81
107
Friday, June 3, 2016
Contents
Agriculture

Agriculture Department

See
Forest Service

See
Rural Business-Cooperative Service

See
Rural Utilities Service
Safety Enviromental Enforcement

Bureau of Safety and Environmental Enforcement

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Sulphur Operations,
35798-35801
2016-13102
Centers Medicare

Centers for Medicare & Medicaid Services

RULES
State Health Insurance Assistance Program,
35643-35644
2016-13136

NOTICES
Meetings:
Health Insurance Marketplace SM , Medicare, Medicaid, and Children's Health Insurance Program; Advisory Panel on Outreach and Education,
35770-35772
2016-13085
Medicare, Medicaid, and Children's Health Insurance Programs; Advisory Panel on Clinical Diagnostic Laboratory Tests,
35772-35774
2016-13084
Children

Children and Families Administration

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Migrant and Seasonal Head Start Study,
35774
2016-13104
Coast Guard

Coast Guard

RULES
Guidance:
Navigation and Vessel Inspection Circular: Medical Certification Standards, Medications, and Medical Review Process; Change,
35648-35652
2016-13158
Safety Zones:
Richland Regatta, Columbia River, Richland, WA,
35619-35621
2016-13108
Special Local Regulations:
Tri-City Water Follies Spring Testing, Kennewick, WA,
35617-35619
2016-13201

PROPOSED RULES
Safety Zones:
Safety Zones Within the Captain of the Port New Orleans Zone; New Orleans to Baton Rouge, LA,
35671-35674
2016-13119
Commerce

Commerce Department

See
Industry and Security Bureau

See
National Institute of Standards and Technology

See
National Oceanic and Atmospheric Administration
Committee for Purchase

Committee for Purchase From People Who Are Blind or Severely Disabled

NOTICES
Procurement List; Additions and Deletions,
35749-35750
2016-13126
2016-13127
Community Development

Community Development Financial Institutions Fund

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Community Development Financial Institutions Fund,
35815-35818
2016-13122
2016-13123
Community Living Administration

Community Living Administration

RULES
Administration for Community Living--Regulatory Consolidation,
35644-35648
2016-13138
Consumer Product

Consumer Product Safety Commission

NOTICES
Settlement Agreements and Orders:
Teavana Corp.,
35750-35752
2016-12944
Defense Department

Defense Department

See
Engineers Corps

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
35752-35753
2016-13107
Charter Renewals:
Federal Advisory Committees,
35753-35754
2016-13086
Delaware

Delaware River Basin Commission

RULES
Clarifying Language in the Basin Regulations—Water Supply Charges Relating to Certificates of Entitlement,
35608-35609
2016-13011

PROPOSED RULES
Rules of Practice and Procedure Concerning Regulatory Program Fees and Basin Regulations—Water Supply Charges Concerning Rates,
35662-35665
2016-13012
Education Department

Education Department

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Study of the Turnaround School Leaders Program,
35756-35757
2016-13121
Energy Department

Energy Department

See
Federal Energy Regulatory Commission
Engineers

Engineers Corps

NOTICES
Environmental Impact Statements; Availability, etc.:
Draft Integrated Feasibility Report, Flood Risk Management Study, Little Colorado River at Winslow, Navajo County, AZ,
35756
2016-13077
Lower Yellowstone Intake Diversion Dam Fish Passage Project, Dawson County, MT,
35754-35756
2016-13079
Environmental Protection

Environmental Protection Agency

RULES
Air Quality State Implementation Plans; Approvals and Promulgations:
Connecticut; Infrastructure Requirements for Lead, Ozone, Nitrogen Dioxide, Sulfur Dioxide, and Fine Particulate Matter,
35636-35641
2016-12375
North Carolina; Prong 4—2008 Ozone, 2010 NO 2 , SO 2 , and 2012 PM 2.5 ,
35634-35636
2016-13036
Federal Implementation Plans:
True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector; Amendments to the Federal Minor New Source Review Program in Indian Country To Address Requirements for True Minor Sources in the Oil and Natural Gas Sector,
35944-35981
2016-11969
Final Authorization of State Hazardous Waste Management Program Revisions:
Nevada,
35641-35643
2016-13161
Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources,
35824-35942
2016-11971
Source Determination for Certain Emission Units in the Oil and Natural Gas Sector,
35622-35634
2016-11968

PROPOSED RULES
Air Quality State Implementation Plans; Approvals and Promulgations:
Louisiana; Infrastructure State Implementation Plan Requirements for the National Ambient Air Quality Standards,
35674-35680
2016-13032

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Information Collection Effort for Oil and Gas Facilities,
35763-35766
2016-11967
Procedures for Implementing the National Environmental Policy Act and Assessing the Environmental Effects Abroad of EPA Actions,
35762-35763
2016-13153
Draft Guidance:
Pesticides; Pesticide Registrants on Herbicide Resistance Management Labeling, Education, Training, and Stewardship,
35767-35769
2016-13157
Pesticides; Pesticide Registrants on Pesticide Resistance Management Labeling,
35766-35767
2016-13155
Environmental Impact Statements; Availability,
35761-35762
2016-13150
Requests for Nominations:
Peer Reviewers; Draft Biologically Based Dose-Response Model for Perchlorate, Draft Model Support Document and Draft Approach for Deriving a Maximum Contaminant Level Goal for Perchlorate in Drinking Water,
35760-35761
2016-12724
Federal Aviation

Federal Aviation Administration

RULES
Airworthiness Directives:
BLANIK LIMITED Gliders,
35581-35583
2016-12608

PROPOSED RULES
Airworthiness Directives:
Ameri-King Corporation Emergency Locator Transmitters,
35657-35661
2016-12852
The Boeing Company Airplanes,
35655-35657
2016-12849
Special Conditions:
Bell Helicopter Textron, Inc. (BHTI), Model 525 Helicopters; Crew Alerting System,
35654-35655
2016-13148

NOTICES
Aeronautical Land-Use Assurance Waivers:
Former Willmar Municipal Airport, Willmar, MN,
35811-35812
2016-13143
Pleasanton Municipal Airport, Pleasanton, TX,
35811
2016-13147
Petitions for Exemption; Summaries,
35812-35813
2016-13074
2016-13075
2016-13076
Federal Communications

Federal Communications Commission

RULES
Television Broadcasting Services:
Scottsbluff, NE, and Sidney, NE,
35652-35653
2016-12603

PROPOSED RULES
Assessment and Collection of Regulatory Fees,
35680-35698
2016-13087
New Regulatory Framework for Business Data Services (Special Access),
36030-36075
2016-12058

NOTICES
Deletion of Consent Agenda Items From Sunshine Act Meeting,
35769
2016-13089
Federal Emergency

Federal Emergency Management Agency

NOTICES
Major Disaster and Related Determinations:
Montana,
35789-35790
2016-13178
Major Disaster Declarations:
Mississippi; Amendment No. 6,
35789
2016-13175
Missouri; Amendment No. 2,
35790
2016-13180
Missouri; Amendment No. 3,
35789
2016-13176
Federal Energy

Federal Energy Regulatory Commission

NOTICES
Clarification of Peak Reliability,
35759-35760
2016-13064
Combined Filings,
35757-35759
2016-13063
2016-13128
2016-13129
Federal Railroad

Federal Railroad Administration

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
35813-35815
2016-13141
2016-13142
Federal Trade

Federal Trade Commission

PROPOSED RULES
Labeling and Advertising of Home Insulation,
35661-35662
2016-13097
Financial Crimes

Financial Crimes Enforcement Network

PROPOSED RULES
Imposition of Special Measure Against North Korea as a Jurisdiction of Primary Money Laundering Concern,
35665-35671
2016-13037
Fish

Fish and Wildlife Service

PROPOSED RULES
Endangered and Threatened Wildlife and Plants:
90-Day Findings on Two Petitions,
35698-35701
2016-13120

NOTICES
Endangered and Threatened Wildlife and Plants Permit Applications,
35792-35793
2016-13151
Environmental Impact Statements; Availability, etc.:
South Bay Salt Pond Restoration Project, Phase 2; Don Edwards National Wildlife Refuge,
35790-35792
2016-13100
Food and Drug

Food and Drug Administration

RULES
Food Additives Permitted in Feed and Drinking Water of Animals:
Chromium Propionate,
35610-35611
2016-13082

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Reporting Associated With New Animal Drug Applications,
35774-35776
2016-13078
Guidance:
Charging for Investigational Drugs Under an Investigational New Drug Application--Questions and Answers,
35779-35781
2016-13166
E18 Genomic Sampling and Management of Genomic Data; International Council for Harmonisation,
35781-35782
2016-13168
Expanded Access to Investigational Drugs for Treatment Use--Questions and Answers,
35778-35779
2016-13165
Individual Patient Expanded Access Applications,
35776-35777
2016-13167
Meetings:
Pharmacy Compounding Advisory Committee,
35782-35783
2016-13169
Forest

Forest Service

NOTICES
Meetings:
Sabine-Angelina Resource Advisory Committee,
35733
2016-13106
Gulf Coast Ecosystem Restoration Council

Gulf Coast Ecosystem Restoration Council

NOTICES
Funding Availability:
Spill Impact Component of the RESTORE Act,
35769-35770
2016-13059
Health and Human

Health and Human Services Department

See
Centers for Medicare & Medicaid Services

See
Children and Families Administration

See
Community Living Administration

See
Food and Drug Administration

See
Health Resources and Services Administration

See
Indian Health Service

See
National Institutes of Health

RULES
Administration for Community Living—Regulatory Consolidation,
35644-35648
2016-13138
State Health Insurance Assistance Program,
35643-35644
2016-13136

NOTICES
Findings of Research Misconduct,
35785-35786
2016-13072
Health Resources

Health Resources and Services Administration

NOTICES
Petitions:
National Vaccine Injury Compensation Program,
35783-35785
2016-13073
Homeland

Homeland Security Department

See
Coast Guard

See
Federal Emergency Management Agency
Housing

Housing and Urban Development Department

NOTICES
Federal Property Suitable as Facilities To Assist the Homeless,
35790
2016-12861
Indian Health

Indian Health Service

NOTICES
Meetings:
Tribal Consultation and Urban Confer Sessions on the State of the Great Plains Area Indian Health Service,
35786-35787
2016-13135
Industry

Industry and Security Bureau

RULES
Export Administration Regulations:
Revisions to Definitions,
35586-35608
2016-12734
Interior

Interior Department

See
Bureau of Safety and Environmental Enforcement

See
Fish and Wildlife Service

See
Land Management Bureau

See
Reclamation Bureau
Internal Revenue

Internal Revenue Service

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
35818-35821
2016-13000
2016-13090
2016-13091
2016-13092
2016-13093
2016-13094
International Trade Com

International Trade Commission

NOTICES
Complaints:
Certain Inkjet Printers, Printheads, and Ink Cartridges, Components Thereof, and Products Containing Same,
35803-35804
2016-13070
Certain Magnetic Data Storage Tapes and Cartridges Containing the Same,
35802-35803
2016-13068
Certain Silicon-on-Insulator Wafers,
35801-35802
2016-13069
Labor Department

Labor Department

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Standard on 4,4'-Methylenedianiline for General Industry,
35804-35805
2016-13109
Land

Land Management Bureau

NOTICES
Environmental Assessments; Availability, etc.:
Draft Medford District Resource Management Plan Amendment Table Rocks Area of Critical Environmental Concern Proposed Boundary Change,
35796-35798
2016-13130
Environmental Impact Statements; Availability, etc.:
Draft Resource Management Plan, Uncompahgre Field Office, Colorado,
35793-35796
2016-13131
NASA

National Aeronautics and Space Administration

RULES
Cooperative Agreements With Commercial Firms,
35583-35586
2016-12850
National Institute

National Institute of Standards and Technology

NOTICES
Meetings:
Commission on Enhancing National Cybersecurity,
35733-35734
2016-13096
National Institute

National Institutes of Health

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery, National Institute of Neurological Disorders and Stroke,
35788-35789
2016-13154
Government-Owned Inventions; Availability for Licensing,
35787
2016-13112
National Oceanic

National Oceanic and Atmospheric Administration

RULES
Fisheries Off West Coast States:
Highly Migratory Species Fishery; Closure,
35653
2016-13137

PROPOSED RULES
Endangered and Threatened Species:
Critical Habitat for the Endangered Carolina and South Atlantic Distinct Population Segments of Atlantic Sturgeon,
36078-36123
2016-12744
Designation of Critical Habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments of Atlantic Sturgeon,
35701-35732
2016-12743

NOTICES
Interagency Working Group on the Harmful Algal Bloom and Hypoxia Research and Control Amendments Act,
35747-35749
2016-13110
International Trade Data System Test Concerning the Electronic Submission of Certain Data Required for Exports,
35734-35736
2016-13125
Meetings:
New England Fishery Management Council,
35736-35737
2016-13132
Sites Added to the Inventory of Possible Areas for Designation as New National Marine Sanctuaries,
35737-35739
2016-13111
Takes of Marine Mammals:
Sand Quality Study Activities at the Children's Pool Beach, La Jolla, CA,
35739-35747
2016-13171
National Science

National Science Foundation

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals,
35805-35806
2016-13081
Postal Regulatory

Postal Regulatory Commission

NOTICES
New Postal Products,
35806-35807
2016-13133
2016-13134
Postal Service

Postal Service

NOTICES
Product Changes:
First-Class Package Service Negotiated Service Agreement,
35808
2016-13061
Parcel Select Negotiated Service Agreement,
35808
2016-13062
Priority Mail Negotiated Service Agreement,
35807-35808
2016-13065
2016-13066
2016-13067
2016-13071
Presidential Documents

Presidential Documents

PROCLAMATIONS
Special Observances:
African-American Music Appreciation Month (Proc. 9455),
36125-36128
2016-13357
Great Outdoors Month (Proc. 9456),
36129-36130
2016-13358
Lesbian, Gay, Bisexual, and Transgender Pride Month (Proc. 9457),
36131-36132
2016-13361
National Caribbean-American Heritage Month (Proc. 9458),
36133-36134
2016-13363
National Oceans Month (Proc. 9459),
36135-36136
2016-13364

ADMINISTRATIVE ORDERS
Bipartisan Congressional Trade Priorities and Accountability Act of 2015; Delegation of Authority (Memorandum of May 24, 2016),
35579
2016-13290
Reclamation

Reclamation Bureau

NOTICES
Environmental Impact Statements; Availability, etc.:
Lower Yellowstone Intake Diversion Dam Fish Passage Project, Dawson County, MT,
35754-35756
2016-13079
Rural Business

Rural Business-Cooperative Service

RULES
Guaranteed Loanmaking and Servicing Regulations,
35984-36027
2016-12945
Rural Utilities

Rural Utilities Service

RULES
Guaranteed Loanmaking and Servicing Regulations,
35984-36027
2016-12945
Securities

Securities and Exchange Commission

NOTICES
Meetings; Sunshine Act,
35808-35809
2016-13213
State Department

State Department

RULES
International Traffic in Arms:
Revisions to Definition of Export and Related Definitions,
35611-35617
2016-12732

NOTICES
Meetings:
Advisory Committee on Private International Law,
35809
2016-13163
Surface Transportation

Surface Transportation Board

NOTICES
Agency Information Collection Activities; Proposals, Submissions, and Approvals:
Household Goods Movers' Disclosure Requirements,
35810-35811
2016-12897
Modified Rail Certificates of Public Convenience and Necessity:
WRL, LLC, Adams and Grant Counties, WA,
35809-35810
2016-13139
Transportation Department

Transportation Department

See
Federal Aviation Administration

See
Federal Railroad Administration
Treasury

Treasury Department

See
Community Development Financial Institutions Fund

See
Financial Crimes Enforcement Network

See
Internal Revenue Service

Separate Parts In This Issue

Part II
Environmental Protection Agency,
35824-35942
2016-11971

Part III
Environmental Protection Agency,
35944-35981
2016-11969

Part IV
Agriculture Department, Rural Business-Cooperative Service,
35984-36027
2016-12945
Agriculture Department, Rural Utilities Service,
35984-36027
2016-12945

Part V
Federal Communications Commission,
36030-36075
2016-12058

Part VI
Commerce Department, National Oceanic and Atmospheric Administration,
36078-36123
2016-12744

Part VII
Presidential Documents,
36125-36136
2016-13357
2016-13358
2016-13361
2016-13363
2016-13364

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 LISTSERV electronic mailing list, go to http://listserv.access.gpo.gov and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
81
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Friday, June 3, 2016
Rules and Regulations
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 39
[Docket No. FAA-2016-4231; Directorate Identifier 2015-CE-042-AD; Amendment 39-18537; AD 2016-11-10]
RIN 2120-AA64
Airworthiness Directives; BLANIK LIMITED Gliders

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

ACTION:
Final rule.

SUMMARY:
We are superseding airworthiness directive (AD) 2000-20-11 for BLANIK LIMITED Models L-13 Blanik and L-13 AC Blanik gliders (type certificate previously held by LET Aeronautical Works). This AD results from mandatory continuing airworthiness information (MCAI) issued by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as insufficient material strength of the tail-fuselage attachment fitting. We are issuing this AD to require actions to address the unsafe condition on these products.

DATES:
This AD is effective July 8, 2016.
The Director of the Federal Register approved the incorporation by reference of a certain other publication listed in this AD as of November 27, 2000 (65 FR 60845, October 13, 2000).

ADDRESSES:
You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-4231; or in person at the Docket Management Facility, U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590.
For service information identified in this AD, contact BLANIK LIMITED, 2nd Floor Beaux Lane House, Mercer Street Lower, Dublin 2, Republic of Ireland; phone: +420 733 662 194; email: info@blanik.aero; Internet: http://www.blanik.aero/%EF%BB%BFcustomer_support. You may view this referenced service information at the FAA, Small Airplane Directorate, 901 Locust, Kansas City, Missouri 64106. For information on the availability of this material at the FAA, call (816) 329-4148. It is also available on the Internet at http://www.regulations.gov by searching for Docket No. FAA-2016-4231.

FOR FURTHER INFORMATION CONTACT:
Jim Rutherford, Aerospace Engineer, 901 Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329-4165; fax: (816) 329-4090; email: jim.rutherford@faa.gov.

SUPPLEMENTARY INFORMATION:

Discussion
We issued a notice of proposed rulemaking (NPRM) to amend 14 CFR part 39 by adding an AD that would apply to BLANIK LIMITED Models L-13 Blanik and L-13 AC Blanik gliders. That NPRM was published in the Federal Register on March 3, 2016 (81 FR 11134), and proposed to supersede AD 2000-20-11, Amendment 39-11922 (65 FR 60845; October 13, 2000).
The NPRM proposed to correct an unsafe condition for the specified products and was based on mandatory continuing airworthiness information (MCAI) originated by an aviation authority of another country. The MCAI states that:
To prevent destruction of tail-fuselage attachment fitting which can lead to loss of control of the sailplane. This destruction could be caused due to lower strength of the material used during production.
The MCAI can be found in the AD docket on the Internet at: https://www.regulations.gov/#!documentDetail;D=FAA-2016-4231-0003.
A review of records since issuance of AD 2000-20-11 revealed that the FAA inadvertently did not address this MCAI for the EVEKCTOR, spol. s.r.o. Model L 13 SDM VIVAT gliders and the BLANIK LIMITED Model L-13 AC Blanik gliders. This AD supersedes AD 2000-20-11 to add the BLANIK LIMITED Model L-13 AC Blanik gliders to the applicability of the AD.
The FAA is addressing the EVEKTOR, spol. s.r.o. Model L 13 SDM VIVAT gliders in another AD action.

Comments
We gave the public the opportunity to participate in developing this AD. We received no comments on the NPRM (81 FR 11134, March 3, 2016) or on the determination of the cost to the public.

Conclusion
We reviewed the relevant data and determined that air safety and the public interest require adopting the AD as proposed except for minor editorial changes. We have determined that these minor changes:
• Are consistent with the intent that was proposed in the NPRM (81 FR 11134, March 3, 2016) for correcting the unsafe condition; and
• Do not add any additional burden upon the public than was already proposed in the NPRM (81 FR 11134, March 3, 2016).

Related Service Information Under 1 CFR Part 51
LET Aeronautical Works has issued LET Mandatory Bulletin No.: L13/085a, dated November 17, 1999. The service information describes procedures for testing the material strength of attachment fitting part number A 102 021 N and instructions for contacting the manufacturer for replacement information if necessary. 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 the ADDRESSES section of the AD.

Costs of Compliance
We estimate that this AD will affect 124 products of U.S. registry. We also estimate that it would take about 4 work-hours per product to comply with the basic requirements of this AD. The average labor rate is $85 per work-hour.
Based on these figures, we estimate the cost of the AD on U.S. operators to be $42,160, or $340 per product.
In addition, we estimate that any necessary follow-on actions would take about 16 work-hours and require parts costing $500, for a cost of $1,860 per product. We have no way of determining the number of products that may need these actions.

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.
We are 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
We 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 this AD:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska, and
(4) 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.

Examining the AD Docket
You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-4231; or in person at the Docket Management Facility between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains the NPRM, the regulatory evaluation, any comments received, and other information. The street address for the Docket Office (telephone (800) 647-5527) is in the ADDRESSES section. Comments will be available in the AD docket shortly after receipt.

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

Adoption of 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 removing Amendment 39-11922 (65 FR 60845; October 13, 2000) and adding the following new AD:
2016-11-10 BLANIK LIMITED: Amendment 39-18537; Docket No. FAA-2016-4231; Directorate Identifier 2015-CE-042-AD.

(a) Effective Date
This airworthiness directive (AD) becomes effective July 8, 2016.

(b) Affected ADs
This AD supersedes AD 2000-20-11, Amendment 39-11922 (65 FR 60845; October 13, 2000) (“AD 2000-20-11”).

(c) Applicability
This AD applies to BLANIK LIMITED Models L-13 Blanik and L-13 AC Blanik gliders (type certificate previously held by LET Aeronautical Works), all serial numbers, certificated in any category.

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

(e) Reason
This AD was prompted by mandatory continuing airworthiness information (MCAI) originated by an aviation authority of another country to identify and correct an unsafe condition on an aviation product. The MCAI describes the unsafe condition as insufficient material strength of the tail-fuselage attachment fitting. We are issuing this AD to detect and correct tail-fuselage fittings with insufficient material strength, which if left uncorrected could result in detachment of the tail from the fuselage with consequent loss of control.

(f) Actions and Compliance
Unless already done, do the following actions in paragraphs (f)(1) and (f)(2) of this AD, including all subparagraphs:
(1) Model L-13 Blanik gliders:
(i) Within the next 60 days after November 27, 2000 (the effective date retained from AD 2000-20-11), inspect the tail-fuselage attachment fitting, part number (P/N) A 102 021 N, for damage and material hardness following the procedures in LET Mandatory Bulletin No.: L13/085a, dated November 17, 1999.
(ii) If you find the tail-fuselage attachment fitting is damaged or the material does not meet the hardness requirements specified in the service bulletin during the inspection required in paragraph (f)(1)(i) of this AD, before further flight, you must contact the manufacturer to obtain an FAA-approved replacement part for P/N A 102 021 N and FAA-approved installation instructions and install the replacement part. Use the contact information found in paragraph (i)(4) to contact the manufacturer.
(iii) As of November 27, 2000 (the effective date retained from AD 2000-20-11), do not install, on any glider, a P/N A 102 021 N attachment fitting that has not passed the inspection required in paragraph (f)(1)(i) of this AD.
(2) Model L-13 AC Blanik gliders:
(i) Within the next 60 days after July 8, 2016 (the effective date of this AD), inspect the tail-fuselage attachment fitting, P/N A 102 021 N, for damage and material hardness following the procedures in LET Mandatory Bulletin No.: L13/085a, dated November 17, 1999.
(ii) If you find the tail-fuselage attachment fitting is damaged or the material does not meet the hardness requirements specified in the service bulletin during the inspection required in paragraph (f)(2)(i) of this AD, before further flight, you must contact the manufacturer to obtain an FAA-approved replacement part for P/N A 102 021 N and FAA-approved installation instructions and install the replacement part. Use the contact information found in paragraph (i)(4) to contact the manufacturer.
(iii) As of July 8, 2016 (the effective date of this AD), do not install, on any glider, a P/N A 102 021N attachment fitting that has not passed the inspection required in paragraph (f)(2)(i) of this AD.

(g) Other FAA AD Provisions
The following provisions also apply to this AD:
(1) Alternative Methods of Compliance (AMOCs): The Manager, Standards Office, FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. Send information to ATTN: Jim Rutherford, Aerospace Engineer, FAA, Small Airplane Directorate, 901 Locust, Room 301, Kansas City, Missouri 64106; telephone: (816) 329-4165; fax: (816) 329-4090; email: jim.rutherford@faa.gov. Before using any approved AMOC on any airplane to which the AMOC applies, notify your appropriate principal inspector (PI) in the FAA Flight Standards District Office (FSDO), or lacking a PI, your local FSDO.
(2) Airworthy Product: For any requirement in this AD to obtain corrective actions from a manufacturer or other source, use these actions if they are FAA-approved. Corrective actions are considered FAA-approved if they are approved by the State of Design Authority (or their delegated agent). You are required to assure the product is airworthy before it is returned to service.

(h) Related Information
Refer to MCAI Civil Aviation Authority AD CAA-AD-T-112/1999R1, dated November 23, 1999, for related information. The MCAI can be found in the AD docket on the Internet at: https://www.regulations.gov/#!documentDetail;D=FAA-2016-4231-0003.

(i) 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.
(3) The following service information was approved for IBR on November 27, 2000 (65 FR 60845, October 13, 2000).
(i) LET Mandatory Bulletin No.: L13/085a, dated November 17, 1999.
(ii) Reserved.
(4) For service information identified in this AD, contact BLANIK LIMITED, 2nd Floor Beaux Lane House, Mercer Street Lower, Dublin 2, Republic of Ireland; phone: +420 733 662 194; email: info@blanik.aero; Internet: http://www.blanik.aero/%EF%BB%BFcustomer_support.
(5) You may view this service information at the FAA, Small Airplane Directorate, 901 Locust, Kansas City, Missouri 64106. For information on the availability of this material at the FAA, call (816) 329-4148. In addition, you can access this service information on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-4231.
(6) You may view this service information that is incorporated by reference at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html.
Issued in Kansas City, Missouri, on May 23, 2016.
Pat Mullen,

Acting Manager, Small Airplane Directorate, Aircraft Certification Service.
NATIONAL AERONAUTICS AND SPACE ADMINISTRATION
14 CFR Part 1274
[NFS Case 2015-N014]
RIN 2700-AE25
Cooperative Agreements With Commercial Firms

AGENCY:
National Aeronautics and Space Administration.

ACTION:
Final rule.

SUMMARY:
NASA is issuing a final rule amending its regulation on Cooperative Agreements with Commercial Firms to implement section 872 of the National Defense Authorization Act for Fiscal Year 2009. The revision is part of NASA's retrospective plan under Executive Order (EO) 13563 completed in August 2011.

DATES:
Effective: July 5, 2016.

FOR FURTHER INFORMATION CONTACT:
Barbara Orlando, telephone (202) 358-3911.

SUPPLEMENTARY INFORMATION:

I. Background
This final rule implements the requirements of section 872 for recipients and NASA staff to report information that will appear in the Federal Awardee Performance and Integrity Information System (FAPIIS). Pursuant to section 872, NASA will consider information contained within the system about a non-Federal entity before awarding a grant or cooperative agreement to that non-Federal entity. The rule also addresses how FAPIIS and other information may be used in assessing recipient integrity. The major elements of the rule are summarized as follows:
• NASA is to report information in FAPIIS about—
Any termination of an award due to a material failure to comply with the award terms and conditions;
Any administrative agreement with a non-Federal entity to resolve a suspension or debarment proceeding; and
Any finding that a non-Federal entity is not qualified to receive a given award, if the finding is based on criteria related to the non-Federal entity's integrity or prior performance under Federal awards and it is anticipated that the total Federal funding will exceed the simplified threshold during the period of performance.
• Recipients that have Federal contract, grant, and cooperative agreement awards with a cumulative total value greater than $10,000,000 must enter information in FAPIIS about certain civil, criminal, and administrative proceedings that reached final disposition within the most recent five year period and that were connected with the award or performance of a Federal award.
• Recipients that have been awarded a Federal contract, grant, and cooperative agreement with a cumulative total value greater than $10,000,000 are required to disclose semiannually the information about the criminal, civil, and administrative proceedings as described in section 872(c).
• Federal awarding agencies, prior to making an award to a non-Federal entity, must review FAPIIS to determine whether that non-Federal entity is qualified to receive the Federal award. In making the determination, NASA must take into consideration any information about the entity that is in FAPIIS.
• Notice of funding opportunities and Federal award terms and conditions to inform a non-Federal entity that it may submit comments in FAPIIS about any information that NASA had reported to the system about the non-Federal entity, for consideration by NASA in making future Federal awards to the non-Federal entity.
NASA published a proposed rule in Federal Register on Feb. 22, 2016, to revise 14 CFR part 1274 to implement Section 872 of the Duncan Hunter National Defense Authorization Act (NDAA) for Fiscal Year (FY) 2009 (Pub. L. 110-417, codified as amended at 41 U.S.C. 2313, as it applies to cooperative agreements.

II. Discussion and Analysis
On February 22, 2016, NASA published a proposed rule in the Federal Register (81 FR 8671) and received a comment from one respondent. NASA reviewed the comment in the formation of the final rule and determined that the comment was not within the scope of the regulation. No revisions to the proposed rule were made as a result of the public comment received.

III. Executive Orders 12866 and 13563
Executive Orders (E.O.s) 12866 and 13563 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). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This is not a significant regulatory action and, therefore, was not subject to review under section 6(b) of E.O. 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.

IV. Paperwork Reduction Act
The Paperwork Reduction Act (Pub. L. 104-13) does not apply because this final rule does not contain any information collection requirements that require the approval of the Office of Management and Budget under 44 U.S.C. 3501, et seq.
List of Subjects in 14 CFR Part 1274 Federal financial assistance.
Manuel Quinones,

Federal Register Liaison.
Accordingly, 14 CFR part 1274 is amended as follows:

PART 1274—COOPERATIVE AGREEMENTS WITH COMMERCIAL FIRMS
1. The authority citation for 14 CFR part 1274 is revised to read as follows:

Authority:
51 U.S.C. 20113(e) and 31 U.S.C. 6301 to 6308; 51 U.S.C. 20102, et seq.
2. Amend § 1274.203 by adding paragraph (g) to read as follows:
§ 1274.203
Solicitations/cooperative agreement notices.
* * * * *
(g) If NASA anticipates that the total Federal share of any award made under a funding agreement may exceed, over the period of performance, the simplified acquisition threshold, the notice of funding opportunity must include the information as required in Appendix 1 to Part 200, paragraph E.3, paragraph E.4, and paragraph F.3.
3. Amend § 1274.209 by redesignating paragraphs (e) through (l) as (f) through (m), respectively and adding a new paragraph (e) to read as follows:
§ 1274.209
Evaluation and selection.
* * * * *
(e)(1) Prior to making a Federal award, agreement officers are required by 31 U.S.C. 3321 and 41 U.S.C. 2313 note, to review information available through any OMB-designated repositories of governmentwide eligibility qualification, currently the System of Award Management (SAM), or financial integrity information (currently Federal Awardee Performance and Integrity Information System (FAPIIS)), as appropriate. See also suspension and debarment requirements at 2 CFR part 180 as well as individual Federal agency suspension and debarment regulations in title 2 of the Code of Federal Regulations.
(2) In accordance with 41 U.S.C. 2313, agreement officers are required to review the non-public segment of FAPIIS prior to making a Federal award where the Federal share is expected to exceed the simplified acquisition threshold, defined in 41 U.S.C. 134, over the period of performance. At a minimum, the information in the system for a prior Federal award recipient must demonstrate a satisfactory record of executing programs or activities under Federal grants, cooperative agreements, or procurement awards; and integrity and business ethics. NASA may make a Federal award to a recipient who does not fully meet these standards, if it is determined that the information is not relevant to the current Federal award under consideration or there are specific conditions that can appropriately mitigate the effects of the non-Federal entity's risk in accordance with 2 CFR 200.207, Specific conditions.
* * * * *
4. Amend § 1274.211 by:
a. In paragraph (c), removing “ Central Contractor Registration (CCR) ” and adding “ System for Award Management (SAM) ” in its place; removing “Department of Defense (DOD) Central Contractor Registration (CCR)” and adding “System for Award Management” in its place; removing “CCR” and adding “SAM” in its place; and removing “ http://www.ccr2000.com or by calling toll free: 888-227-2423, commercial: 616-961-5757” and adding “ https://www.sam.gov ” in its place; and
b. Adding paragraph (d)(5) to read as follows:
§ 1274.211
Award procedures.
* * * * *
(d) * * *
(5) The non-Federal entity or applicant for a Federal award must disclose, in a timely manner, in writing to the assigned agreement officer or pass-through entity all violations of Federal criminal law involving fraud, bribery, or gratuity violations potentially affecting the Federal award. Non-Federal entities that have received a Federal award including the term and condition outlined in Appendix XII—Award Term and Condition for Recipient Integrity and Performance Matters are required to report certain civil, criminal, or administrative proceedings to SAM. Failure to make required disclosures can result in any of the remedies described in § 200.338 Remedies for noncompliance, including suspension or debarment. (See also 2 CFR part 180, 31 U.S.C. 3321, and 41 U.S.C. 2313.)
5. Amend § 1274.212 by revising the section heading and adding paragraph (c) to read as follows:
§ 1274.212
Award information.
* * * * *
(c) Recipient integrity and performance matters. If the total Federal share of the Federal award is more than $500,000 over the period of performance, agreement officers must include the terms and conditions in § 1274.944 of this chapter.
6. Amend subpart 1274.3 by adding new §§ 1274.303 and 1274.304 to read as follows:
§ 1274.303
Public access to Federal award information.
(a) In accordance with statutory requirements for Federal spending transparency ( e.g., FFATA), except as noted in this section, for applicable Federal awards NASA must announce all Federal awards publicly and publish the required information at www.USAspending.gov.
(b) All information posted in FAPIIS, accessible through SAM, on or after April 15, 2011 will be publicly available after a waiting period of 14 calendar days, except for—
(1) Past performance reviews required by Federal Government contractors in accordance with the Federal Acquisition Regulation (FAR) 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 the Federal Government official.
(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.
§ 1274.304
Reporting a determination that a non-Federal entity is not qualified for a Federal award.
(a) If NASA does not make a Federal award to a non-Federal entity because the agreement officer determines that the non-Federal entity does not meet either or both of the minimum qualification standards, as described in paragraph (a)(2) of 2 CFR 200.205, the agreement officer must report that determination in FAPIIS, accessible through SAM, only if all of the following apply:
(1) The only basis for the determination described in paragraph (a) of this section is the non-Federal entity's prior record of executing programs or activities under Federal awards or its record of integrity and business ethics, as described in paragraph (a)(2) of 2 CFR 200.205, ( i.e., the entity was determined to be qualified based on all factors other than those two standards); and
(2) The total Federal share of the Federal award that otherwise would be made to the non-Federal entity is expected to exceed the simplified acquisition threshold over the period of performance.
(b) Agreement officers are not required to report a determination that a non-Federal entity is not qualified for a Federal award if they make the Federal award to the non-Federal entity and includes specific award terms and conditions (see § 1274.209).
(c) If the agreement officer reports a determination that a non-Federal entity is not qualified for a Federal award, as described in paragraph (a) of this section, the agreement officer also must notify the non-Federal entity that—
(1) The determination was made and reported to FAPIIS, accessible through SAM, and include with the notification an explanation of the basis for the determination;
(2) The information will be kept in the system for a period of five years from the date of the determination, as required by section 872 of Public Law 110-417, as amended (41 U.S.C. 2313), then archived;
(3) Agreement officers making a Federal award to the non-Federal entity during that five year period must consider the information found in FAPIIS when judging whether the non-Federal entity is qualified to receive the Federal award when the total Federal share of the Federal award is expected to include an amount of Federal funding in excess of the simplified acquisition threshold over the period of performance of the award;
(4) The non-Federal entity may go to the awardee integrity and performance portal accessible through SAM (currently the Contractor Performance Assessment Reporting System (CPARS)) and comment on any information the system contains about the non-Federal entity itself; and
(5) Agreement officers will consider that non-Federal entity's comments in determining whether the non-Federal entity is qualified for a future Federal award.
(d) If the agreement officer enters information into FAPIIS about a determination that a non-Federal entity is not qualified for a Federal award and subsequently—
(1) Learns that any of that information is erroneous, the agreement officer 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 awarding agencies, the agreement officer is strongly encouraged to amend the information in the system to incorporate the update in a timely way.
(e) The agreement officer shall not post any information that will be made publicly available in the non-public segment of designated integrity and performance system that is covered by a disclosure exemption under the Freedom of Information Act. If the recipient asserts within seven calendar days to NASA that some or all of the information made publicly available is covered by a disclosure exemption under the Freedom of Information Act, agreement officers must remove the posting within seven calendar days of receiving the assertion. Prior to reposting the releasable information, agreement officers must resolve the issue in accordance with the agency's Freedom of Information Act procedures.
7. Amend § 1274.701 by adding paragraphs (b)(5) through (b)(8), (c), and (d) to read as follows:
§ 1274.701
Suspension or termination.
* * * * *
(b) * * *
(5) When NASA terminates a Federal award prior to the end of the period of performance due to the non-Federal entity's material failure to comply with the Federal award terms and conditions, NASA must report the termination in FAPIIS.
(6) The information required under paragraph (b) of this section is not to be reported to designated integrity and performance system until the non-Federal entity either—
(i) Has exhausted its opportunities to object or challenge the decision, see § 200.341 Opportunities to object, hearings and appeals; or
(ii) Has not, within 30 calendar days after being notified of the termination, informed the agreement officer that it intends to appeal the decision to terminate.
(7) If the agreement officer, after entering information into FAPIIS about a termination, subsequently:
(i) Learns that any of that information is erroneous, the agreement officer 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 awarding agencies, the agreement officer is strongly encouraged to amend the information in the system to incorporate the update in a timely way.
(8) Agreement officers shall not post any information that will be made publicly available in the non-public segment of designated integrity and performance system that is covered by a disclosure exemption under the Freedom of Information Act. If the non-Federal entity asserts within seven calendar days to the Federal awarding agency who posted the information that some of the information made publicly available is covered by a disclosure exemption under the Freedom of Information Act, agreement officers must remove the posting within seven calendar days of receiving the assertion. Prior to reposting the releasable information, agreement officers must resolve the issue in accordance with the agency's Freedom of Information Act procedures.
(c) When a Federal award is terminated or partially terminated, both NASA or the pass-through entity and the non-Federal entity remain responsible for compliance with the closeout and post-closeout requirements and continuing responsibilities.
(d) Notification of termination requirement. If the Federal award is terminated for the non-Federal entity's material failure to comply with the Federal statutes, regulations, or terms and conditions of the Federal award, the notification must state that—
(1) The termination decision will be reported in FAPIIS, accessible through SAM;
(2) The information will be available in FAPIIS for a period of five years from the date of the termination, then archived;
(3) When considering making a Federal award to the non-Federal entity during that five year period, NASA must consider that information in judging whether the non-Federal entity 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 non-Federal entity may comment on any information that the OMB-designated integrity and performance system contains about the non-Federal entity for future consideration by NASA. The non-Federal entity may submit comments to the awardee integrity and performance portal accessible through SAM (currently (CPARS).
(5) Agreement officers will consider non-Federal entity comments when determining whether the non-Federal entity is qualified for a future Federal award.
8. Add § 1274.803 to read as follows:
§ 1274.803
Suspension and Debarment.
Non-federal entities are subject to the non-procurement debarment and suspension regulations implementing Executive Orders 12549 and 12689, 2 CFR part 180, adopted by NASA at 2 CFR part 1880. These regulations restrict awards, subawards, and contracts with certain parties that are debarred, suspended, or otherwise excluded from or ineligible for participation in Federal assistance programs or activities.
9. Amend subpart 1274.9 by adding § 1274.944 to read as follows:
§ 1274.944
Award term and condition for recipient integrity and performance matters.
(a) Reporting of matters related to recipient integrity and performance —(1) General reporting requirement. (i) If the total value of your currently active grants, cooperative agreements, and procurement contracts from all Federal awarding agencies exceeds $10,000,000 for any period during the period of performance of this Federal award, then you as the recipient during that period of time must maintain the currency of information reported in FAPIIS about civil, criminal, or administrative proceedings described in paragraph (a)(2) of this section. This is a statutory requirement under section 872 of Public Law 110-417, as amended (41 U.S.C. 2313).
(ii) As required by section 3010 of Public Law 111-212, all information posted in FAPIIS on or after April 15, 2011, except past performance reviews required for Federal procurement contracts, will be publicly available.
(2) Proceedings about which you must report. Submit the information required 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, as defined in paragraph (a)(5)(ii) of this section.
(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, as defined in paragraph (a)(5)(i) of this award term and condition, 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.
(D) Any other criminal, civil, or administrative proceeding if—
( 1 ) It could have led to an outcome described in paragraph (a)(2)(iii)(A), (B), or (C) of this section;
( 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 and condition to disclose information about the proceeding does not conflict with applicable laws and regulations.
(3) Reporting procedures. Enter in the SAM Entity Management area the information that SAM requires about each proceeding described in paragraph (a)(4) of this section. You do not need to submit the information a second time under assistance awards that you received if you already provided the information through SAM, because you were required to do so under Federal procurement contracts that you were awarded.
(4) Reporting frequency. During any period of time when you are subject to the requirement in paragraph (a)(1) of this section, you must report proceedings information through SAM for the most recent five year period, either to report new information about any proceeding(s) that you have not reported previously or affirm that there is no new information to report. Recipients that have Federal contract, grant, and cooperative agreement awards with a cumulative total value greater than $10,000,000 must disclose semiannually any information about the criminal, civil, and administrative proceedings.
(5) Definitions. For purposes of this section:
(i) Administrative proceeding means a non-judicial process that is adjudicatory in nature in order to make a determination of fault or liability ( e.g., 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 performance of a Federal contract or grant. It does not include audits, site visits, corrective plans, or inspection of deliverables.
(ii) Conviction, for purposes of this award term and condition, 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.
(6) Total value of currently active grants, cooperative agreements, and procurement contracts includes—
(i) Only the Federal share of the funding under any Federal award with a recipient cost share or match; and
(ii) The value of all expected funding increments under a Federal award and options, even if not yet exercised.
(b) [Reserved]
DEPARTMENT OF COMMERCE
Bureau of Industry and Security
15 CFR Parts 734, 740, 750, and 772
[Docket No. 141016858-6004-02]
RIN 0694-AG32
Revisions to Definitions in the Export Administration Regulations

AGENCY:
Bureau of Industry and Security, Commerce.

ACTION:
Final rule.

SUMMARY:
This final rule is part of the Administration's Export Control Reform (ECR) Initiative. The Initiative will enhance U.S. national and economic security, facilitate compliance with export controls, update the controls, and further the goal of reducing unnecessary regulatory burdens on U.S. exporters. As part of this effort, the Bureau of Industry and Security (BIS), in publishing this rule, makes revisions to the Export Administration Regulations (EAR) to include certain definitions to enhance clarity and consistency with terms also found in the International Traffic in Arms Regulations (ITAR), which is administered by the Department of State, Directorate of Defense Trade Controls (DDTC), or that DDTC expects to publish in proposed rules. This final rule also revises the Scope part of the EAR to update and clarify application of controls to electronically transmitted and stored technology and software, including by way of cloud computing. DDTC is concurrently publishing comparable amendments to certain ITAR definitions for the same reasons. Finally, this rule makes conforming changes to related provisions.

DATES:
This rule is effective September 1, 2016.

ADDRESSES:
Although there is no formal comment period, public comments on this final rule are welcome on a continuing basis. You may submit comments by either of the following methods:
• By email directly to publiccomments@bis.doc.gov . Include RIN 0694-AG32 in the subject line.
• By mail or delivery to Regulatory Policy Division, Bureau of Industry and Security, U.S. Department of Commerce, Room 2099B, 14th Street and Pennsylvania Avenue NW., Washington, DC 20230. Refer to RIN 0694-AG32.
Commerce's full plan for retrospective regulatory review can be accessed at: http://open.commerce.gov/news/2011/08/23/commerce-plan-retrospective-analysis-existing-rules .

FOR FURTHER INFORMATION CONTACT:
For questions on application of controls to electronically transmitted and stored technology and software, contact Bob Rarog, Senior Advisor to the Assistant Secretary for Export Administration, Bureau of Industry and Security at (202) 482-9089. For other questions, contact Hillary Hess, Director, Regulatory Policy Division, Office of Exporter Services, Bureau of Industry and Security at (202) 482-2440 or rpd2@bis.doc.gov .

SUPPLEMENTARY INFORMATION:

Background
This final rule is part of the Administration's Export Control Reform (ECR) Initiative. The Initiative will enhance U.S. national and economic security, facilitate compliance with export controls, update the controls, and continue the process of reducing unnecessary regulatory burdens on U.S. exporters. As part of this effort, the Bureau of Industry and Security (BIS), in publishing this rule, makes revisions to the Export Administration Regulations (EAR) to include the definitions of “access information,” “technology,” “required,” “foreign person,” “proscribed person,” “published,” results of “fundamental research,” “export,” “reexport,” “release,” “transfer,” and “transfer (in-country)” to enhance clarity and consistency with terms also found in the International Traffic in Arms Regulations (ITAR), which is administered by the Department of State, Directorate of Defense Trade Controls (DDTC). This final rule also revises the Scope part of the EAR to update and clarify application of controls to electronically transmitted and stored technology and software. DDTC is concurrently publishing comparable amendments to the ITAR's definitions of “export,” “reexport,” “release,” and “retransfer” for the same reasons. Finally, this rule makes conforming changes to related provisions. DDTC anticipates publishing its comparable provisions pertaining to “technical data,” “directly related,” “public domain,” and the results of “fundamental research” in a separate proposed rule.
One aspect of the ECR Initiative includes amending the export control regulations to facilitate enhanced compliance while reducing unnecessary regulatory burdens. For similar national security, foreign policy, including human rights, reasons, the EAR and the ITAR each control, inter alia, the export, reexport, and in-country transfer by U.S. and foreign persons of commodities, products or articles, technology, technical data, software, and services to various destinations, end users, and end uses. The two sets of regulations have been issued pursuant to different statutes, have been administered by different agencies with missions that are distinct from one another in certain respects, and have covered different items (or articles). For those reasons, and because each set of regulations has evolved separately over decades without much coordination between the two agencies regarding their structure and content, they often use different words, or the same words differently, to accomplish similar regulatory objectives.
Many parties' export, reexport, and transfer transactions are regulated by both the Commerce Department's EAR and the State Department's ITAR, particularly now that regulatory jurisdiction over many types of military items has been transferred from the ITAR to the EAR. Using common terms and common definitions to regulate the same types of items or actions will facilitate enhanced compliance and reduce unnecessary regulatory burdens. Conversely, if different concerns between the two sets of export control regulations warrant different terms or different controls, the differences should be made clear for the same reason. Such clarity will benefit national security because it will be easier for exporters to comply with the regulations and for prosecutors to prosecute violations of the regulations. Such clarity will also enhance our economic security because it will reduce unnecessary regulatory burdens for exporters when attempting to determine the meaning of key words and phrases across similar sets of regulations. Finally, this rule and the rule DDTC is publishing concurrently address only a portion of the terms and phrases that warrant harmonization between the ITAR and the EAR. They are nonetheless a significant step toward accomplishing one of the ultimate objectives of the ECR initiative, which is the creation of a common export control list and common set of export control regulations.

Proposed Rule
On June 3, 2015, BIS published a proposed rule entitled “Revisions to Definitions in the Export Administration Regulations” (80 FR 31505) (hereafter “the June 3 proposed rule” or “the June 3 rule”). Simultaneously, the Department of State published a proposed rule entitled “International Traffic in Arms: Revisions to Definitions of Defense Services, Technical Data, and Public Domain; Definition of Product of Fundamental Research; Electronic Transmission and Storage of Technical Data; and Related Definitions” (80 FR 31525) (hereafter “the State June 3 rule”).
BIS welcomed comments on all aspects of the June 3 rule. Additionally, in the preamble to the June 3 rule, BIS specifically solicited public comment with questions on eight issues. Two of those questions pertained to the definition of fundamental research; one pertained to whether the questions and answers in Supplement No. 1 to part 734 had criteria that should be retained in part 734; two pertained to encryption standards in the definition of “Activities that are Not Exports, Reexports, or Transfers;” and one pertained to the effectiveness of the proposed definition of “peculiarly responsible.” Public comments on these questions are addressed in their corresponding sections below.
The two remaining questions were broadly applicable across the rule: Whether the proposed revisions created gaps, overlaps, or contradictions between the EAR and the ITAR or among various provisions within the EAR; and whether a 30-day delayed effective date was appropriate for the final rule.
Eleven commenters cited the difference between the EAR and ITAR standards for prepublication review of research as a significant gap between the two bodies of regulations that would create compliance difficulties. These commenters recommended that both final rules adopt the EAR standard. Further discussion of this issue may be found in the section of the preamble describing fundamental research, below.
Twenty-two commenters recommended a six-month delayed effective date from date of publication. Most of these commenters explicitly based the recommendation on the anticipated difficulty created by adoption of differing proposed EAR and ITAR standards for prepublication review of research. State is not publishing revisions to fundamental research at this time; therefore, the rationale for requesting a six-month delay is largely eliminated.
One commenter recommended at least a three-month delayed effective date to enable non-U.S. companies to understand and prepare for compliance with the revisions. BIS accepts this recommendation, and this final rule will be effective 90 days from the date of publication.
One commenter recommended issuing an interim final rule with a comment period of at least 60 days due to the breadth of the proposed changes. BIS does not accept this recommendation, because this final rule has a 90-day delayed effective date, which is a longer delay than generally applies to an interim final rule. The State rule published concurrently with this final rule also has a 90-day delayed effective date. Moreover, the State Department plans to publish a second proposed rule seeking comment on most of the terms at issue.

Frequently Asked Questions
Objectives of this final rule include streamlining, clarifying, and updating regulatory text. BIS has attempted to focus the regulatory text on control criteria, limiting notes and examples to those necessary to adequately convey the criteria. Many public comments raised questions about how criteria would be applied in particular situations or suggested illustrative revisions. BIS considers these comments helpful to compliance with the EAR and is publishing them along with responses on the BIS Web site as Frequently Asked Questions (FAQs).

Items Subject to the EAR
The June 3 rule proposed re-titling the section “Subject to the EAR” (from “Important EAR terms and principles”), retaining the definition and description of that term, and creating separate sections in part 734 to define “export,” “reexport,” “release,” and “transfer (in-country),” rather than retaining them in that section. The June 3 rule also proposed removing § 734.2(b)(7) regarding the listing of foreign territories and possessions in the Commerce Country Chart (Supplement No. 1 to part 738) because it duplicated existing § 738.3(b).
BIS received no comments on its proposed revisions to § 734.2. These revisions are adopted in this final rule.

Items Not Subject to the EAR
Section 734.3(a) describes items ( i.e., commodities, software, and technology) subject to the EAR. Paragraph (b) describes items that are not subject to the EAR. The June 3 rule proposed minor revisions to paragraph (b)(3), which describes software and technology that are not subject to the EAR, to describe more fully educational and patent information that are not subject to the EAR, and to add a note to make explicit that information that is not “technology” as defined in the EAR is per se not subject to the EAR. One commenter specifically offered support for inclusion of the note, and no commenters objected to it; BIS has adopted it in this final rule.

Educational Information
The June 3 rule proposed to move the statement in § 734.9 that educational information released by instruction in a catalog course or associated teaching laboratory of an academic institution is not subject to the EAR to § 734.3(b) and remove § 734.9. The June 3 rule also proposed to revise the description of such educational information as information and software that “[c]oncern general scientific, mathematical, or engineering principles commonly taught in schools, and released by instruction in a catalog course or associated teaching laboratory of an academic institution” to better match the existing ITAR description. The proposed revisions were not intended to change the scope of educational information that is not subject to the EAR.
Twenty-seven commenters stated that, in spite of BIS's declared intent to leave the scope of this provision unchanged, the proposed revision in fact narrowed the scope of educational information that is not subject to the EAR. With the adoption of the terms in the comparable ITAR provision, such as “general” and “commonly,” commenters said that the revision could be read to make courses with advanced or novel content subject to the EAR and suggested either changing “and released by instruction” to “or released by instruction” or reverting to the existing wording. BIS agrees that the revision could be read to narrow the scope of the exclusion, and because this narrowing was not intended, reverts to the existing wording in this final rule.
BIS received no comments on the placement of the educational information provision in the list of information that is per se not subject to the EAR rather than in a separate section. BIS adopts the proposed placement in this final rule.

Additional Exclusions
This final rule adopts two additional revisions that were not in § 734.3(b)(3) in the June 3 proposed rule. This final rule adds paragraphs (b)(3)(v) and (vi), two additional exclusions from the EAR: Items that are non-proprietary system descriptions or are telemetry data. These two exclusions appeared in the June 3 proposed rule as exclusions from the definition of technology. For discussion of public comments on these exclusions and BIS's response to those comments, see the section on “Technology” below.

Exports of Encryption Source Code Notes
The June 3 rule proposed no changes to the notes to paragraphs (b)(2) and (b)(3) of § 734.3 that a printed book or other printed material setting forth encryption source code is not itself subject to the EAR, but that encryption source code in electronic form or media remains subject to the EAR. It also proposed no changes to the note that publicly available encryption object code software classified under Export Control Classification Number (ECCN) 5D002 is not subject to the EAR when the corresponding source code meets the criteria specified in § 740.13(e) of the EAR.
BIS received no comments on these notes, and this final rule makes no changes to them.

Published Technology and Software
Section 734.7 sets forth that technology and software is “published” and thus not subject to the EAR when it becomes generally accessible to the interested public in any form, including through publication, availability at libraries, patents, distribution or presentation at open gatherings, and public dissemination ( i.e., unlimited distribution) in any form ( e.g., not necessarily in published form), including posting on the Internet on sites available to the public.
The June 3 rule proposed a definition of “published” that retained the same scope, but with a simpler structure. The proposed § 734.7(a) read: “Except as set forth in paragraph (b), “technology” or “software” is “published” and is thus not “technology” or “software” subject to the EAR when it is not classified national security information and has been made available to the public without restrictions upon its further dissemination,” followed by a list of examples of published information. The proposed definition was substantially the same as the wording of definitions adopted by the multilateral export control regimes of which the United States is a member: The Wassenaar Arrangement on Export Controls for Conventional Arms and Dual-Use Goods and Technologies (herein “Wassenaar Arrangement” or “Wassenaar”), the Nuclear Suppliers Group, the Missile Technology Control Regime, and the Australia Group. The phrase “classified national security information” refers to information that has been classified in accordance with Executive Order 13526, 75 FR 707; 3 CFR 2010 Comp., p. 298. The relevant restrictions do not include copyright protections or generic property rights in the underlying physical medium.
This final rule adopts the definition of “published” from the June 3 proposed rule, with the exception of adding certain information, intended to be published, released to “researchers conducting fundamental research” (see discussion below of “Fundamental Research”). BIS received a number of comments on the definition of “published.” Two commenters found helpful the addressing of Internet posting and the clarification that submission of manuscripts to journal editors constitutes “published.” Commenters requested that BIS define “unclassified” and clarify whether university libraries are “open to the public.” “Unclassified information” refers to information that has not been classified in accordance with Executive Order 13526, 75 FR 707; 3 CFR 2010 Comp., p. 298. University libraries are open to the public. BIS does not implement these requests in this final rule because answering them does not require a change to the regulations. BIS is, however, addressing the questions in FAQs posted on BIS's Web site. One commenter stated that, as proposed, the definition of “published” “suggests that releasing (publishing) technology that is unclassified but subject to the EAR makes that technology no longer subject to the EAR.” One commenter described allowing publication by Internet posting as a “loophole” because the site may be obscure and the duration of posting is not specified. Another commenter warned of “the risk of intentional abuse.” Nonetheless, BIS confirms that technology or software that is “published” as provided in § 734.7 is not subject to the EAR.
A commenter noted that the definition “does not appear to address the case of information posted by someone other than the rightful owner.” BIS agrees with this statement, but notes that such cases are addressed by other laws and regulations.
BIS received thirty comments opposing a provision in the definition of “public domain” in the State June 3 rule to which there is no corresponding provision in the definition of “published.” BIS is making no changes to the EAR in response to these comments because they are outside the scope of this rule. They address concerns with the ITAR, not the EAR.
As adopted in this final rule, section 734.7(b) keeps certain published encryption software subject to the EAR, a restriction that the June 3 rule proposed moving from § 734.7(c) without revision.

