relocation costs are costs incident to the permanent change of duty assignment (for an indefinite period or a stated period of not less than 12 months) of an existing employee or upon recruitment of a new employee. Relocation costs are allowable, subject to the limitations described in paragraphs (b), (c), and (d) of this section, provided that:
(1) The move is for the benefit of the employer.
(2) Reimbursement to the employee is in accordance with an established written policy consistently followed by the employer.
(3) The reimbursement does not exceed the employee's actual (or reasonably estimated) expenses.
(b) Allowable relocation costs for current employees are limited to the following:
(1) The costs of transportation of the employee, members of their immediate family and their household, and personal effects to the new location.
(2) The costs of finding a new home, such as advance trips by employees and spouses to locate living quarters and temporary lodging during the transition period, up to a maximum period of 30 calendar days.
(3) Closing costs, such as brokerage, legal, and appraisal fees, incidental to the disposition of the employee's former home. These costs, together with those described in paragraph (b)(4) of this section, are limited to eight percent of the sales price of the employee's former home.
(4) The continuing costs of ownership (for up to six months) of the vacant former home after the settlement or lease date of the employee's new permanent home, such as maintenance of buildings and grounds (exclusive of fixing-up expenses), utilities, taxes, and property insurance.
(5) Other necessary and reasonable expenses normally incident to relocation, such as canceling an unexpired lease, transportation of personal property, and purchasing insurance against loss of or damages to personal property. The cost of canceling an unexpired lease is limited to three times the monthly rental.
(c) Allowable relocation costs for new employees are limited to those described in paragraphs (b)(1) and (2) of this section. If relocation costs incurred incident to the recruitment of a new employee have been funded in whole or in part by a Federal award, and the newly hired employee resigns for reasons within the employee's control within 12 months after hire, the recipient or subrecipient must refund or credit the Federal Government for its share of the cost. If a new employee is relocating to an overseas location and dependents are not permitted for any reason, and the costs do not include transporting household goods, the costs must be considered travel costs in accordance with § 200.474 , not relocation costs under this section.
(d) The following costs related to relocation are unallowable:
(1) Fees and other costs associated with acquiring a new home.
(2) A loss on the sale of a former home.
(3) Continuing mortgage principal and interest payments on a home being sold.
(4) Income taxes paid by an employee related to reimbursed relocation costs.
§ 200.465
Rental costs of real property and equipment.
(a) Subject to the limitations described in paragraphs (b) through (d) of this section, rental costs are allowable to the extent that the rates are reasonable in light of such factors as costs of comparable rental properties; market conditions in the area; alternatives available; and the type, life expectancy, condition, and value of the property leased. Rental arrangements should be reviewed periodically to determine if circumstances have changed and if other options are available.
(b) Rental costs under “sale and lease back” arrangements are allowable only up to the amount that would have been allowed if the recipient or subrecipient had continued to own the property. This amount would include expenses such as depreciation, maintenance, taxes, and insurance.
(c) Rental costs under “less-than-arm's-length” leases are allowable only up to the amount described in paragraph (b) of this section. For this purpose, a less-than-arm's-length lease is one under which one party to the lease agreement can control or substantially influence the actions of the other. Such leases include, but are not limited to, those between:
(1) Divisions of the recipient or subrecipient;
(2) The recipient or subrecipient and another entity under common control through common officers, directors, or members; and
(3) The recipient or subrecipient and a director, trustee, officer, or key employee of the recipient or subrecipient or an immediate family member, either directly or through corporations, trusts, or similar arrangements in which they hold a controlling interest. For example, the recipient or subrecipient may establish a separate corporation to own property and lease it back to the recipient or subrecipient.
(4) Family members include one party with any of the following relationships to another party:
(i) Spouse and parents thereof;
(ii) Children and spouses thereof;
(iii) Parents and spouses thereof;
(iv) Siblings and spouses thereof;
(v) Grandparents and grandchildren and spouses thereof;
(vi) Domestic partner and parents thereof, including domestic partners of any individual in 2 through 5 of this definition; and
(vii) Any individual related by blood or affinity whose close association with the employee is the equivalent of a family relationship.
(d) Rental costs under leases which are required to be accounted for as a financed purchase under GASB standards or a finance lease under FASB standards are allowable only up to the amount (described in paragraph (b) of this section) that would have been allowed if the recipient or subrecipient had purchased the property on the date the lease agreement was executed. Interest costs related to these leases are allowable if they meet the criteria in § 200.449. Unallowable costs include costs that would not have been incurred if the recipient or subrecipient had purchased the property, such as amounts paid for profit, management fees, and taxes.
(e) Rental or lease payments are allowable under lease contracts where the recipient or subrecipient is required to recognize an intangible right-to-use lease asset under GASB standards or right-of-use operating lease asset under FASB standards for purposes of financial reporting in accordance with GAAP.
(f) The rental of any property owned by any individuals or entities affiliated with the recipient or subrecipient, including commercial or residential real estate, for purposes such as the home office is unallowable.
§ 200.466
Scholarships, student aid costs, and tuition remission.
(a) Costs of scholarships, fellowships, and student aid programs at IHEs are allowable only when the purpose of the Federal award is to provide training to participants, and the Federal agency approves the cost.
(b) Tuition remission and other forms of compensation paid as, or instead of, wages to students performing necessary work are allowable provided that:
(1) The individual is conducting activities necessary to the Federal award;
(2) Tuition remission and other support are provided in accordance with the established written policy of the IHE and consistently provided in a like manner to students in return for similar activities conducted under Federal awards as well as other activities; and
(3) The student is enrolled in an advanced degree program at the IHE or an affiliated institution during the academic period and the student's activities under the Federal award are related to their degree program;
(4) The tuition or other payments are reasonable compensation for the work performed and are conditioned explicitly upon the performance of necessary work; and
(5) The IHE compensates students under Federal awards as well as other activities in similar manners.
(c) Charges for tuition remission and other forms of compensation paid to students as, or instead of, salaries and wages are subject to the reporting requirements in § 200.430. The charges must be treated as a direct or indirect cost in accordance with the actual work performed. Tuition remission may be charged on an average rate basis. See § 200.431.
§ 200.467
Selling and marketing costs.
Costs of selling and marketing any products or services of the recipient or subrecipient are unallowable unless they are allowed under § 200.421 and are necessary to meet the requirements of the Federal award.
§ 200.468
Specialized service facilities.
(a) The costs of services provided by highly complex or specialized facilities operated by the recipient or subrecipient are allowable provided the charges for the services meet the conditions of either paragraph (b) or (c) of this section and take into account any items of income or Federal financing that qualify as applicable credits under § 200.406. These costs include charges for facilities such as computing facilities, wind tunnels, and reactors.
(b) The costs of such services, when material, must be charged directly to the applicable Federal awards based on actual usage of the services on the basis of a schedule of rates or established methodology that:
(1) Does not discriminate between activities under Federal awards and other activities of the recipient or subrecipient, including usage by the recipient or subrecipient for internal purposes; and
(2) Is designed to recover only the aggregate costs of the services. Each service's costs must normally consist of its direct costs and an allocable share of all indirect costs. Rates must be adjusted at least biennially and must consider any over or under-applied costs of the previous period(s).
(c) Where the costs incurred for a service are not material, they may be allocated as indirect costs.
(d) Under extraordinary circumstances, the cognizant agency for indirect costs and the recipient or subrecipient may negotiate and establish an alternative costing arrangement if it is in the Federal Government's best interest.
§ 200.469
Student activity costs.
Costs incurred for intramural activities, student publications, student clubs, and other student activities are unallowable unless expressly authorized in the Federal award.
§ 200.470
Taxes (including Value Added Tax).
(a) For States, local governments, and Indian Tribes. (1) Taxes that a governmental unit is legally required to pay are allowable, except for self-assessed taxes that disproportionately affect Federal programs or changes in tax policies that disproportionately affect Federal programs.
(2) Gasoline taxes, motor vehicle fees, and other taxes that are, in effect, user fees for benefits provided to the Federal Government are allowable.
(3) This provision does not restrict the authority of the Federal agency to identify taxes where Federal participation is inappropriate. The cognizant agency for indirect costs may accept a reasonable approximation in circumstances where determining the amount of unallowable taxes would require an excessive amount of effort.
(b) For nonprofit organizations and IHEs. (1) Taxes that the recipient or subrecipient is required to pay and which are paid or accrued in accordance with GAAP are generally allowable. These costs include payments made to local governments instead of taxes and that are commensurate with the local government services received. The following taxes are unallowable:
(i) Taxes for which exemptions are available to the recipient or subrecipient directly or which are available to the recipient or subrecipient based on an exemption afforded the Federal Government and, in the latter case, when the Federal agency makes available the necessary exemption certificates;
(ii) Special assessments on land which represent capital improvements; and
(iii) Federal income taxes.
(2) Any refund of taxes and interest thereon, which were allowed as Federal award costs, must be credited to the Federal Government as a cost reduction or cash refund, as appropriate. However, any interest paid or credited to a recipient or subrecipient incident to a refund of tax, interest, and penalty will be paid or credited to the Federal Government only to the extent that such interest accrued over the period during which the Federal Government has reimbursed the recipient or subrecipient for the taxes, interest, and penalties.
(c) Value Added Tax (VAT). Foreign taxes charged for procurement transactions that a recipient or subrecipient is legally required to pay in a country are allowable. Foreign tax refunds or applicable credits under Federal awards refer to receipts or reduction of expenditures, which operate to offset or reduce expense items that are allocable to Federal awards as direct or indirect costs. To the extent that such credits accrued or received by the recipient or subrecipient relate to allowable cost, these costs must be credited to the Federal agency as a cost reduction or cash refunds, as appropriate. In cases where the costs are credited back to the Federal award, the recipient or subrecipient may reduce the Federal share of costs by the amount of the foreign tax reimbursement, or where Federal award has not expired, the Federal agency may allow the recipient or subrecipient to use the foreign government tax refund for approved activities under the Federal award.
§ 200.471
Telecommunication and video surveillance costs.
(a) Costs incurred for telecommunications and video surveillance services or equipment such as phones, internet, video surveillance, and cloud servers are allowable except for the following circumstances:
(b) Obligating or expending covered telecommunications and video surveillance services or equipment or services as described in § 200.216 to:
(1) Procure or obtain, extend or renew a contract to procure or obtain;
(2) Enter into a contract (or extend or renew a contract) to procure; or
(3) Obtain the equipment, services, or systems.
§ 200.472
Termination and standard closeout costs.
(a) Termination Costs. Termination of a Federal award generally gives rise to the incurrence of costs or the need for special treatment of costs, which would not have arisen had the Federal award not been terminated. Cost principles covering these items are set forth in this section. They must be used in conjunction with the other termination requirements of this part.
(1) The cost of items reasonably usable on the recipient's or subrecipient's other work is unallowable unless the recipient or subrecipient submits evidence that it would not retain such items without sustaining a loss. In deciding whether such items are reasonably usable on other work of the recipient or subrecipient, the Federal agency or pass-through entity should consider the recipient's or subrecipient's plans and orders for current and scheduled activity. Contemporaneous purchases of common items by the recipient or subrecipient must be considered evidence that the items are reasonably usable on the recipient's or subrecipient's other work. Any acceptance of common items as allocable to the terminated portion of the Federal award must be limited to the extent that the quantities of such items on hand, in transit, and on order do not exceed the reasonable quantitative requirements of other work.
(2) If the recipient or subrecipient cannot discontinue certain costs immediately after the effective termination date, despite making all reasonable efforts, then the costs are generally allowable within the limitations of this part. Any costs continuing after termination due to the negligent or willful failure of the recipient or subrecipient to immediately discontinue the costs are unallowable.
(3) Loss of useful value of special tooling, machinery, and equipment is generally allowable if:
(i) Such special tooling, special machinery, or equipment is not reasonably capable of use in the other work of the recipient or subrecipient;
(ii) The interest of the Federal Government is protected by transfer of title or by other means deemed appropriate by the Federal agency (see § 200.313 (d)); and
(iii) The loss of useful value for any one terminated Federal award is limited to the portion of the acquisition cost which bears the same ratio to the total acquisition cost as the terminated portion of the Federal award bears to the entire terminated Federal award and other Federal awards for which the special tooling, machinery, or equipment was acquired.
(4) If paragraph (a)(4)(i) and (ii) below are satisfied, rental costs under unexpired leases (less the residual value of such leases) are generally allowable where clearly shown to have been reasonably necessary for the performance of the terminated Federal award. These rental costs may include the cost of alterations of the leased property and the cost of reasonable restoration required by the lease, provided the alterations were necessary for the performance of the Federal award.
(i) The amount of claimed rental costs does not exceed the reasonable use value of the property leased for the period of the Federal award and a further period as may be reasonable; and
(ii) The recipient or subrecipient makes all reasonable efforts to terminate, assign, settle, or otherwise reduce the cost of the lease.
(5) The following settlement expenses are generally allowable.
(i) Accounting, legal, clerical, and similar costs that are reasonably necessary for:
(A) The preparation and presentation to the Federal agency or pass-through entity of settlement claims and supporting data with respect to the terminated portion of the Federal award, unless the termination is for cause (see §§ 200.339-200.343); and
(B) The termination and settlement of subawards.
(ii) Reasonable costs for the storage, transportation, protection, and disposition of property provided by the Federal Government or acquired or produced for the Federal award.
(6) Claims under subawards, including the allocable portion of claims common to the Federal award and other work of the recipient or subrecipient, are generally allowable. An appropriate share of the recipient's or subrecipient's indirect costs may be allocated to the amount of settlements with contractors and subrecipients, provided that the amount allocated is consistent with the requirements of § 200.414. These allocated indirect costs must exclude the same and similar costs claimed directly or indirectly as settlement expenses.
(b) Closeout Costs. Administrative costs associated with the closeout activities of a Federal award are allowable. The recipient or subrecipient may charge the Federal award during the closeout for the necessary administrative costs of that Federal award (for example, salaries of personnel preparing final reports, publication and printing costs, costs associated with the disposition of equipment and property, and related indirect costs). These costs may be incurred until the due date of the final report(s). If incurred, these costs must be liquidated prior to the due date of the final report(s) and charged to the final budget period of the award unless otherwise specified by the Federal agency.
§ 200.473
Training and education costs.
The cost of training and education provided for employee development is allowable.
§ 200.474
Transportation costs.
Costs incurred for freight, express, cartage, postage, and other transportation services relating to goods purchased, in process, or delivered, are allowable. When the costs can be readily identified with the items involved, they may be charged directly as transportation costs or added to the cost of such items. When identification with the materials received cannot be readily made, the inbound transportation cost may be charged to the appropriate indirect cost accounts if the recipient or subrecipient follows a consistent, equitable procedure in this respect. If reimbursable under the terms and conditions of the Federal award, outbound freight should be treated as a direct cost.
§ 200.475
Travel costs.
(a) General. Travel costs include the transportation, lodging, subsistence, and related items incurred by employees who are in travel status on official business of the recipient or subrecipient. These costs may be charged on an actual cost basis, on a per diem or mileage basis, or on a combination of the two, provided the method used is applied to an entire trip and not to selected days of the trip. The method used must be consistent with those normally allowed in like circumstances in the recipient's or subrecipient's other activities and in accordance with the recipient's or subrecipient's established written policies. Notwithstanding the provisions of § 200.444, travel costs of officials covered by that section are allowable with the prior written approval of the Federal agency or pass-through entity when they are specifically related to the Federal award.
(b) Lodging and subsistence. Costs incurred by employees and officers for travel, including costs of lodging, other subsistence, and incidental expenses, must be considered reasonable and otherwise allowable only to the extent such costs do not exceed charges normally allowed by the recipient or subrecipient in its regular operations as the result of the recipient's or subrecipient's established written policy. In addition, if these costs are charged directly to the Federal award documentation must justify that:
(1) Participation of the individual is necessary for the Federal award; and
(2) The costs are reasonable and consistent with the recipient's or subrecipient's established written policy.
(c) Dependents. (1) Temporary dependent care costs (dependent is defined in 26 U.S.C. 152) above and beyond regular dependent care are allowable provided that these costs:
(i) Are a direct result of the individual's travel to a conference for the Federal award;
(ii) Are consistent with the recipient's or subrecipient's established written policy for all travel; and
(iii) Are only temporary during the travel period.
(2) Travel costs for dependents are unallowable, except for travel of six months or more with prior approval of the Federal agency. See § 200.432.
(d) Establishing rates and amounts. In the absence of an established written policy regarding travel costs, the rates and amounts established under 5 U.S.C. 5701-11 (“Travel and Subsistence Expenses; Mileage Allowances”), by the Administrator of General Services, or by the President (or their designee) pursuant to any provisions of such subchapter must apply to travel under Federal awards (48 CFR 31.205-46(a)).
(e) Commercial air travel. (1) Airfare costs in excess of the basic least expensive unrestricted accommodations class offered by commercial airlines are unallowable except when such accommodations would:
(i) Require circuitous routing;
(ii) Require travel during unreasonable hours;
(iii) Excessively prolong travel;
(iv) Result in additional costs that would offset the transportation savings; or
(v) Offer accommodations not reasonably adequate for the traveler's medical needs. The recipient or subrecipient must justify and document these conditions on a case-by-case basis for the use of first-class or business-class airfare to be allowable in such cases.
(2) Unless a pattern of avoidance is detected, the Federal Government will generally not question a recipient's or subrecipient's determinations that customary standard airfare or other discount airfare is unavailable for specific trips if the recipient or subrecipient can demonstrate that such airfare was not available in the specific case.
(f) Air travel by other than commercial carrier. Travel costs by recipient or subrecipient-owned, -leased, or -chartered aircraft include the cost of the lease, charter, operation (including personnel costs), maintenance, depreciation, insurance, and other related costs. The portion of these costs that exceeds the cost of airfare, as provided for in paragraph (d), is unallowable.
§ 200.476
Trustees.
Travel and subsistence costs of trustees (or directors) at IHEs and nonprofit organizations are allowable. See § 200.475.

Subpart F—Audit Requirements

General
§ 200.500
Purpose.
This part sets forth standards for obtaining consistency and uniformity among Federal agencies for the audit of non-Federal entities expending Federal awards.

Audits
§ 200.501
Audit requirements.
(a) Audit required. A non-Federal entity that expends $1,000,000 or more during the non-Federal entity's fiscal year in Federal awards must have a single or program-specific audit conducted for that year in accordance with the provisions of this part.
(b) Single audit. A non-Federal entity that expends $1,000,000 or more in Federal awards during the non-Federal entity's fiscal year must have a single audit conducted in accordance with § 200.514 except when it elects to have a program-specific audit conducted in accordance with paragraph (c) or (d) of this section.
(c) Program-specific audit election (in general). A non-Federal entity may elect to have a program-specific audit conducted in accordance with § 200.507 if the following conditions are met:
(1) The non-Federal entity expends Federal awards under only one Federal program (excluding research and development); and
(2) The Federal program's statutes or regulations, or terms and conditions of the Federal award, do not require a financial statement audit of the non-Federal entity.
(d) Program-specific audit election for research and development. A non-Federal entity may elect to have a program-specific audit for research and development conducted in accordance with § 200.507, but only if all of the following conditions are met:
(1) The non-Federal entity expends Federal awards only from the same Federal agency, or the same Federal agency and the same pass-through entity; and
(2) The Federal agency, or pass-through entity in the case of a subrecipient, approves a program-specific audit in advance.
(e) Exemption when Federal awards expended are less than $1,000,000. A non-Federal entity that expends less than $1,000,000 in Federal awards during its fiscal year is exempt from Federal audit requirements for that year, except as noted in § 200.503. However, in all instances, the records of the non-Federal entity must be available for review or audit by appropriate officials of the Federal agency, pass-through entity, and the Government Accountability Office (GAO).
(f) Federally Funded Research and Development Centers (FFRDC). Management of an auditee that owns or operates a FFRDC may elect to treat the FFRDC as a separate entity for purposes of this part.
(g) Subrecipients and contractors. An auditee may simultaneously be a recipient, a subrecipient, and a contractor. Unless a program is exempt by Federal statute, Federal awards expended as a recipient or a subrecipient are subject to audit under this part. Payments received for goods or services provided as a contractor under a Federal award (see § 200.331) are not subject to audit under this part.
(h) Compliance responsibility for contractors. In most cases, the auditee's compliance responsibility for contractors is to ensure that the procurement, receipt, and payment for goods and services comply with Federal statutes, regulations, and the terms and conditions of a Federal award. Federal award compliance requirements normally do not flow down to contractors. However, for procurement transactions in which the contractor is made responsible for meeting program requirements, the auditee must ensure those requirements are met, including by clearly stating the contractor's responsibilities within the contract and reviewing the contractor's records to determine compliance. Also, when these procurement transactions relate to a major program, the scope of the audit must include a determination of whether these transactions comply with Federal statutes, regulations, and the terms and conditions of a Federal award. See also § 200.318(b).
(i) For-profit subrecipient. This subpart does not apply to for-profit organizations. As necessary, the pass-through entity is responsible for establishing requirements to ensure compliance by for-profit subrecipients. The subaward with a for-profit subrecipient must describe applicable compliance requirements and the for-profit subrecipient's compliance responsibility. Methods to ensure compliance for Federal awards made to for-profit subrecipients may include pre-award audits, monitoring throughout the performance of the subaward, and post-award audits (see § 200.332).
§ 200.502
Basis for determining Federal awards expended.
(a) Determining Federal awards expended. The determination of when a Federal award is expended must be based on when the activity related to the Federal award occurs. Generally, the activity related to the Federal award pertains to events that require the non-Federal entity to comply with Federal statutes, regulations, and the terms and conditions of Federal awards, such as:
(1) Expenditure/expense transactions associated with grants, cooperative agreements, cost-reimbursement contracts under the FAR, compacts with Indian Tribes, and direct appropriations;
(2) The disbursement of funds to subrecipients;
(3) The use of loan proceeds under loan and loan guarantee programs;
(4) The receipt of property (including surplus property);
(5) The receipt or use of program income;
(6) The distribution or use of food commodities;
(7) The disbursement of amounts entitling the non-Federal entity to an interest subsidy; and
(8) The period when insurance is in force.
(b) Loan and loan guarantees (loans). The Federal Government is at risk for loans until the debt is repaid. Therefore, the following guidelines must be used to calculate the value of Federal awards expended under loan programs (except as noted in paragraphs (c) and (d)):
(1) The value of new loans made or received during the audit period; plus
(2) The balance of loans from previous years at the beginning of the audit period for which the Federal Government imposes continuing compliance requirements; plus
(3) Any interest subsidy, cash, or administrative cost allowance received.
(c) Loan and loan guarantees (loans) at Institutions of Higher Education (IHE). When loans are made to students of an IHE, but the IHE itself does not have continuing compliance requirements for the loans, then only the value of loans made during the audit period are considered Federal awards expended in that audit period. The balance of loans for previous audit periods is not included as Federal awards expended because the lender accounts for the prior balances.
(d) Prior loan and loan guarantees (loans). Loans, the proceeds of which were received and expended in prior years, are not considered Federal awards expended under this part when Federal statutes, regulations, and the terms and conditions of Federal awards pertaining to such loans impose no continuing compliance requirements other than to repay the loans.
(e) Endowment funds. The cumulative balance of Federal awards for endowment funds that are federally restricted is considered Federal awards expended in each audit period in which the funds are still restricted.
(f) Free rent. Free rent received by itself is not considered a Federal award expended under this part. However, free rent received as part of a Federal award to carry out a Federal program must be included in determining Federal awards expended and is subject to audit under this part.
(g) Valuing non-cash assistance. Federal non-cash assistance (such as free rent, food commodities, donated property, or donated surplus property that is received as part of a Federal award to carry out a Federal program) must be valued at fair market value at the time of receipt or the assessed value provided by the Federal agency and must be included in determining Federal awards expended under this part.
(h) Medicare. Medicare payments to a non-Federal entity for providing patient care services to Medicare-eligible individuals are not considered Federal awards expended under this part.
(i) Medicaid. Medicaid payments to a subrecipient for providing patient care services to Medicaid-eligible individuals are not considered Federal awards expended under this part unless a State requires the funds to be treated as Federal awards expended because reimbursement is on a cost-reimbursement basis.
(j) Certain loans provided by the National Credit Union Administration. For purposes of this part, loans from the National Credit Union Share Insurance Fund and the Central Liquidity Facility funded by contributions from insured non-Federal entities are not considered Federal awards expended.
§ 200.503
Relation to other audit requirements.
(a) Other financial audits. An audit conducted in accordance with this part must be in lieu of any financial audit of Federal awards which a non-Federal entity is required to undergo under any other Federal statute or regulation. To the extent that such an audit provides a Federal agency with the information it requires to carry out its responsibilities under Federal statute or regulation, a Federal agency must rely upon and use that information.
(b) Conducting additional audits. Notwithstanding paragraph (a) of this section, a Federal agency, Inspectors General, or GAO may conduct or arrange additional audits to carry out its responsibilities under Federal statute or regulation. The provisions of this part do not authorize any non-Federal entity to constrain, in any manner, such Federal agency from carrying out or arranging for such additional audits, except that the Federal agency must plan such audits not to be duplicative of other audits of Federal awards. Prior to commencing such an audit, the Federal agency or pass-through entity must review the FAC for recent audits submitted by the non-Federal entity, and to the extent such audits meet a Federal agency or pass-through entity's needs, the Federal agency or pass-through entity must rely upon and use such audits. Any additional audits must be planned and performed in such a way as to build upon work performed, including the audit documentation, sampling, and testing already performed by other auditors.
(c) Authority to conduct additional audits. The provisions of this part do not limit the authority of Federal agencies to conduct, or arrange for the conduct of, audits and evaluations of Federal awards, nor limit the authority of any Federal agency Inspector General or other Federal officials. For example, requirements that may be applicable under the FAR or CAS and the terms and conditions of a cost-reimbursement contract may include additional applicable audits to be conducted or arranged for by Federal agencies.
(d) Federal agency to pay for additional audits. A Federal agency that conducts or arranges for additional audits must, consistent with other applicable Federal statutes and regulations, arrange for funding the full cost of such additional audits.
(e) Request for a program to be audited as a major program. A Federal agency may request that an auditee have a particular Federal program audited as a major program in lieu of the Federal agency conducting or arranging for the additional audits. Such requests should be made at least 180 calendar days prior to the end of the fiscal year to be audited to allow for planning. After consultation with its auditor, the auditee should promptly respond to such a request by informing the Federal agency whether the program would otherwise be audited as a major program using the risk-based audit approach described in § 200.518 and, if not, the estimated incremental cost. The Federal agency must then promptly confirm to the auditee whether it wants the program audited as a major program. If the program is to be audited as a major program based upon this Federal agency request, and the Federal agency agrees to pay the full incremental costs, then the auditee must have the program audited as a major program. With approval of the Federal agency, a pass-through entity may use the provisions of this paragraph for a subrecipient.
§ 200.504
Frequency of audits.
Audits required by this part must be performed annually unless biennial audits are permitted under paragraph (a) or (b) of this section. Biennial audits must cover both fiscal years within the biennial period.
(a) A State, local government, or Indian Tribe that is required by constitution or statute, in effect on January 1, 1987, to undergo its audits less frequently than annually, is permitted to undergo biennial (every other year) audits pursuant to this part. This requirement must still be in effect for the biennial period.
(b) Any nonprofit organization that had biennial audits for all biennial periods ending between July 1, 1992, and January 1, 1995, is permitted to undergo biennial audits pursuant to this part.
§ 200.505
Remedies for audit noncompliance.
In cases of continued inability or unwillingness of a non-federal entity to have an audit conducted in accordance with this part, Federal agencies or pass-through entities must take appropriate action as provided in § 200.339.
§ 200.506
Audit costs.
See § 200.425.
§ 200.507
Program-specific audits.
(a) Program-specific audit guide available. In some cases, a program-specific audit guide will be available to provide specific guidance to the auditor concerning internal controls, compliance requirements, suggested audit procedures, and audit reporting requirements. A listing of current program-specific audit guides can be found in the compliance supplement (Appendix VI, Program-Specific Audit Guides). When a current program-specific audit guide is available, the auditor must follow Generally Accepted Government Auditing Standards (GAGAS) and the guide when performing a program-specific audit.
(b) Program-specific audit guide not available. (1) When a current program-specific audit guide is not available, the auditee and auditor must have basically the same responsibilities for the Federal program as they would have for an audit of a major program in a single audit.
(2) The auditee must prepare the financial statement(s) for the Federal program that includes a schedule of expenditures of Federal awards for the program and notes that describe the significant accounting policies used in preparing the schedule, a summary schedule of prior audit findings consistent with the requirements of § 200.511(b), and a corrective action plan consistent with the requirements of § 200.511(c).
(3) The auditor must:
(i) Perform an audit of the financial statement(s) for the Federal program in accordance with GAGAS;
(ii) Obtain an understanding of internal controls and perform tests of internal controls over the Federal program consistent with the requirements for a major program in accordance with§ 200.514(c);
(iii) Determine whether the auditee has complied with Federal statutes, regulations, and the terms and conditions of Federal awards that could have a direct and material effect on the Federal program consistent with the requirements for a major program under § 200.514(d);
(iv) Follow up on prior audit findings and perform procedures to assess the reasonableness of the summary schedule of prior audit findings prepared by the auditee in accordance with the requirements of § 200.511 When the auditor concludes that the summary schedule of prior audit findings materially misrepresents the status of any prior audit finding, the auditor must report this condition as a current-year audit finding.; and
(v) Report any audit findings consistent with the requirements of § 200.516.
(4) The auditor's report(s) may be in the form of either combined or separate reports. It may be organized differently from the manner presented in this section. The auditor's report(s) must state that the audit was conducted in accordance with this part and include the following:
(i) An opinion (or disclaimer of opinion) as to whether the financial statement(s) of the Federal program is presented fairly in all material respects in accordance with the stated accounting policies;
(ii) A report on internal control related to the Federal program, which must describe the scope of testing of internal control and the results of the tests;
(iii) A report on compliance that includes an opinion (or disclaimer of opinion) as to whether the auditee complied with laws, regulations, and the terms and conditions of Federal awards which could have a direct and material effect on the Federal program; and
(iv) A schedule of findings and questioned costs for the Federal program that includes a summary of the auditor's results relative to the Federal program in a format consistent with § 200.515(d)(1) and findings and questioned costs consistent with the requirements of § 200.515(d)(3).
(c) Report submission for program-specific audits. (1) Submission deadline and public availability. The audit must be completed and submitted in accordance with paragraph (c)(2) or (c)(3) of this section. Unless a different period is specified in the program-specific audit guide, the audit must be submitted within 30 calendar days after the auditee receives the auditor's report(s) or nine months after the end of the audit period (whichever is earlier). The submission is due the next business day when the due date falls on a Saturday, Sunday, or Federal holiday. Unless restricted by Federal law or regulation, the auditee must make copies of the reporting package available for public inspection. Auditees and auditors must ensure that their respective parts of the reporting package do not include protected personally identifiable information.
(2) Program-specific audit guide available. When a program-specific audit guide is available, the auditee must electronically submit the data collection form prepared in accordance with § 200.512(b), as applicable to the program-specific audit, to the Federal Audit Clearinghouse (FAC). The submission must also include the reporting required by the program-specific audit guide.
(3) Program-specific audit guide not available. When a program-specific audit guide is not available, the auditee must electronically submit the data collection form prepared in accordance with § 200.512(b) to the FAC. The submission must also include the financial statement(s) of the Federal program, summary schedule of prior audit findings, and corrective action plan as described in paragraph § 200.507(b)(2) and the auditor's report(s) described in paragraph § 200.507(b)(4).
(d) Other sections of this part may apply. Program-specific audits are subject to:
(1) 200.500 Purpose through 200.503 Relation to other audit requirements, paragraph (d);
(2) 200.504 Frequency of audits through 200.506 Audit costs;
(3) 200.508 Auditee responsibilities through 200.509 Auditor selection;
(4) 200.511 Audit findings follow-up;
(5) 200.512 Report submission, paragraphs (e) through (h);
(6) 200.513 Responsibilities;
(7) 200.516 Audit findings through 200.517 Audit documentation;
(8) 200.521 Management decision; and
(9) Other referenced provisions of this part unless contrary to the provisions of this section, a program-specific audit guide, or program statutes and regulations.

Auditees
§ 200.508
Auditee responsibilities.
The auditee must:
(a) Arrange for the audit required by this part in accordance with § 200.509, and ensure it is properly performed and submitted in accordance with § 200.512.
(b) Prepare financial statements, including the schedule of expenditures of Federal awards in accordance with § 200.510.
(c) Promptly follow up and take corrective action on audit findings. This includes preparing a summary schedule of prior audit findings and a corrective action plan in accordance with § 200.511(b) and (c), respectively.
(d) Provide the auditor access to personnel, accounts, books, records, supporting documentation, and any other information needed for the auditor to perform the audit required by this part.
§ 200.509
Auditor selection.
(a) Auditor procurement. When procuring audit services, the auditee must follow the procurement standards in §§ 200.317 through 200.327 of subpart D or the FAR (48 CFR part 42), as applicable. When requesting proposals for audit services, the objectives and scope of the audit must be made clear, and the non-Federal entity must request a copy of the audit organization's peer review report, which the auditor must provide under GAGAS. Factors to be considered in evaluating each proposal for audit services include the responsiveness to the request for proposal, relevant experience, availability of staff with professional qualifications and technical abilities, the results of peer and external quality control reviews, and price. Whenever possible, the auditee must make efforts to contract with businesses as stated in § 200.321 or the FAR (48 CFR part 42), as applicable.
(b) Restriction on auditor preparing indirect cost proposals. An auditor who prepares the indirect cost proposal or cost allocation plan may not be selected to perform the audit required by this part when the indirect costs recovered by the auditee during the prior year exceed $1 million. This restriction applies to the base year used to prepare the indirect cost proposal or cost allocation plan and any subsequent years in which the resulting indirect cost agreement or cost allocation plan is used to recover costs.
(c) Use of Federal auditors. Federal auditors may perform all or part of the work required under this part if they fully comply with the requirements of this part.
§ 200.510
Financial statements.
(a) Financial statements. The auditee must prepare financial statements that reflect its financial position, results of operations or changes in net assets, and, where appropriate, cash flows for the fiscal year audited. The financial statements must be for the same organizational unit and fiscal year chosen to meet this part's requirements. However, organization-wide financial statements of the non-Federal entity may also include departments, agencies, and other organizational units that have separate audits in accordance with § 200.514(a) and prepare separate financial statements.
(b) Schedule of expenditures of Federal awards. The auditee must also prepare a schedule of expenditures of Federal awards for the period covered by the auditee's financial statements. The schedule must include the total Federal awards expended as determined in accordance with § 200.502. The auditee may choose to provide information requested by Federal agencies or pass-through entities to make the schedule easier to use. For example, when a Federal program has multiple Federal award years, the auditee may separately list the amount of Federal awards expended for each year of a Federal award. The schedule must:
(1) List individual Federal programs by Federal agency using the applicable Assistance Listing number(s). For a cluster of programs, the non-Federal entity must provide the cluster name, a list of individual Federal programs within the cluster, and provide the Federal agency name and the applicable Assistance Listing number(s). For research and development, total Federal awards expended must be shown either by individual Federal award or by Federal agency and major subdivision within the Federal agency. For example, the National Institutes of Health is a major subdivision within the Department of Health and Human Services.
(2) For Federal awards received as a subrecipient, the name of the pass-through entity and identifying number assigned by the pass-through entity must be included.
(3) Provide total Federal awards expended for each individual Federal program and the Assistance Listings number or other identifying number when the Assistance Listings information is unavailable. For a cluster of programs, the auditee must also provide the total for the cluster.
(4) Include the total amount provided to subrecipients from each Federal program.
(5) For loan or loan guarantee programs described in § 200.502(b), identify in the notes to the schedule the balances outstanding at the end of the audit period. This requirement is in addition to including the total Federal awards expended for loan or loan guarantee programs in the schedule.
(6) Include notes describing the significant accounting policies used in preparing the schedule and whether the auditee elected to use the de minimis indirect cost rate of up to 15 percent (see § 200.414).
§ 200.511
Audit findings follow-up.
(a) General. The auditee is responsible for follow-up and corrective action on all audit findings. As part of this responsibility, the auditee must prepare a summary schedule of prior audit findings. The auditee must also prepare a corrective action plan for current year audit findings. The summary schedule of prior audit findings and the corrective action plan must include the reference numbers the auditor assigns to audit findings under § 200.516(c). Since the summary schedule may include audit findings from multiple years, it must include the fiscal year in which the finding initially occurred. The corrective action plan and summary schedule of prior audit findings must include financial statement findings that the auditor was required to report in accordance with GAGAS.
(b) Summary schedule of prior audit findings. The summary schedule of prior audit findings must report the status of all audit findings included in the prior audit's schedule of findings and questioned costs. The summary schedule must also include audit findings reported in the prior audit's summary schedule of prior audit findings except audit findings listed as corrected in accordance with paragraph (b)(1) of this section or no longer valid or not warranting further action in accordance with paragraph (b)(3) of this section.
(1) When audit findings were fully corrected, the summary schedule need only list the audit findings and state that corrective action was taken.
(2) When audit findings were not corrected or only partially corrected, the summary schedule must describe the reasons for the finding's recurrence, planned corrective action, and any partial corrective action taken. When the corrective action taken significantly differs from the corrective action previously reported in a corrective action plan or the Federal agency's or pass-through entity's management decision, the summary schedule must provide an explanation.
(3) When the auditee believes the audit findings are no longer valid or do not warrant further action, the reasons for this position must be described in the summary schedule. A valid reason for considering an audit finding as not warranting further action is that all of the following have occurred:
(i) Two years have passed since the audit report in which the finding occurred was submitted to the FAC;
(ii) The Federal agency or pass-through entity is not currently following up with the auditee on the audit finding; and
(iii) A management decision was not issued.
(c) Corrective action plan. At the completion of the audit, the auditee must prepare a corrective action plan to address each audit finding included in the auditor's report for the current year. The corrective action plan must be a document separate from the auditor's findings described in § 200.516. The corrective action plan must also provide the name(s) of the contact person(s) responsible for the corrective action, the corrective action to be taken, and the anticipated completion date. When the auditee does not agree with the audit findings or believes corrective action is not required, the corrective action plan must include a detailed explanation of the reasons.
§ 200.512
Report submission.
(a) General. (1) The audit, the data collection form, and the reporting package must be submitted within 30 calendar days after the auditee receives the auditor's report(s) or nine months after the end of the audit period (whichever is earlier). The cognizant agency for audit or oversight agency for audit (in the absence of a cognizant agency for audit) may authorize an extension when the nine-month timeframe would place an undue burden on the auditee. If the due date falls on a Saturday, Sunday, or Federal holiday, the reporting package is due the next business day.
(2) The auditee must make copies available for public inspection unless restricted by Federal statute or regulation. Auditees and auditors must ensure that their respective parts of the reporting package do not include protected personally identifiable information.
(b) Data collection. The FAC is the repository of record for subpart F reporting packages and the data collection form. All Federal agencies, pass-through entities and others interested in a reporting package and data collection form must obtain it by accessing the FAC.
(1) The auditee must submit the required data collection form described in Appendix X of this part. This form provides information about the auditee, its Federal programs, the results of the audit, and whether the audit was completed in accordance with this part. The form must include all information required by this part that is necessary for Federal agencies to use the audit to ensure the integrity of Federal programs. The form includes data elements and a format that OMB must approve, is available from the FAC, and include collections of information from the reporting package described in paragraph (c).
(2) A senior-level representative of the auditee (for example, a State controller, director of finance, chief executive officer, or chief financial officer) must sign a statement to be included as part of the data collection form stating that the auditee complied with the requirements of this part, including that:
(i) The data collection form was prepared in accordance with this part (and the instructions accompanying the form);
(ii) The reporting package does not include protected personally identifiable information;
(iii) The information included in its entirety is accurate and complete; and
(iv) The FAC is authorized to make the reporting package and the form publicly available on a website.
(3) An auditee that is an Indian Tribe or a tribal organization (as defined in the Indian Self-Determination, Education and Assistance Act (ISDEAA), 25 U.S.C. 450b(l)) may opt not to authorize the FAC to make the reporting package publicly available on a website. To opt-out, an Indian Tribe or tribal organization must exclude the authorization described in paragraph (b)(2)(iv) of this section. In these instances, the Indian Tribe is responsible for submitting the reporting package directly to any pass-through entities through which it has received a Federal award and to pass-through entities for which the summary schedule of prior audit findings reported the status of any findings related to those Federal awards that the pass-through entity provided. Unless restricted by Federal statute or regulation, if the Indian Tribe opts not to authorize publication, it must make copies of the reporting package available for public inspection.
(4) The auditor must complete the applicable data elements of the data collection form using the information included in the reporting package described in paragraph (c) of this section. The auditor must sign a statement to be included as part of the data collection form stating:
(i) The source of information included in the data collection form;
(ii) The auditor's responsibility for the information;
(iii) The data collection form is not a substitute for the reporting package described in paragraph (c); and
(iv) The content of the form is limited to the collection of information prescribed by OMB.
(c) Reporting package. The reporting package must include the following:
(1) Financial statements and schedule of expenditures of Federal awards discussed in § 200.510(a) and (b), respectively;
(2) Summary schedule of prior audit findings discussed in § 200.511(b);
(3) Auditor's report(s) discussed in § 200.515; and
(4) Corrective action plan discussed in § 200.511(c).
(d) Submission to FAC. The auditee must electronically submit the data collection form described in paragraph (b) of this section and the reporting package described in paragraph (c) of this section to the FAC.
(e) Requests for management letters issued by the auditor. Auditees must submit, when requested by a Federal agency or pass-through entity, a copy of any management letters issued by the auditor.
(f) Report retention requirements. Auditees must keep a copy of the data collection form described in paragraph (b) of this section and a copy of the reporting package described in paragraph (c) on file for three years from the date of submission to the FAC. Copies of audit records must be maintained in accordance with § 200.336.
(g) FAC responsibilities. The FAC must make available the reporting packages received in accordance with paragraph (c) of this section and § 200.507(c) to the public, except for Indian Tribes exercising the option in paragraph (b)(3) of this section, and maintain a database of completed audits, provide appropriate information to Federal agencies, and follow up with known auditees that have not submitted the required data collection forms and reporting packages.
(h) Electronic filing. Nothing in this part must preclude electronic submissions to the FAC in such a manner as may be approved by OMB.

Federal Agencies
§ 200.513
Responsibilities.
(a) Cognizant agency for audit responsibilities. (1) A non-Federal entity expending more than $50 million a year in Federal awards must have a cognizant agency for audit. The cognizant agency for audit must be the Federal agency that provides the largest amount of direct funding (as listed on the non-Federal entity's Schedule of expenditures of Federal awards, see § 200.510(b)) unless OMB designates a specific cognizant agency for audit. When the direct funding represents less than 25 percent of the total expenditures (as direct and subawards) by the non-Federal entity, then the Federal agency with the predominant amount of total funding is the designated cognizant agency for audit.
(2) To provide for continuity of cognizance, the determination of the predominant amount of direct funding must be based upon direct Federal awards expended in the non-Federal entity's fiscal years ending in 2019 and every fifth year after that.
(3) Notwithstanding how audit cognizance is determined, a Federal agency may reassign cognizance to another Federal agency that provides substantial funding to an auditee if it agrees to be the cognizant agency for audit. Within 30 calendar days after any reassignment, both the old and the new cognizant agency for audit must notify the FAC, the auditee, and the auditor (if known) of the change.
(4) The cognizant agency for audit must:
(i) Provide technical audit advice and liaison assistance to auditees and auditors.
(ii) Obtain or conduct quality control reviews on selected audits made by non-Federal auditors and provide the results to other interested organizations.
(iii) Cooperate and support the Federal agency designated by OMB to lead a government-wide analysis to assess the quality of single audits. The government-wide analysis may rely on the current and ongoing quality control review work performed by Federal agencies, State auditors, and professional audit associations. This government-wide audit analysis must be performed at an interval determined by OMB, and the results must be posted publicly. In providing support to the government-wide analysis, a Federal agency must provide the following:
(A) An assessment of the extent to which single audits conform to the requirements, standards, and procedures of this part; and
(B) Recommendations to address audit quality issues, including recommendations for any changes to this part's requirements, standards, and procedures.
(iv) Promptly inform the appropriate Federal law enforcement officials and impacted Federal agencies of any direct reporting by the auditee or its auditor required by GAGAS, Federal statute, or regulation.
(v) Advise the community of independent auditors of any noteworthy or important factual trends related to the quality of audits stemming from quality control reviews. Significant problems or quality issues consistently identified through quality control reviews of audit reports must be referred to appropriate State licensing agencies and professional bodies.
(vi) Advise the auditor, Federal awarding agencies, and, where appropriate, the auditee of any deficiencies found in the audits when the deficiencies require corrective action by the auditor. When advised of deficiencies, the auditee must work with the auditor to take corrective action. If corrective action is not taken, the cognizant agency for audit must notify the auditor, the auditee, and applicable Federal awarding agencies and pass-through entities of the facts and make recommendations for follow-up action. Major inadequacies or repetitive substandard performance by auditors must be referred to appropriate State licensing agencies and professional bodies for disciplinary action.
(vii) Coordinate, to the extent practical, audits or reviews made by or for Federal agencies that are in addition to the audits made pursuant to this part, so that the additional audits or reviews build upon, rather than duplicate, audits performed in accordance with this part.
(viii) Coordinate a management decision for cross-cutting audit findings that affect the Federal programs of more than one agency when requested by any Federal agency whose awards are included in the audit finding of the auditee. Cross-cutting audit finding means an audit finding where the same underlying condition or issue affects all Federal awards (including Federal awards of more than one Federal agency or pass-through entity); for example, a cross-cutting audit finding may include an issue related to the recipient's accounting system.
(ix) Coordinate the audit work and reporting responsibilities among auditors to achieve the most cost-effective audit.
(x) Provide advice to auditees as to how to handle changes in fiscal year.
(b) Oversight agency for audit responsibilities. An auditee who does not have a designated cognizant agency for audit will be under the general oversight of the Federal agency determined in accordance with § 200.1 oversight agency for audit. A Federal agency with oversight for an auditee may reassign oversight to another Federal agency that agrees to be the oversight agency for audit. Within 30 calendar days after any reassignment, both the old and the new oversight agency for audit must provide notice of the change to the FAC, the auditee, and, if known, the auditor. The oversight agency for audit:
(1) Must provide technical advice and assistance to auditees and auditors.
(2) May assume all or some of the responsibilities normally performed by a cognizant agency for audit.
(c) Awarding Federal agency responsibilities. In addition to all other requirements of this part, the awarding Federal agency must:
(1) Ensure that audits are completed, and reports are received in a timely manner in accordance with the requirements of this part.
(2) Provide technical advice and assistance to auditees and auditors.
(3) Follow-up on audit findings to ensure that non-Federal entities take appropriate and timely corrective action. Follow-up includes:
(i) Issuing a management decision in accordance with § 200.521;
(ii) Monitoring the non-Federal entity's progress implementing a corrective action;
(iii) Using a cooperative audit resolution approach to improve Federal program outcomes through better audit resolution, follow-up, and corrective action, which means the use of audit follow-up techniques promoting prompt corrective action by improving communication, fostering collaboration, promoting trust, and developing an understanding between the Federal agency and the non-Federal entity. This approach is based upon:
(A) A strong commitment by Federal agency and non-Federal entity leadership to Federal program integrity;
(B) Federal agencies strengthening partnerships and working cooperatively with non-Federal entities and their auditors; non-Federal entities and their auditors working cooperatively with Federal agencies;
(C) A focus on current conditions and corrective action going forward;
(D) Federal agencies offering appropriate relief for past noncompliance when audits show prompt corrective action has occurred; and
(E) Federal agency leadership sending a clear message that continued failure to correct conditions identified by audits likely to cause improper payments, fraud, waste, or abuse is unacceptable and will result in sanctions.
(iv) Tracking the effectiveness of the Federal agency's follow-up processes, the effectiveness of single audits in improving non-Federal entity accountability, and the use of single audits in making Federal award decisions. The Federal agency should develop a baseline, metrics, and targets to track, over time, the effectiveness of the Federal agency's process to follow up on audit findings.
(4) Provide OMB with annual updates to the compliance supplement. These updates include working with OMB to ensure that the compliance supplement focuses the auditor on testing the compliance requirements most likely to cause improper payments, fraud, waste, abuse, or generate audit findings for which the Federal agency will take action in accordance with § 200.505. Prior to submitting compliance supplement drafts to OMB, Federal agencies should engage with external audit stakeholders, the Federal agency's Office of Inspector General, and the National Single Audit Coordinator (NSAC).
(5) Provide OMB with the name of a single audit accountable official from among the senior policy officials of the Federal agency. The accountable official must be:
(i) Responsible for ensuring that the Federal agency fulfills the requirements of this section and effectively uses the single audit process to reduce improper payments and improve Federal program outcomes.
(ii) Accountable for improving the effectiveness of the Federal agency's single audit processes in accordance with paragraph (c)(3)(iv).
(iii) Responsible for designating the Federal agency's key management single audit liaison.
(6) Provide OMB with the name of a key management single audit liaison. The liaison must:
(i) Serve as the Federal agency's point of contact for the single audit process within and outside the Federal Government.
(ii) Promote interagency coordination, consistency, and information sharing. This includes coordinating audit follow-up, identifying higher risk non-Federal entities, providing input on single audit and follow-up policy, enhancing the utility of the FAC, and identifying ways to use single audit results to improve Federal award accountability and best practices.
(iii) Oversee training for the Federal agency's program management personnel related to the single audit process.
(iv) Promote the Federal agency's use of a cooperative audit resolution approach as described in paragraph (c)(3)(iii) of this section.
(v) Coordinate the Federal agency's audit follow-up processes and ensure non-Federal entities implement corrective actions for audit findings.
(vi) Ensure the Federal agency fulfills its responsibility, as a cognizant agency for audit, to coordinate a management decision for cross-cutting audit findings under (a)(4)(viii) of this section. Cross-cutting audit findings means an audit finding where the same underlying condition or issue affects all Federal awards (including Federal awards of more than one Federal agency or pass-through entity). For example, this may include an issue related to the recipient's accounting system.
(vii) Ensure the Federal agency provides OMB with annual updates to the compliance supplement consistent with the compliance supplement preparation guide.
(viii) Support the mission of the Federal agency's single audit accountable official and coordinate with the Federal agency's Office of Inspector General and National Single Audit Coordinator (NSAC).

Auditors
§ 200.514
Standards and scope of audit.
(a) General. The audit must be conducted in accordance with GAGAS. The audit must also cover the entire operations of the auditee, or, at the option of the auditee, such audit must include a series of audits that cover departments, agencies, and other organizational units that expended or otherwise administered Federal awards during the audit period. In these instances, the audit must include the financial statements and schedule of expenditures of Federal awards for each such department, agency, and other organizational unit, which must be considered to be a non-Federal entity. The financial statements and schedule of expenditures of Federal awards must be for the same audit period.
(b) Financial statements. The auditor must determine whether the auditee's financial statements are presented fairly in all material respects in accordance with generally accepted accounting principles (or a special purpose framework such as cash, modified cash, or regulatory as required by State law). The auditor must also determine whether the schedule of expenditures of Federal awards is stated fairly in all material respects in relation to the auditee's financial statements as a whole.
(c) Internal control. (1) The compliance supplement provides guidance on internal controls over Federal programs based upon the guidance in Standards for Internal Control in the Federal Government issued by the Comptroller General of the United States and the Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
(2) In addition to the requirements of GAGAS, the auditor must perform procedures to obtain an understanding of internal control over Federal programs sufficient to plan the audit to support a low assessed level of control risk of noncompliance for major programs.
(3) Except as provided in paragraph (c)(4) of this section, the auditor must:
(i) Plan the testing of internal control over compliance for major programs to support a low assessed level of control risk for assertions relevant to the compliance requirements for each major program; and
(ii) Perform testing of internal control as planned in paragraph (c)(3)(i) of this section.
(4) When internal control over some or all of the compliance requirements for a major program are likely to be ineffective in preventing or detecting noncompliance, the planning and performing of testing described in paragraph (c)(3) of this section are not required for those compliance requirements. However, the auditor must report a significant deficiency or material weakness in accordance with § 200.516, assess the related control risk at the maximum, and consider whether additional compliance tests are required because of ineffective internal control.
(d) Compliance. (1) In addition to the requirements of GAGAS, the auditor must determine whether the auditee has complied with Federal statutes, regulations, and the terms and conditions of Federal awards that may have a direct and material effect on each of its major programs.
(2) The principal compliance requirements applicable to most Federal programs and the compliance requirements of the largest Federal programs are included in the compliance supplement.
(3) For the compliance requirements related to Federal programs contained in the compliance supplement, an audit of these compliance requirements will meet the requirements of this part. Where there have been changes to the compliance requirements, and the changes are not reflected in the compliance supplement, the auditor must determine the current compliance requirements and modify the audit procedures accordingly. For those Federal programs not covered in the compliance supplement, the auditor must follow the compliance supplement's guidance for programs not included.
(4) The compliance testing must include tests of transactions or other auditing procedures necessary to provide the auditor with sufficient appropriate audit evidence to support an opinion on compliance.
(e) Audit follow-up. The auditor must follow up on prior audit findings regardless of whether a prior audit finding is related to a major program in the current year. Audit follow-up includes performing procedures to assess the reasonableness of the summary schedule of prior audit findings prepared by the auditee in accordance with the requirements of § 200.511. When the auditor concludes that the summary schedule of prior audit findings materially misrepresents the status of any prior audit finding, the auditor must report this condition as a current-year audit finding.
(f) Data collection form. As required in § 200.512(b)(4), the auditor must complete and sign specified sections of the data collection form.
§ 200.515
Audit reporting.
The auditor's report(s) may be in the form of either combined or separate reports. It may be organized differently from the manner presented in this section. The auditor's report(s) must state that the audit was conducted in accordance with this part and include the following:
(a) An opinion (or disclaimer of opinion) on whether the financial statement(s) of the auditee is presented fairly in all material respects in accordance with generally accepted accounting principles (or a special purpose framework such as cash, modified cash, or regulatory as required by State law). The auditor must also decide whether the schedule of expenditures of Federal awards is stated fairly in all material respects in relation to the auditee's financial statements as a whole.
(b) A report on internal control over financial reporting and compliance with provisions of laws, regulations, contracts, and award agreements, noncompliance with which could have a material effect on the financial statements. This report must describe the scope of internal control and compliance testing and the results of the tests. Where applicable, the report must refer to the separate schedule of findings and questioned costs described in paragraph (d) of this section.
(c) A report on compliance for each major program and a report on internal control over compliance. This report must describe the scope of testing of internal control over compliance and include an opinion (or disclaimer of opinion) as to whether the auditee complied with Federal statutes, regulations, and the terms and conditions of Federal awards that could have a direct and material effect on each major program and refer to the separate schedule of findings and questioned costs described in paragraph (d) of this section.
(d) A schedule of findings and questioned costs which must include the following three components:
(1) A summary of the auditor's results, which must include:
(i) The type of report the auditor issued (unmodified opinion, qualified opinion, adverse opinion, or disclaimer of opinion) on whether the audited financial statements were prepared in accordance with GAAP;
(ii) A statement about whether significant deficiencies or material weaknesses in internal control were disclosed by the audit of the financial statements;
(iii) A statement as to whether the audit disclosed any noncompliance that is material to the financial statements of the auditee;
(iv) A statement about whether significant deficiencies or material weaknesses in internal control over major programs were disclosed by the audit;
(v) The type of report the auditor issued (unmodified opinion, qualified opinion, adverse opinion, or disclaimer of opinion) on compliance for major programs;
(vi) A statement as to whether the audit disclosed any audit findings that the auditor is required to report under § 200.516(a);
(vii) An identification of major programs by listing each individual major program; however, in the case of a cluster of programs, only the cluster name as shown on the schedule of expenditures of Federal Awards is required; (viii) The dollar threshold used to distinguish between Type A and Type B programs, as described in § 200.518(b)(1) or (3) when a recalculation of the Type A threshold is required for large loan or loan guarantees; and
(ix) A statement as to whether the auditee qualified as a low-risk auditee under§ 200.520.
(2) Findings relating to the financial statements required to be reported in accordance with GAGAS.
(3) Findings and questioned costs for Federal awards which must include audit findings as defined in § 200.516(a) and be reported in the following manner:
(i) Audit findings (for example, internal control findings, compliance findings, questioned costs, or fraud) that relate to the same issue must be presented as a single audit finding. Where practical, audit findings should be organized by Federal agency or pass-through entity.
(ii) Audit findings that relate to both the financial statements (paragraph (d)(2) of this section) and Federal awards (this paragraph (d)(3)) must be reported in both sections of the schedule. However, the reporting in one section of the schedule may be in summary form and reference a detailed reporting in the other section.
(e) Nothing in this part precludes combining the reporting required by this section with the reporting required by § 200.512(b) when allowed by GAGAS and Appendix X of this part.
§ 200.516
Audit findings.
(a) Audit findings reported. The auditor must report the following as an audit finding in the schedule of findings and questioned costs:
(1) Significant deficiencies and material weaknesses in internal control over major programs. The auditor's determination of whether a deficiency in internal control is a significant deficiency or a material weakness for the purpose of reporting an audit finding is in relation to a type of compliance requirement for a major program identified in the compliance supplement.
(2) Material noncompliance with the provisions of Federal statutes, regulations, or the terms and conditions of Federal awards related to a major program. The auditor's determination of whether noncompliance with the provisions of Federal statutes, regulations, or the terms and conditions of Federal awards is material for the purpose of reporting an audit finding is in relation to a type of compliance requirement for a major program identified in the compliance supplement.
(3) Known questioned costs when either known or likely questioned costs are greater than $25,000 for a type of compliance requirement for a major program. When reporting questioned costs, the auditor must include information to provide proper perspective for evaluating the prevalence and consequences of the questioned costs.
(4) Known questioned costs greater than $25,000 for a Federal program that is not audited as a major program. Except for audit follow-up, the auditor is not required to perform audit procedures for such a Federal program; therefore, the auditor will normally not find questioned costs for a program that is not audited as a major program. However, if the auditor does become aware of questioned costs for a Federal program that is not audited as a major program (for example, as part of audit follow-up or other audit procedures) and the known questioned costs are greater than $25,000, the auditor must report this as an audit finding.
(5) The circumstances concerning why the auditor's report on compliance for each major program is other than an unmodified opinion. This must be included unless the circumstances are otherwise reported as audit findings in the schedule of findings and questioned costs.
(6) Known or likely fraud affecting a Federal award, unless the fraud is otherwise reported as an audit finding in the schedule of findings and questioned costs. This paragraph does not require the auditor to publicly report information that could compromise investigative or legal proceedings or to make an additional reporting when the auditor confirms that the fraud was reported outside the auditor's reports under the direct reporting requirements of GAGAS.
(7) Instances where the results of audit follow-up procedures disclosed that the summary schedule of prior audit findings prepared by the auditee in accordance with § 200.511(b) materially misrepresents the status of any prior audit finding.
(b) Audit finding detail and clarity. Audit findings must be presented with sufficient detail and clarity for the auditee to prepare a corrective action plan and take corrective action and for Federal agencies or pass-through entities to arrive at a management decision. As applicable, the following information must be included in audit findings:
(1) The Federal program and specific Federal award identification, including the Assistance Listings title and number, Federal award identification number and year, the name of the Federal agency, and name of the applicable pass-through entity. When information, such as the Assistance Listings title and number or Federal award identification number, is unavailable, the auditor must provide the best information available to describe the Federal award.
(2) The criteria or specific requirement for the audit finding (for example, the specific Federal statute, regulation, or term and condition of the Federal award). The criteria or specific requirement provides a context for evaluating evidence and understanding findings. The criteria should generally identify the required or desired state or expectation with respect to the program or operation.
(3) The condition found, including facts that support the deficiency identified in the audit finding.
(4) A statement of cause that identifies the reason or explanation for the condition or the factors responsible for the difference between the situation that exists (condition) and the required or desired state (criteria), which may also serve as a basis for recommendations for corrective action
(5) The possible asserted effect to provide sufficient information to the auditee and Federal agency or pass-through entity to permit them to determine the cause and effect to facilitate prompt and proper corrective action. A statement of the effect or potential effect should provide a clear, logical link to establish the impact or potential impact of the difference between the condition and the criteria.
(6) The identification of known questioned costs, by applicable Assistance Listing number(s) and Federal award identification number(s), and how these questioned costs were computed.
(7) When there are known questioned costs but the dollar amount is undetermined or not reported, a description of why the dollar amount was undetermined or otherwise could not be reported.
(8) Information to provide proper perspective for evaluating the prevalence and consequences of the audit finding. For example, whether the audit finding represents an isolated instance or a systemic problem. Where appropriate, instances identified must be related to the universe and the number of cases examined and be quantified in terms of dollar value. In addition, the audit finding should indicate whether the sampling was a statistically valid sample.
(9) The identification of whether the audit finding is a repeat of a finding in the immediately prior audit. The audit finding must identify the applicable prior year audit finding reference numbers in these instances.
(10) Recommendations to prevent future occurrences of the deficiency identified in the audit finding.
(11) Views of responsible officials of the auditee.
(c) Reference numbers. Each audit finding in the schedule of findings and questioned costs must include a reference number in the format meeting the requirements of the data collection form submission (see § 200.512(b)).
§ 200.517
Audit documentation.
(a) Retention of audit documentation. The auditor must retain audit documentation and reports for a minimum of three years after the date of issuance of the auditor's report(s) to the auditee. The cognizant agency for audit, oversight agency for audit, cognizant agency for indirect costs, or pass-through entity may extend the retention period by providing written notification to the auditor. When the auditor is aware that the Federal agency, pass-through entity, or auditee is contesting an audit finding, the auditor must contact the parties contesting the audit finding for guidance prior to the destruction of the audit documentation and reports.
(b) Access to audit documentation. Audit documentation must be made available upon request to the cognizant or oversight agency for audit or its designee, cognizant agency for indirect cost, a Federal agency, or GAO at the completion of the audit, as part of a quality review, to resolve audit findings, or to carry out oversight responsibilities consistent with the purposes of this part. Access to audit documentation includes the right of Federal agencies to obtain copies of audit documentation as is reasonable and necessary.
§ 200.518
Major program determination.
(a) General. The auditor must use a risk-based approach to determine which Federal programs are major programs. This risk-based approach must consider current and prior audit experience, oversight by Federal agencies and pass-through entities, and the inherent risk of the Federal program. The process described in paragraphs (b) through (h) of this section must be followed.
(b) Step one. (1) The auditor must identify and label the larger Federal programs as Type A programs. Type A programs are defined as Federal programs with Federal awards expended during the audit period exceeding the levels outlined in table 1:
Table 1 to Paragraph ( b )(1)
Total Federal awards expended | Type A threshold
Equal to or exceed $1,000,000 but less than or equal to $34 million | $1,000,000.
Exceed $34 million but less than or equal to $100 million | Total Federal awards expended times .03.
Exceed $100 million but less than or equal to $1 billion | $3 million.
Exceed $1 billion but less than or equal to $10 billion | Total Federal awards expended times .003.
Exceed $10 billion but less than or equal to $20 billion | $30 million.
Exceed $20 billion | Total Federal awards expended times .0015.
(2) Federal programs not labeled Type A under paragraph (b)(1) of this section must be labeled Type B programs.
(3) Including large loans and loan guarantees (loans) must not result in the exclusion of other programs as Type A programs. A Federal program providing loans is considered a large loan program when it exceeds four times the largest non-loan program. The auditor must identify each large loan program as a Type A program and exclude its values in determining other Type A programs. This recalculation of the Type A program is performed after removing the total of all large loan programs. For this paragraph, a program is only considered a Federal program providing loans if the value of Federal awards expended for loans within the program comprises 50 percent or more of the total Federal awards expended for the program. A cluster of programs is treated as one program, and the value of Federal awards expended under a loan program is determined as described in § 200.502.
(4) For biennial audits (see § 200.504), the determination of Type A and Type B programs must be based on the Federal awards expended during the two-year audit period.
(c) Step two. (1) The auditor must identify Type A programs that are low-risk. In making this determination, the auditor must consider whether the requirements in § 200.519(c), the results of audit follow-up, or any changes in personnel or systems affecting the program indicate significantly increased risk and preclude the program from being low-risk. For a Type A program to be considered low-risk, it must have been audited as a major program in at least one of the two most recent audit periods (in the most recent audit period in the case of a biennial audit), and, in the most recent audit period, the program must not have had:
(i) Internal control deficiencies that were identified as material weaknesses in the auditor's report on internal control for major programs as required under § 200.515(c);
(ii) A modified opinion on the program in the auditor's report on major programs as required under § 200.515(c); or
(iii) Known or likely questioned costs that exceed five percent of the total Federal awards expended for the program.
(2) Notwithstanding paragraph (c)(1) of this section, OMB may approve a Federal agency request that a Type A program not be considered low-risk for a specific recipient. For example, it may be necessary for a large Type A program to be audited as a major program each year for a particular recipient for the Federal agency to comply with 31 U.S.C. 3515. The Federal agency must notify the auditee and, if known, the auditor of OMB's approval at least 180 calendar days prior to the end of the fiscal year to be audited.
(d) Step three. (1) The auditor must identify high-risk Type B programs using professional judgment and the criteria in § 200.519. However, the auditor is not required to identify more high-risk Type B programs than at least one-fourth of the number of low-risk Type A programs identified as low-risk under step two. Except for known material weakness in internal control or compliance problems as discussed in § 200.519(b)(1), (2), and (c)(1), a single criterion in risk would rarely cause a Type B program to be considered high-risk. When identifying which Type B programs to assess for risk, the auditor is encouraged to use an approach that provides an opportunity for different high-risk Type B programs to be audited as major programs over a period of time.
(2) The auditor is not expected to perform risk assessments on relatively small Federal programs. Therefore, the auditor is only required to perform risk assessments on Type B programs that exceed 25 percent (0.25) of the Type A threshold determined in step one.
(e) Step four. At a minimum, the auditor must audit all of the following as major programs:
(1) All Type A programs not identified as low-risk under step two.
(2) All Type B programs identified as high-risk under step three.
(3) Additional programs as necessary to comply with the percentage of coverage rule described in paragraph (f). This rule may require the auditor to audit more programs as major programs than the number of Type A programs.
(f) Percentage of coverage rule. When the auditee meets the criteria in § 200.520, the auditor only needs to audit the major programs identified in paragraphs (e)(1) and (2) of this section and such additional Federal programs with Federal awards expended that, in the aggregate, all major programs encompass at least 20 percent (0.20) of total Federal awards expended. Otherwise, the auditor must audit the major programs identified in paragraphs (e)(1) and (2) of this section and such additional Federal programs with Federal awards expended that, in the aggregate, all major programs encompass at least 40 percent (0.40) of total Federal awards expended.
(g) Documentation of risk. The auditor must include in the audit documentation the risk analysis used for determining major programs.
(h) Auditor's judgment. The auditor's judgment in applying the risk-based approach to determine major programs must be presumed correct when the determination was performed and documented in accordance with this part. Challenges by a Federal agency or pass-through entity must only be for clearly improper use of the requirements in this part. However, a Federal agency or pass-through entity may provide auditors guidance about the risk of a particular Federal program. The auditor must consider this guidance in determining major programs in audits not yet completed.
§ 200.519
Criteria for Federal program risk.
(a) General. The auditor's determination should be based on an overall evaluation of the risk of noncompliance occurring that could be material to the Federal program. The auditor must consider criteria, such as those described in paragraphs (b), (c), and (d) of this section, to identify risk in Federal programs. Also, as part of the risk analysis, the auditor may wish to discuss a particular Federal program with auditee management and the Federal agency or pass-through entity.
(b) Current and prior audit experience. (1) Weaknesses in internal control over Federal programs would indicate higher risk. Therefore, consideration should be given to the control environment over Federal programs. This includes considering factors such as the expectation of management's adherence to Federal statutes, regulations, and the terms and conditions of Federal awards, and the competence and experience of personnel who administer the Federal programs.
(i) A Federal program administered under multiple internal control structures may have higher risk. When assessing risk in a large single audit, the auditor must consider whether weaknesses are isolated in a single operating unit (for example, one college campus) or pervasive throughout the entity.
(ii) A weak system for monitoring subrecipients would indicate higher risk when significant parts of a Federal program are passed to subrecipients through subawards.
(2) Prior audit findings would indicate higher risk, especially when the situations identified in the audit findings could significantly impact a Federal program or have not been corrected.
(3) Federal programs not recently audited as major programs may be of higher risk than those recently audited as major programs without audit findings.
(c) Oversight exercised by Federal agencies and pass-through entities. (1) The oversight exercised by Federal agencies or pass-through entities may be used to assess risk. For example, recent monitoring or other reviews performed by an oversight entity that disclosed no significant problems would indicate lower risk, whereas monitoring that disclosed significant problems would indicate higher risk.
(2) With the concurrence of OMB, a Federal agency may identify Federal programs that are higher risk. OMB will identify these Federal programs in the compliance supplement.
(d) Inherent risk of the Federal program. (1) The nature of a Federal program may indicate risk. Consideration should be given to the complexity of the program and the extent to which the Federal program contracts for goods and services. For example, Federal programs that disburse funds through third-party contracts or have eligibility criteria may be higher risk. Federal programs primarily involving staff payroll costs may be at high risk for noncompliance with the requirements of § 200.430 but otherwise be at low risk.
(2) The phase of a Federal program in its lifecycle at the Federal agency may indicate risk. For example, a new Federal program with new or interim regulations may have higher risk than an established program with time-tested regulations. Also, significant changes in Federal programs, statutes, regulations, or the terms and conditions of Federal awards may increase risk.
(3) The phase of a Federal program in its lifecycle at the auditee may indicate risk. For example, during the first and last years that an auditee participates in a Federal program, the risk may be higher due to the start-up or closeout of program activities and staff.
(4) Type B programs with larger Federal awards expended would be of higher risk than programs with substantially smaller Federal awards expended.
§ 200.520
Criteria for a low-risk auditee.
An auditee that meets all of the following conditions for each of the preceding two audit periods must qualify as a low-risk auditee and be eligible for reduced audit coverage in accordance with § 200.518.
(a) Single audits were performed on an annual basis in accordance with the provisions of this subpart, including submitting the data collection form and the reporting package to the FAC within the timeframe specified in § 200.512. A non-Federal entity that has biennial audits does not qualify as a low-risk auditee.
(b) The auditor's opinion on whether the financial statements were prepared in accordance with generally accepted accounting principles (or a special purpose framework such as cash, modified cash, or regulatory as required by State law), and the auditor's in-relation-to opinion on the schedule of expenditures of Federal awards were unmodified.
(c) No internal control deficiencies were identified as material weaknesses under the requirements of GAGAS.
(d) The auditor did not report a substantial doubt about the auditee's ability to continue as a going concern.
(e) None of the Federal programs had audit findings from any of the following in either of the preceding two audit periods in which they were classified as Type A programs:
(1) Internal control deficiencies that were identified as material weaknesses in the auditor's report on internal control for major programs as required under § 200.515(c);
(2) A modified opinion on a major program in the auditor's report on major programs as required under § 200.515(c); or
(3) Known or likely questioned costs that exceeded five percent (.05) of the total Federal awards expended for a Type A program during the audit period.

Management Decisions
§ 200.521
Management decisions.
(a) General. The management decision must clearly state whether or not the audit finding is sustained, the reasons for the decision, and the expected auditee action to repay disallowed costs, make financial adjustments or take other action. If the auditee has not completed corrective action, a timetable for follow-up should be given. Prior to issuing the management decision, the Federal agency or pass-through entity may request additional information or documentation from the auditee, including a request for auditor assurance related to the documentation, as a way of mitigating disallowed costs. The management decision should describe any appeal process available to the auditee. While not required, the Federal agency or pass-through entity may also issue a management decision on findings relating to the financial statements, which are required to be reported in accordance with GAGAS.
(b) Federal agency. The cognizant agency for audit is responsible for coordinating a management decision for audit findings that affect the programs of more than one Federal agency (see § 200.513(a)(4)(viii)). The awarding Federal agency is responsible for issuing a management decision for audit findings that affect the Federal awards it makes to a non-Federal entity (see § 200.513(c)(3)(i)).
(c) Pass-through entity. The pass-through entity is responsible for issuing a management decision for audit findings that affect subawards it issues to subrecipients under a Federal award (see § 200.332(e)).
(d) Time requirements. The Federal agency or pass-through entity responsible for issuing a management decision must do so within six months of the FAC's acceptance of the audit report. The auditee must initiate and proceed with corrective action as rapidly as possible and corrective action should begin no later than upon receipt of the audit report.
(e) Reference numbers. Management decisions must include the reference numbers the auditor assigned to each audit finding in accordance with § 200.516(c).
15. Revise appendix I to part 200 to read as follows:

Appendix I to Part 200—Full Text of Notice of Funding Opportunity
(a) General Requirements.
(1) Requirements for developing NOFOs. In developing a notice of funding opportunity (NOFO), Federal agencies must:
(i) Be concise and use plain language per the guidance at PlainLanguage.gov wherever possible.
(ii) For electronic NOFOs and other information about them, comply with Section 508 of the Rehabilitation Act of 1973 (29 U.S.C. 794d).
(2) Considerations for developing NOFOs. Federal agencies may:
(i) Link to standard content to include required information rather than including the full language in the NOFO. The NOFO should make clear if linked information is critical—for example, standard terms and conditions, administrative and national policy requirements, and standard templates.
(ii) Include links to relevant regulations and other sources.
(iii) Use cross-references between the sections, including hyperlinks in electronic versions.
(3) Required Consistency. Potential applicants must be able to find similar information across all Federal NOFOs. To that end, Federal agencies must include the same or similar section headings and a table of contents with at least these sections:
(i) Basic Information
(ii) Eligibility
(iii) Program Description
(iv) Application Contents and Format
(v) Submission Requirements and Deadlines
(vi) Application Review Information
(vii) Award Notices
(viii) Post-Award Requirements and Administration
(b) Required Sections and Information.
As required below, the Federal agency must include the following sections and information in the text of a NOFO and a table of contents.
(1) Basic Information.
This section provides sufficient information to help an applicant make an informed decision about whether to submit a proposal.
(i) This section must include the following:
(A) Federal Agency Name.
(B) Funding Opportunity Title.
(C)I Announcement Type (whether the funding opportunity is the initial announcement or a modification of a previously announced opportunity).
(D) Funding Opportunity Number (required, if the Federal agency has assigned a number to the funding opportunity announcement).
(E) Assistance Listing Number(s).
(F) Funding Details. The total amount of funding that the Federal agency expects to award, the anticipated number of awards, and the expected dollar values of individual awards, which may be a range.
(G) Key Dates. Key dates include due dates for submitting applications or Executive Order 12372 submissions, as well as for any letters of intent or preapplications. For any announcement issued before a program's application materials are available, key dates also include the date on which those materials will be released; and any other additional information, as deemed applicable by the Federal agency. If possible, the Federal agency should provide an anticipated award date. If the NOFO is evaluated on a “rolling” basis, the Federal agency should provide an estimate of the time needed to process an application and notify the applicant of the Federal agency's decision.
(H) Executive Summary. A brief description that is written in plain language and summarizes the goals and objectives of the program, the target audience, and eligible recipients. The text of the executive summary should not exceed 500 words
(I) Agency contact information.
(ii) This section could include the following:
(A) The amount of funding per Federal award, on average, experienced in previous years.
(B) Whether this is a new program or a one-time initiative.
(2) Eligibility.
This section addresses the factors that determine applicant or application eligibility.
(i) Eligible Applicants. This subsection must identify the following:
(A) A complete and specific list of entity types eligible to apply.
(B) Any additional restrictions on eligibility beyond the type of entity.
(C) Eligibility factors for the principal investigator or project director, if any.
(D) Criteria that would make any particular projects ineligible.
(E) A reference to any funding restriction elsewhere in the NOFO that could affect an applicant's or project's eligibility.
(F) A reference or link to any other factors that would disqualify an applicant or application, such as the responsiveness criteria in 6a.
(G) Any limit on the number of applications an applicant may submit under the announcement. Make clear whether the limitation is on the submitting organization, individual investigator or program director, or both.
(ii) Cost Sharing. This subsection must state:
(A) Whether there is required cost sharing. This statement must be clear that not committing to the required cost sharing will make the application ineligible. If cost sharing is not required, the announcement must say so.
(B) An explanation of the calculation for the required cost sharing. Required cost sharing may be a certain percentage or amount or in the form of contributions of specified items or activities ( for example, provision of equipment).
(C) Any restrictions on the types of cost, such as in-kind contributions, acceptable as cost sharing.
(D) Any requirement to commit to cost sharing. This section should refer to the appropriate portions of section (b)(4) stating any pre-award requirements for the submission of letters or other documentation to verify commitments to meet cost-sharing requirements if a Federal award is made.
(3) Program Description. This section contains the full program description of the funding opportunity.
(i) This section must include the following:
(A) The general purpose of the funding and what it is expected to achieve for the public good.
(B) The Federal agency's funding priorities or focus areas, if any.
(C) Program goals and objectives.
(D) A description of how the award will contribute to achieving the program's goals and objectives.
(E) The expected performance goals, indicators, targets, baseline data, data collection, and other outcomes the Federal agency expects recipients to achieve.
(F) For cooperative agreements, the “substantial involvement” that the Federal agency expects to have or should reference where the potential applicant can find that information.
(G) Information on program specific unallowable costs so that the applicant can develop an application and budget consistent with program requirements and any limits on indirect costs.
(H) Any eligibility criteria for beneficiaries or program participants other than Federal award recipients.
(I) Citations for authorizing statutes and regulations for the funding opportunity.
(ii) This section could also include the following:
(A) Any program history, such as whether it is a new program or a new or changed area of program emphasis.
(B) Examples of successful projects funded in the past.
(C) For infrastructure projects subject to Build America, Buy America requirements, information on key items anticipated to be purchased under the program, and any related domestic sourcing concerns based on market research.
(D) Other information the Federal agency finds necessary.
(4) Application Contents and Format. This section must identify the required content of an application and the forms or formats an applicant must use. If any requirements are stated elsewhere, this section should refer to where those requirements may be found. This section also should include required forms or formats as part of the announcement or state where the applicant may obtain them.
(i) This section must specifically address content and form or format requirements for:
(A) Whether pre-applications, letters of intent, or white papers are required or encouraged.
(B) The application as a whole.
(C) Component pieces of the application.
(D) Information that successful applicants must submit after notification of intent to make a Federal award but prior to a Federal award. For example, this could include evidence of compliance with requirements relating to human subjects or information needed to comply with the National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et seq. ).
(ii) Within each of the categories above, this subsection must include, where relevant:
(A) Limitations on page numbers.
(B) Formatting requirements, including font and font size, margins, paper size, and color limitations.
(C) Any requirements for file naming, file size limitations, or file format such as PDF.
(D) The number of copies required if paper submissions are allowed.
(E) The sequence required for application sections or components.
(F) Signature requirements, including those for electronic submissions.
(G) Any requirements for third-party information such as references, letters of support, or letters of commitment to the project or to contribute to cost sharing.
(H) A reference to any requirements to provide documentation to support an eligibility determination, such as proof of 501(c)(3) status or an authorizing tribal resolution.
(I) Instructions needed to develop the narrative portions of the application. Include any requirements for its order, format, or required headings.
(J) If applicable, the need to identify proprietary information. Include how to do so and how the Federal agency will handle it.
(5) Submission Requirements and Deadlines.
(i) Address to Request Application Package. This section must include the following:
(A) How to get application forms, kits, or other materials needed to apply. If the announcement contains everything needed, this section needs only say so. If not, the guidance must include:
(1) An internet address where the materials can be accessed.
(2) An email address.
(3) A U.S. Postal Service mailing address.
(4) Telephone number.
(5) Telephone Device for the Deaf (TDD), Text Telephone (TTY) number, or other appropriate telecommunication relay service.
(ii) Unique entity identifier and System for Award Management (SAM.gov). This section must state the requirements for unique entity identifiers and registration in SAM.gov . It must include the following:
(A) Each applicant must:
(1) Be registered in SAM.gov before submitting its application;
(2) Provide a valid unique entity identifier in its application; and
(3) Continue to maintain an active registration in SAM.gov with current information at all times during which it has an active Federal award or an application or plan under consideration by a Federal agency.
(B) If individuals are eligible to apply, they are exempt from this requirement under 2 CFR 25.110(b).
(C) If the Federal agency exempts any applicants from this requirement under 2 CFR 25.110(c) or (d), a statement to that effect.
(iii) Submission Instructions. This section addresses how the applicant will submit the application. It must include the following:
(A) Actions needed prior to applying:
(1) Instructions on any registrations required to access electronic submission systems or links to them. Where possible, provide the expected time frames needed to complete the registration process.
(B) The methods for submitting the application:
(1) Whether the applicant must submit in electronic or paper form or whether the applicant has an option. Applicants should not be required to submit in more than one format.
(2) Instructions on how to submit electronically or links to them. Must include the URL to the electronic submission system and information on or links to information about the system or software requirements needed by the system.
(3) If the Federal agency allows paper submissions, the process used to approve this option if it is not automatically allowed.
(4) If the Federal agency allows paper submissions, the method for submitting the application. This information must include a postal address and “care of” information needed to route the application to the appropriate person, office, or email address, if the Federal agency allows such submissions.
(C) If applicable, this section also must say how applicants must submit pre-applications, letters of intent, third-party information, or other information required before the award. It must include the following:
(1) Instructions on how to submit electronically or links to them.
(2) Whether the applicant must submit in electronic or paper form or whether the applicant has an option.
(3) If the Federal agency allows paper submissions, the method for submitting the required information. This information must include a postal address and “care of” information needed to route the application to the appropriate person, office, or email address.
(D) This section must also include what to do in the event of system problems and a point of contact who will be available if the applicant experiences technical difficulties.
(iv) Submission Dates and Times. This section must include due dates and times for all submissions. If they are different for electronic and paper submissions, be clear about the differences. This includes the following:
(A) Full applications.
(B) Any preliminary submissions, such as letters of intent, white papers, or pre-applications.
(C) Any other submissions required before Federal award separate from the full application.
(D) If the funding opportunity is a general announcement that is open for a period of time with no specific due dates for applications, this section should say so.
(v) Intergovernmental Review. This section must include the following:
(A) Whether or not the funding opportunity is subject to Executive Order 12372, “Intergovernmental Review of Federal Programs”.
(B) If it is applicable, include the following:
(1) A short description of this requirement.
(2) Where applicants can find their State's Single Point of Contact, learn whether their State has an intergovernmental review process, and if so, get information on their State's process. The list of SPOCs is on the Office of Management and Budget's website.
(6) Application Review Information.
(i) Responsiveness Review. This section includes information on the criteria that make an application or project ineligible. These are sometimes referred to as “responsiveness” criteria, “go-no-go” criteria, or “threshold” criteria. Federal agencies may change the title of this section as appropriate. This section must include the following:
(A) A brief understanding of the Federal agency responsiveness review process.
(B) A list and enough detail to understand the criteria or disqualifying factors to be reviewed.
(C) A reference to the regulation or requirement that describes the restriction, if applicable. For example, if entities that have been found to be in violation of a particular Federal statute are ineligible, say so.
(ii) Review Criteria. This section must address the review criteria that the Federal agency will use to evaluate applications for merit. This information includes the merit and other review criteria evaluators will use to judge applications, including any statutory, regulatory, or other preferences that will be applied in the review process. These criteria are distinct from eligibility criteria that are addressed before an application is accepted for review and any program policy or other factors that are applied during the selection process, after the review process is completed.
The intent is to make the application process transparent so applicants can make informed decisions when preparing their applications to maximize the fairness of the process.
(A) This section must include the following:
(1) A clear description of each criterion and sub-criterion used.
(2) If criteria vary in importance, the relative percentages, weights, or other means used to distinguish between them.
(3) For statutory, regulatory, or other preferences, an explanation of those preferences with an explicit indication of their effect, for example, if they result in additional points being assigned.
(4) How an applicant's proposed cost sharing will be considered in the review process if it is not an eligibility criterion in Section 2b. For example, to assign a certain number of additional points to applicants who offer cost sharing or to break ties among applications with equivalent scores after evaluation against all other factors. If cost sharing will not be considered in the evaluation, the announcement should say so. Do not include statements that cost sharing is encouraged without providing clarity about what that means.
(5) The relevant information if the Federal agency permits applicants to nominate reviewers of their applications or suggest those they feel may be inappropriate due to a conflict of interest.
(B) This section could include the following:
(1) The types of people responsible for evaluation against the merit criteria. For example, peers external to the Federal agency or Federal agency personnel.
(2) The number of people on an evaluation panel and how it operates, how reviewers are selected, reviewer qualifications, and how conflicts of interest are avoided.
(iii) Review and Selection Process. This section may vary in the level of detail provided.
(A) It must include the following:
(1) Any program policy, factors, or elements that the selecting official may use in selecting applications for the award. For example, geographical dispersion, program balance, or diversity.
(2) A brief description of the merit review process, including how the Federal agency uses merit review outcomes in final decision-making. For example, whether they are advisory only.
(B) It could also include the following:
(1) Who makes the final selections for awards.
(2) Any multi-phase review methods. For example, an external panel that advises on, makes, or approves final recommendations to the deciding official.
(iv) Risk Review.
(A) This section must include the following:
(1) A brief description of the factors used for the Federal agency's risk review as required by § 200.206.
(2) If the Federal agency expects that any award under the NOFO will be more than the simplified acquisition threshold during its period of performance, include the following information:
(i) That before making a Federal award with a total amount of Federal share greater than the simplified acquisition threshold, the Federal agency must review and consider any information about the applicant that is in the responsibility/qualification records available in SAM.gov (see 41 U.S.C. 2313).
(ii) That an applicant can review and comment on any information in the responsibility/qualification records available in SAM.gov .
(iii) That before making decisions in the risk review required by § 200.206 the Federal agency will consider any comments by the applicant, along with information available in the responsibility/qualification records in SAM.gov .
(7) Award Notices. This section must address what a successful applicant can expect to receive following selection.
(i) It must include the following:
(A) If the Federal agency's practice is to provide a separate notice stating that an application has been selected before it makes the Federal award, indicate that the letter is not an authorization to begin performance and that the Federal award is the authorizing document.
(B) If pre-award costs are allowed, beginning performance is at the applicant's own risk.
(C) This section should indicate that the notice of Federal award signed by the grants officer, or equivalent, is the official document that obligates funds, and whether it is provided through postal mail or by electronic means and to whom.
(D) The timing, form, and content of notifications to unsuccessful applicants. See also § 200.211.
(8) Post-Award Requirements and Administration.
(i) Administrative and National Policy Requirements. Providing information on administrative and policy requirements lets a potential applicant identify any requirements with which it would have difficulty complying. This section must include the following:
(A) A statement related to the “general” terms and conditions of the award, including requirements that the Federal agency normally includes.
(B) Any relevant specific terms and conditions.
(C) Any special requirements that could apply to specific awards after the review of applications and other information based on the particular circumstances of the effort to be supported. For example, if human subjects were to be involved or if some situations may justify specific terms on intellectual property, data sharing, or security requirements.
(D) As in other sections, the announcement need not include all terms and conditions of the award but may refer to documents with details on terms and conditions.
(ii) Reporting. This section includes information needed to understand the post-award reporting requirements. Highlight any special reporting requirements for Federal awards under this funding opportunity that differ from what the Federal agency's Federal awards usually require. For example, differences in report type, frequency, form, format, or circumstances for use. This section must include the following:
(A) The type of reporting required, such as financial or performance.
(B) The reporting frequency.
(C) The means of submission, such as paper or electronic.
(D) References to all relevant requirements, such as those at 2 CFR 180.335 and 180.350.
(E) If the Federal share of any Federal award may include more than $500,000 over the period of performance, this section must inform potential applicants about the post-award reporting requirements reflected in appendix XII to this part.
(9) Other Information—Optional. This section may include any additional information to help potential applicants. For example, the section could include the following:
(i) Related programs or other upcoming or ongoing Federal agency funding opportunities for similar activities.
(ii) Current internet addresses for Federal agency websites that may be useful to an applicant in understanding the program.
(iii) Routine notices to applicants. For example, the Federal Government is not obligated to make any Federal award as a result of the announcement, or only grants officers can bind the Federal Government to the expenditure of funds.
13. Amend appendix III to part 200 by revising the heading of section A.1. and paragraph C.2 to read as follows:

Appendix III to Part 200—Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Institutions of Higher Education (IHEs)
* * * * *

A. General
* * * * *

1. Major Functions/Activities of an IHE
* * * * *

C. Determination and Application of Indirect (F&A) Cost Rate or Rates
* * * * *

2. The Distribution Basis
Indirect (F&A) costs must be distributed to applicable Federal awards and other benefitting activities within each major function (see section A.1) on the basis of modified total direct costs (MTDC), consisting of all salaries and wages, fringe benefits, materials and supplies, services, travel, and up to the first $50,000 of each subaward (regardless of the period covered by the subaward). MTDC is defined in § 200.1. For this purpose, an indirect (F&A) cost rate should be determined for each of the separate indirect (F&A) cost pools developed pursuant to subsection 1. The rate in each case should be stated as the percentage which the amount of the particular indirect (F&A) cost pool is of the modified total direct costs identified with such pool.
16. Amend appendix IV to part 200 by revising paragraphs B.2.c. and B.4.a.iii to read as follows:

Appendix IV to Part 200—Indirect (F&A) Costs Identification and Assignment, and Rate Determination for Nonprofit Organizations
* * * * *

B. Allocation of Indirect Costs and Determination of Indirect Cost Rates
* * * * *
2. * * *
c. The distribution base may be total direct costs (excluding capital expenditures and other distorting items, such as subawards for $50,000 or more), direct salaries and wages, or other base which results in an equitable distribution. The distribution base must exclude participant support costs as defined in § 200.1.
* * * * *
4. * * *
a. * * *
(iii) other direct functions (including projects performed under Federal awards). Joint costs, such as depreciation, rental costs, operation and maintenance of facilities, telephone expenses, information technology, and the like are prorated individually as direct costs to each category and to each Federal award or other activity using a base most appropriate to the particular cost being prorated.
17. Amend appendix VII to part 200 by revising and republishing paragraphs C.2.c.(1), C.3.e.(1), and D.1 to read as follows:

C. Allocation of Indirect Costs and Determination of Indirect Cost Rates
* * * * *
2. * * *
c. The distribution base may be (1) total direct costs (excluding capital expenditures and other distorting items, such as pass-through funds, subcontracts in excess of $50,000, and participant support costs), (2) direct salaries and wages, or (3) another base which results in an equitable distribution.
* * * * *
3. * * *
e. The distribution base used in computing the indirect cost rate for each function may be (1) total direct costs (excluding capital expenditures and other distorting items such as pass-through funds, subawards in excess of $50,000, and participant support costs), (2) direct salaries and wages, or (3) another base which results in an equitable distribution. An indirect cost rate should be developed for each separate indirect cost pool developed. The rate in each case should be stated as the percentage relationship between the particular indirect cost pool and the distribution base identified with that pool.
* * * * *

D. Submission and Documentation of Proposals
* * * * *

1. Submission of Indirect Cost Rate Proposals
a. All departments or agencies of the governmental unit desiring to claim indirect costs under Federal awards must prepare an indirect cost rate proposal and related documentation to support those costs. The proposal and related documentation must be retained for audit in accordance with the records retention requirements contained in § 200.334.
b. A governmental department or agency (such as a state or local Department of Health, Department of Transportation, or Department of Housing) that receives more than $35 million in direct Federal funding during its fiscal year must submit its indirect cost rate proposal to its cognizant agency for indirect costs.
c. If a governmental department or agency (such as a state or local Department of Health, Department of Transportation, or Department of Housing) receives $35 million or less in direct Federal funding during its fiscal year, it must develop an indirect cost proposal in accordance with the requirements of this part and maintain the proposal and related supporting documentation for audit. This established rate must be accepted by any Federal agency to which the governmental department or agency applies for funding. Federal agencies must not compel the governmental department or agency to accept the de minimis rate or some other rate established by the Federal agency. These governmental departments or agencies are not required to submit their proposals unless they are specifically requested to do so by an awarding Federal agency. The Federal agency's review should be limited to ensuring the proposal is consistent with the principles of this part. Where a non-Federal entity only receives funds as a subrecipient, the pass-through entity will be responsible for negotiating and/or monitoring the subrecipient's indirect costs.
c. Each Indian tribal government desiring reimbursement of indirect costs must submit its indirect cost proposal to the Department of the Interior (its cognizant agency for indirect costs).
d. Indirect cost proposals must be developed (and, when required, submitted) within six months after the close of the governmental unit's fiscal year, unless an exception is approved by the cognizant agency for indirect costs. If the proposed central service cost allocation plan for the same period has not been approved by that time, the indirect cost proposal may be prepared including an amount for central services that is based on the latest federally approved central service cost allocation plan. The difference between these central service amounts and the amounts ultimately approved will be compensated for by an adjustment in a subsequent period.
* * * * *
18. Revise appendix X to part 200 to read as follows:

Appendix X to Part 200—Data Collection Form
The data collection form is available as a series of workbooks on the Federal Audit Clearinghouse ( FAC.gov ). The form and submission instructions can be found at https://www.fac.gov/.
19. Revise appendix XII to part 200 to read as follows:

Appendix XII to Part 200—Award Term and Condition for Recipient Integrity and Performance Matters

I. Reporting of Matters Related to Recipient Integrity and Performance

(a) General Reporting Requirement.
(1) If the total value of your active grants, cooperative agreements, and procurement contracts from all Federal agencies exceeds $10,000,000 for any period of time during the period of performance of this Federal award, then you as the recipient must ensure the information available in the responsibility/qualification records through the System for Award Management ( SAM.gov ), about civil, criminal, or administrative proceedings described in paragraph (b) of this award term is current and complete. This is a statutory requirement under section 872 of Public Law 110-417, as amended (41 U.S.C. 2313). As required by section 3010 of Public Law 111-212, all information posted in responsibility/qualification records in SAM.gov on or after April 15, 2011 (except past performance reviews required for Federal procurement contracts) will be publicly available.
(b) Proceedings About Which You Must Report.
(1) You must submit the required information about each proceeding that—
(i) Is in connection with the award or performance of a grant, cooperative agreement, or procurement contract from the Federal Government;
(ii) Reached its final disposition during the most recent five-year period; and
(iii) Is one of the following—
(A) A criminal proceeding that resulted in a conviction;
(B) A civil proceeding that resulted in a finding of fault and liability and payment of a monetary fine, penalty, reimbursement, restitution, or damages of $5,000 or more;
(C) An administrative proceeding that resulted in a finding of fault and liability and your payment of either a monetary fine or penalty of $5,000 or more or reimbursement, restitution, or damages in excess of $100,000; or
(D) Any other criminal, civil, or administrative proceeding if—
( 1 ) It could have led to an outcome described in paragraph (b)(1)(iii)(A) through (C);
( 2 ) It had a different disposition arrived at by consent or compromise with an acknowledgment of fault on your part; and
( 3 ) The requirement in this award term to disclose information about the proceeding does not conflict with applicable laws and regulations.
(c) Reporting Procedures. Enter the required information in SAM.gov for each proceeding described in paragraph (b) of this award term. You do not need to submit the information a second time under grants and cooperative agreements that you received if you already provided the information in SAM.gov because you were required to do so under Federal procurement contracts that you were awarded.
(d) Reporting Frequency. During any period of time when you are subject to the requirement in paragraph (a) of this award term, you must report proceedings information in SAM.gov for the most recent five-year period, either to report new information about a proceeding that you have not reported previously or affirm that there is no new information to report. If you have Federal contract, grant, and cooperative agreement awards with a cumulative total value greater than $10,000,000, you must disclose semiannually any information about the criminal, civil, and administrative proceedings.
(e) Definitions. For purposes of this award term—
Administrative proceeding means a non-judicial process that is adjudicatory in nature to make a determination of fault or liability (for example, Securities and Exchange Commission Administrative proceedings, Civilian Board of Contract Appeals proceedings, and Armed Services Board of Contract Appeals proceedings). This includes proceedings at the Federal and State level but only in connection with the performance of a Federal contract or grant. It does not include audits, site visits, corrective plans, or inspection of deliverables.
Conviction means a judgment or conviction of a criminal offense by any court of competent jurisdiction, whether entered upon a verdict or a plea, and includes a conviction entered upon a plea of nolo contendere.
Total value of currently active grants, cooperative agreements, and procurement contracts includes the value of the Federal share already received plus any anticipated Federal share under those awards (such as continuation funding).

II. [Reserved]
Deidre A. Harrison,

Deputy Controller, performing the delegated duties of the Controller Office of Federal Financial Management.
89
78
Monday, April 22, 2024
Rules and Regulations
Part V
Department of Defense
General Services Administration
National Aeronautics and Space Administration
48 CFR Chapter 1

Federal Acquisition Regulation: Federal Acquisition Circular 2024-05; Introduction; Summary of Final Rules
DEPARTMENT OF DEFENSE
GENERAL SERVICES ADMINISTRATION
NATIONAL AERONAUTICS AND SPACE ADMINISTRATION
48 CFR Chapter 1
[Docket No. FAR-2024-0051, Sequence No. 3]
Federal Acquisition Regulation; Federal Acquisition Circular 2024-05; Introduction

AGENCY:
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

ACTION:
Summary presentation of final rules.

SUMMARY:
This document summarizes the Federal Acquisition Regulation (FAR) rules agreed to by the Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (Councils) in this Federal Acquisition Circular (FAC) 2024-05. A companion document, the Small Entity Compliance Guide (SECG), follows this FAC.

DATES:
For effective dates see the separate documents, which follow.

FOR FURTHER INFORMATION CONTACT:
The analyst whose name appears in the table below in relation to the FAR case. For information pertaining to status or publication schedules, contact the Regulatory Secretariat Division at 202-501-4755 or GSARegSec@gsa.gov.
Rules Listed in FAC 2024-05
Item | Subject | FAR case | Analyst
I | Sustainable Procurement | 2022-006 | Hawes.
II | Technical Amendments

ADDRESSES:
The FAC, including the SECG, is available at https://www.regulations.gov.

SUPPLEMENTARY INFORMATION:
Summaries for each FAR rule follow. For the actual revisions and/or amendments made by these FAR rules, refer to the specific item numbers and subjects set forth in the documents following these item summaries. FAC 2024-05 amends the FAR as follows:

Item I—Sustainable Procurement (FAR Case 2022-006)
This final rule amends the Federal Acquisition Regulation (FAR) to restructure and update FAR part 23 to focus on current environmental and sustainability matters and to implement a requirement for agencies to procure sustainable products and services to the maximum extent practicable. As a result of this rule, content related to sustainable products and services, energy savings performance contracts, hazardous and radioactive materials, pollution prevention at Federal facilities, and greenhouse gases are consolidated into single subparts at FAR subpart 23.1, 23.2, 23.3, 23.4, and 23.5, respectively. Non-environmental matters, to include requirements for a drug-free workplace and encouraging contractors to ban texting while driving, are moved to FAR part 26. The existing statutory and other Environmental Protection Agency (EPA) purchasing program requirements (previously implemented in FAR subparts 23.2, 23.4, 23.7, and 23.8) are consolidated in FAR subpart 23.1. This rule will require agencies to specify in the statement of work, or elsewhere in the contract, the sustainable products and services, including the purchasing programs and types of products or services, that are applicable to the acquisition. A new omnibus contract clause at FAR 52.223-23, Sustainable Products and Services, will require contractors to ensure the sustainable products and services identified in the contract are delivered, incorporated, or furnished under the contract. The rule also updates agency requirements for construction and architect-engineer contracts at FAR 36.104(b)(1) to align with the Council on Environmental Quality's Guiding Principles for Federal Leadership in High-Performance and Sustainable Buildings. The final rule may have a significant economic impact on a substantial number of small entities who compete on Federal contracts. These entities will need to ensure that they are offering and delivering sustainable products and services, as specified in agency solicitations and contracts.

Item II—Technical Amendments
An administrative change is made at FAR 1.106, 1.401, 4.1702, 5.704, 8.402, 8.404, 8.405-1, 8.405-2, 8.405-3, 8.405-6, 16.505, 19.305, 19.507, 28.203-1, 31.205-40, 39.000, and 52.212-3.
William F. Clark,
Director, Office of Government-wide Acquisition Policy, Office of Acquisition Policy, Office of Government-wide Policy.
Federal Acquisition Circular (FAC) 2024-05 is issued under the authority of the Secretary of Defense, the Administrator of General Services, and the Administrator of National Aeronautics and Space Administration.
Unless otherwise specified, all Federal Acquisition Regulation (FAR) and other directive material contained in FAC 2024-05 is effective April 22, 2024 except for Items I and II, which are effective May 22, 2024.
John M. Tenaglia,

Principal Director, Defense Pricing and Contracting, Department of Defense.
Jeffrey A. Koses,

Senior Procurement Executive/Deputy CAO, Office of Acquisition Policy, U.S. General Services Administration.
Karla Smith Jackson,

Assistant Administrator for Procurement, Senior Procurement Executive/Deputy CAO, National Aeronautics and Space Administration.
89
78
Monday, April 22, 2024
Rules and Regulations
Part VI
Department of Defense
General Services Administration
National Aeronautics and Space Administration
48 CFR Parts 1, 2, 4, 5, 7, 9, 10, 11, 12, 13, 15, 18, 23, 26, 36, 37, 39, 42, and 52

Federal Acquisition Regulation: Sustainable Procurement; Final Rule
DEPARTMENT OF DEFENSE
GENERAL SERVICES ADMINISTRATION
NATIONAL AERONAUTICS AND SPACE ADMINISTRATION
48 CFR Parts 1, 2, 4, 5, 7, 9, 10, 11, 12, 13, 15, 18, 23, 26, 36, 37, 39, 42, and 52
[FAC 2024-05; FAR Case 2022-006, Item 1; Docket No. FAR-2022-0006, Sequence No. 1]
RIN 9000-AO43
Federal Acquisition Regulation: Sustainable Procurement

AGENCY:
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

ACTION:
Final rule.

SUMMARY:
DoD, GSA, and NASA are issuing a final rule amending the Federal Acquisition Regulation (FAR) to restructure and update the regulations to focus on current environmental and sustainability matters and to implement a requirement for agencies to procure sustainable products and services to the maximum extent practicable.

DATES:
Effective: May 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Ms. Jennifer Hawes, Procurement Analyst, at 202-255-9194 or by email at jennifer.hawes@gsa.gov, for clarification of content. For information pertaining to status, publication schedules, or alternate instructions for submitting comments if https://www.regulations.gov cannot be used, contact the Regulatory Secretariat Division at 202-501-4755 or GSARegSec@gsa.gov. Please cite FAC 2024-05, FAR Case 2022-006.

SUPPLEMENTARY INFORMATION:

I. Background
On December 8, 2021, the President signed Executive Order (E.O.) 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability. Section 208(a) directs agencies to reduce emissions, promote environmental stewardship, support resilient supply chains, drive innovation, and incentivize markets for sustainable products and services by purchasing sustainable products and services in accordance with relevant statutory requirements, and, to the maximum extent practicable, as identified or recommended by the Environmental Protection Agency (EPA). The Executive Office of the President's Office of Management and Budget (OMB), Council on Environmental Quality (CEQ), and Climate Policy Office jointly issued Memorandum M-22-06 on the same date to provide direction for agency compliance with the E.O. Paragraph G of section I of the memorandum reiterates the requirement to purchase, to the maximum extent practicable and after meeting statutory mandates, sustainable products and services identified or recommended by EPA.
In August 2022, CEQ issued Implementing Instructions for E.O. 14057. Section 4.6 of the instructions further directs agencies to prioritize multi-attribute products and delineates when it is considered not practicable to procure sustainable products and services. The CEQ implementing instructions provide additional direction as it relates to Federal facility requirements, such as goals for pollution prevention and waste diversion and requirements for waste reduction, as well as direction for certain construction and modernization projects to meet and (where practicable) exceed the CEQ's Guiding Principles for Sustainable Federal Buildings and Associated Instructions (Guiding Principles) (available at https://www.sustainability.gov/pdfs/guiding_principles_for_sustainable_federal_buildings.pdf ).
In alignment with E.O. 14057, memorandum M-22-06, and the CEQ Implementing Instructions, DoD, GSA, and NASA published a proposed rule at 88 FR 51672 on August 3, 2023, to amend the FAR to restructure and update FAR part 23 to focus on current environmental and sustainability matters, implement a requirement for agencies to procure sustainable products and services to the maximum extent practicable, and update requirements for construction and architect-contracts. The following changes are made to the FAR as a result of this final rule:
• Dedicates FAR part 23 to environmental matters by moving content related to drug-free workplaces and encouraging contractors to ban texting while driving to FAR part 26.
• Adds a definition of “sustainable products and services” in FAR 2.101.
• Consolidates and updates statutory and other environmental purchasing program requirements in FAR subpart 23.1, Sustainable Products and Services.
• Creates a new omnibus contract clause at FAR 52.223-23, Sustainable Products and Services, to uniformly communicate the Government's requirements for sustainable products and services.
• Dedicates FAR subpart 23.2 to energy savings performance contracts.
• Consolidates requirements related to hazardous and radioactive material in FAR subpart 23.3.
• Consolidates and updates Federal facility and pollution prevention requirements in FAR subpart 23.4.
• Redesignates the remaining content at FAR subpart 23.8 as FAR subpart 23.5.
• Makes other conforming changes throughout the FAR to align with the revision in FAR part 23.
• Updates agency requirements for construction and architect-engineer contracts at FAR 36.104(b)(1) to align with the CEQ's Guiding Principles for Sustainable Federal Buildings and Associated instructions.
• Removes certain contractor reporting requirements in the clauses at FAR clauses 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons; 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners; and the alternates to FAR clause 52.223-5, Pollution Prevention and Right-to-Know Information.
• Finalizes the interim rule published under FAR Case 2010-001 (see 76 FR 31395, May 31, 2011).
A presentation illustrating the overarching changes at the FAR part/subpart level and more detailed distribution and derivation tables illustrating changes at the section/paragraph level are provided as supplemental documents to this final rule. To access the presentation and tables, go to https://www.regulations.gov, search for “FAR Case 2022-006,” click “Open Docket,” and view “Supporting Documents”.

II. Discussion and Analysis
Fifty-two respondents submitted comments on the proposed rule and twenty-three respondents submitted comments on the interim rule. The Civilian Agency Acquisition Council and the Defense Acquisition Regulations Council (the Councils) reviewed the public comments in the development of the final rule. A discussion of the comments and the changes made to the rule are provided as follows:

A. Summary of Changes

1. Applicability of Statutory Purchasing Programs
The phrase “all applicable statutory purchasing program requirements” at FAR 23.103(b)(1) and 23.104(c)(1) is changed to “applicable statutory purchasing program requirements.” This change addresses a concern that the word “all” suggests sustainable products and services must meet the requirements of all four statutory purchasing programs in all cases, which is incorrect. Sustainable products and services must meet applicable statutory purchasing program requirements. In some cases, there may be more than one applicable statutory purchasing program requirement. For example, roofing-related products are covered under three of the statutory purchasing programs: recovered content, biobased, and energy efficient.

2. Reasonable Price Considerations
FAR 23.103(a)(2) is revised to clarify that agencies should consider the life-cycle cost of any sustainable product or service, when considering whether the sustainable product or service can be procured at a reasonable price. The paragraph is further revised to clarify that the life-cycle cost tools referenced in the paragraph are for “energy-efficient products.” FAR 23.103(a)(1)(iii) is revised to include a cross-reference to FAR 23.103(a)(2). These changes respond to a public comment suggesting that life-cycle cost considerations should not be limited to ENERGY STAR® or Federal Energy Management Program (FEMP)-designated products.

3. Identification of Applicable Sustainable Products and Services
The instructions at FAR 23.104(b) are revised to require the contracting officer to ensure that the solicitation and contract identify the sustainable products and services, including the purchasing program and type of product or service, that are applicable to the acquisition, as identified by the requiring activity. This change aligns with the revisions that were proposed at FAR 11.002(d)(2) and are implemented in this final rule. FAR 11.002(d)(2)(ii) requires agencies to incorporate the use of sustainable products and services when describing Government requirements for products and services. In other words, the requiring activity is responsible for identifying the sustainable products and services that are applicable to the requirement and for justifying when certain sustainable products and services are not practicable (see 23.104(b)(1)(i) and 23.104(a), respectively). This facilitates the technical personnel and contracting officer's ability to determine whether offers are responsive to the solicitation requirements, as well as the ability of the administrative contracting officer to ensure compliance during performance of the contract.
Conforming changes are also made to the clause at FAR 52.223-23. The previously proposed paragraph (b)(2) is removed and replaced by a new paragraph (b)(1). The new paragraph states that the Government will set forth in the statement of work or elsewhere in the contract the sustainable products and services that apply to the acquisition, as well as any products or services that are not subject to the clause. In addition, paragraph (c) regarding prioritization is removed from the clause, since the decision regarding which sustainable products and services are applicable to the acquisition resides with the requiring activity. These changes ensure that potential offerors have access to the same information on applicable specifications, standards, and ecolabels when preparing their offers. It also provides an opportunity for potential offerors to provide feedback to the contracting officer if they believe that certain sustainable products and services may have been inadvertently left out of the statement of work or solicitation.
A conforming change is also made to FAR 42.302(a)(68)(ii) to ensure that the administrative contracting officer is monitoring compliance with contractual requirements to deliver, use, or furnish sustainable products and services in accordance with the clause at FAR 52.223-23, instead of FAR part 23.

4. Updates Related to the Environmental Protection Agency Recommendations of Specifications, Standards, and Ecolabels
Paragraph (2)(iii) of the definition of “sustainable products and services” at FAR 2.101 and in the clause at FAR 52.223-23 is revised to specify that products and services must meet the Environmental Protection Agency (EPA) Recommendations of Specifications, Standards, and Ecolabels (EPA Recommendations) in effect as of October 2023. The EPA website at https://www.epa.gov/greenerproducts/recommendations-specifications-standards-and-ecolabels-federal-purchasing now provides a search functionality to allow users to search for EPA recommended specifications, standards, and ecolabels in effect since October 2023.
This change is in response to public comments that stated updates to the EPA Recommendations should be subject to formal notice and comment and expressed concern regarding the ability of industry to meet shifting or unpredictable requirements. If EPA makes updates to its recommendations in the future, the Federal Acquisition Regulatory Council (FAR Council) will consider updating this paragraph and will seek notice and comment on such changes.

5. Applicability to Subcontracts
Paragraph (b)(1) of the clause at FAR 52.223-23 is moved to paragraph (b)(2) and revised to state that the contractor must “ensure” sustainable products and services, as required by the contract, are delivered, furnished, or incorporated during performance of the contract. This change is in response to a public comment that interpreted the clause as not applicable to subcontracts, based solely on the absence of a paragraph on subcontracts. The change makes clear that the prime contractor is ultimately responsible for ensuring sustainable products and services are delivered, furnished, or incorporated, regardless of whether performance is by the prime contractor or subcontractors. No subcontract paragraph is necessary. Prime contractors flow down the clause to their subcontractors as appropriate or necessary.

6. Applicability to Supplies Versus Services
This rule makes several clarifications regarding applicability to supplies versus services. Revisions are made to better align the instructions to agencies at FAR 23.103(c) with the requirements for contractors in paragraph (b)(2) of FAR clause 52.223-23. The differing lists in these sections generated some questions regarding applicability. This rule revises both sections to make clear that contractors must provide sustainable products and services, including products that meet the definition of sustainable products and services, if the products and services are: (1) delivered to the Government; (2) furnished for Government use; (3) incorporated into the construction of a public building or public work; or (4) used by the contractor in performing services under a Government contract where the cost of the products is a direct cost to the contract.
In addition, the phrase “including use at Government-owned contractor-operated facilities” is removed from paragraph (b)(2)(i) of the clause. Instead, a new sentence is added at the end of FAR 52.223-23(b)(2)(iv) to clarify that contractors performing management and operation of Government-owned facilities are required to use products that meet the definition of sustainable products and services to the same extent that an agency would be required to comply if an agency operated or supported the facility.

7. Applicability Outside the United States
FAR 23.105(a) is revised to clarify that the requirement to procure sustainable products and services to the maximum extent practicable does not apply to contracts performed and supplies delivered outside of the United States, unless the agency head determines that such application is in the interest of the United States. This change is modeled after the exception previously provided at FAR 23.804(a) and accords with section 601(a) of Executive Order 14057.

8. Removal of Instruction Regarding Conflict With Statute
The language previously proposed at FAR 23.104(c)(4) and 52.223-23(c)(4) is removed in the final rule. This language stated that agencies and contractors should procure products and services that meet the EPA Recommendations, unless doing so would conflict with statute, Executive orders, or regulations that impose domestic manufacturing and content requirements. This final rule requires agencies to identify the standards and ecolabels that are applicable to the acquisitions and provides a process for agencies to document when the EPA Recommendations do not meet reasonable performance requirements. Should a statute, Executive order, or regulation impose any performance requirement that makes use of any statutory or other EPA purchasing program requirement impracticable, agencies may document the conflict and proceed with procuring other than sustainable products and services.

9. Revision of Procedures for Simplified Acquisitions
The special instructions proposed at FAR 13.302(d)(5) are not included in this final rule. The proposed paragraph directed contracting officers to delete FAR 52.223-23 from the clause at FAR 52.213-4, Terms and Conditions—Simplified Acquisitions (Other Than Commercial Products and Commercial Services), and mark the paragraph as reserved when there is an authorized exception, exemption, or a written justification that it is not practicable to procure sustainable products and services, and the scope of the exception, exemption, or justification covers the entirety of the acquisition. This final rule revises 52.213-4 to state that the omnibus clause at 52.223-23 is applicable when the contract identifies in the statement of work, or elsewhere in the contract, the types of sustainable products and services that apply to the acquisition. As a result, the special instructions proposed at FAR 13.302(d)(5) are no longer necessary.

10. Renumbering FAR Subpart 23.8 as Subpart 23.5
This rule renumbers FAR subpart 23.8 as subpart 23.5 to complete the streamlining of FAR part 23. A conforming change is made at FAR 52.223-22 to change the cross-reference for the clause prescription from FAR 23.804(b) to 23.502.

B. Analysis of Public Comments

1. FAR Part 23 Restructuring
Comment: Several respondents expressed support for restructuring, streamlining, and updating FAR part 23. Two of the respondents specifically expressed support for the consolidation of purchasing preference program requirements in FAR subpart 23.1, with one respondent highlighting the helpful references to statutory authority, lead agency implementing regulations, and other lead agency information on particular programs. One of these respondents also expressed support for removing extraneous items from FAR part 23 and consolidating Federal facility requirements in FAR subpart 23.4.
Response: Noted.
Comment: One respondent suggested that the FAR subpart on encouraging contractors to ban texting while driving should be eliminated altogether, instead of moving the subpart to FAR part 26.
Response: This comment is outside the scope of this FAR rule, which sought only to relocate the existing content at FAR subpart 23.11 to FAR subpart 26.6 to dedicate FAR part 23 to environmental and sustainability matters. This subpart implements Executive Order 13513, Federal Leadership on Reducing Text Messaging While Driving, which remains in effect.

2. Sustainable Products and Services

a. General

i. Support
Comment: Many respondents expressed general support for implementing the requirement to procure sustainable products and services to the maximum extent practicable. One of these respondents asserted that by requiring or incentivizing purchasing programs to consider environmental factors when sourcing products and services, the Federal Government can standardize the use of sustainable materials and practices in contracts and, consequently, create demand. Another respondent suggested that the proposed revisions would ensure that the environmental benefits of recycling are realized. Another respondent noted that by consolidating the full list of products and services identified by EPA, Department of Energy (DOE), and Department of Agriculture (USDA), the FAR Council would greatly increase the visibility and usage of a wide array of sustainable products and services and help agencies and contractors better understand and comply with existing sustainable procurement requirements.
Response: Noted.

ii. Oppose
Comment: Two respondents expressed concern regarding the proposal to require sustainable products and services to the maximum extent practicable with only a few exceptions. The respondents stated that changing Federal procurement across 34 purchase categories and that requiring sustainable products and services be procured to the maximum extent practicable will have far reaching impacts and implications for both Government suppliers and Federal agency procurement offices. They further asserted that the proposed rule would have a direct and damaging impact on companies supplying the Federal Government and on the Government's readiness and operational capacity; place product sustainability procurement above national security; and have a disproportionate impact on small businesses throughout the contracting supply chain that will be ineligible to participate in Federal procurement.
Response: The requirement for Government agencies to procure sustainable products and services is not new. Since 2011, FAR 23.103(a) has required Federal agencies to advance sustainable acquisition by ensuring that 95 percent of new contract actions are for products that are energy-efficient, water-efficient, biobased, environmentally preferable, non-ozone depleting, or made with recovered materials (see 76 FR 31395, May 31, 2011). In addition, since 2002, FAR 23.703 has required agencies to employ acquisition strategies that maximize the utilization of environmentally preferable products and services (based on EPA-issued guidance) and promote energy-efficiency and water conservation (see 66 FR 65351, December 18, 2001).
This rule standardizes the procedures across the Federal Government to ensure sustainable products and services are procured to the maximum extent practicable. National security and mission readiness are enduring priorities; this rule retains a process to allow procurement of other than sustainable products and services when mission specifications ( i.e., reasonable performance requirements) cannot otherwise be met (see FAR 23.103(a)(1)(ii) and 23.104(a)). This rule also continues to include statutory exceptions and other exemptions related to national security for certain types of acquisitions in certain product categories (see FAR 23.105 and 23.106).
To improve transparency, this rule includes amendments that will require agencies to specify in their solicitations and contracts the sustainable products and services that apply to the acquisition (see 23.104(b)). This will ensure offerors are proposing solutions against the same requirements and facilitate the agency's ability to evaluate the responsiveness of offers in a fair and consistent manner. In addition, the rule will only require compliance with the EPA Recommendations in effect as of October 2023. This will provide industry an opportunity to provide input on future updates to the EPA Recommendations and ensure adequate time for compliance.
Comment: One respondent expressed concern regarding the basis for the preference provided to products and services qualified under EPA programs identified in FAR 23.108-1 through 23.108-3.
Response: A cornerstone of the Pollution Prevention Act (PPA) of 1990 (Pub. L. 101-508, 42 U.S.C. 13101) is the establishment of the national policy that pollution should be prevented or reduced at the source whenever feasible. Under the PPA, EPA is specifically charged with identification of Federal procurement opportunities to encourage source reduction. Using the EPA programs on a governmentwide basis to qualify goods and services for a preference enhances efficiency while reducing costs for both offerors and the Government. Absent governmentwide standards, offerors would need to qualify products on a contract-by-contract basis, and it would impair both the offeror and Government's ability to benefit from economies of scale. In alignment with the National Technology Transfer and Advancement Act of 1995 (NTTAA) (Pub. L. 104-113) and OMB Circular A-119, this rule relies on standards and ecolabels that meet voluntary consensus standards or other private sector standards when they are fit for purpose. While similar to a qualified products list, acquisition of goods and services listed under FAR 23.108 are subject to the exceptions in FAR 23.105 and the exemptions in FAR 23.106 and are only required to be procured to the maximum extent practicable as described at FAR 23.103(a). While the PPA is of general applicability, other statutory authority exists for specific environmental aspects, such as energy pursuant to the authorities cited at FAR 23.107-3(a). The FAR has provided a preference for several of these programs for over two decades.

iii. Environmentally Preferable
Comment: One respondent sought clarification regarding the terms “sustainable products and services” and “environmentally preferable products and services.” The respondent also asked how the term “environmentally preferable products and services” will be applied in FAR 23.108-3 and how this term will interact with FAR 23.103 and 23.109(a) or 23.107.
Response: Both terms are defined in FAR 2.101. This rule will require agencies to procure sustainable products and services. One of the categories of sustainable products and services includes products and services that meet the EPA Recommendations of Specifications, Standards, and Ecolabels. The term “environmentally preferable” applies when addressing types of products and services that meet the EPA Recommendations (see FAR 23.108-3(a)).
Comment: One respondent requested clarification regarding how agencies will be required to source products from the “sustainable products and services” and “environmentally preferable products and services” categories.
Response: There are numerous tools and resources available to agencies when conducting market research. This rule provides links to the lead agency websites for information regarding specific purchasing programs. In addition, the rule highlights at FAR 11.102(d), 23.104(d), and 52.223-23(d) GSA's Green Procurement Compilation, available at https://sftool.gov/greenprocurement, which provides a comprehensive list of sustainable products and services and sustainable acquisition guidance. Agencies are encouraged to review GSA's Green Procurement Compilation when assessing which purchasing programs apply to a specific product or service.

iv. Standards
Comment: One respondent encouraged the Government to leverage existing global sustainability frameworks that reference recognized standards and ecolabels, rather than creating new, U.S. Government-specific specifications.
Response: The standards and ecolabels referenced in this rule are not Government-specific specifications. While some of these ecolabels are established and maintained by Government agencies, they have been developed for public use; none were intended for Government use only. This rule also allows the Government to access and utilize recognized private sector environmental performance standards and ecolabels that are recommended by the EPA, in alignment with the NTTAA and OMB Circular A-119. EPA's Recommendations consider and incorporate private sector standards and ecolabels that are used across the global marketplace.
Comment: One respondent suggested that the Government enact standards for the procurement of sustainable products and services and transition away from voluntary guidelines. The respondent asserted that, under a circular economy, sustainable purchasing must become the default and not just a suggestion.
Response: This rule advances sustainable purchasing by requiring agencies to procure sustainable products and services to the maximum extent practicable. Some of the standards and ecolabels referenced in this rule are statutorily mandated. Others are recommended by the EPA and are in alignment with the NTTAA and OMB Circular A-119 direction to agencies to adopt voluntary consensus standards or private sector standards when fit for purpose.
Comment: Two respondents suggested the FAR Council consider alternative means for showing that a product or service is “environmentally preferable” beyond the directory/registry approach required in the EPA Framework. One respondent suggested permitting flexibility in what is required to demonstrate conformance in a manner that is relevant for a particular requirement or solicitation. The other respondent encouraged the FAR Council to provide an illustrative list of standards, rather than an exhaustive one, which could be used to consider multiple economic impacts over time, such as job creation, workforce, development, supply chain resilience, or other outcomes.
Response: Nothing in this rule prohibits agencies from pursuing environmentally preferable products and services in categories not covered by the EPA Recommendations. This rule leverages the EPA Recommendations as a means of efficiency for Government acquisition. Both offerors and the Government benefit from the economies of scale associated with leveraging EPA's efforts to assess standards and ecolabels. Absent use of the EPA Recommendations, offerors and the Government would need to conduct their own assessment of standards and ecolabels on a contract-by-contract basis.

v. Clarify Procedures
Comment: Two respondents requested additional clarity and guidance on implementing the rule and the new clause. One of the respondents asked that the FAR Council provide clear instructions to both Government contracting officials and offerors on how to understand and appropriately account for sustainability information in the proposal evaluation and contract award process. This respondent also asked for additional clarification regarding how agencies will ensure that statutory purchasing program requirements are met. The other respondent asked how contracting officers will assess a contractor's compliance with the requirements of this rule and whether compliance will be considered in contract award decisions.
Response: This rule is revised to require the Government to identify the types of sustainable products and services that are applicable to the acquisition. The procedures at FAR 23.104(b) are revised to direct the contracting officer to include in the solicitation the sustainable products and services that are applicable to the solicitation, as identified by the requiring activity, as well as any products and services that are not subject to the requirements of the clause at 52.223-23, based on a written justification from the requiring activity or an authorized exception or exemption. Paragraph (b) of the clause at FAR 52.223-23 is also revised to advise offerors and contractors that the types of sustainable products and services that are applicable to the clause will be specified in the statement of work or elsewhere in the contract.
These changes in the final rule align with the changes that were proposed at FAR 7.103(p) and FAR 11.002(d) and implemented in this final rule, that agencies incorporate the use of sustainable products and services when developing specifications and standards and describing the Government's requirements. This rule also implements without change the requirement that was proposed at paragraph (b)(3) of FAR clause 52.223-23 that sustainable products and services must meet the applicable standards, specifications, or other program requirements at time of quote or offer submission, except for the EPA Recommendations, which are now as of October 2023. This language ensures transparency in the Government's specific requirements for sustainable products and services and that offerors include in their offers sustainable products and services that are subject to the same criteria.