Fundamental Research
The June 3 rule proposed revising § 734.8, which excludes most information resulting from fundamental research from the scope of the EAR, but it was not intended to change the scope of the current § 734.8.

Alternative Definitions
In the June 3 proposed rule, BIS specifically solicited comments on whether the alternative definition of fundamental research suggested in the preamble should be adopted. BIS also specifically solicited comments on whether the alternative definition of applied research suggested in the preamble should be adopted, or whether basic and applied research definitions are needed given that they are subsumed by fundamental research.
Issued in 1985, National Security Decision Directive (NSDD)-189 established a definition of “fundamental research” that has been incorporated into numerous regulations, internal compliance regimes, and guidance documents. The June 3 proposed rule contained a definition of “fundamental research” that was identical to that in NSDD-189. However, in the preamble to that rule, BIS provided a simpler definition that was consistent with NSDD-189, but not identical. Specifically, the alternative definition read: “ ‘Fundamental research’ means non-proprietary research in science and engineering, the results of which ordinarily are published and shared broadly within the scientific community.” BIS believed that the scope of this wording was the same as that of the wording in NSDD-189 and sought comment on whether the final rule should adopt the simpler wording. Unlike the simpler alternative definition, the proposed definition of “fundamental research” included references to “basic” and “applied” research and proposed definitions of those terms, as well as a possible alternative definition of applied research.
Comments on alternative definitions of fundamental research were mixed. Thirteen commenters generally favored a simpler definition, in some cases offering their own revised versions of the alternative from the preamble to the June 3 proposed rule. Seven commenters recommended retaining the NSDD-189 wording. Many commenters favored one definition but expressed willingness to accept another. Comments on alternative definitions of basic and applied research were similarly mixed, including instances of the same commenter offering support for more than one option. There was greater unanimity on the term “non-proprietary:” twenty commenters objected to it, most finding it vague. Commenters suggested the variation, research “for which the researchers have not accepted restrictions for proprietary or national security reasons.”
BIS agrees with the majority of commenters that the shorter definition of fundamental research is clearer and covers the same scope. Given the wide spectrum of definitions and applications of basic and applied research in different bodies of regulations, BIS determined that the definition should address the core concept, i.e., that the research is to be published and shared broadly without restriction. Having sub-definitions of basic and applied research in the definition of fundamental research does not change this core concept and would, moreover, merely add more words and layers of interpretation that would not change the outcome of an analysis. Adopting the shorter definition drops references to basic and applied research. BIS accepted the comments regarding the term “non-proprietary” and adopted a clearer variation that has the same scope as that intended by the June 3 proposed rule.
In addition to research in science and engineering, BIS included the term “mathematics” to broaden the definition in response to a comment by a BIS technical advisory committee. In this final rule, BIS adopts the following definition of fundamental research: “ “Fundamental research” means research in science, engineering, or mathematics, the results of which ordinarily are published and shared broadly within the research community, and for which the researchers have not accepted restrictions for proprietary or national security reasons.”

Software
The June 3 proposed rule revised § 734.8 to use the term “technology” in place of the term “information.” Thirty-two commenters objected that “technology” was too limiting and recommended including either “software” or “source code” in addition to “technology” to describe information arising during or resulting from fundamental research. Many commenters pointed to the text of § 734.3(b)(3) (not subject to the EAR), which referred to certain “technology and software” not subject to the EAR, proposed to be revised to “information and software” in the June 3 rule, as support for this recommendation. The commenters further argued that “findings resulting from fundamental research may be written in natural-language or computer language.” BIS accepts these comments and has adopted “technology” and “software” throughout § 734.8 in this final rule.
Two commenters recommended that BIS make commodities that result from fundamental research not subject to the EAR. BIS does not accept this recommendation because the policy foundations for the exclusion from the EAR of fundamental research apply only to technology and software, not commodities.

Note on Inputs
The June 3 proposed rule contained the following note: “Note 1 to paragraph (a): The inputs used to conduct fundamental research, such as information, equipment, or software, are not `technology that arises during or results from fundamental research' except to the extent that such inputs are technology that arose during or resulted from earlier fundamental research.” Six commenters stated that the proposed note arbitrarily narrows the conduct of fundamental research under NSDD-189. Two additional commenters seemed to find the text unclear regarding the nature of the inputs.
The note regarding inputs was intended to distill varying provisions found in the EAR but proposed to be revised by the June 3 rule that ultimately made the same point: Information that is not intended to be published is not fundamental research. For example, existing § 734.8(b)(2) states, “Prepublication review by a sponsor of university research solely to insure that the publication would not inadvertently divulge proprietary information that the sponsor has furnished to the researchers does not change the status of the research as fundamental research. However, release of information from a corporate sponsor to university researchers where the research results are subject to prepublication review, is subject to the EAR.” Existing section 734.8(b)(4) states, “The initial transfer of information from an industry sponsor to university researchers is subject to the EAR where the parties have agreed that the sponsor may withhold from publication some or all of the information so provided.”
To clarify this distinction, BIS has adopted a simpler note in this final rule. Paragraph (a) establishes that the intention to publish is what makes research not subject to the EAR; the following Note 1 to paragraph (a) states: “This paragraph does not apply to technology or software subject to the EAR that is released to conduct fundamental research.” To support this concept, this final rule adds the following phrase to § 734.7(a)(5) (emphasis added): “Submission of a written composition, manuscript, presentation, computer-readable dataset, imagery, algorithm, formula, or some other representation of knowledge with the intention that such information will be made publicly available if accepted for publication or presentation: (i) To domestic or foreign co-authors, editors, or reviewers of journals, magazines, newspapers, or trade publications; (ii) To researchers conducting fundamental research, or (iii) To organizers of open conferences or other open gatherings.”

Prepublication Review
The June 3 proposed rule listed three types of prepublication review in § 734.8 that could be performed on the results of fundamental research. Three commenters supported the clear statement that certain prepublication review does not render research subject to the EAR. One commenter recommended removing the criterion that the research be published without delay, pointing out that “[p]ublication can be (and very often is) delayed for any number of reasons having nothing to do with the content or sensitivity of research results” and that this provision would have the unintended effect of limiting or even eliminating the researchers' ability to use the fundamental research provisions. BIS accepts this latter comment and does not adopt the phrase “or delay.” The key point is that the researcher is able to publish without restriction.
One commenter suggested that Note 2 to paragraph (b) proposed in the June 3 rule be replaced with a similar note from the State June 3 rule (§ 120.49(b) of the ITAR) regarding research voluntarily subjected to U.S. government review. BIS agrees with commenters that the ITAR text is clearer. So, this final rule adopts that ITAR text in Note 2 to paragraph (b). Seven commenters recommended that BIS also adopt the text of Note 3 from the State June 3 rule's text of § 120.49(b) of the ITAR regarding U.S. government-imposed access and dissemination controls. BIS agrees. With adoption of Note 3 to paragraph (b), paragraph (a) of § 734.11, Specific National Security Controls, is no longer necessary. BIS includes the examples from paragraph (b) of § 734.11, which commenters deemed helpful, in new Note 3 to paragraph (b) of § 734.8 in this final rule. Thus, this rule removes § 734.11 in its entirety.
One commenter stated that the only permissible method of restricting government-funded research was to classify it. BIS does not accept this comment because it is incorrect. Indeed, BIS has the authority under the EAR to control unclassified technology that warrants control for national security, foreign policy, or other reasons. For example, government-funded research that does not meet the criteria of § 734.8, such as prepublication review, remains subject to the EAR regardless of whether it is classified information.

Locus of Research
The June 3 rule proposed streamlining the fundamental research provisions, in § 734.8. Instead of organizing the provisions primarily by locus (specifically by the type of organization in which the research takes place: Universities; federal agencies or Federally Funded Research and Development Centers; or business entities), the June 3 rule proposed consolidating different provisions that involved the same criteria with respect to prepublication review and removing any reference to locus unless it made a difference to the jurisdictional status of the research.
Five commenters expressed support for the applicability of the concept of fundamental research regardless of locus, and this final rule retains the consolidated structure originally proposed.
Although not objecting to the consolidation, eleven commenters requested that BIS retain the § 734.8(b) statement that there is a presumption that university-based research is fundamental research. Although this presumption continues to exist, BIS does not adopt the specific statement in this final rule. Such a presumption has no effect on the jurisdictional status of technology. If it meets the criteria for fundamental research, it is not subject to the EAR; if it does not meet the criteria, it is subject. However, BIS is noting in its FAQs on its Web site that, although university-based research is presumed to be fundamental research, as with all rebuttable presumptions, it is rebutted if the research is not within the scope of technology and software that arises during, or results from fundamental research as described in § 734.8.
Eleven commenters requested that BIS retain the § 734.8(b)(2) through (6) criteria for universities. BIS is not doing so because these criteria have been incorporated into this final rule more concisely. To address the comment, BIS has revised its FAQs to describe how these criteria are within the scope of the revised definition.

Patents
The June 3 rule proposed revising § 734.10, “Patent applications,” only for clarity and did not change the scope of control. For the sake of structural consistency with the ITAR's treatment of information in patents, paragraph (a) was added to state that a patent or an open (published) patent application available from or at any patent office is per se not subject to EAR. The former footnote to the § 734.10 was removed because it would be redundant of the proposed text.
BIS received one comment on the proposed revisions to § 734.10. Introductory text to the section reads: “ “Technology” is not “subject to the EAR” if it is contained in:”. The commenter suggested adding the phrase “any of the following” to this text. BIS agrees and is making the addition to this final rule.

Specific National Security Controls
The June 3 rule proposed minor conforming edits to § 734.11, describing specific national security controls. The proposed revisions were not intended to change the scope of the section. As discussed above with respect to fundamental research, BIS has adopted the substance of former § 734.11, Specific National Security Controls, in new Note 3 to paragraph (b) of § 734.8 in this final rule. This final rule removes and reserves § 734.11.

Export
The June 3 proposed rule included a new § 734.13 to define “Export.” Section 734.13(a) had six paragraphs, with paragraphs (a)(4) and (5) reserved, because the corresponding paragraphs in the ITAR contained provisions that were not relevant to the EAR. One commenter noted that paragraph (a) had a typo and should refer to § 734.18, not § 734.17. BIS does not agree—the reference is to the subset of exports of encryption source code and object code software—but does accept the recommendation to add a reference to § 734.18 (Activities that are not exports, reexports, or transfers) in this final rule.
Proposed paragraph (a)(1) of the definition of “export” used the EAR terms “actual shipment or transmission out of the United States,” combined with the existing ITAR “sending or taking an item outside the United States in any manner.”
One commenter recommended that BIS add “release” after “actual shipment.” BIS does not adopt this recommendation, because release is a separate concept and thus a separately defined term. BIS makes no revisions to this paragraph (a)(1) in this final rule.
Proposed paragraph (a)(2), specifying the concept of transfer or release of technology to a foreign national in the United States, or “deemed export,” retains the treatment of software source code as technology for deemed export purposes from § 734.2(b)(2)(ii). In this final rule, including in this paragraph (a)(2), BIS has substituted the term “foreign person” for “foreign national.” “Foreign person” has the same scope as “foreign national;” it mirrors the ITAR term. One commenter found the term “otherwise transferring” confusing, but this final rule retains it to distinguish releases as a subset of transfers.
Proposed paragraph (a)(3) included in the definition of “export” the transfer by a person in the United States of registration, control, or ownership (i) of a spacecraft subject to the EAR that is not eligible for export under License Exception STA ( i.e., spacecraft that provide space-based logistics, assembly or servicing of any spacecraft) to a person in or a national of any other country, or (ii) of any other spacecraft subject to the EAR to a person in or a national of a Country Group D:5 country.
One commenter requested BIS to confirm whether the definition would carve out from the definitions of “export” and “reexport” the mere transfer of ownership to an entity outside of a Country Group D:5 country ( e.g., as part of an on orbit transfer of ownership to an entity outside a D:5 country) of satellites subject to the EAR that are eligible for License Exception STA. BIS confirms this understanding of the definition and is adding an FAQ regarding the point to the BIS Web site.
Proposed paragraph (a)(6) defined as an export the release or other transfer of the means of access to encrypted data. This paragraph was not adopted in this final rule (see the section discussing transfer of access information in § 734.19 below). Without a paragraph (a)(6), reserved paragraphs (a)(4) and (a)(5) that appeared in the June 3 rule are unnecessary and, therefore, do not appear in this final rule.
As adopted in this final rule, proposed paragraph (b) of § 734.13 is unchanged from the June 3 rule, except for the substitution of the term “foreign person” for “foreign national.” This paragraph retains BIS's deemed export rule as set forth in § 734.2(b). It also codifies a long-standing BIS policy that when technology or source code is released to a foreign national, the export is “deemed” to occur to that person's most recent country of citizenship or permanent residency. See, e.g., 71 FR 30840 (May 31, 2006).
Four commenters raised deemed export issues, particularly with respect to the difficulty of determining the “permanent residency” status of a person in a foreign country. Two of these commenters recommended changing “permanent residency” to “legal residency” or establishing criteria in the EAR. One of these commenters suggested making deemed exports a separate definition. BIS finds that these comments have merit; however, the issues they raise are too wide-ranging and complex to be resolved in this final rule. Addressing these issues would constitute a novel proposal that is outside the scope of the proposed rule, requiring an opportunity for comment before BIS makes a decision as to whether to adopt it. Where practical, BIS will state existing policy in FAQs. For those issues not addressed by existing policy, BIS will develop proposed revisions and seek public comment.
Proposed paragraph (c) stated that items that will transit through a country or countries or will be transshipped in a country or countries to a new country, or are intended for reexport to the new country are deemed to be destined to the new country. (Proposed paragraph (c) text was taken without change from § 734.2(b)(6).)
One commenter requested that BIS clarify “new country.” BIS accepts this comment, and adopts the term “destination” in this final rule. BIS also drops the term “transshipped,” because the intended meaning of this paragraph is captured by “transit.” One commenter recommended that BIS specify that paragraph (c) applies to items “subject to the EAR.” BIS does not believe the phrase is necessary.
Two commenters requested that BIS clarify the status of services under the EAR. Unlike the ITAR, the EAR do not control services as such except as described in § 744.6(a)(2) (“Restrictions on certain activities of U.S. persons”) and § 736.2(b)(10) (“General Prohibition 10”). Section 744.6(a)(2) imposes licensing requirements on the performance by U.S. persons of any contract, service, or employment regarding various activities pertaining to missiles, biological weapons, and chemical weapons in various countries. General Prohibition 10 prohibits, inter alia, servicing an item subject to the EAR if a violation has occurred, is about to occur, or is intended to occur in connection with the item. Except for these provisions, the EAR regulates the export, reexport, and transfer (in-country) of commodities, technology, and software, regardless of whether such activities are in connection with a service. This means that, except with respect to activities described in these two provisions, services do not need to be analyzed separately for purposes of determining requirements under the EAR. Moreover, the ITAR does not impose controls on services unless they are “directly related” to a “defense article,” i.e., an article, software, or technical data described on the ITAR's U.S. Munitions List at 22 CFR 121.1. In response to the commenters, BIS has added this explanation to its FAQs. A core goal of the ECR initiative was to make the distinctions in the ITAR and the EAR regarding the scope of controls over services as such clear. Thus, after the publication of the FAQs, if commenters believe that provisions of the ITAR or the EAR, statements by government officials, or any other government actions contradict this point regarding the narrow scope of controls over services pertaining to items subject to the EAR, they are encouraged to contact BIS to begin the process of resolving the issue.

Reexport
The June 3 rule proposed moving the definition of “reexport” to new § 734.14. In general, the provisions of the proposed definition of “reexport” paralleled those of the proposed definition of export discussed above, except that reexports occur outside of the United States. Public comments on the definition of “reexport” and BIS responses also mirror those discussed above for “export.”
One commenter recommended that BIS specify “subject to the EAR” in paragraphs (a)(1), (a)(2), and (a)(4) of “reexport.” BIS accepts this recommendation, except for paragraph (a)(4). Paragraph (a)(4) in the June 3 rule proposed to define as a reexport the release or other transfer of the means of access to encrypted data outside of the United States to a foreign national. This paragraph was not adopted in this final rule (see the section discussing transfer of access information in § 734.19 below).
One commenter requested that BIS confirm that sending an item back to the United States is not a reexport. BIS confirms that sending items to the United States is not a “reexport.” Moreover, unlike the ITAR, the EAR have no provisions controlling or otherwise pertaining to the act of importing items into the United States. BIS will confirm these points in an FAQ.

Release
The June 3 proposed rule included a definition of “release” in a new § 734.15. The proposed text provided that inspection (including other types of inspection in addition to visual, such as aural or tactile) must actually reveal technology or source code subject to the EAR to constitute a “release.” Thus, for example, merely seeing an item briefly is not necessarily sufficient to constitute a release of the technology required, for example, to develop or produce it. A foreign person's having theoretical or potential access to technology or software is similarly not a “release” because such access, by definition, does not reveal technology or software. A release would occur when the technology or software is revealed to the foreign person. The June 3 rule also proposed adding “written” to “oral exchanges” in paragraph (a)(2) as a means of release. No commenters objected to the clarification, and it remains unchanged. This final rule adds “source code” as well as “technology” to paragraph (a)(2) for consistency with paragraph (a)(1) and the definitions of deemed export and reexport; its omission from the June 3 rule was inadvertent.
The proposed text also clarified, in paragraph (a)(3), that the application of “technology” and “software” is a “release” in situations where U.S. persons abroad use personal knowledge or technical experience acquired in the United States in a manner that reveals technology or software to foreign nationals. As indicated by various BIS training materials and statements of BIS officials publicly and in response to specific questions, this clarification makes explicit a long-standing BIS interpretation of the EAR. The June 3 rule's proposed definition did not use the existing phrase “visual inspection by foreign nationals of U.S.-origin equipment and facilities” because such inspections do not per se release “technology.” For example, merely seeing equipment does not necessarily mean that the seer is able to glean any technology from it and, in any event, not all visible information pertaining to equipment is necessarily “technology” subject to the EAR.
Four commenters stated that this redefinition of “release” was helpful.
Three comments expressed concern that paragraph (a)(1) is not sufficiently explicit in clarifying that visual inspection must “actually” or “substantively” reveal technology in order to be defined as a “release,” or that “actual access” rather than “theoretical access” is caught. BIS believes that the intent is clear and that the text only would be complicated by additional modifications. One commenter requested that BIS simplify the provision in which application of personal knowledge constitutes a release. Upon further consideration, BIS determined that the control criteria in that provision are already covered by the provisions governing inspection and oral or written exchanges. Therefore, BIS does not adopt this paragraph (a)(3) in this final rule. BIS has, however, created FAQs that include the points and examples contained in the foregoing description of the changes to the definition of “release.”
One commenter recommended that paragraph (a)(6) in the June 3 rule's proposed definition of “export,” which addressed transfer of decryption keys or other such information, be moved to the definition of “release.” Related to the revisions regarding transfer of access information, and consistent with this commenter's recommendation, this final rule adopts in § 734.15(b) a provision stating that the act of causing the “release” of “technology” or “software,” through use of “access information” or otherwise, to onesself or another person requires an authorization to the same extent an authorization would be required to export or reexport such “technology” or “software” to that person.
The purpose of this provision is to make it clear that the person who uses, for example, a password to access a technology database, or who hacks into the database, to transfer technology to himself or someone else is the one who caused the release of technology rather than the person who first placed the technology in the database through a technology export or an act described in new § 734.18(a)(5). This provision codifies that basic concept that the unwitting victim of, for example, a database hack is not the one responsible for the theft of technology—the hacker is the one responsible because it is that person who caused the release through the use of a password or other access information. This provision is merely an application with respect to intangibles of a concept that is basic to tangible items—the export of an item is not the cause of a third person's later reexport of the same item. Placing technology into a database is not the cause of a third person's later transfer of the technology through the use of access information. The third person's use of the access information is the cause of the release to himself or others.
Although the person who originally placed the technology into the database did not cause its release to the third person who used access information to later cause the technology to be released, the person who originally placed the technology into the database nonetheless would have liability in connection with the third party technology exfiltration if, for example, it conspired with the exfiltrator (see § 764.2(d)) or placed the technology into the database with “knowledge” that the exfiltrator would later violate the EAR by causing its release without a required license (see § 764.2(e)). Similarly, liability would arise from a violation of new section 734.19, which, as discussed below, states that providing a password or other access information to someone with “knowledge” that the provision would result in the release of technology or software to the third person is tantamount to releasing the technology or software itself to the third person. BIS has created FAQs describing all the points in the foregoing examples.
Finally, and in contrast to section 734.19, new section 734.15(b) does not contain a “knowledge” element. Thus, a “release” of “technology” or “software” occurs when access information is used to transfer the “technology” or “software”—resulting in liability if the release was not undertaken pursuant to a required authorization and regardless of whether the one using the access information knew it would be transferring controlled “technology” or “software” when it did so.

Transfer (In-Country)
The June 3 rule proposed removing the definition of “transfer (in-country)” from § 772.1 and adding the following revised definition to new § 734.16: “a transfer (in-country) is a change in end use or end user of an item within the same foreign country.” This revision was intended to eliminate any potential ambiguity regarding whether a change in end use or end user within a foreign country is a “transfer (in-country).” “Transfer (in-country)” parallels the term “retransfer” in the ITAR.
Four commenters said that this revision expands controls, and that such changes were beyond exporters' knowledge or control. While BIS acknowledges that “end use” was not explicitly included in the former definition of “transfer (in-country),” a change in end use is nonetheless a material change. When BIS and the other agencies review an application's description of a proposed end use and approve the license based on that end use, BIS is approving the transaction for the end use described, not all other end uses in the same country. Other end uses may or may not be acceptable, but a change in end use from that which the U.S. Government reviewed would be material in that there is the possibility that another end use may not have been approved. BIS further notes that, depending on the facts of the transaction, the foreign party may be responsible for obtaining authorization for the subsequent disposition of the item subject to the EAR. If a violation occurs, BIS will assess responsibility based on whether the parties involved violated any of the provisions of section 764.2 (“violations”).
To assist the commenters and others who have questions about BIS's policy regarding when a license or other authorization is required for in-country transfers, BIS has made the following the standard first condition on its licenses: “Items subject to the EAR and within the scope of this license may not be reexported or transferred (in-country) unless such reexport or in-country transfer is (i) authorized by this license, or another license or other approval issued by the U.S. Government; (ii) authorized by a license exception or other authorization under the Export Administration Regulations (EAR); or (iii) to a destination, end user, and end use that would be “NLR” (No License Required) under the EAR.”

Export of Encryption Source Code and Object Code Software
The June 3 proposed rule included a new § 734.17, export of encryption source code and object code software, that retained the text of § 734.2(b)(9) with only minor conforming and clarifying edits. Its relocation to a new, separate section, following similar definitions improves its accessibility to exporters.
BIS received no comments on its proposed minor revisions to § 734.2(b)(9) or its creation of § 734.17. These revisions are adopted in this final rule.

Activities That Are Not Exports, Reexports, or Transfers
The June 3 proposed rule solicited public comment on two questions regarding the proposed definition of “Activities that are not exports, reexports, or transfers.” First, with respect to end-to-end encryption, BIS asked whether the illustrative standard proposed in the EAR rulemaking also should be adopted in the ITAR rulemaking; whether the safe harbor standard proposed in the ITAR rulemaking also should be adopted in the EAR rulemaking; or whether the two bodies of regulations should have different standards. Second, BIS asked whether encryption standards adequately address data storage and transmission issues with respect to export controls.
As proposed, § 734.18 gathered existing EAR exclusions from exports, reexports, and transfers into one place, and included a new exemption for encrypted technical data and software. A number of changes and adjustments are made in this final rule to the proposed text in response to comments received from the public.
Paragraph (a)(1) in the June 3 proposed rule stated that by statute, launching a spacecraft, launch vehicle, payload, or other item into space is not an export. See 51 U.S.C. 50919(f). BIS received no comments on this paragraph and adopts it in this final rule.
Paragraph (a)(2) in the June 3 proposed rule was based on text in former § 734.2(b)(2)(ii) of the EAR, and provided that release in the United States of technology or software to U.S. nationals, permanent residents, or protected individuals would not be an export. In this final rule, the term “release” has been replaced in § 734.18(a)(2) with “transmitting or otherwise transferring,” and the previous reference to U.S. persons, permanent residents, and protected individuals has been eliminated in favor of a reference to a person “who is not a foreign person” for reasons of clarity and brevity. The EAR contain three definitions of “U.S. person,” only one of which is applicable to this section. Additionally, the ITAR use the term “foreign person,” and a comment from a BIS technical advisory committee recommended adopting the term in the EAR. “Foreign person” accordingly is defined in a new entry in § 772.1.
The change creates a structure parallel to that which is being adopted in the State rule published concurrently with this final rule, and to make clear that transmission from one U.S. person in the United States to another, regardless of the means or route of the transmission, does not constitute an export. Along the same lines, paragraph (a)(3) is added to clarify that the transmission between or among U.S. persons within the same foreign country similarly does not constitute an export, reexport, or transfer. The State June 3 rule received comments recommending these revisions, and this final rule adopts them in the EAR to stay parallel with the ITAR text.
Proposed paragraph (a)(3) in the June 3 rule contained text from § 734.2(b)(8) stating that shipments between or among the states or possessions of the United States are not “exports” or “reexports.” The words “moving” and “transferring” were inserted next to “shipment” in order to avoid suggesting that the only way movement between or among the states or possessions would not be a controlled event was if they were “shipped.” BIS received no comments on this paragraph and adopts it in this final rule, renumbered as paragraph (a)(4).
Paragraph (a)(5)—numbered (a)(4) in the June 3 proposed rule—provides that technology and software that is encrypted in accordance with certain specified criteria are not exports, reexports, or transfers even when they leave one country for another. In the June 3 proposed rule, this paragraph specifically excluded from this carve-out technology and software stored in countries in Country Group D:5 and Russia, for foreign policy reasons. In response to comments pointing out that Internet traffic in transit across D:5 countries and Russia may be technically “stored” temporarily on servers located in these countries without the knowledge of the sender, BIS has added text in (a)(5) specifying that the carve-out continues to apply to technology not authorized under the EAR for storage in these countries or intended for storage in these countries. Encrypted data may not be stored in these countries unless an appropriate authorization is available or has been approved. BIS has also added a note clarifying that data in-transit via the Internet is not deemed to be stored. For a more complete understanding of § 734.18(a)(5), see the discussion above of § 734.15(b).
BIS received many comments on the proposed definition of “end-to-end encryption,” the presence of which is a condition of the export control carve-out for technology and software. Commenters observed that encryption and decryption services may be provided within defined security boundaries by organizational rather than personal systems or servers. BIS agrees that in such cases, the security objectives of the “end-to-end” requirement in terms of eliminating access by third parties can still be met by expanding the definition of “end-to-end” to include transmissions between security boundaries.
This approach has the added advantages of providing more flexibility and allowing the execution of shared services, such as virus scanning, that can enhance security. However, BIS has also specified that the “security boundary” must be in-country—that is, such boundaries cannot be defined as including infrastructure resources encompassing multiple countries. A consequence of this requirement is that data eligible for the carve-out must by definition be encrypted before crossing any national boundary and must remain encrypted at all times while being transmitted from one security boundary to another. This principle applies to transmissions within a cloud service infrastructure, where a transmission from one node or cloud infrastructure element to another could qualify for the carve-out provided that it was appropriately encrypted before any data crossed a national border.
The June 3 proposed rule's definition of end-to-end encryption included a clause that specified that data not be decrypted at any point between the initiation of the transmission by the originator and its receipt by the intended recipient. The purpose of this requirement was to prevent unauthorized access to data in clear text by parties other than the originator (or the originator's company or organization) and the recipient, such as external service providers.
Commenters pointed out that in many circumstances, companies and organizations encrypt and decrypt multiple times in the course of transmission between originator and recipient for technical reasons (for example, to initially establish communications with a VPN server and subsequently to transmit among servers) without release to any third party. As a result, the point-to-point requirement in the original proposal would impose an unnecessary and potentially disruptive burden on many encryption applications, in which data in clear text are never actually shared.
To address this problem and more precisely describe BIS's original intent with the provision, BIS eliminated the statement in the end-to-end definition specifying that exempted data must be encrypted by the originating party without decryption except by the intended recipient. This final rule adopts instead a requirement that the means of decryption may not be provided to any third party, thus permitting decryption and re-encryption within the security boundary of either the originator or recipient, provided that no third party ( i.e., a party outside the security boundary) has the ability to access the data in clear text, and that no decryption takes place outside of the security boundaries of the originator and the recipient.
The June 3 proposed rule's paragraph (4)(iii), which this final rule adopts in paragraph (5)(iii), described encryption standards that would qualify for the exemption. In the BIS proposed rule, use of encryption modules certified under the Federal Information Processing Standards Publication 140-2 (FIPS 140-2), supplemented by appropriate software implementation, cryptographic key management and other procedures or controls that are in accordance with guidance provided in current U.S. National Institute for Standards and Technology publications, would qualify as sufficient security.
A number of commenters questioned the designation of the FIPS 140-2 as an example of effective cryptography and thus a qualification for the control carve-out, preferring instead no reference to a standard, or a reference to any “commercially reasonable” standard.
BIS rejects these suggestions. FIPS 140-2 is a well-understood cryptographic standard used for Federal Government procurement in the United States and Canada, as well as for many other uses, both in the U.S. and abroad. Citation of this standard provides a useful reference point for what the U.S. Federal Government considers effective encryption.
The text adopted in this final rule allows for use of “equally or more effective cryptographic means,” meaning that alternative approaches are allowable provided that they work as well as or better than FIPS 140-2. In such cases, the exporter is responsible for ensuring that the alternative approaches work as well as or better than FIPS 140-2, regardless of common commercial practices.
In the June 3 proposed rule, paragraph (c) confirmed that the mere ability to access “technology” or “software” while it is encrypted in a manner that satisfies the requirements in the section does not constitute the “release” or export of such “technology” or “software.” This responds to a common industry question on the issue. This final rule adopts the proposed text with only a minor revision to correct a cross-reference.

Transfer of Access Information
New § 734.18(a)(5)(iii) excludes transfers of information encrypted to a particular standard as not being exports, reexports, or transfers and, thus, not subject to the EAR. Logically, providing keys or other information that would allow access to encrypted data exported, reexported, or released under this provision should be subject to controls much as the export, reexport, or transfer of the data itself. In the June 3 proposed rule, this concept was specifically addressed in proposed § 734.13(a)(6) as part of the definition of “export.” The June 3 rule also proposed adding a new paragraph (l) to § 764.2 “Violations” providing that the unauthorized release of decryption keys or other information that would allow access to particular controlled technology or software would constitute a violation to the same extent as a violation in connection with the export of the underlying controlled “technology” or “software.”
Although recognizing the need to control the decryption of controlled technical data otherwise exempted by the encryption carve-out, commenters noted that this construction might lead to the conclusion that keys and other data permitting access might be controlled as separate stand-alone items, distinct from the underlying data that they could potentially release. This would pose problems with key and identity management, where such data are stored and transmitted separately. Controlling access information as a distinct item was not the intent of the proposal. As also discussed below with respect to the definition of “technology,” one commenter stated that decryption keys and other such information are not technology and recommended moving the proposed paragraph (a)(5) text to the definition of “release” and control “accessing” them. To address the concerns of such commenters, this final rule creates a new positive authorization requirement in a new § 734.19, stating that “[t]o the extent an authorization would be required to transfer “technology” or “software,” a comparable authorization is required to transfer access information if with “knowledge” that such transfer would result in the release of such “technology” or “software” without a required authorization.” Five commenters found use of the term “cause or permit” inconsistent with BIS's principle of an export's occurring only when actual export or transfer takes place. This final rule replaces the former reference to “cause or permit” with “result in.”
One commenter requested “the removal of § 764.2(l) in its entirety as the current language of § 764.2 is adequate.” With creation of new § 734.19, and in light of the availability of § 764.2 to punish any violation of § 734.19, BIS accepts this comment and does not adopt the proposed § 764.2(l) in this final rule.
To simplify this section, proposed references to “decryption keys, network access codes, passwords and other information,” are replaced with a new § 772.1 definition of “access information,” which uses these as examples only of information that allows access to encrypted technology or encrypted software in an unencrypted format. In response to a commenter's request for a definition of “clear text,” this final rule replaces references to “clear text” with “in an unencrypted form,” as part of the definition of “access information.”
References in the June 3 proposed rule to what is termed “access information” in this final rule ( e.g., references to decryption keys) were eliminated in the § 772.1 definition of “technology,” the § 734.13 definition of export, and the § 734.14 definition of reexport.

Activities That Are Not Deemed Reexports
The June 3 proposed rule created a new § 734.20, Activities that are not Deemed Reexports. This section codified BIS's interagency-cleared Deemed Reexport Guidance previously posted on the BIS Web site and dated October 31, 2013. This guidance was created so that the provisions regarding possible deemed reexports contained in §§ 124.16 and 126.18 of the ITAR would be available for EAR technology and source code in addition to legacy BIS guidance on the topic.
Under BIS's legacy guidance and new § 734.20, release of technology or source code by an entity outside the United States to a foreign national of a country other than the foreign country where the release takes place does not constitute a deemed reexport of such technology or source code if the entity is authorized to receive the technology or source code at issue, whether by a license, license exception, or in situations where no license is required under the EAR for such technology or source code and the foreign national's most recent country of citizenship or permanent residency is that of a country to which export from the United States of the technology or source code at issue would be authorized by the EAR either under a license exception, or in situations where no license under the EAR would be required.
Release of technology or source code by an entity outside the United States to a foreign national of a country other than the foreign country where the release takes place also does not constitute a deemed reexport if: (i) The entity is authorized to receive the technology or source code at issue, whether by a license, license exception, or through situations where no license is required under the EAR; (ii) the foreign national is a bona fide regular and permanent employee (who is not a proscribed person) of the entity; (iii) such employee is a national exclusively of a country in Country Group A:5; and (iv) the release of technology or source code takes place entirely within the physical territory of any such country, or within the United States.
For nationals other than those of Country Group A:5 countries, which are close military allies of the United States, other criteria may apply. In particular, the section specifies the situations in which the releases would not constitute deemed exports in a manner consistent with § 126.18 of the ITAR. For purposes of this section, “substantive contacts” has the same meaning as it has in § 126.18 of the ITAR. The proposed phrase “permanent and regular employee” was a combination of BIS's definition of “permanent employee,” as set forth in a BIS advisory opinion issued on November 19, 2007 (available on the BIS Web site), and the ITAR's definition of “regular employee” in § 120.39. The June 3 proposed rule added specific text excluding persons proscribed under U.S. law to make clear that § 734.20 does not authorize release of technology to persons proscribed under U.S. law, and defined “proscribed person” in § 772.1. ( Note: The U.S.-U.K. Exchange of Notes and U.S.-Canadian Exchange of Letters referred to in the existing online guidance can be found on the State Department's Web site. The URLs for the letters are not being published in the EAR because URL addresses periodically change. BIS will place the URL references in an “FAQ” section of its Web site.)
One commenter stated that due to the number of conditions contained in these provisions, this section should be a license exception. BIS does not agree. Many if not most of the transactions to which these provisions apply are already covered by a license or a license exception; this section will generally allow affected entities to comply with the terms of those authorizations in a rational way that will meet U.S. control objectives while minimizing conflict with non-U.S. entities' domestic requirements.
Two commenters requested that BIS replace “is certain” of a foreign person's most recent country of citizenship or permanent residency with “has knowledge,” to address concerns about ability to comply with such a standard. BIS agrees with this comment and adopts “has 'knowledge'” in this final rule.
One commenter requested that BIS add “or within the physical territory of the United States” to certain provisions to account for the possibility of releases in the United States, because often “release of U.S.-origin technology or software could be said to take place partially within the United States and partially within the country in which the foreign person employee is located;” BIS accepts this request. Another commenter requested that for releases to A:5 nationals, BIS “also include countries where the entity conducts official business or operates, which is part of § 734.20(c) Release to other than A:5 nationals.” BIS did not adopt this request because it would expand the provision too broadly.
Two commenters requested that BIS cross reference the “deemed reexport” definition in § 734.14(b). BIS accepts this request. One commenter asked BIS to clarify that this section addresses non-U.S. entities. BIS believes that this is clear from context and is thus not changing the rule in response to this comment. However, BIS is including a description of the purpose of this section in its FAQs.
Two commenters objected to the requirement that employees must be engaged for a year to be eligible for these provisions and asked that it be removed. Additionally, two commenters objected to the associated screening and recordkeeping requirements and asked that they be reduced. BIS does not accept these comments. The year-long period and the screening and recordkeeping requirements reduce the risk of diversion associated with the technology release.

Questions and Answers—Technology and Software Subject to the EAR
The June 3 proposed rule removed Supplement No. 1 to part 734, “Questions and Answers—Technology and Software Subject to the EAR” on the basis that the questions and answers are illustrative rather than regulatory, and are therefore more appropriately posted as Web site guidance than included in the EAR. BIS specifically solicited comments on whether the questions and answers in existing Supplement No. 1 to part 734 proposed to be removed have criteria that should be retained in part 734.
Thirty commenters stated that BIS should not remove the questions and answers from the EAR. Reasons cited for opposing removal of the supplement included that the questions and answers will not have the same weight on the BIS Web site as they do in the EAR; that they are legally binding in the EAR; that their removal will create uncertainty; that their presence in EAR lessens the likelihood that interpretations will change outside the rulemaking process and promotes consistency of interpretation; and that other supplements contain regulatory information. One of these comments went on to say, “Accordingly, Supplement No. 1 must not be removed unless all its substantive provisions are adequately incorporated into Part 734 or elsewhere in the regulations” (emphasis supplied). BIS believes that the adequate incorporation of substantive provisions is the key point behind the comments. This concern drove the specific solicitation in the June 3 rule to identify criteria in the Supplement that should be retained in part 734. None of the thirty comments opposing removal of this Supplement from the EAR identified any substantive provisions that were not adequately incorporated into part 734 or elsewhere in the EAR. BIS is publishing on its Web site FAQs that will cover the same guidance that was found in Supplement No. 1, in addition to answers to other questions generated by the public comments to the proposed rule. Questions regarding how regulations apply to specific fact patterns are better set out in FAQs. In sum, although Supplement No. 1 will no longer be in the EAR, all its content will be placed into FAQs on BIS's Web site in addition to the other FAQs referred to in this preamble.

Technology
In the June 3 proposed rule, paragraph (a)(1) of the definition of technology reads as follows: “Information necessary for the “development,” “production,” “use,” operation, installation, maintenance, repair, overhaul, or refurbishing (or other terms specified in ECCNs on the CCL that control “technology”) of an item. “Technology” may be in any tangible or intangible form, such as written or oral communications, blueprints, drawings, photographs, plans, diagrams, models, formulae, tables, engineering designs and specifications, computer-aided design files, manuals or documentation, electronic media or information gleaned through visual inspection.”
A note addressed modification of items. Proposed paragraphs (a)(2) through (a)(4) of the definition were held in reserve to allow for the eventual mirroring of the corresponding ITAR paragraph structure while not including provisions that were not relevant to the EAR. Proposed paragraph (a)(5) described access information. Proposed paragraph (b) described exclusions from the definition of technology.

Required vs. Necessary
For the definition of “technology,” four commenters recommended that “necessary” be revised to read “required” to match the proposed ITAR definition. BIS does not adopt these recommendations. “Required” is a defined term that describes certain technology on the Commerce Control List, and not all technology that is subject to the EAR is controlled on the Commerce Control List. One commenter recommended restoring a note from the definition that existed in the EAR prior to publication of this rule, to the effect that technology not elsewhere specified on the Commerce Control List is designated as EAR99 unless it is not subject to the EAR. BIS does not accept this recommendation in this final rule because a regulatory change is not required to make the same point. BIS will, however, add an FAQ stating that “technology” subject to the EAR and that is not described on the CCL is designated EAR99. One commenter recommended including a note that refers to the General Technology Note. BIS accepts this comment and includes the reference in this final rule.

“Use” Elements
As explained in the preamble to the June 3 rule, the proposed definition of “technology” was based on the Wassenaar Arrangement definition of technology, including the Wassenaar-defined sub-definitions of “development,” “production,” and “use,” which are currently defined in § 772.1. (No changes were proposed to the definitions of “development,” “production,” and “use” in the June 3 rule, and none are made in this final rule.) The June 3 rule proposed no change to BIS's long-standing policy that all six activities in the definition of “use” (operation, installation (including on-site installation), maintenance (checking), repair, overhaul and refurbishing) must be present for an item to be classified under an ECCN paragraph that uses “use” to describe the “technology” controlled. (See 71 FR 30842, May 31, 2006.) Drawing from this existing framework, the proposed definition of “technology” included the terms “operation, installation, maintenance, repair, overhaul, or refurbishing (or other terms specified in ECCNs on the CCL that control `technology') of an item” because such words are used to describe technology controlled in multiple ECCNs, often with “or” rather than the “and” found in “use.”
One commenter recommended inserting a Note in the definition of technology that states the BIS policy that all six elements are necessary for “use” technology. BIS does not adopt this recommendation in this final rule because the definition of “use” links the six elements with the conjunctive “and” rather than the disjunctive “or.” BIS nonetheless makes this point in an FAQ pertaining to the word “use” in the definition of “technology.” One commenter recommended removing the term “installation” from the definition based on its use in the context of the definition of defense services. BIS does not accept this comment. Many entries on the Commerce Control List explicitly control installation technology, and it is also an element of “use” technology. Three commenters recommended that BIS remove the separate listing of the six “use” elements or limit them to control of 600 series items. BIS does not accept these recommendations. The six elements may be listed separately in entries on the Commerce Control List and are not limited to 600 series entries.

Information Gleaned Through Visual Inspection
One commenter suggested dropping “or information gleaned through visual inspection” because it was a form or method of transfer, not what constitutes technology. BIS adopts the recommendation in this comment in part. “Information gleaned through visual inspection” is an example of a form of technology, with visual inspection as the method of transfer. The list to which this example belongs, however, illustrates rather than defines “technology;” therefore, BIS adopts the text as Note 1 to the definition of “technology” in this final rule, limiting the definition to what constitutes technology and illustrating the forms in a note.
Another commenter suggested using “revealed” instead of “gleaned,” first to align with “release,” and second, because “use of the term ‘glean' implies the value of the information is based on the capability of the viewer, which is unknowable and unquantifiable. The use of the term ‘reveal' is a more objective measure of what is provided by the visual inspection.” BIS agrees and has adopted the term “revealed” in this final rule.

Modification Note
The June 3 rule proposed adding a note to address a common industry question about modification. The note read as follows: “The modification of an existing item creates a new item and technology for the modification is technical data for the development of the new item.”
Three commenters suggested revisions to this note. Two commenters described the note as overbroad or confusing. One commenter recommended adding “production” as well as “development.” In this final rule, BIS has adopted a revision that clarifies and narrows the description of the technology for modification, and includes “production” technology. The revised note reads as follows: “The modification of the design of an existing item creates a new item and technology for the modified design is technology for the development or production of the new item.” BIS created this note to address the fact that multiple variations of a product are usually created by one or more companies, and companies often struggle with how to classify the technology that is and is not common to the variations. Consider, for example, a company that makes a 9A991.d civil aircraft switch. It later modifies the switch so that it would work in a military aircraft. The modified switch—the “dash one” model—is, in this example, specially designed for a military aircraft and thus controlled under ECCN 9A610.x. The technology that is common to both switches is 9E991, but the additional or different technology to make the 9A610.x switch is controlled under 9E610. That is, the technology additional or different that is required to make the 9A991.d commercial aircraft switch into a 9A610.x switch is the technology for the new, modified item. This example is contained in an FAQ posted on the BIS Web site.

Decryption Keys
One commenter stated that decryption keys and other such information are not technology and recommended moving the proposed paragraph (a)(5) text to the definition of “release” and control “accessing” them. Another commenter pointed out that keys may also be hardware or software. BIS agrees with these comments; therefore, BIS does not adopt proposed paragraph (a)(5) in this final rule and adds text to the definition of “release” regarding transfer of “access information” (see also discussion above).

Exclusions
The June 3 rule proposed adding three exclusions to clarify the limits of the scope of the definition of “technology:” non-proprietary general system descriptions; information on basic function or purpose of an item; and telemetry data as defined in note 2 to Category 9, Product Group E (see Supplement No. 1 to Part 774 of the EAR).
The first two exclusions paralleled exclusions in the ITAR and the third, the exclusion of telemetry data, mirrored specific exclusions added to both the ITAR and the EAR as part of recent changes regarding the scope of U.S. export controls pertaining to satellites and related items. See 79 FR 27417 (May 13, 2014).
One commenter recommended excluding Build/Design-to-Specifications from the definition of technology and adding sub-definitions of different forms of technology. BIS does not accept this recommendation in this final rule because such specifications are not always outside the scope of the EAR's definition of “development” or “production” technology. However, BIS will incorporate information on this topic into its FAQs. Five commenters objected to use of the term “non-proprietary,” arguing that certain proprietary system descriptions should not be subject to the EAR. One commenter thought that the term “systems” was too narrow. BIS did not adopt these recommendations. Whether a particular technology is one that the possessor would readily share with competitors provides a fairly reliable test of whether that technology is subject to the EAR. With respect to the breadth of the term “system,” BIS notes that this exclusion is not the only provision in the EAR under which technology may be determined to be not subject. BIS did remove the modifier “general,” because of its potential to be ambiguous and subjective. BIS also did not adopt in this final rule the exclusion for “information on basic function or purpose of an item,” because the phrase was too vague and substantively already addressed by other provisions.
One commenter questioned the scope of these exclusions from the definition of technology and another questioned how the exclusions from the definition should be read in conjunction with the provisions in the Scope part that make items not subject to the EAR. Based on these comments, and as noted earlier in the preamble to this final rule, the exclusion of “information on basic function or purpose of an item” is not adopted and the remaining two exclusions are moved from the definition of technology to § 734.3(b)(3).

Required
The June 3 proposed rule retained the existing EAR definition of “required” in § 772.1, but added notes clarifying the application of the term. It removed parenthetical references in the existing definition to CCL Categories 4, 5, 6, and 9 to avoid the suggestion that BIS applies the definition of “required” only to the uses of the term in these categories. BIS has never had a separate definition of “required” used elsewhere in the EAR, and this removal merely eliminated a potential ambiguity and reflects long-standing BIS policy that “required” applies generally to “technology” entries on the CCL. (See, e.g., the Advisory Opinion dated December 27, 2010 on the BIS Web site.) BIS received one comment praising the removal of the references and none objecting to it; the revision is adopted in this final rule. The definition of “required” contained an illustrative example. BIS did not propose any revisions to this example in the June 3 rule. In this final rule, however, BIS revises the example to make clear that technology that is peculiarly responsible for the characteristics of the item that make it controlled is thus “required” technology. This subtle change thus responds to the question of which technology is “peculiarly responsible” but without changing the well-established definition of “required” that is central to the scope of the technology and software controls in the EAR. This revision also addresses issues raised by commenters, discussed more fully below, with respect to the proposed definition of “peculiarly responsible.”
To address common questions BIS has received regarding the meaning of the word “required,” the June 3 rule proposed adding two notes. The first stated that the references to “characteristics” and “functions” are not limited to entries on the CCL that use specific technical parameters to describe the scope of what is controlled. The “characteristics” and “functions” of an item listed are, absent a specific regulatory definition, a standard dictionary's definition of the item. The first note also included examples of this point. The second note referred to the fact that the ITAR and the EAR often divide within each set of regulations or between each set of regulations (a) controls on parts, components, accessories, attachments, and software and (b) controls on the end items, systems, equipment, or other articles into which those parts, components, accessories, attachments, and software are to be installed or incorporated. The note also referred to jurisdiction over technology. The public comments on these parts of the notes were favorable and the first note is included in this final rule without modification, except that it is now designated as Note 2 to the definition of “required.” The second note is split into Notes 1 and 3 to the definition of “required,” and the text is modified from the June 3 proposal as discussed below.
A core tenet of ECR is that the jurisdictional status of the technical data/technology for an article that moves from the USML to the EAR follows the article. BIS and DDTC recognize the need to clarify the jurisdictional line for such technical data/technology. To help those making jurisdictional self-determinations for technical data/technology pertaining to articles affected by the reform effort, BIS and DDTC had proposed in their respective June 3 rules common definitions of “required” and “peculiarly responsible” so that the regulatory line between technical data subject to the ITAR and technology subject to the EAR would be bright. Based on a review of the comments, BIS and DDTC have, however, decided not to publish their proposed common definitions of “required” and “peculiarly responsible.” (See discussion of the public comments on “peculiarly responsible” below.) Rather, DDTC and BIS have determined that a better way for the ITAR to address this bright-line objective is for DDTC to publish, and get public comments on, a proposed definition of “directly related” that will eventually lead to a final ITAR definition acceptable to both DDTC and BIS. The reason for this approach is that, with the exception of technical data specifically enumerated on the USML, technical data is subject to the ITAR only if it is “ directly related” to a defense article. This means, by definition, that technology that is indirectly related to, or only “related to,” a defense article, such as by merely being capable for use with, used in connection with, or somehow having something generally to do with the eventual functioning of a defense article, is not subject to the ITAR and is, thus, subject to the EAR. For example, technology required for the production of a 9A610.x aircraft component—which, by definition, means that that it is specially designed for a USML VIII(a) aircraft—does not become subject to the ITAR merely because it generally relates to a defense article by virtue of being a component that will be or is integrated into and necessary for the functioning of the aircraft subject to the ITAR. It is technology required for the aircraft component subject to the EAR, not the whole of the USML aircraft or another defense article, and thus subject to the EAR. On the other hand, technical data that is directly related to the production of a component subject to the ITAR does not become subject to the EAR merely because, for example, it is developed or manufactured with equipment subject to the EAR.
Wanting to nonetheless respond to the comments seeking guidance regarding the jurisdictional status of technology pertaining to items that have moved to the CCL from the USML and to further advance the effort of creating a truly bright line jurisdictional rule, BIS is publishing with this rule as a third note to “required” its guidance on the topic because the meaning of “required” is central to such determinations. Specifically, unclassified technology not specifically enumerated on the USML is “subject to the EAR” if it is “ required ” for the “development,” “production,” “use,” operation, installation, maintenance, repair, overhaul, or refurbishing (or other terms specified in ECCNs on the CCL that control “technology”) of a commodity or software that is “subject to the EAR.” If such information is technical data that is not “required” for an item subject to the EAR and directly related to a defense article, then it is subject to the ITAR. If the application of industry-standard or dictionary definitions of “directly related” does not resolve doubts about whether any unit of technical data is, as a matter of law, “directly related” (as opposed to indirectly related) to a defense article, one should contact DDTC for resolution of the doubt through established procedures in the ITAR's Part 120.

Peculiarly Responsible
In the June 3 rule, BIS proposed a definition of the term “peculiarly responsible” that was modeled on the catch-and-release structure BIS adopted for the definition of “specially designed.” Thus, under the proposed definition, an item was “peculiarly responsible” for achieving or exceeding any referenced controlled performance levels, characteristics, or functions if it was used in “development,” “production,” “use,” operation, installation, maintenance, repair, overhaul, or refurbishing of an item subject to the EAR unless (a) the Department of Commerce had determined otherwise in a commodity classification determination, (b) the item was identical to information used in or with a commodity or software that was or had been in production and was EAR99 or described in an ECCN controlled only for Anti-Terrorism (AT) reasons, (c) the item had been or was being developed for use in or with general purpose commodities or software, or (d) the item had been or was being developed with “knowledge” that it would be for use in or with commodities or software described (i) in an ECCN controlled for AT-only reasons and also EAR99 commodities or software or (ii) exclusively for use in or with EAR99 commodities or software.
BIS specifically solicited comments on whether the proposed definition of “peculiarly responsible” effectively explained how items may be “required” or “specially designed” for particular functions. Two commenters offered support for the definition but still suggested revisions. Twelve additional commenters objected to the definition, describing it as confusing and stating that it dramatically expanded the scope of control beyond the existing “required” technology definition. BIS agrees with these comments and does not adopt the proposed definition of “peculiarly responsible” in this final rule. As described above, in this final rule, peculiarly responsible is defined within the scope of the already existing definition of required, thus providing a definition while guaranteeing no expansion of scope.

Temporary Export of Technology
The June 3 proposed rule included amended text in the temporary export of technology provisions of License Exception TMP by revising § 740.9(a)(3) to clarify that the “U.S. employer” and “U.S. persons or their employees” using this license exception are not foreign subsidiaries. The proposed paragraph streamlined current text without changing the scope. In this final rule, BIS substitutes “foreign person” for “foreign national” in this section for reasons discussed elsewhere in this preamble, except where “natural person” was meant and BIS substituted “individual” for clarity (and in so doing responded to a comment on including foreign nationals in paragraph (a)(3)(iii)). BIS also added authority to reexport or transfer (in-country) to the authority to export; the absence of these terms from the June 3 proposed rule was an oversight.
One commenter stated that BIS should provide for use of this license exception by non-U.S. persons. Another commenter recommended that BIS expand the scope of the license exception to include foreign subsidiaries and affiliates. BIS does not adopt these recommendations. Because of the risks associated with securing temporary exports of technology, BIS is not broadening the provisions for foreign persons beyond those employed by U.S. companies or to allow use by foreign companies.
BIS received two comments on the recordkeeping provision in paragraph (a)(3)(v), with one requesting that it be clarified and one requesting that it be removed in view of the existing broad recordkeeping requirements in the EAR. BIS agrees with these comments and does not adopt the recordkeeping provision in this final rule.
One commenter asked BIS to clarify if TMP is available for remote access to U.S. servers. Another commenter asked BIS to clarify if taking an encrypted device is an export. BIS is not including these changes in regulatory text, because these are applications of the rule that are more appropriate to FAQs. However, BIS is confirming in its FAQs that TMP is available for remote access if its provisions are met. BIS is also confirming in its FAQs that taking an encrypted device is an export and referring to a different paragraph of § 740.9 for authorizing export of devices. Devices are commodities and therefore not eligible for paragraph (a)(3), which authorizes only technology.
One commenter recommended that BIS remove a requirement to encrypt the technology, saying that the list of techniques for securing the data required all to be used. BIS accepts this comment, and this final rule adds “may” before “include” to make clear that the list is illustrative. One commenter recommended allowing obfuscation/tokenization to protect data. BIS agrees that done properly, this is an effective security measure, and will add an FAQ on the topic to its Web site.

Scope of a License
The June 3 rule proposed implementing in the EAR the interagency-agreed boilerplate notification for all licenses that was posted on the BIS Web site and began appearing on licenses December 8, 2014. It was a slight revision to the former § 750.7(a), which stated that licenses authorize only the transaction(s) described in the license application and the license application support documents. The proposed revision also codified the existing interpretation that a license authorizing the release of technology to an entity also authorizes the release of the same technology to the entity's foreign nationals who are permanent and regular employees of the entity's facility or facilities authorized on the license, except to the extent a license condition limits or prohibits the release of the technology to nationals of specific countries or country groups.
Two commenters requested that BIS drop the modifier “permanent and” from “regular employees.” BIS does not adopt this request due to risk of diversion associated with non-permanent and non-regular employees. See further discussion of this issue above with respect to activities that are not deemed reexports. The phrase “under U.S. law” that modified “proscribed persons” in the June 3 rule is not adopted in this final rule for reasons discussed in connection with the definition of “proscribed persons” below. Except for that change, this final rule adopts the text proposed in the June 3 rule.

Removals From and Additions to EAR's List of Definitions in § 772.1
This final rule creates stand-alone sections in the EAR to address the scope and meaning of “publicly available information,” “publicly available technology and software,” and “technical data.” To avoid redundancy, this rule removes those definitions from § 772.1. In light of the changes described above, the definitions of “export,” “reexport,” “required,” “technology,” and “transfer” are revised accordingly. A clarifying note is added at the bottom of the definition explaining that the use of “transfer” does not apply to the unrelated “transfers of licenses” provision in § 750.10 or the antiboycott provisions in Supplement No. 8 to part 760 of the EAR. It also states that the term “transfer” may be included on licenses issued by BIS. In that regard, the changes that can be made to a BIS license are the non-material changes described in § 750.7(c). Any other change to a BIS license without authorization is a violation of the EAR. See §§ 750.7(c) and 764.2(e). Finally, consistent with the explanations above, definitions for the terms “access information,” “foreign person,” “fundamental research,” “proscribed person,” “publicly available encryption software,” “published,” and “release” are added to § 772.1.
One commenter stated that the definition of proscribed persons was overbroad, catching those individuals sanctioned under U.S. law without an export control nexus and recommended deleting “under US law.” BIS agrees with this comment. One commenter recommended striking “scientific” from the definition of “basic scientific research” in part 772 and adding definitions of applied and fundamental research to part 772. BIS does not accept this recommendation. The definition of “basic scientific research” reflects a Wassenaar Arrangement definition; it is retained in this final rule. A definition for applied research is not adopted because it is not necessary as a result of the adoption of a simplified definition of fundamental research, and as fundamental research is defined in § 734.8, use of a cross reference in part 772 is appropriate.

Issues Raised by Public Comments That Are Outside the Scope of This Rule
One commenter requested that BIS clarify treatment of U.S.-origin chemical materials that are substantially transformed and exempt Japan and other like-minded countries from reexport controls. One commenter requested that BIS expand controls on missile production and drop Fiji from Country Group D:5. One commenter appended comments on a separate BIS proposed rule for which the comment period was already closed. One commenter stated that items classified under Export Control Classification Number 0A998 will no longer be subject to the EAR under the new note to § 734.3(b)(3). One commenter requested that BIS drop the term “serial” from the definition of “production,” which was not revised by this rule. Although these comments are outside the scope of this rule and thus not addressed in this notice, BIS nonetheless encourages the public to submit thoughts, suggestions, and comments to BIS about the EAR and the export control system. BIS cannot commit to addressing them in every case, but nonetheless encourages as much industry participation as possible in the development and drafting of the regulations.

Export Administration Act
Since August 21, 2001, the Export Administration Act of 1979, as amended, has been in lapse. However, the President, through Executive Order 13222 of August 17, 2001, 3 CFR, 2001 Comp., p. 783 (2002), as amended by Executive Order 13637 of March 8, 2013, 78 FR 16129 (March 13, 2013), and as extended by the Notice of August 7, 2015 (80 FR 48233 (Aug. 11, 2015) has continued the EAR in effect under the International Emergency Economic Powers Act (50 U.S.C. 1701 et seq. ). BIS continues to carry out the provisions of the Export Administration Act, as appropriate and to the extent permitted by law, pursuant to Executive Order 13222 as amended by Executive Order 13637.

Regulatory Requirements
1. Executive Orders 13563 and 12866 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, distribute impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This final rule has been designated a “significant regulatory action,” although not economically significant, under section 3(f) of Executive Order 12866. Accordingly, this final rule has been reviewed by the Office of Management and Budget (OMB).
2. This final rule does not contain information collections subject to the requirements of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ) (PRA). Notwithstanding any other provision of law, no person is required to respond to, nor is 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.
3. This final rule does not contain policies with Federalism implications as that term is defined under E.O. 13132.
4. Pursuant to the Regulatory Flexibility Act, as amended by the Small Business Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. 601 et seq., BIS has prepared the following final Regulatory Flexibility Act analysis of the impact that this final rule will have on small entities.

Statement of the Objectives of, and Legal Basis for, the Final Rule; Identification of All Relevant Federal Rules Which May Duplicate, Overlap, or Conflict With the Final Rule
The objective of this final rule (and a final rule being published simultaneously by the Department of State) is to provide greater clarity and precision in the EAR and the ITAR by providing, where warranted and possible, common definitions and common terms to regulate the same types of actions and issues. This final rule also seeks to express some concepts more clearly.
The final rule alters definitions in the EAR. It also updates and clarifies application of controls to electronically transmitted technology and software.
The legal basis for this proposed rule is 50 U.S.C. 4601 et seq.; 50 U.S.C. 1701 et seq.; E.O. 12938, 59 FR 59099, 3 CFR, 1994 Comp., p. 950; E.O. 13020, 61 FR 54079, 3 CFR, 1996 Comp., p. 219; E.O. 13026, 61 FR 58767, 3 CFR, 1996 Comp., p. 228; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; E.O. 13637, 78 FR 16129, 3 CFR, 2014 Comp., p. 223; Notice of August 7, 2015, 80 FR 48233 (August 11, 2015); Notice of November 12, 2015, 80 FR 70667 (November 13, 2015).
No other Federal rules duplicate, overlap, or conflict with this final rule.

Comments in Response to the Initial Regulatory Flexibility Analysis
BIS received one comment from the public in response to the Initial Regulatory Flexibility Analysis (IRFA). The comment stated that while the proposed regulatory text indicated that the extent to which release of access information could be a violation of the EAR was limited by whether the party acted with knowledge, text in the IRFA regarding the impact of this provision created tension by stating that other provisions in the EAR could be used to bring charges for that same type of misconduct. The comment requested that BIS provide clarification in the final rule. BIS addressed this comment by not adopting § 764.2(l), the provision that would have established the violation at issue in the final rule. The Chief Counsel for Advocacy of the Small Business Administration filed no comments in response to the proposed rule.

Number and Description of Small Entities to Which This Rule Will Apply
This final rule will apply to all persons engaged in the export, reexport, or transfer of commodities, technology, or software subject to the EAR. BIS does not maintain data from which it can determine how many of those persons are small entities as identified in the Small Business Administration size standards. Nevertheless, BIS recognizes that some of those persons are likely to be small entities.

Description of the Projected Reporting, Recordkeeping, and Other Compliance Requirements of the Final Rule
This final rule is unlikely to increase the number of transactions that must be reported to BIS because EAR reporting requirements apply only in five specific situations, none of which will change as a result of this final rule. Those situations are: Exports of items on the Wassenaar Arrangement Sensitive List that do not require a license; Exports of High Performance Computers; Exports of certain thermal imaging cameras that do not require a license; Certain exports of Conventional Arms; and 600 series major defense equipment. Because recordkeeping requirements already apply to all transactions that are subject to the EAR, BIS expects that this final rule will not expand recordkeeping requirements.
It is possible that some of these changes will increase the number of licenses that some small entities will have to seek from BIS, although BIS is not aware of any specific instance in which additional licenses will be required.
The following discussion describes the changes made by this final rule. It is divided into two sections: Changes that BIS believes will not impose any new regulatory obligations; and Changes that are not intended to imposed any new regulatory obligation, but that BIS cannot state with certainty will not do so.

Changes That BIS Believes Will Not Impose Any New Regulatory Burden
This final rule makes certain changes to clarify and streamline the definitions of comparable terms, phrases, and concepts between the EAR and the ITAR. Many of these changes are technical in nature and attempt to consolidate and re-phrase the definitions to enhance readability and to parallel the structure of the ITAR's definition of the same term. There are a small number of new provisions, but these changes do not impose any new regulatory burdens. Specifically, this final rule makes the following changes:
Removes § 734.2(b) which formerly defined export, reexport, release, transfer (in country) and export of encryption source code or object code software, because those terms are defined in separate sections. Section 734.2(b) also stated the policy of applying license requirements that apply to a country to its dependencies and possessions; this policy is currently stated elsewhere in the EAR.
Creates new separate sections defining export, reexport, release and export of encryption source code or object code software. Those terms are clarified and presented in a more organized manner, but substantively unchanged from the former regulatory text.
Creates a new section identifying activities that are not exports, reexports, or transfers. This section restates the transactions that are excluded from the definition of export in former regulatory text and adds two additional activities that are expressly declared not to be exports, reexports or transfers: Space launches; and sending, taking or storing certain technology or software abroad using specified cryptographic techniques. The former, although it was not included in past regulatory text, states an exclusion already set forth in a statute ( see 51 U.S.C. 50919(f)) and is consistent with past BIS practice of not treating a space launch as an export, reexport or transfer. The latter is, in fact, new. However, by removing the transactions it describes from the definitions of exports, reexports, or transfers, it removes existing license requirements from those transactions.
Clarifies without substantively changing the provisions related to patent applications and adds specific text stating that technology contained in a patent available from or at any patent office is not subject to the EAR. The addition reflects BIS's long-standing interpretation. To the extent that it could be characterized as new, its only effect would be to appear to release from the EAR technology that some readers of the EAR might have (erroneously) concluded was subject to the EAR.
Adds text to License Exception TMP to emphasize that foreign subsidiaries of U.S. companies are neither U.S. employers nor “U.S. persons or their employees” as those terms are used in the license exception. This additional text adds no restriction that is not already imposed by the definition of “U.S. persons” that currently appears in the text of License Exception TMP.
Adds text codifying in the EAR limits on transactions authorized by a license that currently are imposed by conditions on the license itself.
Adds text specifying that to the extent an authorization would be required to transfer technology or software, a comparable authorization is required to transfer access information ( e.g., decryption keys, network access codes, and passwords) with “knowledge” that such transfer would result in the unauthorized release of such technology or software.

Changes That Are Not Intended To Impose Any Regulatory Obligation, But That BIS Cannot State With Certainty Would Not Do So
This final rule revises the definitions of the two existing terms “required” and “transfer (in-country).” It also adopts BIS's interpretative guidance regarding deemed reexports as regulatory text. These changes are not intended to impose any regulatory obligations on regulated entities, but BIS cannot state with certainty that there will be no impact. This final rule makes the following changes:
Adds to the EAR a definition of “proscribed person.” This definition does not create any new regulated class. It simply provides a clear, shorthand reference to a person who is already prohibited from receiving items or participating in a transaction that is subject to the EAR without authorization, such as persons on the Entity List.
Removes from the definition of the term “required” references to CCL Categories 4, 5, 6 and 9 to accurately reflect BIS's long-standing interpretation that its definition applies wherever the EAR imposes a license requirement for technology “required” for a particular process or activity.
In the definition of “transfer (in-country),” replaces the phrase “shipment, transmission, or release of items subject to the EAR from one person to another person that occurs outside the United States within a single foreign country” with “a change in end use or end user of an item within the same foreign country.” This new text will parallel the term “retransfer” in the ITAR and will eliminate any potential ambiguity that a change in end use or end user within a foreign country is or is not a “transfer (in-country).”
Each of the foregoing changes serves the overall policy goals of reducing uncertainty and harmonizing, to the extent warranted and possible, the requirements of the ITAR and the EAR. In most instances, reduced uncertainty will be beneficial to persons who have to comply with the regulations, particularly persons who engage in transactions subject to both sets of regulations. They will be able to make decisions more quickly and have less need to contact BIS for advice. Additionally, by making these terms more explicit, the possibility of their being interpreted contrary to BIS's intent is reduced. Such contrary interpretations would have three undesirable effects. First, they would undermine the national security and foreign policy objectives that the EAR are intended to implement. Second, persons who are interpreting the regulations in a less restrictive manner than BIS intends may seek fewer licenses from BIS than their competitors who are interpreting the regulations consistent with BIS's intent or who are obtaining advice from BIS, thereby gaining a commercial advantage to the detriment of the relevant national security or foreign policy interests. Third, unnecessary regulatory complexity and unnecessary differences between the terminology of the ITAR and that of the EAR could discourage small entities from even attempting to export. The beneficial effects of making these terms more explicit justify the economic impact that might be incurred by small entities that will have to change their conduct because their contrary interpretations can no longer be relied on given the clearer and more explicit terms in the regulations.
This final rule also adds to the EAR a description of activities that are not deemed reexports. This description formerly appeared as interpretative guidance on BIS's Web site and closely tracks the regulatory text of the ITAR. Deemed reexports are releases of technology or software source code within a single foreign country by a party located outside the United States to a national of a country other than the country in which the releasing party is located. The new section describes three situations in which that party may release the technology or source code without obtaining a license from BIS.
By adopting this guidance as regulatory text that closely tracks the text governing the same activities in the ITAR, BIS reduces both complexity and unnecessary differences between the two sets of regulations with the salutary effects of faster decision making, reduced need to contact BIS for advice, and reduced possibility that small entities would be discouraged from exporting as noted above.

Description of Any Significant Alternatives to the Final Rule That Accomplish the Stated Objectives of Applicable Statutes and That Minimize Any Significant Economic Impact of the Final Rule on Small Entities
As required by 5 U.S.C. 603(c), BIS's analysis considered significant alternatives. Those alternatives are: (1) The preferred alternative of altering definitions and updating and clarifying application of controls to electronically transmitted technology and software; (2) Maintaining the status quo and not revising the definitions or updating and clarifying application of controls to electronically transmitted technology and software; and (3) Establishing a size threshold below which entities would not be subject to the changes proposed by this rulemaking.
By altering definitions and updating and clarifying application of controls to electronically transmitted technology and software as this final rule does, BIS reduces uncertainty for all parties engaged in transactions that are subject to the EAR. Potential ambiguities are reduced; decisions can be made more quickly; the need to contact BIS for advice is reduced; and the possibility of inconsistent interpretations providing one party commercial advantages over others is reduced. Persons (including small entities) engaged in transactions that are subject to the ITAR and transactions that are subject to the EAR face fewer actual or apparent inconsistencies that must be addressed in their regulatory compliance programs. Although small entities, along with all other parties, will need to become familiar with the revised terminology, in the long run, compliance costs are likely to be reduced when compared to the present situation where the ITAR and the EAR use different terminology to regulate the same types of activity in the same manner. Therefore, BIS adopted this alternative.
If BIS had chosen to maintain the status quo, small entities and other parties would not have to incur the cost and effort of becoming familiar with the revised regulations, and any party who was interpreting the regulations in a way that would clearly be precluded by the more explicit interpretations would not incur the cost of complying with the regulations consistent with their underlying intent and in the way that BIS believes most regulated parties do. However, the benefits of these proposed changes would be lost. Those benefits, greater clarity, consistency between the ITAR and the EAR, and reduced possibility of inconsistent application of the regulations by similarly situated regulated parties, would be foregone. Therefore, BIS has not adopted this alternative.
If BIS had chosen to create a size threshold exempting small entities as currently defined by the SBA size standards from the changes imposed by this final rule, those entities would face a more complicated regulatory environment than larger entities. The small entities would continue to be subject to the EAR as a whole but without the benefit of the clarifications introduced by this final rule. The only way to make a size threshold beneficial to entities falling below the threshold would be to exempt them from all or at least many of the requirements of the EAR. However, doing so would create a major loophole allowing commodities, software, and technology that are controlled for export for national security or foreign policy reasons to go, without restriction, to any party abroad, undermining the interests that the regulations are intended to protect. Therefore, BIS has not adopted this alternative.

List of Subjects
15 CFR Parts 734 and 772
Exports.
15 CFR Parts 740 and 750
Administrative practice and procedure, Exports, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, parts 734, 740, 750, and 772 of the Export Administration Regulations (15 CFR subchapter C) are amended as follows:

PART 734—SCOPE OF THE EXPORT ADMINISTRATION REGULATIONS
1. The authority citation for part 734 continues to read as follows:

Authority:
50 U.S.C. 4601 et seq.; 50 U.S.C. 1701 et seq.; E.O. 12938, 59 FR 59099, 3 CFR, 1994 Comp., p. 950; E.O. 13020, 61 FR 54079, 3 CFR, 1996 Comp., p. 219; E.O. 13026, 61 FR 58767, 3 CFR, 1996 Comp., p. 228; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; E.O. 13637, 78 FR 16129, 3 CFR, 2014 Comp., p. 223; Notice of August 7, 2015, 80 FR 48233 (August 11, 2015); Notice of November 12, 2015, 80 FR 70667 (November 13, 2015).
2. Section 734.2 is amended by revising the heading to read as follows and by removing and reserving paragraph (b).
§ 734.2
Subject to the EAR.
* * * * *
3. Section 734.3 is amended by revising paragraph (b) introductory text, paragraph (b)(3), the Note to paragraphs (b)(2) and (b)(3), and adding a Note to paragraph (b)(3) to read as follows.
§ 734.3
Items subject to the EAR.
* * * * *
(b) The following are not subject to the EAR:
* * * * *
(3) Information and “software” that:
(i) Are published, as described in § 734.7;
(ii) Arise during, or result from, fundamental research, as described in § 734.8;
(iii) Are released by instruction in a catalog course or associated teaching laboratory of an academic institution;
(iv) Appear in patents or open (published) patent applications available from or at any patent office, unless covered by an invention secrecy order, or are otherwise patent information as described in § 734.10;
(v) Are non-proprietary system descriptions; or
(vi) Are telemetry data as defined in Note 2 to Category 9, Product Group E (see Supplement No. 1 to part 774 of the EAR).

Note to paragraphs (b)(2) and (b)(3):
A printed book or other printed material setting forth encryption source code is not itself subject to the EAR (see § 734.3(b)(2)). However, notwithstanding § 734.3(b)(2), encryption source code in electronic form or media ( e.g., computer diskette or CD ROM) remains subject to the EAR (see § 734.17)). Publicly available encryption object code “software” classified under ECCN 5D002 is not subject to the EAR when the corresponding source code meets the criteria specified in § 740.13(e) of the EAR.

Note to paragraph (b)(3):
Except as set forth in part 760 of this title, information that is not within the scope of the definition of “technology” (see § 772.1 of the EAR) is not subject to the EAR.
* * * * *
4. Section 734.7 is revised to read as follows:
§ 734.7
Published.
(a) Except as set forth in paragraph (b) of this section, unclassified “technology” or “software” is “published,” and is thus not “technology” or “software” subject to the EAR, when it has been made available to the public without restrictions upon its further dissemination such as through any of the following:
(1) Subscriptions available without restriction to any individual who desires to obtain or purchase the published information;
(2) Libraries or other public collections that are open and available to the public, and from which the public can obtain tangible or intangible documents;
(3) Unlimited distribution at a conference, meeting, seminar, trade show, or exhibition, generally accessible to the interested public;
(4) Public dissemination ( i.e., unlimited distribution) in any form ( e.g., not necessarily in published form), including posting on the Internet on sites available to the public; or
(5) Submission of a written composition, manuscript, presentation, computer-readable dataset, formula, imagery, algorithms, or some other representation of knowledge with the intention that such information will be made publicly available if accepted for publication or presentation:
(i) To domestic or foreign co-authors, editors, or reviewers of journals, magazines, newspapers or trade publications;
(ii) To researchers conducting fundamental research; or
(iii) To organizers of open conferences or other open gatherings.
(b) Published encryption software classified under ECCN 5D002 remains subject to the EAR unless it is publicly available encryption object code software classified under ECCN 5D002 and the corresponding source code meets the criteria specified in § 740.13(e) of the EAR.
5. Section 734.8 is revised to read as follows:
§ 734.8
“Technology” or “software” that arises during, or results from, fundamental research.
(a) Fundamental research. “Technology” or “software” that arises during, or results from, fundamental research and is intended to be published is not subject to the EAR.

Note 1 to paragraph (a):
This paragraph does not apply to “technology” or “software” subject to the EAR that is released to conduct fundamental research. (See § 734.7(a)(5)(ii) for information released to researchers that is “published.”)

Note 2 to paragraph (a):
There are instances in the conduct of research where a researcher, institution or company may decide to restrict or protect the release or publication of “technology” or “software” contained in research results. Once a decision is made to maintain such “technology” or “software” as restricted or proprietary, the “technology” or “software,” if within the scope of § 734.3(a), becomes subject to the EAR.
(b) Prepublication review. “Technology” or “software” that arises during, or results, from fundamental research is intended to be published to the extent that the researchers are free to publish the “technology” or “software” contained in the research without restriction. “Technology” or “software” that arises during or results from fundamental research subject to prepublication review is still intended to be published when:
(1) Prepublication review is conducted solely to ensure that publication would not compromise patent rights, so long as the review causes no more than a temporary delay in publication of the research results;
(2) Prepublication review is conducted by a sponsor of research solely to insure that the publication would not inadvertently divulge proprietary information that the sponsor has furnished to the researchers; or
(3) With respect to research conducted by scientists or engineers working for a Federal agency or a Federally Funded Research and Development Center (FFRDC), the review is conducted within any appropriate system devised by the agency or the FFRDC to control the release of information by such scientists and engineers.

Note 1 to paragraph (b):
Although “technology” or “software” arising during or resulting from fundamental research is not considered intended to be published if researchers accept restrictions on its publication, such “technology” or “software” will nonetheless qualify as “technology” or “software” arising during or resulting from fundamental research once all such restrictions have expired or have been removed.

Note 2 to paragraph (b):
Research that is voluntarily subjected to U.S. government prepublication review is considered “intended to be published” when the research is released consistent with the prepublication review and any resulting controls.

Note 3 to paragraph (b):
“Technology” or “software” resulting from U.S. government funded research that is subject to government-imposed access and dissemination or other specific national security controls qualifies as “technology” or “software” resulting from fundamental research, provided that all government-imposed national security controls have been satisfied and the researchers are free to publish the “technology” or “software” contained in the research without restriction. Examples of specific national security controls include requirements for prepublication review by the Government, with right to withhold permission for publication; restrictions on prepublication dissemination of information to non-U.S. citizens or other categories of persons; or restrictions on participation of non-U.S. citizens or other categories of persons in the research. A general reference to one or more export control laws or regulations or a general reminder that the Government retains the right to classify is not a specific national security control.
(c) Fundamental research definition. Fundamental research means research in science, engineering, or mathematics, the results of which ordinarily are published and shared broadly within the research community, and for which the researchers have not accepted restrictions for proprietary or national security reasons.
§ 734.9—[Removed
and Reserved]
6. Section 734.9 is removed and reserved.
7. Section 734.10 is revised to read as follows:
§ 734.10
Patents.
“Technology” is not subject to the EAR if it is contained in any of the following:
(a) A patent or an open (published) patent application available from or at any patent office;
(b) A published patent or patent application prepared wholly from foreign-origin “technology” where the application is being sent to the foreign inventor to be executed and returned to the United States for subsequent filing in the U.S. Patent and Trademark Office;
(c) A patent application, or an amendment, modification, supplement or division of an application, and authorized for filing in a foreign country in accordance with the regulations of the Patent and Trademark Office, 37 CFR part 5; or
(d) A patent application when sent to a foreign country before or within six months after the filing of a United States patent application for the purpose of obtaining the signature of an inventor who was in the United States when the invention was made or who is a co-inventor with a person residing in the United States.
§ 734.11—[Removed
and Reserved]
8. Section 734.11 is removed and reserved.
9. Section 734.13 is added to read as follows:
§ 734.13
Export.
(a) Except as set forth in §§ 734.17 or 734.18, Export means:
(1) An actual shipment or transmission out of the United States, including the sending or taking of an item out of the United States, in any manner;
(2) Releasing or otherwise transferring “technology” or source code (but not object code) to a foreign person in the United States (a “deemed export”);
(3) Transferring by a person in the United States of registration, control, or ownership of:
(i) A spacecraft subject to the EAR that is not eligible for export under License Exception STA ( i.e., spacecraft that provide space-based logistics, assembly or servicing of any spacecraft) to a person in or a national of any other country; or
(ii) Any other spacecraft subject to the EAR to a person in or a national of a Country Group D:5 country.
(b) Any release in the United States of “technology” or source code to a foreign person is a deemed export to the foreign person's most recent country of citizenship or permanent residency.
(c) The export of an item that will transit through a country or countries to a destination identified in the EAR is deemed to be an export to that destination.
10. Section 734.14 is added to read as follows:
§ 734.14
Reexport.
(a) Except as set forth in §§ 734.18 and 734.20, Reexport means:
(1) An actual shipment or transmission of an item subject to the EAR from one foreign country to another foreign country, including the sending or taking of an item to or from such countries in any manner;
(2) Releasing or otherwise transferring “technology” or source code subject to the EAR to a foreign person of a country other than the foreign country where the release or transfer takes place (a deemed reexport);
(3) Transferring by a person outside the United States of registration, control, or ownership of:
(i) A spacecraft subject to the EAR that is not eligible for reexport under License Exception STA ( i.e., spacecraft that provide space-based logistics, assembly or servicing of any spacecraft) to a person in or a national of any other country; or
(ii) Any other spacecraft subject to the EAR to a person in or a national of a Country Group D:5 country.
(b) Any release outside of the United States of “technology” or source code subject to the EAR to a foreign person of another country is a deemed reexport to the foreign person's most recent country of citizenship or permanent residency, except as described in § 734.20.
(c) The reexport of an item subject to the EAR that will transit through a country or countries to a destination identified in the EAR is deemed to be a reexport to that destination.
11. Section 734.15 is added to read as follows:
§ 734.15
Release.
(a) Except as set forth in § 734.18, “technology” and “software” are “released” through:
(1) Visual or other inspection by a foreign person of items that reveals “technology” or source code subject to the EAR to a foreign person; or
(2) Oral or written exchanges with a foreign person of “technology” or source code in the United States or abroad.
(b) Any act causing the “release” of “technology” or “software,” through use of “access information” or otherwise, to yourself or another person requires an authorization to the same extent an authorization would be required to export or reexport such “technology” or “software” to that person.
12. Section 734.16 is added to read as follows:
§ 734.16
Transfer (in-country).
Except as set forth in § 734.18(a)(3), a Transfer (in-country) is a change in end use or end user of an item within the same foreign country. Transfer (in-country) is synonymous with In-country transfer.
13. Section 734.17 is added to read as follows:
§ 734.17
Export of encryption source code and object code software.
(a) For purposes of the EAR, the Export of encryption source code and object code “software ” means:
(1) An actual shipment, transfer, or transmission out of the United States ( see also paragraph (b) of this section); or
(2) A transfer of such “software” in the United States to an embassy or affiliate of a foreign country.
(b) The export of encryption source code and object code “software” controlled for “EI” reasons under ECCN 5D002 on the Commerce Control List (see Supplement No. 1 to part 774 of the EAR) includes:
(1) Downloading, or causing the downloading of, such “software” to locations (including electronic bulletin boards, Internet file transfer protocol, and World Wide Web sites) outside the U.S., or
(2) Making such “software” available for transfer outside the United States, over wire, cable, radio, electromagnetic, photo optical, photoelectric or other comparable communications facilities accessible to persons outside the United States, including transfers from electronic bulletin boards, Internet file transfer protocol and World Wide Web sites, unless the person making the “software” available takes precautions adequate to prevent unauthorized transfer of such code. See § 740.13(e) of the EAR for notification requirements for exports or reexports of encryption source code “software” considered to be publicly available or published consistent with the provisions of § 734.3(b)(3). Publicly available encryption “software” in object code that corresponds to encryption source code made eligible for License Exception TSU under § 740.13(e) of the EAR is not subject to the EAR.
(c) Subject to the General Prohibitions described in part 736 of the EAR, such precautions for Internet transfers of products eligible for export under § 740.17(b)(2) of the EAR (encryption “software” products, certain encryption source code and general purpose encryption toolkits) shall include such measures as:
(1) The access control system, either through automated means or human intervention, checks the address of every system outside of the U.S. or Canada requesting or receiving a transfer and verifies such systems do not have a domain name or Internet address of a foreign government end-user ( e.g., “.gov,” “.gouv,” “.mil” or similar addresses);
(2) The access control system provides every requesting or receiving party with notice that the transfer includes or would include cryptographic “software” subject to export controls under the Export Administration Regulations, and anyone receiving such a transfer cannot export the “software” without a license or other authorization; and
(3) Every party requesting or receiving a transfer of such “software” must acknowledge affirmatively that the “software” is not intended for use by a government end user, as defined in part 772 of the EAR, and he or she understands the cryptographic “software” is subject to export controls under the Export Administration Regulations and anyone receiving the transfer cannot export the “software” without a license or other authorization. BIS will consider acknowledgments in electronic form provided they are adequate to assure legal undertakings similar to written acknowledgments.
14. Section 734.18 is added to read as follows:
§ 734.18
Activities that are not exports, reexports, or transfers.
(a) Activities that are not exports, reexports, or transfers. The following activities are not exports, reexports, or transfers:
(1) Launching a spacecraft, launch vehicle, payload, or other item into space.
(2) Transmitting or otherwise transferring “technology” or “software” to a person in the United States who is not a foreign person from another person in the United States.
(3) Transmitting or otherwise making a transfer (in-country) within the same foreign country of “technology” or “software” between or among only persons who are not “foreign persons,” so long as the transmission or transfer does not result in a release to a foreign person or to a person prohibited from receiving the “technology” or “software.”
(4) Shipping, moving, or transferring items between or among the United States, the District of Columbia, the Commonwealth of Puerto Rico, or the Commonwealth of the Northern Mariana Islands or any territory, dependency, or possession of the United States as listed in Schedule C, Classification Codes and Descriptions for U.S. Export Statistics, issued by the Bureau of the Census.
(5) Sending, taking, or storing “technology” or “software” that is:
(i) Unclassified;
(ii) Secured using ‘end-to-end encryption;'
(iii) Secured using cryptographic modules (hardware or “software”) compliant with Federal Information Processing Standards Publication 140-2 (FIPS 140-2) or its successors, supplemented by “software” implementation, cryptographic key management and other procedures and controls that are in accordance with guidance provided in current U.S. National Institute for Standards and Technology publications, or other equally or more effective cryptographic means; and
(iv) Not intentionally stored in a country listed in Country Group D:5 ( see Supplement No. 1 to part 740 of the EAR) or in the Russian Federation.

Note to paragraph (a)(4)(iv):
Data in-transit via the Internet is not deemed to be stored.
(b) Definitions. For purposes of this section, End-to-end encryption means (i) the provision of cryptographic protection of data such that the data is not in unencrypted form between an originator (or the originator's in-country security boundary) and an intended recipient (or the recipient's in-country security boundary), and (ii) the means of decryption are not provided to any third party. The originator and the recipient may be the same person.
(c) Ability to access “technology” or “software” in encrypted form. The ability to access “technology” or “software” in encrypted form that satisfies the criteria set forth in paragraph (a)(5) of this section does not constitute the release or export of such “technology” or “software.”
15. Section 734.19 is added to read as follows:
§ 734.19
Transfer of access information.
To the extent an authorization would be required to transfer “technology” or “software,” a comparable authorization is required to transfer access information if done with “knowledge” that such transfer would result in the release of such “technology” or “software” without a required authorization.
16. Section 734.20 is added to read as follows:
§ 734.20
Activities that are not deemed reexports.
The following activities are not deemed reexports (see “deemed reexport” definition in § 734.14(b)):
(a) Authorized Release of “technology” or source code. Release of “technology” or source code by an entity outside the United States to a foreign person of a country other than the foreign country where the release takes place if:
(1) The entity is authorized to receive the “technology” or source code at issue, whether by a license, license exception, or situation where no license is required under the EAR for such “technology” or source code; and
(2) The entity has “knowledge” that the foreign national's most recent country of citizenship or permanent residency is that of a country to which export from the United States of the “technology” or source code at issue would be authorized by the EAR either under a license exception or in situations where no license under the EAR would be required.
(b) Release to Country Group A:5 nationals. Without limiting the scope of paragraph (a), release of “technology” or source code by an entity outside the United States to a foreign person of a country other than the foreign country where the release takes place if:
(1) The entity is authorized to receive the “technology” or source code at issue, whether by a license, license exception, or through situations where no license is required under the EAR;
(2) The foreign person is a bona fide `permanent and regular employee' of the entity and is not a proscribed person (see § 772.1 for definition of proscribed person);
(3) Such employee is a national exclusively of a country in Country Group A:5; and
(4) The release of “technology” or source code takes place entirely within the physical territory of any such country, or within the United States.
(c) Release to other than Country Group A:5 nationals. Without limiting the scope of paragraph (a), release of “technology” or source code by an entity outside the United States to a foreign person of a country other than the foreign country where the release takes place if:
(1) The entity is authorized to receive the “technology” or source code at issue, whether by a license, license exception, or situations where no license is required under the EAR;
(2) The foreign person is a bona fide `permanent and regular employee' of the entity and is not a proscribed person (see § 772.1 for definition of proscribed person);
(3) The release takes place entirely within the physical territory of the country where the entity is located, conducts official business, or operates, or within the United States;
(4) The entity has effective procedures to prevent diversion to destinations, entities, end users, and end uses contrary to the EAR; and
(5) Any one of the following six ( i.e., paragraphs (c)(5)(i), (ii), (iii), (iv), (v), or (vi) of this section) situations is applicable:
(i) The foreign person has a security clearance approved by the host nation government of the entity outside the United States;
(ii) The entity outside the United States:
(A) Has in place a process to screen the foreign person employee and to have the employee execute a non-disclosure agreement that provides assurances that the employee will not disclose, transfer, or reexport controlled “technology” contrary to the EAR;
(B) Screens the employee for substantive contacts with countries listed in Country Group D:5 (see Supplement No. 1 to part 740 of the EAR). Although nationality does not, in and of itself, prohibit access to “technology” or source code subject to the EAR, an employee who has substantive contacts with foreign persons from countries listed in Country Group D:5 shall be presumed to raise a risk of diversion, unless BIS determines otherwise;
(C) Maintains a technology security or clearance plan that includes procedures for screening employees for such substantive contacts;
(D) Maintains records of such screenings for the longer of five years or the duration of the individual's employment with the entity; and
(E) Will make such plans and records available to BIS or its agents for civil and criminal law enforcement purposes upon request;
(iii) The entity is a U.K. entity implementing § 126.18 of the ITAR (22 CFR 126.18) pursuant to the U.S.-U.K. Exchange of Notes regarding § 126.18 of the ITAR for which the U.K. has provided appropriate implementation guidance;
(iv) The entity is a Canadian entity implementing § 126.18 of the ITAR pursuant to the U.S.-Canadian Exchange of Letters regarding § 126.18 of the ITAR for which Canada has provided appropriate implementation guidance;
(v) The entity is an Australian entity implementing the exemption at paragraph 3.7b of the ITAR Agreements Guidelines; or
(vi) The entity is a Dutch entity implementing the exemption at paragraph 3.7c of the ITAR Agreements Guidelines.
(d) Definitions —(1) Substantive contacts include regular travel to countries in Country Group D:5; recent or continuing contact with agents, brokers, and nationals of such countries; continued demonstrated allegiance to such countries; maintenance of business relationships with persons from such countries; maintenance of a residence in such countries; receiving salary or other continuing monetary compensation from such countries; or acts otherwise indicating a risk of diversion.
(2) Permanent and regular employee is an individual who:
(i) Is permanently ( i.e., for not less than a year) employed by an entity, or
(ii) Is a contract employee who:
(A) Is in a long-term contractual relationship with the company where the individual works at the entity's facilities or at locations assigned by the entity (such as a remote site or on travel);
(B) Works under the entity's direction and control such that the company must determine the individual's work schedule and duties;
(C) Works full time and exclusively for the entity; and
(D) Executes a nondisclosure certification for the company that he or she will not disclose confidential information received as part of his or her work for the entity.

Note to paragraph (d)(2):
If the contract employee has been seconded to the entity by a staffing agency, then the staffing agency must not have any role in the work the individual performs other than to provide the individual for that work. The staffing agency also must not have access to any controlled “technology” or source code other than that authorized by the applicable regulations or a license.

Supplement No. 1 to Part 734 [Removed and Reserved]
17. Supplement No. 1 to part 734 is removed and reserved.

PART 740— LICENSE EXCEPTIONS
18. The authority citation for part 740 continues to read as follows:

Authority:
50 U.S.C. 4601 et seq.; 50 U.S.C. 1701 et seq.; 22 U.S.C. 7201 et seq.; E.O. 13026, 61 FR 58767, 3 CFR, 1996 Comp., p. 228; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; Notice of August 7, 2015, 80 FR 48233 (August 11, 2015).
19. In § 740.9, paragraph (a)(3) is revised to read as follows:
§ 740.9
Temporary imports, exports, reexports, and transfers (in-country) (TMP).
* * * * *
(a) * * *
(3) “Technology,” regardless of media or format, may be exported, reexported, or transferred (in-country) by or to a U.S. person, or a foreign person employee of a U.S. person traveling or on temporary assignment abroad, subject to the following restrictions:
(i) Foreign persons may only export, reexport, transfer (in country) or receive such “technology” as they are authorized to receive through a license, license exception other than TMP or because no license is required.
(ii) “Technology” exported, reexported, or transferred under this authorization may only be possessed or used by a U.S. person or authorized foreign person. Sufficient security precautions must be taken to prevent the unauthorized release of the “technology.” Such security precautions may include encryption of the “technology,” the use of secure network connections, such as Virtual Private Networks, the use of passwords or other access restrictions on the electronic device or media on which the “technology” is stored, and the use of firewalls and other network security measures to prevent unauthorized access.
(iii) The individual is an employee of the U.S. Government or is directly employed by a U.S. person and not, e.g., by a foreign subsidiary.
(iv) “Technology” authorized under this exception may not be used for foreign production purposes or for technical assistance unless authorized through a license or license exception other than TMP.
* * * * *

PART 750—APPLICATION PROCESSING, ISSUANCE, AND DENIAL
20. The authority citation for 15 CFR part 750 continues to read as follows:

Authority:
50 U.S.C. 4601 et seq.; 50 U.S.C. 1701 et seq.; Sec 1503, Pub. L. 108-11, 117 Stat. 559; E.O. 13026, 61 FR 58767, 3 CFR, 1996 Comp., p. 228; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; E.O. 13637, 78 FR 16129, 3 CFR, 2013 Comp., p. 223; Presidential Determination 2003-23, 68 FR 26459, 3 CFR, 2004 Comp., p. 320; Notice of August 7, 2015, 80 FR 48233 (August 11, 2015).
21. Section 750.7 is amended by revising paragraph (a) to read as follows:
§ 750.7
Issuance of licenses.
(a) Scope. Unless limited by a condition set out in a license, the export, reexport, or transfer (in-country) authorized by a license is for the item(s), end-use(s), and parties described in the license application and any letters of explanation. The applicant must inform the other parties identified on the license, such as the ultimate consignees and end users, of the license's scope and of the specific conditions applicable to them. BIS grants licenses in reliance on representations the applicant made in or submitted in connection with the license application, letters of explanation, and other documents submitted. A BIS license authorizing the release of “technology” to an entity also authorizes the release of the same “technology” to the entity's foreign persons who are permanent and regular employees (and who are not proscribed persons) of the entity's facility or facilities authorized on the license, except to the extent a license condition limits or prohibits the release of the “technology” to foreign persons of specific countries or country groups.
* * * * *

PART 772—DEFINITIONS OF TERMS
22. The authority citation for part 772 continues to read as follows:

Authority:
50 U.S.C. 4601 et seq.; 50 U.S.C. 1701 et seq.; E.O. 13222, 66 FR 44025, 3 CFR, 2001 Comp., p. 783; Notice of August 7, 2015, 80 FR 48233 (August 11, 2015).
23. Section 772.1 is amended by:
a. Adding in alphabetical order a definition for “Access information”;
b. Revising the definition of “Export”;
c. Adding in alphabetical order definitions for “Foreign person,” “Fundamental research,” “Proscribed person,” and “Publicly available encryption software”;
d. Removing the definitions of “Publicly available information” and “Publicly available technology and software”;
e. Adding in alphabetical order a definition for “Published”;
f. Revising the definition of “Reexport”;
g. Adding in alphabetical order a definition for “Release”;
h. Revising the definition of “Required”;
i. Removing the definition of “Technical data”; and
j. Revising the definitions of “Technology,” and “Transfer.”
The revisions and additions read as follows:
§ 772.1
Definitions of terms as used in the Export Administration Regulations (EAR).
* * * * *
Access information. Information that allows access to encrypted technology or encrypted software in an unencrypted form. Examples include decryption keys, network access codes, and passwords.
* * * * *
Export. See § 734.13 of the EAR.
* * * * *
Foreign person. Any natural person who is not a lawful permanent resident of the United States, citizen of the United States, or any other protected individual as defined by 8 U.S.C. 1324b(a)(3). It also means any corporation, business association, partnership, trust, society or any other entity or group that is not incorporated in the United States or organized to do business in the United States, as well as international organizations, foreign governments and any agency or subdivision of a foreign government ( e.g., diplomatic mission). “Foreign person” is synonymous with “foreign national,” as used in the EAR, and “foreign person” as used in the International Traffic in Arms Regulations (22 CFR 120.16). This definition does not apply to part 760 of the EAR (Restrictive Trade Practices or Boycotts).
* * * * *
Fundamental research. See § 734.8 of the EAR.
* * * * *
Proscribed person. A person who is prohibited from receiving the items at issue or participating in a transaction that is subject to the EAR without authorization under the EAR, such as persons on the Entity List or denied persons.
Publicly available encryption software. See § 740.13(e) of the EAR.
Published. See § 734.7 of the EAR.
* * * * *
Reexport. See § 734.14 of the EAR.
Release. See § 734.15 of the EAR.
* * * * *
Required. (General Technology Note) —As applied to “technology” or “software,” refers to only that portion of “technology” or “software” which is peculiarly responsible for achieving or exceeding the controlled performance levels, characteristics or functions. Such “required” “technology” or “software” may be shared by different products. For example, assume product “X” is controlled on the CCL if it operates at or above 400 MHz and is not controlled if it operates below 400 MHz. If production technologies “A,” “B,” and “C” allow production at no more than 399 MHz, then technologies “A,” “B,” and “C” are not “required” to produce the controlled product “X”. If technologies “A,” “B,” “C,” “D,” and “E” are used together, a manufacturer can produce product “X” that operates at or above 400 MHz. In this example, technologies “D” and “E” are peculiarly responsible for making the controlled product and are thus “required” technology under the General Technology Note. (See the General Technology Note.)

Note 1 to the definition of Required:
The ITAR and the EAR often divide within each set of regulations or between each set of regulations:
(a) Controls on parts, components, accessories, attachments, and software; and
(b) Controls on the end items, systems, equipment, or other items into which those parts, components, accessories, attachments, and software are to be installed or incorporated.

Note 2 to the definition of Required:
The references to “characteristics” and “functions” are not limited to entries on the CCL that use specific technical parameters to describe the scope of what is controlled. The “characteristics” and “functions” of an item listed are, absent a specific regulatory definition, a standard dictionary's definition of the item. For example, ECCN 9A610.a controls military aircraft specially designed for a military use that are not enumerated in USML paragraph VIII(a). No performance level is identified in the entry, but the control characteristic of the aircraft is that it is specially designed “for military use.” Thus, any technology, regardless of significance, peculiar to making an aircraft “for military use” as opposed to, for example, an aircraft controlled under ECCN 9A991.a, would be technical data “required” for an aircraft specially designed for military use thus controlled under ECCN 9E610.

Note 3 to the definition of Required:
Unclassified technology not specifically enumerated on the USML is “subject to the EAR” if it is “ required” for the “development,” “production,” “use,” operation, installation, maintenance, repair, overhaul, or refurbishing (or other terms specified in ECCNs on the CCL that control “technology”) of a commodity or software that is subject to the EAR. Thus, for example, if unclassified technology not specifically enumerated on the USML is “required” for the development or production of a 9A610.x aircraft component that is to be integrated or installed in a USML VIII(a) aircraft, then the “technology” is controlled under ECCN 9E610, not USML VIII(i). Conversely, technical data directly related to, for example, the development or production of a component subject to the ITAR does not become subject to the EAR merely because it is developed or produced with equipment subject to the EAR.
* * * * *
Technology. Technology means:
Information necessary for the “development,” “production,” “use,” operation, installation, maintenance, repair, overhaul, or refurbishing (or other terms specified in ECCNs on the CCL that control “technology”) of an item.
N.B.: Controlled “technology” is defined in the General Technology Note and in the Commerce Control List (Supplement No. 1 to part 774 of the EAR).

Note 1 to definition of Technology:
“Technology” may be in any tangible or intangible form, such as written or oral communications, blueprints, drawings, photographs, plans, diagrams, models, formulae, tables, engineering designs and specifications, computer-aided design files, manuals or documentation, electronic media or information revealed through visual inspection;

Note 2 to definition of Technology:
The modification of the design of an existing item creates a new item and technology for the modified design is technology for the development or production of the new item.
* * * * *
Transfer. A shipment, transmission, or release of items subject to the EAR either within the United States or outside the United States. For In-country transfer/Transfer (in-country) , see § 734.16 of the EAR.

Note to definition of Transfer:
This definition of “transfer” does not apply to § 750.10 of the EAR or Supplement No. 8 to part 760 of the EAR. The term “transfer” may also be included on licenses issued by BIS. In that regard, the changes that can be made to a BIS license are the non-material changes described in § 750.7(c) of the EAR. Any other change to a BIS license without authorization is a violation of the EAR. See §§ 750.7(c) and 764.2(e) of the EAR.
* * * * *
Dated: May 23, 2016.
Kevin J. Wolf,

Assistant Secretary for Export Administration.
DELAWARE RIVER BASIN COMMISSION
18 CFR Part 420
Clarifying Language in the Basin Regulations—Water Supply Charges Relating to Certificates of Entitlement

AGENCY:
Delaware River Basin Commission.

ACTION:
Final rule.

SUMMARY:
The Delaware River Basin Commission is codifying revisions to its Basin Regulations—Water Supply Charges. The revisions involve no changes in the substance or administration of the rule. They were made in order to clarify the language of the rule to conform to the Commission's decisions and practices so as to provide better notice to users regarding how the Commission implements its entitlements program and to avoid future controversy.

DATES:
This final rule is effective July 5, 2016.

FOR FURTHER INFORMATION CONTACT:
Pamela Bush, 609-477-7203.

SUPPLEMENTARY INFORMATION:

Background
The Delaware River Basin Commission (“DRBC” or “Commission”) is a federal-interstate compact agency charged with managing the water resources of the Delaware River Basin on a regional basis without regard to political boundaries. Its members are the governors of the four basin states—Delaware, New Jersey, New York and Pennsylvania—and the North Atlantic Division Commander of the U.S. Army Corps of Engineers, representing the federal government.
By Resolution No. 2006-2 on March 1, 2006, the Commission approved revisions to its Basin Regulations—Water Supply Charges, 18 CFR part 420, to clarify the language of the rule to conform to the Commission's decisions and practices, in order to provide better notice to users regarding how the Commission implements its entitlements program and to avoid future controversy. The revisions involved no changes in the substance or administration of the rule. Although the adopted revisions were incorporated into the Commission's Administrative Manual Part III—Basin Regulations—Water Supply Charges, which uses a unique numbering system, the corresponding sections of the Code of Federal Regulations were never updated to include them. This final rule adds the approved changes to the federal code.
Notice of the proposed revisions was published in the Federal Register at 70 FR 60496, October 18, 2005. Notice also appeared in the Delaware Register of Regulations, 9 DE Reg. 674, November 1, 2005; New Jersey Register, 37 N.J.R. 4206, November 7, 2005; New York State Register, November 2, 2005 (page 4); and Pennsylvania Bulletin, 35 Pa.B. 6094, Nov. 5, 2005. The Commission held a public hearing on the proposed revisions on December 7, 2005 and accepted written comments on them through January 10, 2006. The changes were adopted by unanimous vote approving Resolution No. 2006-2 at the Commission's public business meeting on March 1, 2006.

Additional Materials
Additional materials can be found on the Commission's Web site, www.drbc.net. These include: the notice of the proposed amendments published in the Federal Register , at http://nj.gov/drbc/library/documents/water-charges-codify/1_FR_PropRule_CertsEntitle101805.pdf; and in the state registers at http://www.nj.gov/drbc/about/regulations/other-rulemakings.html; the text of the draft revisions as proposed, at http://nj.gov/drbc/library/documents/water-charges-codify/6_ProposedText_WaterSupplyChargingRegs_Art5.2.pdf; Resolution No. 2006-2, adopting the revisions as final, at http://nj.gov/drbc/library/documents/water-charges-codify/7_Res2006-02_CertEntitle_adopted030106.pdf; and the Minutes of the Commission's business meeting of March 1, 2006, explaining the differences between the proposed and adopted rule text, at http://nj.gov/drbc/library/documents/water-charges-codify/8_Min_030106_note-pgs18-21.pdf.
With adoption of this final rule, the Commission will reference the CFR version of the Basin Regulations—Water Supply Charges for most purposes. For the foreseeable future, however, both versions will remain posted on the Commission's Web site, at http://www.nj.gov/drbc/about/regulations/ .

List of Subjects in 18 CFR Part 420
Water supply.
For the reasons set forth in the preamble, the Delaware River Basin Commission amends part 420 of title 18 of the Code of Federal Regulations as follows:

PART 420—BASIN REGULATIONS—WATER SUPPLY CHARGES
1. The authority citation for part 420 continues to read as follows:

Authority:
Delaware River Basin Compact, 75 Stat. 688.
2. Revise § 420.31(d) through (f) to read as follows:
§ 420.31
Certificate of entitlement.
* * * * *
(d) Limitations. (1) A certificate of entitlement is granted to a specific user for water withdrawals or diversions at a specific facility in the amount of the Legal Entitlement as defined in § 420.23(b).
(2) A certificate of entitlement shall not be applied, transferred or modified to apply to a facility other than the facility initially specified in the certificate.
(3) A certificate of entitlement may not be transferred from the certificate holder to another user, except as provided in the exceptions set forth in paragraph (f) of this section.
(4) A certificate of entitlement does not exempt the certificate holder from paying water supply charges for any portion of water withdrawals or diversions used outside the facility specified in the certificate and any additional service area to which the facility supplied water as of October 27, 1961 or at the facility specified in the certificate by a user other than the certificate holder. For purposes of this paragraph (d)(4), a certificate holder claiming an exemption from charges for water supplied within a service area shall submit proof satisfactory to the Commission identifying the facility's service area as of October 27, 1961. In the absence of proof of the service area as of October 27, 1961, the service area defined in the Commission docket, if any, for the facility in effect at the time the certificate was issued shall be deemed to be the facility's service area. In the absence of proof of a service area, the certificate shall only exempt the certificate holder from paying water supply charges for water used at the facility.
(e) Termination of certificate. (1) A certificate of entitlement terminates pursuant to this section and without the need for Commission action if at least one of the following occurs:
(i) The certificate holder dissolves or otherwise ceases to exist;
(ii) The certificate holder ceases the withdrawals or diversions at the facility to which the certificate of entitlement applies, or abandons the intake, provided that a shutdown of the facility for maintenance or improvement, or a replacement of the intake, that is performed at the earliest practicable commercially reasonable time following commencement of the shutdown or replacement, shall not be deemed to be a cessation of withdrawal or diversion;
(iii) The certificate holder through contract, lease or other agreement ceases to be the user or public water system supplier of the water withdrawn or diverted at the facility; or
(iv) There is a change in the ownership or control of the facility. Once terminated, a certificate of entitlement may not be reinstated or reissued.
(2) A change in ownership or control of the facility includes, but is not limited to, any transaction, acquisition, merger or event (collectively “transaction”) resulting in at least one of the following:
(i) A transfer of title to the facility;
(ii) A person or entity or the shareholders or other owners of an entity becoming the beneficial owner, directly or indirectly, or acquiring alone or in concert the power or right to vote at least 20 percent of any class of ownership interest in a certificate holder or any of its parent entities, regardless of the tier in the corporate or entity structure at which the transaction occurs;
(iii) A change in ownership or control for purposes of any of the certificate holder's or any of its parent corporations' employee agreements; or
(iv) A change of the de facto controlling interest in a certificate holder or any of its parent entities, regardless of the tier in the corporate or entity structure at which the change occurs.
(3) A change of the de facto controlling interest in an entity includes, but is not limited to, a change of the persons or entities with the ability or authority, expressed or reserved, to direct the management or policies of an entity and/or to take at least one of the following actions:
(i) Amend or change the entity's identity ( e.g. joint venture agreement, unincorporated business status);
(ii) Appoint or remove at least 50% of the members of the Board of Directors or Trustees of a corporation, general partner of a partnership, or a similar member of the governing body of an entity;
(iii) Amend or change the by-laws, constitution, or other operating or management direction of the entity;
(iv) Control the sale of, use of or access to any or all of the entity's assets;
(v) Encumber the entity's assets by way of mortgage or other indebtedness;
(vi) Control any or all of the assets or other property of the entity upon the sale or dissolution of the entity;
(vii) Dissolve the entity;
(viii) Arrange for the sale or transfer of the entity to a new ownership or control;
(ix) Select or change the management of the entity or determine management compensation; or
(x) Set operating policies, financial policies or budgets.
(4) For purposes of applying paragraph (e)(3) of this section, consideration may be given to circumstances particular to the person or entity and certificate holder involved, including without limitation the ability of that person or entity to take actions in light of the number of shares in the certificate holder or its parent entities that are actively voted, the practice of any majority shareholder in exercising or refraining from exercising majority rights, and any agreements giving the person or entity the right to control votes of others.
(5) A series of transactions undertaken pursuant to a plan or that are otherwise related shall be considered a single transaction for purposes of this section. For purposes of calculating the twenty percent threshold in paragraph (e)(2)(ii) of this section, the securities, shares or other interests held immediately prior to the transaction shall be added to the securities, shares or other interests acquired in the transaction.
(f) Exceptions -(1) Agricultural exception. (i) Whenever ownership or possession of land in agricultural use is transferred, any certificate of entitlement with respect to such land shall be deemed to run with the land, if but only if within sixty days following the land transfer the new user demonstrates to the Executive Director that it will continue to use the water withdrawn or diverted for agricultural irrigation. Following any such timely demonstration, the Executive Director shall transfer the certificate of entitlement to the new user. The Executive Director may extend the sixty day period for good cause shown.
(ii) A certificate of entitlement that has been transferred pursuant to paragraph (f)(1)(i) of this section relieves the user of the obligation to pay water supply charges only with respect to the quantity of water in fact used by the new certificate holder for agricultural irrigation up to the Legal Entitlement specified in the certificate, and not with respect to the quantity of water used for any other purposes. The provisions of § 420.43 shall apply to water uses outside the scope of the certificate of entitlement.
(iii) A certificate of entitlement that has been transferred pursuant to paragraph (f)(1)(i) of this section terminates pursuant to this paragraph (f)(1) and without the need for Commission action if and when the certificate holder ceases using the water for agricultural irrigation, provided that if the cessation occurs in conjunction with a transfer of ownership or possession of the land in agricultural use, the certificate of entitlement may be transferred to a new user pursuant to paragraph (f)(1)(i). Once terminated, a certificate of entitlement may not be reinstated or reissued.
(2) Corporate reorganization exceptions. The following provisions apply where a corporate parent directly or indirectly owning 100% of each class of shares of all of its subsidiary corporations decides to reorganize those subsidiary corporations without affecting the corporate parent's 100% ownership interest.
(i) Whenever a corporate reorganization consists solely of a change of the name, identity, internal corporate structure, or place of organization of a corporate certificate holder or any of its parent corporations, the Executive Director may reissue a certificate of entitlement in the name of the new owner of the facility, provided that the reorganization does not affect ownership and/or control by the certificate holder's corporate family of companies within the meaning of paragraphs (e)(2) through (5) of this section and does not alter the ultimate corporate parent's 100% ownership interest.
(ii) A merger or other plan, transaction or series of transactions that effectuates a change of ownership or control within the meaning of paragraphs (e)(2) through (5) does not fall within the exemption of paragraph (f)(2)(i) of this section on the basis that a corporate reorganization constitutes part of the merger, plan, transaction or series of transactions.
Dated: May 26, 2016.
Pamela M. Bush,

Commission Secretary and Assistant General Counsel.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
21 CFR Part 573
[Docket No. FDA-2014-F-0232]
Food Additives Permitted in Feed and Drinking Water of Animals; Chromium Propionate

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Final rule.