vi. Cost Impact
Comment: Two respondents commented on the cost impact of the rule. One respondent stated that the proposed rule should contain an estimate of the added costs of procured products that are required to adhere to these environmental impact, energy efficiency, and other requirements. The respondent asserted that product selection that favors products better meeting these requirements will result in added cost to taxpayers. The other respondent suggested that the rule raises the cost of procurement by discouraging nonconforming bids, which could provide agencies reference points in the form of lower-cost bids that may be used to determine if the sustainability requirements are impracticable. This respondent noted that the contracting officer would not know that a sustainable product or service is more expensive until receipt of offers.
Response: This rule is not expected to result in added costs for several reasons. First, the requirement for agencies to procure sustainable products and services is not new. Since 2002, FAR section 23.703 has required agencies to implement cost-effective contracting preference programs promoting energy-efficiency, water conservation, and the acquisition of environmentally preferable products and services (see 66 FR 65351, December 18, 2001). In addition, since 2011, FAR 23.103(a) has required Federal agencies to advance sustainable acquisition by ensuring that 95 percent of new contract actions are for products that are energy-efficient, water-efficient, biobased, environmentally preferable, non-ozone depleting, or made with recovered materials (see 76 FR 31395, May 31, 2011). This rule streamlines and standardizes procedures for accomplishing this goal. Second, products that display a required ecolabel or meet the required specifications and standards identified in this rule are not necessarily more expensive than other products in the market and may result in savings when considering the life-cycle costs of the item. Third, this rule allows agencies to justify procuring other than a sustainable product or service if the item cannot be procured at a reasonable price. A revision is made in the final rule to ensure that this market research is conducted by the Government prior to issuance of a solicitation.

b. Applicability

i. Maximum Extent Practicable
Comment: Many respondents supported the proposed rule standard that agencies procure “sustainable products and services” to the maximum extent practicable. These respondents also expressed support for the position that procuring such products is practicable, unless the agency can demonstrate otherwise.
Response: Noted.
Comment: Two respondents commented that the language regarding what is considered “practicable” is too vague or subjective and could allow for too many exceptions, subverting the rule's effectiveness. One respondent suggested that the rule provide further guidance to clearly define the terms “reasonable” and “practicable.” The other respondent suggested that agencies should train procurement staff on the importance of buying products with recovered materials and provide clear guidelines on “unreasonable” parameters that allow for an exception.
Response: In accordance with FAR 1.108(a), this rule will rely on the common dictionary meanings of “practicable” and “reasonable.” FAR 23.103(a) provides an explanation of what is considered “practicable.” This basis for what is “practicable” is not new and does not necessitate a standalone definition; this language aligns with the exceptions for the statutory purchasing programs, which were already implemented in the FAR prior to this rule. The final rule makes one clarification regarding the term “reasonable” in response to another public comment. FAR 23.103(a)(2) is revised and a cross-reference to this paragraph is added at FAR 23.103(a)(1)(iii) to clarify that agencies must consider whether the sustainable product is cost-effective over the life of the product when determining whether the price of the product is reasonable.
Comment: One respondent, while generally supportive of the requirement to procure sustainable products and services to the maximum extent practicable, recommended also maintaining the goal for agencies to have 95 percent of contract actions require products that are energy-efficient and environmentally preferable, as a measurable goal.
Response: Given that agencies are required to procure sustainable products and services to the maximum extent practicable, there is no longer a need for a specific target. The Government tracks alignment with these and other sustainability requirements through the Federal Procurement Data System and other sustainability reporting submitted to the CEQ. See also response to comments on measuring and reporting in section II.B.5.b of this rule preamble.
Comment: One respondent stated that the requirement to procure sustainable products and services to the maximum extent practicable is overly limiting and does not provide agencies with sufficient discretion in selecting alternative products and services where necessary.
Response: The rule provides agencies with sufficient flexibility to address these concerns. When sustainable products and services do not meet an agency's reasonable performance requirements or reasonable delivery schedule, or cannot be procured at a reasonable price, agencies may document these circumstances and proceed with procuring other than sustainable products and services (see FAR 23.104(a)).

ii. Written Justifications
Comment: Two respondents expressed support for the written justification to be prepared by the requiring activity when it is determined that the procurement of sustainable products or services is not practicable. One respondent described this enforcement mechanism as an improvement from the 95 percent target, since it creates a written record that facilitates evaluation of performance and corrective actions at the individual and program levels. The other respondent noted the benefits of communicating to offerors and contractors in solicitations and contracts any products and services that are not subject to the FAR part 23 sustainable acquisition requirements.
Response: Noted.
Comment: One respondent recommended that the rule improve accountability by crafting a definition of “requiring activity,” to make clear that requiring activities are those individuals who identify and define requirements for products and services and request initiation of, and provide funding for, an acquisition. The respondent asserted that use of this definition would help ensure that the appropriate agency official takes responsibility for any decision not to require a sustainable product or service in a solicitation or contract.
Response: The request to add a definition of “requiring activity” for the purposes of this rule is declined. The term “requiring activity” is used throughout the FAR and is well understood by the acquisition workforce.
Comment: One respondent suggested that the rule require collection of these written justifications, not only in the contract file, but centrally at OMB or CEQ, or by the respective program owners at EPA, USDA, or DOE. The respondent asserted that compiling this type of data and information could improve program performance.
Response: While it may be helpful to collect this information on a governmentwide basis, it is impracticable at this time as no central repository currently exists.

iii. Commercial Products and Services and Micro-Purchases
Comment: Two respondents were supportive of the proposed application of the rule to the acquisition of commercial products and services, including purchases below the micro-purchase threshold. One of these respondents noted that this broad approach demonstrates an understanding that industry is already embracing approaches to deliver sustainable products and services commercially.
Response: Noted.

iv. Exceptions and Exemptions
Comment: One respondent expressed appreciation that the rule allows for exemptions when procuring a sustainable product or services is not practicable or is not in the interest of the United States.
Response: Noted.
Comment: One respondent noted the exception at FAR 23.105 from the requirement to procure sustainable products and services for “contracts performed outside of the United States.” This respondent sought clarification regarding how this language applies to contracts for supplies. The respondent requested that the rule clarify whether the place of performance is determined by place of delivery for supply contracts or place of manufacture.
Response: The rule is revised at FAR 23.105(a) to state that contracts performed or supplies delivered outside of the United States are excepted from the requirement to procure sustainable products and services, unless the agency head determines that such application is in the interest of the United States. This change is modeled after the exception previously provided at FAR 23.804(a) and accords with section 601(a) of Executive Order 14057.
Comment: Two respondents requested that a categorical exemption for military equipment (and weapons systems) be eliminated or revised, and products evaluated on a case-by-case basis. These respondents asserted that there is no inherent weakness to biobased products as compared to traditional products and that the burden should be on DoD to exclude biobased products if shown to perform unequally to other embedded products.
Response: The USDA is responsible for providing guidelines for the use of procuring agencies in complying with the requirements of 7 U.S.C. 8102(a)(3). Those guidelines are provided in the USDA regulations at 7 CFR 3201.3. The categorical exception at FAR 23.105(d) regarding biobased products to be used in military equipment (products or systems designed or procured for combat or combat-related missions), spacecraft systems, or launch support equipment is based on USDA regulations at 7 CFR 3201.3(e).
Comment: One respondent recommended that any FAR amendments on sustainable procurement recognize the sole and exclusive authority of the Federal Aviation Administration (FAA) to regulate aviation, including aircraft operations, aircraft fuel specification, and certification of aircraft and other aviation equipment. This respondent noted the exceptions and exemptions at FAR 23.105 and 23.106 and suggested that the rule expressly exempt agencies from any requirements to procure sustainable products and services to the extent they conflict with FAA safety and operational policies and mandates.
Response: A blanket exception is not required. This FAR rule allows agencies to procure other than sustainable products and services if the sustainable products and services do not meet reasonable performance requirements (see FAR 23.103(a)(1)(ii)). This process aligns with the existing statutory exceptions for procuring Biobased products meeting the content requirement of the USDA under the BioPreferred® program, products containing recovered material designated by the EPA under the Comprehensive Procurement Guidelines, and energy- and water-efficient products that are ENERGY STAR® certified or Federal Energy Management Program (FEMP)-designated products. In the event that the procurement of a sustainable product or service conflicts with FAA safety or operational policies and mandates, the requiring activity can provide a written justification to the contracting officer who may proceed with procuring other than sustainable products and services.
Comment: One respondent recommended requiring agencies to justify in writing any decisions made pursuant to FAR 23.104(c)(4), and that these justifications be collected.
Response: The paragraph that was proposed at FAR 23.104(c)(4) is removed in the final rule. That paragraph had sought to highlight that agencies need to ensure procuring certain sustainable products and services does not conflict with statutory or regulatory domestic manufacturing and content requirements. However, the rule already includes a process by which agencies consider whether sustainable products and services meet reasonable performance requirements, which would include those dictated by statute or regulation. As such, no additional guidance is necessary.

v. Services
Comment: One respondent noted the changes related to defining applicability to service contracts. The respondent noted that focusing on products that are a direct cost to the Government contract was a reasonable and fair method to simplify the cost allocation process and should expedite the implementation and widespread acceptance of the rule by contracting officials and contractors bidding on highly complex and efficiency driven projects.
Response: Noted.
Comment: One respondent asked whether the clause would apply to firm-fixed-price contracts, given the proposed language that requires contractors to “furnish sustainable products and services for use in performing services under this contract, where the cost of the products is a direct cost to this contract (versus costs which are normally applied to the Contractor's general and administrative expenses or indirect costs).” The respondent noted that firm-fixed-price contracts do not identify indirect costs to the Government and, therefore, appear to be excluded.
Response: The clause at FAR 52.223-23 is prescribed at FAR 23.109 for use in solicitations and contracts, which includes firm-fixed-price contracts, unless the requiring activity provides a written justification that it is not practicable to procure sustainable products and services. FAR 52.223-23(b)(2)(iii) provides direction to the contractor regarding supplies furnished during the performance of services contracts. Specifically, where supplies are involved in the performance of the service, the Contractor must furnish products that meet the definition of “sustainable products and services” when the cost of such products is a direct cost to the contract. While a firm-fixed-price contract may not identify indirect or direct costs, it does not alleviate the requirement for a contractor to ensure that products that are a direct cost of the service contract are sustainable products and services.
Comment: Two respondents sought clarification regarding application of the clause to supply contracts versus service contracts. The respondents asked whether the proposed language at FAR 52.223-23(b)(1)(i) was meant to apply only to contracts for goods, or also contracts for services. That paragraph stated that, in performance of the contract, the contractor shall “deliver and furnish sustainable products and services for Government use, including use at Government-owned contractor-operated facilities.” These respondents also asked whether the proposed language at 52.223-23(b)(1)(iii) was meant to apply to service contracts that involve goods, products, or hardware as part of that service. That paragraph had stated that the contractor shall “furnish sustainable products and services for use in performing services under this contract, where the cost of the products is a direct cost to this contract (versus costs which are normally applied to the Contractor's general and administrative expenses or indirect costs).”
Response: Paragraph (b)(2) of the clause is revised to make clear the Government's requirements for supplies versus services. In the case of a supply contract, the contractor must deliver or furnish products that meet the definition of “sustainable products and services.” In the case of a service contract, where supplies are involved in the performance of the service, the contractor must furnish products that meet the definition of “sustainable products and services” when the cost of such products is a direct cost to the contract.

vi. Government-Owned, Contractor-Operated Facilities
Comment: One respondent expressed support for language in the rule that clarifies the policy covers products provided by a contractor during performance at Government-owned contractor-operated facilities, as well as certain products used by contractors while performing services at a Federally-controlled facility.
Response: Noted. However, see revisions to FAR 52.223-23 in response to other public comments to make clear at paragraph (b)(2)(i) that the contractor shall deliver or furnish sustainable products and services generally and clarify at (b)(2)(iv) that the requirement to furnish sustainable products when performing services under the contract includes services performed by contractors performing management and operation of Government-owned facilities to the same extent that the Government would be required to comply.

c. Prioritization

i. Prioritization of Multi-Attribute Products and Services
Comment: Two respondents expressed support for the focus on prioritization of multi-attribute products and services that meet at least one statutory purchasing program and one or more of the non-statutory EPA programs. One of these respondents noted that businesses developing products and services that achieve multiple positive environmental outcomes will be able to move forward knowing that this kind of innovation will likely be rewarded.
Response: Noted.
Comment: Two respondents expressed support for multi-attribute products and the purchasing prioritization for such products, as long as biobased products continue to receive equal (or preferred) treatment, especially if prioritization of other attributes is not required in statute. These respondents stated that they have heard of instances of agencies not buying “biobased” based on claims of prioritization of other types of products, such as those that are recycled or otherwise mandated, or for other questionable or illegitimate reasons.
Response: This rule continues to implement the statutory requirement to procure biobased products meeting the content requirements of the U.S. Department of Agriculture under the BioPreferred® program, unless the agency cannot acquire products competitively within a reasonable performance schedule, that meet reasonable performance requirements, or at a reasonable price. Also, this rule will continue to require, when both an EPA-designated item and a biobased product in a USDA-designated product category could be used for the same purposes and both meet the agency's needs, that the agency procure the EPA-designated item (see FAR 23.104(c)(1) of this final rule). This requirement is based on the USDA implementing regulations at 7 CFR 3201.3(b), which provides that the requirements for biobased products do not apply to the extent that they are inconsistent with the EPA regulations for the Comprehensive Procurement Guidelines (see 40 CFR part 247). Questions regarding an agency's compliance with requirements to procure biobased products, as outlined in the FAR, should be directed to the contracting officer for the specific procurement and/or an agency's affirmative procurement program.
Comment: Two respondents sought clarification regarding how an agency will inform vendors and contractors of the agency's intent to provide a preference for multi-attribute ecolabels over other sustainable products categories. One of these respondents asked whether “prioritize” means that agencies should give preference to these products during source selection and, if so, how the Government should weigh sustainability considerations against price and other non-price factors. The other respondent asked, if the current FAR clauses on Electronic Product Environmental Assessment Tool (EPEAT®) are replaced with the clause at FAR 52.223-23, how vendors and contractors will be made aware that agencies intend to preference EPEAT® ecolabel registered products as recommended by the EPA.
Response: This rule is revised to require the Government to identify the types of sustainable products and services that are applicable to the acquisition. The procedures at FAR 23.104(b) are revised to direct the contracting officer to include in the solicitation the sustainable products and services, including the purchasing program and type of product or service, that are applicable to the solicitation, as identified by the requiring activity, as well as any products and services that are not subject to the requirements of the clause at 52.223-23, based on a written justification from the requiring activity or an authorized exception or exemption. Paragraph (b) of the clause at FAR 52.223-23 is also revised to advise offerors and contractors that the types of sustainable products and services that are applicable to the clause will be specified in the statement of work or elsewhere in the contract. Given that there are possible variations in the ways agencies procure sustainable products and services, agencies are given discretion in determining how to consider compliance during the evaluation of offers and how to monitor compliance during performance of the contract. Contractors will need to offer and deliver products and services that meet applicable specifications, standards, and ecolabels in accordance with agency solicitations.

ii. Statutory Programs and Multi-Attributes
Comment: One respondent requested that the rule make clear that statutory requirements must be met prior to meeting the requirements of other EPA programs. The respondent noted that many Federal agencies are still not meeting the requirements for biobased purchasing, which is a statutory requirement and should be implemented before these additional non-statutory programs.
Response: No additional clarification is necessary. FAR 23.103(b)(1) and 23.104(c)(1) direct agencies to procure sustainable products and services that meet statutory purchasing program requirements. FAR 23.104(c)(3) states that, if no statutory purchasing program requirements apply, then agencies must procure sustainable products and services that meet required EPA purchasing program requirements.
Comment: One respondent requested that the rule clarify that preference should be given to ecolabels that address one or more, not all, statutory and EPA program requirements or attributes. The respondent believes that ecolabels like EPEAT®, which apply multiple criteria addressing everything from electronic stewardship, energy and water efficiency, greenhouse gas emission reductions, pollution prevention, and recovered content should be prioritized by Federal purchasers over similar products that may only address a single statutory attribute, such as ENERGY STAR® or recovered content or biobased content, which are all covered in EPEAT® criteria.
Response: FAR 23.103(b)(1), 23.104(c)(1), and 23.104(c)(2) have been revised to remove the term “all” preceding “applicable statutory purchasing program requirements.” This change makes clear that sustainable products and services must meet “applicable” statutory requirements, not “all” four statutory purchasing program requirements. No additional clarification is necessary. FAR 23.104(c)(1) provides direction to ensure that agencies, first and foremost, comply with the statutory purchasing preference program requirements. FAR 23.104(c)(2) provides the additional direction the respondent seeks, which is to prioritize multi-attribute sustainable products and services, which are those that meet all applicable statutory purchasing program requirements and one or more required EPA purchasing programs.

iii. Other Policy Priorities
Comment: Two respondents suggested that the rule clarify the relationship and prioritization of sustainability requirements versus other policy requirements, such as cost, quality, availability, cybersecurity, supply chain risk management, equity, domestic sourcing, and other requirements, including how to deal with potential trade-offs or conflicts between sustainability and other procurement objectives. One of these respondents suggested providing guidance or principles under which agencies prioritize sustainability over other objectives when feasible and justified, take a precautionary approach when there is uncertainty or risk, and seek win-win solutions that optimize multiple objectives.
Response: This rule seeks to require contractors to deliver sustainable products and services, as defined in the rule, to the maximum extent practicable. Agencies are not required to procure sustainable products and services if an exception or exemption applies, or if there is a written justification that the agency cannot acquire products or services competitively within a reasonable performance schedule; that meet reasonable performance requirements; or at a reasonable price. The justification provides agencies a mechanism to document when a reasonable performance requirement conflicts with the requirement to procure sustainable products and services.
Comment: One of these respondents asked how the Government will approach situations where a foreign product is more sustainable than a domestically-produced product, and the acquisition is subject to the Buy American Act.
Response: This rule directs agencies to procure sustainable products and services, which are those that meet applicable statutory and required EPA purchasing program requirements. It establishes the specifications, standards, and ecolabels that apply to the acquisition, unless an exception or exemption applies or there is a written justification. Contractors are to deliver or furnish conforming supplies and services. Agencies should continue to follow FAR subparts 25.1 and 25.2 regarding the Buy American Act.
Comment: One respondent expressed concern regarding the materials used in products provided by the Federal Prison Industries (FPI) or AbilityOne participating nonprofit agencies.
Response: The materials used by FPI or by AbilityOne vendors are outside the scope of this FAR rule. Per FAR 8.002(a) and 8.004, except as required by FAR 8.003 or as otherwise provided by law, agencies are required to satisfy requirements for supplies and services from or through mandatory Government sources, such as supplies from FPI or supplies on the Procurement List maintained by the Committee for Purchase From People Who Are Blind or Severely Disabled, before satisfying requirements through non-mandatory sources.
Comment: One respondent commented that the proposed rule failed to establish safeguards to prevent EPA and USDA decision-making pursuant to separately administered programs from interfering with statutorily mandated divisions of authority among various Federal agencies. The respondent further suggested that the FAR rule should expressly provide that EPA and USDA must, at a minimum, confer with the FAA to ensure any changes to their designations of “sustainable products and services” will not conflict with FAA safety or operational mandates.
Response: This FAR rule has appropriate safeguards in place to ensure the requirement to procure sustainable products and services to the maximum extent practicable do not supersede reasonable performance requirements (such as FAA safety or operational policies and mandates). In the event that procurement of a sustainable product or service conflicts with FAA safety or operational policies and mandates, the requiring activity can provide a written justification to the contracting officer who may proceed with procuring other than sustainable products and services. Comments on administration of the purchasing program have been shared with EPA and USDA.

d. Contract Clause
Comment: Two respondents expressed support for the new clause at FAR 52.223-23, Sustainable Products and Services. One of these respondents noted that the clause ensures the intent of the regulations is included in the actual purchase. The other respondent noted that the clause would strengthen accountability by requiring the contracting officer to identify in solicitations and contracts any products or services not covered by the clause due to exceptions or exemptions.
Response: Noted.
Comment: One respondent expressed appreciation that the new clause at FAR 52.223-23 did not include a mandatory flow-down requirement and, therefore, applied only to the prime contractor.
Response: While there is no subcontracts paragraph within FAR clause 52.223-23, the clause includes the Government's requirement for sustainable products and services. The prime contractor is responsible for ensuring sustainable products and services are delivered or furnished under the contract in accordance with FAR 52.223-23. Paragraph (b)(2) of the clause is revised in the final rule to make this clear. How the prime contractor communicates this requirement to its subcontractors is at the discretion of the prime contractor.
Comment: One respondent sought clarification regarding language in the proposed preamble regarding the mechanics of the clause at FAR 52.212-5, Contract Terms and Conditions Required To Implement Statutes or Executive Orders—Commercial Products and Commercial Services, and application of the policy to commercial products and commercial services. Based on the language in the preamble, the respondent was unsure whether the omnibus clause would be required for use as a standard contract term and condition for all commercial products and commercial services, unless a written justification, exception, or a specific exemption is provided by the requiring official to the contracting officer.
Response: The requirements of FAR 52.223-23 apply to acquisitions of commercial products and services, as well as acquisitions valued at or below the simplified acquisition threshold, unless an exception or exemption applies or there is a written justification that it is not practicable to acquire sustainable products and services ( i.e., the agency cannot acquire sustainable products or services competitively within a reasonable performance schedule, that meet reasonable performance requirements, or at a reasonable price). This rule amends the clause at FAR 52.212-5, Contract Terms and Conditions Required To Implement Statutes or Executive Orders—Commercial Products and Commercial Services, to ensure that the clause is included in contracts for commercial products and services. This rule amends the clause at FAR 52.213-4, Terms and Conditions—Simplified Acquisitions (Other Than Commercial Products and Commercial Services), to ensure that the omnibus clause is also included in simplified acquisitions, when the acquisition is not for commercial products or commercial services (in other words, not covered by FAR 52.212-5).
Comment: One respondent expressed support for the removal of EPEAT® clauses to streamline the FAR part 23 requirements and promotion of an omnibus clause, as long as the omnibus clause requires agencies to procure the EPA recommended ecolabels and could be used by agencies to preference multi-attribute ecolabels, developed in a Voluntary Consensus Process, over single-attribute products to ensure the highest quality and performance for sustainability as required by Executive Order 14057.
Response: This rule will require agencies to procure sustainable products and services to the maximum extent practicable. Agencies must identify in their solicitations and contracts the sustainable products and services that are applicable to the acquisition, including those that are covered by the EPA Recommendations for Specifications, Standards, and Ecolabels. EPA currently recommends EPEAT® for electronic products.

e. Program-Specific Comments

i. Energy Star/FEMP
Comment: One respondent asked why price reasonableness was defined for ENERGY STAR or FEMP-designated products only. The respondent suggested that FAR 23.103(a)(2) be revised to state, “For all designated products, a price is reasonable if it is cost-effective over the life of the product taking life-cycle costing into account.”
Response: An introductory statement has been added at FAR 23.103(a)(2) to advise agencies that, when considering whether the price of any sustainable product or service is reasonable, the agency should consider whether it is cost-effective over the life of the product.

ii. Recovered Materials
Comment: Several respondents expressed support for including within the definition of “sustainable products and services” those products listed under the EPA Comprehensive Procurement Guidelines (CPG). Some of these respondents noted the benefits of the Guidelines for specific products such as landscaping products and compost, recycled paper products, and tires. Another respondent expressed support for the EPA CPG distinction between post-consumer and post-industrial recycled plastics.
Response: Noted. Paragraph (1)(i) of the definition in the proposed rule is implemented without change in the final rule.
Comment: Several respondents commented that the EPA CPG and its product listing should be updated more frequently to better reflect the market, technology, and product changes, with some noting that the Program's last update was in 2007. One of these respondents noted that technology to process and use recovered materials is rapidly improving. Two respondents, who were supportive of the rule, encouraged EPA to update the designated paperboard and packaging products list and revise its recovered material content levels for paperboard and packaging products. Another respondent expressed concern regarding the EPA guidelines and recovered material content levels for products containing steel or steelmaking. Another respondent, while supportive of the EPA CPG distinction between post-consumer recycled content and overall recycled content, suggested rates of post-consumer recycled content should be updated to reflect best practices to achieve greater environmental benefits.
Response: This rule continues to implement the statutory requirement for agencies to procure products that meet the minimum recovered material content standards established by the EPA, in accordance with 42 U.S.C. 6962 and as implemented at 40 CFR part 347. This comment is on EPA's administration of the CPG Program and is, therefore, outside the scope of this FAR rule; however, these comments have been shared with the EPA.
Comment: Two respondents suggested that the FAR require independent, third-party certification of post-consumer recycled content. One respondent made this comment specifically in relation to plastic items containing recovered materials, suggesting that such items be certified as Postconsumer Recycled Content based on the ISO 14021 standard, to ensure that materials the Federal Government is using have met the end of their previously intended life. The other respondent stated that certification programs have largely been voluntary to date but noted that California and Oregon now require certified postconsumer recycled content in some products, while several other states give authority to their state agencies to consider requiring third party post-consumer recycled plastics certification through future rulemaking.
Response: This comment is outside the scope of this FAR rule, which continues to implement the statutory requirement for agencies to procure products that meet the minimum recovered material content standards established by the EPA, in accordance with 42 U.S.C. 6962 and as implemented at 40 CFR part 347. However, these comments have been shared with the EPA.
Comment: Two respondents commented on the definition of “recovered material” in the proposed rule. One respondent noted that the definition is identical to the statutory definition in the Resource Conservation and Recovery Act, (RCRA) and expressed support for minor revisions in the proposed rule to add the statutory citation (42 U.S.C. 6903) for the definition and reflect the proposed removal of special paper requirements from FAR subpart 4.3 and FAR 11.303. The other respondent recommended that the final rule not rely on the definition of “recovered material” designated in the EPA CPG, expressing concerns about the impact on the steelmaking industry.
Response: No changes are made to the definition of “recovered material.” This rule continues to implement the statutory requirement for agencies to procure products that meet the minimum recovered material content standards established by the EPA, in accordance with 42 U.S.C. 6962 and as implemented at 40 CFR part 347. As noted by one of the respondents, the definition of the term “recovered material” comes directly from statute being implemented in the FAR.
Comment: One respondent, in expressing support for the EPA CPG Program, commented that EPA's National Recycling Strategy should incorporate increasingly aggressive preferences for environmentally sustainable products.
Response: This comment on EPA's National Recycling Strategy and is, therefore, outside the scope of this FAR rule.

iii. Biobased Products
Comment: A few respondents expressed support for the requirement to purchase biobased products that meet the content requirement of the USDA under the BioPreferred® program to the maximum extent practicable. Two respondents expressed strong support for the rule to ensure full compliance with applicable statutory purchasing preference programs and, in particular, section 9002 of the Farm Bill.
Response: Noted.
Comment: One respondent provided several recommendations for the USDA BioPreferred® Program, to include the following: extend incentives that already exist for biofuels to biomaterials as well; provide incentives for use of biobased feedstocks to be manufactured into bioplastics in addition to the existing incentives for biofuels; and formally recognize the biogenic component of biobased polymers in lifecycle cost assessment methodology.
Response: This comment is on USDA's administration of the BioPreferred® Program and is, therefore, outside the scope of this FAR rule. However, these comments have been shared with USDA.
Comment: One respondent recommended that the rule further elaborate on the phrase at FAR 23.107-2(e)(2), “highest percentage of biobased material practical.” The respondent suggested that agency contracts that specify having the “highest percentage of biobased material practical” also comply with biobased testing requirements in accordance with the USDA BioPreferred® Program, specifically ASTM D6866 method B.
Response: The FAR specifies that contracts include language requiring compliance with the regulations implementing the Biobased Markets Program (the BioPreferred® Program). The BioPreferred® Program has established “minimum” biobased content requirements for qualifying biobased products. These minimum biobased contents are determined by examining the biobased content of the various manufacturer's products offered within each designated product category. The BioPreferred® Program recognizes that within a given product category the available products may vary significantly in biobased content as a result of varying performance needs and features required of the product. It is the intent of the BioPreferred® Program that purchasers of biobased products choose to purchase the products with the highest biobased content that meets their performance needs. The BioPreferred® Program specifies that demonstration of a product's compliance with the required minimum biobased content must be verified using ASTM D6866. USDA believes it would be redundant for the FAR to specify the use of ASTM D6866 as this method is already specified in the BioPreferred® Program's regulations and the FAR specifies compliance with those regulations.
Comment: One respondent suggested that the rule include a new contract clause to specify that the USDA BioPreferred® Program requires a minimum of 25 percent biobased carbon content, which varies depending on the product category. This respondent also suggested that whenever biobased product procurement is mentioned in the FAR, it should clearly state that the biobased product must be third-party tested by an ISO 17025 accredited laboratory and contain a verified biobased carbon content percentage that meets or exceeds the “highest percentage of biobased material practical.”
Response: The specific requirements included in the comment are already contained in the BioPreferred® Program's regulations. As stated in the previous response, USDA believes that, as long as the FAR requires compliance with the BioPreferred® Program's regulations, it would be redundant to list selected requirements in the FAR. Singling out specific requirements for inclusion in the FAR, but not including others, could also be confusing to the agencies.
Comment: Several respondents commented on the definition of “biobased products.” One respondent expressed support for the revised definition included in the proposed rule. The other respondents recommended updating the biobased products definition to fully reflect the exact language of Public Law 115-334. The respondents noted that the statute refers to “renewable chemicals,” terminology that is missing in the proposed rule.
Response: The definition of “biobased product” in section FAR 2.101(b)(2) aligns with the definition of “biobased product” in the USDA's implementing regulations at 7 CFR 3201.2. However, these comments have been shared with USDA. If the USDA's definition in its implementing regulations is updated to include “renewable chemicals,” a conforming change will be made to the FAR.
Comment: One respondent commented that the rule should include the requirements in section 9002 of the Farm Security and Rural Investment Act of 2002, as amended (see 7 U.S.C. 8102(a)(2)(A)(i)(III)), for agencies to “establish a targeted biobased-only procurement requirement under which the procuring agency shall issue a certain number of biobased-only contracts when the procuring agency is purchasing products, or purchasing services that include the use of products, that are included in a biobased product category designated by the Secretary [of Agriculture]” and to “report quantities and types of biobased products purchased by procuring agencies.”
Response: The comment on targeted biobased-only procurement requirements is outside the scope of this rule, which continues to implement the statutory requirement for agencies to establish affirmative procurement programs to promote a preference for biobased products (see content at FAR 23.107-2 of this rule, which was previously implemented at FAR subpart 23.4). Executive Order 14081, Advancing Biotechnology and Biomanufacturing Innovation for a Sustainable, Safe, and Secure American Bioeconomy, addresses implementation of biobased products procurement, including agency efforts for biobased-only contracts. Efforts to monitor targets and reporting can be achieved through internal efforts outside the regulatory process.
Comment: One respondent, who supports usage of biobased materials when appropriate or necessary, strongly urged the Federal Government to only use biobased products that have been responsibly sourced.
Response: This comment is outside the scope of this rule, which continues to implement the statutory requirement for agencies to procure biobased products that meet the content requirement of the USDA under the BioPreferred® program in accordance with 7 U.S.C. 8102 and the USDA implementing regulations at 7 CFR part 3201. The USDA's implementing regulations at 7 CFR 3201.3(c) direct agencies to procure qualified biobased products composed of the highest percentage of biobased content practicable or such products that meet the minimum standards issued by the USDA. The direction to agencies at FAR 23.107-2 is in alignment with these USDA regulations.
Comment: One respondent commented that reliance on the biobased products in categories designated by USDA for crop and other biobased purchasing options under this rule works contrary to the overall objective to procure sustainable products and services to the maximum extent practicable. The respondent suggested that biobased products must demonstrate they have not contributed to deforestation or conversion of critical habitats/ecosystems such as grasslands; (2) the Government should ensure that the program is not causing environmental harm, such as no deforestation or grassland conversion; (3) prioritize and give preference to those products that demonstrate more sustainable production methods; and (4) create ways to incentivize environmental benefit, such as participation in sustainable agriculture/regenerative agriculture programs or use of metrics/models that document sustainability outcomes.
Response: This rule continues to implement the statutory requirement for agencies to procure biobased products that meet the content requirement of the USDA under the BioPreferred® program in accordance with 7 U.S.C. 8102 and the USDA implementing regulations at 7 CFR part 3201. This comment is on the USDA's administration of the BioPreferred® Program and is, therefore, outside the scope of this case. However, the comment has been shared with the USDA.
Comment: One respondent recommended that GSA consider integration of the BioPreferred® Products Catalog available at https://www.biopreferred.gov/BioPreferred/faces/catalog/Catalog.xhtml into its procurement system along with links to approved suppliers who stock the products to ensure contracting officers can easily access information about biobased options when making purchasing decisions and that training be offered to contracting officers. This respondent also noted that DoD and NASA would have interest in new sustainable technologies and their resulting biobased products, some of which are displayed in the BioPreferred® Catalog but are not receiving the attention they should be since there is no connection with the BioPreferred® Catalog and the Federal agencies.
Response: The BioPreferred® Program is currently integrated into several GSA procurement tools and databases, including the following:
• GSAAdvantage: GSA's online shopping and ordering system provides access to thousands of contractors and millions of products and services and Federal buyers can use filters to locate BioPreferred® compliant products. See https://www.gsaadvantage.gov/advantage/ws/search/special_category_search?cat=ADV.ENV.
• GSA's Green Procurement Compilation: GSA's comprehensive green purchasing resource designed for Federal contracting personnel and program managers, as well as vendors working with Federal agencies. It helps identify applicable green purchasing requirements by consolidating and organizing information from Federal environmental programs in one place. The BioPreferred® categories are included in GSA's Green Procurement Compilation. See https://sftool.gov/gpcsearch?query=BioPreferred.
• GSA's SFTool Product Search: A product database aimed at simplifying procurement, documentation, and reporting by creating digital catalogs of commercially available, environmentally preferable products that align with Federal requirements. GSA's SFTool Product Search is the largest curated database of environmentally preferable, high-performance products in the marketplace, including over 150 categories and subcategories that represent over 5,700 brands and more than 300,000 products. The BioPreferred® product catalog is included in GSA's SFTool Product Search; see https://sftool.ecomedes.com.

iv. WaterSense®
Comment: One respondent requested clarification regarding how WaterSense® would be applied to services, since the WaterSense® site only describes its applicability to products.
Response: As a result of this rule, when performing on a service contract, contractors will be expected to provide products that meet the definition of sustainable products and services, which includes WaterSense® products, during performance of the contract if such products are a direct cost to the contract. See paragraph (b)(2)(iii) of the clause at FAR 52.223-23.

v. SaferChoice
Comment: One respondent noted that FAR subpart 23.7, which is superseded by FAR subpart 23.1 as a result of this rule, directed agencies to give preference to the procurement of acceptable alternative chemicals and products that reduce the overall risks to human health. The respondent suggested that this rule acknowledge and/or promote the viability of all relevant ecolabels, so as not to create an unfair position in the marketplace.
Response: This rule seeks to implement statutory and other EPA purchasing program requirements. Federal agencies benefit from the efforts of EPA under the SaferChoice program in that they can easily and efficiently identify products that contain safer chemicals for procurement versus duplicating the effort of assessing viable specifications, standards, and ecolabels on a contract-by-contract or agency-by-agency basis. However, nothing in this rule prohibits an agency from considering other factors when procuring other products and services that meet their mission needs.

vi. EPA Recommendations of Specifications, Standards, and Ecolabels
Comment: Several respondents expressed support for the inclusion of EPA Recommendations of Specifications, Standards, and Ecolabels in its definition of sustainable products and services. One respondent noted that the EPA Recommendations give preference to multi-attribute or life cycle-based standards and ecolabels that address key environmental and human health impact areas, and where product conformance is determined by a competent third-party certification body. Several respondents noted that including this resource will ensure that, should a third-party certification for products and services that reduce food waste be added to the EPA Recommendations, Federal purchasers would have access to that information. One of the respondents expressed appreciation for EPA's evaluation of labels and standards, and extension of the Recommendations to cover uniforms and clothing.
Response: Noted.
Comment: Several respondents supported the replacement of the requirement for agencies to procure products that have the EPEAT® ecolabel with the requirement to procure products and services that meet EPA Recommendations of Specifications, Standards, and Ecolabels. One respondent noted that it had formally petitioned the FAR Council to initiate rulemaking that would amend FAR part 23 to address sole reliance on EPEAT®. This respondent and others commented that this change will allow multiple voluntary consensus standards and labels to be added to the EPA Recommendations and make them available to the Government when purchasing electronic products. One respondent noted that this change will increase competition and remove barriers to doing business with the Government, without penalizing companies that have voluntarily invested in similar efforts. Another respondent strongly advocated for the independent, qualified third-party conformance assessments for standards and ecolabels used by the Federal Government, as well as the transparency of products or services that meet these standards or ecolabels. This respondent noted that independent third-party assessments ensure that the Federal Government procures products and services that conform to the recommended standard or ecolabel and saves Federal resources as agency staff do not have to conduct their own evaluations of products and services or hire third parties to conduct necessary research and separate evaluations.
Response: Noted. As highlighted by the respondents, this rule removes the EPEAT®-specific requirements at FAR 23.704 and the associated contract clauses at FAR 52.223-13, 52.223-14, 52.223-16. These clauses are replaced by the omnibus clause at FAR 52.223-23, which directs contractors to deliver or furnish sustainable products and services, including those that meet EPA Recommendations of Specifications, Standards, and Ecolabels. The EPEAT® ecolabel remains an EPA Recommendation for the electronic products category; however, this product category could be expanded to cover additional ecolabels in the future.
Comment: A few of the respondents who expressed support for the removal of EPEAT®, also urged EPA to commit to revising the EPA Recommendations of Specifications, Standards and Ecolabels for Federal Purchasing to allow eligibility for additional ecolabels for electronic products. One respondent described this as an important step toward compliance with the principles of fair competition in contracting and the rigor of EPA Recommendations as a required resource in the FAR and would align the electronics category with other product categories in the EPA Recommendations.
Response: These comments are on EPA's application of their Framework for the Assessment of Environmental Performance Standards and Ecolabels for Federal Purchasing and expansion of their Recommendations of Specifications, Standards, and Ecolabels for Federal Purchasing for certain product categories (primarily the electronic product category), which are outside the scope of this rulemaking. However, these comments have been shared with the EPA.
Comment: A few respondents commented that the EPA should establish a clear and transparent process for the identification, evaluation, and selection of standards, specifications, and ecolabels for the EPA Recommendations of Specifications, Standards, and Ecolabels. One of the respondents asserted that this must be done in close coordination with all stakeholders to ensure harmonization with established global standards and ecolabels. The other respondent suggested EPA establish a formal timeline, application, and review process to facilitate approval and/or endorsement of new ecolabels and expressed support for an adjudicative process for ecolabel review that is fair and can be used to provide scientifically valid sustainability standards.
Response: This rule is revised to incorporate the EPA Recommendations as of October 2023. Future updates to the EPA Recommendations will be incorporated in the FAR via notice and comment to ensure industry has an opportunity to provide inputs on the incorporation of new standards, specifications, and ecolabels in the FAR and enough time to comply with the Recommendations.
EPA advises that it has a formal application and review process for the assessment of new standards and ecolabels for consideration for inclusion in the EPA Recommendations. EPA conducts assessments against EPA's Framework for the Assessment of Environmental Performance Standards and Ecolabels for Federal Purchasing, which was developed using a consensus-based process and went through several public comment periods. EPA also issues Federal Register notices inviting standards and ecolabels to apply for assessment. The Federal Register notice also included timeline targets for the current assessment process.
Public input regarding plans to assess and potentially add new standards and ecolabels to EPA's Recommendations are sought via issuance of a notice in the Federal Register (see 87 FR 66176, November 2, 2022). EPA recently issued a notice to seek input on possible product and/or service categories to add to the Recommendations and invited standards and ecolabel owners addressing these product and/or service categories to apply to be considered for assessment.
Comment: Several respondents stated that any environmental standards or ecolabels that are evaluated by EPA must have a public notice and opportunity for public comment. One of these respondents stated that the references to externally administered programs and recommendations subject contractors to shifting and unpredictable requirements. This respondent suggested that, given the lack of opportunity for companies whose products and services are subject to the EPA Recommendations to inform or challenge the EPA's decisions, the definition of sustainable products and services in this rule should be limited to those categories addressed in the designated statutory programs and the EPA Recommendations at the time of the rule's adoption, and that the FAR be amended through formal notice and comment to incorporate any subsequent changes. One respondent asked what the FAR Council will do to ensure that contracting officers and contractors are made aware that ecolabels have been added to the EPA Recommendations of Specifications, Standards, and Ecolabels for Federal Purchasing list. The respondent noted that contractors may not be aware that ecolabels that apply to their products and services are in the EPA Recommendations.
Response: Paragraph (2)(iii) of the definition of “sustainable products and services” at FAR 2.101 and in the clause at FAR 52.223-23 is revised to specify that products and services must meet the EPA Recommendations of Specifications, Standards, and Ecolabels in effect as of October 2023. The EPA website at https://www.epa.gov/greenerproducts/recommendations-specifications-standards-and-ecolabels-federal-purchasing now provides a search functionality to allow users to search for EPA recommended specifications, standards, and ecolabels in effect since October 2023. If EPA makes updates to its Recommendations in the future, the FAR will consider updating this paragraph and will seek notice and comment on such changes.
Comment: One respondent noted that the EPA Recommendations include endorsed third-party certifications for product end-of-life (such as the Biobased Products Institute certification for compostable products) and full product life cycle (such as Cradle to Cradle certification) and recommended that a third-party certification for products and services that reduce food waste be added to the EPA's Recommendations.
Response: This comment suggests expanding the EPA Recommendations of Specifications, Standards, and Ecolabels for Federal Purchasing, which are outside the scope of this rulemaking; however, these comments have been shared with the EPA.
Comment: One respondent stated that any environmental standards or ecolabels that are evaluated by EPA must be consensus standards as described by OMB Circular A-119, Federal Participation in the Development and Use of Voluntary Consensus Standards and in Conformity Assessment Activities.
Response: OMB Circular A-119 gives a preference for using voluntary consensus standards. Agencies are also directed to use private sector standards that are fit for purpose. If there are voluntary consensus standards, which are not fit for purpose, agencies have the authority to utilize non-consensus-based standards. EPA indicates on the Recommendations website which standards are voluntary consensus standards.
Comment: One respondent recommended that the EPA add a compost certification program to its Recommendations, such as the U.S. Composting Council's Seal of Testing Assurance, or recommend a compost testing protocol to site users, such as the Test Method for the Examination of Composting and Compost.
Response: This comment suggests expanding the EPA Recommendations of Specifications, Standards, and Ecolabels for Federal Purchasing, which are outside the scope of this rulemaking; however, these comments have been shared with the EPA.
Comment: One respondent requested clarification regarding which Federal agencies are involved in the administration and/or implementation of the EPA Recommendations, including the development of criteria for how products are included, and whether lead agencies will be required to coordinate with GSA and/or DoD.
Response: Paragraph (2)(iii) of the definition of “sustainable products and services” at FAR 2.101 and in the clause at FAR 52.223-23 is revised to specify that products and services must meet the EPA Recommendations of Specifications, Standards, and Ecolabels in effect as of October 2023. If EPA makes updates to its Recommendations in the future, DoD, GSA, and NASA will consider updating this paragraph and will seek notice and comment on such changes.
Comment: One respondent encouraged GSA, EPA, and other Federal agencies to prioritize working together to minimize any information gaps in identifying environmentally preferable products for sustainable acquisition.
Response: Noted.

f. Training and Outreach
Comment: Two respondents recommended that the Government allocate additional resources to training and technical assistance for the acquisition workforce to drive adoption of and successfully implement the rule in Government contracts. One of these respondents suggested drawing from state and local procurement efforts.
Response: These comments have been shared with the Federal Acquisition Institute (FAI) and the Defense Acquisition University (DAU). FAI and DAU are responsible for determining training requirements and identifying, creating, or updating training for the acquisition workforce to ensure understanding of the FAR requirements. Federal agencies also take steps necessary to educate their workforce regarding new or revised FAR requirements and provide additional guidance as appropriate for their specific mission and needs.
Comment: Two respondents supported Government training, assistance, education, and outreach to Federal suppliers to help them understand and successfully implement sustainable procurement requirements. One of these respondents suggested DoD, GSA, and NASA identify ways to improve education and outreach, with the objectives of expanding markets and advancing fairness and equity. The respondent noted that the education and outreach should be heavily focused on assisting small and medium-sized businesses as well as low-income communities, communities of color, and other vulnerable communities. The respondent also suggested the Administration announce an education and outreach plan with clear strategies, metrics, and timelines for helping disadvantaged businesses and communities fully participate in the transition to a more sustainable, clean energy economy that is underway, as well as actions to ensure meaningful participation from nongovernmental organizations and other representatives from disadvantaged businesses and vulnerable communities.
Response: Establishing an education and outreach plan or providing Government assistance and training to Federal suppliers is outside the scope of this rule. However, industry will benefit from the restructuring of FAR part 23 and consolidation of the purchasing preference programs requirements and procedures in FAR subpart 23.1, which lends itself to a better understanding of the Government's requirements for sustainable products and services. FAR 23.107 and 23.108 include links to lead agency websites where additional information on the specific program and, in some cases, additional training material is available. Paragraph (d) of clause at FAR 52.223-23 also includes a link to GSA's Green Procurement Compilation available at https://sftool.gov/greenprocurement , which is a publicly available research tool that may be used to better understand which programs apply to products and services procured by the Government. Also, FAR sections 23.107-1 and 23.107-2 require agencies to, as part of their affirmative procurement programs, promote recovered materials and biobased product preference programs. Finally, it is anticipated that industry may also benefit from any new or updated training developed by FAI or DAU in response to this FAR rule.