SUMMARY:
The Food and Drug Administration (FDA, we, or the Agency) is amending the regulations for food additives permitted in feed and drinking water of animals to provide for the safe use of chromium propionate as a source of chromium in broiler chicken feed. This action is in response to a food additive petition filed by Kemin Industries, Inc.

DATES:
This rule is effective June 3, 2016. Submit either written or electronic objections and requests for a hearing by July 5, 2016. See section V of this document for information on the filing of objections.

ADDRESSES:
You may submit comments or written objections and a request for a hearing as follows:

Electronic Submissions
Submit electronic comments/objections in the following way:
• Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments. Comments/objections submitted electronically, including attachments, to http://www.regulations.gov will be posted to the docket unchanged. Because your comment/objection will be made public, you are solely responsible for ensuring that your comment/objection does not include any confidential information that you or a third party may not wish to be posted, such as medical information, your or anyone else's Social Security number, or confidential business information, such as a manufacturing process. Please note that if you include your name, contact information, or other information that identifies you in the body of your comments/objection, that information will be posted on http://www.regulations.gov.
• If you want to submit a comment/objection with confidential information that you do not wish to be made available to the public, submit the comment/objection as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).

Written/Paper Submissions
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments/objections submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
Instructions: All submissions received must include the Docket No. FDA-2014-F-0232 for “Food Additives Permitted in Feed and Drinking Water of Animals; Chromium Propionate.” Received comments/objections will be placed in the docket and, except for those submitted as “Confidential Submissions,” publicly viewable at http://www.regulations.gov or at the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.
• Confidential Submissions —To submit a comment/objection with confidential information that you do not wish to be made publicly available, submit your comments/objections only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on http://www.regulations.gov. Submit both copies to the Division of Dockets Management. If you do not wish your name and contact information to be made publicly available, you can provide this information on the cover sheet and not in the body of your comments and you must identify this information as “confidential.” Any information marked as “confidential” will not be disclosed except in accordance with 21 CFR 10.20 and other applicable disclosure law. For more information about FDA's posting of comments to public dockets, see 80 FR 56469, September 18, 2015, or access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm.
Docket: For access to the docket to read background documents or the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in the heading of this document, into the “Search” box and follow the prompts and/or go to the Division of Dockets Management, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852.

FOR FURTHER INFORMATION CONTACT:
Chelsea Trull, Center for Veterinary Medicine, Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855, 240-402-6729, chelsea.trull@fda.hhs.gov.

SUPPLEMENTARY INFORMATION:

I. Background
In a notice published in the Federal Register of March 10, 2014 (79 FR 13263), FDA announced that we had filed a food additive petition (animal use) (FAP 2282) submitted by Kemin Industries, Inc., 2100 Maury St., Des Moines, IA 50317. The petition proposed to amend the food additive regulations to provide for the safe use of chromium propionate as a source of chromium in broiler chicken feed. The notice of petition was subsequently corrected to indicate the submission of an environmental assessment by the petitioner (79 FR 38478, July 8, 2014).

II. Conclusion
FDA concludes that the data establish the safety and utility of chromium propionate for use as proposed and that the food additive regulations should be amended as set forth in this document.

III. Public Disclosure
In accordance with § 571.1(h) (21 CFR 571.1(h)), the petition and documents we considered and relied upon in reaching our decision to approve the petition will be made available for public disclosure (see FOR FURTHER INFORMATION CONTACT ). As provided in § 571.1(h), we will delete from the documents any materials that are not available for public disclosure.

IV. Analysis of Environmental Impact
The Agency has carefully considered the potential environmental impact of this action and has concluded that the action will not have a significant impact on the human environment and that an environmental impact statement is not required. FDA's finding of no significant impact and the evidence supporting that finding, contained in an environmental assessment, may be seen in the Division of Dockets Management (see ADDRESSES ) between 9 a.m. and 4 p.m., Monday through Friday.

V. Objections and Hearing Requests
Any person who will be adversely affected by this regulation may file with the Division of Dockets Management (see ADDRESSES ) either electronic or written objections. Each objection shall be separately numbered, and each numbered objection shall specify with particularity the provision of the regulation to which objection is made and the grounds for the objection. Each numbered objection on which a hearing is requested shall specifically so state. Failure to request a hearing for any particular objection shall constitute a waiver of the right to a hearing on that objection. Each numbered objection for which a hearing is requested shall include a detailed description and analysis of the specific factual information intended to be presented in support of the objection in the event that a hearing is held. Failure to include such a description and analysis for any particular objection shall constitute a waiver of the right to a hearing on the objection.
It is only necessary to send one set of documents. Identify documents with the docket number found in brackets in the heading of this document. Any objections received in response to the regulation may be seen in the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday, and will be posted to the docket at http://www.regulations.gov.

List of Subjects in 21 CFR Part 573
Animal feeds, Food additives.
Therefore, under the Federal Food, Drug, and Cosmetic Act and under authority delegated to the Commissioner of Food and Drugs and redelegated to the Center for Veterinary Medicine, 21 CFR part 573 is amended as follows:

PART 573—FOOD ADDITIVES PERMITTED IN FEED AND DRINKING WATER OF ANIMALS
1. The authority citation for part 573 continues to read as follows:

Authority:
21 U.S.C. 321, 342, 348.
2. Add § 573.304 to read as follows:
§ 573.304
Chromium Propionate.
The food additive chromium propionate may be safely used in animal feed as a source of supplemental chromium in accordance with the following prescribed conditions:
(a) The additive is manufactured by the reaction of a chromium salt with propionic acid, at an appropriate stoichiometric ratio, to produce triaqua-(mu 3 -oxo) hexakis (mu 2 -propionato- O,O ′) trichromium propionate with the empirical formula, [Cr 3 (O)(CH 3 CH 2 CO 2 ) 6 (H 2 O) 3 ]CH 3 CH 2 CO 2 .
(b) The additive shall be incorporated at a level not to exceed 0.2 milligrams of chromium from chromium propionate per kilogram feed in broiler chicken complete feed.
(c) The additive meets the following specifications:
(1) Total chromium content, 8 to 10 percent.
(2) Hexavalent chromium content, less than 2 parts per million.
(3) Arsenic, less than 1 part per million.
(4) Cadmium, less than 1 part per million.
(5) Lead, less than 0.5 part per million.
(6) Mercury, less than 0.5 part per million.
(7) Viscosity, not more than 2,000 centipoise.
(d) The additive shall be incorporated into feed as follows:
(1) It shall be incorporated into each ton of complete feed by adding no less than one pound of a premix containing no more than 181.4 milligrams of added chromium from chromium propionate per pound.
(2) The premix manufacturer shall follow good manufacturing practices in the production of chromium propionate premixes. Inventory, production, and distribution records must provide a complete and accurate history of product production.
(3) Chromium from all sources of supplemental chromium cannot exceed 0.2 parts per million of the complete feed.
(e) To assure safe use of the additive in addition to the other information required by the Federal Food, Drug, and Cosmetic Act:
(1) The label and labeling of the additive, any feed premix, and complete feed shall contain the name of the additive.
(2) The label and labeling of the additive and any feed premix shall also contain:
(i) A guarantee for added chromium content.
(ii) Adequate directions for use and cautions for use including this statement: Caution: Follow label directions. Chromium from all sources of supplemental chromium cannot exceed 0.2 parts per million of the complete feed.
Dated: May 26, 2016.
Tracey Forfa,

Acting Director, Center for Veterinary Medicine.
DEPARTMENT OF STATE
22 CFR Parts 120, 123, 124, 125, and 126
[Public Notice: 9487]
RIN 1400-AD70
International Traffic in Arms: Revisions to Definition of Export and Related Definitions

AGENCY:
Department of State.

ACTION:
Interim final rule.

SUMMARY:
As part of the President's Export Control Reform (ECR) initiative, the Department of State amends the International Traffic in Arms Regulations (ITAR) to update the definitions of “export,” and “reexport or retransfer” in order to continue the process of harmonizing the definitions with the corresponding terms in the Export Administration Regulations (EAR), to the extent appropriate. Additionally, the Department creates definitions of “release” and “retransfer” in order to clarify and support the interpretation of the revised definitions that are in this rulemaking. The Department creates new sections of the ITAR detailing the scope of licenses, unauthorized releases of controlled information and revises the section on “exports” of technical data to U.S. persons abroad. Finally, the Department consolidates regulatory provisions on the treatment of foreign dual and third country national employees within one exemption.

DATES:
The rule is effective on September 1, 2016. The Department of State will accept comments on this interim final rule until July 5, 2016.

ADDRESSES:
Interested parties may submit comments within 30 days of the date of publication by one of the following methods:
• Email:
DDTCPublicComments@state.gov with the subject line, “ITAR Amendment—Final Revisions to Definitions.”
• Internet: At www.regulations.gov, search for this notice by using this rule's RIN (1400-AD70).
Comments received after that date may be considered, but consideration cannot be assured. Those submitting comments should not include any personally identifying information they do not desire to be made public or information for which a claim of confidentiality is asserted because those comments and/or transmittal emails will be made available for public inspection and copying after the close of the comment period via the Directorate of Defense Trade Controls Web site at www.pmddtc.state.gov. Parties who wish to comment anonymously may do so by submitting their comments via www.regulations.gov, leaving the fields that would identify the commenter blank and including no identifying information in the comment itself. Comments submitted via www.regulations.gov are immediately available for public inspection.

FOR FURTHER INFORMATION CONTACT:
Mr. C. Edward Peartree, Director, Office of Defense Trade Controls Policy, Department of State, telephone (202) 663-1282; email DDTCResponseTeam@state.gov. ATTN: ITAR Amendment—Revisions to Definitions. The Department of State's full retrospective plan can be accessed at http://www.state.gov/documents/organization/181028.pdf.

SUPPLEMENTARY INFORMATION:
The Directorate of Defense Trade Controls (DDTC), U.S. Department of State, administers the International Traffic in Arms Regulations (ITAR) (22 CFR parts 120 through 130). The items subject to the jurisdiction of the ITAR, i.e., defense articles and defense services, are identified on the ITAR's U.S. Munitions List (USML) (22 CFR 121.1). With few exceptions, items not subject to the export control jurisdiction of the ITAR are subject to the jurisdiction of the Export Administration Regulations (“EAR,” 15 CFR parts 730 through 774, which includes the Commerce Control List (CCL) in Supplement No. 1 to part 774), administered by the Bureau of Industry and Security (BIS), U.S. Department of Commerce. Both the ITAR and the EAR create license requirements for exports and reexports of controlled items. Items not subject to the ITAR or to the exclusive licensing jurisdiction of any other set of regulations are subject to the EAR.
BIS is concurrently publishing amendments (BIS companion rule) to definitions, including “export,” “reexport,” “release,” and “transfer (in-country)” in the EAR.

Changes in This Rule
The following changes are made to the ITAR with this interim final rule: (i) Revisions to the definitions for “export” and “reexport or retransfer;” (ii) new definitions for “release” and “retransfer;” (iii) new sections of the ITAR detailing the scope of licenses, unauthorized releases of information; (iv) revisions to the section on “exports” of technical data to U.S. persons abroad; and (v) consolidates §§ 124.16 and 126.18 within one exemption. The remaining definitions published in the June 3, 2015 proposed rule (80 FR 31525), will be the subject of separate rulemakings and the public comments on those definitions will be addressed therein.
The Department received several public comments that address the rule as a whole. These comments are addressed here. Comments on a specific definition or other proposed change are addressed below in the relevant section of the rule.
Several commenters replied to DDTC's request for public comments on the effective date described in the proposed rule, suggesting dates ranging from 60 to 180 days. Some commenters also requested that the rule be published as an interim final rule to allow additional public comments. The Department partially accepts these comments. The Department determined that the changes to definitions and additional definitions included in this rule can be implemented with minimal impact on the export control management systems. However, the Department agrees that additional public comment on all aspects of this rule may be beneficial. Therefore, the rule will be effective 90 days from publication, with a public comment period of 30 days to allow the Department to make any necessary improvements to the rule prior to it becoming effective.
One commenter suggested that the Department place all terms defined within the ITAR in quotations marks, as is done in the EAR. The Department does not accept this comment. The Department has determined that the addition of quotation marks will not enhance the readability of the ITAR.
Several commenters noted that the revised and new definitions in the proposed rule created layered definitions, where exporters must understand multiple definitions of words used within a definition. The Department recognizes that the new definitions require additional study of the new regulations.
One commenter suggested that the Department harmonize § 126.1 with the list of restricted destinations under the EAR, specifically Crimea. The Department does not accept this comment. The imposition of a license requirement under the EAR is not the same as a presumption of denial for exports to a destination listed under § 126.1. All defense articles require authorization from the Department for “export” or “reexport” to, or “retransfer” within, Ukraine and Russia, and all applications are processed consistent with U.S. government policy.
One commenter requested that the Department adopt an intra-company transfer exception, authorizing exports and reexports between company facilities in different destinations. This suggestion is outside the scope of the rulemaking and the Department does not accept the comment.

1. Export Definition Revised
The Department revises the definition of “export” in § 120.17 to better align with the EAR's revised definition of the term and to remove activities associated with the further movement of a defense article or its “release” outside the United States, which now fall within the definition of “reexport” in § 120.19 or “retransfer” in § 120.51. The definition is revised to explicitly identify that §§ 126.16 and 126.17 (exemptions pursuant to the Australia and United Kingdom Defense Trade Cooperation Treaties) have their own definitions of “export,” which apply exclusively to those exemptions.
Although the wording of paragraph (a)(1) of this section has changed, the scope of the control is the same. Paragraph (a)(2) includes the control listed in the former paragraph (a)(4) (transfer of technical data to a foreign person). Paragraph (a)(3) includes the control listed in the former paragraph (a)(2) (transfer of registration, control, or ownership to a foreign person of an aircraft, vessel, or satellite). Paragraph (a)(4) includes the control listed in the former paragraph (a)(3) (transfer in the United States to foreign embassies). Paragraph (a)(5) maintains the control on performing a defense service. Paragraph (a)(6) is retained from the existing text to continue to advise exporters that the launch of a launch vehicle or payload does not constitute an export, but may involve a defense service. Paragraph (b) is added to clarify that disclosing technical data to a foreign person in the United States is deemed to be an “export” to all countries in which the foreign person holds or has held citizenship or holds permanent residency.
In response to public comments, the Department revised proposed paragraph (a)(4) to clarify that it is the “release” or transfer to an embassy or one of its agencies or subdivisions that is the activity of concern. This includes transfers to employees of an embassy or other foreign persons who will take the defense article to an embassy.
The Department also removed proposed paragraphs (a)(6) and (7). Proposed paragraph (a)(6) is no longer necessary, and the Department will address controls on encrypted technical data in a separate rulemaking. Proposed paragraph (a)(7) will also be addressed in a separate rulemaking, and until such time, the existing ITAR controls remain in place.
One commenter suggested that the Department adopt the definition of “export” that was in the EAR, which states “[e]xport means an actual shipment or transmission of items out of the United States,” and state that the other activities identified in § 120.17 are “subject to the regulations in the same manner and with the same effect as an export.” The Department does not accept this comment. All of the activities identified in this section are an “export.”
Several commenters stated that the definition of “export” is too broad, as individuals may share information that they do not believe to be technical data and accidentally violate the ITAR. The Department does not accept this comment. For information to be ITAR-controlled, it must be directly related to a defense article or specifically enumerated on the USML, and not satisfy one of the exclusions in § 120.10(b).
One commenter suggested that the Department revise paragraphs (a)(1) and (2) so that (a)(1) includes only hardware exports and (a)(2) includes all technical data exports, whether to a foreign person in the United States or to someone in another country. The Department does not accept this comment. A major purpose of this rule is to harmonize the ITAR with the EAR, and the Department determined it would better align the definition of “export” by adopting the EAR's framework of including one paragraph for an “export” that moves a defense article to another country, whether tangible or intangible, and another paragraph that addresses the “export” of technical data to foreign persons in the United States.
One commenter suggested that the changes to paragraph (a)(2), which define transfers to a foreign person in the United States as an “export,” and transfers to a foreign person outside the United States, but within one foreign country, as a “reexport” under § 120.19(a)(2), would preclude a U.S. company from obtaining a DSP-5 to authorize their overseas foreign national employee to receive technical data. The Department does not accept this comment. The sending or taking of technical data out of the United States to a foreign person employee will remain an “export” under paragraph (a)(1).
One commenter requested that the Department exclude software object code from paragraph (a)(2) so that the provision of ITAR-controlled object code to a foreign person is not an “export.” The Department does not accept this comment. Due to the sensitivity of items that remain defense articles following the revisions on the USML through ECR, retaining those items that provide the United States a critical military or intelligence advantage, ITAR control of the “release” of object code that is within the scope of the USML to foreign persons is appropriate.
Several commenters requested that the Department remove the portion of (a)(6) that addressed the provision of physical access to technical data. The Department has removed paragraph (a)(6). However, as described above for paragraph (a)(7), while the act of providing physical access does not constitute an “export,” any release of technical data to a foreign person is an “export,” “reexport,” or “retransfer” and will require authorization from the Department. If a foreign person views or accesses technical data as a result of being provided physical access, then an “export” requiring authorization will have occurred and the person who provided the foreign person with physical access to the technical data is an exporter responsible for ITAR compliance.
A commenter suggested that the Department revise paragraph (b) to state that only the last country of citizenship or permanent residency will be considered for foreign persons, to harmonize with the EAR. The Department does not accept this comment. A main tenet of ECR is that the ITAR will have higher walls around fewer, more sensitive items, and this aspect of the control system is an example of the more stringent controls that the ITAR maintains.
One commenter noted that the preamble to the proposed rule and paragraph (b) are inconsistent because the preamble language was not limited to “releases” in the United States. The Department confirms that a disclosure to a foreign person in the United States is an “export,” while a “release” to a third-country foreign person abroad is a “reexport,” and a “release” to a foreign person within their own country is a “retransfer.” However, all such activities require authorization, and all citizenships held and any permanent residency status must be accounted for in the authorization.
One commenter requested the Department define permanent residency. The Department notes that permanent resident is defined at 8 U.S.C. Chapter 12, Immigration and Nationality, for the purpose of U.S. law. For the purpose of the ITAR related to third-country foreign persons in a foreign country, the Department generally considers the right to reside in the country indefinitely, be employed by an employer in the country, to make unlimited entry and exit to/from the country without a visa, and rights of voting or office holding in making a determination.

2. Reexport Definition Revised
The Department revises the definition of “reexport” in § 120.19 to better align with the EAR's revised definition and describe transfers of items subject to the jurisdiction of the ITAR between two foreign countries. The activities identified are the same as those in paragraphs (a)(1) through (3) of the revised definition of “export,” except that the shipment, “release,” or transfer is between two foreign countries or is to a third country national foreign person outside of the United States.
One commenter requested that the Department address the implications of § 124.16 and § 126.18 on the control in § 120.19(a)(2). The Department notes that § 120.19(a)(2) does not impose a new license requirement. However, the Department has determined that the authorization that may be requested for an agreement under § 124.16 may be used for any authorization from the Department. Therefore, § 124.16 is converted into an exemption and moved to § 126.18(d).
One commenter requested that the Department state that no “reexport” occurs if an item is moved from one foreign country to another either under the possession of the same end user or by being sent to the same end user. The Department does not accept this comment. Any movement of a defense article between two foreign countries is a “reexport” and requires an authorization. However, an “export” authorization may authorize further “reexport.”

3. Release Definition Added
The Department adds a definition of “release” in § 120.50. This term is added to harmonize with the EAR, which has long used the term to cover activities that disclose information to foreign persons. “Release” includes the activities encompassed within the undefined term “disclose.” The activities that are captured include allowing a foreign person to inspect a defense article in a way that reveals technical data to the foreign person and oral or written exchanges of technical data with a foreign person. The adoption of the definition of “release” does not change the scope of activities that constitute an “export” and other controlled transactions under the ITAR. The word software was removed from the proposed definition of “release” because the Department is not revising the definitions of defense article and technical data at this time, and as such, all ITAR controlled software remains technical data under § 120.10.
Several commenters requested that the Department revise (a)(1) by replacing inspection with examination or “close examination” and state that such inspection or examination must “actually reveal technical data or software” to the foreign person. The Department does not accept this comment. Inspection and examination are synonyms. Adding the modifier “close” may be appropriate in certain circumstances, but other defense articles may not require a close examination for the “release” of technical data to occur. The Department is confident that limiting the control to situations where a visual or other inspection “releases” technical data sets the appropriate scope of control. Additionally, the Department confirms that the information about the defense article must be technical data and not simply attributes, such as size or weight.

4. Retransfer Definition Added
The Department adds a definition of “retransfer” in § 120.51. This interim final rule moves “retransfer” from the definition of “reexport” in § 120.19, better describes the activities being regulated and harmonizes it with the EAR, which controls “exports,” “reexports,” and “transfers (in country)” as discrete events. Under the definition adopted in this interim final rule, a “retransfer” occurs with a change of end use or end user within the same foreign territory. Certain activities may fit within the definition of “reexport” and “retransfer,” such as the disclosure of technical data to a third country national abroad. Authorizations to “reexport” or “retransfer” a defense article are generally issued through the General Correspondence process under § 123.9(c), or by an exemption.
One commenter requested that the Department confirm that the new definition of “retransfer”— i.e., a change in end use or end user—means that authorizations will no longer be required for transfers to subcontractors or intermediate consignees within the same country. The Department does not accept this comment. Providing a defense article to a subcontractor, or any party not explicitly authorized, for additional processing or repair is a change in the end user and end use of the defense article. Such a “retransfer” requires authorization, even if the party is required to return the defense article to the transferor.
One commenter requested that the Department remove “change of end use” from the definition of “retransfer,” asserting that this is an expansion of the scope of activities controlled under the ITAR. The commenter alternatively requested that the Department confirm that the party responsible for any violation due to change in end use is the ultimate consignee. The Department does not accept these comments. Change in end use is within the prior definition of reexport/retransfer that was in § 120.19. An ultimate consignee may also contact the Department to obtain authorization for a change in end use under § 123.9(c). If a violation does occur, the Department will assess responsibility pursuant to its civil enforcement authority based on the relative culpability of all of the parties to the transaction. (See, e.g., § 127.1(c)).

5. Exemption for the Export of Technical Data to or for U.S. Persons Abroad Revised
The Department revises § 125.4(b)(9) to better harmonize controls on the “release” of controlled information to U.S. persons abroad and to update the provisions of this section. The most significant updates are that foreign persons authorized to receive technical data in the United States will be eligible to receive that same technical data abroad, when on temporary assignment on behalf of their employer, and that the exemption will now authorize a “reexport” or “retransfer” as well. The revisions also clarify that a person travelling abroad may use this exemption to “export” technical data for their own use abroad. In all events, the technical data must be secured while abroad to prevent unauthorized “release.”
In response to public comments, the Department includes the ability to use this exception to authorize “reexports” and “retransfers,” in addition to “exports.” The Department also revises the introductory text from the proposed text to clarify that the requirement that a person be travelling or on temporary assignment abroad only applies to foreign person employees, maintaining the current scope of the exemption for U.S. persons. Further, the Department removes the additional proposed recordkeeping requirement, as the Department has determined that the recordkeeping requirements in § 123.26 applicable to all exemptions are sufficient.
One commenter noted that the data security provisions appear to be wholly within the control of the person abroad, and not the exporter, at least in instances where the exporter is not also the person abroad. The Department agrees that the person in possession of the technical data abroad will have the primary responsibility for ensuring that the technical data is adequately secured, consistent with paragraph (b)(9)(ii). As with all “exports,” however, the exporter is responsible for ITAR compliance and must, prior to using the exemption, be confident that the person abroad is aware of the requirement and will properly implement the necessary security.
One commenter requested that the Department remove the reference to “encryption of the technical data” from the security provision in subparagraph (ii). The Department partially accepts this comment. Subparagraph (ii) requires that sufficient security precautions be taken and has been revised to clarify that the list of security precautions is exemplary.
One commenter requested that the Department explicitly state that technical data stored on servers in the United States may be accessed by a U.S. person in a foreign country through a secure/encrypted connection, using this exemption. The Department confirms that a U.S. person or authorized foreign person may access technical data in the United States from abroad using a secure connection. This activity constitutes an “export” of the technical data because it is sent to the foreign country, even if only as a transient or temporary document in electronic storage, and such export may be authorized by this exemption.
One commenter requested that the Department include foreign subsidiaries and affiliates of U.S. companies in paragraph (b)(9), so long as the foreign subsidiary or affiliate is authorized to receive the technical data. The Department does not accept this comment. If an authorization exists that allows a foreign subsidiary or affiliate access to technical data, that authorization is an authorization to “export” that technical data to its employees within the approved territory. If the employees are outside of approved territory, they are not authorized to receive the technical data.
One commenter requested that the Department clarify whether a party who followed DDTC guidance in direct conflict with the National Industrial Security Program Operating Manual (NISPOM), as provided by subparagraph (v), would be at risk of violating the NISPOM. The Department notes that the Secretary of State has the authority to impose different conditions on “exports” apart from those imposed by the Department of Defense, as noted in 71 FR 20534, 20535 (April 21, 2006), and that this paragraph is not being revised by the current rulemaking.
One commenter requested that the Department clarify whether a U.S. person sending or taking technical data overseas on an encrypted device for his personal use or use by another U.S. person is engaged in an “export.” As noted above, the Department will address the proposed § 120.52(a)(4) in a separate rulemaking.
One commenter requested that the Department insert a note cross-referencing to § 120.52 for other options for sending information to persons abroad. As noted above, the Department will address the proposed § 120.52 in a separate rulemaking.
One commenter stated that this section implies that technical data sent to a foreign country in compliance with the proposed § 120.52(a)(4) is an “export.” As noted above, the Department will address the proposed § 120.52 in a separate rulemaking.

6. Scope of License Added
The Department adds § 123.28 and § 124.1(e) to clarify the scope of a license, in the absence of a proviso, and to state that authorizations are granted based on the information provided by the applicant. This means that while providing false information to the U.S. government as part of the application process for the “export,” “reexport,” or “retransfer” of a defense article or the performance of a defense service is a violation of the ITAR ( see § 127.2(a)), the Department may also deny, revoke, suspend, or amend the license under § 126.7(a) as a result of the false information.
One commenter suggested that the Department not adopt these sections, as an exporter could identify a defense article, end user, or end use in the supporting documentation for a license application that the Department did not intend to authorize in the license itself. The Department does not accept this comment. The Department reviews all information submitted by an applicant and includes provisos to condition the scope of the authorization to the defense articles, parties, and end uses that are intended to be authorized.

Request for Comments
The Department invites public comment on any of the definitions set forth in this rulemaking.

Regulatory Findings

Administrative Procedure Act
The Department of State is of the opinion that controlling the import and export of defense articles and services is a foreign affairs function of the U. S. government and that rules implementing this function are exempt from sections 553 (rulemaking) and 554 (adjudications) of the Administrative Procedure Act (APA). Although the Department is of the opinion that this rulemaking is exempt from the rulemaking provisions of the APA, the Department is publishing this rule with a 30-day provision for public comment and without prejudice to its determination that controlling the import and export of defense articles and defense services is a foreign affairs function.

Regulatory Flexibility Act
Since the Department is of the opinion that this rulemaking is exempt from the rulemaking provisions of 5 U.S.C. 553, there is no requirement for an analysis under the Regulatory Flexibility Act.

Unfunded Mandates Reform Act of 1995
This rulemaking does not involve a mandate that will result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or more in any year and it will not significantly or uniquely affect small governments. Therefore, no actions were deemed necessary under the provisions of the Unfunded Mandates Reform Act of 1995.

Small Business Regulatory Enforcement Fairness Act of 1996
For purposes of the Small Business Regulatory Enforcement Fairness Act of 1996 (the “Act”), a major rule is a rule that the Administrator of the OMB Office of Information and Regulatory Affairs finds has resulted or is likely to result in: (1) An annual effect on the economy of $100,000,000 or more; (2) a major increase in costs or prices for consumers, individual industries, federal, state, or local government agencies, or geographic regions; or (3) significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based enterprises to compete with foreign-based enterprises in domestic and foreign markets.
The Department does not believe this rulemaking will have an annual effect on the economy of $100,000,000 or more, nor will it result in a major increase in costs or prices for consumers, individual industries, federal, state, or local government agencies, or geographic regions, or have significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based enterprises to compete with foreign-based enterprises in domestic and foreign markets. The proposed means of solving the issue of data protection are both familiar to and extensively used by the affected public in protecting sensitive information.

Executive Orders 12372 and 13132
This rulemaking 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. Therefore, in accordance with Executive Order 13132, it is determined that this rulemaking does not have sufficient federalism implications to require consultations or warrant the preparation of a federalism summary impact statement. The regulations implementing Executive Order 12372 regarding intergovernmental consultation on Federal programs and activities do not apply to this rulemaking.

Executive Orders 12866 and 13563
Executive Orders 12866 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, distributed impacts, and equity). The executive orders stress the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rulemaking has been designated a “significant regulatory action,” although not economically significant, under section 3(f) of Executive Order 12866. Accordingly, the rulemaking has been reviewed by the Office of Management and Budget (OMB).

Executive Order 12988
The Department of State has reviewed the rulemaking in light of sections 3(a) and 3(b)(2) of Executive Order 12988 to eliminate ambiguity, minimize litigation, establish clear legal standards, and reduce burden.

Executive Order 13175
The Department of State has determined that this rulemaking will not have tribal implications, will not impose substantial direct compliance costs on Indian tribal governments, and will not preempt tribal law. Accordingly, Executive Order 13175 does not apply to this rulemaking.

Paperwork Reduction Act
This rulemaking does not impose any new reporting or recordkeeping requirements subject to the Paperwork Reduction Act, 44 U.S.C. Chapter 35; however, the Department of State seeks public comment on any unforeseen potential for increased burden.

List of Subjects
22 CFR 120 and 125
Arms and munitions, Classified information, Exports.
22 CFR 123
Arms and munitions, Exports, Reporting and recordkeeping requirements.
22 CFR Part 124
Arms and munitions, Exports, Technical assistance.
22 CFR 126
Arms and munitions, Exports.
Accordingly, for the reasons set forth above, title 22, chapter I, subchapter M, parts 120, 123, 124, 125, and 126 are amended as follows:

PART 120—PURPOSE AND DEFINITIONS
1. The authority citation for part 120 continues to read as follows:

Authority:
Secs. 2, 38, and 71, Pub. L. 90-629, 90 Stat. 744 (22 U.S.C. 2752, 2778, 2797); 22 U.S.C. 2794; 22 U.S.C. 2651a; Pub. L. 105-261, 112 Stat. 1920; Pub. L. 111-266; Section 1261, Pub. L. 112-239; E.O. 13637, 78 FR 16129.
2. Section 120.17 is revised to read as follows:
§ 120.17
Export.
(a) Except as set forth in § 126.16 or § 126.17, export means:
(1) An actual shipment or transmission out of the United States, including the sending or taking of a defense article out of the United States in any manner;
(2) Releasing or otherwise transferring technical data to a foreign person in the United States (a “deemed export”);
(3) Transferring registration, control, or ownership of any aircraft, vessel, or satellite subject to the ITAR by a U.S. person to a foreign person;
(4) Releasing or otherwise transferring a defense article to an embassy or to any of its agencies or subdivisions, such as a diplomatic mission or consulate, in the United States;
(5) Performing a defense service on behalf of, or for the benefit of, a foreign person, whether in the United States or abroad; or
(6) A launch vehicle or payload shall not, by reason of the launching of such vehicle, be considered an export for purposes of this subchapter. However, for certain limited purposes (see § 126.1 of this subchapter), the controls of this subchapter may apply to any sale, transfer or proposal to sell or transfer defense articles or defense services.
(b) Any release in the United States of technical data to a foreign person is deemed to be an export to all countries in which the foreign person has held or holds citizenship or holds permanent residency.
3. Section 120.19 is revised to read as follows:
§ 120.19
Reexport.
(a) Reexport means:
(1) An actual shipment or transmission of a defense article from one foreign country to another foreign country, including the sending or taking of a defense article to or from such countries in any manner;
(2) Releasing or otherwise transferring technical data to a foreign person who is a citizen or permanent resident of a country other than the foreign country where the release or transfer takes place (a “deemed reexport”); or
(3) Transferring registration, control, or ownership of any aircraft, vessel, or satellite subject to the ITAR between foreign persons.
(b) Any release outside the United States of technical data to a foreign person is deemed to be a reexport to all countries in which the foreign person has held or holds citizenship or holds permanent residency.
4. Section 120.50 is added to read as follows:
§ 120.50
Release.
(a) Technical data is released through:
(1) Visual or other inspection by foreign persons of a defense article that reveals technical data to a foreign person; or
(2) Oral or written exchanges with foreign persons of technical data in the United States or abroad.
(b) [Reserved]
5. Section 120.51 is added to read as follows:
§ 120.51
Retransfer.
A retransfer is a change in end use or end user of a defense article within the same foreign country.

PART 123—LICENSES FOR THE EXPORT AND TEMPORARY IMPORT OF DEFENSE ARTICLES
6. The authority citation for part 123 continues to read as follows:

Authority:
Secs. 2, 38, and 71, 90, 90 Stat. 744 (22 U.S.C. 2752, 2778, 2797); 22 U.S.C. 2753; 22 U.S.C. 2651a; 22 U.S.C. 2776; Pub. L. 105-261, 112 Stat. 1920; Sec. 1205(a), Pub. L. 107-228; Section 1261, Pub. L. 112-239; E.O. 13637, 78 FR 16129.
7. Section 123.28 is added to read as follows:
§ 123.28
Scope of a license.
Unless limited by a condition set out in a license, the export, reexport, retransfer, or temporary import authorized by a license is for the item(s), end-use(s), and parties described in the license application and any letters of explanation. DDTC grants licenses in reliance on representations the applicant made in or submitted in connection with the license application, letters of explanation, and other documents submitted.

PART 124—AGREEMENTS, OFF-SHORE PROCUREMENT, AND OTHER DEFENSE SERVICES
8. The authority citation for part 124 continues to read as follows:

Authority:
Secs. 2, 38, and 71, 90, 90 Stat. 744 (22 U.S.C. 2752, 2778, 2797); 22 U.S.C. 2651a; 22 U.S.C. 2776; Section 1514, Pub. L. 105-261; Pub. L. 111-266; Section 1261, Pub. L. 112-239; E.O. 13637, 78 FR 16129.
9. Section 124.1 is amended by adding paragraph (e) to read as follows:
§ 124.1
Manufacturing license agreements and technical assistance agreements.
* * * * *
(e) Unless limited by a condition set out in an agreement, the export, reexport, retransfer, or temporary import authorized by a license is for the item(s), end-use(s), and parties described in the agreement, license, and any letters of explanation. DDTC approves agreements and grants licenses in reliance on representations the applicant made in or submitted in connection with the agreement, letters of explanation, and other documents submitted.
§ 124.8
[Amended]
10. Section 124.8 is amended by removing “§§ 124.16 and 126.18” and adding “§ 126.18” in its place in paragraph (5).
§ 124.12
[Amended]
11. Section 124.12 is amended by removing paragraph (a)(10).
§ 124.16
[Removed and Reserved]
12. Section 124.16 is removed and reserved.

PART 125—LICENSES FOR THE EXPORT OF TECHNICAL DATA AND CLASSIFIED DEFENSE ARTICLES
13. The authority citation for part 125 continues to read as follows:

Authority:
Secs. 2 and 38, 90, 90 Stat. 744 (22 U.S.C. 2752, 2778); 22 U.S.C. 2651a; E.O. 13637, 78 FR 16129.
14. Section 125.4 is amended by revising paragraph (b)(9) to read as follows:
§ 125.4
Exemptions of general applicability.
* * * * *
(b) * * *
(9) Technical data, including classified information, regardless of media or format, exported, reexported, or retransferred by or to a U.S. person, or a foreign person employee of a U.S. person travelling or on temporary assignment abroad, subject to the following restrictions:
(i) Foreign persons may only export, reexport, retransfer, or receive such technical data as they are authorized to receive through a separate license or other approval.
(ii) The technical data exported, reexported, or retransferred under this authorization may only be possessed or used by a U.S. person or authorized foreign person. Sufficient security precautions must be taken to prevent the unauthorized release of the technical data. Such security precautions may include encryption of the technical data; the use of secure network connections, such as virtual private networks; the use of passwords or other access restrictions on the electronic device or media on which the technical data is stored; and the use of firewalls and other network security measures to prevent unauthorized access.
(iii) The individual is an employee of the U.S. government or is directly employed by a U.S. person and not by a foreign subsidiary.
(iv) Technical data authorized under this exception may not be used for foreign production purposes or for defense services unless authorized through a license or other separate approval.
(v) Classified information is sent or taken outside the United States in accordance with the requirements of the Department of Defense National Industrial Security Program Operating Manual (unless such requirements are in direct conflict with guidance provided by the Directorate of Defense Trade Controls, in which case such guidance must be followed).
* * * * *

PART 126—GENERAL POLICIES AND PROVISIONS
15. The authority citation for part 126 continues to read as follows:

Authority:
Secs. 2, 38, 40, 42, and 71, Pub. L. 90-629, 90 Stat. 744 (22 U.S.C. 2752, 2778, 2780, 2791, and 2797); 22 U.S.C. 2651a; 22 U.S.C. 287c; E.O. 12918, 59 FR 28205; 3 CFR, 1994 Comp., p. 899; Sec. 1225, Pub. L. 108-375; Sec. 7089, Pub. L. 111-117; Pub. L. 111-266; Sections 7045 and 7046, Pub. L. 112-74; E.O. 13637, 78 FR 16129.
16. Section 126.18 is amended by removing “§ 124.16” in paragraph (a) and adding “paragraph (d) of this section” in its place, and adding paragraph (d).
The addition reads as follows:
§ 126.18
Exemptions regarding intra-company, intra-organization, and intra-governmental transfers to employees who are dual nationals or third-country nationals.
* * * * *
(d) Notwithstanding any other provisions of this subchapter, no approval is needed from the Directorate of Defense Trade Controls (DDTC) for the reexport of unclassified defense articles or defense services to individuals who are dual national or third-country national employees of a foreign business entity, foreign governmental entity, or international organization, that is an authorized end-user, foreign signatory, or consignee (including approved sub-licensees) for those defense articles or defense services, when such individuals are:
(1) Bona fide regular employees directly employed by the foreign business entity, foreign governmental entity, or international organization;
(2) Nationals exclusively of countries that are members of NATO, the European Union, Australia, Japan, New Zealand, or Switzerland;
(3) Within the physical territories of the countries listed in paragraph (d)(2) of this section or the United States during the reexport;
(4) Signatory to a Non-Disclosure Agreement, unless their employer is a signatory or sublicensee to an agreement under § 124.1 authorizing those defense articles or defense services; and
(5) Not the recipient of any permanent transfer of hardware.
Dated: May 23, 2016.
Rose E. Gottemoeller,

Under Secretary, Arms Control and International Security, Department of State.
DEPARTMENT OF HOMELAND SECURITY
Coast Guard
33 CFR Part 100
[Docket Number USCG-2016-0385]
RIN 1625-AA08
Special Local Regulation; Tri-City Water Follies Spring Testing, Kennewick, WA

AGENCY:
Coast Guard, DHS.

ACTION:
Temporary interim rule; request for comments.

SUMMARY:
The Coast Guard is establishing a Special Local Regulation for all navigable waters within the Columbia River in the vicinity of Columbia Park, commencing at the Interstate 395 Bridge and continuing up river approximately 2.0 miles and terminating at the northern end of Wade Island, during the Tri-City Water Follies Spring Testing event. The special local regulation is needed to protect personnel, vessels, and the marine environment from potential hazards created by high-speed watercraft. Entry of vessels or persons into this area is prohibited unless specifically authorized by the Captain of the Port Columbia River or his designated representative.

DATES:
This rule is effective from June 3, 2016 through June 10, 2016 at 6 p.m. This rule will be enforced from June 10, 2016 at 7 a.m. through June 10, 2016 at 6 p.m. Comments and related material must be received by the Coast Guard on or before July 5, 2016.

ADDRESSES:
To view documents mentioned in this preamble as being available in the docket, go to http://www.regulations.gov, type USCG-2016-0385 in the “SEARCH” box and click “SEARCH.” Click on Open Docket Folder on the line associated with this rule. You may submit comments identified by docket number USCG-2016-0385 using the Federal eRulemaking Portal at http://www.regulations.gov. See the “Public Participation and Request for Comments” portion of the SUPPLEMENTARY INFORMATION section for further instructions on submitting comments.

FOR FURTHER INFORMATION CONTACT:
If you have questions on this rule, call or email Mr. Kenneth Lawrenson, Waterways Management Division, Marine Safety Unit Portland, U.S. Coast Guard; telephone 503-240-9319, email msupdxwwm@uscg.mil.

SUPPLEMENTARY INFORMATION:

I. Table of Abbreviations
CFR Code of Federal Regulations
DHS Department of Homeland Security
FR Federal Register
NPRM Notice of proposed rulemaking
§ Section
U.S.C. United States Code

II. Background Information and Regulatory History
The Coast Guard is issuing this temporary rule without prior notice and opportunity to comment pursuant to authority under section 4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This provision authorizes an agency to issue a rule without prior notice and opportunity to comment when the agency for good cause finds that those procedures are “impracticable, unnecessary, or contrary to the public interest.” Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good cause exists for not publishing a Notice of Proposed Rulemaking (NPRM) with respect to this rule because to do so would be impracticable. The NPRM process would be contrary to public interest in this situation due to the extremely hazardous conditions this event could potentially pose if held without an enforceable special local regulation area. Furthermore, the event staff submitted the application for marine event on March 18, 2016, limiting the Coast Guard to two months to complete an NPRM and full comment period, which is the main factor in our decision to forego the NPRM process.
We are issuing this rule, and under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause exists for making it effective less than 30 days after publication in the Federal Register . Delaying the effective date until 30 days after publication would be impracticable, for the reasons stated above.

III. Legal Authority and Need for Rule
The Coast Guard is issuing this rule under authority in 33 U.S.C. 1231. The Captain of the Port Columbia River (COTP) has determined that potential hazards associated with high-speed watercraft will be a safety concern for anyone within Columbia River mile 330 and 332 during the event hours. This rule is needed to protect personnel, vessels, and the marine environment in the navigable waters within the special local regulation area during the event hours.

IV. Discussion of the Rule
This rule establishes a special local regulation area from 7 a.m. to 6 p.m. on June 10, 2016. The special local regulation area will cover all navigable waters within the Columbia River in the vicinity of Columbia Park, commencing at the Interstate 395 Bridge and continuing up river approximately 2.0 miles and terminating at the northern end of Wade Island. The duration of the special local regulation area is intended to protect personnel, vessels, and the marine environment in these navigable waters for the entirety of the Tri-City Water Follies Spring Testing event. No vessel or person will be permitted to enter the special local regulation area specified in this rule without obtaining permission from the COTP or a designated representative.

V. Regulatory Analyses
We developed this rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive orders, and we discuss First Amendment rights of protestors.

A. Regulatory Planning and Review
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, it has not been reviewed by the Office of Management and Budget.
This regulatory action determination is based on the size, location, and duration. The special local regulation for the Tri-City Water Follies Test event will only be effective from 7 a.m. to 6 p.m. on the date of the test event. Furthermore, the Tri-City Water Follies Test event is directly related to the main Tri-City Water Follies Hydroplane racing event which has occurred annually for the last 50 years and is extremely well received in the Kennewick-Pasco-Richland metropolitan area. Moreover, the Coast Guard will issue Broadcast Notice to Mariners via VHF-FM marine channel 16 about the special local regulation area and the rule allows vessels to seek permission from the COTP or his designated representative to enter the area.

B. Impact on Small Entities
The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.
While some owners or operators of vessels intending to transit the safety zone may be small entities, for the reasons stated in section V.A above, this rule will not have a significant economic impact on any vessel owner or operator.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.

C. Collection of Information
This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

D. Federalism and Indian Tribal Governments
A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.
Also, this rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect 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. If you believe this rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section above.

E. Unfunded Mandates Reform Act
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such expenditure, we do discuss the effects of this rule elsewhere in this preamble.

F. Environment
We have analyzed this rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969(42 U.S.C. 4321-4370f), and have determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule involves a Special Local Regulation for a limited access area lasting less than 12 hours that will prohibit vessels from entering an area encompassing Columbia River mile 330 and 332 unless given permission to do so by the Captain of the Port Columbia River or his designated representative. It is categorically excluded from further review under paragraph 34(h) of Figure 2-1 of the Commandant Instruction. An environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under ADDRESSES . We seek any comments or information that may lead to the discovery of a significant environmental impact from this rule.

G. Protest Activities
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places or vessels.

List of Subjects in 33 CFR Part 100
Marine safety, Navigation (water), Reporting and recordkeeping requirements, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 100 as follows:

PART 100—REGATTAS AND MARINE PARADES
1. The authority citation for part 100 continues to read as follows:

Authority:
33 U.S.C. 1233.
2. Add § 100.T13-0385 to read as follows:
§ 100.T13-0385
Special Local Regulation; Tri-City Water Follies Spring Testing, Kennewick, WA.
(a) Regulated area. The following is designated as a special local regulation area:
(1) Location. The special local regulation area covered by this rule will cover all navigable waters within the Columbia River in the vicinity of Columbia Park, commencing at the Interstate 395 Bridge and continuing up river approximately 2.0 miles and terminating at the northern end of Wade Island.
(2) Enforcement period. This special local regulation area is in effect on June 10, 2016 from 7 a.m. to 6 p.m. The rule will be enforced for the duration of the Tri-City Water Follies Spring Testing event. The Coast Guard will inform mariners of any change to this period of enforcement via Broadcast Notice to Mariners.
(b) Regulations. In accordance with the general regulations in 33 CFR part 100, to enter, transit through, anchor in, or remain within the special local regulation area is prohibited unless permission has been authorized by the Captain of the Port or his designated representative.
(1) The following applies to the special local regulation area identified in paragraph (a)(1) of this section.
(i) This special local regulation area is designed to restrict vessel traffic, including all non-motorized vessels, except as may be permitted by the Captain of the Port Columbia River or his designated representative.
(ii) Within this area all vessels will transit at the minimum speed necessary to maintain headway without creating a wake.
(iii) A succession of sharp, short signals by whistle, siren, or horn from vessels patrolling the area under the direction of the U.S. Coast Guard Patrol Commander shall serve as a signal to stop. Vessels signaled shall stop and shall comply with the orders of the patrol vessel personnel; failure to do so may result in expulsion from the area, citation for failure to comply, or both.
(2) [Reserved]
(c) Enforcement. Any Coast Guard commissioned, warrant, or petty officer may enforce the rules in this section. In the navigable waters of the United States to which this section applies, when immediate action is required and representatives of the Coast Guard are not present or are not present in sufficient force to provide effective enforcement of this section, any Federal Law Enforcement Officer or Washington Law Enforcement Officer may enforce the rules contained in this section pursuant to 46 U.S.C. 70118. In addition, the Captain of the Port may be assisted by other federal, state, or local agencies in enforcing this section.
Dated: May 25, 2016.
D.J. Travers,

Captain, U.S. Coast Guard, Captain of the Port, Sector Columbia River.
DEPARTMENT OF HOMELAND SECURITY
Coast Guard
33 CFR Part 165
[Docket Number USCG-2016-0162]
RIN 1625-AA00
Safety Zone; Richland Regatta, Columbia River, Richland, WA

AGENCY:
Coast Guard, DHS.

ACTION:
Temporary final rule.

SUMMARY:
The Coast Guard is establishing a temporary safety zone for certain waters of the Columbia River in the vicinity of Howard Amon Park, Richland, WA, between River Miles 337 and 338, during hydroplane boat races from June 3, 2016, through June 5, 2016. This action is necessary to provide for the safety of life on the navigable waters of the Columbia River during the event. This regulation prohibits persons and vessels from being in the safety zone unless authorized by the Captain of the Port Sector Columbia River or a designated representative.

DATES:
This rule is effective from June 3, 2016, through June 5, 2016. The rule will be enforced from 7 a.m. to 7 p.m. each day it is effective.

ADDRESSES:
To view documents mentioned in this preamble as being available in the docket, go to http://www.regulations.gov, type USCG-2016-0162 in the “SEARCH” box and click “SEARCH.” Click on Open Docket Folder on the line associated with this rule.

FOR FURTHER INFORMATION CONTACT:
If you have questions about this rule, call or email Mr. Ken Lawrenson, Waterways Management Division, MSU Portland, OR, U.S. Coast Guard; telephone 503-240-9319, email msupdxwwm@uscg.mil.

SUPPLEMENTARY INFORMATION:

I. Table of Abbreviations
CFR Code of Federal Regulations
DHS Department of Homeland Security
FR Federal Register
NPRM Notice of proposed rulemaking
§ Section
U.S.C. United States Code

II. Background Information and Regulatory History
On December 21, 2015, the Northwest Power Boat Association notified the Coast Guard that it will be conducting hydroplane boat races from 7 a.m. to 7 p.m. daily from June 3, 2016 through June 5, 2016, as part of the Richland Regatta. The races will be held in the vicinity of Howard Amon Park, Richland, WA. In response, on March 21, 2016, the Coast Guard published a notice of proposed rulemaking (NPRM) titled Safety Zone; Richland Regatta, Columbia River, Richland, WA (81 FR 14998). There we stated why we issued the NPRM, and invited comments on our proposed regulatory action related to this marine event. During the comment period that ended April 20, 2016, we received no comments.
We are issuing this rule, and under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause exists for making it effective less than 30 days after publication in the Federal Register . Due to delays in processing this regulation, it would be impracticable to delay the effective date until 30 days after publication, as this delay would eliminate the safety zone's effectiveness and usefulness in preventing the potential dangers to the public caused by the racing of vessels at high speeds.

III. Legal Authority and Need for Rule
The Coast Guard is issuing this rule under the authority in 33 U.S.C. 1231. The Captain of the Port Columbia River (COTP) has determined that potential hazards associated with the hydroplane races on June 3, 2016, through June 5, 2016, will be a safety concern for all waterway users on the Columbia River between River Miles 337 and 338 during the event. The hydroplane races pose significant dangers to the maritime public including excessive noise, vessels racing at high speeds in proximity to other vessels, and flying debris in the event of an accident. The purpose of this rule is to ensure the safety of vessels and the navigable waters before, during and after the scheduled event.

IV. Discussion of Comments, Changes, and the Rule
As noted above, we received no comments on our NPRM published March 21, 2016. There are no changes in the regulatory text of this rule from the proposed rule in the NPRM.
This rule establishes a safety zone from 7 a.m. to 7 p.m. on June 3, 2016, through June 5, 2016. The safety zone will include all navigable waters of the Columbia River in the vicinity of Howard Amon Park, Richland, WA between River Miles 337 and 338. The duration of the zone is intended to ensure the safety of vessels and these navigable waters during the scheduled hydroplane races. No vessel or person will be permitted to enter, transit through, anchor in, or remain within the regulated area unless authorized by Captain of the Port Sector Columbia River or a designated representative.

V. Regulatory Analyses
We developed this rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize on analyses based on a number of these statutes and Executive orders, and we discuss First Amendment rights of protestors.

A. Regulatory Planning and Review
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, it has not been reviewed by the Office of Management and Budget.
This regulatory action determination is based on the following factors. The safety zone will only be effective for twelve hours daily over a three day period, and while non-participant vessels will be unable to enter, transit through, anchor in, or remain within the event area without authorization from the Captain of the Port Sector Columbia River or a designated representative, they may operate in the surrounding areas during the enforcement period. Additionally, non-participant vessels may still enter, transit through, anchor in, or remain within the event area during the enforcement period if authorized by the COTP Sector Columbia River or a designated representative. The Coast Guard would issue a Broadcast Notice to Mariners via VHF-FM marine channel 16 about the zone.

B. Impact on Small Entities
The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard received no comments from the Small Business Administration on this rulemaking. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule would not have a significant economic impact on a substantial number of small entities.
While some owners or operators of vessels intending to transit the safety zone may be small entities, for the reasons stated in section V.A. above this rule will not have a significant economic impact on any vessel owner or operator.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.

C. Collection of Information
This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

D. Federalism and Indian Tribal Governments
A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.
Also, this rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect 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. If you believe this rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

E. Unfunded Mandates Reform Act
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

F. Environment
We have analyzed this rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule involves a safety zone from 7 a.m. to 7 p.m. daily from June 3, 2016 through June 5, 2016. The safety zone would cover all navigable waters of the Columbia River in the vicinity of Howard Amon Park, Richland, WA. It is categorically excluded from further review under paragraph 34(g) of Figure 2-1 of Commandant Instruction M16475.lD. An environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under ADDRESSES . We seek any comments or information that may lead to the discovery of a significant environmental impact from this rule.

G. Protest Activities
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places, or vessels.

List of Subjects in 33 CFR Part 165
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 165 as follows:

PART 165—REGULATED NAVIGATION AREAS AND LIMITED ACCESS AREAS
1. The authority citation for part 165 continues to read as follows:

Authority:
33 U.S.C. 1231; 50 U.S.C. 191; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Department of Homeland Security Delegation No. 0170.1.
2. Add § 165.T13-0162 to read as follows:
§ 165.T13-0162
Safety Zone; Richland Regatta, Columbia River, Richland, WA.
(a) Regulated area. The following regulated area is a safety zone. The safety zone will include all navigable waters of the Columbia River in the vicinity of Howard Amon Park, Richland, WA, between River Miles 337 and 338.
(b) Definitions. (1) The term “designated representative” means Coast Guard Patrol Commanders, including Coast Guard coxswains, petty officers, and other officers operating Coast Guard vessels, and Federal, state, and local officers designated by or assisting the Captain of the Port Sector Columbia River in the enforcement of the regulated area.
(2) The term “Non-participant persons and vessels” means a vessel or person not participating in the event as a participant, spectator, or event attendee.
(c) Regulations. (1) In accordance with the general regulations in subpart C of this part, non-participant persons and vessels are prohibited from entering, transiting through, anchoring in, or remaining within the regulated area unless authorized by Captain of the Port Sector Columbia River or a designated representative.
(2) Non-participant persons and vessels may request authorization to enter, transit through, anchor in, or remain within the regulated area by contacting the Captain of the Port Sector Columbia River or a designated representative via VHF radio on channel 16. If authorization is granted by the Captain of the Port Sector Columbia River or a designated representative, all persons and vessels receiving such authorization must comply with the instructions of the Captain of the Port Sector Columbia River or a designated representative.
(d) Enforcement period. This safety zone as described in paragraph (a) of this section will be enforced from 7 a.m. to 7 p.m. each day on June 3, 2016, through June 5, 2016.
Dated: May 27, 2016.
D.J. Travers,

Captain, U.S. Coast Guard, Captain of the Port, Sector Columbia River.
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, 70, and 71
[EPA-HQ-OAR-2013-0685; FRL-9946-55-OAR]
RIN 2060-AS06
Source Determination for Certain Emission Units in the Oil and Natural Gas Sector

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
The U.S. Environmental Protection Agency (EPA) is finalizing a revision to regulations applicable to permitting of stationary sources of air pollution under the New Source Review (NSR) and title V programs in the Clean Air Act (CAA or Act). For sources in the oil and natural gas sector, this rule clarifies the meaning of the term “adjacent” that is used to determine the scope of a “stationary source” for purposes of the Prevention of Significant Deterioration (PSD) and Nonattainment NSR (NNSR) preconstruction permitting programs and the scope of a “major source” in the title V operating permit program in the onshore oil and natural gas sector. The revised definitions are based on the proximity of emitting activities and consideration of whether the activities share equipment. We believe that this clarification will provide greater certainty for the regulated community and for permitting authorities, and will result in more consistent determinations of the scope of a source in this sector. The EPA is adopting this revised definition in the regulations that apply to permits issued by the EPA and states to which the EPA has delegated federal authority to administer these programs. Other state and local permitting authorities with EPA-approved programs may also revise their permit programs to adopt this definition, but are not required to do so.

DATES:
This final rule is effective on August 2, 2016.

ADDRESSES:
The EPA has established a docket for this action under Docket ID No. EPA-2060-2013-0685. All documents in the docket are listed on the http://www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., Confidential Business Information 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 electronically through http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:
For further general information on this rulemaking, contact Ms. Cheryl Vetter, Office of Air Quality Planning and Standards (C504-03), U.S. Environmental Protection Agency, by phone at (919) 541-4391, or by email at vetter.cheryl@epa.gov; or Mr. Greg Nizich, Office of Air Quality Planning and Standards (C504-03), U.S. Environmental Protection Agency, by phone at (919) 54l-3078, or by email at nizich.greg@epa.gov.

SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?
Entities potentially affected directly by this final action include owners or operators of sources of new and modified operations within the oil and natural gas production and processing segments of the oil and gas sector (herein after referred to as “oil and natural gas operations”). Such entities are expected to be in the groups indicated in the following table. In addition, state, local and tribal governments may be affected by the rule if they update state rules to adopt the changes being made to federal permit program rules.
Industry group | NAICS code ^1
Oil and Gas Extraction | 21111.
Crude Petroleum and Natural Gas Extraction | 211111.
Natural Gas Liquid Extraction | 211112.
Drilling Oil and Gas Wells | 213111.
Support Activities for Oil and Gas | 213112.
Federal Government | May Be Affected.
State/Local/Tribal Government | May Be Affected.

B. Where can I get a copy of this document and other related information?
In addition to being available in the docket, an electronic copy of this document will be posted at: http://www3.epa.gov/airquality/oilandgas/actions.html. Upon its publication in the Federal Register , only the published version may be considered the final official version of the notice, and will govern in the case of any discrepancies between the Federal Register published version and any other version.
^1 North American Industry Classification System (NAICS). The table refers to the more commonly used NAICS code. However, the four-digit SIC codes was the only code system in use at the time our rules were developed. This classification system has since been replaced by the six-digit NAICS, which was developed with Canada and Mexico, and is used for classifying North American businesses. While the SIC codes are no longer updated, the United States Department of Labor's Occupational Safety and Health Administration still mains the list of SIC codes for references. We have retained the SIC codes in the regulation.

C. How is this document organized?
The information presented in this document is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related information?
C. How is this document organized?
II. Background for Final Rulemaking
III. Summary of the Final Rule Requirements
IV. Responses to Significant Comments on the Proposed Rule
A. General Comments
B. Comments on Option 1
C. Comments on Option 2
D. Implementation Issues
V. Environmental Justice Considerations
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and 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
J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations
K. Congressional Review Act (CRA)
L. Judicial Review
Statutory Authority

II. Background for Final Rulemaking
This action affects the determination of what constitutes a “stationary source” for the PSD and NNSR preconstruction permit programs under title I of the CAA, and the determination what constitutes a “major source” for the title V operating permit program. Under the PSD and NNSR programs, a “stationary source” is defined as a “building, structure, facility, or installation” that emits or may emit a “regulated NSR pollutant.” ^2 40 CFR 51.165(a)(1)(i), 51.166(b)(5). In turn, a “building, structure, facility, or installation” is defined as “all of the pollutant-emitting activities” that satisfy three prongs: they “belong to the same industrial grouping”; “are located on one or more contiguous or adjacent properties”; and “are under the control of the same person (or persons under common control).” 40 CFR 51.165(a)(1)(ii); 51.166(b)(6). Under the title V program, “stationary source” is defined similarly, but with reference to a different set of pollutants; however, the term “building, structure, facility, or installation” is not defined. Instead, the same three-prong test is incorporated into the definition of “major source.” 40 CFR 70.2; 71.2. We ^3 use the term “source determination” to describe a case-specific examination of particular pollutant-emitting activities to see whether, under the definitions just discussed, they are collectively a “stationary source” for purposes of the PSD or NNSR programs or are potentially (depending on their level of emissions) a “major source” for the purposes of the title V program.
^2 The term “regulated NSR pollutant” is defined differently for the two programs, consistent with their separate purposes. 40 CFR 51.165(a)(1); 51.166(b)(49).
^3 In this preamble, the term “we” and “our” refers to the EPA.
On September 18, 2015, the EPA proposed two options for clarifying the meaning of the term “adjacent” in the second prong discussed in the previous paragraph as applied to oil and gas sources, under both the preconstruction and operating permits programs. Source Determination for Certain Emission Units in the Oil and Natural Gas Sector. See 80 FR 56579, September 18. 2015. The preamble to the proposal provided a discussion of the history of making source determinations generally, and for these segments specifically, the previous guidance we have issued and the litigation that resulted. We explained our rationale for the two options we proposed for clarifying the term “adjacent” as it is used in determining the scope of a source for purposes of air permitting for these segments. The EPA's preferred option, referred to as Option 1, would have required permitting authorities to aggregate, for permitting purposes, all onshore oil and natural gas emitting equipment ^4 that are within the two-digit Standard Industrial Classification (SIC) code 13 ^5 (hereafter referred to as “oil and natural gas operations”), are under common control of a single person (or persons under common control), and that are located within 1/4 mile of each other. We believed that establishing a “bright line” based on the proximity of the equipment (in this case, 1/4 mile), as several oil and gas-producing states seemed to have done, would simplify permitting because it would avoid a more detailed case-by-case evaluation based on the relationship of the emitting equipment. We also proposed a second option, Option 2, which would have aggregated all emitting equipment within 1/4 mile but would also have allowed permitting authorities to aggregate emitting equipment located beyond 1/4 mile based on the relationship between the operations. The EPA described this relationship as “exclusive functional interrelatedness,” but requested comment on more specific ways to describe a relationship that meets the common sense notion of a plant. Finally, we requested comment on whether some combination of these two options might be preferable. This final rulemaking notice does not repeat all of the discussion, but refers interested readers to the preamble of the proposed rule for additional background.
^4 Within this document the terms “emitting equipment” and “emitting activities” are used interchangeably.
^5 The description for Major Group 13: Oil and Gas Extraction can be found at https://www.osha.gov/pls/imis/sic_manual.display?id=8&tab=group. This major group includes establishments primarily engaged in: (1) Producing crude petroleum and natural gas; (21 extracting oil from oil sands and oil shale; (3) producing natural gasoline and cycle condensate; and (4) producing gas and hydrocarbon liquids from coal at the mine site. Types of activities included are exploration, drilling, oil and gas well operation and maintenance, the operation of natural gasoline and cycle plants, and the gasification, liquefaction, and pyrolysis of coal at the mine site. This major group also includes such basic activities as emulsion breaking and desilting of crude petroleum in the preparation of oil and gas customarily done at the field site. Pipeline transportation of petroleum, gasoline, and other petroleum products (except crude petroleum field gathering lines) is classified in Transportation and Public Utilities, Major Group 46, and of natural gas in Major Group 49.

III. Summary of the Final Rule Requirements
This section provides a brief summary of the requirements of the final rule. Further discussion of the basis for these requirements and summaries of our responses to significant comments are provided in the next section.
Based on the range and substance of the comments received, the EPA has made two revisions to the proposed definition of “adjacent” that are reflected in the final rule. As discussed in the proposal, we proposed that pollutant-emitting activities from onshore oil and natural gas operations that are located on the same “surface site,” as defined in 40 CFR 63.761, ^6 or on surface sites located within 1/4 mile of each other, would be considered “adjacent” for purposes of determining the source. We selected 1/4 mile as a “bright line” distance for clarifying the meaning of “adjacent” based on proximity to be consistent with those states that also use a “bright line” approach as a way of delineating sources in this category. This also was, in our view, a reasonable distance within which sources in oil and natural gas operations are likely to be interconnected. However, we received comments from several entities that said that we misunderstood the states' approach. According to them, several states that use the 1/4 mile boundary do not aggregate everything within it, as we proposed. Rather they use the 1/4 mile boundary to define an area beyond which they would not consider pollutant emitting equipment to be adjacent and part of a single source. Within 1/4 mile, these states determine on a case-by-case basis which equipment should be considered a single source because it meets the “common sense notion of a plant.”
^6 40 CFR 63.761 defines surface sites as any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically affixed.
For the reasons discussed more fully later in this notice, we have decided to modify the proposed definition in response to the recommendations made by commenters. As we proposed under both Option 1 and Option 2, emitting equipment in the oil and natural gas production and processing segments located at a single onshore surface site will be considered “adjacent” under the final rule and, thus, part of a single stationary source, assuming the equipment is also under the control of one person (or persons under common control) and belongs to the two-digit SIC code 13. Also, as we proposed in Option 1, we are finalizing a definition that equipment on separate surface sites located more than 1/4 mile apart is not “adjacent” and, therefore, is not part of the same stationary source. However, in this final rule, we are modifying Option 1 by incorporating an element from Option 2 and the state policies on which we modeled Option 1. Specifically, we would not require that all emitting equipment located on separate surface sites within 1/4 mile of each other be considered “adjacent.” Instead, emitting equipment located on separate surface sites within 1/4 mile of each other would only be aggregated as a single stationary source if the emitting equipment also have a relationship that meets the “common sense notion of a plant.”
This expression, the “common sense notion of a plant,” has been a criterion by which we have made source determinations for sources in all industries since our PSD rules were revised in 1980 (45 FR 52676, August 7, 1980) in response to the D.C. Circuit Court of Appeals Alabama Power decision. Alabama Power Co. v. Costle, 636 F. 2d 323, 397 (D.C. Cir. 1979). In the onshore oil and natural gas production and processing segments, the “plant” is not as easy to discern as it is for other industrial operations, such as an electric utility generating plant or an oil refinery. Unlike these industrial operations, onshore oil and natural gas operations may not have an obvious boundary and may be located on property owned and controlled by others.
As explained in our proposal, one way in which we historically have evaluated whether activities meet the common sense notion of a plant was through the use of “functional interrelatedness” or “operational dependence.” See 80 FR 56581, September 18. 2015. Our proposed Option 2 would have looked for “exclusive functional interrelatedness” of emitting equipment outside the 1/4 mile radius. See 80 FR 56587, September 18. 2015. We asked for comment on whether we should further define “exclusive functional interrelatedness” to give additional clarity to regulators and the regulated community.
Rather than looking for “functional interrelatedness” in oil and natural gas operations and giving this term more specific definition, we have decided in this final rule that it is preferable to look for “shared equipment” to determine when emitting activities in oil and natural gas operations have a relationship that meets the “common sense notion of a plant.” The EPA has applied the generalized notion of “functional interrelatedness” in other ways in other source categories, in some cases, at the request of the source. However, for oil and natural gas operations, we find it preferable to use a term that will give a more precise and clear criterion for defining when emitting activities within a 1/4 mile proximity are sufficiently related to be considered adjacent, in line with the objectives of the proposal.
For onshore oil and natural gas production, this final rule establishes that, where separate surface sites located within 1/4 mile of each other include shared equipment necessary to process or store oil or natural gas, these surface sites will be aggregated. The EPA has concluded that equipment satisfying these criteria will meet the common sense notion of a plant. Under this final rule, separate surface sites that do not include shared emitting equipment, even if within 1/4 mile, will not be aggregated.
For example, an owner or operator proposing to construct a new well site should draw a 1/4 mile circle from the center of the proposed new well site. If there is commonly-controlled emitting equipment located within that 1/4 mile circle and within major SIC code 13, and that equipment is used to process or store the oil, natural gas or the byproducts of production that will come from the new well site, then the emissions from that equipment should be included in determining whether the new well site is a major source. Examples of shared equipment include, but are not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. In this example, the shared equipment is necessary for the operation of the new well site, and should be considered part of the same source because together all of the equipment operates as a “plant.” However, under the terms of this rule, we would not consider two well sites that feed to a common pipeline to be part of the same stationary source if they do not share any processing or storage equipment between them.
We believe this change from the proposed rule is responsive to both the comments that we received from several states about the burden of aggregating individual surface sites, and from the industry about the independent nature of many, if not most, surface sites.
We proposed to clarify the meaning of “adjacent” in all of the permitting rules, both the rules that apply to the EPA and delegated states as the permitting authority, as well as the rules that apply to state, local or tribal permitting authorities. However, we requested comment on whether we should require state, local and tribal permitting authorities to make this proposed change to their regulations. Several states, including both those with oil and natural gas operations and those without, expressed a desire to retain their existing approach to source determinations in permitting. These states, particularly those with oil and natural gas operations, expressed concern about the increased burden of the EPA's proposed Option 1. After reviewing the comments, the EPA has decided to adopt this change in its permitting rules, but to not require state, local and tribal permitting authorities to adopt this change. However, if they choose to do so, state, local and tribal permitting authorities may adopt the EPA's revised definition and submit their revised program to the EPA for approval.

IV. Responses to Significant Comments on the Proposed Rule
The EPA received more than 19,000 comments on the proposed rule. In this section we summarize the major comments and our responses. For details of all the significant comments and our responses, please refer to the Response to Comments document in the docket for this rulemaking.

A. General Comments

1. Need for Clear Guidance

a. Summary of Proposal
In the proposed rule, the EPA described the history and the current status of making source determinations for onshore oil and natural gas operations. We described the guidance that had been issued, the source determinations that have been made and the lack of clarity that has often resulted. We proposed two options for clarifying the term “adjacent” when making source determinations for onshore oil and natural gas operations.

b. Brief Summary of Comments
Several commenters stated that providing clear and reasonable definitions in rulemaking would benefit the regulated community, regulators and other stakeholders by providing needed certainty. The current lack of clarity, according to commenters, has resulted in increased costs due to permitting delays and litigation following the issuance of a permit. Several commenters also supported our decision to provide this clarification through rulemaking, rather than by additional guidance.
Other commenters did not believe that a rulemaking is necessary. These commenters stated that the rulemaking is not necessary because the term “adjacent” is unambiguous, that it is synonymous with “contiguous,” i.e., that “adjacent' means touching, sharing a border, or abutting. These commenters pointed to the dictionary definition of the word “adjacent” as being “contiguous.” Some of these commenters went on to say that the meaning of the term “adjacent” has been clearly established in relevant case law, citing Summit Petroleum Corp. v. EPA, 690 F.3d 733, 742 (6th Cir. 2012). And some commenters questioned our authority to adopt the two meanings of the term that we proposed, claiming that the proposed definitions violated the D.C. Circuit Court of Appeals' holdings in Alabama Power or that the EPA simply lacked authority to define the term “adjacent” in a way that, according to commenters, conflicted with the dictionary definition and/or the decision of the Sixth Circuit Court of Appeals in Summit Petroleum.

c. EPA Response
We agree with the commenters who stated that a rulemaking is the best way to provide clarity in permitting. However, we recognize that most permits are issued by states, and that some states have substantial experience in making source determinations for oil and natural gas operations. Accordingly, in recognition of this state expertise, and in response to many comments, we are making the meaning of “adjacent” adopted in this rule mandatory only for the permit programs administered by the EPA or delegated states, while leaving to other states the decision of whether to make a similar change to their approved permitting.
We disagree with commenters who claim that the EPA lacks authority to define adjacent by regulation or that state the rulemaking is unnecessary because of the dictionary meaning of “adjacent” and the Summit Petroleum decision. These commenters are mistaken that the EPA cannot define “adjacent” by rule to mean all emitting equipment within a specified radius. ^7 Commenters gave two reasons for this: first, that to do so would not comport with Alabama Power, and second, that the EPA's authority to give a meaning to “adjacent” that varies from its dictionary definition is foreclosed by the Summit Petroleum decision.
^7 Although we are not finalizing an option (such as our proposed Option 2) that would potentially include emitting activities outside a 1/4 mile radius, commenters are also mistaken (for similar reasons) in asserting that we could not have finalized such an option.
Regarding the first point, the CAA affords the EPA discretion in the permitting context to provide a more specific meaning to the term “stationary source” that is used in the Act. See, Chevron USA, Inc. v. NRDC, 467 U.S. 837 (1984) (discussing the meaning of the term stationary source under the CAA). Through a rulemaking process, we are defining the statutory term “stationary source” for a particular context: the PSD, NNSR and title V programs as applied to oil and natural gas operations. The definition of the term “stationary source” in section 302(z) of the Act, the related definition in section 111(a)(3), the structure of the Act, and its legislative history do not supply a clear meaning of “stationary source” in this context. Thus, it is permissible for the agency, in a rulemaking process, to apply a reasonable interpretation of the statute that resolves an ambiguity. ^8 It is also permissible for the EPA to create a rule using a “bright line,” as we are doing here, for purposes of better administering the Act, see Emily's List v. Fed. Election Comm'n, 581 F.3d 1, 22 n.20 (D.C. Cir. 2002).
^8 In fact, the Supreme Court in Chevron reversed the D.C. Circuit Court of Appeals' judgment that the EPA had impermissibly interpreted “stationary source,” stating that the Circuit Court erred by “read[ing] the statute inflexibly” and not deferring to the EPA's reasonable interpretation.
As to the second point, while the Summit Petroleum decision is a motivating factor for this action, the decision, and the Court's reference to the dictionary meaning of “adjacent” in that decision, are not preclusive of our authority to take the action. The Summit Petroleum Court addressed the issue of whether, in the absence of a rule defining the term “adjacent,” the EPA had permissibly interpreted the term in a particular source determination. The Court looked to the dictionary definition of “adjacent” to determine whether the EPA's interpretation of this term would “permit the agency, under the guise of interpreting a regulation, to create de facto a new regulation.” Summit Petroleum, 690 F.3d at 740 (quoting Christensen v. Harris Cnty., 529 U.S. 576, 588 (2000)). In this rulemaking action, the EPA is not interpreting the term “adjacent” in the existing regulation; instead we are assigning a meaning to the term by going through a rulemaking process. When an agency is defining a word by rule, the agency is free to give specialized meaning to the word without being bound to hew precisely to a particular dictionary definition. See Stenberg v. Carhart, 530 U.S. 914, 942 (2000) (noting that an “explicit definition” can permissibly “vary from the term's ordinary meaning”). And in fact, the PSD regulations in 40 CFR 51.166 are replete with such specialized meanings, for example in the definitions of “significant” and “process unit.” ^9
^9 For similar reasons, comments that cite case law about agency interpretations of statutes and that refer to the dictionary definition of “adjacent” are off target: the statutory term we are interpreting is “stationary source” (and the related definition in section 111(a)(3)), not “adjacent.” We are defining the term “adjacent” in order to give meaning to our reasonable interpretation of the statutory term “stationary source.”
Even if commenters were correct—and they are not—that the EPA is bound by a particular dictionary definition of “adjacent” when defining the term for specialized use, commenters are mistaken about the meaning of the term. While many dictionary definitions of “adjacent” include “contiguous” as one definition, this is not the only definition of the word “adjacent.” For example, one online dictionary defines “adjacent” to mean “lying near, close, or contiguous; adjoining; neighboring.” ^{10} Another dictionary provides the following “Synonym Discussion of Adjacent”: “Adjacent may or may not imply contact but always implies absence of anything of the same kind in between . . .” ^{11} This dictionary makes a further distinction in its “Synonym Discussion”, stating that the word “adjoining” definitely implies meeting and touching at some point or line.” ^{12} So, while we agree that “adjacent” can mean contiguous, we do not agree that it unambiguously must. We are finalizing this rule to provide a bright line distance beyond which pollutant-emitting operations in the onshore oil and natural gas production and processing segments are not considered “adjacent.” The decision to use both words “contiguous” and “adjacent” in our PSD rules was a deliberate choice, designed to include emitting equipment that is on property that is touching (contiguous) with equipment that may not be contiguous, but still meets the common sense notion of a plant. Had we intended “adjacent” to mean exactly the same as “contiguous,” we would not have included the word “adjacent.”
^{10} Dictionary.com http://dictionary.reference.com/browse/adjacent?s=t accessed February 22, 2016.
^{11} Thus, two surface sites separated by 1/4 mile may be “adjacent,” if there is no surface site in between them.
^{12} Merriam-Webster Dictionary, http://www.merriam-webster.com/dictionary/adjacent accessed February 22, 2016.
Finally, we disagree with commenters who argue the Summit Petroleum Court provided sufficient guidance on the meaning of “adjacent” to obviate the need for this rulemaking. The Court's decision is binding only in the Sixth Circuit, which leaves the issue unresolved elsewhere. ^{13} The Court also did not provide guidance on how “nearby” sources must be to consider them “adjacent” for purposes of permitting. This is the question that we have taken up in this rulemaking, specific to onshore oil and natural gas operations. We have clarified that “adjacent” for these segments means within 1/4 mile and having shared equipment.
^{13} While the D.C. Circuit Court of Appeals has held that the EPA is bound by our regional consistency regulations, the Court also suggested that we could revise them in order “to account for regional variances created by a judicial decision or circuit splits.” Nat'l Envt'l Dev. Ass'n's Clean Air Proj. v. EPA, 752 F.3d 999, 1010 (D.C. Cir. 2014). We have proposed to do so. 80 FR 63935 (October 22, 2015).

B. Comments on Option 1

1. Support for Option 1

a. Summary of Proposal
In Option 1, the EPA proposed that the meaning of “adjacent,” for purposes of determining the scope of a source in the oil and natural gas production and processing segments, should be based solely on the distance between pollutant emitting activities. Under this option, emitting equipment at a single surface site would be considered to be adjacent, and emitting equipment at two or more surface sites would be considered “adjacent” if they are located within 1/4 mile of each other. We stated in the proposal that we believed this option to be the most consistent with the “common sense notion of a plant.” We chose the distance, 1/4 mile, because it is the distance we found in permitting guidance issued by a number of oil and natural gas producing states. The EPA also considered this distance reasonable to use for the types of equipment used in this industry.

b. Brief Summary of Comments
Several commenters supported Option 1 as written. These commenters preferred Option 1 over Option 2 because they believed it is the least ambiguous and reflects the plain meaning of the word “adjacent.” One commenter stated that this approach would streamline the determination of the scope of a “stationary source” and would reduce the time it takes to get a permit.
Other commenters, while supporting Option 1 over Option 2, recommended revisions to Option 1. Many of these commenters offered different distances within which emitting equipment or operations should be considered one source. The suggested distances ranged from a requirement that operations be physically touching or abutting to be considered “adjacent” to distances of up to one mile.
Finally, many state and industry commenters recommended a particular revision to Option 1. These commenters recommended that the EPA consider emitting activities located on separate surface sites within 1/4 mile to be adjacent only if they also meet the “common sense notion of a plant” that the EPA has used since 1980 when determining the scope of a source for permitting purposes. Two state commenters told us that while their state has guidance that includes 1/4 mile as the distance for determining the source, they do not use the distance as a bright line. Rather, they use it as an outer boundary, within which they assess whether emitting equipment should be considered a single source for purposes of permitting, but beyond which they do not consider emitting equipment to be adjacent.

c. EPA Response
We are adopting the approach recommended by several commenters: to require that pollutant-emitting equipment on separate surface sites be considered one source only if the sites are within 1/4 mile of each other and the equipment is considered by the permitting authority to meet the common sense notion of a plant. More specifically, the language in the final rule treats certain oil and gas-related pollutant-emitting activities as a plant based on “shared equipment.” Operations located on the same surface site would continue to be considered part of the same source provided that they are also within the same two-digit SIC code and are under common control of the same person (or persons under common control). While we do not agree with comments that argue that a particular dictionary definition of “adjacent” and/or the Summit Petroleum and Alabama Power decisions compel this outcome, we agree with the comments that this approach better achieves the purpose of the rule: to reduce permitting burdens, as explained later in this notice.

2. Do Not Support Option 1

a. Brief Summary of Comments
Some commenters did not support Option 1. One concern raised was that, while the Option 1 approach would streamline permitting, it would not provide sufficient flexibility to consider and address local air quality concerns. Other commenters were concerned that the Option 1 approach would result in the aggregation of sources that should not be treated as one source. Another commenter was concerned that the Option 1 approach would allow the oil and gas industry to avoid major source regulation under the CAA. This commenter went on to say that Option 1 would not approximate a “common sense notion of a plant” or fit within the ordinary meaning of facility or installation as used in the definition of source.

b. EPA Response
In response to concerns raised by commenters about the need for permitting authorities to be able to address local air quality concerns, we are not requiring that EPA-approved state and local programs adopt the approach that the EPA is finalizing for permits issued by the EPA and delegated states. This will allow state and local permitting authorities with EPA-approved programs to continue to use their discretion to make source determinations for this industry in the manner that they believe best addresses their local air quality concerns. For example, those local programs in California that have a long history of permitting oil and natural gas operations on contiguous leases as single sources under their approved programs will be able to continue to do so, without having to submit an equivalency demonstration showing that their programs are at least as stringent as the program adopted by the EPA. Because the EPA is not requiring states with approved programs to apply our meaning of the term “adjacent,” and our rule changes make clear that for approved programs this change is optional, these approved programs already comply with our PSD, NNSR and title V rules, without these changes. States also remain free to adopt more stringent requirements in order to address local air quality concerns.
Those states that administer PSD permitting programs under a delegation of federal authority by the EPA will have to follow the approach that we are finalizing, or develop their own permitting programs and have them approved by the EPA as a revision to a state implementation plan (SIP). We did not receive adverse comments regarding delegated PSD programs having to use this approach. Those state and local programs that are approved, not delegated, that incorporate the EPA's program by reference, may incorporate the definition of “adjacent” for onshore oil and natural gas operations in 40 CFR 52.21(b)(6)(ii), and/or 40 CFR appendix S to part 51; or they may specifically exclude this paragraph from their incorporation when they next update it.
There may be state and local governments with approved programs that wish to clarify the meaning of adjacent for oil and natural gas operations, as the EPA has done in its own permitting rules. Those state and local governments would be able to do so, but would not be required to do so on any particular schedule. We believe, after careful review of the comments received, that this approach offers the best resolution for the lack of clarity that has existed for this industry, particularly when we have been the permitting authority, but does not increase the burden on approved states by requiring them to revise their permitting programs (or to develop an equivalency demonstration) and submit the changes to us as SIP revisions.

3. Response to the EPA's Question on the Appropriate Distance

a. Summary of Proposal
We requested comments on whether some distance other than the proposed 1/4 mile would be a more appropriate distance within which emitting equipment should be considered “adjacent.” See 80 FR 56579, September 18, 2015.

b. Brief Summary of Comments
Commenters provided a range of responses to this question, ranging from 44 feet, which the commenter said was consistent with guidance from the Bureau of Land Management, to one mile, which the commenter suggested is consistent with the largest manufacturing plant that is considered one source. Other commenters recommended that a “city block” be used as the basis for determining the sources. However, these commenters did not agree on the dimensions of a city block. Other suggestions included distances based on the size of the lease, or some combination of leases, and a distance based on the well spacing in a particular field or state.

c. EPA Response
The EPA is retaining the proposed 1/4 mile distance in the final rule. This distance was originally selected to be consistent with those states that also use a specific distance. In addition, as commenters mention, it is a commonly-used distance in oil and gas development for well spacing. Well spacing is typically set by a state agency such as an oil and gas conservation commission, and is intended to develop the oil and gas resource fairly and efficiently. One-quarter of a mile corresponds to a 40-acre lease. We think that a variable distance, such as one based on an individual lease or combination of leases held by an entity would complicate permitting, contrary to the purpose of this rule. And, while a city block might have some meaning in an urban area, we were not persuaded that it has any more meaning than 1/4 mile in the areas where the majority of oil and natural gas development is taking place.

4. Response to the EPA's Question on “Daisy Chaining”

a. Summary of Proposal
We requested comments on whether sources within 1/4 mile of each other should be “daisy chained.” We described a series of emissions units as being “daisy chained” when each individual emitting unit is located within 1/4 mile of the next unit, but where the last unit is separated from the first unit by a much larger distance. See 80 FR 56587, September 18, 2015.

b. Brief Summary of Comments
Most commenters expressed opposition to “daisy chaining.” Commenters were concerned that by “daisy chaining” emitting equipment, sources could extend for dozens of miles, or could even bring in equipment connected by a pipeline which would be inconsistent with the EPA's previous statements on source in the 1980 PSD rule preamble. In that rule, we stated that we did not intend “stationary source” to encompass activities that would be many miles apart along a long line operation (45 FR 52676, August 7, 1980).

c. EPA Response
After reviewing the comments we received, the EPA has determined that “daisy chaining” of emitting equipment would not provide the additional clarity that we seek through this rulemaking. We agree with commenters who said it could extend sources over many miles, perhaps even into the jurisdiction of multiple permitting authorities and in some instances beyond any common sense notion of a plant. This would increase the permitting burden for federal, state, local and tribal permitting authorities but we do not believe that it would provide additional air quality benefits beyond those that will occur as a result of the emission controls provided under the various New Source Performance Standards (NSPS), National Emission Standards for Hazardous Air Pollutants (NESHAP), and state and federal minor source programs, as explained later in this notice. We are, therefore, not adopting a requirement to include “daisy chained” equipment as part of a single source.
To illustrate how we intend this process to work in order to avoid “daisy chaining”, we provide the following example. On surface site “A”, there is an existing collection of equipment consisting of several tanks, a pump jack, a heater-treater and a flare. The owner/operator of site A decides to drill a new well within 1/4 mile of site A, called site “B.” Site B feeds its produced water to the tanks on site A. Site B must consider the emissions from site A in determining whether site B is a major source because sites A and B are part of the same stationary source. At a later date, the same owner/operator decides to drill a third well, “C,” within 1/4 mile of site B but more than 1/4 mile from site A. Sites C and B do not share any equipment. Therefore, site C is a single stationary source. Site C is not included with sites A and B (just because of proximity to B), and, therefore, there is no daisy chain created. If site C feeds material to the storage tanks at site A, then it would still not be considered part of the stationary source that includes site A, because it is located more than 1/4 mile away from site A.
Now, assume that the same owner/operator drills a fourth well, “D,” within 1/4 mile of site A, but more than 1/4 mile from sites B and C. Site D will also feed its produced water to site A. Site D must be treated as a modification to the source that is made up of sites A and B. In this case, site A may be viewed as a “hub” and sites B and D are the spokes. The new source consists of sites A, B and D because sites B and D are within 1/4 mile of the site at which the shared equipment exists. However, site C is not part of this source because site C is more than 1/4 from the surface site with which it shares equipment. New sites would not be included within the source that includes sites A, B and D if they were beyond 1/4 mile, so there would be no daisy chain.
We believe that the permitting authority can make these source determinations, on a case-by-case basis, based on the clarifications that the EPA has provided. We do not believe that it is possible to eliminate all case-by-case source determinations. However, we believe we have provided sufficient guidance to ensure that such determinations are made consistently, and with more certainty for both permitting authorities and sources.

5. Response to the EPA's Question on What To Use as the Starting Point for Measuring the Radius of the Source

a. Summary of Proposal
We requested comment on whether to use the edge or some other feature of the oil or natural gas operation as the starting point of the 1/4 mile measurement radius when determining the source.

b. Brief Summary of Comments
Commenters generally supported defining the point from which the distance between pollutant-emitting equipment is measured. However, there was disagreement on whether the center of the emitting equipment or the property boundary should be used. Several state commenters recommended that the property boundary be the starting point for determining the distance between operations because this distance is most relevant for purposes of air quality. However several commenters in the oil and gas industry recommended that the geographic center of the site for purposes of establishing the 1/4 mile distance, because property boundaries may be difficult to determine. Unlike sites in other industries, oil and natural gas operations frequently do not have fences, so the property boundaries are not always easily distinguished. Emitting equipment, such as may be found at a well site, can be and often is easily identified by Global Positioning System coordinates.

c. EPA Response
The EPA has decided to establish the 1/4 mile boundary from the center of the equipment at the new or modified source for construction permits. At an oil or natural gas well, that may be the wellhead; on a surface site, it should be established from the center of the emitting activities. We believe the center of the emitting activities is the easiest to establish for purposes of permitting, and the easiest to observe for purposes of enforcement. This best achieves our goal of providing greater clarity for permitting authorities and permittees, improving permitting, compliance and enforcement. For title V permits, the center of the equipment on each surface site(s) being permitted should be used.

6. Permitting Burden Under Option 1

a. Summary of Proposal
We requested comment on whether the potentially smaller scope of each source could result in an unacceptable permitting burden by creating a larger number of smaller sources.

b. Brief Summary of Comments
Several state commenters expressed concern that Option 1, as proposed, would increase the administrative burden of issuing permits. This is primarily because they believe that the proposed requirement to aggregate emitting equipment within 1/4 mile would require them to reassess prior source determinations. This is particularly a concern when wells change ownership. The commenters stated that each transaction would require permitting authorities to reanalyze one or more previously-permitted sources to determine which equipment should be included in the source after the purchase or sale. Another commenter stated that while they expect an increase in minor source permitting under the EPA's proposed Option 1, they already have in place a number of streamlining options, such as general permits, which expedite regulatory timelines.

c. EPA Response
As discussed in Section IV.D.3 in this document, this rule will apply prospectively and will not require a reassessment of permits that have been completed. Furthermore, the EPA has revised the approach to source determination in the final rule to address concerns about burden raised by commenters. Instead of requiring that all activities within a 1/4 mile radius be aggregated, the EPA would instead only aggregate those activities within a 1/4 mile radius that share equipment. In many cases, this would result in the wells being permitted separately, reducing the administrative burden of transferring or modifying permits when wells change ownership. In addition, the EPA is not requiring that state, local, and tribal permitting authorities adopt the approach being finalized by us, so those permitting authorities that are concerned there would be an increased burden from our approach (which we do not expect) would not have to follow it.
We believe that the overall effect of this rule will be to reduce the permitting burden for permits issued by the EPA. The permitting burden for state, local and tribal permitting will differ depending on whether those permitting authorities choose to adopt these changes, and will depend on how any revised procedures differ from their current permitting practices. In some jurisdictions, the burden may be unchanged, either because the permitting authority chooses not to adopt the changes, or because the changes the EPA is finalizing do not substantially differ from the permitting authority's current practices.

7. Environmental Impact of Option 1

a. Summary of Proposal
We requested comment on whether there would be adverse air quality impacts, including effects on National Ambient Air Quality Standard (NAAQS) compliance, as a result of Option 1.

b. Brief Summary of Comments
One commenter expressed concern that the EPA's proposal would adversely affect the environment because it would encourage development of oil and gas resources over a larger area in order to avoid being within 1/4 mile. This would increase the footprint of operations, and have an adverse impact on landowners and communities. Other commenters stated that the aggregation of oil and gas operations would not result in environmental benefits because the emissions are already controlled by multiple NSPS and NESHAP standards as well as state minor source permitting programs. Finally, one commenter stated that oil and gas development is the largest industrial source of volatile organic compounds and a significant source of sulfur dioxide and nitrogen oxide pollution in many areas, and that failure to subject these sources to PSD and NNSR would frustrate attempts to ensure NAAQS compliance.

c. EPA Response
The EPA is finalizing several rules applicable to oil and natural gas operations, including an NSPS that will require pollution controls for oil well completions, equipment leaks and pneumatic controllers, among others, and a control techniques guideline (CTG) that will similarly define presumptive controls for the CAA's reasonably available control technology (RACT) requirements for certain areas. The additional emissions control requirements of the NSPS (and the CTG when adopted in RACT SIPs) make it less likely that these sources will be major sources, with or without the meaning of “adjacent” that we are adopting in this rule. This is because the threshold for permitting is based on the potential-to-emit of the source and the potential-to-emit may be reduced by enforceable limitations, such as those imposed by the NSPS. These restrictions, along with enforceable restrictions imposed by the states, reduce both the actual and potential emissions of the sources, reducing the likelihood that they will trigger major NSR or title V permitting. These control requirements will also ensure that new and modified operations emit substantially less air pollution which would contribute to local air quality. To the extent that NSPS requirements for these sources are insufficient to protect the NAAQS in attainment or unclassifiable areas—which we do not expect—the federal or state minor NSR program is intended to address that issue. For nonattainment areas, if the CTG presumptive controls are not sufficient to attain the NAAQS, then other emission reductions will be required in order to attain the standards.
We do not believe that this final rule is likely to result in decisions by companies to locate farther apart to avoid major source permitting. We believe that the location of the underground mineral assets, advances in drilling technology that allow multiple wells to be drilled from one surface site, restrictions on well spacing imposed by a state agency such as an oil and gas conservation commission, and the restrictions imposed by the owner of the surface land are more likely to affect siting decisions than a desire to avoid major source permitting. As discussed earlier in this document, we believe the combined effect of the emission control standards already in place and the additional controls now being finalized is that fewer oil and natural gas operations will be major.

C. Comments on Option 2

1. Support for Option 2

a. Summary of Proposal
In Option 2, the EPA proposed that all equipment within 1/4 mile would be considered a single source and would allow equipment beyond 1/4 mile to be included in the source if it was “exclusively functionally interrelated.” See 80 FR 56579, September 18, 2015.

b. Brief Summary of Comments
Several commenters representing permitting authorities supported Option 2 because they believed that it is the option most similar to the way they make source determinations for this industry and others under their existing, SIP-approved programs.

c. EPA Response
The EPA is not adopting the “functional interrelatedness” criterion in the final rule, but we are incorporating one aspect of Option 2 into the final rule. In addition, the EPA is including its final approach only in the regulations that apply to the EPA and delegated states. This means that the states that prefer to use an approach like Option 2 will be able to continue to do so.

2. Do Not Support Option 2

a. Brief Summary of Comments
Oil and gas industry commenters were uniformly opposed to Option 2. These commenters stated that the use of “functionality” has no support in the CAA, is inconsistent with the plain meaning of the term “adjacent,” and results in sources that do not resemble in any way a “plant.” In addition, they stated that the use of such a test resulted in significant uncertainty because of the subjective nature of the analysis involved in determining which emissions units are part of the source. Several state permitting authority commenters echoed these sentiments and added that the interrelatedness test adds layers of analysis that is not productive. Several commenters expressed concern about the permitting burden of adopting Option 2. Commenters noted that in two cases where the EPA attempted to assess “functional interrelatedness,” the source determinations took several years, were litigated, and ultimately ended in decisions not to aggregate the various surface sites.

b. EPA Response
Because of the difficulty of applying a “functional interrelatedness” criterion to oil and natural gas operations, the EPA is not adopting this criterion as part of the final rule. We do not agree with all of the comments opposed to Option 2, in particular those that stated Option 2 was beyond the EPA's authority, for similar reasons that we disagree with comments that Option 1 was beyond our authority. We do agree with those that stated applying a “functional interrelatedness” criterion by itself would not reduce permitting burdens for oil and natural gas operations to the same degree as a proximity test alone under Option 1. However, because of concerns discussed above with applying a proximity criterion alone, we are combining the proximity criterion in Option 1 with the element of Option 2 that involves considering whether equipment is related in a manner that meets the common sense notion of a plant. Our selected approach combines these elements by limiting aggregation to pollutant emitting equipment within 1/4 mile of each other, but requires that these sources also have shared equipment. We believe that this approach, unlike applying “functional interrelatedness” outside of a specific perimeter, will limit the amount of analysis required for permitting in the oil and natural gas production and processing segments. By providing a clear limit on the distance within which we would require analysis of the relationship of the equipment, we believe permitting will proceed more quickly, and with more certainty for permitting authorities and the regulated community.

3. Environmental Impact Under Option 2

a. Summary of Proposal
We specifically requested comments on whether there might be any environmental harm or benefit resulting from adopting Option 2.

b. Brief Summary of Comments
One state commenter expressed concern that a strict application of the plain meaning of the term “adjacent” could allow oil and gas companies to manipulate their operations to avoid being considered a major source. Another commenter stated that without aggregation, oil and gas operations are subject to widely varying and less stringent standards under state minor source programs. This commenter believes that subjecting these operations to major source permitting would provide substantial public health and environmental benefits. This commenter believes that the emission control provided by the NSPS is not sufficient because it only addresses new or modified equipment and does not cover all equipment or activities encompassed by the industry and does not address local or regional air quality issues.
Other commenters stated that the proposal would have little to no impact on air emissions because the control technology required if equipment is aggregated into major sources will likely be identical to what is required of minor sources. One commenter listed the numerous federal and state standards that already apply to oil and gas sources, regardless of whether the sources are determined to be major or minor, as evidence that the industry is already subject to stringent emissions control requirements.

c. EPA Response
It is important to understand that even if equipment beyond a 1/4 mile distance is aggregated under something like Option 2, only new or modified equipment would be subject to the control requirements of Best Available Control Technology under PSD or Lowest Achievable Emission Rate under the NNSR permitting program. Most new equipment would also be subject to limitations under the NSPS, whether the source is considered major or minor. Emission control requirements under state and federal minor source programs apply in addition to any requirements of the NSPS. These requirements may be more stringent than the NSPS, and in some states apply to new as well as to existing sources. Title V permitting generally does not result in new control requirements, it only compiles the requirements that exist in the underlying standards, such as the NSPS or NESHAP into one permit.
For these reasons, we believe that aggregating equipment into major sources for title V, PSD or NNSR permitting under Option 2 would result in little environmental benefit over the approach adopted today. In our judgement, Option 2 would be more likely to result in delays in permitting and greater uncertainty for the permitting authorities and regulated community alike.

D. Implementation Issues

1. Requirements for States To Adopt

a. Summary of Proposal
We proposed changes to the permitting rules that would have applied both to the EPA, as the permitting authority, to delegated states, and to state, local and tribal permitting authorities. We invited comment on whether states should be required to adopt the proposed changes.

b. Brief Summary of Comments
We received comments from several state and local permitting authorities, including those with and without oil and gas operations, requesting that their programs be allowed to continue to make determinations of “adjacent” on a case-by-case basis without being required to adopt the approach finalized by the EPA. This was particularly true for local programs in California, which have a long history of regulating oil and gas operations. A commenter representing the oil and gas industry operating in California echoed the comment that the existing program should not be disrupted.

c. EPA Response
We agree with commenters who expressed the view that state and local permitting authorities should have the ability to make source determinations under their existing permitting programs. Once their programs are approved by the EPA, state and local governments are given the responsibility to make permitting decisions, and we do not intend any changes in this balance of responsibilities. We, therefore, are adopting these changes in our rules, but not requiring that state and local permitting authorities with approved programs also adopt the new definitions. These permitting authorities may, but are not required to, adopt these definitions, as discussed earlier in this document. This approach has a number of advantages. First, it is responsive to states' concerns that they have much experience making source determinations and they do not see the need to make changes to their existing approach. Second, it would not trigger an obligation for approved states, particularly those states without oil and gas development, to revise their state rules and submit a SIP revision, or to provide a demonstration that their existing rules are of equivalent stringency.
With regard to title V permitting, we are also only adopting these changes in the rules that apply to the EPA and delegated programs. States and local agencies with approved programs may adopt a similar provision in their title V rules at their discretion.

2. Applicability to Other Industries

a. Summary of Proposal
In the proposed rule, we stated that we intended to define “adjacent” only for onshore oil and natural gas operations covered by two-digit SIC Major Group 13, for reasons that are discussed more fully in the preamble to the proposed rule. See 80 FR 56586, September 18, 2015.

b. Brief Summary of Comments
We received comments both asking us to and asking us not to apply the definition developed for oil and natural gas operations to all industries. One state commenter stated that permitting authorities and regulated sources in all categories should be subject to the same definition developed for the oil and natural gas industry. A commenter from an industry outside the oil and natural gas industry asked that the EPA confirm that proximity is the only basis on which the EPA will make determinations of adjacency. We also received comments from the transmission and distribution segments of the oil and natural gas sector requesting that the EPA clarify how this rule applies to these segments of the industry.

c. EPA Response
The EPA did not propose this approach for other industries, and, therefore, we are not finalizing this approach for any industry other than onshore oil and natural gas extraction and production within two-digit SIC Major Group 13. It does not apply to the transmission or distribution of oil or natural gas, which is covered under two-digit SIC Major Group 49. We continue to believe, as we stated in our proposal, that the nature of this industry poses unique challenges for making these source determinations, so this approach is warranted for this industry category. Source determinations for other industries will continue to be made on a case-by-case basis.

3. Applicability to Previously Issued Permits

a. Summary of Proposal
The EPA did not discuss the application of the proposed options to previously issued permits in the preamble to the proposed rule.

b. Brief Summary of Comments
Several commenters stated that any new rule that the EPA adopts should not be applied retroactively. One commenter urged the EPA to both make it clear that new federal language will be implemented only on a prospective basis, but at the same time asked that any previous decisions made to aggregate sources should be subject to new source determinations under the language finally adopted. Another commenter said that with a new definition of an existing term, some previous determinations will be consistent with the new definition, but others will not. This commenter specifically requested that the EPA include anti-backsliding language in the final rule to minimize the impact on previous determinations. In particular, under this rule surface sites that do not share equipment with other surface sites will not be aggregated, which will simplify permit actions when an independent surface site changes ownership.

c. EPA Response
Historically, the EPA's rules are generally adopted on a prospective basis. That is, a new rule applies only after that rule is effective, and is not be applied retroactively to previous actions. This rule is no different. The EPA intends that this rule will be applied from August 2, 2016 forward. Previous source determinations and issued permits, whether sources were aggregated or not, should not be affected by this new definition of “adjacent”.

V. Environmental Justice Considerations
This document is intended to clarify the definition of “adjacent” used to determine the source to be permitted within the existing PSD, NNSR and title V programs as it applies to oil and natural gas operations. This clarification will assist permitting authorities and permit applicants in making source determinations for the oil and natural gas industry, and is not intended to result in less environmental protection for human health and the environment. It is being finalized as a part of a comprehensive strategy to addresses emissions from the oil and natural gas sector which includes new (or lower) emission standards or requirements for a number of types of emitting equipment. As explained earlier in this document and in detail in our response to comments, the EPA does not anticipate that this rule will create a significant issue for attainment and maintenance of the NAAQS. Therefore, the EPA believes this action will not have a disproportionately high and adverse human health or environmental effects on minority populations or low-income populations.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
This action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review because it raises novel policy issues regarding one of the President's priorities. Any changes made in response to OMB recommendations have been documented in the docket.

B. Paperwork Reduction Act (PRA)
This action does not impose any new information collection burden. The OMB has previously approved the information collection requirements contained in the existing regulations for PSD (40 CFR 52.21) and title V (40 CFR parts 70 and 71) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-0003, 2060-0336 and 2060-0243. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. Instead of new information collection burdens, this action finalizes a definition that clarifies the permitting requirements applicable to new and modified oil and natural gas sources. This final action is not likely to increase the burden associated with permitting. It is likely to decrease the burden of permitting for the EPA, when it is the permitting authority. The extent to which it will change the permitting burden for other permitting authorities will depend on whether state or local permitting authorities adopt the changes, and the extent to which these changes are different from the current practice.

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. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if a rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule. This final rule will not impose any additional requirements on small entities. This action clarifies existing requirements, and, by limiting the area in which an oil and gas source's operations must be analyzed for consideration as a single source, limits the burden on the sources and permitting authorities. Entities potentially affected directly by this final rule include state, local and tribal governments and none of these governments are small entities.

D. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or more as described in the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism
This action does not have federalism implications. It 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. The requirement to obtain permits for new major sources is imposed by the CAA. This rule would interpret those requirements as they apply to oil and natural gas operations. Thus, Executive Order 13132 does not apply to these regulation revisions. Finally, the EPA is not requiring that states adopt these changes.

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments
This action does not have tribal implications, as specified in Executive Order 13175. It would not have a substantial direct effect on one or more Indian tribes, since no tribe has developed a Tribal Implementation Plan that allows it to issue NSR permits and, in any case, we are not requiring any permitting authority other than the EPA and delegated states to adopt these changes. Furthermore, this regulation does not affect the relationship or distribution of power and responsibilities between the federal government and Indian tribes. The CAA and the Tribal Air Rule establish the relationship of the federal government and tribes in characterizing air quality and developing plans to attain the NAAQS, and this regulation does nothing to modify that relationship. Thus, Executive Order 13175 does not apply to this action.
Consistent with the EPA Policy on Consultation and Coordination with Indian tribes, the EPA held several meetings with tribal environmental professionals to discuss issues associated with this rule, including a presentation on a National Tribal Air Association policy call on September 10, 2015, and an outreach call to state, local and tribal permitting authorities on September 15, 2015. These meetings discussed several related oil and gas rules, including this Source Determination rule. Summaries of these meetings are included in the docket for this rule.
The EPA also offered consultation during the rulemaking process, but received no requests. The EPA provided an opportunity for tribes and stakeholders to provide written comments on the proposed rule. One tribe did submit comments and these comments are included in the docket for this rule.

G. Executive Order 13045: Protection of Children From Environmental Health and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not directly involve an environmental health risk or safety risk.

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. The EPA is finalizing this clarification to its permitting rules and we believe this action is not likely to have any adverse energy effects because it will not increase, and may decrease, the permitting burden on owners and operators of oil and natural gas sources.

I. National Technology Transfer and Advancement Act
This action does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income or indigenous populations, because it does not affect the level of protection provided to human health or the environment. The results of the evaluation of environmental justice considerations is contained in Section V of this preamble titled, “Environmental Justice Considerations.”

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 is not a “major rule” as defined by 5 U.S.C. 804(2).

L. Judicial Review
Under section 307(b)(1) of the CAA, petitions for judicial review of any nationally applicable regulation, or any action the Administrator “finds and publishes” as based on a determination of nationwide scope or effect must be filed in the United States Court of Appeals for the District of Columbia Circuit within 60 days of the date the promulgation, approval, or action appears in the Federal Register . This action is nationally applicable, as it revises the rules governing all PSD, NNSR and title V programs, in 40 CFR 51.166, 40 CFR 51.165, 40 CFR 52.21, 40 CFR part 70 and 40 CFR part 71. The Administrator also finds that this action is based on a determination of nationwide scope and effect, as it revises the EPA's direct implementation of the PSD and title V programs, which is in effect in multiple Circuits. As a result, petitions for review of this regulation must be filed in the United States Court of Appeals for the District of Columbia Circuit within August 2, 2016. Filing a petition for reconsideration by the Administrator of this final action 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 must be filed, and shall not postpone the effectiveness of this action.

Statutory Authority
The statutory authority for this action is provided by sections 101; 111; 114; 116, 160-165, 169, 173, 301, 302, 501 and 502 of the CAA, as amended (42 U.S.C. 7401; 42 U.S.C. 7411; 42 U.S.C. 7414; 42 U.S.C. 7416; 7470-7475, 7479, 7503, 7601, 7602, 7661, and 7662.

List of Subjects
40 CFR Part 51
Environmental protection, Air pollution control, Construction permit, Intergovernmental relations, Major source, Oil and gas.
40 CFR Part 52
Environmental protection, Air pollution control, Construction permit, Incorporation by reference, Intergovernmental relations, Major source, Oil and gas.
40 CFR Part 70
Environmental protection, Air pollution control, Intergovernmental relations, Major source, Oil and gas, Operating permit.
40 CFR Part 71
Environmental protection, Air pollution control, Intergovernmental relations, Major source, Oil and gas, Operating permit.
Dated: May 12, 2016.
Gina McCarthy,

Administrator.
For the reasons stated in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows:

PART 51—REQUIREMENTS FOR PREPARATION, ADOPTION, AND SUBMITTAL OF IMPLEMENTATION PLANS
1. The authority citation for part 51 continues to read as follows:

Authority:
23 U.S.C. 101; 42 U.S.C. 7401-7671q.
2. In § 51.165, revise paragraph (a)(1)(ii) to read as follows:
§ 51.165
Permit requirements.
(a) * * *
(1) * * *
(ii)(A) Building, structure, facility, or installation means all of the pollutant-emitting activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control) except the activities of any vessel. Pollutant emitting activities shall be considered as part of the same industrial grouping if they belong to the same Major Group ( i.e., which have the same two-digit code) as described in the Standard Industrial Classification Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock numbers 4101-0065 and 003-005-00176-0, respectively).
(B) The plan may include the following provision: Notwithstanding the provisions of paragraph (a)(1)(ii)(A) of this section, building, structure, facility, or installation means, for onshore activities under Standard Industrial Classification (SIC) Major Group 13: Oil and Gas Extraction, all of the pollutant-emitting activities included in Major Group 13 that are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control). Pollutant emitting activities shall be considered adjacent if they are located on the same surface site; or if they are located on surface sites that are located within 1/4 mile of one another (measured from the center of the equipment on the surface site) and they share equipment. Shared equipment includes, but is not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. Surface site, as used in this paragraph (a)(1)(ii)(B), has the same meaning as in 40 CFR 63.761.
* * * * *
3. In § 51.166, revise paragraph (b)(6) to read as follows:
§ 51.166
Prevention of significant deterioration of air quality.
* * * * *
(b) * * *
(6)(i) Building, structure, facility, or installation means all of the pollutant-emitting activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control) except the activities of any vessel. Pollutant-emitting activities shall be considered as part of the same industrial grouping if they belong to the same Major Group ( i.e., which have the same two-digit code) as described in the Standard Industrial Classification Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock numbers 4101-0066 and 003-005-00176-0, respectively).
(ii) The plan may include the following provision: Notwithstanding the provisions of paragraph (b)(6)(i) of this section, building, structure, facility, or installation means, for onshore activities under SIC Major Group 13: Oil and Gas Extraction, all of the pollutant-emitting activities included in Major Group 13 that are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control). Pollutant emitting activities shall be considered adjacent if they are located on the same surface site; or if they are located on surface sites that are located within 1/4 mile of one another (measured from the center of the equipment on the surface site) and they share equipment. Shared equipment includes, but is not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. Surface site, as used in this paragraph (b)(6)(ii), has the same meaning as in 40 CFR 63.761.
* * * * *
4. In appendix S to part 51, revise section II.A.2. to read as follows:

Appendix S to Part 51—Emission Offset Interpretative Ruling
* * * * *

II. Initial Screening Analyses and Determination of Applicable Requirements
A. * * *
2. (i) Building, structure, facility or installation means all of the pollutant-emitting activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control) except the activities of any vessel. Pollutant-emitting activities shall be considered as part of the same industrial grouping if they belong to the same “Major Group” ( i.e., which have the same two digit code) as described in the Standard Industrial Classification Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock numbers 4101-0066 and 003-005-00176-0, respectively).
(ii) Notwithstanding the provisions of paragraph II.A.2(i) of this section, building, structure, facility or installation means, for onshore activities under SIC Major Group 13: Oil and Gas Extraction, all of the pollutant-emitting activities included in Major Group 13 that are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control). Pollutant emitting activities shall be considered adjacent if they are located on the same surface site; or if they are located on surface sites that are located within 1/4 mile of one another (measured from the center of the equipment on the surface site) and they share equipment. Shared equipment includes, but is not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. Surface site, as used in this paragraph II.A.2(ii), has the same meaning as in 40 CFR 63.761.
* * * * *

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

Authority:
42 U.S.C. 7401 et seq.
6. In § 52.21, revise paragraph (b)(6) to read as follows:
§ 52.21
Prevention of significant deterioration of air quality.
* * * * *
(b) * * *
(6)(i) Building, structure, facility, or installation means all of the pollutant-emitting activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control) except the activities of any vessel. Pollutant-emitting activities shall be considered as part of the same industrial grouping if they belong to the same “Major Group” ( i.e., which have the same first two digit code) as described in the Standard Industrial Classification Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock numbers 4101-0066 and 003-005-00716-0, respectively).
(ii) Notwithstanding the provisions of paragraph (b)(6)(i) of this section, building, structure, facility, or installation means, for onshore activities under Standard Industrial Classification (SIC) Major Group 13: Oil and Gas Extraction, all of the pollutant-emitting activities included in Major Group 13 that are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control). Pollutant emitting activities shall be considered adjacent if they are located on the same surface site; or if they are located on surface sites that are located within 1/4 mile of one another (measured from the center of the equipment on the surface site) and they share equipment. Shared equipment includes, but is not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. Surface site, as used in this paragraph (b)(6)(ii), has the same meaning as in 40 CFR 63.761.
* * * * *

PART 70—STATE OPERATING PERMIT PROGRAMS
7. The authority citation for part 70 continues to read as follows:

Authority:
42 U.S.C. 7401, et seq.
8. In § 70.2, revise the introductory text of the definition for “Major source” to read as follows:
§ 70.2
Definitions.
* * * * *
Major source means any stationary source (or any group of stationary sources that are located on one or more continuous or adjacent properties, and are under common control of the same person (or persons under common control)) belonging to a single major industrial grouping and that are described in paragraph (1), (2), or (3) of this definition. For the purposes of defining “major source,” a stationary source or group of stationary sources shall be considered part of a single industrial grouping if all of the pollutant emitting activities at such source or group of sources on contiguous or adjacent properties belong to the same Major Group ( i.e., all have the same two-digit code) as described in the Standard Industrial Classification Manual, 1987. State programs may adopt the following provision: For onshore activities belonging to Standard Industrial Classification (SIC) Major Group 13: Oil and Gas Extraction, pollutant emitting activities shall be considered adjacent if they are located on the same surface site; or if they are located on surface sites that are located within 1/4 mile of one another (measured from the center of the equipment on the surface site) and they share equipment. Shared equipment includes, but is not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. Surface site, as used in the introductory text of this definition, has the same meaning as in 40 CFR 63.761.
* * * * *

PART 71—FEDERAL OPERATING PERMIT PROGRAMS
9. The authority citation for part 71 continues to read as follows:

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

Subpart A—Operating Permits
10. In § 71.2, revise the introductory text of the definition for “Major sources” to read as follows:
§ 71.2
Definitions.
* * * * *
Major source means any stationary source (or any group of stationary sources that are located on one or more contiguous or adjacent properties, and are under common control of the same person (or persons under common control)), belonging to a single major industrial grouping and that are described in paragraph (1), (2), or (3) of this definition. For the purposes of defining “major source,” a stationary source or group of stationary sources shall be considered part of a single industrial grouping if all of the pollutant emitting activities at such source or group of sources on contiguous or adjacent properties belong to the same Major Group ( i.e., all have the same two-digit code) as described in the Standard Industrial Classification Manual, 1987. For onshore activities belonging to Standard Industrial Classification (SIC) Major Group 13: Oil and Gas Extraction, pollutant emitting activities shall be considered adjacent if they are located on the same surface site; or if they are located on surface sites that are located within 1/4 mile of one another (measured from the center of the equipment on the surface site) and they share equipment. Shared equipment includes, but is not limited to, produced fluids storage tanks, phase separators, natural gas dehydrators or emissions control devices. Surface site, as used in the introductory text of this definition, has the same meaning as in 40 CFR 63.761.
* * * * *
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R04-OAR-2016-0072; FRL-9947-22-Region 4]
Air Plan Approval; North Carolina; Prong 4—2008 Ozone, 2010 NO 2 , SO 2 , and 2012 PM 2.5

AGENCY:
Environmental Protection Agency.