3. Special Requirements for Paper
Comment: One respondent expressed support for the proposed changes to remove special requirements for paper on the basis that e-commerce is now the primary means of conducting acquisition-related activities, printing double-sided on recycled paper is a common practice, and agencies will be required to procure products (including paper) that meet the minimum recovered material content standards established by EPA's CPG Program.
Response: Noted.
Comment: One respondent commented that increased recycled content mandates beyond those set in the U.S. Environmental Protection Agency's Comprehensive Procurement Guidelines, especially 100 percent recycled content in products, should be avoided for paper and paper packaging. The respondent asserted that such mandates ignore performance requirements and are not necessary given the circular nature of paper and paper packaging.
Response: This rule does not increase recycled content mandates beyond those set by EPA's CPG Program.
Comment: One respondent expressed concern about the proposed removal of the clause at FAR 52.204-4, Printed or Copied Double-Sided on Postconsumer Fiber Content Paper, which addresses contractor-submitted paper document requirements. The respondent questioned whether removal of the clause would result in less double-sided printing and copying on recycled paper when paper documents are used. The respondent suggested adjusting the definition of “contract action” to address paper requirements, as an alternative to retaining the clause.
Response: The requirement to print or copy double-sided on postconsumer fiber content paper was based on direction provided in E.O. 13423, Strengthening Federal Environmental, Energy, and Transportation Management, and E.O. 13514, Federal Leadership in Environmental, Energy, and Economic Performance, both of which have been rescinded. In addition, electronic commerce is the predominant mechanism for conducting acquisitions since agencies are required to use electronic commerce in contracting whenever practicable or cost-effective in accordance with FAR 4.502.

4. Construction
Comment: One respondent expressed support for the proposed changes to FAR part 36 to ensure that Federal construction and modernization projects meet or, wherever practicable, exceed CEQ's Guiding Principles. The respondent noted several benefits to incorporating CEQ's Guiding Principles, to include increasing efficiency, optimizing performance, eliminating unnecessary use of resources, ensuring the health of occupants, protecting the environment, generating cost savings, and mitigating risks to assets.
Response: Noted.
Comment: Another respondent suggested incentivizing the use and incorporation of whole building life-cycle assessments in procurement to understand the overall impacts of a particular building and the project's products by utilizing GSA's Facilities Standards for the Public Buildings Service (P100) section 1.9.2.9 on Decarbonization. The respondent noted that taking a holistic view enables buildings to be designed with significantly lower carbon footprints through smart material selection across multiple product categories throughout the project. In particular, the respondent noted the potential benefits of wood products.
Response: GSA's Facilities Standards for the Public Buildings Service (P100) establishes mandatory performance-based standards and prescriptive requirements that design and construction professionals must use in the programming, design, and documentation of GSA buildings. While other Federal agencies and the commercial construction industry look to the P100 as a leadership design standard, it applies only to buildings under GSA's jurisdiction, custody, and control and lease construction facilities that GSA intends to own or has an option to purchase.
FAR 36.104(b) directs agencies to ensure compliance with the Guiding Principles for Sustainable Federal Buildings (Guiding Principles), available at https://www.sustainability.gov/pdfs/guiding_principles_for_sustainable_federal_buildings.pdf. The Guiding Principles provide a consistent governmentwide portfolio approach for Federal agencies to design, mitigate, and measure the impact of their buildings. The Guiding Principles incentivize use of holistic sustainable design practices in material selection through several sections:
• New Construction and Modernization (NC&M) Criteria 5.1 and Existing Building (EB) Criteria 5.1 require that agencies use Resource Conservation and Recovery Act (RCRA) section 6002 compliant products that meet or exceed EPA's Comprehensive Procurement Guideline Program.
• NC&M Criteria 5.2 and EB Criteria 5.2 require that agencies implement a policy and verify procedures are in place to procure and use USDA BioPreferred® products, which are designated products with the highest biobased content level per USDA's recommendations.
• NC&M Criteria 5.3 and EB Criteria 5.3 require that agencies verify that a policy or procedures are in place to procure and use products recommended under EPA's Recommendations of Specifications, Standards, and Ecolabels for Federal Purchasing, as appropriate and applicable. Option 2 of this same criterion also allows agencies with renovation projects to meet this guiding principle by conforming to 2018 International Green Construction Code (IgCC) Section 901.4.1.4 (9.4.1.4) Multiple-Attribute Product Declaration or Certification.

5. Other Approaches

a. General
Comment: Two respondents commented generally on the Government's approach to sustainable procurement. One respondent suggested that the rule define sustainability and provide criteria for determining the sustainability of a product or service that agencies should consider. The respondent suggested that, when evaluating the sustainability of a product or service, agencies should consider factors such as the results of a life-cycle assessment, environmental impact, social responsibility, circular economy, etc. The other respondent urged the FAR Council and the EPA to allow contractors to identify the most efficient and effective pathways to show compliance with the sustainability provisions of the FAR and avoid adopting a “one size fits all” approach for assessing contractors' compliance with Federal sustainability requirements through the rulemaking process.
Response: This rule seeks to implement statutory and other EPA purchasing program requirements. Federal agencies benefit from the efforts of DOE, USDA, and EPA in that they can easily and efficiently identify sustainable products and services for procurement versus duplicating these efforts by assessing viable specifications, standards, and ecolabels on a contract-by-contract or agency-by-agency basis. However, nothing in this rule prohibits an agency from considering other factors when procuring products and services that meet their mission needs.
Comment: Several respondents recommended expanding the rule to encourage the Federal Government to promote circular economy approaches by its vendors, which keeps products and materials in circulation through processes like maintenance, reuse, refurbishment, remanufacture, recycling, and composting. One respondent emphasized that the sustainability of a product depends on not only how the product is manufactured, but also how it is disposed of and whether it brings benefits ( e.g., diversion from landfill, compost, recyclability, reuse) or causes harm.
Response: These comments are outside the scope of the current rulemaking but have been shared with the CEQ.
Comment: One respondent stated that the definition of “diversion,” which relies on CEQ instructions, fails to specify composting of organic waste that is not recoverable. This respondent recommended that the definition of “diversion” be revised to include composting and that the rule more clearly specify how Government purchasing decisions can support these end-of-life benefits.
Response: FAR 36.001 provides a definition of “diverting,” which is developed based on CEQ's Implementing Instructions. Adjustment of this definition is not appropriate since this definition is provided for the purposes of construction. However, the respondent's suggestion regarding adjustment of the definition has been shared with CEQ.

b. Measure and Report on Progress
Comment: Several respondents recommended or supported specifying how agencies should measure and report their progress and performance in procuring sustainable products and services. Some of these respondents asserted that the lack of measurement and reporting mechanisms could limit the accountability, transparency, and effectiveness of the rule. These respondents suggested that the rule should require agencies to establish and report on specific goals, objectives, benchmarks, and metrics for sustainable procurement, such as percentage of spending, number of contracts, and greenhouse gas emissions.
Response: The respondents' comments are noted and will be taken into consideration for future efforts as the Government seeks to advance sustainable acquisition objectives. Internal Government measuring, benchmarking, goaling, and other efforts are frequently addressed via internal procedures rather via regulatory language.
Comment: One respondent encouraged GSA to develop and implement a plan to establish stronger Federal data standards and protocols for ecolabel certifications. This respondent acknowledged that such an effort is outside the purview of the FAR Council but emphasized the importance of creating a Federal green data standard and data collection protocol.
Response: As the respondent noted, such activities are outside the scope of this FAR rule; however, the comments will be taken into consideration for future efforts as the Government seeks to advance sustainable acquisition objectives.
Comment: Two respondents suggested that the rule should have stronger verification and enforcement mechanisms. One of these respondents stated that the current framework, including the requirement for agency affirmative procurement programs, is not working. Both respondents suggested that there should be regular audits and assessments of agencies' adherence to and contractor performance in sustainable procurement requirements.
Response: The respondents' comments are noted and will be taken into consideration for future efforts as the Government seeks to advance sustainable acquisition objectives. This rule continues to implement the statutory requirement for agencies to establish affirmative procurement programs to promote a preference for biobased products (see content at FAR 23.107-2 of this rule, which was previously implemented at FAR subpart 23.4). Internal Government tracking can be done external to the regulation, such as in Executive Order 14081, Advancing Biotechnology and Biomanufacturing Innovation for a Sustainable, Safe, and Secure American Bioeconomy, which reinforces the requirements for agency affirmative procurement programs, and addresses implementation of biobased products procurement, including agency efforts for biobased-only contracts.
Comment: Two respondents supported stronger transparency requirements. One respondent suggested that there should be an annual public announcement of sustainable procurement performance metrics by Federal agencies. Another respondent suggested that written decisions to not procure sustainable products and services, and other data should be stored in an easily searchable, publicly accessible website. This respondent further suggested that GSA should prepare and publish a biannual evaluation and analysis of decision documents and related materials and recommend improvements to Federal sustainable procurement policies and procedures.
Response: The respondents' comments are noted and will be taken into consideration for future efforts as the Government seeks to advance sustainable acquisition objectives. Internal Government measuring, benchmarking, goaling, and other efforts are frequently addressed with internal procedures rather than regulatory language.
Comment: Several respondents recommended that FAR clause 52.223-2, Reporting of Biobased Products Under Service and Construction Contracts, be updated to include supply contracts. Two of these respondents also recommended that agencies should be required to report the types and dollar amounts of biobased products purchased to obtain information necessary to assess uptake and gaps, or to improve innovation.
Response: This is outside the scope of this FAR rule, which does not seek to modify existing biobased requirements.
Comment: One respondent suggested that suppliers should be expected to report in pounds the amount of recovered material used in the products acquired by the Government. This respondent also suggested that, when there are supply gaps, suppliers should be required to show proof of how they will procure recovered materials, instead of just resorting to virgin materials. The respondent further advocated for a supplier feedback or scorecard program, as well as incentives to encourage suppliers to innovate to use higher percentages of recovered materials and to secure future supply to meet those higher thresholds.
Response: Nothing in this rule prohibits agencies from pursuing other environmentally preferable products and services beyond those specified in the definition of “sustainable products and services.” Agencies also have flexibility to determine what incentives and evaluation criteria to use when evaluating offerors' proposals.

c. Other Environmentally Preferable Products and Services
Comment: One respondent suggested the requirement to procure sustainable products and services, as defined, to the maximum extent practicable, should be the basic requirement. The respondent stated that the rule should clarify that agencies and contracting officers are permitted to or should procure environmentally preferable products and services beyond those subject to statutory or other EPA purchasing program requirements to promote the policy objectives of E.O. 14057.
Response: Nothing in this rule prohibits agencies from pursuing other environmentally preferable products and services beyond those specified in the definition of “sustainable products and services.”
Comment: Several respondents submitted comments related to promoting reuse programs over single use. Comments from two respondents focused on increasing reusable products or packaging, which may be more environmentally impactful than using recovered materials. These respondents suggested that the FAR identify where reusable products should be prioritized, such as pallets, conference supplies, food service items, office products, composite railroad ties and decking, storage containers, crates, and other durable goods. The other respondent requested that the FAR explicitly discourage the purchasing of single-use plastic products to the maximum extent practicable and prioritize and refillable alternatives.
Response: These comments are outside the scope of the current rulemaking but have been shared with the CEQ.
Comment: Several respondents requested that the definition of sustainable products and services be expanded to cover sustainable food procurement. Some of these respondents suggested requiring agencies to hire food service contractors that follow the principles of EPA's Food Recovery Hierarchy to prevent food waste. The respondents generally acknowledged that the FAR contains at subpart 26.4 a requirement to donate any wholesome, surplus food; however, the respondents expressed concern about nondonatable food being diverted from going to landfills. Another respondent suggested that the EPA Recommendations for Specifications, Standards, and Ecolabels should be expanded to cover climate-friendly food and food services. Another respondent offered recommendations for ways in which GSA should look to structure its procurement of food and food service contracts.
Response: These comments are outside the scope of the current rulemaking but have been shared with the CEQ, EPA, and GSA.
Comment: Several respondents also made comments related to composting. Two respondents stated that agencies should prioritize purchasing finished compost products, noting that purchasing compost has a direct environmental benefit, as well as positive downstream effects by supporting compost end markets. Another respondent suggested that food scraps should be recycled at organics recycling processing facilities, such as composting facilities or anaerobic digestion facilities that produce digestate that is then composted and noted the benefits of such soil amendments when added to the land. Several respondents suggested that the EPA add a compost certification program to its Recommendations of Specifications, Standards, and Ecolabels, such as the U.S. Composting Council's Seal of Testing Assurance Program (STA) or recommend a compost testing protocol to site users such as the Test Method for the Examination of Composting and Compost.
Response: These comments are outside the scope of the current rulemaking but have been shared with the EPA. EPA has designated the landscaping products, including compost, under the CPG Program to promote the use of materials recovered from municipal solid waste. See the EPA web page at https://www.epa.gov/smm/comprehensive-procurement-guidelines-landscaping-products.
Comment: One respondent noted that there are opportunities beyond the referenced purchasing programs to address the materials manufacture, production, and waste management stages of product life. The respondent suggested expanding sustainable products to include products that have the following attributes: manufactured with renewable energy; sourced with upstream agricultural interventions or from deforestation-free supply chains; reuse systems; or end-of-life and waste management, including whether products are recyclable and compostable.
Response: These comments are outside the scope of the current rulemaking but have been shared with the CEQ, EPA, and GSA. Nothing in this rule prohibits agencies from pursuing other environmentally preferable products and services beyond those specified in the definition of “sustainable products and services.”

d. Impact Assessments
Comment: Several respondents made recommendations to expand the rule to require agencies to consider environmental and social benefits and costs of their procurement decision. One respondent suggested that the FAR encourage inclusion of the social costs of carbon and, eventually, plastic in decision making, particularly regarding any guidance to reduce single-use plastics. Another respondent suggested that agencies could go further to consider indirect social equity and justice issues (such as risks of labor exploitation, deforestation, or other harmful practices) throughout the supply chain that impact sustainability beyond the direct purchase.
Response: These comments are outside the scope of the current rulemaking. This rule is focused on requiring agencies to procure sustainable products and services, as defined in the rule, to the maximum extent practicable. The respondents' suggestions are similar to inputs received in response to the advance notice of proposed rulemaking published under FAR Case 2021-016, Minimizing the Risk of Climate Change in Federal Acquisitions (see 86 FR 57404, October 15, 2021). The FAR Council is currently considering those public inputs as it develops a proposed rule under that FAR Case. The FAR Council notes that nothing in this final rule prohibits agencies from pursuing other goals beyond those specified in the definition of “sustainable products and services.”
Comment: Two respondents cautioned against incorporating rigid life-cycle assessment (LCA) methodologies. One of these respondents emphasized the need for agencies to have flexibility and remain adaptive to newer techniques as they become available. Another respondent noted that the assessment of greenhouse gas emissions under LCAs should be supplemented with other analyses regarding reduced packaging, alternative delivery systems, and alternative materials to understand the performance of these alternatives in the context of broader energy system decarbonization.
Response: These comments are outside the scope of the current rulemaking. This final rule does not implement a requirement for agencies to conduct life-cycle assessments (LCA) or mandate specific LCA methodologies. Rather, this final rule advises agencies, when considering whether the price of a sustainable product is reasonable, that they should consider whether the product is cost-effective over the life of the product (see FAR 23.103(a)(2)). The respondents' comments are similar to inputs received in response to the advance notice of proposed rulemaking published under FAR Case 2021-016, Minimizing the Risk of Climate Change in Federal Acquisitions (see 86 FR 57404, October 15, 2021). The FAR Council is currently considering those public inputs as it develops a proposed rule under that FAR Case.

6. Comments on Interim Rule
The following is a summary of public comments received on the interim rule published in 2011, which is finalized by this rule.

a. General
Comment: Some respondents were supportive of the interim rule and the Government's leadership in advancing sustainable acquisition goals, while others were unsupportive of the use of an interim rule for this purpose.
Response: Support for the overarching policy objective is noted. The decision to use an interim rule for initial implementation of the requirements for sustainable acquisition were justified in the interim rule. Given that the requirements of the interim rule have been in place since 2011, DoD, GSA, and NASA sought public comments on making further changes to the interim rule prior to finalizing the interim rule.

b. Applicability
Comment: Two respondents expressed concerns regarding the previous 95 percent target at FAR 23.103. One respondent recommended a phased approach in implementation of the objective to allow for development of intermediate steps that include educating the acquisition workforce on sustainable acquisition, identification of sustainable products and services, and development of supporting agency processes. Another respondent believed that each agency should be given the flexibility to determine how to impose the requirements on its acquisitions.
Response: Implementation of the interim rule in 2011 was supplemented with training for the acquisition workforce and efforts to ensure that agencies are identifying sustainable products and services. This final rule achieves governmentwide efficiencies by pointing agencies to specifications, standards, and ecolabels that are required by statute or recommended by the EPA. The alternative would require each agency or procurement office to conduct such market research on a contract-by-contract basis. The rule also includes procedures to provide flexibility to agencies when sustainable products and services do not meet the agency's performance requirements or cannot be procured in a timely manner at a reasonable price.
Comment: Several respondents requested clarifications regarding applicability of the sustainable procurement requirements to multiple-award contracts, such as the GSA Multiple Award Schedule, and questioned whether compliance with the 95 percent target would be measured at the contract-level or the order-level.
Response: This rule replaces the 95 percent target with the requirement for agencies to procure sustainable products and services to the maximum extent practicable. The sustainable products and services that apply to the acquisition will be incorporated into the statement of work or other requirement document and incorporated into the solicitation and contract. For multiple-award contracts or governmentwide acquisition contracts, the contracting officer for the contract will need to ensure all potential sustainable products and services that may be ordered under the contract are listed in the solicitation and resulting contract, while ordering agencies will need to specify in their statement of work or other requirement document the sustainable products and services that apply to their task order or delivery order under the contract.
Comment: Two respondents requested that the rule be revised to require the Government advance sustainable acquisition “where such products and services meet agency performance requirements.”
Response: This rule provides procedures and FAR 23.104(a) when sustainable products and services do not meet the agency's reasonable performance requirements.
Comment: One respondent commented that the language at FAR 12.102 is unclear and inconsistent. The respondent stated that FAR part 12 should govern the acquisition of commercial items and that Government-unique acquisition requirements should be prohibited when acquiring commercial items.
Response: FAR part 12, Acquisition of Commercial Products and Commercial Services, implements the Federal Government's preference for the acquisition of commercial products and commercial services. FAR 12.102(c) states that contracts for the acquisition of commercial products or commercial services are subject to the policies in other parts of the FAR; however, FAR part 12 takes precedence for the acquisition of commercial products or commercial services, when other parts are inconsistent with FAR part 12. The requirements in FAR subpart 23.1 do not conflict with FAR part 12. This rule applies to the acquisition of commercial products and commercial services to the extent that sustainable products and services are available to meet the Government's needs.
Comment: A respondent recommended adding exceptions in the rule for repair of existing building infrastructure, systems, and components that are not designated as sustainable and still have a useful life and products for which no formal environmental label is available.
Response: The exceptions and exemptions cited in FAR 23.105 and 23.106 are based on law or provided by Executive order. This rule does not prohibit agencies from procuring products where no formal environmental label is available.
Comment: One respondent expressed concern that the rule lacks flexibility for approving new technologies, such as emerging technologies that may not qualify as providing a “renewable” resource, despite the obvious nature of the energy product being renewable.
Response: This rule revises FAR subpart 23.1 to focus on procedures for procuring sustainable products and services, which include those that are ENERGY STAR® or FEMP-designated products and services, a statutory requirement. Language regarding renewable technologies is removed.
Comment: Two respondents recommend reconsideration of applicability of the requirements for energy efficiency, water efficiency, and renewable energy below the micro-purchase threshold. One of these respondents suggested that the policy only apply above the simplified acquisition threshold.
Response: The requirement to procure energy- and water-efficient products that are ENERGY STAR® certified or FEMP-designated products is based in statute (see 42 U.S.C. 8259b and the implementing regulations at 10 CFR part 436 subpart C). This rule continues to apply these requirements to acquisitions valued at or below the simplified acquisition threshold and micro-purchases to ensure agencies are achieving energy savings, while also protecting the environment.
Comment: One respondent requested clarification regarding how the rule will apply to service contracts. The respondent requested advice as to how the rule will impact the selection of service providers and by what metrics service providers will be measured during performance.
Response: Applicability to service contracts is described at FAR 23.103(c) and in the clause at FAR 52.223-23. Under service contracts, the contractor is required to provide products that meet the definition of sustainable products and services, if the products are delivered to the Government, furnished for use by the Government, incorporated into the construction of a public building or public work, or acquired by the contractor for use in performing services under a Government contract where the cost of the products is a direct cost to a Government contract. Agencies have discretion on how to monitor a contractor's compliance with this term and condition during performance of the contract.
Comment: One respondent stated that a preference for “environmentally friendly” products will require a phase-in period to develop agency processes, identify products, develop technologies, address availability, and educate the acquisition workforce.
Response: The FAR has addressed environmental programs (use of biobased, energy-efficient, environmentally preferable, and recycled products) in FAR subpart 23.2, Energy and Water Efficiency and Renewable Energy, subpart 23.4, Use of Recovered Materials and Biobased Products, subpart 23.7, Contracting for Environmentally Preferable Products and Services, and subpart 23.8, Ozone-Depleting Substances, for many years at this point.
Agencies will need to monitor updates to specifications, standards, and ecolabels covered by the definition of sustainable products and services as they define their requirements. Per paragraph (b)(3) of the clause at FAR 52.223-23, offerors will need to ensure that their offers comply with the specifications, standards, and ecolabels in effect at the time of quote or offer submission, except for the EPA Recommendations of Specifications, Standards, and Ecolabels, which are those in effect as of October 2023. Future updates to the EPA Recommendations will be incorporated into the FAR via formal rulemaking to obtain notice and comments on the recommended specifications, standards, and ecolabels, and to allow enough time for industry to come into compliance.

c. Definitions
Comment: One respondent requested that a definition be added for “reasonable price” and “cost-effective,” as addressed in FAR 23.403. The respondent was concerned that contracting officers will purchase a cheaper product based on initial price and suggested adding policy to allow the purchase of products which are environmentally preferable but have a price up to 10 percent higher than a product that is not environmentally preferable.
Response: Applying a price premium does not align with some of the statutory requirements to consider life-cycle costs. Instead, FAR 23.103(a) is revised to clarify that, when considering whether the price of a sustainable product is reasonable, agencies should consider whether the product is cost-effective over the life of the product.
Comment: Two respondents requested revisions to the definition of “environmentally preferable” at FAR subpart 23.7. One respondent suggested adding more suggestions of environmentally preferable items. Another respondent recommended deleting EPEAT® from the list of examples in the definition of “environmentally preferable.”
Response: The definition of “environmentally preferable” in FAR 2.101 is updated to provide a reference to the source of the definition, which is based in statute (section 314 of Pub. L. 107-314, 10 U.S.C. Chapter 223 note). As used in FAR subpart 23.1, this term refers to environmentally preferable products and services that meet EPA Recommendations for Specifications, Standards, and Ecolabels (see FAR 23.108-3). EPEAT® is no longer referenced by name, but remains an EPA recommendation, and therefore required, for electronic products.
Comment: Several respondents commented on definitions related to renewable energy and use of those terms. One respondent noted that the definition of “renewable energy” does not include hydroelectric energy, new pumped hydro storage, or energy storage technologies. Two respondents also found the definition of “biomass” to be inadequate. One respondent suggested revisions to align 7.103(p)(2) with 11.002(d) regarding use of products and services that utilize “renewable energy technologies.”
Response: This rule revises the FAR in a manner that no longer uses the terms “renewable energy” and “renewable energy technology.” As such these definitions are removed from FAR 2.101. This rule also revises FAR 7.103(p) and 11.002(d) to now refer more generally to the requirements for sustainable products and services in FAR subpart 23.1.
Comment: One respondent suggested that the FAR rule should make clear that the policy applies to “construction,” in addition to the acquisition of supplies and services. The respondent suggested, for example, that the definition of “sustainable acquisition” at FAR 2.101 should be revised to state “acquiring . . . and services, including construction.”
Response: Adjustment to the definition of “sustainable procurement” is not necessary. The new omnibus clause at FAR 52.223-23, Sustainable Products and Services, is prescribed for use at FAR 23.109(a) in all solicitations and contracts, unless there is a written justification from the requiring activity or an authorized exception or exemption. The clause directs contractors to incorporate sustainable products and services, as specified in the contract, into the construction of a public building or public work.
Comment: Several respondents commented on the definition of “contract action.” Two respondents expressed concerns about a separate definition for FAR part 23. One of these respondents objected to the inclusion of “oral action.” Another respondent noted that “contract action” is defined, but also described in another section for the purposes of achieving the 95 percent target; the respondent noted that the definition includes micro-purchases, but the description does not.
Response: This definition previously mirrored the definition of “contract action” at FAR 4.601, except to clarify that it includes “oral or written actions” valued at or below the micro-purchase threshold. It is necessary to retain a definition of “contract action” for the purposes of specifying applicability of the requirement to procure sustainable products and services under contract actions for services. However, the definition is revised to remove the reference to “micro-purchases” and other information that is not necessary for the purposes of the subpart. FAR 13.201(f) clarifies that the requirements of FAR subpart 23.1 apply to micro-purchases.
Comment: Two respondents found the definition of “sustainable acquisition” at FAR 2.101(b)(2) overly broad and thought it may lead to misinterpretation. The respondent expressed special concern about the phrase “social, economic and other requirements” because, according to the respondent, this phrase “is not commonly used in the context of federal procurement.”
Response: No changes to the definition are necessary. The term aligns with one of the FAR guiding principles at FAR 1.102(d) to fulfill public policy objectives. The term is also used as an overarching term; specific requirements related to “sustainable acquisition” are found in the streamlined subparts of FAR part 23.

d. Compliance
Comment: Several respondents expressed concerns about the use of EPEAT® standards. One of these respondents recommended that references to EPEAT® should be replaced with individual standards. Others suggested that the Government rely on the underlying technical standards used by EPEAT®. Another respondent believed the embedded references to EPEAT® could result in time-to-market delays and additional costs that could reduce the competitiveness of U.S. products.
Response: This rule removes specific references to EPEAT® from the FAR and instead references the EPA Recommendations of Specifications, Standards, and Ecolabels as of October 2023. EPA continues to recommend EPEAT® for electronic products; however, the Recommendations could be expanded to cover additional ecolabels in this space.
Comment: Two respondents expressed support for utilizing Federal Procurement Data System (FPDS) data to measure and assess the effect of Federal contracting to promote sustainable acquisition.
Response: Noted.
Comment: One respondent noted that there are FAR clauses addressing recycled, biobased, and energy-efficient products, and recommended additional FAR clauses to address water-efficient, non-ozone depleting, and environmentally preferable products.
Response: As a result of this rule, the requirements for procuring sustainable products and services, to include those that meet statutory purchasing program requirements and those that meet other EPA purchasing programs, are consolidated into a single omnibus clause at FAR 52.223-23.
Comment: One respondent requested a new contract clause to require contractors to report all types of green products purchased under construction and service contracts, similar to the reporting requirement under FAR clause 52.223-2, now titled “Reporting of Biobased Products Under Service and Construction Contracts.”
Response: The Government will continue to leverage information reported to the FPDS, the System for Award Management (SAM), or directly to the agency, such as the reports under FAR clause 52.223-2 and 52.223-9, Estimate of Percentage of Recovered Material Content for EPA-designated Items, in lieu of including new contractor reporting requirements at this time.
Comment: One respondent recommended that FAR 11.002(d)(2), which requires documentation of an exception when acquiring sustainable products and services, specify the responsible approving official and state whether the documentation should be included in the contract file.
Response: FAR 11.002(d)(2) requires that agencies incorporate sustainable products and services when describing agency needs unless it is not practicable. FAR 23.104(a) allows the contracting officer to consider it not practicable to procure sustainable products and services if the requiring activity submits a written justification addressing the reasons it is not practicable as described at FAR 23.103(a). FAR 23.104(a) also requires the contracting officer to maintain the written justification in the contract file.

e. Other Comments
Comment: Two respondents commented on the overarching policy statement at FAR 23.002. One respondent expressed concern regarding the overarching policy statement at FAR 23.002, which did not include or reference Environmental Management Systems (EMS) requirements. Another respondent recommended using the introductory policy statement at FAR 23.202 as the introduction for the part.
Response: The overarching policy statement for FAR part 23, continues to be located at FAR 23.002, but has been revised to align with the current direction provided in E.O. 14057. It is not necessary to restate the specific policy objective of each subpart in this section.
Comment: Several respondents commented on the requirements for EMS. Two respondents believed that EMS plans will vary from agency to agency and may contradict one another or create overly burdensome requirements. Two respondents suggested that the rule should require the contracting officer to incorporate the EMS requirements into the contract so that the contractor is aware of these requirements prior to award. One of these respondents suggested that the rule state that EMS requirements are provided by the requiring activity.
Response: The requirements for EMS previously at FAR subpart 23.9 have been consolidated with other Federal facility requirements in FAR subpart 23.4. FAR section 23.404 now states that agencies may implement an EMS when it aligns with and supports its agency's mission needs and facilitates implementation and progress toward E.O. 14057 goals. When doing so, the rule requires that EMS requirements be included in the contract to ensure proper implementation and execution of EMS roles and responsibilities. How agencies incorporate specific EMS requirements remains at the discretion of the agency.
Comment: One respondent requested that the web address for the Guiding Principles for Federal Leadership in High-Performance and Sustainable Buildings (“Guiding Principles”) at FAR 7.103(p)(3) be replaced with the text of the guiding principles.
Response: This final rule revises FAR 7.103(p)(3) and 36.104(b)(1) to replace the reference to the Guiding Principles for Federal Leadership in High-Performance and Sustainable Buildings with a reference to the current Guiding Principles for Sustainable Federal Buildings and Associated Instructions. It is standard practice in the FAR to provide a link to a referenced guidance document in lieu of summarizing or repeating the content in the FAR.
Comment: Several respondents requested clarification regarding changes to the paper content requirements in FAR 11.303 and the clause at FAR 52.204-4.
Response: Both FAR 11.303 and the clause at FAR 52.204-4 are removed as a result of this rule.
Comment: One respondent asked whether it was clear that contractors are to submit documents electronically whenever possible.
Response: The policy at FAR 4.502(a) to use electronic commerce “whenever practicable or cost-effective” has been in effect since October 30, 1998 (see 63 FR 58590) and was not impacted by the interim rule or proposed rule.
Comment: One respondent suggested that information should be disseminated about the availability of resources and procurement-based tools for biobased products. The respondent listed a few web-based training videos and templates created by the USDA.
Response: FAR subpart 23.1, Sustainable Products and Services, now includes links to each purchasing program website where resources, training, and information for both buyers and sellers is available. A link to https://www.biopreferred.gov and an instruction to consult an agency's affirmative procurement program are provided at FAR 23.107-2(f). This rule also encourages requiring activities, contracting officers, and contractors to consult GSA's Green Procurement Compilation available at https://sftool.gov/greenprocurement, when determining which purchasing programs apply to a specific product or service (see FAR 11.002, 23.104(d), and 52.223-23(d)). This tool provides a comprehensive list of sustainable products and services and other related sustainable acquisition guidance.
Comment: One respondent expressed concerns regarding the disposal of spent batteries generated by operations funded by, or conducted for, the Federal Government.
Response: This comment is outside the scope of both the 2011 interim rule and this final rule.
Comment: One respondent requested that the phrase “availability of competition” in the first sentence of FAR 23.403 be revised to state “availability” only. The respondent stated that the phrase “availability of competition” is not used in section 6002 of the Resource Conservation and Recovery Act of 1976 and that “availability” and “competition” are separate concepts that should not be merged.
Response: As a result of this rule, the content of FAR 23.403 is removed. Requirements for procuring sustainable products and services, including products containing recovered material and biobased products, to the maximum extent practicable are now located in FAR subpart 23.1. Per the policy at FAR 23.103(a)(1)(i), procuring sustainable products and services is considered practicable, unless the agency cannot acquire the products or services competitively within a reasonable performance schedule. This new language addresses the respondent's concern by not confusing availability of a product or services with availability of competition.
Comment: One respondent suggested that, at FAR 23.803(b)(2), the word “safe” be replaced by the word “acceptable” to align with the EPA SNAP web page, and because the term “safe,” according to the respondent, seemed ambiguous and undefined.
Response: The respondent's suggestion was already addressed by the final rule for FAR Case 2014-026, High Global Warming Potential Hydrofluorocarbons, published at 81 FR 30429 on May 16, 2016. As a result of this rule, the content of FAR 23.803 has been transferred to FAR 23.108-4; the section continues to use the term “acceptable.”
Comment: One respondent requested removal of FAR 23.205(a) directing agencies to maximize the use of energy savings performance contracts, when life-cycle cost-effective to reduce energy use and cost in the agency's facilities and operations. The respondent stated that the E.O. that supported such a statement had been revoked.
Response: As a result of this rule, FAR 23.205(a) has been transferred to FAR 23.202(a). This content is not removed; the authority for agencies to use energy savings performance contracts is based on the National Energy Conservation Policy Act (42 U.S.C. 8287).
Comment: One respondent suggested adding FAR subpart 23.8 to the list of subparts that apply to micro-purchases.
Response: As a result of this rule, the purchasing program requirements in FAR subpart 23.8 have been consolidated with the other purchasing programs in FAR subpart 23.1 (see FAR 23.107-4 of this rule). Based on this consolidation, it is no longer necessary to separately cite the subparts for each purchasing program at FAR 13.201(f). As a result of this rule, FAR 13.201(f) now states that the procurement requirements in FAR subpart 23.1 apply to purchases at or below the micro-purchase threshold.

7. Greenhouse Gas Emissions
Comment: One respondent expressed support for the Government's goal of doing business with the most sustainable suppliers; however, the respondent recommended, if the Government intends to consider corporate sustainability (for example through a responsibility determination as contemplated by FAR Case 2021-015), then the Government should consider existing corporate investments in sustainability performance, rather than adopting new or U.S. Government-specific corporate requirements. Another respondent suggested that the Government should allow contractors to utilize business-to-business cloud-based collaboration platforms and business networks accessible via public websites or mobile applications to satisfy the requirement in FAR 23.801(c) for certain contractors to provide the websites.
Response: This comment is outside of the scope of this rule, which does not make any substantive changes to the existing disclosure requirements.
Comment: One respondent supported the inclusion of FAR subpart 23.8 requiring the attestation of whether an offeror registered within SAM publicly discloses greenhouse gas emissions and whether the offeror publicly discloses greenhouse gas emissions reduction goals, as well as providing websites for such public disclosures. The respondent recommended that the rule be revised to, over time, require disclosure from all offerors outside of the current threshold of $7.5 million to encompass a more comprehensive supplier base.
Response: This comment is outside of the scope of this rule, which does not make any substantive changes to the existing disclosure requirements.
Comment: A suggestion was made by one respondent to remove the existing greenhouse gas emissions disclosure requirements at FAR subpart 23.8 and the provision at FAR 52.223-22 based on the revocation of E.O. 13693, Planning for Federal Sustainability in the Next Decade.
Response: This comment is outside the scope of this rulemaking, which is not creating a new disclosure requirement or making any substantive changes to the current disclosure requirements at FAR subpart 23.8 and the associated provision. In any event, while E.O. 13693 has been revoked, subsequent Executive orders continue the policy direction regarding greenhouse gas emissions. For example, E.O. 13990, Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis, discusses bolstering resilience to climate change. E.O. 14008, Tackling the Climate Crisis at Home and Abroad, provided direction to move quickly to build resilience, both at home and abroad, against the impacts of climate change that are already manifest and will continue to intensify according to current trajectories. E.O. 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, provides direction to improve the Nation's preparedness and resilience to the effects of a changing climate and establishes the target of net-zero emissions from Federal procurement by 2050. The existing FAR disclosure provisions, while not within the scope of this rule, are also well-grounded in statutory authority (see, for example, 41 U.S.C. 1303(d); 40 U.S.C. 121(c); 10 U.S.C. chapter 4 and 10 U.S.C. chapter 137 legacy provisions (see 10 U.S.C. 3016); and 51 U.S.C. 20113).
Comment: One respondent highlighted that EPA is reevaluating aspects of its Greenhouse Gas Reporting Program to improve the accuracy of greenhouse gas emissions data. The respondent noted that it submitted comments to EPA to express concern should EPA continue to use scientific approaches to ensure reported methane emission from landfills is accurate.
Response: This comment is outside the scope of this FAR rule.

8. Other Out of Scope
Comment: One respondent suggested that GSA employees should be allowed to bid on GSA auctions.
Response: This comment is outside the scope of this FAR rule.

III. Applicability to Contracts at or Below the Simplified Acquisition Threshold (SAT), for Commercial Products (Including Commercially Available Off-the-Shelf (COTS) Items), and for Commercial Services
The new clause at FAR 52.223-23, Sustainable Products and Services, is prescribed at FAR 23.109(a) for use in all solicitations and contracts, unless a justification, exception, or exemption applies to all potential sustainable products and services in an acquisition. The new omnibus clause is required to be included in covered solicitations and contracts valued at or below the simplified acquisition threshold and for commercial products, including COTS items, or commercial services. It is necessary to apply the requirements of this clause to these types of acquisition to achieve the intended policy outcome, which is for the Government to meet statutory purchasing program requirements and to procure sustainable products and services under required EPA purchasing programs to the maximum extent practicable.
The following FAR clauses are removed by this final rule and will no longer be listed in FAR clause 52.212-5, Contract Terms and Conditions Required To Implement Statutes or Executive Orders—Commercial Products and Commercial Services, as applicable to acquisitions of commercial products or commercial services:
• FAR 52.223-13, Acquisition of EPEAT®-Registered Imaging Equipment, and its Alternate I.
• FAR 52.223-14, Acquisition of EPEAT®-Registered Televisions, and its Alternate I.
• FAR 52.223-15, Energy Efficiency in Energy-Consuming Products.
• 52.223-16, Acquisition of EPEAT®-Registered Personal Computer Products, and its Alternate I.
Since it is being removed, FAR clause 52.223-15 will also no longer be listed in 52.213-4, Terms and Conditions—Simplified Acquisitions (Other Than Commercial Products and Commercial Services), as applicable to simplified acquisitions. Though these clauses are removed from the FAR the requirement to procure energy-efficient products and produces that meet EPA Recommendations of Specifications, Standards, and Ecolabels, such as EPEAT®, remains; these requirements continue to be implemented via the omnibus clause at FAR 52.223-23.
This rule does not include any changes to the existing prescriptions for other FAR part 23 solicitation provisions or contract clauses, except to renumber the section or paragraph where content has been relocated to a new FAR part or subpart.