ACTION:
Final rule.

SUMMARY:
The Environmental Protection Agency (EPA) is approving portions of revisions to the North Carolina State Implementation Plan (SIP), submitted by the North Carolina Department of Environment and Natural Resources (NC DENR), addressing the Clean Air Act (CAA or Act) visibility transport (prong 4) infrastructure SIP requirements for the 2008 8-hour Ozone, 2010 1-hour Nitrogen Dioxide (NO 2 ), 2010 1-hour Sulfur Dioxide (SO 2 ), and 2012 annual Fine Particulate Matter (PM 2.5 ) National Ambient Air Quality Standards (NAAQS). The CAA requires that each state adopt and submit a SIP for the implementation, maintenance, and enforcement of each NAAQS promulgated by EPA, commonly referred to as an “infrastructure SIP.” Specifically, EPA is approving the prong 4 portions of North Carolina's November 2, 2012, 2008 8-hour Ozone infrastructure SIP submission; August 23, 2013, 2010 1-hour NO 2 infrastructure SIP submission; March 18, 2014, 2010 1-hour SO 2 infrastructure SIP submission; and December 4, 2015, 2012 Annual PM 2.5 infrastructure SIP submission. All other applicable infrastructure requirements for these SIP submissions have been or will be addressed in separate rulemakings.

DATES:
This rule is effective July 5, 2016.

ADDRESSES:
EPA has established a docket for this action under Docket Identification No. EPA-R04-OAR-2016-0072. All documents in the docket are listed on the http://www.regulations.gov Web site. Although listed in the index, some information may not be publicly available, i.e., Confidential Business Information 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 either electronically through http://www.regulations.gov or in hard copy at the Air Regulatory Management Section, Air Planning and Implementation Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303-8960. EPA requests that if at all possible, you contact the person listed in the FOR FURTHER INFORMATION CONTACT section to schedule your inspection. The Regional Office's official hours of business are Monday through Friday 8:30 a.m. to 4:30 p.m., excluding federal holidays.

FOR FURTHER INFORMATION CONTACT:
Sean Lakeman of the Air Regulatory Management Section, Air Planning and Implementation Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303-8960. Mr. Lakeman can be reached by telephone at (404) 562-9043 or via electronic mail at lakeman.sean@epa.gov.

SUPPLEMENTARY INFORMATION:

I. Background
By statute, SIPs meeting the requirements of sections 110(a)(1) and (2) of the CAA are to be submitted by states within three years after promulgation of a new or revised NAAQS to provide for the implementation, maintenance, and enforcement of the new or revised NAAQS. EPA has historically referred to these SIP submissions made for the purpose of satisfying the requirements of sections 110(a)(1) and 110(a)(2) as “infrastructure SIP” submissions. Sections 110(a)(1) and (2) require states to address basic SIP elements such as the requirements for monitoring, basic program requirements, and legal authority that are designed to assure attainment and maintenance of the newly established or revised NAAQS. More specifically, section 110(a)(1) provides the procedural and timing requirements for infrastructure SIPs. Section 110(a)(2) lists specific elements that states must meet for the infrastructure SIP requirements related to a newly established or revised NAAQS. The contents of an infrastructure SIP submission may vary depending upon the data and analytical tools available to the state, as well as the provisions already contained in the state's implementation plan at the time in which the state develops and submits the submission for a new or revised NAAQS.
Section 110(a)(2)(D) has two components: 110(a)(2)(D)(i) and 110(a)(2)(D)(ii). Section 110(a)(2)(D)(i) includes four distinct components, commonly referred to as “prongs,” that must be addressed in infrastructure SIP submissions. The first two prongs, which are codified in section 110(a)(2)(D)(i)(I), are provisions that prohibit any source or other type of emissions activity in one state from contributing significantly to nonattainment of the NAAQS in another state (prong 1) and from interfering with maintenance of the NAAQS in another state (prong 2). The third and fourth prongs, which are codified in section 110(a)(2)(D)(i)(II), are provisions that prohibit emissions activity in one state from interfering with measures required to prevent significant deterioration of air quality in another state (prong 3) or from interfering with measures to protect visibility in another state (prong 4). Section 110(a)(2)(D)(ii) requires SIPs to include provisions ensuring compliance with sections 115 and 126 of the Act, relating to interstate and international pollution abatement.
North Carolina's November 2, 2012, 2008 8-hour Ozone submission; August 23, 2013, 2010 1-hour NO 2 submission; March 18, 2014, 2010 1-hour SO 2 submission; and December 4, 2015, 2012 Annual PM 2.5 submission cite to the State's regional haze SIP as satisfying prong 4 requirements. However, at those dates, EPA had not yet fully approved North Carolina's regional haze SIP because the SIP relied on the Clean Air Interstate Rule (CAIR) to satisfy the nitrogen oxides (NO X ) and SO 2 Best Available Retrofit Technology (BART) requirements for the CAIR-subject electric generating units (EGUs) in the State and the requirement for a long-term strategy (LTS) sufficient to achieve the state-adopted reasonable progress goals. ^1
^1 CAIR, promulgated in 2005, required 27 states and the District of Columbia to reduce emissions of NO X and SO 2 that significantly contribute to, or interfere with maintenance of, the 1997 NAAQS for fine particulates and/or ozone in any downwind state. CAIR imposed specified emissions reduction requirements on each affected State, and established an EPA-administered cap and trade program for EGUs in which States could join as a means to meet these requirements.
EPA demonstrated that CAIR achieved greater reasonable progress toward the national visibility goal than BART for NO X and SO 2 at BART-eligible EGUs in CAIR affected states, and revised the regional haze rule (RHR) to provide that states participating in CAIR's cap-and-trade program need not require affected BART-eligible EGUs to install, operate, and maintain BART for emissions of SO 2 and NO X . See 70 FR 39104 (July 6, 2005). As a result, a number of states in the CAIR region designed their regional haze SIPs to rely on CAIR as an alternative to NO X and SO 2 BART for CAIR-subject EGUs. These states also relied on CAIR as an element of a LTS for achieving their reasonable progress goals.
The United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) initially vacated CAIR in 2008, ^2 but ultimately remanded the rule to EPA without vacatur to preserve the environmental benefits provided by CAIR. ^3 On August 8, 2011, acting on the D.C. Circuit's remand, EPA promulgated the Cross State Air Pollution Rule (CSAPR) to replace CAIR and thus to address the interstate transport of emissions contributing to nonattainment and interfering with maintenance of the two air quality standards covered by CAIR as well as the 2006 PM 2.5 NAAQS. ^4
See 76 FR 48208.
^2 North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008).
^3 North Carolina v. EPA, 550 F.3d 1176 (D.C. Cir. 2008).
^4 Although a number of parties challenged the legality of CSAPR and the D.C. Circuit initially vacated and remanded CSAPR to EPA in EME Homer City Generation, L.P. v. EPA, 696 F.3d 7, 38 (D.C. Cir. 2012), the United States Supreme Court reversed the D.C. Circuit's decision on April 29, 2014, and remanded the case to the D.C. Circuit to resolve remaining issues in accordance with the high court's ruling. EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 (2014). On remand, the D.C. Circuit affirmed CSAPR in most respects and CSAPR is now in effect. EME Homer City Generation, L.P. v . EPA, 795 F.3d 118 (D.C. Cir. 2015).
Due to CAIR's status as a temporary measure following the D.C. Circuit's 2008 ruling, EPA could not fully approve regional haze SIP revisions to the extent that they relied on CAIR to satisfy the BART requirement and the requirement for a long-term strategy sufficient to achieve the state-adopted reasonable progress goals. On these grounds, EPA finalized a limited disapproval of North Carolina's regional haze SIP on June 7, 2012, triggering the requirement for EPA to promulgate a federal implementation plan (FIP) unless North Carolina submitted and EPA approved a SIP revision that corrected the deficiency. See 77 FR 33642. EPA finalized a limited approval of North Carolina's regional haze SIP on June 27, 2012, as meeting the remaining applicable regional haze requirements set forth in the CAA and the RHR. See 77 FR 38185.
On October 31, 2014, North Carolina submitted a regional haze plan revision to correct the deficiencies identified in the June 7, 2012, limited disapproval by replacing reliance on CAIR with reliance on a BART alternative to satisfy NO X and SO 2 BART requirements for EGUs formerly subject to CAIR. EPA finalized approval of the October 31, 2014, SIP revision and converted North Carolina's regional haze plan from a limited approval to a full approval on May 12, 2016. That action also removed EPA's obligation to implement a FIP to correct the previous deficiencies for North Carolina's initial regional haze plan.
In a proposed rulemaking (NPRM) published on April 8, 2016 (81 FR 20600), EPA proposed to approve the prong 4 portions of North Carolina's infrastructure SIP submissions for the 2008 8-hour Ozone, 2010 1-hour NO 2 , 2010 1-hour SO 2 , and 2012 annual PM 2.5 NAAQS based on final approval of the State's October 31, 2014, SIP revision. As discussed above, EPA subsequently finalized that SIP revision and converted North Carolina's regional haze plan from a limited approval to a full approval. The details of the aforementioned North Carolina infrastructure SIP submissions and the rationale for EPA's action is explained in the NPRM. Comments on the proposed rulemaking were due on or before April 29, 2016. EPA received no adverse comments on the proposed action.

II. Final Action
EPA is approving the prong 4 portions of North Carolina's November 2, 2012, 2008 8-hour Ozone infrastructure SIP submission; August 23, 2013, 2010 1-hour NO 2 infrastructure SIP submission; March 18, 2014, 2010 1-hour SO 2 infrastructure SIP submission; and December 4, 2015, 2012 Annual PM 2.5 infrastructure SIP submission. All other applicable infrastructure requirements for these SIP submissions have been or will be addressed in separate rulemakings.

III. Statutory and Executive Order Reviews
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. See 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. 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 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 CAA; and
• does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
The SIP is not approved to apply on any Indian reservation land or in any other area where 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 as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), nor will it impose substantial direct costs on tribal governments or preempt tribal law.
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register . A major rule cannot take effect until 60 days after it is published in the Federal Register . This action is not a “major rule” as defined by 5 U.S.C. 804(2).
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 August 2, 2016. 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, Particulate matter, Reporting and recordkeeping requirements, Volatile organic compounds.
Dated: May 23, 2016.
Heather McTeer Toney,

Regional Administrator, Region 4.
40 CFR part 52 is amended 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 II—North Carolina
2. Section 52.1770(e), is amended by adding new entries for “110(a)(1) and (2) Infrastructure Requirements for the 2008 8-Hour Ozone NAAQS”, “110(a)(1) and (2) Infrastructure Requirements for the 2010 1-hour NO 2 NAAQS”, “110(a)(1) and (2) Infrastructure Requirements for the 2010 1-hour SO 2 NAAQS” and “110(a)(1) and (2) Infrastructure Requirements for the 2012 Annual PM 2.5 NAAQS” at the end of the table to read as follows:
§ 52.1770
Identification of plan.
* * * * *
(e) * * *
EPA-Approved North Carolina Non-Regulatory Provisions
Provision | State effective date | EPA approval date | Federal Register citation | Explanation
* * * * * * *
110(a)(1) and (2) Infrastructure Requirements for the 2008 8-Hour Ozone NAAQS | 11/2/2012 | 6/3/2016 | [Insert citation of publication in Federal Register ] | Addressing prong 4 of section 110(a)(2)(D)(i) only.
110(a)(1) and (2) Infrastructure Requirements for the 2010 1-hour NO 2 NAAQS | 8/23/2013 | 6/3/2016 | [Insert citation of publication in Federal Register ] | Addressing prong 4 of section 110(a)(2)(D)(i) only.
110(a)(1) and (2) Infrastructure Requirements for the 2010 1-hour SO 2 NAAQS | 3/18/2014 | 6/3/2016 | [Insert citation of publication in Federal Register ] | Addressing prong 4 of section 110(a)(2)(D)(i) only.
110(a)(1) and (2) Infrastructure Requirements for the 2012 Annual PM 2.5 NAAQS | 12/4/2015 | 6/3/2016 | [Insert citation of publication in Federal Register ] | Addressing prong 4 of section 110(a)(2)(D)(i) only.
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R01-OAR-2015-0198; FRL-9940-14-Region 1]
Approval and Promulgation of Implementation Plans; Connecticut; Infrastructure Requirements for Lead, Ozone, Nitrogen Dioxide, Sulfur Dioxide, and Fine Particulate Matter

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
The Environmental Protection Agency (EPA) is approving elements of State Implementation Plan (SIP) submissions from Connecticut regarding the infrastructure requirements of the Clean Air Act (CAA or Act) for the 2008 lead, 2008 ozone, 2010 nitrogen dioxide, and 2010 sulfur dioxide National Ambient Air Quality Standards (NAAQS). EPA is also converting conditional approvals for several infrastructure requirements for the 1997 ozone NAAQS and for the 1997 and 2006 fine particle (PM 2.5 ) NAAQS to full approval under the CAA. Furthermore, we are conditionally approving elements of Connecticut's infrastructure requirements of the CAA regarding prevention of significant deterioration requirements to treat nitrogen oxides as a precursor to ozone and to establish a minor source baseline date for PM 2.5 emissions. Lastly, EPA is approving three statutes submitted by Connecticut in support of its demonstration that the infrastructure requirements of the CAA have been met. The infrastructure requirements are designed to ensure that the structural components of each state's air quality management program are adequate to meet the state's responsibilities under the CAA.

DATES:
This rule is effective on July 5, 2016.

ADDRESSES:
EPA has established a docket for this action under Docket Identification No. EPA-R01-OAR-2015-0198. All documents in the docket are listed on the http://www.regulations.gov Web site, although some information, such as confidential business information or other information whose disclosure is restricted by statute is not publically available. 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 at http://www.regulations.gov or at the U.S. Environmental Protection Agency, EPA New England Regional Office, Office of Ecosystem Protection, Air Quality Planning Unit, 5 Post Office Square, Suite 100, Boston, MA. EPA requests that if at all possible, you contact the contact listed in the FOR FURTHER INFORMATION CONTACT section to schedule your inspection. The Regional Office's official hours of business are Monday through Friday, 8:30 a.m. to 4:30 p.m., excluding legal holidays. Copies of the documents relevant to this action are also available for public inspection during normal business hours, by appointment at: Bureau of Air Management, Department of Energy and Environmental Protection, State Office Building, 79 Elm Street, Hartford, CT 06106-1630.

FOR FURTHER INFORMATION CONTACT:
Alison C. Simcox, Environmental Scientist, Air Quality Planning Unit, Air Programs Branch (Mail Code OEP05-02), U.S. Environmental Protection Agency, Region 1, 5 Post Office Square, Suite 100, Boston, Massachusetts 02109-3912; (617) 918-1684; simcox.alison@epa.gov.

SUPPLEMENTARY INFORMATION:
Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA.
Organization of this document. The following outline is provided to aid in locating information in this preamble.
I. Background and Purpose
II. Final Action
III. Statutory and Executive Order Reviews

I. Background and Purpose
This rulemaking addresses submissions from the Connecticut Department of Energy and Environmental Protection (CT DEEP). The state submitted its infrastructure SIP for each NAAQS on the following dates: 2008 Pb—October 13, 2011; 2008 ozone—December 28, 2012; 2010 NO 2 —January 2, 2013; and 2010 SO 2 —May 30, 2013. This rulemaking also addresses certain infrastructure SIP elements for the 1997 and 2006 PM 2.5 NAAQS for which EPA previously issued a conditional approval. See 77 FR 63228 (October 16, 2012). The state submitted these infrastructure SIPs on September 4, 2008, and September 18, 2009, respectively. Lastly, this rulemaking addresses one infrastructure SIP element for the 1997 8-hour ozone NAAQS for which EPA previously issued a conditional approval. See 76 FR 40248 (July 8, 2011). The state submitted this infrastructure SIP on December 28, 2007.
EPA did not receive any comments, adverse or otherwise, in response to the Notice of Proposed Rulemaking (NPR). See 80 FR 54471 (September 10, 2015).

II. Final Action
EPA is approving SIP submissions from Connecticut certifying that the state's current SIP is sufficient to meet the required infrastructure elements under sections 110(a)(1) and 110(a)(2) for the 2008 Pb, 2008 ozone, 2010 NO 2 , and 2010 SO 2 NAAQS, with the exception of certain aspects relating to PSD which we are conditionally approving. A summary of EPA's actions regarding these infrastructure SIP requirements is contained in Table 1 below.
Table 1—Action Taken on CT Infrastructure SIP Submittals for Listed NAAQS
Element | 2008 Pb | 2008 Ozone | 2010 NO 2 | 2010 SO 2
(A): Emission limits and other control measures | A | A | A | A
(B): Ambient air quality monitoring and data system | A | A | A | A
(C)(i): Enforcement of SIP measures | A | A | A | A
(C)(ii): PSD program for major sources and major modifications | A * | A * | A * | A *
(C)(iii): Permitting program for minor sources and minor modifications | A | A | A | A
(D)(i)(I): Contribute to nonattainment/interfere with maintenance of NAAQS (prongs 1 and 2) | A | No action | A | No action
(D)(i)(II): PSD (prong 3) | A * | A * | A * | A *
(D)(i)(II): Visibility Protection (prong 4) | A | A | A | A
(D)(ii): Interstate Pollution Abatement | A | A | A | A
(D)(ii): International Pollution Abatement | A | A | A | A
(E)(i): Adequate resources | A | A | A | A
(E)(ii): State boards | A | A | A | A
(E)(iii): Necessary assurances with respect to local agencies | NA | NA | NA | NA
(F): Stationary source monitoring system | A | A | A | A
(G): Emergency power | A | A | A | A
(H): Future SIP revisions | A | A | A | A
(I): Nonattainment area plan or plan revisions under part D | + | + | + | +
(J)(i): Consultation with government officials | A | A | A | A
(J)(ii): Public notification | A | A | A | A
(J)(iii): PSD | A * | A * | A * | A *
(J)(iv): Visibility protection | + | + | + | +
(K): Air quality modeling and data | A | A | A | A
(L): Permitting fees | A | A | A | A
(M): Consultation and participation by affected local entities | A | A | A | A
In the above table, the key is as follows:
A | Approve
A * | Approve, but conditionally approve aspect relating to NO X as a precursor to ozone and minor source baseline date for PM 2.5 under the PSD program.
+ | Not germane to infrastructure SIPs.
No action | EPA is taking no action on this infrastructure requirement.
NA | Not applicable.
With respect to the 1997 and 2006 PM 2.5 NAAQS, EPA is approving Connecticut's infrastructure SIP submittal requirements pertaining to Elements 110(a)(2)A, D(ii) (interstate pollution abatement), and E(ii) (state boards) for which a conditional approval was previously issued. See 77 FR 63228, October 16, 2012. Also with respect to the 1997 and 2006 PM 2.5 NAAQS, EPA is newly conditionally approving Connecticut's submittals pertaining to Elements 110(a)(2)C(ii), D(i)(II), and J(iii) for the requirements to treat NO X as a precursor to ozone and to establish a minor source baseline date for PM 2.5 in the PSD program.
With respect to the 1997 8-hour ozone NAAQS, EPA is approving Connecticut's infrastructure SIP submittal requirements pertaining to Element 110(a)(2)(D)(ii) (interstate pollution abatement) for which a conditional approval was previously issued. See 77 FR 63228, October 16, 2012.
In addition, we are incorporating into the Connecticut SIP the following Connecticut statutes which were included for approval in Connecticut's infrastructure SIP submittals:
Connecticut General Statutes (CGS) Section 1-85 (Formerly Sec. 1-68) “Interest in conflict with discharge of duties,” as published in the General Statutes of Connecticut revised to January 1, 2015; amended in Public Act 89-97 in January 1989, effective October 1, 1989;
CGS Section 22a-171 (Formerly Sec. 19-507) “Duties of Commissioner of Energy and Environmental Protection,” as published in the General Statutes of Connecticut revised to January 1, 2013; amended in Public Act 84-546 in 1984, effective October 1, 1984;
CGS Section 16a-21a “Sulfur content of home heating oil and off-road diesel fuel. Suspension of requirements for emergency,” as published in the General Statutes of Connecticut revised to January 1, 2013, effective July 1, 2011.
As noted in Table 1, EPA is conditionally approving Connecticut's commitment for sub-element sections 110(a)(2)(C)(ii), (D)(i)(II) and (J)(iii) with respect to the 2008 Pb, 2008 ozone, 2010 NO 2 , and 2010 SO 2 NAAQS, as well as newly conditionally approving the state's submittals for these sub-elements with respect to the 1997 and 2006 PM 2.5 NAAQS. In a letter dated August 5, 2015, Connecticut committed to adopt and submit to EPA, one year from the publication of this conditional approval, regulatory revisions to Connecticut's prevention of significant deterioration and new source review permitting requirements that meet the requirements to treat NO X as a precursor pollutant to ozone and to establish a minor source baseline date for PM 2.5 .
Under section 110(k)(4) of the Act, EPA may conditionally approve a plan based on a commitment from the State to adopt specific enforceable measures by a date certain, but not later than one year from the date of approval. By this date, the State must meet its commitment made in its August 5, 2015 letter to submit revisions to its PSD program that fully meet the requirements above. If the State fails to do so, this action will become a disapproval one year from the date of publication of final approval. EPA will notify the State by letter that this action has occurred. At that time, this commitment will no longer be a part of the approved Connecticut SIP. EPA subsequently will publish a document in the Federal Register notifying the public that the conditional approval is converted to a disapproval. If the State meets its commitment within the applicable time frame, the conditionally approved submission will remain a part of the SIP until EPA takes final action approving or disapproving the new submittal. If EPA disapproves the new submittal, the conditionally approved portions of Connecticut's Infrastructure SIP submittals will also be disapproved at that time. If EPA approves the revised PSD program submittal, then the portions of Connecticut's infrastructure SIP submittals that were conditionally approved will be fully approved in their entirety. In addition, final disapproval of an infrastructure SIP submittal triggers the Federal implementation plan (FIP) requirement under section 110(c).
Other specific requirements of infrastructure SIPs and the rationale for EPA's final action on Connecticut's submittals are explained in the NPR and will not be restated here.

III. 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, 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 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 EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where 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).
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this action and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication of the rule in the Federal Register . A major rule cannot take effect until 60 days after it is published in the Federal Register . 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 August 2, 2016. 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, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides, Volatile organic compounds.
Dated: December 3, 2015.
H. Curtis Spalding,

Regional Administrator, EPA New England.
Part 52 of chapter I, title 40 of the Code of Federal Regulations is amended 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 H—Connecticut
2. Section 52.370 is amended by adding reserved paragraph (c)(111) and adding paragraph (c)(112) to read as follows:
§ 52.370
Identification of plan.
* * * * *
(c) * * *
(111) [Reserved]
(112) Revisions to the State Implementation Plan submitted by the Connecticut Department of Energy and Environmental Protection on December 28, 2007; September 4, 2008; September 18, 2009; October 13, 2011; December 28, 2012; January 2, 2013; and May 30, 2013.
(i) [Reserved.]
(ii) Additional materials.
(A) The Connecticut Department of Energy and Environmental Protection document, “Adequacy Determination of the Connecticut State Implementation Plan with Regard to Clean Air Act Section 110(a)(1) and (2) for the 8-Hour Ozone National Ambient Air Quality Standard Program Infrastructure,” Final, December 28, 2007.
(B) The Connecticut Department of Energy and Environmental Protection document, “Adequacy Determination of the Connecticut State Implementation Plan for Clean Air Act Section 110(a) Infrastructure Elements: 1997 National Ambient Air Quality Standard for Fine Particulate Matter,” Final, September 4, 2008.
(C) The Connecticut Department of Energy and Environmental Protection document, “Adequacy Determination of the Connecticut State Implementation Plan with Regard to Clean Air Act Section 110(a)(1) and (2) for the 2006 Fine Particulate Matter National Ambient Air Quality Standard,” Final, September 18, 2009.
(D) The Connecticut Department of Energy and Environmental Protection document, “Request to Withdraw a Portion of Connecticut's PM 2.5 Infrastructure Adequacy Determination,” January 7, 2011.
(E) The Connecticut Department of Energy and Environmental Protection document, “Addendum to the CAA § 110(a)(2)(D)(i)(I) Portion of Connecticut's Infrastructure Submittal for the 2006 PM 2.5 NAAQS,” August 19, 2011.
(F) The Connecticut Department of Energy and Environmental Protection document, “Adequacy Determination of the Connecticut State Implementation Plan with Regard to Clean Air Act Section 110(a)(1) and
(2) for the 2008 Lead National Ambient Air Quality Standard,” Final, October 13, 2011.
(G) The Connecticut Department of Energy and Environmental Protection document, “Update to Connecticut PM 2.5 Infrastructure Submittals,” June 15, 2012.
(H) The Connecticut Department of Energy and Environmental Protection document, “Connecticut State Implementation Plan with Regard to the Infrastructure Requirements of Clean Air Act Section 110(a)(1) and 110(s)(2) for the 2008 Ozone National Ambient Air Quality Standards, Final, December 28, 2012.
(I) The Connecticut Department of Energy and Environmental Protection document, “Connecticut State Implementation Plan with Regard to the Infrastructure Requirements of Clean Air Act Section 110(a)(1) and 110(a)(2) for the 2010 Nitrogen Dioxide National Ambient Air Quality Standards, Final, January 2, 2013.
(J) The Connecticut Department of Energy and Environmental Protection document, “Connecticut State Implementation Plan for Clean Air Act Section 110(a) Infrastructure Elements: 2010 Sulfur Dioxide National Ambient Air Quality Standard, Final, May 30, 2013.
(K) The Connecticut Department of Energy and Environmental Protection letter, “Supplement to Infrastructure State Implementation Plan (SIP) Revisions,” August 5, 2015.
3. Section 52.380 is amended by adding paragraphs (f), (g), and (h) to read as follows:
§ 52.380
Rules and regulations.
* * * * *
Note 1 to paragraphs (f) through (h): “state” means the state of Connecticut.
(f) Connecticut General Statutes Section 1-85. (Formerly Sec. 1-68). Interest in conflict with discharge of duties: A public official, including an elected state official, or state employee has an interest which is in substantial conflict with the proper discharge of his duties or employment in the public interest and of his responsibilities as prescribed in the laws of this state, if he has reason to believe or expect that he, his spouse, a dependent child, or a business with which he is associated will derive a direct monetary gain or suffer a direct monetary loss, as the case may be, by reason of his official activity. A public official, including an elected state official, or state employee does not have an interest which is in substantial conflict with the proper discharge of his duties in the public interest and of his responsibilities as prescribed by the laws of this state, if any benefit or detriment accrues to him, his spouse, a dependent child, or a business with which he, his spouse or such dependent child is associated as a member of a profession, occupation or group to no greater extent than any other member of such profession, occupation or group. A public official, including an elected state official or state employee who has a substantial conflict may not take official action on the matter.
(g) Connecticut General Statutes Section 22a-171. (Formerly Sec. 19-507). Duties of Commissioner of Energy and Environmental Protection: The Commissioner of Energy and Environmental Protection of the State of Connecticut shall:
(1) Initiate and supervise programs for the purposes of determining the causes, effect and hazards of air pollution;
(2) Initiate and supervise state-wide programs of air pollution control education;
(3) Cooperate with and receive money from the Federal Government and, with the approval of the Governor, from any other public or private source;
(4) Adopt, amend, repeal and enforce regulations as provided in Connecticut General Statutes Section 22a-174 and do any other act necessary to enforce the provisions of Connecticut General Statutes Chapter 446c and Connecticut General Statutes Section 14-164c;
(5) Advise and consult with agencies of the United States, agencies of the state, political subdivisions and industries and any other affected groups in furtherance of the purposes of Connecticut General Statutes Chapter 446c.
(h) Connecticut General Statutes Section 16a-21a. Sulfur content of home heating oil and off-road diesel fuel. Suspension of requirements for emergency. (1)(i) The amount of sulfur content of the following fuels sold, offered for sale, distributed or used in this state shall not exceed the following percentages by weight:
(A) For number two heating oil, three-tenths of one per cent; and
(B) For number two off-road diesel fuel, three-tenths of one per cent.
(ii) Notwithstanding paragraph (h)(1)(i) of this section, the amount of sulfur content of number two heating oil sold, offered for sale, distributed or used in this state shall not exceed the following percentages by weight:
(A) For the period beginning July 1, 2011, and ending June 30, 2014, fifty parts per million; and
(B) On and after July 1, 2014, fifteen parts per million.
(iii) The provisions of paragraph (h)(1)(ii) of this section shall not take effect until the states of New York, Massachusetts and Rhode Island each have adopted requirements that are substantially similar to the provisions of said paragraph (h)(1)(ii).
(2) As of the date on which the last of the states of New York, Massachusetts and Rhode Island limits the sulfur content of number two heating oil to one thousand five hundred parts per million, the sulfur content of number two heating oil sold, offered for sale, distributed or used in this state shall not exceed one thousand five hundred parts per million.
(3) As of the date on which the last of the states of New York, Massachusetts and Rhode Island limits the sulfur content of number two heating oil to one thousand two hundred fifty parts per million, the sulfur content of number two heating oil sold, offered for sale, distributed or used in this state shall not exceed one thousand two hundred fifty parts per million.
(4) As of the date on which the last of the states of New York, Massachusetts and Rhode Island limits the sulfur content of number two heating oil to five hundred parts per million, the sulfur content of number two heating oil sold, offered for sale, distributed or used in this state shall not exceed five hundred parts per million.
(5) As of the date on which the last of the states of New York, Massachusetts and Rhode Island limits the sulfur content of number two off-road diesel fuel to five hundred parts per million, the sulfur content of number two off-road diesel fuel offered for sale, distributed or used in this state shall not exceed five hundred parts per million.
(6) The Commissioner of Energy and Environmental Protection of the State of Connecticut may suspend the requirements of subsections (a) to (e), inclusive, of this Connecticut General Statutes Section 16a-21a if the commissioner finds that the physical availability of fuel which complies with such requirements is inadequate to meet the needs of residential, commercial or industrial users in this state and that such inadequate physical availability constitutes an emergency provided the commissioner shall specify in writing the period of time such suspension shall be in effect.
Note 2 to paragraph (h): EPA has replaced the original structure of the CT statute with the structure of the CFR and uses “paragraph” instead of the original statutory language of “subsection” and “subdivision.” EPA has also replaced the (a)-level of the original statute with the (1)-level in the CFR and the (1)-level in the original statute with the (i)-level in the CFR.
4. In § 52.385, Table 52.385 is amended by adding an entry for Section 1-85, revising the entry for Section 16a-21a, and adding new an entry for Section 22a-171 to read as follows:
§ 52.385 EPA-approved
Connecticut regulations.
* * * * *
Table 52.385—EPA-Approved Regulations
Connecticut state citation | Title/subject | Dates | Date adopted by state | Date approved by EPA | Federal Register citation | Section 52.370 | Comments/ description
* * * * * * *
Connecticut General Statutes | Interest in conflict with discharge of duties | October 1, 1989 | June 3, 2016 | [Insert Federal Register citation] | c(112) | Criteria for identifying a conflict of interest.
Section 1-85
Connecticut General Statutes | Sulfur content of home heating oil and off road diesel fuel. Suspension of requirements for emergency | July 8, 2013 | June 3, 2016 | [Insert Federal Register citation] | c(112) | Allowable sulfur content of fuels provided. Criteria for suspension of requirements identified.
Section 16a-21a
Connecticut General Statutes | Duties of Commissioner of Energy and Environmental Protection. | October 1, 1984 | June 3, 2016 | [Insert Federal Register citation] | c(112) | Obligations and activities of the Commissioner identified.
Section 22a-171
5. Add § 52.386 to read as follows:
§ 52.386
Section 110(a)(2) infrastructure requirements.
The Connecticut Department of Energy and Environmental Protection submitted the following infrastructure SIPs on these dates: 2008 Pb NAAQS—October 13, 2011; 2008 ozone NAAQS— December 28, 2012; 2010 NO 2 NAAQS—January 2, 2013; and 2010 SO 2 NAAQS—May 30, 2013. These infrastructure SIPs are approved, with the exception of certain elements within 110(a)(2)(C)(ii), D(i)(II), and J(iii), which are conditionally approved. Connecticut submitted infrastructure SIPs for the 1997 and 2006 PM 2.5 NAAQS on September 4, 2008, and September 18, 2009, respectively, and elements 110(a)(2)(A), D(ii), and E(ii), which were previously conditionally approved, are now approved. Also with respect to the 1997 and 2006 PM 2.5 NAAQS, elements related to PSD, which include 110(a)(2)C(ii), D(i)(II), and J(iii) are newly conditionally approved. Connecticut also submitted an Infrastructure SIP for the 1997 8-hour ozone NAAQS on December 28, 2007, and element 110(a)(2)(D)(ii), which was previously conditionally approved, is now approved.
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 271
[EPA-R09-RCRA-2015-0822; FRL-9947-28-Region 9]
Nevada: Final Authorization of State Hazardous Waste Management Program Revisions

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
EPA received several comments during the open comment period on the March 23, 2016, proposed rule to authorize Nevada's changes to the State Hazardous Waste Management program. EPA is responding to one comment opposing the action and reaffirming the effective date of the direct final rule as June 6, 2016.

DATES:
The final authorization is effective June 6, 2016.

FOR FURTHER INFORMATION CONTACT:
Laurie Amaro, U.S. Environmental Protection Agency Region 9, 75 Hawthorne Street LND-1-1, San Francisco, CA 94105, amaro.laurie@epa.gov, 415-972-3364.

SUPPLEMENTARY INFORMATION:

A. What decisions has EPA made in this rule?
On November 25, 2015, and December 28, 2015, Nevada submitted final complete program revision applications seeking authorization of changes to its hazardous waste program that correspond to certain federal rules promulgated between July 1, 2005, and June 30, 2008, (also known as RCRA Clusters XVI through XVIII). EPA concludes that Nevada's application to revise its authorized program meets all of the statutory and regulatory requirements established by RCRA, as set forth in RCRA section 3006(b), 42 U.S.C. 6926(b), and 40 CFR part 271. Therefore, EPA grants Nevada final authorization to operate as part of its hazardous waste program the changes listed in Section G of the direct final rule (81 FR 15440), as further described in the authorization application.
Nevada has responsibility for permitting treatment, storage, and disposal facilities within its borders (except in Indian country) and for carrying out the aspects of the RCRA program described in its revised program application. New federal requirements and prohibitions imposed by federal regulations that EPA promulgates pursuant to the Hazardous and Solid Waste Amendments of 1984 take effect in authorized states at the same time that they take effect in unauthorized states. Thus, EPA will implement those requirements and prohibitions in Nevada, including the issuance of new permits implementing those requirements, until the State is granted authorization to do so.

B. What is the effect of today's authorization decision?
The effect of this decision is that the changes described in Nevada's authorization application will become part of the authorized state hazardous waste program and therefore will be federally enforceable. Nevada will continue to have primary enforcement authority and responsibility for its state hazardous waste program. EPA retains its authorities under RCRA sections 3007, 3008, 3013, and 7003, including its authority to:
• Conduct inspections, and require monitoring, tests, analyses or reports;
• Enforce RCRA requirements, including authorized state program requirements, and suspend or revoke permits; and
• Take enforcement actions regardless of whether the state has taken its own actions.
This action does not impose additional requirements on the regulated community because the regulations for which Nevada is being authorized by today's action are already effective and are not changed by today's action.

C. What were the comments on EPA's proposal and what is EPA's response?
On March 23, 2016, EPA published a proposed rule (81 FR 15497) and a direct final rule (81 FR 15440) to authorize Nevada's November 25 and December 28, 2015, applications to make revisions to Nevada's State Hazardous Waste Management program that correspond to certain federal rules promulgated between July 1, 2005, and June 30, 2008 (also known as RCRA Clusters XVI through XVIII). EPA stated that if adverse comments were received by May 9, 2016, the rule would be withdrawn and not take effect. On May 9, 2016, EPA received a comment opposing approval; however, due to the reasons explained below, EPA is not withdrawing the direct final rule but rather is responding to the comment and reaffirming the effective date of June 6, 2016, of the rule, pursuant to 40 CFR 271.21(b)(3)(iii)(B).
EPA received four comments on the proposed rule, Nevada: Final Authorization of State Hazardous Waste Management Program Revisions. Three comments stated, “Good” and do not require a response. The fourth comment stated, “Instead of not authorizing Nevada's antifreeze recycling program (and in the process violate 271.1(h), the partial authorization prohibition) EPA should instead require the program to be amended so it is no less stringent than EPAs [sic] requirements. This has been wrong since 2009!”
The State of Nevada adopted regulations for the “Recycling of Used Antifreeze” effective October 3, 1996, at NAC 444.8801-9071. These regulations are applicable to those categories of antifreeze that are recycled and have been determined to be hazardous waste because they either exhibit a characteristic of hazardous waste ( i.e., the toxicity characteristic) or they are a listed hazardous waste in the state of their origin, for those categories of antifreeze entering Nevada from another State (NAC 444.8871). Under the Federal code, spent antifreeze destined to be recycled, as defined by Nevada, would be subject to the requirements of 40 CFR 261.6(b)-(d) “Requirements for Recyclable Materials.” In the Nevada regulations at NAC 444.8801-9071, spent antifreeze that is recycled is not regulated as universal waste, but is subject to requirements that are less stringent than the Federal regulations at 40 CFR 261.6(b)-(d). Accordingly, EPA cannot authorize Nevada's regulations specific to the recycling of used antifreeze.
However, Nevada has incorporated the federal regulations contained in 40 CFR 261.6(b)-(d) at NAC 444.8632. The purpose of EPA's notice in the Federal Register is to direct generators and recyclers of used antifreeze to comply with 40 CFR 261.1(b)-(d) as incorporated by reference in NAC 444.8632, rather than the antifreeze-specific provisions at NAC 444.8801-9071. Because Nevada's authorized program regulates used antifreeze recycling at NAC 444.8632 in a program that is no less stringent than the federal requirements, there is no gap in coverage of used antifreeze recycling that could be considered a partial authorization, and EPA is not running afoul of the requirement contained in 40 CFR 271.1(h). Additionally, as noted in the guidance document, Clarification of EPA Policy on Authorizing Incomplete or Late “Clusters” Under 40 CFR 271.21 and Availability of Public Information under RCRA Section 3006(f), Nov. 6, 1992,
There is regulatory history [relevant to 40 CFR 271.1(h)] which supports our interpretation that the prohibition on partial programs means States are prohibited from implementing RCRA programs that address only part of the universe of waste handlers, e.g., “generators”, “transporters”, “treatment, storage and disposal facilities”. This prohibition, therefore, would not be relevant to the great majority of program revisions, since any State program that has obtained initial authorization already addresses the full universe of waste handlers.
The prohibition contained in 40 CFR 271.1(h) therefore does not apply to this authorization decision. Nevada obtained initial authorization of its hazardous waste management program on August 19, 1985, effective November 1, 1985 (50 FR 42181), and Nevada's federally authorized program covers the full universe of waste handlers. Accordingly, EPA affirms that the immediate final decision takes effect on June 6, 2016, as described in the direct final rule, Nevada: Final Authorization of State Hazardous Waste Management Program Revisions.

D. Administrative Requirements
The Office of Management and Budget (OMB) has exempted this action from the requirements of Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011). Therefore this action is not subject to review by OMB. This action authorizes state requirements for the purpose of RCRA section 3006 and imposes no additional requirements beyond those imposed by state law. Accordingly, I certify that this action will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. ). Because this action authorizes pre-existing requirements under state law and does not impose any additional enforceable duty beyond that required by state law, it does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538). For the same reason, this action also does not significantly or uniquely affect the communities of tribal governments, as specified by Executive Order 13175 (65 FR 67249, November 9, 2000). This action 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, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999), because it merely authorizes state requirements as part of the state RCRA hazardous waste program without altering the relationship or the distribution of power and responsibilities established by RCRA. This action also is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997), because it is not economically significant and it does not make decisions based on environmental health or safety risks. This rule is not subject to Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) because it is not a significant regulatory action under Executive Order 12866.
Under RCRA section 3006(b), EPA grants a state's application for authorization as long as the state meets the criteria required by RCRA. It would thus be inconsistent with applicable law for EPA, when it reviews a state authorization application, to require the use of any particular voluntary consensus standard in place of another standard that otherwise satisfies the requirements of RCRA. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. As required by section 3 of Executive Order 12988 (61 FR 4729, February 7, 1996), in issuing this rule, EPA has taken the necessary steps to eliminate drafting errors and ambiguity, minimize potential litigation, and provide a clear legal standard for affected conduct. EPA has complied with Executive Order 12630 (53 FR 8859, March 15, 1988) by examining the takings implications of the rule in accordance with the “Attorney General's Supplemental Guidelines for the Evaluation of Risk and Avoidance of Unanticipated Takings” issued under the executive order. This rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. ). “Burden” is defined at 5 CFR 1320.3(b). Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. Because this rule authorizes pre-existing state rules which are at least equivalent to, and no less stringent than existing federal requirements, and imposes no additional requirements beyond those imposed by state law, and there are no anticipated significant adverse human health or environmental effects, the rule is not subject to Executive Order 12898.
The Congressional Review Act, 5 U.S.C. 801-808, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the United States. EPA will submit a report containing this document and other required information to the U.S. Senate, the U.S. House of Representatives, and the Comptroller General of the United States prior to publication in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal Register. This action is not a “major rule” as defined by 5 U.S.C. 804(2). However, this action is effective 75 days after the date of initial publication in the Federal Register.

List of Subjects in 40 CFR Part 271
Environmental protection, Administrative practice and procedure, Confidential business information, Hazardous waste, Hazardous waste transportation, Indian lands, Intergovernmental relations, Penalties, Reporting and recordkeeping requirements.

Authority:
This action is issued under the authority of sections 2002(a), 3006, and 7004(b) of the Solid Waste Disposal Act as amended, 42 U.S.C. 6912(a), 6926, and 6974(b).
Dated: May 26, 2016.
Alexis Strauss,

Acting Regional Administrator, Region 9.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Centers for Medicare & Medicaid Services
42 CFR Part 403
DEPARTMENT OF HEALTH AND HUMAN SERVICES
45 CFR Part 1331
RIN 0985-AA11
State Health Insurance Assistance Program (SHIP)

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

ACTION:
Final rule.

SUMMARY:
The Department of Health and Human Services is issuing a final regulation that adopts, without change, the interim final rule (IFR) entitled “State Health Insurance Assistance Program (SHIP).” This final rule implements a provision enacted by the Consolidated Appropriations Act of 2014 and reflects the transfer of the State Health Insurance Assistance Program (SHIP) from the Centers for Medicare & Medicaid Services (CMS), in the Department of Health and Human Services (HHS) to the Administration for Community Living (ACL) in HHS. Prior to the interim final rule, prior regulations were issued by CMS under the authority granted by the Omnibus Budget Reconciliation Act of 1990 (OBRA), Section 4360.

DATES:
Effective June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Josh Hodges, Administration for Community Living, telephone (202) 795-7364 (Voice). This is not a toll-free number. This document will be made available in alternative formats upon request. Written correspondence can be sent to Administration for Community Living, U.S. Department of Health and Human Services, 330 C St. SW., Washington, DC 20201.

SUPPLEMENTARY INFORMATION:

I. Background
The State Health Insurance Assistance Program (SHIP) was created under Section 4360 of the Omnibus Budget Reconciliation Act (OBRA) of 1990 (Pub. L. 101-508). This section of the law authorized the Centers for Medicare & Medicaid Services (CMS) to make grants to States to establish and maintain health insurance advisory service programs for Medicare beneficiaries. Grant funds were made available to support information, counseling, and assistance activities relating to Medicare, Medicaid, and other related health insurance options such as: Medicare supplement insurance, long-term care insurance, managed care options, and other health insurance benefit information. In January 2014, in the Consolidated Appropriations Act of 2014, Congress transferred the funding for the SHIP program from CMS to the Administration for Community Living (ACL). This transfer reflects the existing formal and informal collaborations between the SHIP programs and the networks that ACL serves.
On February 4, 2016, ACL and CMS issued an IFR (81 FR 5917) that transferred all provisions of the existing SHIP regulations at 42 CFR part 403 Subpart E, (§§ 403.500 through 403.512), to a new part at 45 CFR 1331.1-1331.7. The IFR also changed all references to CMS' administration of the program to ACL and made a technical change to reflect new Uniform Administrative Requirements, Cost Principles, and Audit Requirements for HHS Awards, codified at 45 CFR part 75. This final rule adopts, without making any changes, the regulatory requirements established in the IFR.

II. Comments on the IFR
HHS received one responsive comment to the IFR. The commenter expressed support for the rule and optimism for the new opportunities that come with the SHIP's transfer to ACL. We are grateful for the commenter's support and look forward to continuing to improve the program's effectiveness and efficiency.

III. Regulatory Analysis

A. Executive Order 12866
This rule is not being treated as a “significant regulatory action” under section 3(f) of Executive Order 12866. Accordingly, the rule has not been reviewed by the Office of Management and Budget.

B. Regulatory Flexibility Analysis
The Secretary certifies under 5 U.S.C. 605(b), the Regulatory Flexibility Act (Pub. L. 96-354), that this regulation will not have a significant economic impact on a substantial number of small entities. The primary impact of this regulation is on entities applying for SHIP funding opportunities, specifically researchers, States, public or private agencies and organizations, institutions of higher education, and Indian tribes and Tribal organizations. The regulation does not have a significant economic impact on these entities.

C. Paperwork Reduction Act of 1995
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Ch. 3506; 5 CFR 1320 Appendix A.1) (PRA), ACL and CMS have determined that there are no new collections of information contained in this final rule.

D. Waiver of Proposed Rulemaking
Under the Administrative Procedure Act (APA), ACL and CMS are required to publish a notice of proposed rulemaking and provide the public with an opportunity to comment on proposed regulations prior to establishing a final rule unless it is determined for good cause that the notice and comment procedure is impracticable, unnecessary or contrary to public interest. 5 U.S.C. 553(b). As noted previously, Congress has already transferred the SHIP program to ACL under the Consolidated Appropriations Act of 2014. This final rule makes no changes other than aligning the location of the regulations within the Code of Federal Regulations with other ACL programs; amending the name of the administering agency to ACL; and updating a reference to new Uniform Administrative Requirements, Cost Principles, and Audit Requirements for HHS Awards, which have already undergone notice and comment rulemaking, therefore, there is good cause under 5 U.S.C. 553(b)(B) for waiving proposed rulemaking as unnecessary.

E. Waiver of Delayed Effective Date
Agencies are required to delay the effective date of their final regulations by 30 days after publication, as required under 5 U.S.C. 553(d), unless an exception under subsection (d) applies. Under 5 U.S.C. 553(d), ACL and CMS may waive the delayed effective date requirement if they find good cause and explain the basis for the waiver in the final rulemaking document or if the regulations grant or recognize an exemption or relieve a restriction.
In the present case, there is good cause to waive the delayed effective date for this final rule, because the substance of the regulation, other than the name of the administering agency, is identical to the current regulation.

F. Unfunded Mandates Reform Act
Section 202 of the Unfunded Mandates Reform Act of 1995 requires that a covered agency prepare a budgetary impact statement before promulgating a rule that includes any Federal mandate that may result in expenditures by State, local, or Tribal governments, in the aggregate, or by the private sector, of $100 million, adjusted for inflation, or more in any one year. ACL and CMS have determined that this rule does not result in the expenditure by State, local, and Tribal government in the aggregate or by the private sector of more than $100 million in any one year.

G. Congressional Review
This rule is not a major rule as defined in 5 U.S.C. Section 804(2).

H. Assessment of Federal Regulations and Policies on Families
Section 654 of the Treasury and General Government Appropriations Act of 1999 requires Federal agencies to determine whether a policy or regulation may affect family wellbeing. If the agency's conclusion is affirmative, then the agency must prepare an impact assessment addressing seven criteria specified in the law. These regulations do not have an impact on family well-being as defined in the legislation.

I. Executive Order 13132
Executive Order 13132 on “federalism” was signed August 4, 1999. The purposes of the Order are: “. . . to guarantee the division of governmental responsibilities between the national government and the States that was intended by the Framers of the Constitution, to ensure that the principles of federalism established by the Framers guide the executive departments and agencies in the formulation and implementation of policies, and to further the policies of the Unfunded Mandates Reform Act . . .” Executive Order 13132 applies to actions with federalism implications, which are actions that have substantial direct effect on States, on the relationship between the Federal government and the States, or on the distribution of power and responsibilities among the various levels of government. For actions that have federalism implications and preempt state law or have federalism implications and impose substantial compliance costs on states and local governments, the agency must consult with state and local officials before publishing the rule and include a federalism statement in the preamble.
The Department certifies that this rule does not have a substantial direct effect on States, on the relationship between the Federal government and the States, or on the distribution of power and responsibilities among the various levels of government.
ACL and CMS are not aware of any specific state laws that would be preempted by the adoption of the regulation.

List of Subjects
42 CFR Part 403
Grant programs, Health insurance, Medicare, Reporting and recordkeeping requirements.
45 CFR Part 1331
Grant programs, health insurance, Medicare, reporting and recordkeeping requirements.
Accordingly, the interim final rule amending 42 CFR part 403 and adding 45 CFR part 1331 that published on February 4, 2016 (81 FR 5917), is adopted as a final rule without change.
Dated: April 29, 2016.
Andrew M. Slavitt,

Acting Administrator, Centers for Medicare & Medicaid Services.
Dated: May 12, 2016.
Kathy Greenlee,

Administrator, Administration for Community Living.
Approved: May 26, 2016.
Sylvia M. Burwell,

Secretary, U.S. Department of Health and Human Services.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
45 CFR Parts 1385, 1386, 1387, and 1388
Administration for Community Living
45 CFR Parts 1321, 1322, 1323, 1324, 1325, 1326, 1327, and 1328
Administration for Community Living—Regulatory Consolidation

AGENCY:
Administration for Community Living (ACL), Department of Health and Human Services (HHS).

ACTION:
Final rule; technical amendments.

SUMMARY:
The Administration for Community Living (ACL) is amending its regulations to reflect the creation of ACL in 2012 and consolidate all of its regulations under a single subchapter. No substantive changes to the text of the regulations are being made by this rule.

DATES:
This final rule is effective on July 1, 2016.

FOR FURTHER INFORMATION CONTACT:
Greg Pugh, Administration for Community Living, telephone (202) 795-7422 (Voice). This is not a toll-free number. This document will be made available in alternative formats upon request. Written correspondence can be sent to Administration for Community Living, U.S. Department of Health and Human Services, 330 C St. SW., Washington, DC 20201.

SUPPLEMENTARY INFORMATION:
The Administration for Community Living (ACL) was created in 2012 by merging the HHS Administration on Aging (AoA), Administration on Intellectual and Developmental Disabilities (AIDD), and the Office of Disability (Statement of Organization Functions, and Delegations of Authority; Administration for Community Living, 77 FR 23250 (Apr. 28 2012)). This consolidation reflected these organizations' shared mission to maximize the independence, well-being, and health of older adults, people with disabilities across the lifespan, and their families and caregivers. Since the creation of ACL, a number of synergistic programs have been transferred under its purview, including the State Health Insurance Assistance Programs (SHIPs) from the Centers for Medicare and Medicaid Services (CMS) (Department of Health and Human Services Appropriations Act, 2014, Public Law 113-76 (Jan 17, 2014)) and the National Institute on Disability, Independent Living, and Rehabilitation Research (NIDILRR) and the Independent Living Administration from the Department of Education in 2014 (Workforce Investment and Opportunity Act of 2014, Public Law 113-128 (July 22, 2014)).
Many of ACL's component programs and organizations had existing regulations prior to their transfer. ACL is consolidating these regulations in a single place to streamline administration and increase access and transparency. This rule renames the Administration on Aging's subchapter C of chapter XIII, subtitle B, title 45 from “The Administration on Aging, Older Americans Programs” to “The Administration for Community Living.” It then rearranges the existing AoA rules sequentially. This rule also transfers the existing AIDD rules from subchapter I to ACL's subchapter C. Conforming edits are made throughout in order to correct internal citations.
Publication of this document constitutes final action on this change under the Administrative Procedures Act (5 U.S.C. 553). ACL has found that notice and public comment procedures are unnecessary because ACL is making a technical change merely updating the location and order of existing content.
This Final Rule will be effective July 1, 2016, in order to allow the Long Term Care Ombudsman final rule, one of the sections being renumbered within ACL's subchapter, to take effect.
Although this Final Rule contains no changes to programmatic or reporting requirements, we include the following table summarizing the changes made in order to simplify public understanding of the Final Rule:
Previous part | Previous heading | New part | New heading
45 CFR chapter XIII, subchapter C | The Administration on Aging | No change | The Administration for Community Living.
45 CFR part 1321 | Grants to State and Community Programs on Aging | No change | No change.
45 CFR part 1326 | Grants to Indian Tribes for Support and Nutrition Services | 1322 | No change.
45 CFR part 1327 | Allotments for Vulnerable Elder Rights Protection Activities | 1324 | No change.
45 CFR part 1328 | Grants for Supportive and Nutritional Services for Older Hawaiian Natives | 1323 | No change.
45 CFR part 1385 | Requirements Applicable to the Developmental Disabilities Program | 1325 | No change.
45 CFR part 1386 | Formula Grant Programs | 1326 | Developmental Disabilities Formula Grant Programs.
45 CFR part 1387 | Projects of National Significance | 1327 | Developmental Disabilities Projects of National Significance.
45 CFR part 1388 | National Network of University Centers For Excellence In Developmental Disabilities Education, Research, and Service | 1328 | No change.