IV. Severability
If any portion ( e.g., section, clause, sentence) of this rule is held to be invalid or unenforceable facially, or as applied to any entity or circumstance, it shall be severable from the remainder of this rule, and shall not affect the remainder thereof, or its application to entities not similarly situated or to other dissimilar circumstances. The various portions of this rule are independent and serve distinct purposes. Even if one aspect were rendered invalid, the other benefits of the rule would still be applicable. As an illustrative but not exhaustive example, were a court to stay or invalidate the changes to FAR subpart 23.1 regarding sustainable products and services, the agencies would intend the broader restructuring of FAR part 23 to remain effective.

V. Expected Impact of the Rule

A. FAR Part 23 Restructuring
The revisions to FAR part 23 establish a clear and simplified framework for the Government to communicate current requirements related to environmental matters and sustainable acquisition. First, non-environmental matters, such as drug-free workplace and banning texting while driving, are transferred to FAR part 26. Then, existing content on similar topics, such as requirements for sustainable products and services, hazardous and radioactive materials, and pollution prevention at Federal facilities, are consolidated into single subparts. These changes more clearly communicate current policies and procedures and are expected to improve agency compliance with requirements in each of these areas.

B. Sustainable Products and Services
In addition to consolidating existing statutory and other EPA purchasing program requirements in FAR subpart 23.1, this rule directs agencies to procure sustainable products and services to the maximum extent practicable. As stated in the proposed rule, the requirement to procure sustainable products and services is not new; agencies have been required to ensure that most of their contract actions meet statutory and other EPA purchasing program requirements for over a decade. This rule consolidates, streamlines, and updates the procedures for procuring sustainable products and services to ensure more effective communication and implementation of these requirements.
For example, agencies were previously required to include in 95 percent of new contract actions requirements for products that are energy-efficient; water-efficient; biobased; environmentally preferable, or non- or less toxic alternatives; non-ozone depleting; or made with recovered materials. They were also directed to maximize the use of environmentally preferable products and services based on EPA-issued guidance, promote water conservation, and give preference to the procurement of acceptable alternative chemicals and products that reduce overall risks to human health. This rule removes the 95 percent target and other generic directions and makes procuring sustainable products and services the default position. The process that allows agencies to explain why purchasing a sustainable product or service is not practicable in terms of performance requirements, availability, and price remains, but is expanded to all categories of sustainable products and services for uniformity and ease of implementation. The exceptions, such as those for acquisitions performed outside the United States, weapon systems, and space systems, and exemptions also remain, though the emergency response exemption previously at FAR 23.105(a)(3) is expanded at FAR 23.106(c).
This rule also provides a definition of “sustainable products and services” that helps Government agencies and suppliers better understand how to identify sustainable products and services. As illustrated in the following table, generic terms are supplemented with references to the applicable statutory or other EPA purchasing program requirements, standards, or ecolabels:
Product or service | Program/standard/ecolabel
Made with recovered materials | Products containing recovered material designated by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Procurement Guidelines.
Energy-efficient and water-efficient | Energy- and water-efficient products that are ENERGY STAR® certified or Federal Energy Management Program (FEMP)-designated products.
Biobased | Biobased products meeting the content requirement of the U.S. Department of Agriculture under the BioPreferred® program.
Non-ozone depleting | Acceptable chemicals, products, and manufacturing processes listed under EPA's Significant New Alternatives Policy (SNAP) program, which ensures a safe and smooth transition away from substances that contribute to the depletion of stratospheric ozone.
Water-efficient | WaterSense® labeled (water efficient) products and services.
Non-/less toxic alternatives | Safer Choice-certified products (products that contain safer chemical ingredients).
Environmentally preferable | Products and services that meet EPA Recommendations of Specifications, Standards, and Ecolabels.
Other information on statutory purchasing program requirements previously implemented at FAR subparts 23.2, 23.4, and 23.8 is consolidated at FAR 23.107. Agencies are required to continue ensuring that products and services meet statutory purchasing program requirements. Agencies are also directed to prioritize multi-attribute products and services, which are products and services that meet both statutory purchasing program and other EPA purchasing programs, to maximize environmental benefits.
Finally, this rule standardizes the way in which agencies communicate their requirements for sustainable products and services to contractors. This rule makes clear in FAR 11.002(d)(2) and 23.104(b) that agencies are required to identify in their requirement documents, such as the statement of work, the sustainable products and services that apply to the acquisition. A new omnibus clause at FAR 52.223-23, Sustainable Products and Services, notifies offerors and contractors that they are expected to ensure that the sustainable products and services required under the contract are delivered; furnished for Government use; incorporated into the construction of a public building or public work; and furnished for use in performing services, where the cost of the products is a direct cost to the contract. These changes will help the Government ensure it is meeting its goal to procure sustainable products and services to the maximum extent practicable to reduce emissions, save natural resources, and protect individuals, communities, and the environment.
According to data available in the Federal Procurement Data System for fiscal years 2019 through 2021, on average approximately 85,826 contractors are awarded Federal contracts each year, of which approximately 61,797 contractors are small businesses. These contractors should be familiar with the purchasing program requirements identified in this rule since agencies have been directed to procure these types of products and services for many years. However, contractors will no longer be required to review the stand-alone provisions and clauses at FAR 52.223-13, 52.223-14, 52.223-15, 52.223-16, and 52.223-17 removed under this rule, all of which provide varying instructions to contractors on the requirements for existing purchasing programs, such as ENERGY STAR®, FEMP, products containing recovered material, and EPEAT®-registered electronic products. This information is consolidated in the omnibus clause at FAR 52.223-23. For example, EPEAT® is no longer referenced by name in the FAR. Contractors will no longer see standalone FAR clauses on EPEAT®-registered electronic products (formerly FAR clause 52.223-13, 52.223-14, and 52.223-15) in solicitations and contracts. However, EPEAT® is one of EPA's Recommendations of Specifications, Standards, and Ecolabels, which means it is required for electronic products unless it is not practicable to procure such items (see 23.103(a)). The Government will now specify in the solicitation the sustainable products and services that apply to the acquisition. For electronic products, this would include the EPA Recommendation of EPEAT® and other statutory ecolabels for energy-efficient products, such as ENERGY STAR®. Contractors will be required to provide sustainable products and services as specified in the contract in accordance with the new omnibus clause at FAR 52.223-23.
Contractors that do not currently prioritize or propose sustainable products and services when developing offers in response to Government solicitations may need to adjust their internal processes and supply chains, as necessary, to ensure that they are in fact delivering sustainable products and services under Government contracts. Contractors not familiar with the specific programs will need to review the definition of “sustainable products and services,” the information available on the lead agency purchasing program website, and GSA's Green Procurement Compilation available at https://sftool.gov/greenprocurement to identify conforming products and services. While this effort for some contractors is acknowledged, it is not viewed as imposing additional burden. Prior to this final rule, contractors were already required to ensure products included in their offers met the Government's requirements for environmentally preferable products and other sustainable requirements.
Two respondents commented on the potential cost impact of the rule. One respondent stated that the proposed rule should contain an estimate of the added costs of procured products that are required to adhere to these environmental impact, energy efficiency, and other requirements. The respondent asserted that product selection that favors products better meeting these requirements will result in added cost to taxpayers. The other respondent suggested that the rule raises the cost of procurement by discouraging nonconforming bids, which will likely deprive agencies of lower-cost bids that can be used to determine if the sustainability requirements are impracticable. This respondent noted that the contracting officer would not know that a sustainable product or service is more expensive until receipt of offers.
The Government does not agree that this will necessarily result in added costs for several reasons. As illustrated in this section, the requirement for agencies to procure sustainable products and services is not new. Since 2002, FAR section 23.703 has required agencies to implement cost-effective contracting preference programs promoting energy efficiency, water conservation, and the acquisition of environmentally preferable products and services (see 66 FR 65351, December 18, 2001). In addition, since 2011, FAR 23.103(a) has required Federal agencies to advance sustainable acquisition by ensuring that 95 percent of new contract actions are for products that are energy-efficient, water-efficient, biobased, environmentally preferable, non-ozone depleting, or made with recovered materials (see 76 FR 31395, May 31, 2011). This rule streamlines and standardizes procedures for accomplishing this goal. Also, products that display a required ecolabel or meet the required specifications and standards identified in this rule are not necessarily more expensive than other products in the market and may result in savings when considering the life-cycle costs of the item. Finally, this rule allows agencies to justify procuring other than a sustainable product or service if the item cannot be procured at a reasonable price. A revision is made in the final rule to ensure that this market research is conducted by the Government prior to issuance of a solicitation.

C. Other Changes
While the clause at FAR 52.204-4 to require printing and copying double-sided on postconsumer fiber content paper is removed, the impact is not considered significant, since most acquisitions are conducted electronically. Contractors are also no longer be required to report information on hydrofluorocarbons under contracts that contain FAR clause 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons, and 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners, a reduction in burden for contractors. The alternates to FAR clause 52.223-5, Pollution Prevention and Right-to-Know Information, and associated reporting requirements related to agency EMS are also removed; however, per FAR 52.223-19, contractors will still be required to comply with any agency-specific requirements for EMS.

VI. Executive Orders 12866 and 13563
Executive Orders (E.O.s) 12866 (as amended by E.O. 14094) and 13563 direct agencies to assess costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This is a significant regulatory action and, therefore, was subject to review under Section 6(b) of E.O. 12866, Regulatory Planning and Review, dated September 30, 1993.

VII. Congressional Review Act
Pursuant to the Congressional Review Act, DoD, GSA, and NASA will send this rule to each House of the Congress and to the Comptroller General of the United States. The Office of Information and Regulatory Affairs (OIRA) in the Office of Management and Budget has determined that this rule does not meet the definition in 5 U.S.C. 804(2).

VIII. Regulatory Flexibility Act
DoD, GSA, and NASA have prepared a Final Regulatory Flexibility Analysis (FRFA) consistent with the Regulatory Flexibility Act, 5 U.S.C. 601-612. The FRFA is summarized as follows:
Executive Order (E.O.) 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, signed December 8, 2021, directs agencies to reduce emissions, promote environmental stewardship, support resilient supply chains, drive innovation, and incentivize markets for sustainable products and services. As part of this effort, and pursuant to memorandum M-22-06 issued jointly by the Office of Management and Budget (OMB), Council on Environmental Quality (CEQ), and the Climate Policy Office and pursuant to the CEQ Implementing Instructions for E.O. 14057, agencies are required to purchase, to the maximum extent practicable and after meeting statutory mandates, sustainable products and services identified or recommended by the U.S. Environmental Protection Agency (EPA). This rule is in alignment with the direction in E.O. 14057, Memorandum M-22-06, and the CEQ Implementing Instructions.
The rule streamlines FAR part 23 by consolidating similar content into specific subparts and providing uniform procedures to ensure agencies procure sustainable products and services to the maximum extent practicable. Consolidated in FAR subpart 23.1 are the existing requirements for agencies to procure products that meet the statutory environmental purchasing program requirements previously implemented in FAR subparts 23.2, 23.4, and 23.8, and the requirement to procure environmentally preferable products and services previously implemented in FAR subpart 23.7. FAR subpart 23.1 now directs agencies to specify in the statement of work, or elsewhere in the contract, which sustainable products and services are applicable to the acquisition. The new omnibus contract clause at FAR 52.223-23, Sustainable Products and Services, requires the contractor to ensure the sustainable products and services identified in the contract are delivered, incorporated, or furnished under the contract.
As part of the FAR part 23 streamlining effort, content on energy savings performance contracts, hazardous materials, pollution prevention at Federal facilities, and greenhouse gases are consolidated into single subparts at FAR 23.2, 23.3, 23.4, and 23.5, respectively. Non-environmental matters, to include requirements for a drug-free workplace and encouraging contractors to ban texting while driving, are moved to FAR part 26 (see FAR subparts 26.5 and 26.6, respectively). This rule also removes several reporting requirements, including those under FAR clauses 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons, and 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners. Reporting requirements associated with agency environmental management systems in the alternates to FAR clause 52.223-5, Pollution Prevention and Right-to-Know Information, are also removed, though compliance with agency-specific requirements for their environmental management systems is still required.
There were no significant issues raised by the public in response to the initial regulatory flexibility analysis (IRFA). While not a comment on the IRFA, one respondent suggested that the rule will have a disproportionate impact on small businesses throughout the contracting supply chain that will be ineligible to participate in Federal procurement. Nothing in this rule is viewed as rendering a small business as ineligible for Government contracts. As another respondent noted, the efforts to streamline and consolidate sustainability purchasing requirements throughout the FAR reduce implementation burdens—especially for small businesses that may be new to demonstrating sustainability in Government purchasing. Agencies have been directed to procure sustainable products and services, including those mandated by statute and environmentally preferable products and services per EPA-issued guidance, for over a decade. This rule continues this policy by providing clear and uniform procedures for agencies regarding requirements for specifying sustainable products and services in their solicitations and contracts and improves communication to industry of the Government's requirements through use of an omnibus clause. This rule also continues to maintain the statutory exceptions, provides other exemptions, and includes a process for justifying when it is not practicable.
Any small business competing on Federal contracts for products or services will need to become familiar with this rule. According to data available in the Federal Procurement Data System for Fiscal Years 2019 through 2021, on average approximately 85,826 contractors are awarded Federal contracts each year, of which approximately 61,797 contractors (72 percent) are small businesses.
These small businesses will need to ensure they are including in their offers sustainable products and services as specified in the solicitation and delivering, incorporating, or furnishing sustainable products and services, as specified in the resulting contract. Sustainable products and services include the following:
• Products containing recovered material designated by the EPA under the Comprehensive Procurement Guidelines (CPG) (see https://www.epa.gov/smm/comprehensive-procurement-guideline-cpg-program#products ).
• Energy- and water-efficient products that are ENERGY STAR® certified or Federal Energy Management Program (FEMP)-designated products (see https://www.energy.gov/eere/femp/search-energy-efficient-products and https://www.energystar.gov/products?s=mega ).
• Biobased products meeting the content requirement of the U.S. Department of Agriculture under the BioPreferred® program (see https://www.biopreferred.gov ).
• Acceptable chemicals, products, and manufacturing processes listed under EPA's Significant New Alternatives Policy (SNAP) program, which ensures a safe and smooth transition away from substances that contribute to the depletion of stratospheric ozone (see https://www.epa.gov/snap ).
• WaterSense® labeled (water efficient) products and services (see https://www.epa.gov/watersense/watersense-products ).
• Safer Choice-certified products (products that contain safer chemical ingredients) (see https://www.epa.gov/saferchoice/products ).
• Products and services that meet EPA Recommendations of Specifications, Standards, and Ecolabels as of October 2023 (see https://www.epa.gov/greenerproducts/recommendations-specifications-standards-and-ecolabels-federal-purchasing ).
As shown above, the definition of sustainable products and services at FAR 2.101 and in the omnibus clause at FAR 52.223-23 includes links to each lead agency's purchasing program website, where information on conforming products and services is provided for both buyers and sellers. In addition, FAR 11.002(d)(3), 23.104(d), and the clause reference as a resource GSA's Green Procurement Compilation available at https://sftool.gov/greenprocurement. GSA's Green Procurement Compilation provides a comprehensive list of required sustainable products and services and other related sustainability guidance and may be used by small businesses to identify and source sustainable products and services.
Two changes are adopted in this final rule that will minimize the impact on small businesses. First, the final rule will require the Government to specify which sustainable products and services are applicable to the acquisition. This change from the proposed rule in the final rule eliminates the need for small businesses to determine which purchasing programs apply to a specific acquisition and ensures all offerors have access to the same information about the Government's requirements. Second, this rule will require compliance only with the EPA Recommendations for Specifications, Standards, and Ecolabels in effect as of October 2023. The FAR Council will consider incorporating future updates to the EPA Recommendations through rulemaking to ensure that businesses are afforded an opportunity to provide inputs on any expansions of the EPA Recommendations and have adequate time to implement new standards, specifications, and ecolabels.
Interested parties may obtain a copy of the FRFA from the Regulatory Secretariat Division. The Regulatory Secretariat Division has submitted a copy of the FRFA to the Chief Counsel for Advocacy of the Small Business Administration.

IX. Paperwork Reduction Act
The Paperwork Reduction Act (44 U.S.C. 3501-3521) applies. The rule contains information collection requirements. The Regulatory Secretariat Division has submitted to the Office of Management and Budget (OMB) a request to review and approve revisions to previously approved information collection requirements in FAR part 23 and the transfer of a previously approved information collection requirement to a new OMB Control Number for FAR part 26.

A. OMB Control Number, Title, and Any Associated Form(s)
OMB Control Number 9000-0107, Federal Acquisition Regulation Part 23 Requirements, and OMB Control Number 9000-0207, Federal Acquisition Regulation Part 26 Requirements.

B. Need and Uses
The rule renumbers FAR clause 52.223-6, Drug-Free Workplace, as 52.226-7. As such the associated information collection requirements are being transferred from OMB Control Number 9000-0107 to the new OMB Control Number 9000-0207 for FAR part 26. The rule also proposes to remove previously approved information collection requirements under OMB Control Number 9000-0107, to include the contractor environmental management system and facility compliance audit reporting requirements under FAR clause 52.223-5, Pollution Prevention and Right-to-Know Information, and the contractor hydrofluorocarbon reporting requirements under FAR clauses 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons, and 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners.

C. Annual Burden
Public reporting burden for this collection of information includes the time for reviewing instructions, searching existing data sources, gathering, and maintaining the data needed, and completing and reviewing the collection of information.

1. OMB Control Number 9000-0207, Federal Acquisition Regulation Part 26 Requirements
Respondents: 228.
Total Annual Responses: 228.
Total Burden Hours: 114.

2. OMB Control Number 9000-0107, Federal Acquisition Regulation Part 23 Requirements
Respondents: 34,527.
Total Annual Responses: 160,600.
Total Burden Hours: 706,089.

D. Public Comment to OMB on Information Collections
A 60-day notice was published in the Federal Register at 88 FR 51672, on August 3, 2023. No comments were received. Written comments and recommendations for these information collections should be sent within 30 days of publication of this rule to www.reginfo.gov/public/do/PRAMain. Find these information collections by selecting “Currently under Review—Open for Public Comments” or by using the search function.

E. Obtaining Copies
Requesters may obtain a copy of the information collection documents from the GSA Regulatory Secretariat Division, by calling 202-501-4755 or emailing GSARegSec@gsa.gov. Please cite OMB Control Number “9000-0107, Federal Acquisition Regulation Part 23 Requirements” or “9000-0207, Federal Acquisition Regulation Part 26 Requirements.”

List of Subjects in 48 CFR Parts 1, 2, 4, 5, 7, 9, 10, 11, 12, 13, 15, 18, 23, 26, 36, 37, 39, 42, and 52
Government procurement.
William F. Clark,

Director, Office of Government-wide Acquisition Policy, Office of Acquisition Policy, Office of Government-wide Policy.
Accordingly, the interim rule amending 48 CFR parts 1, 2, 4, 5, 7, 11, 12, 13, 23, 36, 37, 39, and 52, which published in the Federal Register at 76 FR 31395 on May 31, 2011, is adopted as a final rule with the following changes:
1. The authority citation for 48 CFR parts 1, 2, 4, 5, 7, 9, 10, 11, 12, 13, 15, 18, 23, 26, 36, 37, 39, 42, and 52 continues to read as follows:

Authority:
40 U.S.C. 121(c); 10 U.S.C. chapter 4 and 10 U.S.C. chapter 137 legacy provisions (see 10 U.S.C. 3016); and 51 U.S.C. 20113.

PART 1—FEDERAL ACQUISITION REGULATIONS SYSTEM
2. In section 1.106, amend the table by—
a. Removing the entry for FAR segment “52.223-6(b)(5); and
b. Adding in numerical order an entry for “52.226-7”.
The addition reads as follows:
1.106
OMB approval under the Paperwork Reduction Act.
* * * * *
FAR segment | OMB control No.
* * * * *
52.226-7 | 9000-0207
* * * * *

PART 2—DEFINITIONS OF WORDS AND TERMS
3. Amend section 2.101 by—
a. Revising the definition of “Biobased product”;
b. In the definition of “Conviction”, removing “23.5” and “23.503” and adding “26.5” and “26.503” in their place, respectively;
c. Removing the definition of “Energy-savings performance contract” and adding the definition of “ Energy savings performance contract” in its place;
d. Revising the definition of “Environmentally preferable”;
e. Removing the definitions of “Global warming potential”, “High global warming potential hydrofluorocarbons”, and “Hydrofluorocarbons”;
f. Revising the definition of “Recovered material”;
g. Removing the definitions of “Renewable energy” and “Renewable energy technology”;
h. In the definition of “Sustainable acquisition”, removing from the introductory text “acquiring goods” and adding “acquiring products” in its place;
i. Adding in alphabetic order the definition of “Sustainable products and services”;
j. In the definition of “United States”, revising paragraph (9); and
k. Removing the definition “Water consumption intensity”.
The revisions and additions read as follows:
2.101
Definitions.
* * * * *
Biobased product means a product determined by the U.S. Department of Agriculture to be a commercial product or industrial product (other than food or feed) that is composed, in whole or in significant part, of biological products, including renewable domestic agricultural materials and forestry materials, or that is an intermediate ingredient or feedstock. The term includes, with respect to forestry materials, forest products that meet biobased content requirements, notwithstanding the market share the product holds, the age of the product, or whether the market for the product is new or emerging. (7 U.S.C. 8101) (7 CFR 3201.2).
* * * * *
Energy savings performance contract, pursuant to 42 U.S.C. 8287 and 10 CFR 436.31, means a contract that requires the contractor to—
(1) Perform services for the design, acquisition, financing, installation, testing, operation, and where appropriate, maintenance and repair, of an identified energy conservation measure or series of measures at one or more locations;
(2) Incur the costs of implementing the energy savings measures, including at least the cost (if any) incurred in making energy audits, acquiring and installing equipment, and training personnel in exchange for a predetermined share of the value of the energy savings directly resulting from implementation of such measures during the term of the contract; and
(3) Guarantee future energy and cost savings to the Government.
Environmentally preferable means, in the case of a product or service, having a lesser or reduced effect on human health and the environment when compared with competing products or services that serve the same purpose. This comparison may consider raw materials acquisition, production, manufacturing, packaging, distribution, reuse, operation, maintenance, or disposal of the product or service. (Section 314 of Pub. L. 107-314, 10 U.S.C. chapter 223 note)
* * * * *
Recovered material means waste materials and by-products recovered or diverted from solid waste, but the term does not include those materials and by-products generated from, and commonly reused within, an original manufacturing process. (42 U.S.C. 6903)
* * * * *
Sustainable products and services means products and services that are subject to and meet the following applicable statutory mandates and directives for purchasing:
(1) Statutory purchasing programs. (i) Products containing recovered material designated by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Procurement Guidelines (42 U.S.C. 6962) (40 CFR part 247) ( https://www.epa.gov/smm/comprehensive-procurement-guideline-cpg-program#products ).
(ii) Energy- and water-efficient products that are ENERGY STAR® certified or Federal Energy Management Program (FEMP)-designated products (42 U.S.C. 8259b) (10 CFR part 436, subpart C) ( https://www.energy.gov/eere/femp/search-energy-efficient-products and https://www.energystar.gov/products?s=mega ).
(iii) Biobased products meeting the content requirement of the U.S. Department of Agriculture under the BioPreferred® program (7 U.S.C. 8102) (7 CFR part 3201) ( https://www.biopreferred.gov ).
(iv) Acceptable chemicals, products, and manufacturing processes listed under EPA's Significant New Alternatives Policy (SNAP) program, which ensures a safe and smooth transition away from substances that contribute to the depletion of stratospheric ozone (42 U.S.C. 7671l) (40 CFR part 82, subpart G) ( https://www.epa.gov/snap ).
(2) Required EPA purchasing programs. (i) WaterSense® labeled (water efficient) products and services ( https://www.epa.gov/watersense/watersense-products ).
(ii) Safer Choice-certified products (products that contain safer chemical ingredients) ( https://www.epa.gov/saferchoice/products ).
(iii) Products and services that meet EPA Recommendations of Specifications, Standards, and Ecolabels in effect as of October 2023 ( https://www.epa.gov/greenerproducts/recommendations-specifications-standards-and-ecolabels-federal-purchasing ).
* * * * *
United States * * *
(9) For use in subpart 23.1, see definition at 23.101.
* * * * *

PART 4—ADMINISTRATIVE AND INFORMATION MATTERS

Subpart 4.3 [Removed and Reserved]
4. Remove and reserve subpart 4.3.
4.602
[Amended]
5. Amend section 4.602 by removing from paragraph (a)(3) the words “products, and high-performance” and adding the words “products, services, and high-performance” in its place.
4.1202
[Amended]
6. Amend section 4.1202 by removing paragraph (a)(25) and redesignating paragraphs (a)(26) through (34) as paragraphs (a)(25) through (33).

PART 5—PUBLICIZING CONTRACT ACTIONS
7. Amend section 5.207 by revising paragraph (c)(11) to read as follows:
5.207
Preparation and transmittal of synopses.
* * * * *
(c) * * *
(11) Sustainable acquisition requirements, such as a description of high-performance sustainable building practices required, if for design, construction, renovation, repair, or deconstruction (see part 23 and 36.104).
* * * * *

PART 7—ACQUISITION PLANNING
8. Amend section 7.103 by revising paragraph (p) to read as follows:
7.103
Agency-head responsibilities.
* * * * *
(p) Ensuring that agency planners—
(1) Comply with the policy in 11.002(d) regarding procurement of sustainable products and services (as defined in 2.101) in accordance with subpart 23.1;
(2) Comply with the Guiding Principles for Sustainable Federal Buildings and Associated Instructions (Guiding Principles), for the design, construction, renovation, repair, or deconstruction of Federal buildings (see 36.104). The Guiding Principles can be accessed at https://www.sustainability.gov/pdfs/guiding_principles_for_sustainable_federal_buildings.pdf; and
(3) Require contractor compliance with Federal environmental requirements, when the contractor is operating Government-owned facilities or vehicles, to the same extent as the agency would be required to comply if the agency operated the facilities or vehicles.
* * * * *
9. Amend section 7.105 by revising paragraph (b)(17) to read as follows:
7.105
Contents of written acquisition plans.
* * * * *
(b) * * *
(17) Environmental and energy conservation objectives. Discuss—
(i) All applicable environmental and energy conservation objectives associated with the acquisition (see part 23);
(ii) The applicability of an environmental assessment or environmental impact statement (see 40 CFR part 1502);
(iii) The proposed resolution of environmental issues; and
(iv) Any sustainable acquisition requirements to be included in the solicitation and contract (see 11.002 and part 23).
* * * * *

PART 9—CONTRACTOR QUALIFICATIONS
9.405
[Amended]
10. Amend section 9.405 by removing from paragraph (a) “23.506(e)” and adding “26.505(e)” in its place.
9.406-1
[Amended]
11. Amend section 9.406-1 by removing from paragraph (c) “23.506(e)” and adding “26.505(e)” in its place.
9.406-2
[Amended]
12. Amend section 9.406-2 by—
a. In paragraph (b)(1)(ii)(A), removing “52.223-6” and adding “52.226-7” in its place; and
b. In paragraph (b)(1)(ii)(B), removing “23.504” and adding “26.504” in its place.
9.406-4
[Amended]
13. Amend section 9.406-4 by removing from paragraph (a)(1)(i) “23.506” and adding “26.505” in its place.
9.407-1
[Amended]
14. Amend section 9.407-1 by removing from paragraph (d) “23.506(e)” and adding “26.505(e)” in its place.
9.407-2
[Amended]
15. Amend section 9.407-2 by—
a. In paragraph (a)(4)(i), removing “52.223-6” and adding “52.226-7” in its place; and
b. In paragraph (a)(4)(ii) “23.504” and adding “26.504” in its place.

PART 10—MARKET RESEARCH
16. Amend section 10.001 by revising paragraph (a)(3)(v) to read as follows:
10.001
Policy.
(a) * * *
(3) * * *
(v) Ensure maximum practicable use of sustainable products and services (as defined in 2.101) in accordance with subpart 23.1;
* * * * *

PART 11—DESCRIBING AGENCY NEEDS
17. Amend section 11.002 by revising paragraphs (d)(1) and (d)(2) introductory text and adding paragraph (d)(3) to read as follows:
11.002
Policy.
* * * * *
(d)(1) Agencies shall procure sustainable products and services (as defined in 2.101) in accordance with subpart 23.1.
(2) Unless it is not practicable (see 23.104(a)) or an exception or exemption applies (see 23.105 and 23.106, respectively), agencies shall incorporate the use of sustainable products and services when—
* * * * *
(3) The Green Procurement Compilation (GPC) available at https://sftool.gov/greenprocurement provides a comprehensive list of sustainable products and services and other related sustainable acquisition guidance. Agencies should—
(i) Consult the GPC when determining which purchasing programs apply to a specific product or service; and
(ii) Incorporate into agency requirements any required standards, specifications, or ecolabels identified in the GPC for a specific product or service.
* * * * *
11.301
[Removed]
18. Remove section 11.301.
11.302
[Redesignated as 11.301]
19. Redesignate section 11.302 as section 11.301.
11.303
[Removed]
20. Remove section 11.303.
11.304
[Redesignated as 11.302]
21. Redesignate section 11.304 as section 11.302.

PART 12—ACQUISITION OF COMMERCIAL PRODUCTS AND COMMERCIAL SERVICES
12.503
[Amended]
22. Amend section 12.503 by removing from paragraph (a)(8) “23.501” and adding “26.501” in its place.
12.504
[Amended]
23. Amend section 12.504 by removing from paragraph (a)(10) “23.5” and adding “26.5” in its place.

PART 13—SIMPLIFIED ACQUISITION PROCEDURES
13.006
[Amended]
24. Amend section 13.006 by removing from paragraph (f) “52.223-6” and adding “52.226-7” in its place.
13.201
[Amended]
25. Amend section 13.201 by removing from paragraph (f) “subparts 23.1, 23.2, 23.4, and 23.7” and adding “subpart 23.1” in its place.

PART 15—CONTRACTING BY NEGOTIATION
15.603
[Amended]
26. Amend section 15.603 by removing from paragraph (e) the words “energy-savings” and adding the words “energy savings” in its place.

PART 18—EMERGENCY ACQUISITIONS
27. Amend section 18.202 by adding paragraph (e) to read as follows:
18.202
Defense or recovery from certain events.
* * * * *
(e) Sustainable products and services. Contracting officers are encouraged, but not required, to procure sustainable products and services if the head of the agency determines the supplies or services are to be used to facilitate defense against or recovery from cyber, nuclear, biological, chemical, or radiological attack; to facilitate provision of international disaster assistance; or to support response to an emergency or major disaster (see 23.106(c)).

PART 23—ENVIRONMENT, SUSTAINABLE ACQUISITION, AND MATERIAL SAFETY
28. Revise the heading for part 23 to read as set forth above.
29. Revise section 23.000 to read as follows:
23.000
Scope of part.
This part prescribes acquisition policies and procedures supporting the Government's program to protect and improve the quality of the environment, to foster markets for sustainable products and services, and to ensure proper handling and notification of hazardous materials.
30. Amend section 23.001 by—
a. Removing the definition of “Greenhouse gases” and adding the definition of “Greenhouse gas” in its place; and
b. Removing the definition of “United States”.
The addition reads as follows:
23.001
Definitions.
* * * * *
Greenhouse gas means carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, nitrogen trifluoride, or sulfur hexafluoride.
* * * * *
31. Revise section 23.002 to read as follows:
23.002
Policy.
In accordance with section 208(a) of Executive Order 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, agencies shall reduce emissions, including greenhouse gas emissions; promote environmental stewardship; support resilient supply chains; drive innovation; and incentivize markets for sustainable products and services.
32. Revise subpart 23.1 to read as follows:

Subpart 23.1—Sustainable Products and Services
Sec.
23.100
Scope of subpart.
23.101
Definitions.
23.102
Authorities.
23.103
Policy.
23.104
General procedures.
23.105
Exceptions.
23.106
Exemptions.
23.107
Statutory purchasing programs.
23.107-1
Products containing recovered materials.
23.107-2
Biobased products.
23.107-3
Energy-consuming products and water-consuming products.
23.107-4
Products that contain, use, or are manufactured with ozone-depleting substances or products that contain or use high global warming potential hydrofluorocarbons.
23.108
Required Environmental Protection Agency purchasing programs.
23.108-1
Water-efficient products.
23.108-2
Chemically-intensive products.
23.108-3
Products and services that are subject to EPA Recommendations of Specifications, Standards, and Ecolabels.
23.109
Solicitation provisions and contract clauses.