List of Subjects in 45 CFR Parts 1321, 1322, 1323, 1324, 1325, 1326, 1327, 1328, 1385, 1386, 1387, and 1388
Administrative practice and procedures, Aged, Colleges and universities, Disabled, Grant programs—education, Grant programs—Indians, Grant programs—social programs, Indians, Individuals with disabilities, Legal services, Long-term care, Nutrition, Research, Reporting and recordkeeping requirements.
Dated: May 4, 2016.
Kathy Greenlee,

Administrator, Administration for Community Living.
Dated: May 26, 2016.
Sylvia M. Burwell

Secretary, U.S. Department of Health and Human Services.
For the reasons discussed in the preamble, under the authority at 5 U.S.C. 301, 42 U.S.C. 3001 et seq., and 42 U.S.C. 15001 et seq., the Department of Health and Human Services, the Administration for Community Living, and the Administration for Children and Families amend title 45, chapter XIII, subchapter C, and title 45, chapter XIII, subchapter I, respectively, as follows:

Subchapter C—The Administration for Community Living
1. The heading for 45 CFR chapter XIII, subchapter C, is revised to read as set forth above.

PARTS 1326, 1327, 1328, 1385, 1386, 1387, and 1388 [REDESIGNATED AS PARTS 1322, 1324, 1323, 1325, 1326, 1327, and 1328]
2. Parts 1326, 1327, 1328, 1385, 1386, 1387, and 1388 are redesignated as parts 1322, 1324, 1323, 1325, 1326, 1327, and 1328, respectively.

PART 1321—GRANTS TO STATE AND COMMUNITY PROGRAMS ON AGING
3. The authority citation for part 1321 continues to read as follows:

Authority:
42 U.S.C. 3001 et seq.; title III of the Older Americans Act as amended.
§ 1321.11
[Amended]
4. In § 1321.11, amend paragraph (b) by removing the reference “§ 1327.11(e)(3)” and adding in its place the reference “§ 1324.11(e)(3)”.

PART 1322—GRANTS TO INDIAN TRIBES FOR SUPPORT AND NUTRITION SERVICES
5. The authority citation for newly redesignated part 1322 continues to read as follows:

Authority:
42 U.S.C. 3001; Title VI, Part A of the Older Americans Act.
§§ 1322.3 and 1322.19
[Amended]
6. In the table below, for each section and paragraph indicated in the first two columns, remove the reference indicated in the third column and add the reference indicated in the fourth column:
Newly redesignated section | Paragraph(s) | Remove | Add
§ 1322.3 | Definition of “Budgeting period” | § 1326.19 of this part | § 1322.19.
§ 1322.3 | Definition of “Project period” | § 1326.19 of this part | § 1322.19.
§ 1322.3 | Definition of “Service area” | § 1326.9(b) | § 1322.9(b).
§ 1322.3 | Definition of “Tribal organization” | § 1326.7 | § 1322.7.
§ 1322.19 | (d)(5) | §§ 1326.7 through 1326.17 | §§ 1322.7 through 1322.17.

PART 1323—GRANTS FOR SUPPORTIVE AND NUTRITIONAL SERVICES FOR OLDER HAWAIIAN NATIVES
7. The authority citation for newly redesignated part 1323 continues to read as follows:

Authority:
42 U.S.C. 3001; Title VI Part B of the Older Americans Act.
§§ 1323.3 and 1323.19
[Amended]
8. In the table below, for each section and paragraph indicated in the first two columns, remove the reference indicated in the third column and add the reference indicated in the fourth column:
Newly redesignated section | Paragraph(s) | Remove | Add
§ 1323.3 | Definition of “Budgeting period” | § 1328.19 of this part | § 1323.19.
§ 1323.3 | Definition of “Project period” | § 1328.19 of this part | § 1323.19.
§ 1323.3 | Definition of “Service area” | § 1328.9(b) | § 1323.9(b).
§ 1323.19 | (d)(5) | §§ 1328.7 through 1328.17 | §§ 1323.7 through 1323.17.

PART 1324—ALLOTMENTS FOR VULNERABLE ELDER RIGHTS PROTECTION ACTIVITIES
9. The authority citation for newly redesignated part 1324 is revised to read as follows:

Authority:
42 U.S.C. 3001 et seq.
§§ 1324.1, 1324.11, 1324.13, 1324.15, and 1324.19
[Amended]
10. In the table below, for each section and paragraph indicated in the first two columns, remove the reference indicated in the third column and add the reference indicated in the fourth column:
Newly redesignated section | Paragraph(s) | Remove | Add
§ 1324.1 | Definition of “Representatives of the Office of the State Long-Term Care Ombudsman” | § 1327.19(a) | § 1324.19(a).
§ 1324.1 | Definition of “State Long-Term Care Ombudsman, or Ombudsman” | §§ 1327.13 and 1327.19 | §§ 1324.13 and 1324.19.
§ 1324.1 | Definition of “Willful interference” | § 1327.13 | § 1324.13.
§ 1324.1 | Definition of “Willful interference” | § 1327.19 | § 1324.19.
§ 1324.11 | (a) | § 1327.13 | § 1324.13.
§ 1324.11 | (a) | § 1327.19 | § 1324.19.
§ 1324.11 | (c) introductory text | §§ 1327.13 and 1327.19 | §§ 1324.13 and 1324.19.
§ 1324.11 | (e)(1)(i) | § 1327.13 | § 1324.13.
§ 1324.11 | (e)(2)(ii) and (iii) | §§ 1327.13 and 1327.19 | §§ 1324.13 and 1324.19.
§ 1324.11 | (e)(3)(i) | § 1327.13(e) | § 1324.13(e).
§ 1324.11 | (e)(3)(ii) introductory text | § 1327.19(b)(5) through (8) | § 1324.19(b)(5) through (8).
§ 1324.11 | (e)(3)(iv) | § 1327.19(b)(5) through (8) | § 1324.19(b)(5) through (8).
§ 1324.11 | (e)(4) introductory text and (e)(6)(i) | § 1327.21 | § 1324.21.
§ 1324.13 | (b)(1) | § 1327.11(e) | § 1324.11(e).
§ 1324.13 | (b)(2) | § 1327.19 | § 1324.19.
§ 1324.13 | (c) introductory text | § 1327.11(e)(6) | § 1324.11(e)(6).
§ 1324.13 | (c)(3) introductory text | § 1327.19 | § 1324.19.
§ 1324.15 | (b) | § 1327.11(e)(2) | § 1324.11(e)(2).
§ 1324.15 | (e) | §§ 1327.13 and 1327.19 | §§ 1324.13 and 1324.19.
§ 1324.15 | (f) | §§ 1327.11(e)(3) and 1327.13(e) | §§ 1324.11(e)(3) and 1324.13(e).
§ 1324.15 | (h) | § 1327.13(h) | § 1324.13(h).
§ 1324.15 | (i)(1)(ii) | §§ 1327.13 and 1327.19 | §§ 1324.13 and 1324.19.
§ 1324.15 | (k)(1) | § 1327.13(g) | § 1324.13(g).
§ 1324.15 | (k)(4) | § 1327.13(c)(2) | § 1324.13(c)(2).
§ 1324.15 | (k)(5) | § 1327.13(h) | § 1324.13(h).
§ 1324.19 | (b)(3) introductory text, (b)(6) introductory text, (b)(7) introductory text, and (b)(8) introductory text | § 1327.11(e)(3) | § 1324.11(e)(3).
§ 1324.21 | (d)(1) | § 1327.11(e)(4) | § 1324.11(e)(4).
§ 1324.21 | (d)(1) | § 1327.21(c) | § 1324.21(c).

PART 1325—REQUIREMENTS APPLICABLE TO THE DEVELOPMENTAL DISABILITIES PROGRAM
11. The authority citation for newly redesignated part 1325 continues to read as follows:

Authority:
42 U.S.C. 15001 et seq.
§§ 1325.1, 1325.3, 1325.6, and 1325.9
[Amended]
12. In the table below, for each section and paragraph indicated in the first two columns, remove the reference indicated in the third column and add the reference indicated in the fourth column:
Newly redesignated section | Paragraph(s) | Remove | Add
§ 1325.1 | Introductory text | § 1385.4 | § 1325.4.
§ 1325.3 | Introductory text | parts 1385 through 1388 | parts 1325 through 1328.
§ 1325.3 | Definition of “Required planning documents” | § 1386.30 | § 1326.30.
§ 1325.3 | Definition of “Required planning documents” | § 1386.22(c) | § 1326.22(c).
§ 1325.3 | Definition of “Required planning documents” | § 1388.7 | § 1328.7.
§ 1325.6 | Last sentence of paragraph | subpart E of 45 CFR part 1386 | subpart E of 45 CFR part 1326.
§ 1325.9 | (a) introductory text | parts 1386 and 1388 | parts 1326 and 1328.

PART 1326—DEVELOPMENTAL DISABILITIES FORMULA GRANT PROGRAMS
13. The authority citation for newly redesignated part 1326 continues to read as follows:

Authority:
42 U.S.C. 15001 et seq.
14. The part heading for newly redesignated part 1326 is revised to read as set forth above.
§§ 1326.21, 1326.26, 1326.93, and 1326.94
[Amended]
15. In the table below, for each section and paragraph indicated in the first two columns, remove the reference indicated in the third column and add the reference indicated in the fourth column:
Newly redesignated section | Paragraph(s) | Remove | Add
§ 1326.21 | (c) | § 1386.23(c) | § 1326.23(c).
§ 1326.26 | First sentence of paragraph | § 1386.25 | § 1326.25.
§ 1326.93 | (e) | § 1386.90 | § 1326.90.
§ 1326.94 | (b)(2) introductory text | § 1386.85(b) | § 1326.85(b).

PART 1327—DEVELOPMENTAL DISABILITIES PROJECTS OF NATIONAL SIGNIFICANCE
16. The authority citation for newly redesignated part 1327 continues to read as follows:

Authority:
42 U.S.C. 15001 et seq.
17. The part heading for newly redesignated part 1327 is revised to read as set forth above.

PART 1328—THE NATIONAL NETWORK OF UNIVERSITY CENTERS FOR EXCELLENCE IN DEVELOPMENTAL DISABILITIES, EDUCATION, RESEARCH, AND SERVICE
18. The authority citation for newly redesignated part 1328 continues to read as follows:

Authority:
42 U.S.C. 15001 et seq.
§§ 1328.2, 1328.3, and 1328.5
[Amended]
19. In the table below, for each section and paragraph indicated in the first two columns, remove the reference indicated in the third column and add the reference indicated in the fourth column:
Newly redesignated section | Paragraph(s) | Remove | Add
§ 1328.2 | (a)(2) | § 1388.3 | § 1328.3.
§ 1328.2 | (a)(2) | § 1385.3 | § 1325.3.
§ 1328.2 | (b) | § 1388.4 | § 1328.4.
§ 1328.3 | Introductory text | § 1388.2 | § 1328.2.
§ 1328.5 | (a) | § 1388.2 | § 1328.2.
§ 1328.5 | (b)(1) | § 1385.3 | § 1325.3.
§ 1328.5 | (c)(3) | § 1388.2(a)(1) and (2) | § 1328.2(a)(1) and (2).

Subchapter I [Removed and Reserved]
20. 45 CFR chapter XIII, subchapter I, is removed and reserved.
DEPARTMENT OF HOMELAND SECURITY
Coast Guard
46 CFR Part 10
[Docket No. USCG-2016-0029]
Change-2 to Navigation and Vessel Inspection Circular 04-08: Medical Certification Standards, Medications, and Medical Review Process

AGENCY:
Coast Guard, DHS.

ACTION:
Notice of policy; availability.

SUMMARY:
The Coast Guard announces the availability of Change-2 to Navigation and Vessel Inspection Circular (NVIC) 04-08, “Medical and Physical Evaluation Guidelines for Merchant Mariner Credentials” (NVIC 04-08). Change-2 to NVIC 04-08 contains revisions to Enclosure (1) Medical Certification Standards, Enclosure (4) Medications, and Enclosure (6) Medical Review Process. The revisions to Enclosures (1) and (6) reflect process and procedural changes related to centralization of the evaluation of credential applications at the National Maritime Center and implementation of the final rule that aligned Coast Guard regulations with amendments to the International Convention on Standards of Training, Certification and Watchkeeping for Seafarers and made changes to national endorsements. The revisions to Enclosure (4) provide more detailed guidance on medications that are subject to further review, and address comments received in response to a notice published in the Federal Register on January 28, 2015 seeking input from the public on this issue.

DATES:
Change-2 to NVIC 04-08 is in effect on June 3, 2016.

ADDRESSES:
Submit comments online at http://www.regulations.gov in accordance with Web site instructions.

FOR FURTHER INFORMATION CONTACT:
If you have questions on this document, call or email LCDR Ian Bird, Office of Commercial Vessel Compliance (CG-CVC), 202-372-1255, email MMCPolicy@uscg.mil.

SUPPLEMENTARY INFORMATION:

Viewing Documents
Navigation and Vessel Inspection Circular (NVIC) 04-08 is available on the Internet at: http://www.uscg.mil/hq/cg5/nvic/pdf/2008/NVIC%2004-08%20CH%201%20with%20Enclosures%2020130607.pdf. It can also be viewed on the Coast Guard's Web site at: www.uscg.mil/nmc.

Background
Coast Guard regulations contained in 46 CFR part 10, subpart C, contain the medical and physical standards that merchant mariner applicants must meet prior to being issued a merchant mariner medical certificate. NVIC 04-08 provides guidance to the regulated community on how to comply with the regulations pertaining to medical and physical qualifications for merchant mariners.
On December 24, 2013, the Coast Guard published a final rule in the Federal Register (78 FR 77796) entitled “Implementation of the Amendments to the International Convention on Standards of Training, Certification and Watchkeeping for Seafarers, 1978, and Changes to National Endorsements.” It amended 46 CFR parts 1, 10, 11, 12, 13, and 15 to implement the International Convention on Standards of Training, Certification and Watchkeeping for Seafarers, 1978 (STCW Convention), including the 2010 amendments to the STCW Convention, and the Seafarers' Training, Certification and Watchkeeping Code, as well as updating requirements for national endorsements. The final rule also established the merchant mariner medical certificate as a document issued independently of the merchant mariner credential. Merchant mariner credentials issued after January 24, 2014, and that require a general medical examination are not valid for service unless accompanied by a valid medical certificate. Enclosures (1) and (6) of NVIC 04-08 required revision to reflect changes implemented with the final rule and a reorganization of the mariner credentialing function.
Guidance on medication use contained in Enclosure (4) to NVIC 04-08 prior to Change-2 noted that use of certain medications was considered disqualifying for issuance of credentials. The guidance did not provide details on the types of medications that might lead to denial of a medical certificate, nor did it provide discussion of the information and criteria that the Coast Guard considers in determining whether to issue a waiver for certain medications.
In developing this policy, the Coast Guard sought recommendations from the Merchant Mariner Medical Advisory Committee (MEDMAC) on waiver considerations for mariner applicants whose conditions require the use of potentially impairing medications while operating under the authority of the credential. In response to Coast Guard Task Statement 14-09, Medical Evaluation of Merchant Mariners Treated with Potentially Impairing Medications, MEDMAC recommended that medications with central nervous depressant effects, such as opioid, benzodiazepine, or non-benzodiazepine medications, be considered disqualifying and generally not waiverable. They also recommended that the following medications be determined disqualifying: medications that impair vision, anticoagulants, anti-metabolites and cancer treatments, sedating anti-histamines, antipsychotics, opioid-like analgesics, anti-seizure medications, and stimulant medications, such as amphetamine and methylphenidate. MEDMAC's recommendations did not include specific criteria for waiver consideration for mariners whose conditions require the use of potentially impairing medication while operating under the authority of the credential.
On January 28, 2015, the Coast Guard published a notice in the Federal Register requesting public comments on a proposed revision to Enclosure (4) that would provide more in-depth guidance on these issues (80 FR 4582).
We summarize the policy contained in Change-2 to NVIC 04-08 and address the public comments received on the proposed revision to Enclosure (4) below.

Discussion
Enclosure (1) and Enclosure (6). The revised Enclosure (1) Medical Certification Standards summarizes the medical and physical requirements for mariner endorsements and provides additional guidance regarding the medical certificate. The revision to Enclosure (6) provides guidance on the medical review process used to determine if a mariner meets the medical and physical standards for issuance of a medical certificate.
Enclosure (4)—Medications. The revision to Enclosure (4) provides guidance to the regulated community on medications that may be deemed disqualifying for issuance of a medical certificate due to risks of impairment or other safety concerns. The new guidance also clarifies the extenuating circumstances related to the use of potentially impairing medications that the Coast Guard weighs in evaluating risks to public and maritime safety, and in determining suitability for a medical waiver. The revised enclosure additionally provides a safety warning to mariners advising them to refrain from operating under the authority of the credential when they are under the influence of any medication that can cause drowsiness, or impair cognitive ability, judgment, or reaction time. The revised guidance for mariners seeking a waiver to use potentially impairing medications while operating under the authority of the credential follows.

I. Medication Waivers Requiring Special Consideration
Medications that may impair cognitive ability, judgment or reaction time are considered disqualifying for issuance of credentials. The underlying condition, as well as the effects of the medications, may lead to denial of a medical certificate or may result in issuance of a waiver.
Due to the documented risks of impaired cognition, judgment, and reaction time associated with the use of certain legally prescribed controlled substances; the Coast Guard has determined that use of these medications while acting under the authority of the credential generally will not be waived. These medications include, but are not limited to opioid/opiate medications, benzodiazepine medications, non-benzodiazepine sedative hypnotic medications, and barbiturate medications. However, waivers may be considered, on a case-by-case basis, if the Coast Guard determines that there are exceptional circumstances that warrant consideration for a waiver.
Exceptional Circumstances. The criteria for waiver consideration for applicants seeking to use, or be under the influence of, medications that may impair their cognitive ability, judgment, or reaction time, while acting under the authority of the credential, are listed below. Applicants unable to meet all of the criteria are only considered for a waiver under extraordinary circumstances, if the Coast Guard deems the risk of impairment to be sufficiently low. The criteria follow.
1. The mariner was previously granted a waiver allowing use of the same medication while working under the authority of the credential, where the credential was of the same scope of authority.
2. The mariner demonstrated compliance with all terms of the prior waiver.
3. There were no accidents or other safety concerns related to medication, judgment, cognitive ability, or reaction time during the course of the prior waiver period(s).
4. The mariner has been on a stable medication regimen for a minimum of 2 years, as documented by the treating physician and pharmacy records.
a. Mariners who have required periodic increases in medication dosing during the preceding 2-year period would not meet this criterion.
b. Mariners who have consistently or periodically supplemented their medication regimen with other disqualifying medications during the 2-year period are not likely to be considered as meeting this criterion. For example, an individual who has been on a stable dose of one opioid pain medication for 2 years, but has also periodically taken or filled prescriptions for an opioid cough medication during that same time period, would not be considered as being on a stable dose of medicine.
c. Mariners whose medication dose has been decreased or tapered off, without subsequent dose increase, may be considered as meeting this criterion.
5. The mariner is not seeking to use, or be under the influence of, more than one medication with risk for impairment while working under the authority of the credential.
6. The mariner's treating physician provides written assessment that adequately addresses all information requested in the section on Recommended Evaluation Data for Medication Waivers Requiring Special Consideration, and that supports a determination that the mariner is at low risk for medication impairment based upon objective testing and standard evaluation tools.
7. When requested, formal neuropsychological/neurocognitive testing, performed as outlined in the section providing guidance on formal neuropsychological/neurocognitive evaluation, documents the absence of significant medication impairment.
8. The mariner does not use any other medications or have any other medical conditions, which may alone, or in combination, adversely affect the mariner's fitness.
9. Use of methadone may not be waived under any circumstances.
The risk presented by the mariner's position may be considered in determining whether to grant a waiver. Because of the wide-range of operational conditions, it is impossible to set out in advance which positions may be suitable for a waiver. The Coast Guard retains final authority for the issuance of waivers. Waivers may include restrictions and/or operational limitations on the credential.
Recommended Evaluation Data for Medication Waivers Requiring Special Consideration. Applicants seeking consideration for a medication waiver for the use of medications that may impair cognitive ability, judgment, or reaction time, while acting under the authority of the credential, should submit the additional information detailed below, for each medication.
1. A letter from the prescribing and/or treating physician that includes the following:
a. Whether the physician has familiarized himself/herself with the detailed guidelines on medical conditions and medications contained in NVIC 04-08.
b. Whether the physician understands the safety-sensitive nature of the credential and the specialized shipboard environment.
c. A detailed discussion of the condition that requires the use of the potentially impairing medication.
d. A description of any known complications experienced by the mariner from the use of a particular medication, level of current stability, and prognosis of the underlying condition. The physician should also provide his or her professional opinion on whether the condition is suitable for safety-sensitive work.
e. A description of the dosage and frequency of use of the medication (this description should be very specific; “as needed” is not sufficient information). The description should also reflect that the physician has reviewed the mariner's pharmacy records for documentation of the number of pills dispensed for use each month and documentation of the length of time that the mariner has been on the medication.
f. A detailed statement about whether the mariner is taking the medication as directed, and if there are any concerns of misuse or overuse of the medication.
g. A statement about whether the mariner is compliant with therapy and follow-up appointments.
h. A statement about whether the mariner requires use of this medication while at work, or while aboard the vessel. If the mariner requires use of the potentially impairing medication while at work or while aboard the vessel, the physician should provide a detailed explanation and rationale for the use.
i. A statement about whether the physician has advised the mariner of the risks of impairment related to the medication. The physician should also discuss any risks advised, as well as any instructions discussed with the mariner for mitigating risk.
j. A statement about whether the mariner's other medications, medical conditions, and work/sleep conditions might compound the impairing effects of this medication. This discussion should reflect that the physician has knowledge of the specifics of the mariner's medications, medical conditions, and work/sleep schedule.
k. A statement about whether the physician has formally evaluated the mariner for the presence of any impairing medication effects. This discussion should include a description of the method of evaluation utilized, as well as the findings.
l. A medical opinion of whether the mariner has any medication effects that would impede safe operation of a vessel or interfere with work in a safety sensitive position. This discussion should include the rationale for the physician's opinion.
m. A statement of whether the physician has advised the mariner that it is safe to operate a vessel, operate hazardous machinery, and perform safety sensitive functions while under the influence of this medication.
2. When specifically requested by the reviewing authority, additional amplifying information, to include a formal neuropsychological/neurocognitive evaluation.
a. In particular, mariners seeking waivers to use or be under the influence of potentially impairing opioid/opiate, benzodiazepine, sedative hypnotic, and/or barbiturate medications, while acting under the authority of the credential, may be asked to submit the results of a formal neuropsychological/neurocognitive evaluation.
b. The Coast Guard will not normally request a neuropsychological/neurocognitive evaluation unless the applicant meets all other requirements for waiver consideration. This is to prevent mariners from undergoing costly testing when issuance of a waiver is unlikely.
c. Mariners are advised that submission of neuropsychological/neurocognitive evaluation results does not guarantee issuance of a waiver.
d. When a formal neuropsychological/neurocognitive evaluation is requested, the assessment should include objective assessment of the following functions, at a minimum:
(1) Alertness, arousal, and vigilance;
(2) Attention (focused, shifting, and divided), processing speed, and working memory;
(3) Reaction time (choice and complex), psychomotor function, upper motor speed, and coordination;
(4) Sensory perceptual function;
(5) Executive function: mental flexibility, adaptive problem solving, abstract reasoning, impulse control, risk taking/risk assessment, organizational ability (including visual spatial organization), and planning;
(6) Memory; and
(7) Communication skills.
e. When a formal neuropsychological/neurocognitive evaluation is requested, the evaluation and narrative interpretation must be provided by a neuropsychologist who is board-certified and licensed in the United States.
f. The report of the formal neuropsychological/neurocognitive evaluation should also include:
(1) Documentation of witnessed administration of the medication in question by a licensed medical provider; and
(2) Documentation of the time interval between ingestion of the medication and administration of the neuropsychological/neurocognitive testing battery.

II. Safety Warning for Mariners
Certain medications, whether prescription or over-the-counter, have known impairing effects and their labels warn about the risk of drowsiness and caution against use while driving or operating hazardous machinery.
The nature of shipboard life and shipboard operations is such that mariners may be subject to unexpected or emergency response duties associated with vessel or crew safety, and prevention of pollution and maritime security at any time while aboard a vessel.
In the interest of safety of life and property at sea, the Coast Guard views shipboard life and the attendant shipboard duties that can arise without warning, as safety sensitive duties that are analogous to operating hazardous machinery. As such:
1. Mariners are advised to discuss all medication use with their treating providers and to inform them of the safety sensitive nature of their credential; and
2. Mariners are cautioned against acting under the authority of their credential while under the influence of medications that:
a. Can cause drowsiness; or
b. Can impair cognitive ability, judgment, or reaction time; or
c. Can carry warnings that caution against driving or operating heavy machinery.
3. Mariners are advised that they are considered to be acting under the authority of the credential anytime they are aboard a vessel in a situation to which 46 CFR 5.57(a) applies, even when off-watch or while asleep.

Public Comments on the Proposed Revision to the Medication Policy, Enclosure (4) to NVIC 04-08
The Coast Guard's notice sought general comments on whether the proposed revision to Enclosure (4) adequately addresses safety concerns regarding merchant mariners whose medical conditions require use of potentially impairing medication. The Coast Guard received 13 comment letters in response.
The majority of commenters expressed general agreement with the proposed policy clarification, noting that it provides a case-by-case or individualized assessment of a mariner applicant's condition, instead of imposing a blanket denial for all mariner applicants who require the use of potentially impairing medications, while operating under the authority of the credential. The Coast Guard notes that even prior to Change-2, NVIC 04-08 provided for a case-by-case evaluation of each applicant's condition. The additional specificity of the guidance and criteria included in Change-2 will help provide a consistent framework for those evaluations.
One commenter suggested that the guidance in the proposed policy be made enforceable by incorporating it into regulation. This same commenter also recommended that the guidance include a requirement for mariners to inform vessel owners/operators when they are under the influence of prescription or over-the-counter medications. The Coast Guard disagrees with both comments. First, the purpose of this proposed policy is not to regulate, but instead, to provide guidance to the regulated community on how the Coast Guard evaluates mariners who require the use of certain medications. The policy provides the framework for individualized assessment and allows flexibility for consideration of factors specific to each affected mariner. On the issue of requiring mariners to inform vessel owners/operators about their medications, the Coast Guard does not have any statutory authority to enact such a requirement.
Two commenters disagreed with the policy clarification, arguing that it is overly restrictive in that it presumes that all mariners on the medications are impaired and does not give sufficient deference to the opinion of the treating physician. The Coast Guard notes that the policy is stringent, but holds that it strikes an adequate balance that includes strong consideration of the treating physician's opinion along with objective assessment for signs of impairment. Because of the safety sensitive nature of the medical certificate, the Coast Guard contends that neither mariner self-assessment, nor provider limited office-based assessment, is sufficient to rule out the risk of significant cognitive impairment in cases where the mariner seeks to use medications with known risk of impairment while operating under the authority of their credential. The Coast Guard notes that this opinion was also shared by all of the medical professionals who provided comment on the policy. They all agreed that the treating provider's office assessment would not be sufficient to ensure that a mariner applicant was free of impairing medication effects when using medications of this type.
Three commenters opposed the proposed policy clarification, arguing that the Coast Guard should never issue waivers for mariners who require the use of potentially impairing medications, while operating under the authority of the credential, regardless of the circumstances. The Coast Guard acknowledges that individuals who use potentially impairing medications may suffer impairment, but finds that there is no evidence to support a conclusion that all individuals will uniformly suffer impairment. On this basis, the Coast Guard disagrees with imposing a new, blanket exclusion against all mariners who require the use of potentially impairing medication while operating under the authority of the credential. The merchant mariner medical regulations contained in 46 CFR part 10, subpart C, do not prohibit the use of legally prescribed medications, to include opioids, benzodiazepines, and non-benzodiazepine sedative hypnotics; and NVIC 04-08 has always provided for an individualized assessment of mariner applicants.
The Coast Guard additionally emphasizes that the proposed policy clarification is not a change in policy; rather, it provides the regulated community with specificity and outlines the factors that the Coast Guard will consider during the individualized assessment of mariner applicants who require the use of potentially impairing medications, while operating under the authority of the credential. The individualized assessment considers whether the specifics of an applicant's medical condition, medical history, medication use, and cognitive functioning indicate a low likelihood of impairment, or indicate findings that suggest impairment. The Coast Guard contends that the policy clarification contained in Change-2 to NVIC 04-08 adequately strikes a balance between potential safety concerns and putting mariners out of work unnecessarily, and that individuals who meet all of the criteria outlined in this policy are at low enough risk to warrant consideration for a medical waiver. A blanket exclusion of mariner applicants who meet all of these criteria would likely put mariners out of work without sufficient cause.
One commenter recommended that the Coast Guard provide stronger guidance for over-the-counter anti-motion sickness agents, noting that some of these agents are so sedating that they are sometimes used to induce sleep. The Coast Guard agrees and included a safety warning for use of anti-motion sickness agents that cause drowsiness or impairment.
One commenter argued that the proposed policy clarification's requirement for mariners to report all over-the-counter medications taken is confusing and unnecessarily broad. The commenter noted that while the current medication guidance only requires reporting of over-the-counter medications that were taken for a period of 30 days or more, the proposed guidance suggests that mariners would be held accountable if they did not remember to report even a single dose of a vitamin or fiber tablet taken. The Coast Guard acknowledges that the proposed language on medication disclosure may cause unnecessary concern and confusion. The language in the proposed policy was revised, therefore, to retain the language from the current guidance document regarding the disclosure of over-the-counter medications. The revised language reads: mariner applicants need only report over-the-counter medications that were taken for a period of 30 days or more, within the 90 days prior to the date that the applicant signs the application to the Coast Guard.
Regarding the use of neuropsychological/neurocognitive evaluation, two commenters asserted that the Coast Guard should require neuropsychological/neurocognitive evaluation for all mariners seeking to use potentially impairing medication, while operating under the authority of the credential. Another commenter agreed that such testing would be useful, but contended that such testing would be time and cost prohibitive. Two commenters opposed requiring neuropsychological/neurocognitive evaluations for all applicants in this category because they deemed it unnecessary and expensive. The Coast Guard agrees that while it might be ideal to review neuropsychological/neurocognitive evaluation results for all mariner applicants who seek to use potentially impairing medications when operating under the authority of the credential, such testing may not be necessary in all cases. Therefore, the Coast Guard has retained the wording from the proposed policy indicating that a neuropsychological/neurocognitive evaluation need only be provided when requested by the Coast Guard, as part of the individualized assessment.
Another commenter argued that the Coast Guard would not be able to implement a process to request neuropsychological/neurocognitive evaluation on the basis that testing is time-consuming and expensive, and that there are no objective neurocognitive evaluation tools that are readily available to primary care providers. The Coast Guard agrees that neuropsychological/neurocognitive evaluation may be expensive and time consuming and that the associated evaluation tools are not readily available to primary care providers. However, we disagree with the assertion that their use is not warranted in certain situations. Such a situation may occur during the course of conducting an individualized assessment. Without information from a neuropsychological/neurocognitive evaluation, the evaluator is left to presume the presence or absence of medication impairment based upon limited information. To presume that an applicant is impaired by their medication and deny them medical certification when no impairment truly exists, may result in extraordinary costs for the mariner applicant, including loss of employment, with resultant loss of home and healthcare. Alternatively, to assume that no medication impairment exists when a mariner applicant is actually experiencing impairment, may result in unacceptably high costs to public and maritime safety, should a maritime casualty result. It is important to note that this section of the proposed policy describes the information that the Coast Guard will consider when determining whether extenuating circumstances exist that warrant consideration for a medical waiver for mariners seeking to use potentially impairing medications, while operating under the authority of the credential. As is often the case for any medical condition that is disqualifying and generally not approved for waiver, the evaluation to determine extenuating circumstances may often require assessment and testing that is beyond the scope of the primary care provider. When formal neuropsychological/neurocognitive evaluation is requested as part of the individualized assessment for use of impairing medications, while operating under the authority of the credential, the Coast Guard fully expects that this evaluation will be performed by a specialist trained to perform such evaluations. The Coast Guard also notes that while this testing may be time-consuming and expensive, a formal neuropsychological/neurocognitive evaluation can provide critical documentation on the presence or absence of impairing medication effects for those mariners seeking to use potentially impairing medication, while operating under the authority of the credential. When the Coast Guard determines that a formal neuropsychological/neurocognitive evaluation is needed, the results of the assessment will be considered in the context of the other extensive medical documentation provided to determine whether extenuating circumstances exist that warrant special consideration for a medical waiver. The decision of whether such testing is too time-consuming or too expensive will ultimately be left up to the individual mariner who seeks to demonstrate extenuating circumstances.
On the question of which neuropsychological/neurocognitive functions should be measured, and the appropriate standard for test outcome, one commenter opined that such a determination would require further substantial research on individual job requirements. Another commenter recommended that the Coast Guard add memory and communication skills to the proposed list of neuropsychological/neurocognitive domains, to make the overall panel similar to that used by the Federal Aviation Administration. Another commenter recommended that a witness observe the mariner applicant taking the medication in question prior to the administration of the neuropsychological/neurocognitive evaluation. The Coast Guard considered all of these comments and noted that there are already well-established, validated testing measures for various domains of neuropsychological/neurocognitive functioning. Additionally, other modes of transportation have identified specific neuropsychological/neurocognitive domains that are critical for tasks such as flying an airplane or for driving a motor vehicle. The neuropsychological/neurocognitive functions identified for evaluation in the proposed policy reflect those functions recommended as critical for safe motor vehicle driving. In consideration of the public comments, the current policy has been revised to include testing of memory and communication skills as required elements of the neuropsychological/neurocognitive evaluation, when such testing is requested by the Coast Guard. The current policy also specifies that medication administration should be witnessed and documented by a provider prior to the conduct of neuropsychological/neurocognitive evaluation, when such testing is requested by the Coast Guard.

Authority
This document is issued under the authority of 5 U.S.C. 552(a), 46 U.S.C. 7101 et seq., 46 CFR part 10, subpart C, and Department of Homeland Security Delegation No. 0710.1.
V.B. Gifford,

Captain, U.S. Coast Guard, Director of Inspections & Compliance.
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 73
[MB Docket No. 16-29; RM-11758; DA 16-543]
Television Broadcasting Services; Scottsbluff, Nebraska and Sidney, Nebraska

AGENCY:
Federal Communications Commission.

ACTION:
Final rule.

SUMMARY:
At the request of Gray Television License, LLC, licensee of station KDUH-TV, Channel 7, Scottsbluff, Nebraska, and New Rushmore Radio, Inc., former licensee of KDUH-TV (collectively, Petitioners), the Commission has before it an unopposed Notice of Proposed Rulemaking seeking to amend the Post-Transition Table of DTV Allotments to delete channel 7 at Scottsbluff, Nebraska and to substitute channel 7 at Sidney, Nebraska. Petitioners further request modification of KDUH-TV's license to specify Sidney as the station's community of license. Petitioners assert that their proposal to reallot channel 7 to Sidney is based on the technical specifications currently authorized for KDUH-TV and, therefore, the new allotment will be mutually exclusive with the station's existing allotment. Petitioners further state that their proposal would meet the Commission's allotment priorities by providing Sidney with its first local television service. and that Scottsbluff would remain well-served after the proposed reallotment because full-power television station KSTF(TV), channel 29, would remain licensed to that community.

DATES:
Effective July 5, 2016.

FOR FURTHER INFORMATION CONTACT:
Adrienne Denysyk, Adrienne.Denysyk@fcc.gov, Media Bureau, (202) 418-2651.

SUPPLEMENTARY INFORMATION:
This is a synopsis of the Commission's Report and Order, MB Docket No. 16-29, adopted and released May 16, 2016. The full text of this document is available for public inspection and copying during normal business hours in the FCC's Reference Information Center at Portals II, CY-A257, 445 12th Street SW., Washington, DC, 20554. This document will also be available via ECFS ( http://fjallfoss.fcc.gov/ecfs/ ). To request materials in accessible formats for people with disabilities (braille, large print, electronic files, audio format), send an email to fcc504@fcc.gov or call the Consumer & Governmental Affairs Bureau at 202-418-0530 (voice), 202-418-0432 (tty).
This document does not contain information collection requirements subject to the Paperwork Reduction Act of 1995, Public Law 104-13. In addition, therefore, it does not contain any information collection burden “for small business concerns with fewer than 25 employees,” pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, see 44 U.S.C. 3506(c)(4). Provisions of the Regulatory Flexibility Act of 1980, see 5 U.S.C. 601-612, do not apply to this proceeding.
The Commission will send a copy of this Report and Order in a report to be sent to Congress and the Government Accountability Office pursuant to the Congressional Review Act, see 5 U.S.C. 801(a)(1)(A).

List of Subjects in 47 CFR Part 73
Television.
Federal Communications Commission.
Thomas Horan,

Chief of Staff, Media Bureau.

Final Rule
For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 73 as follows:

PART 73—RADIO BROADCAST SERVICES
1. The authority citation for part 73 continues to read as follows:

Authority:
47 U.S.C. 154, 303, 334, 336, and 339.
§ 73.622
[Amended]
2. Amend § 73.622(i), the Post-Transition Table of DTV Allotments under Nebraska, by removing channel 7 at Scottsbluff and adding, in alphabetical order, Sidney, channel 7.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
50 CFR Part 660
[Docket No. 031125294-4091-02]
RIN 0648-XE621
Fisheries Off West Coast States; the Highly Migratory Species Fishery; Closure

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

ACTION:
Temporary rule; closure.

SUMMARY:
NMFS is prohibiting fishing with large-mesh drift gillnet (DGN) gear (>14 inches mesh) off the coast of southern California east of 120° W. meridian from June 1, 2016, through August 31, 2016. This prohibition is based on the Assistant Administrator for Fisheries' (AA's) determination that El Niño conditions are occurring off the coast of southern California. This action protects Endangered Species Act-listed loggerhead sea turtles ( Caretta caretta ), specifically the endangered North Pacific Ocean Distinct Population Segment.

DATES:
Effective 12:01 a.m. Pacific Daylight Time (PDT), June 1, 2016, through 11:59 p.m. PDT, August 31, 2016.

FOR FURTHER INFORMATION CONTACT:
Keith Shattenkirk, West Coast Region (WCR), NMFS, (562) 980-3248, keith.shattenkirk@noaa.gov.

SUPPLEMENTARY INFORMATION:
The DGN fishery is managed under the Fishery Management Plan for U.S. West Coast Fisheries for Highly Migratory Species (50 CFR part 660, subpart K) and occurs off the coast of California. NMFS regulations provide that no person may fish with, set, or haul back drift gillnet gear in U.S. waters of the Pacific Ocean east of the 120° W. meridian from June 1 through August 31 during a forecasted, or occurring, El Niño event off the coast of southern California (50 CFR 660.713(c)(2)). This area, which falls within the Southern California Bight (SCB), is referred to in the regulations as the “Pacific loggerhead conservation area.”
Under 50 CFR 660.713(c)(2)(ii), the AA is to rely on information developed by NOAA offices (the Climate Prediction Center (CPC) and the West Coast Office of the Coast Watch program) to make the determination that an El Niño event is forecasted or occurring off southern California. The AA is to use monthly sea surface temperature (SST) charts to determine whether there are warmer-than-normal SSTs off southern California “during the months prior to the closure months for years in which an El Niño event has been declared” by the CPC. Specifically, the AA is to use SST data from the third and second months prior to the month of closure.
NMFS published these regulations to protect loggerhead sea turtles, which are listed under the Endangered Species Act. The regulations addressed a reasonable and prudent alternative (RPA) included in NMFS' 2000 biological opinion on issuance of an incidental take permit under the Marine Mammal Protection Act. The biological opinion concluded that bycatch in the DGN fishery was likely to jeopardize the continued existence of loggerhead sea turtles and, as an RPA, recommended the fishery be closed during the summer months when El Niño conditions are present to avoid the likelihood of jeopardy.
On March 5, 2015, the CPC issued an El Niño Advisory, declaring that El Niño conditions were present in equatorial waters. Since that initial advisory, all monthly CPC updates have stated that El Niño conditions remain in these waters. The May 12, 2016, update reaffirmed El Niño conditions are currently present.
In May 2016, NMFS staff reviewed the SST anomalies in the SCB during March and April of 2016, relying on SST maps available through NOAA's Coast Watch program (for details see http://coastwatch.pfeg.noaa.gov/erddap/index.html ). These maps indicated that SSTs were above normal in the SCB. NMFS concluded that a determination of El Niño conditions off southern California is warranted based on SSTs that are warmer than normal during the third and second months prior to the month of the closure, consistent with regulations at 50 CFR 660.713(c)(2)(ii).
If SSTs return to normal or below normal during a closure period, regulations at 50 CFR 660.713(c)(2)(iii) state that the AA may re-open the fishery after publishing a Federal Register notice announcing that El Niño conditions are no longer present in the SCB.

Classification
This action is required by regulations at 50 CFR 660.713 and is exempt from Office of Management and Budget review under Executive Order 12866.
NMFS finds good cause to waive the requirement to provide prior notice and opportunity for public comment pursuant to the authority set forth at 5 U.S.C. 553(b)(B) for the time-area closure of the DGN fishery. Notice and comment procedures are impracticable and contrary to the public interest. The most recent El Niño determination occurred on May 12, 2016, and regulations require that the closure period begin on June 1; therefore, there is insufficient time for notice and comment procedures. For the same reasons, NMFS also finds good cause under 5 U.S.C. 553(d)(3) to waive the general requirement for a 30-day delay in effectiveness for this action. This measure is based upon the best available information and is necessary for the conservation of loggerhead sea turtles. The closure period anticipated by the regulation ends, at the latest, on August 31, 2016. A delay in effectiveness may allow the fishery to interact with and injure or kill loggerhead sea turtles that may occur within the SCB during the time period in which the regulation was intended to protect loggerheads.

Authority:
16 U.S.C. 1801 et seq.
Dated: May 27, 2016.
Samuel D. Rauch III,

Deputy Assistant Administrator for Regulatory Programs, National Marine Fisheries Service.
81
107
Friday, June 3, 2016
Proposed Rules
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 29
[Docket No. FAA-2016-6940; Notice No. 29-039-SW-SC]
Special Conditions: Bell Helicopter Textron, Inc. (BHTI), Model 525 Helicopters; Crew Alerting System (CAS)

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Notice of proposed special conditions.

SUMMARY:
We propose special conditions for the BHTI Model 525 helicopter. This helicopter will have a novel or unusual design feature associated with the electronic CAS. The applicable airworthiness regulations do not contain adequate or appropriate safety standards for this design feature. These proposed special conditions contain the additional safety standards that the Administrator considers necessary to establish a level of safety equivalent to that established by the existing airworthiness standards.

DATES:
Send your comments on or before July 18, 2016.

ADDRESSES:
Send comments identified by docket number FAA-2016-6940 using any of the following methods:
• Federal eRegulations Portal: Go to http://www.regulations.gov and follow the online instructions for sending your comments electronically.
• Mail : Send comments to Docket Operations, M-30, U.S. Department of Transportation (DOT), 1200 New Jersey Avenue SE., Room W12-140, West Building Ground Floor, Washington, DC, 20590-0001.
• Hand Delivery of Courier: Take comments to Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue, SE., Washington, DC, between 8 a.m., and 5 p.m., Monday through Friday, except Federal holidays.
• Fax: Fax comments to Docket Operations at 202-493-2251.
Privacy: The FAA will post all comments it receives, without change, to http://www.regulations.gov, including any personal information the commenter provides. Using the search function of the docket Web site, anyone can find and read the electronic form of all comments received into any FAA docket, including the name of the individual sending the comment (or signing the comment for an association, business, labor union, etc.). DOT's complete Privacy Act Statement can be found in the Federal Register published on April 11, 2000 (65 FR 19477-19478), as well as at http://DocketsInfo.dot.gov.
Docket: Background documents or comments received may be read at http://www.regulations.gov at any time. Follow the online instructions for accessing the docket or go to the Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m., and 5 p.m., Monday through Friday, except Federal holidays.

FOR FURTHER INFORMATION CONTACT:
Martin R. Crane, Aviation Safety Engineer, Safety Management Group, Rotorcraft Directorate, FAA, 10101 Hillwood Pkwy, Fort Worth, TX 76177; telephone (817) 222-5110; email martin.r.crane@faa.gov.

SUPPLEMENTARY INFORMATION:

Comments Invited
We invite interested people to take part in this rulemaking by sending written comments, data, or views. The most helpful comments reference a specific portion of the special conditions, explain the reason for any recommended change, and include supporting data.
We will consider all comments we receive on or before the closing date for comments. We will consider comments filed late if it is possible to do so without incurring expense or delay. We may change these special conditions based on the comments we receive.

Background
On December 15, 2011, BHTI applied for a type certificate for a new transport category helicopter designated as the Model 525. The aircraft is a medium twin-engine rotorcraft. The design maximum takeoff weight is 20,000 pounds, with a maximum capacity of 16 passengers and a crew of 2.
BHTI proposes that the Model 525 use a novel and unusual design feature, which is an electronic CAS. Section 29.1322 of title 14, Code of Federal Regulations (14 CFR), prescribes discrete colored lights for warning, caution, and advisory alerts. In this regard, § 29.1322 lacks adequate airworthiness standards for alerting messages and displays that do not use discrete colored lights, that include non-visual cues, that provide alerting information to the flightcrew, and that use integrated and multiple alerts concurrently.
The Model 525 CAS will have more effective integrated visual, aural, tactile, and alert messaging that will require special airworthiness standards, known as special conditions, to address crew alerting of failures or malfunctions in critical systems. These special conditions will add requirements from the airworthiness standards in § 25.1322 (Amendment 25-131) for advanced crew alerting systems in transport category aircraft.

Type Certification Basis
Under the provisions of 14 CFR 21.17, BHTI must show that the Model 525 meets the applicable provisions of part 29, as amended by Amendments 29-1 through 29-55 thereto. The BHTI Model 525 certification basis date is December 15, 2011, the date of application to the FAA.
If the Administrator finds that the applicable airworthiness regulations ( i.e., 14 CFR part 29) do not contain adequate or appropriate safety standards for the BHTI Model 525 because of a novel or unusual design feature, special conditions are prescribed under the provisions of § 21.16.
Special conditions are initially applicable to the model for which they are issued. Should the type certificate for that model be amended later to include any other model that incorporates the same or similar novel or unusual design feature, the special conditions would also apply to the other model under § 21.101.
The FAA issues special conditions, as defined in 14 CFR 11.19, in accordance with § 11.38, and they become part of the type-certification basis under § 21.17(a)(2).

Novel or Unusual Design Features
The BHTI Model 525 helicopter will incorporate the following novel or unusual design features: an advanced CAS system. The novel design includes the integration of audio and visual alerts, tactical sensors, and CAS message consolidation. The new technologies associated with integrated visual, aural, tactile, and alert messaging are more effective in alerting the flightcrew and aiding them in decision-making than the discrete colored lights for warning, caution, and advisory alerts prescribed in § 29.1322 alone.

Discussion
The current 14 CFR part 29 standards do not provide adequate standards for the advanced CAS system of the Bell Model 525 helicopter due to the complexity of the aircraft systems and the modes of the fly by wire primary flight controls. The proposed special condition will update definitions, define a prioritization scheme, expand color requirements, and address performance for flightcrew alerting to reflect changes in technology and functionality.

Applicability
As discussed above, these special conditions are applicable to the BHTI Model 525 helicopter. Should BHTI apply at a later date for a change to the type certificate to include another model incorporating the same novel or unusual design feature, the special conditions would apply to that model as well.

Conclusion
This action affects only certain novel or unusual design features on one model of helicopter. It is not a rule of general applicability.

List of Subjects in 14 CFR Part 29
Aircraft, Aviation safety, Reporting and recordkeeping requirements.
The authority citation for these special conditions is as follows:

Authority:
49 U.S.C. 106(g), 40113, 44701, 44702, 44704.

The Proposed Special Conditions
Accordingly, the Federal Aviation Administration (FAA) proposes the following special conditions as part of the type certification basis for Bell Helicopter Textron, Inc., Model 525 helicopters.

Flightcrew Alerting
(a) Flightcrew alerts must:
(1) Provide the flightcrew with the information needed to:
(i) Identify non-normal operation or aircraft system conditions, and
(ii) Determine the appropriate actions, if any.
(2) Be readily and easily detectable and intelligible by the flightcrew under all foreseeable operating conditions, including conditions where multiple alerts are provided.
(3) Be removed when the alerting condition no longer exists.
(b) Alerts must conform to the following prioritization hierarchy based on the urgency of flightcrew awareness and response.
(1) Warning: For conditions that require immediate flightcrew awareness and immediate flightcrew response.
(2) Caution: For conditions that require immediate flightcrew awareness and subsequent flightcrew response.
(3) Advisory: For conditions that require flightcrew awareness and may require subsequent flightcrew response.
(c) Warning and caution alerts must:
(1) Be prioritized within each category, when necessary.
(2) Provide timely attention-getting cues through at least two different senses by a combination of aural, visual, or tactile indications.
(3) Permit each occurrence of the attention-getting cues required by paragraph (c)(2) of these special conditions to be acknowledged and suppressed, unless they are required to be continuous.
(d) The alert function must be designed to minimize the effects of false and nuisance alerts. In particular, it must be designed to:
(1) Prevent the presentation of an alert that is inappropriate or unnecessary.
(2) Provide a means to suppress an attention-getting component of an alert caused by a failure of the alerting function that interferes with the flightcrew's ability to safely operate the helicopter. This means must not be readily available to the flightcrew so that it could be operated inadvertently or by habitual reflexive action. When an alert is suppressed, there must be a clear and unmistakable annunciation to the flightcrew that the alert has been suppressed.
(e) Visual alert indications must:
(1) Conform to the following color convention:
(i) Red for warning alert indications.
(ii) Amber or yellow for caution alert indications.
(iii) Any color except red, amber, yellow, or green for advisory alert indications.
(2) Use visual coding techniques, together with other alerting function elements in the cockpit, to distinguish between warning, caution, and advisory alert indications, if they are presented on monochromatic displays that are not capable of conforming to the color convention in paragraph (e)(1) of these special conditions.
(f) Use of the colors red, amber, and yellow in the cockpit for functions other than flightcrew alerting must be limited and must not adversely affect flightcrew alerting.
Issued in Fort Worth, Texas, on May 24, 2016.
Lance T. Gant

Manager, Rotorcraft Directorate, Aircraft Certification Service.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 39
[Docket No. FAA-2016-6672; Directorate Identifier 2016-NM-022-AD]
RIN 2120-AA64
Airworthiness Directives; The Boeing Company Airplanes

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Notice of proposed rulemaking (NPRM).

SUMMARY:
We propose to adopt a new airworthiness directive (AD) for certain The Boeing Company Model 787-8 airplanes. This proposed AD was prompted by a report that the grounding jumper between the environmental control system (ECS) bracket and the current return network (CRN) strap near passenger 1 left and 1 right entry doors was not bonded correctly during manufacturing. This proposed AD would require changing the configuration of the grounding jumpers connecting the ECS brackets and CRN straps; measuring the bond resistance; and related investigative and corrective actions if necessary. We are proposing this AD to prevent an incorrectly bonded jumper between the ECS bracket and the CRN strap, which does not provide proper grounding to the door frames at door 1 left and 1 right. If a fault occurs, an electrical shock hazard can exist to passengers and flight crew and could result in personal or fatal injury.

DATES:
We must receive comments on this proposed AD by July 18, 2016.

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 http://www.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.
For service information identified in this NPRM, contact Boeing Commercial Airplanes, Attention: Data & Services Management, P.O. Box 3707, MC 2H-65, Seattle, WA 98124-2207; telephone 206-544-5000, extension 1; fax 206-766-5680; Internet https://www.myboeingfleet.com . You may view this referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425-227-1221. It is also available on the internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-6672.

Examining the AD Docket
You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-6672; or in person at the Docket Management Facility between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this proposed AD, the regulatory evaluation, any comments received, and other information. The street address for the Docket Office (phone: 800-647-5527) is in the ADDRESSES section. Comments will be available in the AD docket shortly after receipt.

FOR FURTHER INFORMATION CONTACT:
Brendan Shanley, Aerospace Engineer, Systems and Equipment Branch, ANM-130S, FAA, Seattle Aircraft Certification Office (ACO), 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-6492; fax: 425-917-6590; email: brendan.shanley@faa.gov .

SUPPLEMENTARY INFORMATION:

Comments Invited
We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2016-6672; Directorate Identifier 2016-NM-022-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD because of those comments.
We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We will also post a report summarizing each substantive verbal contact we receive about this proposed AD.

Discussion
We have received a report that the grounding jumper between the ECS bracket and the CRN strap near passenger1 left and 1 right entry doors was not bonded correctly during manufacturing. Engineering documentation did not include applying an electrical bond between the ECS bracket and CRN strap. The existing bond configuration does not ground the door frame structure in the event of an electrical equipment fault. This condition, if not corrected, could result in an electrical shock hazard to passengers and flight crew and could result in personal or fatal injury.

Related Service Information Under 1 CFR Part 51
We reviewed Boeing Service Bulletin B787-81205-SB530025-00, Issue 001, dated July 17, 2014. The service information describes procedures for changing the configuration of the grounding jumpers connecting the ECS brackets and CRN straps; measuring the bond resistance; and related investigative and corrective actions if necessary. 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 the ADDRESSES section.

FAA's Determination
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.

Proposed AD Requirements
This proposed AD would require accomplishing the actions specified in the service information described previously. For information on the procedures, see this service information at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-6672.
The phrase “related investigative actions” is used in this proposed AD. Related investigative actions are follow-on actions that (1) are related to the primary action, and (2) further investigate the nature of any condition found. Related investigative actions in an AD could include, for example, inspections.
The phrase “corrective actions” is used in this proposed AD. Corrective actions correct or address any condition found. Corrective actions in an AD could include, for example, repairs.

Costs of Compliance
We estimate that this proposed AD affects 6 airplanes of U.S. registry. We estimate the following costs to comply with this proposed AD:
Estimated Costs
Action | Labor cost | Parts cost | Cost per product | Cost on U.S. operators
Installation | 6 work-hours × $85 per hour = $510 | $100 | $610 | $3,660
We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this proposed AD.
According to the manufacturer, some of the costs of this proposed AD may be covered under warranty, thereby reducing the cost impact on affected individuals. We do not control warranty coverage for affected individuals. As a result, we have included all costs in our cost estimate.

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.
We are 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
We 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) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska, and
(4) 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 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 (AD):
The Boeing Company: Docket No. FAA-2016-6672; Directorate Identifier 2016-NM-022-AD.

(a) Comments Due Date
We must receive comments by July 18, 2016.

(b) Affected ADs
None.

(c) Applicability
This AD applies to The Boeing Company Model 787-8 airplanes, certificated in any category, as identified in Boeing Service Bulletin B787-81205-SB530025-00, Issue 001, dated July 17, 2014.

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

(e) Unsafe Condition
This AD was prompted by a report that the grounding jumper between the environmental control system (ECS) bracket and the current return network (CRN) strap near passenger 1 left and 1 right entry doors was not bonded correctly during manufacturing. We are issuing this AD to prevent an incorrectly bonded jumper between the ECS bracket and the CRN strap, which does not provide proper grounding to the door frames at door 1 left and 1 right. If a fault occurs, an electrical shock hazard can exist to passengers and flight crew and could result in personal or fatal injury.

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

(g) Grounding Jumper Revision
Within 12 months after the effective date of this AD: Change the configuration of the grounding jumpers connecting the ECS brackets and CRN straps, including measuring the bond resistance and doing all applicable related investigative and corrective actions, in accordance with the Accomplishment Instructions of Boeing Service Bulletin B787-81205-SB530025-00, Issue 001, dated July 17, 2014. Do all applicable related investigative and corrective actions before further flight.