Subpart 23.1—Sustainable Products and Services
23.100
Scope of subpart.
This subpart provides policies and procedures for procuring sustainable products and services. This subpart applies to all contract actions, including those using part 12 procedures for the acquisition of commercial products, including commercially available off-the-shelf (COTS) items, and commercial services and acquisitions valued at or below the micro-purchase threshold.
23.101
Definitions.
As used in this subpart—
Contract action means any oral or written action that results in the purchase, rent, or lease of supplies or equipment, services, or construction.
Environmental Protection Agency (EPA)-designated item means a product that is or can be made with recovered material—
(1) That is listed by EPA in a procurement guideline (40 CFR part 247); and
(2) For which EPA has provided recommended recovered material content levels and other purchasing recommendations in a related Recovered Materials Advisory Notice (RMAN) (available at https://www.epa.gov/smm/regulatory-background-comprehensive-procurement-guideline-program-cpg#rman ).
Global warming potential means how much a given mass of a chemical contributes to global warming over a given time period compared to the same mass of carbon dioxide. Carbon dioxide's global warming potential is defined as 1.0.
High global warming potential hydrofluorocarbons means any hydrofluorocarbons in a particular end use for which EPA's Significant New Alternatives Policy (SNAP) program has identified other acceptable alternatives that have lower global warming potential. The SNAP list of alternatives is found at 40 CFR part 82, subpart G, with supplemental tables of alternatives available at https://www.epa.gov/snap/.
Hydrofluorocarbons means compounds that only contain hydrogen, fluorine, and carbon.
Ozone-depleting substance means any substance the EPA designates in 40 CFR part 82 as—
(1) Class I, including, but not limited to, chlorofluorocarbons, halons, carbon tetrachloride, and methyl chloroform; or
(2) Class II, including, but not limited to, hydrochlorofluorocarbons.
United States, as defined in the Executive Office of the President's Office of Management and Budget, Council on Environmental Quality, and Climate Policy Office Memorandum M-22-06, when used in a geographical sense means—
(1) The fifty States;
(2) The District of Columbia;
(3) The commonwealths of Puerto Rico and the Northern Mariana Islands;
(4) The territories of Guam, American Samoa, and the United States Virgin Islands; and
(5) Associated territorial waters and airspace.
U.S. Department of Agriculture (USDA)-designated product category means a generic grouping of products that are or can be made with biobased materials—
(1) That are listed by USDA in a procurement guideline (7 CFR part 3201, subpart B); and
(2) For which USDA has provided purchasing recommendations (available at https://www.biopreferred.gov ).
23.102
Authorities.
(a) Section 208 of Executive Order 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, dated December 8, 2021.
(b) Paragraph G of section I of the Executive Office of the President's Office of Management and Budget, Council on Environmental Quality, and Climate Policy Office Memorandum M-22-06, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, dated December 8, 2021.
(c) Implementing instructions for Executive Order 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, dated August 2022.
(d) The authorities referenced in 23.107 for statutory purchasing programs.
23.103
Policy.
(a) Agencies shall procure sustainable products and services (as defined in 2.101) to the maximum extent practicable.
(1) Procuring sustainable products and services is considered practicable, unless the agency cannot acquire products or services—
(i) Competitively within a reasonable performance schedule;
(ii) That meet reasonable performance requirements; or
(iii) At a reasonable price (see 23.103(a)(2)).
(2) When considering whether the price of a sustainable product is reasonable, agencies should consider whether the product is cost-effective over the life of the product. For ENERGY STAR® or Federal Energy Management Program (FEMP)-designated products, a price is reasonable if it is cost-effective over the life of the product taking energy cost savings into account (42 U.S.C. 8259b(b)(2)). Life-cycle cost savings tools for energy-efficient products are available at https://www.energystar.gov/buildings/save_energy_commercial_buildings/ways_save/energy_efficient_products and https://www.nrel.gov/analysis/tech-lcoe.html.
(b) When procuring sustainable products and services, agencies shall—
(1) Ensure compliance with applicable statutory purchasing program requirements (see 23.107); and
(2) Prioritize multi-attribute sustainable products and services (see 23.104(c)(2)).
(c) Regarding products under contract actions for services or construction, the contractor is required to provide products that meet the definition of sustainable products and services at 2.101, if the products are—
(1) Delivered to the Government;
(2) Furnished by the contractor for use by the Government;
(3) Incorporated into the construction of a public building or public work; or
(4) Acquired by the contractor for use in performing services under a Government contract where the cost of the products is a direct cost to a Government contract (versus costs which are normally applied to a contractor's general and administrative expenses or indirect costs).
23.104
General procedures.
(a) Maximum extent practicable. If the requiring activity submits a written justification addressing the reasons described in 23.103(a)(1), the contracting officer may consider it not practicable to procure sustainable products or services. A written justification may be for a specific product or service or at the line item or contract level. The contracting officer shall maintain the written justification in the contract file.
(b) Identification. (1) Except as provided in paragraph (b)(2) of this section, the contracting officer shall ensure the solicitation and contract identifies—
(i) The sustainable products and services, including the purchasing program and type of product or service, that are applicable to the acquisition, as identified by the requiring activity; and
(ii) Any products and services that are not subject to the requirements of this subpart and the clause at 52.223-23, Sustainable Products and Services, based on the written justification under paragraph (a) of this section, an exception at 23.105, or an exemption at 23.106.
(2) The requirement in paragraph (b)(1) of this section does not apply if the justification, exception, or exemption covers the entirety of the contract action requirements.
(c) Prioritization. Agencies shall prioritize sustainable products and services as follows:
(1) Procure products and services that meet applicable statutory purchasing program requirements (see 23.107). When both an EPA-designated item (see 23.107-1) and a biobased product in a USDA-designated product category (see 23.107-2) could be used for the same purposes, and there is not an EPA-designated item that is also a biobased product in a USDA-designated product category that meets the agency's needs, procure the EPA-designated item.
(2) Consistent with other statutory procurement requirements, prioritize multi-attribute sustainable products and services, which are those that meet applicable statutory purchasing program requirements (see 23.107) and one or more required EPA purchasing programs (see 23.108).
(3) If no statutory purchasing program requirements apply, procure sustainable products and services that meet required EPA purchasing program requirements (see 23.108).
(d) Resource. The Green Procurement Compilation (GPC) available at https://sftool.gov/greenprocurement provides a comprehensive list of sustainable products and services and other related sustainable acquisition guidance. In addition to the resources identified for each purchasing program listed in 23.107 and 23.108, agencies should consult the GPC when determining which purchasing programs apply to a specific product or service.
23.105
Exceptions.
The following are excepted from the requirement to procure sustainable products and services:
(a) Contracts performed or supplies delivered outside of the United States, unless the agency head determines that such application is in the interest of the United States.
(b) Weapon systems; however, compliance with applicable agency affirmative procurement programs is required for recovered materials per 23.107-1 (see 23.109(b)) (42 U.S.C. 6962) and for alternatives for ozone depleting substances per 23.107-4 (see 23.109(d)) (42 U.S.C. 7671l), unless a written justification exists as described at 23.104(a) (42 U.S.C. 6962(c)(1) and 7 U.S.C. 8102(a)(1)(B)).
(c) Energy-consuming products or systems designed or procured for combat or combat-related missions are not subject to the requirements in 23.107-3 (42 U.S.C. 8259b(a)(5)).
(d) Biobased products to be used in military equipment (products or systems designed or procured for combat or combat-related missions), spacecraft systems, or launch support equipment are not subject to the requirements in 23.107-2 (7 CFR 3201.3(e)).
23.106
Exemptions.
(a) The Director of National Intelligence may exempt an intelligence activity of the United States and related personnel, resources, and facilities to the extent the Director determines necessary to protect intelligence sources and methods from unauthorized disclosure.
(b) The head of an agency may exempt the following:
(1) Particular agency activities and related personnel, resources, and facilities when it is in the interest of national security, to protect intelligence sources and methods from unauthorized disclosure, or where necessary to protect undercover law enforcement operations from unauthorized disclosure. The agency shall notify the Chair of the Council on Environmental Quality (CEQ) in writing within 30 days of issuance of the exemption under this paragraph (b)(1).
(2) On an individual or class basis, any manned and unmanned vehicle, vessel, aircraft, or non-road equipment that is used in combat support, combat service support, military tactical or relief operations, or training for such operations or spaceflight vehicles, including associated ground-support equipment.
(c) Contracting officers are encouraged, but not required, to procure sustainable products and services if the head of the agency determines the supplies or services are to be used to facilitate defense against or recovery from cyber, nuclear, biological, chemical, or radiological attack; to facilitate provision of international disaster assistance; or to support response to an emergency or major disaster.
(d) The head of the agency may submit to the President, through the Chair of CEQ, a request for an exemption of an agency activity, and related personnel, resources, and facilities from this subpart for any reason not otherwise addressed in this section.
23.107
Statutory purchasing programs.
Agencies shall ensure compliance with statutory purchasing program requirements described in 23.107-1 through 23.107-4.
23.107-1
Products containing recovered materials.
(a) Authorities. The Resource Conservation and Recovery Act of 1976 (RCRA), 42 U.S.C. 6962, as implemented at 40 CFR part 247.
(b) EPA Comprehensive Procurement Guidelines (CPG) Program. Under RCRA, EPA must designate items that are or can be made with recovered materials and must also recommend practices to assist procuring agencies in meeting their obligations.
(c) Applicability. (1) This section applies to contract actions involving an EPA-designated item, if—
(i) The price of the EPA-designated item exceeds $10,000; or
(ii) The aggregate amount paid for multiple purchases of the EPA-designated item, or a functionally equivalent item, in the preceding fiscal year was $10,000 or more.
(2) While micro-purchases are included in determining the aggregate amount paid under paragraph (c)(1) of this section, it is not necessary for an agency to track micro-purchases when—
(i) The agency anticipates the aggregate amount paid will exceed $10,000; or
(ii) The agency intends to establish or continue an affirmative procurement program as described in paragraph (d) of this section in the following fiscal year.
(d) Agency affirmative procurement program. An agency shall establish an affirmative procurement program for EPA-designated items if the agency's purchases of EPA-designated items exceed the threshold set forth in paragraph (c)(1) of this section.
(1) Agency affirmative procurement programs must include—
(i) A recovered materials preference program;
(ii) A program to promote the recovered materials preference program;
(iii) A program for requiring reasonable estimates and certification of recovered material used in the performance of contracts, including a preaward certification that products will meet EPA recommendations (see 52.223-4, Recovered Material Certification), and either an estimate or a certification at contract completion (see 52.223-9, Estimate of Percentage of Recovered Material Content for EPA-Designated Items, and its Alternate), as well as agency procedures for verification of estimates and certifications;
(iv) Annual review and monitoring of the effectiveness of the affirmative procurement program; and
(v) Guidance for purchases of EPA-designated items at or below the micro-purchase threshold.
(2) Technical or requirements personnel and procurement personnel are responsible for the preparation, implementation, and monitoring of affirmative procurement programs.
(3) Agencies have a period of 1 year to revise their affirmative procurement program(s) after the designation of any new item by EPA.
(e) Procedures. The following procedures apply when the thresholds set forth in paragraph (c)(1) of this section are exceeded.
(1) Once an item has been designated by EPA, agencies shall purchase conforming products to the maximum extent practicable in accordance with 23.104(a), unless a justification, exception, or exemption applies (see 23.104(a), 23.105, and 23.106, respectively).
(2) Agencies may use their own specifications or commercial product descriptions when procuring products containing recovered materials; however, the contract should specify that the product is composed of the—
(i) Highest percentage of recovered materials practicable; or
(ii) Minimum content standards in accordance with EPA's RMANs.
(3) When acquiring products with recovered material, the contracting officer may request information or data on such products, including recycled content or related product standards (see 11.301(c)).
(f) Resources. (1) For information on EPA-designated items and associated minimum content standards, see https://www.epa.gov/smm/comprehensive-procurement-guideline-cpg-program#products.
(2) Contracting officers should also consult their agency's affirmative procurement program for agency-specific guidance.
23.107-2
Biobased products.
(a) Authorities. (1) The Farm Security and Rural Investment Act of 2002 (FSRIA), 7 U.S.C. 8102, as implemented at 7 CFR part 3201.
(2) The Energy Policy Act of 2005, Public Law 109-58.
(b) USDA BioPreferred ® Program. The BioPreferred Program was created in the 2002 Farm Bill and is managed by the USDA. The goal of the BioPreferred Program is to increase the purchase and use of biobased products (as defined in 2.101) by agencies.
(c) Applicability. (1) This section applies to contract actions involving a biobased product in a USDA-designated product category if—
(i) The price of the biobased product exceeds $10,000; or
(ii) The aggregate amount paid for multiple purchases of the biobased product, or for a functionally equivalent product, in the preceding fiscal year was $10,000 or more.
(2) While micro-purchases are included in determining the aggregate amount paid under paragraph (c)(1) of this section, it is not necessary for an agency to track micro-purchases when—
(i) The agency anticipates the aggregate amount paid will exceed $10,000; or
(ii) The agency intends to establish or continue an affirmative procurement program in the following fiscal year.
(d) Agency affirmative procurement program. An agency shall establish an affirmative procurement program for biobased products in USDA-designated product categories if the agency's purchases of such products exceed the threshold set forth in paragraph (c)(1) of this section.
(1) Agency affirmative procurement programs must include—
(i) A biobased products preference program;
(ii) A program to promote the biobased products preference program;
(iii) A program for requiring preaward certification that products meet USDA recommendations (see 52.223-1, Biobased Product Certification) and reporting on biobased products used in performance of contracts (see 52.223-2, Reporting of Biobased Products Under Service and Construction Contracts); and
(iv) Annual review and monitoring of the effectiveness of the program.
(2) Technical or requirements personnel and procurement personnel are responsible for the preparation, implementation, and monitoring of affirmative procurement programs.
(3) Agencies have a period of 1 year to revise their procurement program(s) after USDA updates any USDA-designated product categories.
(e) Procedures. The following procedures apply when the thresholds set forth in paragraph (c)(1) of this section are exceeded.
(1) Once a biobased product is included in a USDA-designated product category, agencies shall purchase conforming products to the maximum extent practicable in accordance with 23.104(a), unless a justification, exception, or exemption applies (see 23.104(a), 23.105, and 23.106, respectively).
(2) Agencies may use their own specifications or commercial product descriptions when procuring biobased products; however, the contract should specify that the biobased product is composed of the—
(i) Highest percentage of biobased material practicable; or
(ii) USDA's recommended minimum contents standards.
(3) When acquiring biobased products, the contracting officer may request information or data on such products, including biobased content or related standards of the products (see 11.301(c)).
(4) Agencies shall treat as eligible for the preference for biobased products, products from designated countries, as defined in 25.003, provided that those products—
(i) Meet the criteria for the definition of biobased product, except that the products need not meet the requirement that renewable agricultural materials or forestry materials in such product must be domestic; and
(ii) Otherwise meet all requirements for participation in the preference program.
(f) Resources. (1) For information on USDA-designated product categories and minimum content standards for biobased products, see https://www.biopreferred.gov.
(2) Contracting officers should also consult their agency's affirmative procurement program for agency-specific guidance.
23.107-3
Energy-consuming products and water-consuming products.
(a) Authorities. (1) Energy Policy and Conservation Act (42 U.S.C. 6361(a)(1)).
(2) National Energy Conservation Policy Act (42 U.S.C. 8253, 8259b, and 8262g).
(3) Executive Order 11912 of April 13, 1976, Delegations of Authority under the Energy Policy and Conservation Act.
(4) Executive Order 13221 of July 31, 2001, Energy-Efficient Standby Power Devices.
(b) Programs —(1) ENERGY STAR® Program. The ENERGY STAR® program is a voluntary product-labeling initiative that identifies and promotes energy and water efficiency and the reduction of greenhouse gas emissions. This joint U.S. EPA and Department of Energy program helps buyers save money and protect the environment through energy- and water-efficient products and practices.
(2) Federal Energy Management Program (FEMP). FEMP publishes acquisition guidance to help Federal buyers meet requirements for purchasing energy-efficient and water-efficient products. In addition, in product categories not covered by the ENERGY STAR® program, FEMP sets efficiency requirements for product categories that have the potential to generate significant Federal energy savings.
(c) Procedures. To the maximum extent practicable in accordance with 23.104(a), unless a justification, exception, or exemption applies (see 23.104(a), 23.105, and 23.106, respectively)—
(1) When acquiring energy- and water-consuming products listed in the ENERGY STAR® Program or FEMP—
(i) Agencies shall purchase ENERGY STAR® certified or FEMP-designated products; and
(ii) For products that consume power in a standby mode and are listed on FEMP's Low Standby Power Devices product listing at https://www.energy.gov/eere/femp/low-standby-power-product-list, agencies shall—
(A) Purchase items that meet FEMP's standby power wattage recommendation or document the reason for not purchasing such items; or
(B) If FEMP has listed a product without a corresponding wattage recommendation, purchase items that use no more than one watt in their standby power consuming mode. When it is impracticable to meet the one-watt requirement, agencies shall purchase items with the lowest standby wattage practicable; and
(2) When contracting for services or construction that will include the provision of energy- and water-consuming products, agencies shall specify products that comply with the applicable requirements in paragraph (c)(1) of this section.
(d) Resources. (1) For information on products under the ENERGY STAR® Program, go to https://www.energystar.gov/products.
(2) For information on energy-efficient products, go to https://www.energy.gov/eere/femp/search-energy-efficient-products.
(3) For information on low standby power products, go to https://www.energy.gov/eere/femp/low-standby-power-product-purchasing-requirements-and-compliance-resources.
23.107-4
Products that contain, use, or are manufactured with ozone-depleting substances or products that contain or use high global warming potential hydrofluorocarbons.
(a) Authorities. (1) Title VI of the Clean Air Act (42 U.S.C. 7671, et seq. ).
(2) Section 706 of Division D, title VII of the Omnibus Appropriations Act, 2009 (Pub. L. 111-8).
(3) EPA regulations, Protection of Stratospheric Ozone (40 CFR part 82).
(b) Program. The EPA SNAP Program.
(c) Agency program s. Agencies shall implement cost-effective programs to minimize the procurement of materials and substances that contribute to the depletion of stratospheric ozone and/or result in the use, release, or emission of high global warming potential hydrofluorocarbons.
(d) Procedures. Agencies shall—
(1) Give preference to the procurement of acceptable alternative chemicals, products, and manufacturing processes that reduce overall risks to human health and the environment by minimizing—
(i) The depletion of ozone in the upper atmosphere; and
(ii) The potential use, release, or emission of high global warming potential hydrofluorocarbons; and
(2) In preparing specifications and purchase descriptions and in the acquisition of products and services—
(i) Comply with the requirements of title VI of the Clean Air Act; section 706 of division D, title VII of Public Law 111-8; and 40 CFR 82.84(a)(2) through (5);
(ii) Substitute acceptable alternatives to ozone-depleting substances, as identified under 42 U.S.C. 7671k, to the maximum extent practicable, as provided in 40 CFR 82.84(a)(1), except in the case of Class I substances being used for specified essential uses, as identified under 40 CFR 82.4(n); and
(iii) Unless a particular contract requires otherwise, specify that, when feasible, contractors shall use another acceptable alternative in lieu of a high global warming potential hydrofluorocarbon in products and services in a particular end use for which EPA's SNAP program has identified other acceptable alternatives that have lower global warming potential.
(e) Resource. Refer to EPA's SNAP program website at https://www.epa.gov/snap for the list of alternatives found at 40 CFR part 82, subpart G, as well as supplemental tables of alternatives.
23.108
Required Environmental Protection Agency purchasing programs.
In accordance with 23.104(c), contracting officers shall, after meeting statutory purchasing program requirements in 23.107, purchase to the maximum extent practicable products and services that meet EPA purchasing program requirements described in 23.108-1 through 23.108-3.
23.108-1
Water-efficient products.
(a) Program. EPA's WaterSense® Program makes it easy to find and select water-efficient products that can save water, energy, and money. WaterSense®-labeled products are backed by independent, third-party certification and meet EPA's specifications for water efficiency and performance.
(b) Resource. For additional information on WaterSense® products, see https://www.epa.gov/watersense/watersense-products.
23.108-2
Chemically-intensive products.
(a) Program. Safer Choice is EPA's label for products that contain safer chemicals. Every chemical, regardless of percentage, in a Safer Choice-certified product is evaluated through EPA's rigorous scientific process and only the safest ingredients are allowed.
(b) Resource. For information on Safer Choice-certified products, see https://www.epa.gov/saferchoice.
23.108-3
Products and services that are subject to EPA Recommendations of Specifications, Standards, and Ecolabels.
(a) Program. The EPA Environmentally Preferable Purchasing (EPP) Program helps Federal agencies identify and procure environmentally preferable products and services to meet zero emissions and other sustainable procurement goals by providing Recommendations of Specifications, Standards, and Ecolabels. The EPP recommendations give preference to multi-attribute or life-cycle based standards and ecolabels that address key environmental and human health impact areas and where product conformance is determined by a competent third-party certification body.
(b) Resource. For additional information on EPA Recommendations of Specifications, Standards, and Ecolabels, see https://www.epa.gov/greenerproducts/recommendations-specifications-standards-and-ecolabels-federal-purchasing.
23.109
Solicitation provisions and contract clauses.
(a) General. Insert the clause at 52.223-23, Sustainable Products and Services, in solicitations and contracts—
(1) Unless—
(i) The requiring activity has provided a written justification that it is not practicable to procure sustainable products and services (see 23.104(a));
(ii) An exception under 23.105 applies; or
(iii) An exemption under 23.106 applies; and
(2) The scope of the written justification, exception, or exemption covers the entirety of the contract action requirements.
(b) EPA-designated items. Except for the acquisition of COTS items—
(1) Insert the provision at 52.223-4, Recovered Material Certification, in solicitations that require the delivery or specify the use of EPA-designated items; and
(2) Insert the clause at 52.223-9, Estimate of Percentage of Recovered Material Content for EPA-designated Items, in solicitations and contracts exceeding $150,000 that are for, or specify the use of, EPA-designated items containing recovered materials. If technical personnel advise that estimates can be verified, use the clause with its Alternate I.
(c) Biobased products in USDA-designated product categories. (1) Insert the provision at 52.223-1, Biobased Product Certification, in solicitations, other than for acquisitions described at 23.105(d), that—
(i) Require the delivery or specify the use of biobased products in USDA-designated product categories; or
(ii) Include the clause at 52.223-2.
(2) Insert the clause at 52.223-2, Reporting of Biobased Products Under Service and Construction Contracts, in service and construction solicitations and contracts, unless the contract will not involve the use of biobased products in USDA-designated product categories at https://www.biopreferred.gov or 7 CFR part 3201.
(d) Products containing ozone-depleting substances and hydrofluorocarbons. Except for contracts for supplies that will be delivered outside the United States and its outlying areas, or contracts for services that will be performed outside the United States and its outlying areas, insert the following clauses:
(1) 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons, in solicitations and contracts for-
(i) Refrigeration equipment (in product or service code (PSC) 4110);
(ii) Air conditioning equipment (PSC 4120);
(iii) Clean agent fire suppression systems/equipment ( e.g., installed room flooding systems, portable fire extinguishers, aircraft/tactical vehicle fire/explosion suppression systems) (in PSC 4210);
(iv) Bulk refrigerants and fire suppressants (in PSC 6830);
(v) Solvents, dusters, freezing compounds, mold release agents, and any other miscellaneous chemical specialty that may contain ozone-depleting substances or high global warming potential hydrofluorocarbons (in PSC 6850);
(vi) Corrosion prevention compounds, foam sealants, aerosol mold release agents, and any other preservative or sealing compound that may contain ozone-depleting substances or high global warming potential hydrofluorocarbons (in PSC 8030);
(vii) Fluorocarbon lubricants (primarily aerosols) (in PSC 9150); and
(viii) Any other manufactured end products that may contain or be manufactured with ozone-depleting substances.
(2) 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners, in solicitations and contracts that include the maintenance, service, repair, or disposal of-
(i) Refrigeration equipment, such as refrigerators, chillers, or freezers; or
(ii) Air conditioners, including air conditioning systems in motor vehicles.
(3) 52.223-20, Aerosols, in solicitations and contracts—
(i) For products that may contain high global warming potential hydrofluorocarbons as a propellant, or as a solvent; or
(ii) That involve maintenance or repair of electronic or mechanical devices.
(4) 52.223-21, Foams, in solicitations and contracts for—
(i) Products that may contain high global warming potential hydrofluorocarbons or refrigerant blends containing hydrofluorocarbons as a foam blowing agent, such as building foam insulation or appliance foam insulation; or
(ii) Construction of buildings or facilities.
33. Revise subpart 23.2 to read as follows:

Subpart 23.2—Energy Savings Performance Contracts
Sec.
23.200
Scope.
23.201
Authorities.
23.202
Policy.

Subpart 23.2—Energy Savings Performance Contracts
23.200
Scope.
(a) This subpart prescribes policies and procedures for using an energy savings performance contract to obtain energy-efficient technologies at Government facilities without Government capital expense.
(b) This subpart applies to acquisitions in the United States and its outlying areas. Agencies conducting acquisitions outside of these areas must use their best efforts to comply with this subpart.
23.201
Authorities.
This subpart implements the National Energy Conservation Policy Act (42 U.S.C. 8287).
23.202
Policy.
(a) Agencies should make maximum use of the authority provided in the National Energy Conservation Policy Act (42 U.S.C. 8287) to use an energy savings performance contract (ESPC), when life-cycle cost-effective to reduce energy use and cost in the agency's facilities and operations.
(b)(1) Under an ESPC, an agency can contract with an energy service company for a period not to exceed 25 years to improve energy efficiency in one or more agency facilities at no direct capital cost to the United States Treasury. The energy service company finances the capital costs of implementing energy conservation measures and receives, in return, a contractually determined share of the cost savings that result.
(2) Except as provided in 10 CFR 436.34, ESPC's are subject to subpart 17.1.
(c) To solicit and award an ESPC, the contracting officer—
(1) Must use the procedures, selection method, and terms and conditions provided in 10 CFR part 436, subpart B; and
(2) May use the “Qualified List” of energy service companies established by the Department of Energy and other agencies.
(d) For procedures related to unsolicited proposals for energy savings performance contracts, see 15.603(e).
(e) For more information see https://energy.gov/eere/femp/energy-savings-performance-contracts-federal-agencies.
34. Revise the heading for subpart 23.3 to read as follows:

Subpart 23.3—Hazardous Material Identification, Material Safety Data, and Notice of Radioactive Materials
35. Revising section 23.300 to read as follows:
23.300
Scope of subpart.
This subpart prescribes policies and procedures for the following:
(a) Acquiring deliverable items, other than ammunition and explosives, that require the furnishing of data involving hazardous materials. Agencies may prescribe special procedures for ammunition and explosives.
(b) Providing notification of radioactive materials prior to delivery.
36. Revise the heading of section 23.302 to read as follows:
23.302
Hazardous material identification and notice of material safety data.
* * * * *
23.303
[Redesignate as 23.304]
37. Redesignate section 23.303 as section 23.304.
38. Add a new section 23.303 to read as follows:
23.303
Notice of radioactive materials.
(a) The clause at 52.223-7, Notice of Radioactive Materials, requires the contractor to notify the contracting officer prior to delivery of radioactive material.
(b) Upon receipt of the notice, the contracting officer shall notify receiving activities so that appropriate safeguards can be taken.
(c) The clause permits the contracting officer to waive the notification if the contractor states that the notification on prior deliveries is still current. The contracting officer may waive the notice only after consultation with cognizant technical representatives.
(d) The contracting officer is required to specify in the clause at 52.223-7, the number of days in advance of delivery that the contractor will provide notification. The determination of the number of days should be done in coordination with the installation/facility radiation protection officer (RPO). The RPO is responsible for ensuring the proper license, authorization, or permit is obtained prior to receipt of the radioactive material.
39. Revise newly redesignated section 23.304 to read as follows:
23.304
Contract clauses.
(a)(1) The contracting officer shall insert the clause at 52.223-3, Hazardous Material Identification and Material Safety Data, in solicitations and contracts if the contract will require the delivery of hazardous materials as defined in 23.301.
(2) If the contract is awarded by an agency other than the Department of Defense, the contracting officer shall use the clause at 52.223-3 with its Alternate I.
(b) The contracting officer shall insert the clause at 52.223-7, Notice of Radioactive Materials, in solicitations and contracts for supplies that are or that contain—
(1) Radioactive material requiring specific licensing under regulations issued pursuant to the Atomic Energy Act of 1954; or
(2) Radioactive material not requiring specific licensing in which the specific activity is greater than 0.002 microcuries per gram or the activity per item equals or exceeds 0.01 microcuries. Such supplies include, but are not limited to, aircraft, ammunition, missiles, vehicles, electronic tubes, instrument panel gauges, compasses, and identification markers.
40. Revise subpart 23.4 to read as follows:

Subpart 23.4—Pollution Prevention, Environmental Management Systems, and Waste Reduction
Sec.
23.400
Scope of subpart.
23.401
Definitions.
23.402
Authorities.
23.403
Emergency planning and toxic release reporting.
23.404
Environmental management systems.
23.405
Waste reduction program.
23.406
Contract clauses.

Subpart 23.4—Pollution Prevention, Environmental Management Systems, and Waste Reduction
23.400
Scope of subpart.
This subpart prescribes policies and procedures for—
(a) Obtaining information needed for Government compliance with right-to-know laws and pollution prevention requirements;
(b) Contractor compliance with environmental management systems; and
(c) Ensuring waste reduction at Federal facilities.
23.401
Definitions.
As used in this subpart—
Federal agency means an executive agency (see 2.101).
Federal facility means a facility owned or operated by a Federal agency in the customs territory of the United States.
23.402
Authorities.
(a) Emergency Planning and Community Right-to-Know Act of 1986, 42 U.S.C. 11001-11050 (EPCRA).
(b) Pollution Prevention Act of 1990, 42 U.S.C. 13101-13109 (PPA).
(c) Executive Order 14057, Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability, dated December 8, 2021.
23.403
Emergency planning and toxic release reporting.
(a) Federal facilities are required to comply with the emergency planning and toxic release reporting requirements in EPCRA and PPA.
(b) Pursuant to EPCRA, PPA, and any agency implementing procedures, every contract that provides for performance on a Federal facility shall require the contractor to provide information necessary for the Federal agency to comply with paragraph (a) of this section.
23.404
Environmental management systems.
Agencies may implement an environmental management system (EMS) when it aligns with and supports its agency's mission needs and facilitates implementation and progress toward E.O. 14057 goals. If an agency uses an EMS for contractor operation of Government-owned or -leased facilities or vehicles, and contractor activities affect the agency's environmental management aspects—
(a) EMS requirements shall be included in contracts to ensure proper implementation and execution of EMS roles and responsibilities; and
(b) The contracting officer shall—
(1) Specify the EMS directives with which the contractor must comply; and
(2) Ensure contractor compliance to the same extent as the agency would be required to comply if the agency operated the facilities or vehicles.
23.405
Waste reduction program.
To support pollution prevention and agency efforts to minimize waste in accordance with E.O. 14057, contracts for contractor operation of Government-owned or -leased facilities or for support services at Government-owned or -operated facilities shall require the contractor to promote cost-effective waste reduction in all operations and facilities covered by the contract.
23.406
Contract clauses.
(a) Insert the clause at 52.223-5, Pollution Prevention and Right-to-Know Information, in solicitations and contracts that provide for performance, in whole or in part, on a Federal facility.
(b) Insert the clause at 52.223-19, Compliance With Environmental Management Systems, in solicitations and contracts for contractor operation of Government-owned or -leased facilities or vehicles located in the United States if an agency uses an EMS and contractor activities affect aspects of the agency's environmental management. For facilities located outside the United States, the agency head may determine that use of the clause is in the best interest of the Government.
(c) Insert the clause at 52.223-10, Waste Reduction Program, in solicitations and contracts for contractor operation of Government-owned or -leased facilities and all solicitations and contracts for support services at Government-owned or -operated facilities.

Subpart 23.5 [Transferred to Part 26]
41. Transfer subpart 23.5, consisting of sections 23.500 through 23.506, to part 26.
42. Add a new subpart 23.5 to read as follows:

Subpart 23.5—Greenhouse Gas Emissions
Sec.
23.500
Scope of subpart.
23.501
Policy.
23.502
Solicitation provision.

Subpart 23.5—Greenhouse Gas Emissions
23.500
Scope of subpart.
This subpart addresses public disclosure of greenhouse gas emissions and reduction goals.
23.501
Policy.
In order to better understand both direct and indirect greenhouse gas emissions that result from Federal activities, offerors that are registered in the System for Award Management (SAM) and received $7.5 million or more in Federal contract awards in the prior Federal fiscal year are required to—
(a) Represent whether they publicly disclose greenhouse gas emissions;
(b) Represent whether they publicly disclose a quantitative greenhouse gas emissions reduction goal; and
(c) Provide the website for any such disclosures.
23.502
Solicitation provision.
The provision at 52.223-22, Public Disclosure of Greenhouse Gas Emissions and Reduction Goals—Representation, is required only when 52.204-7, System for Award Management, is included in the solicitation (see 52.204-8, Annual Representations and Certifications).

Subpart 23.6 [Removed and Reserved]
43. Remove and reserve subpart 23.6, consisting of sections 23.601 and 23.602.

Subpart 23.7 [Removed and Reserved]
44. Remove and reserve subpart 23.7, consisting of sections 23.700 through 23.705.

Subpart 23.8 [Removed and Reserved]
45. Remove and reserve subpart 23.8, consisting of sections 23.800 through 23.804.

Subpart 23.9 [Removed and Reserved]
46. Remove and reserve subpart 23.9, consisting of sections 23.900 through 23.903.

Subpart 23.10 [Removed and Reserved]
47. Remove and reserve subpart 23.10 consisting of sections 23.1000 through 23.1005.

Subpart 23.11 [Transferred to Part 26]
48. Transfer subpart 23.11, consisting of sections 23.1101 through 23.1105, to part 26.

PART 26—OTHER SOCIOECONOMIC PROGRAMS

Subpart 23.5 [Redesignated as Subpart 26.5]
49. Redesignate newly transferred subpart 23.5, consisting of sections 23.500 through 23.506, as subpart 26.5 as indicated in the table below:
Old section | New section
23.500 | 26.500
23.501 | 26.501
23.502 | 26.502
| 23.503 | 26.503
23.504 | 26.504
23.505 | 26.506
23.506 | 26.505
26.504
[Amended]
50. Amend newly redesignated section 26.504 by—
a. Removing from the last sentence of paragraph (a)(5) the words “the postion title” and adding the words “the position title” in its place; and
b. Removing from the end of paragraph (a)(6)(i) “; or” and adding a period in its place.
26.505
[Amended]
51. Amend newly redesignated section 26.505 by removing from paragraph (d)(1) “52.223-6” and adding “52.226-7” in its place.
26.506
[Amended]
52. Amend newly redesignated section 26.506 by removing “23.501” and “52.223-6” and adding “26.501” and “52.226-7” in their place, respectively.

Subpart 23.11 [Redesignated as Subpart 26.6]
53. Redesignate newly transferred subpart 23.11, consisting of sections 23.1101 through 23.1105, as subpart 26.6 as indicated in the table below:
Old section | New section
23.1101 | 26.601
23.1102 | 26.602
23.1103 | 26.603
23.1104 | 26.604
23.1105 | 26.605
26.605
[Amended]
54. Amend newly redesignated section 26.605 by removing “52.223-18” and adding “52.226-8” in its place.

PART 36—CONSTRUCTION AND ARCHITECT-ENGINEER CONTRACTS
36.001
[Amended]
55. Amend section 36.001 by—
a. Removing from the definition of “Construction and demolition materials and debris” the phrase “means materials and debris generated” and adding the phrase “means waste materials and debris generated” in its place;
b. Revising the definition of “Diverting”; and
c. Adding the definition of “Modernization project” in alphabetical order.
The revision and addition read as follows:
36.001
Definitions.
* * * * *
Diverting means redirecting materials from disposal in landfills or incinerators to recycling or recovery, excluding diversion to waste-to-energy facilities.
Modernization project means a project that includes the comprehensive replacement or restoration of virtually all major systems, interior finishes (such as ceilings, partitions, doors, and floor finishes), and building features.
56. Amend section 36.104 by revising paragraph (b) to read as follows:
36.104
Policy.
* * * * *
(b) Agencies shall implement high-performance sustainable building design, construction, renovation, repair, commissioning, operation and maintenance, management, and deconstruction practices so as to—
(1) Ensure that—
(i) All new construction and modernization projects greater than 25,000 gross square feet are designed, constructed, and maintained to meet and, wherever practicable, exceed Federal sustainable design and operations principles for new construction and modernization projects in accordance with the Council on Environmental Quality's Guiding Principles for Sustainable Federal Buildings and Associated Instructions (Guiding Principles) (available at https://www.sustainability.gov/pdfs/guiding_principles_for_sustainable_federal_buildings.pdf ); and
(ii) All renovation projects of existing Federal buildings must use, to the greatest extent technically feasible and practicable, Federal sustainable design and operations principles for existing buildings in accordance with the Guiding Principles;
(2) Identify alternatives to renovation that reduce existing assets' deferred maintenance costs;
(3) Ensure that rehabilitation of Federally-owned historic buildings utilizes best practices and technologies in retrofitting to promote long-term viability of the buildings; and
(4) Ensure pollution prevention and eliminate waste by diverting at least 50 percent of non-hazardous construction and demolition materials and debris.
* * * * *
36.601-3
[Amended]
57. Amend section 36.601-3 by removing from paragraph (a)(2) “subpart 23.2” and adding “23.107-3” in its place.

PART 37—SERVICE CONTRACTING
37.102
[Amended]
58. Amend section 37.102 by removing from paragraph (i) “part 23” and adding “subpart 23.1 (see 23.103(c))” in its place.

PART 39—ACQUISITION OF INFORMATION TECHNOLOGY
59. Amend section 39.101 by revising paragraphs (a)(1)(ii) and (iii) to read as follows:
39.101
Policy.
(a)(1) * * *
(ii) The requirements for sustainable products and services (as defined in 2.101) in accordance with subpart 23.1;
(iii) Policies to enable power management and other energy-efficient or environmentally preferable features on all agency electronic products; and
* * * * *

PART 42—CONTRACT ADMINISTRATION AND AUDIT SERVICES
60. Amend section 42.302 by—
a. In paragraph (a)(66), removing “23.5” and adding “26.5” in its place; and
b. Revising paragraphs (a)(68)(ii) and (iii).
The revision reads as follows:
42.302
Contract administration functions.
(a) * * *
(68) * * *
(ii) Monitoring contractor compliance with specifications or other contractual requirements requiring the delivery, use, or furnishing of sustainable products and services (as defined in 2.101) in accordance with the clause at 52.223-23. This must occur as part of the quality assurance procedures set forth in part 46; and
(iii) As required in the contract, ensuring that the contractor complies with the reporting requirements relating to recovered material content (see 52.223-9) and biobased products (see 52.223-2) utilized in contract performance.
* * * * *

PART 52—SOLICITATION PROVISIONS AND CONTRACT CLAUSES
52.204-4
[Removed and Reserved]
61. Remove and reserve section 52.204-4.
62. Amend section 52.204-8 by—
a. Revising the date of the provision and paragraph (c)(1)(xvii);
b. Removing from the end of paragraph (c)(1)(xix) the parenthesis;
c. Removing paragraph (c)(2)(vi); and
d. Redesignating paragraphs (c)(2)(vii) and (viii) as paragraphs (c)(2)(vi) and (vii), respectively.
The revisions read as follows:
52.204-8
Annual Representations and Certifications.
* * * * *

Annual Representations and Certifications (MAY 2024)
(xvii) 52.223-1, Biobased Product Certification. This provision applies to solicitations that require the delivery or specify the use of biobased products in USDA-designated product categories; or include the clause at 52.223-2, Reporting of Biobased Products Under Service and Construction Contracts.
* * * * *
52.211-5
[Amended]
63. Amend section 52.211-5 by removing from the introductory text “11.304” and adding “11.302” in its place.
64. Amend section 52.212-5 by—
a. Revising the date of the clause; and
b. Revise and republish paragraph(b).
The revisions read as follows:
52.212-5
Contract Terms and Conditions Required To Implement Statutes or Executive Orders—Commercial Products and Commercial Services.
* * * * *

Contract Terms and Conditions Required To Implement Statutes or Executive Orders—Commercial Products and Commercial Services (MAY 2024)
* * * * *
(b) The Contractor shall comply with the FAR clauses in this paragraph (b) that the Contracting Officer has indicated as being incorporated in this contract by reference to implement provisions of law or Executive orders applicable to acquisitions of commercial products and commercial services: [ Contracting Officer check as appropriate. ]
__(1) 52.203-6, Restrictions on Subcontractor Sales to the Government (JUN 2020), with Alternate I (NOV 2021) (41 U.S.C. 4704 and 10 U.S.C. 4655).
__(2) 52.203-13, Contractor Code of Business Ethics and Conduct (NOV 2021) (41 U.S.C. 3509).
__(3) 52.203-15, Whistleblower Protections under the American Recovery and Reinvestment Act of 2009 (JUN 2010) (Section 1553 of Pub. L. 111-5). (Applies to contracts funded by the American Recovery and Reinvestment Act of 2009.)
__(4) 52.203-17, Contractor Employee Whistleblower Rights (NOV 2023) (41 U.S.C. 4712); this clause does not apply to contracts of DoD, NASA, the Coast Guard, or applicable elements of the intelligence community—see FAR 3.900(a).
__(5) 52.204-10, Reporting Executive Compensation and First-Tier Subcontract Awards (JUN 2020) (Pub. L. 109-282) (31 U.S.C. 6101 note).
__(6) [Reserved]
__(7) 52.204-14, Service Contract Reporting Requirements (OCT 2016) (Pub. L. 111-117, section 743 of Div. C).
__(8) 52.204-15, Service Contract Reporting Requirements for Indefinite-Delivery Contracts (OCT 2016) (Pub. L. 111-117, section 743 of Div. C).
__(9) 52.204-27, Prohibition on a ByteDance Covered Application (JUN 2023) (Section 102 of Division R of Pub. L. 117-328).
__(10) 52.204-28, Federal Acquisition Supply Chain Security Act Orders—Federal Supply Schedules, Governmentwide Acquisition Contracts, and Multi-Agency Contracts. (DEC 2023) (Pub. L. 115-390, title II).
__(11)(i) 52.204-30, Federal Acquisition Supply Chain Security Act Orders—Prohibition. (DEC 2023) (Pub. L. 115-390, title II).
__(ii) Alternate I (DEC 2023) of 52.204-30.
__(12) 52.209-6, Protecting the Government's Interest When Subcontracting with Contractors Debarred, Suspended, or Proposed for Debarment. (NOV 2021) (31 U.S.C. 6101 note).
__(13) 52.209-9, Updates of Publicly Available Information Regarding Responsibility Matters (OCT 2018) (41 U.S.C. 2313).
__(14) [Reserved]
__(15) 52.219-3, Notice of HUBZone Set-Aside or Sole-Source Award (OCT 2022) (15 U.S.C. 657a).
__(16) 52.219-4, Notice of Price Evaluation Preference for HUBZone Small Business Concerns (OCT 2022) (if the offeror elects to waive the preference, it shall so indicate in its offer) (15 U.S.C. 657a).
__(17) [Reserved]
__(18)(i) 52.219-6, Notice of Total Small Business Set-Aside (NOV 2020) (15 U.S.C. 644).
__(ii) Alternate I (MAR 2020) of 52.219-6.
__(19)(i) 52.219-7, Notice of Partial Small Business Set-Aside (NOV 2020) (15 U.S.C. 644).
__(ii) Alternate I (MAR 2020) of 52.219-7.
__(20) 52.219-8, Utilization of Small Business Concerns (FEB 2024) (15 U.S.C. 637(d)(2) and (3)).
__(21)(i) 52.219-9, Small Business Subcontracting Plan (SEP 2023) (15 U.S.C. 637(d)(4)).
__(ii) Alternate I (NOV 2016) of 52.219-9.
__(iii) Alternate II (NOV 2016) of 52.219-9.
__(iv) Alternate III (JUN 2020) of 52.219-9.
__(v) Alternate IV (SEP 2023) of 52.219-9.
__(22)(i) 52.219-13, Notice of Set-Aside of Orders (MAR 2020) (15 U.S.C. 644(r)).
__(ii) Alternate I (MAR 2020) of 52.219-13.
__(23) 52.219-14, Limitations on Subcontracting (OCT 2022) (15 U.S.C. 657s).
__(24) 52.219-16, Liquidated Damages—Subcontracting Plan (SEP 2021) (15 U.S.C. 637(d)(4)(F)(i)).
__(25) 52.219-27, Notice of Set-Aside for, or Sole-Source Award to, Service-Disabled Veteran-Owned Small Business (SDVOSB) Concerns Eligible Under the SDVOSB Program (FEB 2024) (15 U.S.C. 657f).
__(26)(i) 52.219-28, Post-Award Small Business Program Rerepresentation (FEB 2024) (15 U.S.C. 632(a)(2)).
__(ii) Alternate I (MAR 2020) of 52.219-28.
__(27) 52.219-29, Notice of Set-Aside for, or Sole-Source Award to, Economically Disadvantaged Women-Owned Small Business Concerns (OCT 2022) (15 U.S.C. 637(m)).
__(28) 52.219-30, Notice of Set-Aside for, or Sole-Source Award to, Women-Owned Small Business Concerns Eligible Under the Women-Owned Small Business Program (OCT 2022) (15 U.S.C. 637(m)).
__(29) 52.219-32, Orders Issued Directly Under Small Business Reserves (MAR 2020) (15 U.S.C. 644(r)).
__(30) 52.219-33, Nonmanufacturer Rule (SEP 2021) (15 U.S.C. 657s).
__(31) 52.222-3, Convict Labor (JUN 2003) (E.O. 11755).
__(32) 52.222-19, Child Labor—Cooperation with Authorities and Remedies (FEB 2024) (E.O. 13126).
__(33) 52.222-21, Prohibition of Segregated Facilities (APR 2015).
__(34)(i) 52.222-26, Equal Opportunity (SEPT 2016) (E.O. 11246).
__(ii) Alternate I (FEB 1999) of 52.222-26.
__(35)(i) 52.222-35, Equal Opportunity for Veterans (JUN 2020) (38 U.S.C. 4212).
__(ii) Alternate I (JULY 2014) of 52.222-35.
__(36)(i) 52.222-36, Equal Opportunity for Workers with Disabilities (JUN 2020) (29 U.S.C. 793).
__(ii) Alternate I (JULY 2014) of 52.222-36.
__(37) 52.222-37, Employment Reports on Veterans (JUN 2020) (38 U.S.C. 4212).
__(38) 52.222-40, Notification of Employee Rights Under the National Labor Relations Act (DEC 2010) (E.O. 13496).
__(39)(i) 52.222-50, Combating Trafficking in Persons (NOV 2021) (22 U.S.C. chapter 78 and E.O. 13627).
__(ii) Alternate I (MAR 2015) of 52.222-50 (22 U.S.C. chapter 78 and E.O. 13627).
__(40) 52.222-54, Employment Eligibility Verification (MAY 2022). (E. O. 12989). (Not applicable to the acquisition of commercially available off-the-shelf items or certain other types of commercial products or commercial services as prescribed in FAR 22.1803.)
__(41)(i) 52.223-9, Estimate of Percentage of Recovered Material Content for EPA-Designated Items (MAY 2008) (42 U.S.C. 6962(c)(3)(A)(ii)). (Not applicable to the acquisition of commercially available off-the-shelf items.)
__(ii) Alternate I (MAY 2008) of 52.223-9 (42 U.S.C. 6962(i)(2)(C)). (Not applicable to the acquisition of commercially available off-the-shelf items.)
__(42) 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons (MAY 2024) (42 U.S.C. 7671, et seq. ).
__(43) 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners (MAY 2024) (42 U.S.C. 7671, et seq. ).
__(44) 52.223-20, Aerosols (MAY 2024) (42 U.S.C. 7671, et seq. ).
__(45) 52.223-21, Foams (MAY 2024) (42 U.S.C. 7671, et seq. ).
__(46) 52.223-23, Sustainable Products and Services (MAY 2024) (E.O. 14057, 7 U.S.C. 8102, 42 U.S.C. 6962, 42 U.S.C. 8259b, and 42 U.S.C. 7671l).
__ (47)(i) 52.224-3, Privacy Training (JAN 2017) (5 U.S.C. 552a).
__ (ii) Alternate I (JAN 2017) of 52.224-3.
__ (48)(i) 52.225-1, Buy American—Supplies (OCT 2022)) (41 U.S.C. chapter 83).
__ (ii) Alternate I (OCT 2022) of 52.225-1.
__ (49)(i) 52.225-3, Buy American—Free Trade Agreements—Israeli Trade Act (NOV 2023) (19 U.S.C. 3301 note, 19 U.S.C. 2112 note, 19 U.S.C. 3805 note, 19 U.S.C. 4001 note, 19 U.S.C. chapter 29 (sections 4501-4732), Public Law 103-182, 108-77, 108-78, 108-286, 108-302, 109-53, 109-169, 109-283, 110-138, 112-41, 112-42, and 112-43.
__ (ii) Alternate I [Reserved].
__ (iii) Alternate II (DEC 2022) of 52.225-3.
__ (iv) Alternate III (FEB 2024) of 52.225-3.
__ (v) Alternate IV (OCT 2022) of 52.225-3.
__ (50) 52.225-5, Trade Agreements (NOV 2023) (19 U.S.C. 2501, et seq., 19 U.S.C. 3301 note).
__ (51) 52.225-13, Restrictions on Certain Foreign Purchases (FEB 2021) (E.O.'s, proclamations, and statutes administered by the Office of Foreign Assets Control of the Department of the Treasury).
__ (52) 52.225-26, Contractors Performing Private Security Functions Outside the United States (OCT 2016) (Section 862, as amended, of the National Defense Authorization Act for Fiscal Year 2008; 10 U.S.C. Subtitle A, Part V, Subpart G Note).
__ (53) 52.226-4, Notice of Disaster or Emergency Area Set-Aside (NOV 2007) (42 U.S.C. 5150).
__ (54) 52.226-5, Restrictions on Subcontracting Outside Disaster or Emergency Area (NOV 2007) (42 U.S.C. 5150).
__ (55) 52.226-8, Encouraging Contractor Policies to Ban Text Messaging While Driving (May 2024) (E.O. 13513).
__ (56) 52.229-12, Tax on Certain Foreign Procurements (FEB 2021).
__ (57) 52.232-29, Terms for Financing of Purchases of Commercial Products and Commercial Services (NOV 2021) (41 U.S.C.4505, 10 U.S.C. 3805).
__ (58) 52.232-30, Installment Payments for Commercial Products and Commercial Services (NOV 2021) (41 U.S.C. 4505, 10 U.S.C. 3805).
__ (59) 52.232-33, Payment by Electronic Funds Transfer—System for Award Management (OCT 2018) (31 U.S.C. 3332).
__ (60) 52.232-34, Payment by Electronic Funds Transfer—Other than System for Award Management (JUL 2013) (31 U.S.C. 3332).
__ (61) 52.232-36, Payment by Third Party (MAY 2014) (31 U.S.C. 3332).
__ (62) 52.239-1, Privacy or Security Safeguards (AUG 1996) (5 U.S.C. 552a).
__ (63) 52.242-5, Payments to Small Business Subcontractors (JAN 2017)(15 U.S.C. 637(d)(13)).
__ (64)(i) 52.247-64, Preference for Privately Owned U.S.-Flag Commercial Vessels (NOV 2021) (46 U.S.C. 55305 and 10 U.S.C. 2631).
__ (ii) Alternate I (Apr 2003) of 52.247-64.
__ (iii) Alternate II (NOV 2021) of 52.247-64.
* * * * *
65. Amend section 52.213-4 by—
a. Revising the date of the clause; and
b. Revise and republish paragraph (b)(1).
The revisions and addition read as follows:
52.213-4
Terms and Conditions—Simplified Acquisitions (Other Than Commercial Products and Commercial Services).
* * * * *

Terms and Conditions—Simplified Acquisitions (Other Than Commercial Products and Commercial Services) (MAY 2024)
* * * * *
(b) * * *
(1) The clauses listed below implement provisions of law or Executive order:
(i) 52.203-17, Contractor Employee Whistleblower Rights (NOV 2023) (41 U.S.C. 4712); this clause does not apply to contracts of DoD, NASA, the Coast Guard, or applicable elements of the intelligence community—see FAR 3.900(a).
(ii) 52.204-10, Reporting Executive Compensation and First-Tier Subcontract Awards (JUN 2020) (Pub. L. 109-282) (31 U.S.C. 6101 note) (Applies to contracts valued at or above the threshold specified in FAR 4.1403(a) on the date of award of this contract).
(iii) 52.222-19, Child Labor—Cooperation with Authorities and Remedies (FEB 2024) (E.O. 13126) (Applies to contracts for supplies exceeding the micro-purchase threshold, as defined in 2.101 on the date of award of this contract).
(iv) 52.222-20, Contracts for Materials, Supplies, Articles, and Equipment (JUN 2020) (41 U.S.C. chapter 65) (Applies to supply contracts over the threshold specified in FAR 22.602 on the date of award of this contract, in the United States, Puerto Rico, or the U.S. Virgin Islands).
(v) 52.222-35, Equal Opportunity for Veterans (JUN 2020) (38 U.S.C. 4212) (Applies to contracts valued at or above the threshold specified in FAR 22.1303(a) on the date of award of this contract).
(vi) 52.222-36, Equal Employment for Workers with Disabilities (JUN 2020) (29 U.S.C. 793) (Applies to contracts over the threshold specified in FAR 22.1408(a) on the date of award of this contract, unless the work is to be performed outside the United States by employees recruited outside the United States). (For purposes of this clause, “United States” includes the 50 States, the District of Columbia, Puerto Rico, the Northern Mariana Islands, American Samoa, Guam, the U.S. Virgin Islands, and Wake Island.)
(vii) 52.222-37, Employment Reports on Veterans (JUN 2020) (38 U.S.C. 4212) (Applies to contracts valued at or above the threshold specified in FAR 22.1303(a) on the date of award of this contract).
(viii) 52.222-41, Service Contract Labor Standards (AUG 2018) (41 U.S.C. chapter 67) (Applies to service contracts over $2,500 that are subject to the Service Contract Labor Standards statute and will be performed in the United States, District of Columbia, Puerto Rico, the Northern Mariana Islands, American Samoa, Guam, the U.S. Virgin Islands, Johnston Island, Wake Island, or the outer Continental Shelf).
(ix)(A) 52.222-50, Combating Trafficking in Persons (NOV 2021) (22 U.S.C. chapter 78 and E.O. 13627) (Applies to all solicitations and contracts).
(B) Alternate I (MAR 2015) (Applies if the Contracting Officer has filled in the following information with regard to applicable directives or notices: Document title(s), source for obtaining document(s), and contract performance location outside the United States to which the document applies).
(x) 52.222-55, Minimum Wages for Contractor Workers Under Executive Order 14026 (JAN 2022) (Applies when 52.222-6 or 52.222-41 are in the contract and performance in whole or in part is in the United States (the 50 States, the District of Columbia, Puerto Rico, the Northern Mariana Islands, American Samoa, Guam, the U.S. Virgin Islands, Johnston Island, Wake Island, and the outer Continental Shelf as defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331, et seq. ))).
(xi) 52.222-62, Paid Sick Leave Under Executive Order 13706 (JAN 2022) (E.O. 13706) (Applies when 52.222-6 or 52.222-41 are in the contract and performance in whole or in part is in the United States (the 50 States and the District of Columbia.))
(xii) 52.223-5, Pollution Prevention and Right-to-Know Information (MAY 2024) (42 U.S.C. 11001-11050 and 13101-13109) (Applies to services performed on Federal facilities).
(xiii) 52.223-11, Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons (MAY 2024) (42 U.S.C. 7671, et seq. ) (Applies to contracts for products as prescribed at FAR 23.109(d)(1)).
(xiv) 52.223-12, Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners (MAY 2024) (42 U.S.C. 7671, et seq. ) (Applies to maintenance, service, repair, or disposal of refrigeration equipment and air conditioners).
(xv) 52.223-20, Aerosols (MAY 2024) (42 U.S.C. 7671, et seq. ) (Applies to contracts for products that may contain high global warming potential hydrofluorocarbons as a propellant or as a solvent; or contracts for maintenance or repair of electronic or mechanical devices).
(xvi) 52.223-21, Foams (MAY 2024) (42 U.S.C. 7671, et seq. ) (Applies to contracts for products that may contain high global warming potential hydrofluorocarbons or refrigerant blends containing hydrofluorocarbons as a foam blowing agent; or contracts for construction of buildings or facilities.
(xvii) 52.223-23, Sustainable Products and Services (MAY 2024) (E.O. 14057, 7 U.S.C. 8102, 42 U.S.C. 6962, 42 U.S.C. 8259b, and 42 U.S.C. 7671l) (Applies to contracts when the agency identifies in the statement of work, or elsewhere in the contract, the sustainable products and services that apply to the acquisition).
(xviii)(A) 52.225-1, Buy American—Supplies (OCT 2022) (41 U.S.C. chapter 67) (Applies to contracts for supplies, and to contracts for services involving the furnishing of supplies, for use in the United States or its outlying areas, if the value of the supply contract or supply portion of a service contract exceeds the micro-purchase threshold, as defined in 2.101 on the date of award of this contract, and the acquisition—
( 1 ) Is set aside for small business concerns; or
( 2 ) Cannot be set aside for small business concerns (see 19.502-2), and does not exceed $50,000).
(B) Alternate I (OCT 2022) (Applies if the Contracting Officer has filled in the domestic content threshold below, which will apply to the entire contract period of performance. Substitute the following sentence for the first sentence of paragraph (1)(ii)(A) of the definition of domestic end product in paragraph (a) of 52.225-1:
(A) The cost of its components mined, produced, or manufactured in the United States exceeds __ percent of the cost of all its components. [ Contracting officer to insert the percentage per instructions at 13.302-5(d)(4). ])
(xix) 52.226-6, Promoting Excess Food Donation to Nonprofit Organizations (JUN 2020) (42 U.S.C. 1792) (Applies to contracts greater than the threshold specified in FAR 26.404 on the date of award of this contract, that provide for the provision, the service, or the sale of food in the United States).
(xx) 52.232-33, Payment by Electronic Funds Transfer—System for Award Management (OCT 2018) (Applies when the payment will be made by electronic funds transfer (EFT) and the payment office uses the System for Award Management (SAM) as its source of EFT information).
(xxi) 52.232-34, Payment by Electronic Funds Transfer—Other than System for Award Management (JUL 2013) (Applies when the payment will be made by EFT and the payment office does not use the SAM database as its source of EFT information.)
(xxii) 52.247-64, Preference for Privately Owned U.S.-Flag Commercial Vessels (NOV 2021) (46 U.S.C. 55305) (Applies to supplies transported by ocean vessels (except for the types of subcontracts listed at 47.504(d).)
* * * * *
66. Revise section 52.223-1 to read as follows:
52.223-1
Biobased Product Certification.
As prescribed in 23.109(c)(1), insert the following provision:

Biobased Product Certification (MAY 2024)
As required by the Farm Security and Rural Investment Act of 2002 (7 U.S.C. 8101(4)) and the Energy Policy Act of 2005 (7 U.S.C. 8102(a)(2)(F)), the offeror certifies, by signing this offer, that biobased products (within categories of products listed by the United States Department of Agriculture in 7 CFR part 3201, subpart B) to be used or delivered in the performance of the contract, other than biobased products that are not purchased by the offeror as a direct result of this contract, will comply with the applicable specifications or other contractual requirements.

(End of provision)
67. Revise section 52.223-2 to read as follows:
52.223-2
Reporting of Biobased Products Under Service and Construction Contracts.
As prescribed in 23.109(c)(2), insert the following clause:

Reporting of Biobased Products Under Service and Construction Contracts (MAY 2024)
(a) Definitions. As used in this clause—
Biobased product means a product determined by the U.S. Department of Agriculture (USDA) to be a commercial product or industrial product (other than food or feed) that is composed, in whole or in significant part, of biological products, including renewable domestic agricultural materials and forestry materials, or that is an intermediate ingredient or feedstock. The term includes, with respect to forestry materials, forest products that meet biobased content requirements, notwithstanding the market share the product holds, the age of the product, or whether the market for the product is new or emerging. (7 U.S.C. 8101) (7 CFR 3201.2).
USDA-designated product category means a generic grouping of products that are or can be made with biobased materials—
(1) That are listed by USDA in a procurement guideline (7 CFR part 3201, subpart B); and
(2) For which USDA has provided purchasing recommendations (available at https://www.biopreferred.gov ).
(b) The Contractor shall report to https://www.sam.gov, with a copy to the Contracting Officer, on the product types and dollar value of any biobased products in USDA-designated product categories purchased by the Contractor during the previous Government fiscal year, between October 1 and September 30; and
(c) Submit this report no later than—
(1) October 31 of each year during contract performance; and
(2) At the end of contract performance.
68. Amend section 52.223-3 by revising the introductory text of the clause and the introductory text of Alternate I to read as follows:
52.223-3
Hazardous Material Identification and Material Safety Data.
As prescribed in 23.304(a)(1), insert the following clause:
* * * * *
Alternate I (JUL 1995). As prescribed in 23.304(a)(2), add the following paragraph (i) to the basic clause:
52.223-4
[Amended]
69. Amend section 52.223-4 by removing from the introductory text “23.406(c)” and adding “23.109(b)(1)” in its place.
70. Amend section 52.223-5 by—
a. Revising the introductory text and the date of the clause;
b. Removing paragraph (c)(6), Alternate I, and Alternate II.
The revision reads as follows:
52.223-5
Pollution Prevention and Right-to-Know Information.
As prescribed in 23.406(a), insert the following clause:

Pollution Prevention and Right-to-Know Information (MAY 2024)
* * * * *
52.223-6
[Redesignated as 52.226-7]
71. Redesignate section 52.223-6 as section 52.226-7.
72. Amend section 52.223-7 by:
a. Revising the section heading; and
b. Removing from the introductory text “23.602” and adding “23.304(b)” in its place.
The revision reads as follows:
52.223-7
Notice of Radioactive Materials.
* * * * *
52.223-9
[Amended]
73. Amend section 52.223-9 by removing from the introductory text and the introductory text of Alternate I “23.406(d)” and adding “23.109(b)(2)” in its place.
74. Amend section 52.223-10 by—
a. Revising the introductory text and the date of the clause; and
b. Removing from paragraph (b) the text “3(e) of Executive Order 13423” and adding the text “207 of Executive Order 14057” in its place.
The revisions read as follows:
52.223-10
Waste Reduction Program.
As prescribed in 23.406(c), insert the following clause:

Waste Reduction Program (MAY 2024)
* * * * *
75. Amend section 52.223-11 by—
a. Revising the introductory text and the date of the clause;
b. In paragraph (a), in the definition of “High global warming potential hydrofluorocarbons”, removing “ http:// www.epa.gov/snap/ ” and adding “ https://www.epa.gov/snap/” in its place.
c. Removing paragraph (c);
d. Redesignating paragraph (d) as paragraph (c); and
e. Revising newly redesignated paragraph (c).
The revisions read as follows:
52.223-11
Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons.
As prescribed in in 23.109(d)(1), insert the following clause:

Ozone-Depleting Substances and High Global Warming Potential Hydrofluorocarbons (MAY 2024)
* * * * *
(c) The Contractor shall refer to EPA's SNAP program to identify alternatives. The SNAP list of alternatives is found at 40 CFR part 82, subpart G, with supplemental tables available at https://www.epa.gov/snap/.
* * * * *
76. Amend section 52.223-12 by—
a. Revising the introductory text and the date of the clause;
b. In paragraph (a), in the definition of “High global warming potential hydrofluorocarbons”, removing “ http://www.epa.gov/snap/ ” and adding “ https://www.epa.gov/snap/ ” in its place.
c. Revising paragraph (c)(4);
d. Removing paragraph (d);
e. Redesignating paragraph (e) as paragraph (d); and
f. In newly redesignated paragraph (d), removing “ http://www.epa.gov/snap/ ” and adding “ https://www.epa.gov/snap/ ” in its place.
The revisions read as follows:
52.223-12
Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners.
As prescribed in 23.109(d)(2), insert the following clause:

Maintenance, Service, Repair, or Disposal of Refrigeration Equipment and Air Conditioners (MAY 2024)
* * * * *
(c) * * *
(4) Using reclaimed hydrofluorocarbons to service and repair refrigeration and air conditioning equipment, where feasible.
* * * * *
52.223-13 through 52.223-17
[Removed and Reserved]
77. Remove and reserve sections 52.223-13 through 52.223-17.
52.223-18
[Redesignated as 52.226-8]
78. Redesignate section 52.223-18 as section 52.226-8.
52.223-19
[Amended]
79. Amend section 52.223-19 in the introductory text by removing “23.903” and adding “23.406(b)” in its place.
80. Amend section 52.223-20 by—
a. Revising the introductory text and the date of the clause; and
b. In paragraph (a), in the definition of “High global warming potential hydrofluorocarbons”, and in paragraph (c), removing “ http://www.epa.gov/snap/ ” and adding “ https://www.epa.gov/snap/ ” in both places.
The revisions read as follows:
52.223-20
Aerosols.
As prescribed in 23.109(d)(3), insert the following clause:

Aerosols (MAY 2024)
* * * * *
81. Amend section 52.223-21 by—
a. Revising the introductory text and the date of the clause; and
b. In paragraph (a), in definition of “High global warming potential hydrofluorocarbons”, and in paragraph (c), removing “ http://www.epa.gov/snap/ ” and adding “ https://www.epa.gov/snap/ ” in both places.
The revisions read as follows:
52.223-21
Foams.
As prescribed in in 23.109(d)(4), insert the following clause:

Foams (MAY 2024)
* * * * *
52.223-22
[Amended]
82. Amend section 52.223-22 in the introductory text by removing “23.804(b)” and adding “23.502” in its place.
83. Add section 52.223-23 to read as follows:
52.223-23
Sustainable Products and Services.
As prescribed in 23.109(a), insert the following clause:

Sustainable Products and Services (MAY 2024)
(a) Definitions. As used in this clause—
Biobased product means a product determined by the U.S. Department of Agriculture (USDA) to be a commercial product or industrial product (other than food or feed) that is composed, in whole or in significant part, of biological products, including renewable domestic agricultural materials and forestry materials, or that is an intermediate ingredient or feedstock. The term includes, with respect to forestry materials, forest products that meet biobased content requirements, notwithstanding the market share the product holds, the age of the product, or whether the market for the product is new or emerging. (7 U.S.C. 8101) (7 CFR 3201.2).
Recovered material means waste materials and by-products recovered or diverted from solid waste, but the term does not include those materials and by-products generated from, and commonly reused within, an original manufacturing process. (42 U.S.C. 6903).
Sustainable products and services means products and services that are subject to and meet the following applicable statutory mandates and directives for purchasing:
(1) Statutory purchasing programs.
(i) Products containing recovered material designated by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Procurement Guidelines (42 U.S.C. 6962) (40 CFR part 247) ( https://www.epa.gov/smm/comprehensive-procurement-guideline-cpg-program#products ).
(ii) Energy- and water-efficient products that are ENERGY STAR® certified or Federal Energy Management Program (FEMP)-designated products (42 U.S.C. 8259b) (10 CFR part 436, subpart C) ( https://www.energy.gov/eere/femp/search-energy-efficient-products and https://www.energystar.gov/products?s=mega ).
(iii) Biobased products meeting the content requirement of the USDA under the BioPreferred® program (7 U.S.C. 8102) (7 CFR part 3201) ( https://www.biopreferred.gov ).
(iv) Acceptable chemicals, products, and manufacturing processes listed under EPA's Significant New Alternatives Policy (SNAP) program, which ensures a safe and smooth transition away from substances that contribute to the depletion of stratospheric ozone (42 U.S.C. 7671l) (40 CFR part 82, subpart G) ( https://www.epa.gov/snap ).
(2) Required EPA purchasing programs.
(i) WaterSense® labeled (water efficient) products and services ( https://www.epa.gov/watersense/watersense-products ).
(ii) Safer Choice-certified products (products that contain safer chemical ingredients) ( https://www.epa.gov/saferchoice/products ).
(iii) Product and services that meet EPA Recommendations of Specifications, Standards, and Ecolabels in effect as of October 2023 ( https://www.epa.gov/greenerproducts/recommendations-specifications-standards-and-ecolabels-federal-purchasing ).
(b) Requirements.
(1) The sustainable products and services, including the purchasing program and type of product or service, that are applicable to this contract, and any products or services that are not subject to this clause, will be set forth in the statement of work or elsewhere in the contract.
(2) The Contractor shall ensure that the sustainable products and services required by this contract are—
(i) Delivered to the Government;
(ii) Furnished for use by the Government;
(iii) Incorporated into the construction of a public building or public work; and
(iv) Furnished for use in performing services under this contract, where the cost of the products is a direct cost to this contract (versus costs which are normally applied to the Contractor's general and administrative expenses or indirect costs). This includes services performed by contractors performing management and operation of Government-owned facilities to the same extent that, at the time of award, an agency would be required to comply if an agency operated or supported the facility.
(3)(i) Except as provided in paragraph (b)(3)(ii) of this clause, sustainable products and services must meet the applicable standards, specifications, or other program requirements at time of quote or offer submission; and
(ii) Sustainable products and services must meet the EPA Recommendations of Specifications, Standards, and Ecolabels in effect as of October 2023.
(c) Resource. The Green Procurement Compilation (GPC) available at https://sftool.gov/greenprocurement provides a comprehensive list of sustainable products and services and sustainable acquisition guidance. The Contractor should review the GPC when determining which purchasing programs apply to a specific product or service.

(End of clause)
84. Amend newly redesignated section 52.226-7 by—
a. Revising the introductory text and the date of the clause; and
b. Removing from paragraph (d) “23.506” and adding “26.505” in its place.
The revisions read as follows:
52.226-7
Drug-Free Workplace.
As prescribed in 26.506, insert the following clause:

Drug-Free Workplace (MAY 2024)
* * * * *
85. Amend newly redesignated section 52.226-8 by revising the introductory text and the date of the clause to read as follows:
52.226-8
Encouraging Contractor Policies To Ban Text Messaging While Driving.
As prescribed in 26.605, insert the following clause:

Encouraging Contractor Policies To Ban Text Messaging While Driving (MAY 2024)
89
78
Monday, April 22, 2024
Rules and Regulations
Part VII
Department of Defense
General Services Administration
National Aeronautics and Space Administration
48 CFR Parts 1, 4, 5, 8, 16, 19, 28, 31, 39, and 52

Federal Acquisition Regulation; Technical Amendments; Final Rule
DEPARTMENT OF DEFENSE
GENERAL SERVICES ADMINISTRATION
NATIONAL AERONAUTICS AND SPACE ADMINISTRATION
48 CFR Parts 1, 4, 5, 8, 16, 19, 28, 31, 39, and 52
[FAC 2024-05; Item II; Docket No. FAR-2024-0052; Sequence No. 1]
Federal Acquisition Regulation; Technical Amendments

AGENCY:
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

ACTION:
Final rule.

SUMMARY:
This document amends the Federal Acquisition Regulation (FAR) to make needed editorial changes.

DATES:
> Effective: May 22, 2024.

FOR FURTHER INFORMATION CONTACT:
Ms. Lois Mandell, Regulatory Secretariat Division (MVCB), at 202-501-4755 or GSARegSec@gsa.gov. Please cite FAC 2024-05, Technical Amendments.

SUPPLEMENTARY INFORMATION:
This document makes editorial changes to 48 CFR parts 1, 4, 5, 8, 16, 19, 28, 31, 39, and 52.

List of Subjects in 48 CFR Parts 1, 4, 5, 8, 16, 19, 28, 31, 39, and 52
Government procurement.
William F. Clark,

Director, Office of Government-wide Acquisition Policy, Office of Acquisition Policy, Office of Government-wide Policy.
Therefore, DoD, GSA, and NASA amend 48 CFR parts 1, 4, 5, 8, 16, 19, 28, 31, 39, and 52 as set forth below:
1. The authority citation for 48 CFR parts 1, 4, 5, 8, 16, 19, 28, 31, 39, and 52 continues to read as follows:

Authority:
40 U.S.C. 121(c); 10 U.S.C. chapter 4 and 10 U.S.C. chapter 137 legacy provisions (see 10 U.S.C. 3016); and 51 U.S.C. 20113.

PART 1—FEDERAL ACQUISITION REGULATIONS SYSTEM
2. Amend section 1.106 by revising the table to read as follows:
1.106
OMB approval under the Paperwork Reduction Act.
* * * * *
FAR segment | OMB control No.
14.205 | 9000-0037.
15.201(c) | 9000-0037.
15.305(a)(2)(ii) | 9000-0142.
15.407-2(e) | 9000-0048.
19.301 | 9000-0163.
22.8 | 1250-0003.
22.14 | 1250-0005.
22.16 | 1245-0004.
31.205-46 | 9000-0079.
32.408(b) | 9000-0073.
33.2 | 9000-0035.
36.213-2 | 9000-0037.
42.1203(a) | 9000-0076.
42.1204(e) and (f) | 9000-0076.
42.1205(a) | 9000-0076.
42.1503(d) | 9000-0142.
47.303 | 9000-0061.
49.6 | 9000-0012.
50.103-3 | 9000-0029.
50.103-4 | 9000-0029.
50.104-3 | 9000-0029.
51.202 | 9000-0032.
51.203 | 9000-0032.
52.201-1 | 9000-0204.
52.203-2 | 9000-0018.
52.203-7 | 9000-0018.
52.203-13 | 9000-0018.
52.203-16 | 9000-0018.
52.204-3 | 9000-0189.
52.204-6 | 9000-0189.
52.204-7 | 9000-0189.
52.204-10(d)(2) and (3) | 3090-0292.
52.204-12 | 9000-0189.
52.204-13 | 9000-0189.
52.204-14 | 9000-0189.
52.204-15 | 9000-0189.
52.204-20 | 9000-0189.
52.204-23 | 9000-0189.
52.204-24 | 9000-0199.
52.204-25 | 9000-0199.
52.204-26 | 9000-0199.
52.204-29 | 9000-0205.
52.204-30 | 9000-0205.
52.207-3 | 9000-0082.
52.207-4 | 9000-0082.
52.209-1 | 9000-0198.
52.209-2 | 9000-0198.
52.209-5 | 9000-0198.
52.209-6 | 9000-0198.
52.209-7 | 9000-0198.
52.209-9 | 9000-0198.
52.209-10 | 9000-0198.
52.209-11 | 9000-0198.
52.209-12 | 9000-0198.
52.209-13 | 9000-0198.
52.211-7 | 9000-0153.
52.211-8 | 9000-0153.
52.211-9 | 9000-0153.
52.212-1(b)(10) | 9000-0142.
52.212-1(j) | 9000-0189.
52.212-3(b) | 9000-0189.
52.212-3(b)(2) | 9000-0136.
52.212-3(h) | 9000-0198.
52.212-3(l) | 9000-0189.
52.212-3(n) | 9000-0198.
52.212-3(q) | 9000-0198.
52.212-5(d) | 9000-0034.
52.214-14 | 9000-0047.
52.214-26 | 9000-0034.
52.214-28 | 9000-0013.
52.215-1(c)(2)(iv) | 9000-0048.
52.215-2 | 9000-0034.
52.215-6 | 9000-0047.
52.215-9 | 9000-0048.
52.215-12 | 9000-0013.
52.215-13 | 9000-0013.
52.215-14 | 9000-0048.
52.215-19 | 9000-0048.
52.215-20 | 9000-0013.
52.215-21 | 9000-0013.
52.215-22 | 9000-0048.
52.215-23 | 9000-0048.
52.216-2 | 9000-0067.
52.216-3 | 9000-0067.
52.216-4 | 9000-0067.
52.216-5 | 9000-0067.
52.216-6 | 9000-0067.
52.216-7 | 9000-0069.
52.216-15 | 9000-0069.
52.216-16 | 9000-0067.
52.216-17 | 9000-0067.
52.219-9 | 9000-0007.
52.219-28 | 9000-0163.
52.219-29 | 3245-0374.
52.219-30 | 3245-0374.
52.222-2 | 9000-0066.
52.222-4 | 1235-0023.
52.222-6 | 1235-0023 and 9000-0066.
52.222-8 | 1235-0008 and 1235-0018.
52.222-11 | 9000-0066.
52.222-18 | 9000-0066.
52.222-21 | 1250-0003.
52.222-22 | 1250-0003.
52.222-23 | 1250-0003.
52.222-25 | 1250-0003.
52.222-26 | 1250-0001 and 1250-0003.
52.222-27 | 1250-0003.
52.222-32 | 9000-0154.
52.222-33 | 9000-0066.
52.222-34 | 9000-0066.
52.222-35 | 1250-0004.
52.222-36 | 1250-0005.
52.222-37 | 1250-0004.
52.222-38 | 1293-0005.
52.222-40 | 1245-0004.
52.222-41 | 1235-0007 and 1235-0018.
52.222-46 | 9000-0066.
52.222-50 | 9000-0188.
52.222-54 | 1615-0092.
52.222-55 | 1235-0018.
52.222-56 | 9000-0188.
52.222-62 | 1235-0018, 1235-0021 and 1235-0029.
52.223-2 | 9000-0107.
52.223-5 | 9000-0107.
52.223-7 | 9000-0107.
52.223-9 | 9000-0107.
52.223-11 | 9000-0107.
52.223-12 | 9000-0107.
52.223-22 | 9000-0107.
52.224-3 | 9000-0182.
52.225-2 | 9000-0024.
52.225-4 | 9000-0024.
52.225-6 | 9000-0024.
52.225-8 | 9000-0024.
52.225-9 | 9000-0024.
52.225-10 | 9000-0024.
52.225-11 | 9000-0024.
52.225-12 | 9000-0024.
52.225-18 | 9000-0161.
52.225-21 | 9000-0024.
52.225-23 | 9000-0024.
52.225-26 | 9000-0184.
52.226-7 | 9000-0207.
52.227-2 | 9000-0095.
52.227-6 | 9000-0095.
52.227-9 | 9000-0095.
52.227-11 | 9000-0095.
52.227-13 | 9000-0095.
52.227-14 | 9000-0095.
52.227-15 | 9000-0095.
52.227-16 | 9000-0095.
52.227-17 | 9000-0095.
52.227-18 | 9000-0095.
52.227-19 | 9000-0095.
52.227-20 | 9000-0095.
52.227-21 | 9000-0095.
52.227-23 | 9000-0095.
52.228-1 | 9000-0001.
52.228-2 | 9000-0001.
52.228-11 | 9000-0001.
52.228-12 | 9000-0135.
52.228-13 | 9000-0001.
52.228-14 | 9000-0001.
52.228-15 | 9000-0001.
| 52.228-16 | 9000-0001.
52.228-17 | 9000-0001.
52.229-2 | 9000-0059.
52.229-11 | 1545-2263.
52.229-12 | 1545-2263.
52.230-6 | 9000-0129.
52.232-1 | 9000-0073.
52.232-2 | 9000-0073.
52.232-3 | 9000-0073.
52.232-4 | 9000-0073.
52.232-5 | 9000-0073.
52.232-6 | 9000-0073.
52.232-7 | 9000-0073.
52.232-10 | 9000-0073.
52.232-12 | 9000-0073.
52.232-16 | 9000-0010.
52.232-20 | 9000-0073.
52.232-22 | 9000-0073.
52.232-27 | 9000-0073.
52.232-28 | 9000-0138.
52.232-29 | 9000-0138.
52.232-30 | 9000-0138.
52.232-31 | 9000-0138.
52.232-32 | 9000-0138.
52.232-34 | 9000-0073.
52.233-1 | 9000-0035.
52.236-5 | 9000-0064.
52.236-13 Alt.I | 9000-0064.
52.236-15 | 9000-0064.
52.236-19 | 9000-0064.
52.237-10 | 9000-0152.
52.242-4 | 9000-0069.
52.242-5 | 9000-0069.
52.242-13 | 9000-0069.
52.243-4 | 9000-0026.
52.243-6 | 9000-0026.
52.243-7 | 9000-0026.
52.244-2 | 9000-0149.
52.245-1(f) and (j) | 9000-0075.
52.245-9(d)(1) | 9000-0075.
52.246-2 | 9000-0077.
52.246-3 | 9000-0077.
52.246-4 | 9000-0077.
52.246-5 | 9000-0077.
52.246-6 | 9000-0077.
52.246-7 | 9000-0077.
52.246-8 | 9000-0077.
52.246-12 | 9000-0077.
52.246-15 | 9000-0077.
52.246-26 | 9000-0077.
52.247-1 | 9000-0061.
52.247-2 | 9000-0061.
52.247-6 | 9000-0061.
52.247-29 | 9000-0061.
52.247-30 | 9000-0061.
52.247-31 | 9000-0061.
52.247-32 | 9000-0061.
52.247-33 | 9000-0061.
52.247-34 | 9000-0061.
52.247-35 | 9000-0061.
52.247-36 | 9000-0061.
52.247-37 | 9000-0061.
52.247-38 | 9000-0061.
52.247-41 | 9000-0061.
52.247-42 | 9000-0061.
52.247-43 | 9000-0061.
52.247-44 | 9000-0061.
52.247-48 | 9000-0061.
52.247-51 | 9000-0061.
52.247-52 | 9000-0061.
52.247-53 | 9000-0061.
52.247-57 | 9000-0061.
52.247-60 | 9000-0061.
52.247-63 | 9000-0061.
52.247-64 | 9000-0061.
52.247-65 | 9000-0061.
52.247-67 | 9000-0061.
52.247-68 | 9000-0061.
52.248-1 | 9000-0027.
52.248-2 | 9000-0027.
52.248-3 | 9000-0027.
52.250-1 | 9000-0029.
SF 24 | 9000-0001.
SF 25 | 9000-0001.
SF 25-A | 9000-0001.
SF 25-B | 9000-0001.
SF 28 | 9000-0001.
SF 34 | 9000-0001.
SF 35 | 9000-0001.
SF 273 | 9000-0001.
SF 274 | 9000-0001.
SF 275 | 9000-0001.
SF 294 | 9000-0007.
SF 330 | 9000-0157.
SF 1403 | 9000-0011.
SF 1404 | 9000-0011.
SF 1405 | 9000-0011.
SF 1406 | 9000-0011.
SF 1407 | 9000-0011.
SF 1408 | 9000-0011.
SF 1413 | 9000-0066.
SF 1414 | 9000-0001.
SF 1415 | 9000-0001.
SF 1416 | 9000-0001.
SF 1418 | 9000-0001.
SF 1428 | 9000-0075.
SF 1429 | 9000-0075.
SF 1435 | 9000-0012.
SF 1436 | 9000-0012.
SF 1437 | 9000-0012.
SF 1438 | 9000-0012.
SF 1439 | 9000-0012.
SF 1440 | 9000-0012.
SF 1443 | 9000-0010.
SF 1444 | 9000-0066.
DD Form 254 | 0704-0567.
1.401
[Amended]
3. Amend section 1.401, in paragraph (c), by removing “2.101(a)” and adding “2.101” in its place.

PART 4—ADMINISTRATIVE AND INFORMATION MATTERS
4.1702
[Amended]
4. Amend section 4.1702 in paragraph (b) by removing the web address “ https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/procurement/memo/service-contract-inventory-guidance.pdf” and adding the web address “ https://www.whitehouse.gov/wp-content/uploads/legacy_drupal_files/omb/memoranda/2017/service_contract_inventories.pdf” in its place.

PART 5—PUBLICIZING CONTRACT ACTIONS
5.704
[Amended]
5. Amend section 5.704 in paragraph (a)(2) by removing the word “e-Buy” and adding the word “eBuy” in its place.

PART 8—REQUIRED SOURCES OF SUPPLIES AND SERVICES
6. Amend section 8.402 by revising paragraphs (d)(1) introductory text and (d)(2) to read as follows:
8.402
General.
* * * * *
(d)(1) eBuy, GSA's electronic request for quotation (RFQ) system, is a part of a suite of online tools which complement GSA Advantage!. GSA's eBuy allows ordering activities to post requirements, obtain quotes, and issue orders electronically. Posting an RFQ on eBuy—
* * * * *
(2) Ordering activities may access eBuy at https://www.ebuy.gsa.gov. For more information or assistance on either GSA Advantage! or eBuy, contact GSA by email at gsa.advantage@gsa.gov.
* * * * *
8.404
[Amended]
7. Amend section 8.404 in paragraph (c)(2) by removing “2.101(b)” and adding “2.101” in its place.
8.405-1
[Amended]
8. Amend section 8.405-1 by removing from paragraphs (d)(3)(i) and (e) the phrase “RFQ on e-Buy” and adding the phrase “RFQ on eBuy” in its place.
8.405-2
[Amended]
9. Amend section 8.405-2 by—
a. Removing from paragraph (c) introductory text the words “Request for Quotation (RFQ)” and “e-Buy” and adding the words “request for quotation (RFQ)” and “eBuy” in their place; and
b. Removing from paragraph (c)(3)(iii)(A) “e-Buy” and adding “eBuy” in its place.
8.405-3
[Amended]
10. Amend section 8.405-3 by—
a. Removing from paragraph (b)(1)(ii)(B)( 1 ) the word “e-Buy” and adding the word “eBuy” in its place;
b. In paragraph (b)(2)(iii): i. Removing from the paragraph heading the word “Quotation” and adding “quotation” in its place; ii. Removing the word “e-Buy” and adding the word “eBuy” in its place; and
c. Removing from paragraph (b)(2)(v)(A) the word “e-Buy” and adding the word “eBuy” in its place.
8.405-6
[Amended]
11. Amend section 8.405-6 in paragraph (b) by—
a. Removing from paragraph (b)(3)(i) introductory text “e-Buy ( http://www.ebuy.gsa.gov )” and adding “eBuy ( https://www.ebuy.gsa.gov )” in its place; and
b. Removing from paragraphs (b)(3)(ii)(B) and (C) the word “e-Buy” and adding the word “eBuy” in its place.

PART 16—TYPES OF CONTRACTS
16.505
[Amended]
12. Amend section 16.505 in paragraph (a)(8)(iii) by removing “2.101(b)” and adding “2.101” in its place.

PART 19—SMALL BUSINESS PROGRAMS
19.305
[Amended]
13. Amend section 19.305 in paragraph (b) by removing the words “Assistant Administrator for SDBCE” and adding the words “Associate Administrator for Business Development (AA/BD)” in its place.
19.507
[Amended]
14. Amend section 19.507 in paragraph (h)(1) introductory text by removing the phrase “contracts (including multiple-award contracts when” and adding “contracts, including multiple-award contracts, when” in its place.

PART 28—BONDS AND INSURANCE
28.203-1
[Amended]
15. Amend section 28.203-1 in paragraph (a) by removing “ https://www.treasurydirect.gov/instit/statreg/collateral/collateral.htm” and adding “ https://www.treasurydirect.gov/files/laws-and-regulations/collateral-programs/2018-final-225-list-of-acceptable-collateral.pdf” in its place.

PART 31—CONTRACT COST PRINCIPLES AND PROCEDURES
16. Amend section 31.205-40 by revising paragraph (a) to read as follows:
31.205-40
Special tooling and special test equipment costs.
(a) The terms “ special tooling” and “ special test equipment” are defined in 2.101.
* * * * *

PART 39—ACQUISITION OF INFORMATION TECHNOLOGY
39.000
[Amended]
17. Amend section 39.000 in paragraph (b) by removing “2.101(b)” and adding “2.101” in its place.

PART 52—SOLICITATION PROVISIONS AND CONTRACT CLAUSES
18. Amend section 52.212-3 by—
a. Revising the date of the provision; and
b. Removing from paragraph (c)(5) the citation “13 CFR 124.1002” and adding the citation “13 CFR 124.1001” in its place.
The revision reads as follows:
52.212-3
Offeror Representations and Certifications—Commercial Products and Commercial Services [Insert Abbreviated Month and Year of Publication in the Federal Register]
* * * * *

Offeror Representations and Certifications—Commercial Products and Commercial Services (MAY 2024)
* * * * *
89
78
Monday, April 22, 2024
Rules and Regulations
Part VIII
Department of Defense
General Services Administration
National Aeronautics and Space Administration
48 CFR Chapter 1

Federal Acquisition Regulation; Federal Acquisition Circular 2024-05; Small Entity Compliance Guide
DEPARTMENT OF DEFENSE
GENERAL SERVICES ADMINISTRATION
NATIONAL AERONAUTICS AND SPACE ADMINISTRATION
48 CFR Chapter 1
[Docket No. FAR-2024-0051, Sequence No. 3]
Federal Acquisition Regulation; Federal Acquisition Circular 2024-05; Small Entity Compliance Guide

AGENCY:
Department of Defense (DoD), General Services Administration (GSA), and National Aeronautics and Space Administration (NASA).

ACTION:
Small Entity Compliance Guide (SECG).

SUMMARY:
This document is issued under the joint authority of DoD, GSA, and NASA. This Small Entity Compliance Guide has been prepared in accordance with section 212 of the Small Business Regulatory Enforcement Fairness Act of 1996. It consists of a summary of the rules appearing in Federal Acquisition Circular (FAC) 2024-05, which amends the Federal Acquisition Regulation (FAR). Interested parties may obtain further information regarding these rules by referring to FAC 2024-05, which also published in this issue of the Federal Register .

DATES:
April 22, 2024.

ADDRESSES:
The FAC, including the SECG, is available at https://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:
For clarification of content, contact the analyst whose name appears in the table below. Please cite FAC 2024-05 and the FAR Case number. For information pertaining to status or publication schedules, contact the Regulatory Secretariat Division at 202-501-4755 or GSARegSec@gsa.gov. An asterisk (*) next to a rule indicates that a regulatory flexibility analysis has been prepared.
Rules Listed in FAC 2024-05
Item | Subject | FAR case | Analyst
*I | Sustainable Procurement | 2022-006 | Hawes.
II | Technical Amendments

SUPPLEMENTARY INFORMATION:
Summaries for each FAR rule follow. For the actual revisions and/or amendments made by these FAR rules, refer to the specific item numbers and subjects set forth in the documents following these item summaries. FAC 2024-05 amends the FAR as follows:

Item I—Sustainable Procurement (FAR Case 2022-006)
This final rule amends the Federal Acquisition Regulation (FAR) to restructure and update FAR part 23 to focus on current environmental and sustainability matters and to implement a requirement for agencies to procure sustainable products and services to the maximum extent practicable. As a result of this rule, content related to sustainable products and services, energy savings performance contracts, hazardous and radioactive materials, pollution prevention at Federal facilities, and greenhouse gases are consolidated into single subparts at FAR subpart 23.1, 23.2, 23.3, 23.4, and 23.5, respectively. Non-environmental matters, to include requirements for a drug-free workplace and encouraging contractors to ban texting while driving, are moved to FAR part 26. The existing statutory and other Environmental Protection Agency (EPA) purchasing program requirements (previously implemented in FAR subparts 23.2, 23.4, 23.7, and 23.8) are consolidated in FAR subpart 23.1. This rule will require agencies to specify in the statement of work, or elsewhere in the contract, the sustainable products and services, including the purchasing programs and types of products or services, that are applicable to the acquisition. A new omnibus contract clause at FAR 52.223-23, Sustainable Products and Services, will require contractors to ensure the sustainable products and services identified in the contract are delivered, incorporated, or furnished under the contract. The rule also updates agency requirements for construction and architect-engineer contracts at FAR 36.104(b)(1) to align with the Council on Environmental Quality's Guiding Principles for Federal Leadership in High-Performance and Sustainable Buildings. The final rule may have a significant economic impact on a substantial number of small entities who compete on Federal contracts. These entities will need to ensure that they are offering and delivering sustainable products and services, as specified in agency solicitations and contracts.

Item II—Technical Amendments
An administrative change is made at FAR 1.106, 1.401, 4.1702, 5.704, 8.402, 8.404, 8.405-1, 8.405-2, 8.405-3, 8.405-6, 16.505, 19.305, 19.507, 28.203-1, 31.205-40, 39.000, and 52.212-3.
William F. Clark,

Director, Office of Government-wide Acquisition Policy, Office of Acquisition Policy, Office of Government-wide Policy.