(h) Alternative Methods of Compliance (AMOCs)
(1) The Manager, Seattle Aircraft Certification Office (ACO), 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 manager of the ACO, send it to the attention of the person identified in paragraph (i)(1) of this AD. Information may be emailed to: 9-ANM-Seattle-ACO-AMOC-Requests@faa.gov .
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district 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 Commercial Airplanes Organization Designation Authorization (ODA) that has been authorized by the Manager, Seattle ACO, 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.

(i) Related Information
(1) For more information about this AD, contact Brendan Shanley, Aerospace Engineer, Systems and Equipment Branch, ANM-130S, FAA, Seattle Aircraft Certification Office (ACO), 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-6492; fax: 425-917-6590; email: brendan.shanley@faa.gov .
(2) For service information identified in this AD, contact Boeing Commercial Airplanes, Attention: Data & Services Management, P.O. Box 3707, MC 2H-65, Seattle, WA 98124-2207; telephone 206-544-5000, extension 1; fax 206-766-5680; Internet https://www.myboeingfleet.com . You may view this referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425-227-1221.
Issued in Renton, Washington, on May 20, 2016.
Victor Wicklund,

Acting Manager, Transport Airplane Directorate, Aircraft Certification Service.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 39
[Docket No. FAA-2016-6673; Directorate Identifier 2015-NM-092-AD]
RIN 2120-AA64
Airworthiness Directives; Ameri-King Corporation Emergency Locator Transmitters

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Notice of proposed rulemaking (NPRM).

SUMMARY:
We propose to adopt a new airworthiness directive (AD) for certain Ameri-King Corporation emergency locator transmitters (ELTs) as installed on various aircraft. This proposed AD was prompted by multiple reports of ELT failure. This proposed AD was also prompted by a report of noncompliance to quality standards and manufacturer processes related to Ameri-King Corporation ELTs. Failure to adhere to these standards and processes could result in ELTs that do not function. This proposed AD would require repetitive inspections of the ELT for discrepancies; repetitive checks, tests, and verifications, as applicable, to ensure that the ELT is functioning; and corrective actions if necessary. This proposed AD also allows for optional replacement of affected ELTs and, for aircraft on which an ELT is not required by operating regulations, optional removal of affected ELTs. We are proposing this AD to detect and correct nonfunctioning ELTs, which could delay or impede the rescue of the flightcrew and passengers after an emergency landing.

DATES:
We must receive comments on this proposed AD by July 18, 2016.

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 http://www.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.
For service information identified in this NPRM, contact Ameri-King Corporation, 17881 Sampson Lane, Huntington Beach, CA 92648; telephone: 714-842-8555; fax: 714-842-4235; Internet: http://ameri-king.com; email: ameriking9@aol.com. You may view this referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425-227-1221.

Examining the AD Docket
You may examine the AD docket on the Internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2016-6673; or in person at the Docket Management Facility between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. The AD docket contains this proposed AD, the regulatory evaluation, any comments received, and other information. The street address for the Docket Office (phone: 800-647-5527) is in the ADDRESSES section. Comments will be available in the AD docket shortly after receipt.

FOR FURTHER INFORMATION CONTACT:
Gilbert Ceballos, Aerospace Engineer, Systems and Equipment Branch, ANM-130L, FAA, Los Angeles Aircraft Certification Office (ACO), 3960 Paramount Boulevard, Lakewood, CA 90712-4137; phone: 562-627-5372; fax: 562-627-5210; email: gilbert.ceballos@faa.gov.

SUPPLEMENTARY INFORMATION:

Comments Invited
We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2016-6673; Directorate Identifier 2015-NM-092-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this proposed AD. We will consider all comments received by the closing date and may amend this proposed AD because of those comments.
We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We will also post a report summarizing each substantive verbal contact we receive about this proposed AD.

Discussion
We received multiple reports of ELT failure (73 reported ELT failures). We also received a report of noncompliance to quality standards and manufacturer processes related to Ameri-King Corporation ELTs. Failure to adhere to these standards and processes could result in ELTs that do not function. ELT failure, if not corrected, could delay or impede the rescue of the flightcrew and passengers after an emergency landing.

Emergency Cease and Desist Order Issued to Ameri-King Corporation
We have determined that Ameri-King Corporation manufactured, sold, or distributed parts and articles that do not conform to an approved design but were represented as FAA-approved for installation on FAA type-certificated aircraft. Investigation of the production issues identified that Ameri-King Corporation violated multiple FAA regulations and falsified documents used to show compliance with FAA regulations. Therefore, we issued an emergency cease and desist order, dated December 28, 2015, to Ameri-King Corporation that terminates their technical standard order authorization (TSOA) and parts manufacturer approval (PMA).
The FAA's emergency cease and desist order requires Ameri-King Corporation to immediately cease and desist manufacturing, selling, and distributing any articles for installation on FAA type-certificated aircraft, which would include advertising, repairing, rebuilding, and altering any articles intended for installation on type certificated products. Any parts and articles produced by Ameri-King Corporation before December 28, 2015, may not conform to an approved design. Any parts and articles produced by Ameri-King Corporation on or after that date were produced without an FAA production approval and contrary to the FAA's emergency cease and desist order.
We might consider additional rulemaking to address other parts and articles that were produced by Ameri-King Corporation with falsified testing records and without complying with its FAA-mandated quality assurance procedures; such non-compliant parts and articles could result in an unacceptable hazard to aviation safety.

Related Service Information Under 1 CFR Part 51
We reviewed Ameri-King Corporation Document IM-450, “INSTALLATION & OPERATION MANUAL,” Revision A, dated October 18, 1995; and Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014. The service information describes procedures for inspections of the ELT for discrepancies; checks, tests, and verifications to ensure the ELT is functioning; and corrective actions. Corrective actions include replacing affected parts. 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 the ADDRESSES section.

FAA's Determination
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.

Proposed AD Requirements
This proposed AD would require accomplishing the actions specified in the service information described previously, except as discussed under “Differences Between this Proposed AD and the Service Information.”

Differences Between This Proposed AD and the Service Information
Ameri-King Corporation Document IM-450, “INSTALLATION & OPERATION MANUAL,” Revision A, dated October 18, 1995; and Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014; specify accomplishing certain inspections of the ELT but do not specify corrective actions for any finding of the following discrepancies: Unsecured fastener or mechanical assembly, cuts or abrasions on the coaxial cable outer jacket, corrosion on the “BNC” connectors and mating plug on the antenna and the ELT main unit, wear or abrasion on the modular cable outer jacket, corrosion on the jack and plug of the modular connecting cable, and corrosion on the battery compartment. This proposed AD would require repairing any discrepancy found during the inspections.
Ameri-King Corporation Document IM-450, “INSTALLATION & OPERATION MANUAL,” Revision A, dated October 18, 1995, specifies doing a functional test, a verification that the G-switch is working, and an activation check, but does not specify corrective actions for any findings. If there are any findings during the test, verification, or check, this proposed AD would require replacing the affected ELT with another serviceable FAA-approved ELT.
Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014, specifies doing an operational test, G-switch and antenna checks, a digital message verification, a registration verification, and verification of ELT and global positioning system (GPS) interface, but does not specify corrective actions for any findings. If there are any findings during the test, checks, or verifications, this proposed AD would require replacing the affected ELT with another serviceable FAA-approved ELT.

Costs of Compliance
We estimate that this proposed AD affects 14,500 ELTs installed on various aircraft of U.S. registry.
We estimate the following costs to comply with this proposed AD:
Estimated Costs
Action | Labor cost | Cost per product | Cost on U.S. operators
Inspections, checks, tests, and verifications | 2 work-hours × $85 per hour = $170 per inspection cycle | $170 per inspection cycle | $2,465,000 per inspection cycle.
We estimate the following costs to do any necessary replacements that would be required based on the results of the proposed inspections, checks, tests, and verifications. We have no way of determining the number of aircraft that might need these replacements.
On-Condition Costs
Action | Labor cost | Parts cost | Cost per product
Replacement | 4 work-hours × $85 per hour = $340 | Between $600 and $1,500 | Between $940 and $1,840.

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.
We are 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
We 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) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska, and
(4) 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 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 (AD):
Ameri-King Corporation: Docket No. FAA-2016-6673; Directorate Identifier 2015-NM-092-AD.

(a) Comments Due Date
We must receive comments by July 18, 2016.

(b) Affected ADs
None.

(c) Applicability
This AD applies to Ameri-King Corporation Model AK-450-( ) and AK-451-( ) series emergency locator transmitters (ELTs). This appliance is installed on, but not limited to, aircraft identified in table 1 to paragraph (c) of this AD.
Table 1 to Paragraph (c) of This AD—Certain Aircraft That Might Have Affected ELTs Installed
Aircraft | ELT model
Airbus rotorcraft | AK-451.
American Champion Aircraft Corp. airplanes | AK-450 and AK-451.
Aviat Aircraft Inc. airplanes | AK-450.
Beechcraft Corporation airplanes | AK-451.
Bell Helicopter Textron Canada Limited rotorcraft | AK-451.
Bombardier Inc. airplanes | AK-451.
Cessna Aircraft Company airplanes | AK-451.
Cirrus Design Corporation airplanes | AK-451.
Diamond Aircraft Industries Inc. airplanes | AK-450 and AK-451.
Eclipse Aerospace Inc. airplanes | AK-451.
Embraer S.A. airplanes | AK-451.
KitFox Aircraft LLC (formerly SkyStar Aircraft Corporation and also Denney Aerocraft Company) airplanes | AK-450.
Luscombe Aircraft Corporation airplanes | AK-450 and AK-451.
Mooney Aircraft Corporation airplanes | AK-450.
Piper Aircraft Inc. airplanes | AK-451.
Robinson Helicopter Company rotorcraft | AK-451.
Sikorsky Aircraft Corporation rotorcraft | AK-451.
SOCATA, S.A., Socata Groupe Aerospatiale airplanes | AK-450.
Twin Commander Aircraft LLC airplanes | AK-451.

(d) Subject
Joint Aircraft System Component (JASC)/Air Transport Association (ATA) of America Code 2562, Emergency Locator Beacon.

(e) Unsafe Condition
This AD was prompted by multiple reports of ELT failure. This AD was also prompted by a report of noncompliance to quality standards and manufacturer processes related to Ameri-King Corporation ELTs. Failure to adhere to these standards and processes could result in ELTs that do not function. We are issuing this AD to detect and correct nonfunctioning ELTs, which could delay or impede the rescue of the flightcrew and passengers after an emergency landing.

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

(g) Repetitive Actions and Corrective Actions
Within 12 months after the effective date of this AD, do general visual inspections of the ELT for discrepancies; checks, tests, and verifications, as applicable, to ensure the ELT is functioning; and all applicable corrective actions; in accordance with section 3.4, “Periodic Maintenance” of Ameri-King Corporation Document IM-450, “INSTALLATION & OPERATION MANUAL,” Revision A, dated October 18, 1995; or Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014; as applicable; except as required by paragraph (h) of this AD. Do all applicable corrective actions following 14 CFR 91.207(a), 14 CFR 91.207(f), and other applicable operating rules after accomplishing the inspections, checks, tests, and verifications. Repeat the inspections and applicable checks, tests, and verifications thereafter at intervals not to exceed 12 months until the terminating action specified in paragraph (j) of this AD is done.

(h) Exceptions to Service Information
(1) If, during any action required by paragraph (g) of this AD, any ELT fails the functional test specified in step 6., the verification specified in step 7., or the activation check specified in step 8., of section 3.4, “Periodic Maintenance,” of Ameri-King Corporation Document IM-450, “INSTALLATION & OPERATION MANUAL,” Revision A, dated October 18, 1995, replace the affected Model AK-450-( ) ELT with a serviceable FAA-approved ELT as specified in paragraph (i) of this AD (“Definition of Serviceable FAA-approved ELT”), following 14 CFR 91.207(a), 14 CFR 91.207(f), and other applicable operating rules.
(2) If, during any action required by paragraph (g) of this AD, any ELT fails any of the actions specified in paragraphs (h)(2)(i) through (h)(2)(v) of this AD, replace the affected Model AK-451-( ) ELT with a serviceable FAA-approved ELT as specified in paragraph (i) of this AD (“Definition of Serviceable FAA-approved ELT”), following 14 CFR 91.207(a), 14 CFR 91.207(f), and other applicable operating rules.
(i) The operational test specified in step 3.4.6 of section 3.4, “Periodic Maintenance,” of Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014.
(ii) Any check specified in step 3.4.7 of section 3.4, “Periodic Maintenance,” of Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014.
(iii) The digital message verification specified in step 3.4.8 of section 3.4, “Periodic Maintenance,” of Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014.
(iv) The registration verification specified in step 3.4.9 of section 3.4, “Periodic Maintenance,” of Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014.
(v) The verification of the ELT and global positioning system (GPS) interface specified in step 3.4.10 of section 3.4, “Periodic Maintenance,” of Ameri-King Corporation Document IM-451, “INSTALLATION AND OPERATION MANUAL,” Revision NC-4.1h, dated July 5, 2014.
(3) If, during any action required by paragraph (g) of this AD, any of the discrepancies specified in paragraphs (h)(3)(i) through (h)(3)(vi) of this AD are found, repair all discrepancies following 14 CFR 91.207(a), 14 CFR 91.207(f), and other applicable operating rules.
(i) Any unsecured fastener or mechanical assembly.
(ii) Any cuts or abrasions on the coaxial cable outer jacket.
(iii) Any corrosion on the “BNC” connectors and mating plug on the antenna and the ELT main unit.
(iv) Any wear or abrasion on the modular cable outer jacket.
(v) Any corrosion on the jack and plug of the modular connecting cable.
(vi) Any corrosion on the battery compartment.
(4) If, during any action required by paragraph (g) of this AD, any non-functioning battery is found, replace non-functioning batteries with non-rechargeable batteries identified in paragraph (h)(4)(i) or (h)(4)(ii) of this AD, as applicable, following 14 CFR 91.207(a), 14 CFR 91.207(f), and other applicable operating rules.
(i) For AK-450 ELTs: For the remote cockpit switch, use a 3-volt lithium battery. For the ELT main unit, use four D cell (1.5 volt) alkaline batteries.
(ii) For AK-451 ELTs: For the remote cockpit switch, use a 3-volt lithium battery. For the ELT main unit, use either four D cell lithium (LiMnO2) batteries or four D cell lithium (LiSO 2 ) batteries.

(i) Definition of Serviceable FAA-approved ELT
For the purposes of this AD, a serviceable FAA-approved ELT is any FAA-approved ELT other than a Model AK-450-( ) and AK-451-( ) series ELT produced by Ameri-King Corporation.

(j) Optional Terminating Action
Doing the applicable action specified in paragraph (j)(1) or (j)(2) of this AD terminates the actions required by paragraphs (g) and (h) of this AD.
(1) For aircraft required by operating regulations to be equipped with an ELT: Replace the ELT with a serviceable FAA-approved ELT as specified in paragraph (i) of this AD (“Definition of Serviceable FAA-approved ELT”).
(2) For aircraft not required by operating regulations to be equipped with an ELT: Replace the ELT with a serviceable FAA-approved ELT as specified in paragraph (i) of this AD (“Definition of Serviceable FAA-approved ELT”). The ELT may be removed as an alternative to the ELT replacement; if an ELT is re-installed, it must be a serviceable ELT as specified in paragraph (i) of this AD (“Definition of Serviceable FAA-approved ELT”).

(k) Alternative Methods of Compliance (AMOCs)
(1) The Manager, Los Angeles Aircraft Certification Office, 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 manager of the ACO, send it to the attention of the person identified in paragraph (l)(1) of this AD.
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district office.

(l) Related Information
(1) For more information about this AD, contact Gilbert Ceballos, Aerospace Engineer, Systems and Equipment Branch, ANM-130L, FAA, Los Angeles Aircraft Certification Office (ACO), 3960 Paramount Boulevard, Lakewood, California 90712-4137; phone: 562-627-5372; fax: 562-627-5210; email: gilbert.ceballos@faa.gov .
(2) For service information identified in this AD, contact Ameri-King Corporation, 17881 Sampson Lane, Huntington Beach, CA 92648; telephone: 714-842-8555; fax: 714-842-4235; Internet: http://ameri-king.com; email: ameriking9@aol.com . You may view this referenced service information at the FAA, Transport Airplane Directorate, 1601 Lind Avenue SW., Renton, WA. For information on the availability of this material at the FAA, call 425-227-1221.
Issued in Renton, Washington, on May 20, 2016.
Victor Wicklund,

Acting Manager, Transport Airplane Directorate, Aircraft Certification Service.
FEDERAL TRADE COMMISSION
16 CFR Part 460
Labeling and Advertising of Home Insulation

AGENCY:
Federal Trade Commission (“FTC” or “Commission”).

ACTION:
Advance notice of proposed rulemaking; extension of deadline for submission of public comments.

SUMMARY:
The FTC is extending the deadline for filing public comments on its recent Advance Notice of Proposed Rulemaking for the “Trade Regulation Rule Concerning the Labeling and Advertising of Home Insulation” (the “R-value Rule” or “Rule”).

DATES:
The comment period for the advance notice of proposed rulemaking published April 6, 2016 (81 FR 19936), is extended. Comments must be received on or before September 6, 2016.

ADDRESSES:
Interested parties may file a comment online or on paper, by following the instructions in the Request for Comment part of the SUPPLEMENTARY INFORMATION section below. Write “16 CFR part 460—R-value Rule Review, File No. R811001” on your comment, and file your comment online at https://ftcpublic.commentworks.com/ftc/rvaluerule, by following the instructions on the web-based form. If you prefer to file your comment on paper, mail your comment to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610 (Annex B), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th St. SW., 5th Floor, Suite 5610 (Annex B), Washington, DC 20024.

FOR FURTHER INFORMATION CONTACT:
Hampton Newsome, (202) 326-2889, Attorney, Division of Enforcement, Bureau of Consumer Protection, Federal Trade Commission, 600 Pennsylvania Avenue NW., Washington, DC 20580.

SUPPLEMENTARY INFORMATION:

I. Comment Period Extension
On April 6, 2016 (81 FR 19936), as part of the Commission's systematic review of its rules and guides, the FTC published an Advance Notice of Proposed Rulemaking (ANPR) in the Federal Register requesting public comments on the R-value Rule. The ANPR set June 6, 2016 as the deadline for filing comments. On May 12, 2016, the American Chemistry Council's (ACC) Center for the Polyurethanes Industry and Spray Foam Coalition requested a 90-day extension to the comment period. ACC represents manufacturers of various types of home insulation products, including spray polyurethane foam (SPF) and rigid polyurethane foam board insulation. The requesters explained that the insulation industry and certain insulation products have changed substantially since the Commission completed its last regulatory review in 2005. In particular, new industry research has become available on the short-term and long-term thermal performance of SPF products. ACC also noted that new research exists about the energy efficiency benefits of insulation products that combine air sealing with high thermal resistance properties. Accordingly, it asserted that additional time is necessary for companies and industry trade organizations to present this new information in a useful manner through comments.
Given the complexity and range of issues raised in the ANPR, the Commission agrees that allowing additional time for filing comments would help facilitate the creation of a more complete record. Moreover, this extension would not harm consumers because the current Rule will remain in effect during the review process. The Commission agrees that extending the comment period to allow interested parties adequate time to address issues raised by the ANPR will facilitate a more complete record. Therefore, the Commission has decided to extend the comment period to September 6, 2016.

II. Request for Comment
You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before September 6, 2016. Write “16 CFR part 460—R-value Rule Review, File No. R811001” on your comment. Your comment—including your name and your state—will be placed on the public record of this proceeding, including, to the extent practicable, on the public Commission Web site, at http://www.ftc.gov/os/publiccomments.shtm. As a matter of discretion, the Commission tries to remove individuals' home contact information from comments before placing them on the Commission Web site.
Because your comment will be made public, you are solely responsible for making sure that your comment does not include any sensitive personal information, such as anyone's Social Security number, date of birth, driver's license number or other state identification number or foreign country equivalent, passport number, financial account number, or credit or debit card number. You are also solely responsible for making sure that your comment does not include any sensitive health information, such as medical records or other individually identifiable health information. In addition, do not include any “[t]rade secret or any commercial or financial information which is . . . privileged or confidential,” as discussed in section 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2). In particular, do not include competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.
If you want the Commission to give your comment confidential treatment, you must file it in paper form, with a request for confidential treatment, and you must follow the procedure explained in FTC Rule 4.9(c), 16 CFR 4.9(c). ^1 Your comment will be kept confidential only if the FTC General Counsel grants your request in accordance with the law and the public interest.
^1 In particular, the written request for confidential treatment that accompanies the comment must include the factual and legal basis for the request, and must identify the specific portions of the comment to be withheld from the public record. See FTC Rule 4.9(c), 16 CFR 4.9(c).
Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, we encourage you to submit your comments online. To make sure that the Commission considers your online comment, you must file it at https://ftcpublic.commentworks.com/ftc/rvaluerule, by following the instruction on the web-based form. If this Notice appears at http://www.regulations.gov, you also may file a comment through that Web site.
If you prefer to file your comment on paper, mail your comment to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610 (Annex B), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th Street SW., 5th Floor, Suite 5610 (Annex B), Washington, DC 20024. If possible, submit your paper comment to the Commission by courier or overnight service.
Visit the Commission Web site at http://www.ftc.gov to read this ANPR and the news release describing it. The FTC Act and other laws that the Commission administers permit the collection of public comments to consider and use in this proceeding, as appropriate. The Commission will consider all timely and responsive public comments that it receives on or before September 6, 2016. You can find more information, including routine uses permitted by the Privacy Act, in the Commission's privacy policy, at http://www.ftc.gov/ftc/privacy.htm.
By direction of the Commission.
Donald S. Clark,

Secretary.
DELAWARE RIVER BASIN COMMISSION
18 CFR Parts 401 and 420
Rules of Practice and Procedure Concerning Regulatory Program Fees and Basin Regulations—Water Supply Charges Concerning Rates

AGENCY:
Delaware River Basin Commission.

ACTION:
Proposed rule; notice of public hearing.

SUMMARY:
The Commission is proposing amendments to the Rules of Practice and Procedure to adopt a new project review fee structure and to the Basin Regulations—Water Supply Charges to provide for automatic inflation adjustments. These changes also are proposed to be incorporated into the Commission's Comprehensive Plan.

DATES:
The Commission will hold a public hearing at 1 p.m. on Wednesday, July 27, 2016. The hearing will continue until all those wishing to testify have had an opportunity to do so. Written comments will be accepted and must be received by 5 p.m. on Friday, August 12, 2016.

ADDRESSES:
The public hearing will be held in the Goddard Conference Room at the Commission's office building located at 25 State Police Drive, West Trenton, NJ. As Internet mapping tools are inaccurate for this location, please use the driving directions posted on the Commission's Web site.
Oral Testimony and Written Comments: Persons wishing to testify at the hearing are asked to register in advance by phoning Paula Schmitt at 609-883-9500, ext. 224. Written comments may be submitted as follows: If by email, to paula.schmitt@drbc.nj.gov; if by fax, to Commission Secretary at 609-883-9522; if by U.S. Mail, to Commission Secretary, DRBC, P.O. Box 7360, West Trenton, NJ 08628-0360; and if by overnight mail, to Commission Secretary, DRBC, 25 State Police Drive, West Trenton, NJ 08628-0360. Comments also may be delivered by hand at any time during the Commission's regular office hours (Monday through Friday, 8:30 a.m. through 5:00 p.m. except on national holidays) until the close of the comment period at 5:00 p.m. on Friday, August 12, 2016. In all cases, please include the commenter's name, address and affiliation, if any, in the comment document and “Fees Rulemaking” in the subject line.

FOR FURTHER INFORMATION CONTACT:
An FAQ document explaining this proposal in further detail is available on the Commission's Web site, www.drbc.net. For queries about the rulemaking process, please contact Pamela Bush at 609-477-7203.

SUPPLEMENTARY INFORMATION:
Background. The Delaware River Basin Commission (“DRBC” or “Commission”) is a Federal interstate compact agency charged with managing the water resources of the Delaware River Basin on a regional basis without regard to political boundaries. Its members are the governors of the four basin states—Delaware, New Jersey, New York and Pennsylvania—and the North Atlantic Division Commander of the U.S. Army Corps of Engineers, representing the federal government. DRBC is proposing a comprehensive revision of its project review fee structure, including an automatic annual indexed inflation adjustment for most fees. The inflation adjustment is also proposed for DRBC's water supply charges rates applicable to consumptive and non-consumptive surface water withdrawals.
Current fees. DRBC's current project review fee structure was adopted by the Commission in 2009 by (uncodified) Resolution No. 2009-2. For projects involving total costs of $250,000 or less, it consists of a flat project review fee of $1,000 for privately sponsored projects and $500 for publically sponsored projects. For projects with total costs greater than $250,000, DRBC's current project review fee is based upon a percentage of the costs of the project attributable to project components physically located within the basin, and is capped at $75,000. However, projects for which the review is exceptionally involved may be charged DRBC's actual costs, which may exceed $75,000. The current fee structure generates an uneven revenue stream that between 2011 and 2015 produced average annual revenues of $610,843. The Commission's total cost associated with project reviews required by the Delaware River Basin Compact and DRBC regulations is estimated to equal $1.15 million annually. This estimate takes into consideration administrative cost savings expected to accompany implementation of the One Process/One Permit Program (also “One Process/One Permit”), recently authorized by the Commission through its adoption of the One Permit Program rule, 18 CFR 401.42.
DRBC's water supply charges are used to pay debt service, annual operation and maintenance costs, and the costs of required improvements, repairs and replacements associated with water supply storage owned by the Commission in two reservoirs—Blue Marsh and Beltzville—located in Pennsylvania and operated by the U.S. Army Corps of Engineers. Water supply charges revenues also support DRBC activities related to water supply planning and operations. DRBC's current water supply charges rates, in effect since January 1, 2011, are $80 per million gallons for consumptive use and $.80 per million gallons for non-consumptive use. The previous rates, $60 per million gallons for consumptive use and $.60 per million gallons for non-consumptive use, were adopted in 1978 and remained unchanged for more than 30 years. DRBC's water supply charges revenues have lagged significantly behind inflation.
Proposed Changes. The proposed project review fee restructuring includes: For wastewater discharge projects, elimination of DRBC project review fees for applications that undergo coordinated review pursuant to the One Process/One Permit Program; and for water withdrawal projects, (1) for those projects for which DRBC continues to act as lead review agency, replacement of the current fee structure with fees based on monthly water allocation limits; and (2) for renewals subject to coordinated review under One Process/One Permit, elimination of the project review fee. DRBC is simultaneously proposing an annual coordination, monitoring and assessment fee for all water withdrawal and wastewater discharge projects subject to DRBC review and approval, including projects that receive permits from a signatory party agency under the One Process/One Permit Program. The annual fee will range from $300 to $1,000 per year, depending upon the permitted discharge capacity or monthly water allocation. The fee for DRBC's review of “Other” projects—those that involve no ongoing withdrawals or discharges—will continue to be calculated on the basis of project cost. The coordination, monitoring and assessment fee will not apply to such “Other” projects. An annual, indexed, automatic inflation adjustment is proposed for most project review fees.
The proposed regulatory program fees structure is expected to provide a more predictable and sustainable source of revenues and to help close the annual gap of approximately $539,000 in funding to support DRBC's project review program.
No increase is proposed to DRBC's current water supply charges rates, set forth at 18 CFR 420.41. However, an annual, indexed, automatic inflation adjustment is proposed, applicable to both the consumptive and non-consumptive use rates for surface water withdrawals.
Additional information. An FAQ document explaining DRBC's fee restructuring proposal in greater detail is available on the Commission's Web site, www.drbc.net.

List of Subjects
18 CFR Part 401
Administrative practice and procedure, Penalties, Water pollution control, Water resources.
18 CFR Part 420
Water Supply.
For the reasons set forth in the preamble, the Delaware River Basin Commission proposes to amend parts 401 and 420 of title 18 of the Code of Federal Regulations as follows:

PART 401—RULES OF PRACTICE AND PROCEDURE
1. The authority citation for part 401 continues to read as follows:

Authority:
Delaware River Basin Compact (75 Stat. 688), unless otherwise noted.
2. Add § 401.43 to subpart C to read as follows:
§ 401.43
Regulatory program fees.
(a) Purpose. The purpose of this section is to provide an adequate, stable and reliable stream of revenue to cover the cost of the Commission's regulatory program activities, an important means by which the Commission coordinates management of the shared water resources of the Basin. Activities to be covered by the fees include the review of applications for projects that are subject to review under the Delaware River Basin Compact and implementing regulations; and ongoing activities associated with such projects, including but not limited to, effluent and ambient monitoring, data analysis, hydrodynamic and water quality modeling, and coordination with state and federal agencies.
(b) Types of fees. The following types of fees are established by this section:
(1) Docket Application Fee. Except as set forth in paragraph (b)(1)(iii) of this section, the Docket Application Fee shall apply to:
(i) Any project that, in accordance with the Delaware River Basin Compact and DRBC regulations, requires a Commission-issued docket or permit, whether it be a new or existing project for which the Commission has not yet issued an approval or a project for which the renewal of a previous Commission approval is required.
(ii) Any project that in accordance with section 11 or section 13.1 of the Delaware River Basin Compact and DRBC regulations must be added to the Comprehensive Plan (also, “Plan”). In addition to any new project required to be included in the Plan, such projects include existing projects that in accordance with section 13.1 of the Compact are required to be included in the Plan and which were not previously added to the Plan. Any existing project that is changed substantially from the project as described in the Plan shall be deemed to be a new and different project for purposes of this section.
(iii) Exemptions. The Docket Application Fee shall not apply to:
(A) Any project for which the Signatory Party Agency serves as lead under the one permit program rule (§ 401.42), unless such project must be added by the Commission to the Comprehensive Plan.
(B) Any project for which an agency, authority or commission of a signatory to the Compact is the primary sponsor. Projects sponsored by political subdivisions of the signatory states shall not be included in this exemption. For purposes of this section “political subdivisions” shall include without limitation municipalities, municipal utility authorities, municipal development corporations, and all other entities not directly under the budgetary and administrative control of the Commission's members.
(2) Annual Monitoring and Coordination Fee. An Annual Monitoring and Coordination Fee shall apply to each withdrawal and/or discharge project for which a water allocation or wastewater discharge approval issued pursuant to the Compact and implementing regulations is in effect, regardless of whether the approval was issued by the Commission in the form of a docket, permit or other instrument, or by a Signatory Party Agency under the one permit program rule (§ 401.42). The fee shall be based on the amount of a project's approved monthly water allocation and/or approved daily discharge capacity.
(3) Alternative Review Fee. In instances where the Commission's activities and related costs associated with the review of an existing or proposed project are expected to involve extraordinary time and expense, an Alternative Review Fee equal to the Commission's actual costs may be imposed. The Executive Director shall inform the project sponsor in writing when the Alternative Review Fee is to be applied and may require advance payment in the amount of the Commission's projected costs. Instances in which the Alternative Review Fee may apply include, but are not limited to, matters in which:
(i) DRBC staff perform a detailed pre-application review, including but not limited to the performance or review of modeling and/or analysis to identify target limits for wastewater discharges;
(ii) DRBC staff perform or review complex modeling in connection with the design of a wastewater discharge diffuser system;
(iii) DRBC manages a public process for which the degree of public involvement results in extraordinary effort and expense, including but not limited to, costs associated with multiple stakeholder meetings, special public hearings, and/or voluminous public comment.
(iv) DRBC conducts or is required to engage third parties to conduct additional analyses or evaluations of a project in response to a court order.
(4) Additional fees— (i) Emergency approval. A request for an emergency certificate under § 401.40 to waive or amend a docket condition shall be subject to a minimum fee in accordance with paragraph (e) of this section. An Alternative Review Fee also may be charged in accordance with paragraph (b)(3) of this section.
(ii) Late filed renewal application. Any renewal application submitted fewer than 120 calendar days in advance of the expiration date or after such other date specified in the docket or permit or letter of the Executive Director for filing a renewal application shall be subject to a Late Filed Renewal Application charge in excess of the otherwise applicable fee.
(iii) Modification of a DRBC approval. Following Commission action on a project, each project revision or modification that the Executive Director deems substantial shall require an additional Docket Application Fee calculated in accordance with paragraph (e) of this section and subject to an Alternative Review Fee in accordance with paragraph (b)(3) of this section.
(iv) Name change. Each project with a docket or permit issued by the DRBC or by a Signatory Party Agency pursuant to the one permit program rule (§ 401.42) will be charged an administrative fee as set forth in paragraph (e) of this section.
(v) Change of ownership. Each project that undergoes a “change in ownership” as that term is defined at 18 CFR 420.31(e)(2) will be charged an administrative fee as set forth in paragraph (e) of this section.
(c) Indexed adjustment. On July 1 of every year, beginning July 1, 2017, all fees established by this section will increase commensurate with any increase in the annual April 12-month Consumer Price Index (CPI) for Philadelphia, published by the U.S. Bureau of Labor Statistics during that year. ^1 In any year in which the April 12-month CPI for Philadelphia declines or shows no change, the Docket Application Fee and Annual Monitoring and Coordination Fee will remain unchanged. Following any indexed adjustment made under this paragraph, a revised fee schedule will be posted on the Commission's Web site. Interested parties may also obtain the current fee schedule by contacting the Commission directly during business hours.
^1 Consumer Price Index—U/Series ID: CWURA102SA0/Not Seasonally Adjusted/Area: Philadelphia-Wilmington-Atlantic City, PA-NJ-DE-MD/Item: All items/Base Period: 1982-84=100.
(d) Late payment charge. When any fee established by this section remains unpaid 30 calendar days after the payment due date provided on the Commission's invoice, an incremental charge equal to 2% of the amount owed shall be automatically assessed. Such charge shall be assessed every 30 days thereafter until the total amount owed, including any late payment charges has been paid in full.
(e) Fee schedules. The fees described in this section shall be as follows:
Docket Application Filing Fee
Project type | Docket application fee | Fee maximum
| $400 per million gallons/month of allocation, ^1 not to exceed $15,000. ^1 | Greater of: $15,000 ^1 or Alternative Review Fee
Water Withdrawal | Fee is doubled for any portion to be exported from the basin
Wastewater Discharge | Private projects: $1,000 ^1 Public projects: $500 ^1 | Alternative Review Fee
| 0.4% of project cost up to $10,000,000 plus 0.12% of project cost above | Greater of: $75,000 ^1 or Alternative Review Fee
Other | $10,000,000 (if applicable), not to exceed $75,000. ^1
^1 Subject to annual adjustment in accordance with paragraph (c) of this section.
Annual Monitoring and Coordination Fee
| Annual fee | Allocation
| ^1 $300 | <4.99 mgm.
| ^1 450 | 5.00 to 49.99 mgm.
Water Withdrawal | ^1 650 | 50.00 to 499.99 mgm.
| ^1 825 | 500.00 to 9,999.99 mgm.
| ^1 1,000; | > or = to 10,000 mgm.
| Annual fee | Discharge design capacity
| ^1 300 | <0.05 mgd.
Wastewater Discharge | ^1 610 | 0.05 to 1 mgd.
| | ^1 820 | 1 to 10 mgd.
| ^1 1,000 | >10 mgd.
^1 Subject to annual adjustment in accordance with paragraph (c) of this section.
Additional Fees
Proposed action | Fee | Fee maximum
Emergency Approval Under 18 CFR 401.40 | $5,000 | Alternative Review Fee.
Late Filed Renewal Surcharge | $2,000
| At Executive Director's discretion, Docket Application Fee for the appropriate project type | Alternative Review Fee.
Modification of a DRBC Approval
Name change | $1,000, ^1
Change of Ownership | $1,500. ^1
^1 Subject to annual adjustment in accordance with paragraph (c) of this section.

PART 420—BASIN REGULATIONS—WATER SUPPLY CHARGES
3. The authority citation for part 420 continues to read as follows:

Authority:
Delaware River Basin Compact, 75 Stat. 688.
4. Revise § 420.41 to read as follows:
§ 420.41
Schedule of water charges.
The schedule of water charges established in accordance with § 420.22 shall be as follows:
(a) $80 per million gallons for consumptive use, subject to paragraph (c) of this section; and
(b) $0.80 per million gallons for non-consumptive use, subject to paragraph (c) of this section.
(c) On July 1 of every year, beginning July 1, 2017, the rates established by this section will increase commensurate with any increase in the annual April 12-month Consumer Price Index (CPI) for Philadelphia, published by the U.S. Bureau of Labor Statistics during that year. ^1 In any year in which the April 12-month CPI for Philadelphia declines or shows no change, the water charges rates will remain unchanged. Following any indexed adjustment made under this paragraph, revised consumptive and non-consumptive use rates will be posted on the Commission's Web site. Interested parties may also obtain the current rates by contacting the Commission directly during business hours.
^1 Consumer Price Index—U/Series ID: CWURA102SA0/Not Seasonally Adjusted/Area: Philadelphia-Wilmington-Atlantic City, PA-NJ-DE-MD/Item: All items/Base Period: 1982-84=100.
Dated: May 26, 2016.
Pamela M. Bush,

Commission Secretary.
DEPARTMENT OF THE TREASURY
Financial Crimes Enforcement Network
31 CFR Part 1010
RIN 1506-AB35
Imposition of Special Measure Against North Korea as a Jurisdiction of Primary Money Laundering Concern

AGENCY:
Financial Crimes Enforcement Network (“FinCEN”), Treasury.

ACTION:
Notice of proposed rulemaking.

SUMMARY:
In a finding, notice of which was published elsewhere in this issue of the Federal Register (“Notice of Finding”), the Director of FinCEN found that the Democratic People's Republic of Korea (“North Korea”) is a jurisdiction of primary money laundering concern. FinCEN is issuing this notice of proposed rulemaking (“NPRM”) to propose to prohibit covered financial institutions from opening or maintaining a correspondent account in the United States for or on behalf of a North Korean banking institution and to prohibit the use of foreign banking institutions' correspondent accounts at covered U.S. financial institutions to process transactions involving North Korean financial institutions.

DATES:
Written comments on the notice of proposed rulemaking must be submitted on or before August 2, 2016.

ADDRESSES:
You may submit comments, identified by 1506-AB35, by any of the following methods:
• Federal E-rulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments. Include 1506-AB35 in the submission.
• Mail: The Financial Crimes Enforcement Network, P.O. Box 39, Vienna, VA 22183. Include RIN 1506-AB35 in the body of the text. Please submit comments by one method only.
• Comments submitted in response to this NPRM will become a matter of public record. Therefore, you should submit only information that you wish to make publicly available.
• Inspection of comments: FinCEN uses the electronic, Internet-accessible dockets at Regulations.gov as its complete, official-record docket; all hard copies of materials that should be in the docket, including public comments, are electronically scanned and placed there. Federal Register notices published by FinCEN are searchable by docket number, RIN, or document title, among other things, and the docket number, RIN, and title may be found at the beginning of such notices. In general, FinCEN will make all comments publicly available by posting them on http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:
The FinCEN Resource Center at (800) 949-2732.

SUPPLEMENTARY INFORMATION:

I. Statutory Provisions
On October 26, 2001, the President signed into law the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, Public Law 107-56 (the “USA PATRIOT Act”). Title III of the USA PATRIOT Act amended the anti-money laundering provisions of the Bank Secrecy Act (“BSA”), codified at 12 U.S.C. 1829b, 12 U.S.C. 1951-1959, and 31 U.S.C. 5311-5314, 5316-5332, to promote the prevention, detection, and prosecution of international money laundering and the financing of terrorism. Regulations implementing the BSA appear at 31 CFR Chapter X. The authority of the Secretary of the Treasury (the “Secretary”) to administer the BSA and its implementing regulations has been delegated to the Director of FinCEN. ^1
^1 Therefore, references to the authority of the Secretary of the Treasury under Section 311 of the USA PATRIOT Act apply equally to the Director of FinCEN.
Section 311 of the USA PATRIOT Act (“Section 311”), codified at 31 U.S.C. 5318A, grants the Director of FinCEN the authority, upon finding that reasonable grounds exist for concluding that a foreign jurisdiction, financial institution, class of transactions, or type of account is of “primary money laundering concern,” to require domestic financial institutions and financial agencies to take certain “special measures” to address the primary money laundering concern.

II. Imposition of a Special Measure Against North Korea as a Jurisdiction of Primary Money Laundering Concern

A. Proposed Imposition of Special Measure Five
As noticed in the June 2, 2016 Federal Register , on May 27, 2016, the Director of FinCEN found that North Korea is a jurisdiction of primary money laundering concern (the “Finding”). ^2 Based upon that Finding, the Director of FinCEN is authorized to impose one or more special measures. Following the consideration of all factors relevant to the Finding and to selecting the special measure proposed in this NPRM, the Director of FinCEN proposes to impose the fifth special measure authorized by section 5318A(b)(5), (the “fifth special measure”). This special measure would prohibit covered financial institutions from opening or maintaining a correspondent account in the United States for or on behalf of a North Korean banking institution. Covered financial institutions would also be prohibited from processing a transaction involving a North Korean financial institution through the United States correspondent account of a foreign banking institution.
^2 Classified information used in support of a section 311 finding and special measure(s) may be submitted by FinCEN to a reviewing court ex parte and in camera. See section 376 of the Intelligence Authorization Act for fiscal year 2004, Public Law 108-177 (amending U.S.C. 5318A by adding new paragraph (f)).
In addition, covered financial institutions would be required under the BSA to apply special due diligence to their foreign correspondent accounts that is reasonably designed to guard against their use to process transactions involving North Korean financial institutions. These proposed requirements are discussed in more detail below. In connection with this action, FinCEN consulted with the Federal Reserve, representatives of the Federal functional regulators, the Department of Justice, and the Department of State, among others.
FinCEN requests comments on all aspects of its proposal to impose the fifth special measure, to include comments on the proposed prohibition on covered financial institutions from opening or maintaining a correspondent account in the United States for or on behalf of a North Korean banking institution.

B. Discussion of Section 311 Factors
In determining which special measures to implement to address the primary money laundering concern described in the associated Notice of Finding, FinCEN considered the following factors.

1. Whether Similar Action Has Been or Will Be Taken by Other Nations or Multilateral Groups Against North Korea
The international community has taken steps to address North Korean's illicit financial activity. Between 2006 and 2016 the United Nations Security Council has adopted multiple resolutions, 1718, ^3 1874, ^4 2087, ^5 2094, ^6 and 2270 ^7 which generally restrict North Korea's financial and operational activities related to its nuclear and missile programs and conventional arms sales. Most recently, in March 2016, the United Nations adopted United Nations Security Council Resolution (UNSCR) 2270, which imposes additional sanctions on North Korea in response to a January 6, 2016 nuclear test and February 7, 2016 launch using ballistic missile technology. This UNSCR contains provisions that generally require nations to: (i) Prohibit North Korean banks from opening branches in their territory or engaging in certain correspondent relationships with these banks; (ii) terminate existing representative offices or subsidiaries, branches, and correspondent accounts with North Korean financial institutions; (iii) prohibit their financial institutions from opening new representative offices or subsidiaries, branches, or bank accounts in North Korea; and (iv) to close existing representative offices or subsidiaries, branches, or bank accounts in North Korea if reasonable grounds exist to believe such financial services could contribute to North Korea's nuclear or missile programs, or UNSCR violations.
^3 See United Nations Security Council Resolution (“UNSCR”) 1718 ( http://www.un.org/en/ga/search/view_doc.asp?symbol=S/RES/1718(2006) ).
^4 See UNSCR 1874 ( http://www.un.org/en/ga/search/view_doc.asp?symbol=S/RES/1874(2009).
^5 See UNSCR 2087 ( http://www.un.org/en/ga/search/view_doc.asp?symbol=S/RES/2087(2013) ).
^6 See UNSCR 2094 ( http://www.un.org/en/ga/search/view_doc.asp?symbol=S/RES/2094(2013) ).
^7 See UNSCR 2270 ( http://www.un.org/en/ga/search/view_doc.asp?symbol=S/RES/2270(2016) ).
The Financial Action Task Force (“FATF”) has issued a series of public statements expressing its concern that North Korea's lack of a comprehensive AML/CFT regime represents a significant vulnerability within the international financial system. The statements further called upon North Korea to address those deficiencies with urgency, and called upon FATF members and urged all jurisdictions to advise their financial institutions to give special attention to business relationships and transactions with North Korea, to protect their correspondent accounts from being used to evade countermeasures and risk mitigation practices. Starting in February 2011, the FATF called upon its members and urged all jurisdictions to apply effective counter-measures to protect their financial sectors from the money laundering and financing of terrorism risks emanating from North Korea. ^8
^8 See “FATF Public Statement—19 February 2016,” Financial Action Task Force ( http://www.fatf-gafi.org/publications/high-riskandnon-cooperativejurisdictions/documents/public-statement-february-2016.html ).

2. Whether the Imposition of the Fifth Special Measure Would Create a Significant Competitive Disadvantage, Including Any Undue Cost or Burden Associated With Compliance, for Financial Institutions Organized or Licensed in the United States
The fifth special measure proposed by this rulemaking would, after the effective date of the final rule, prohibit covered financial institutions from opening or maintaining a correspondent account in the United States for or on behalf of a North Korean banking institution. It would also prohibit the use of a foreign banking institution's U.S. correspondent account to process a transaction involving a North Korean financial institution. As noted in FinCEN's Notice of Finding, none of North Korea's financial institutions currently maintain correspondent accounts directly with U.S. banks. Further, as noted above, U.S. financial institutions are currently subject to a range of prohibitions related to sanctions concerning North Korea, which has generally limited their direct exposure to the North Korean financial system. Therefore, FinCEN believes this action will not present an undue regulatory burden.
Covered financial institutions would also potentially be required to apply special due diligence to their foreign correspondent accounts that is reasonably designed to guard against their use to process transactions involving North Korean financial institutions. For direct correspondent relationships, this would involve a minimal burden in transmitting a one-time notice to certain foreign correspondent account holders concerning the prohibition on processing transactions involving a North Korean financial institution through the U.S. correspondent account. U.S. financial institutions generally apply some level of screening and, when required, conduct some level of reporting of their transactions and accounts, often through the use of commercially available software such as that used for compliance with the economic sanctions programs administered by the Office of Foreign Assets Control (“OFAC”) of the Department of the Treasury and to detect potential suspicious activity. To ensure that U.S. financial institutions are not being used unwittingly to process payments for, or on behalf of, a North Korean financial institution, directly or indirectly, some marginal additional burden will be incurred by U.S. financial institutions to be vigilant in their suspicious activity monitoring procedures. As explained in more detail in the section-by-section analysis below, financial institutions should be able to leverage these current screening and reporting procedures to detect transactions involving a North Korean financial institution.

3. The Extent to Which the Proposed Action or Timing of the Action Will Have a Significant Adverse Systemic Impact on the International Payment, Clearance, and Settlement System, or on Legitimate Business Activities of North Korea
Financial institutions in North Korea are generally not major participants in the international payment system and are not relied upon by the international banking community for clearance or settlement services. In addition, given existing domestic and multilateral sanctions, coupled with the FATF calls for countermeasures to address North Korea's AML/CFT deficiencies, it is unlikely that the imposition of the fifth special measure against North Korea would have a significant adverse systemic impact on the international payment, clearance, and settlement system. In light of the reasons for imposing this special measure, and based on available information, FinCEN does not believe that it would impose an undue burden on legitimate business activities.

4. The Effect of the Proposed Action on United States National Security and Foreign Policy
The exclusion from the U.S. financial system of jurisdictions that serve as conduits for significant money laundering activity, for the financing of weapons of mass destruction or their delivery systems, and for other financial crimes enhances national security by making it more difficult for terrorists, proliferators, and money launderers to access the U.S. financial system. To the extent that this action serves as an additional tool in preventing North Korea from accessing the U.S. financial system, the proposed action would support and uphold U.S. national security and foreign policy goals. The imposition of the fifth special measure also would complement the U.S. Government's worldwide efforts to expose and disrupt international money laundering.
Therefore, pursuant to the Finding that North Korea is a jurisdiction of primary money laundering concern, and after conducting the required consultations and weighing the relevant factors, the Director of FinCEN proposes to impose the fifth special measure.

C. Consideration of Alternative Special Measures
As noted above, and in FinCEN's Notice of Finding, North Korea is subject to numerous United Nations Security Council Resolutions ^9 and U.S. sanctions authorities, ^{10} and it has been consistently identified by the FATF for its AML deficiencies. ^{11} The U.N. has specifically called for enhanced monitoring of financial transactions to prevent the financing of North Korea's nuclear and ballistic missile programs and the freezing of any assets suspected of supporting these illicit programs. Additionally, FinCEN has issued three advisories since 2005 detailing specific concerns of the deceptive financial practices used by North Korea and North Korean entities and calling on U.S. financial institutions to take appropriate risk mitigation measures. However, North Korea has not taken any substantial action to address the range of concerns and continues to be involved in an array of illicit activities, as reflected in the Notice of Finding.
^9 See UNSCRs 1718, 1874, 2087, 2094, and 2270.
^{10} See, e.g., Executive Order (“E.O.”) 13382 “Blocking Property of Weapons of Mass Destruction Proliferators and Their Supporters” (2005) ( https://www.federalregister.gov/articles/2005/07/01/05-13214/blocking-property-of-weapons-of-mass-destruction-proliferators-and-their-supporters ); E.O. 13551 “Blocking Property of Certain Persons with Respect to North Korea” (2010) ( https://www.gpo.gov/fdsys/pkg/FR-2010-09-01/pdf/X10-10901.pdf ); E.O. 13687 “Imposing Additional Sanctions with Respect to North Korea” (2015) ( https://www.federalregister.gov/articles/2015/01/06/2015-00058/imposing-additional-sanctions-with-respect-to-north-korea ); E.O. 13722 “Blocking Property of the Government of North Korea and the Workers' Party of Korea, and Prohibiting Certain Transactions with Respect to North Korea,” (2016) ( https://www.gpo.gov/fdsys/pkg/FR-2016-03-18/pdf/FR-2016-03-18.pdf ).
^{11} See “FATF Public Statement—19 February 2016,” Financial Action Task Force ( http://www.fatf-gafi.org/publications/high-riskandnon-cooperativejurisdictions/documents/public-statement-february-2016.html ).
The special measures enumerated under Section 311 are prophylactic safeguards that defend the U.S. financial system from money laundering and terrorist financing. FinCEN may impose a range of these special measures in order to protect the U.S. financial system from these threats. To that end, special measures one through four impose additional recordkeeping, information collection, and information reporting requirements on covered U.S. financial institutions. The fifth special measure establishes prohibitions or conditions on opening or maintaining certain correspondent or payable-through accounts. North Korea's complicity in money laundering and illicit financial activity, and flagrant disregard for multiple UN resolutions related to the proliferation of weapons of mass destruction, constitute a threat to the integrity of the U.S. financial system. Further, in light of existing sanctions on North Korea, FinCEN is concerned that any condition, additional recordkeeping, or reporting requirement would not be an effective measure to safeguard the U.S. financial system. In the case of the jurisdiction of North Korea, FinCEN views the fifth special measure, with its prohibitions on the opening or maintenance of a correspondent account for or on behalf of a North Korean banking institution, and on the use of a foreign correspondent account to process a transaction involving a North Korean financial institution, as the special measure that can adequately protect the U.S. financial system from North Korean illicit financial activity.

III. Section-by-Section Analysis for Imposition of the Fifth Special Measure
The proposed rule would prohibit covered financial institutions from opening or maintaining in the United States a correspondent account for or on behalf of a North Korean banking institution. It would also prohibit the use of a foreign banking institution's U.S. correspondent account to process a transaction involving a North Korean financial institution. As a corollary to this prohibition, covered financial institutions would be required to screen their correspondents in a manner that is reasonably designed to guard against use by foreign banking institutions to process transactions on behalf of a North Korean financial institution, including access through the use of indirect correspondent accounts held by those foreign institutions. A violation of the special measure could result in the imposition of civil monetary or criminal penalties.

A. 1010.659(a)—Definitions

1. North Korean Financial Institution
A North Korean financial institution would mean any branch, office, or subsidiary of any foreign financial institution, as defined at 31 CFR 1010.605(f), chartered or licensed by North Korea, including any branches, offices, or subsidiaries of such financial institution operating in any jurisdiction, and any branch or office within North Korea of any foreign financial institution.

2. Foreign Banking Institution
Foreign banking institution has the same meaning as provided in 31 CFR 1010.100(u).

3. Correspondent Account
Section 1010.659(a)(3) of the proposed rule would define the term “correspondent account” by reference to the definition contained in 31 CFR 1010.605(c)(1)(i). Section 1010.605(c)(1)(i) defines a correspondent account to mean an account established to receive deposits from, or make payments or other disbursements on behalf of, a foreign financial institution, or to handle other financial transactions related to the foreign financial institution. Under this definition, “payable through accounts” are a type of correspondent account.
In the case of a U.S. depository institution, this broad definition includes most types of banking relationships between a U.S. depository institution and a foreign bank that are established to provide regular services, dealings, and other financial transactions, including a demand deposit, savings deposit, or other transaction or asset account, and a credit account or other extension of credit. FinCEN is using the same definition of “account” for purposes of this proposed rule as was established for depository institutions in the final rule implementing the provisions of section 312 of the USA PATRIOT Act requiring enhanced due diligence for correspondent accounts maintained for certain foreign banks. ^{12}
^{12} See 31 CFR 1010.605(c)(2)(i).
In the case of securities broker-dealers, futures commission merchants, introducing brokers-commodities, and investment companies that are open-end companies (“mutual funds”), FinCEN is also using the same definition of “account” for purposes of this proposed rule as was established for these entities in the final rule implementing the provisions of section 312 of the USA PATRIOT Act requiring enhanced due diligence for correspondent accounts maintained for certain foreign banks. ^{13}
^{13} See 31 CFR 1010.605(c)(2)(ii)-(iv).

4. Covered Financial Institution
Section 1010.659(a)(4) of the proposed rule would define “covered financial institution” with the same definition used in the final rule implementing the provisions of section 312 of the USA PATRIOT Act, ^{14} which in general includes the following:
^{14} See 31 CFR 1010.605(e)(1).
• An insured bank (as defined in section 3(h) of the Federal Deposit Insurance Act (12 U.S.C. 1813(h);
• a commercial bank;
• an agency or branch of a foreign bank in the United States;
• a Federally insured credit union;
• a savings association;
• a corporation acting under section 25A of the Federal Reserve Act (12 U.S.C. 611);
• a trust bank or trust company;
• a broker or dealer in securities;
• a futures commission merchant or an introducing broker-commodities; and
• a mutual fund.

5. Subsidiary
Section 1010.659(a)(5) of the proposed rule would define “subsidiary” as a company of which more than 50 percent of the voting stock or analogous equity interest is owned by another company.

B. 1010.659(b)—Prohibition on Accounts and Due Diligence Requirements for Covered Financial Institutions

1. Prohibition on Opening or Maintaining Correspondent Accounts
Section 1010.659(b)(1) and (2) of the proposed rule would prohibit covered financial institutions from establishing, maintaining, administering, or managing in the United States any correspondent account for or on behalf of a North Korean banking institution. It would also prohibit processing of a transaction involving a North Korean financial institution through the U.S. correspondent account of a foreign banking institution. These prohibitions would not supersede the blocking of property under any Executive order issued pursuant to the International Emergency Economic Powers Act (50 U.S.C. 1701 et seq. ) (IEEPA) or 31 CFR Chapter V.

2. Special Due Diligence for Correspondent Accounts To Prohibit Use
As a corollary to the prohibitions set forth in section 1010.659(b)(1) and (2), section 1010.659(b)(3) of the proposed rule would require a covered financial institution to apply special due diligence to all of its foreign correspondent accounts that is reasonably designed to guard against processing transactions involving North Korean financial institutions. As part of that special due diligence, covered financial institutions must notify those foreign correspondent account holders that the covered financial institutions know or have reason to believe provide services to a North Korean financial institution that such correspondents may not provide a North Korean financial institution with access to the correspondent account maintained at the covered financial institution. A covered financial institution may satisfy this notification requirement using the following notice:
Notice: Pursuant to U.S. regulations issued under Section 311 of the USA PATRIOT Act, see 31 CFR 1010.659, we are prohibited from establishing, maintaining, administering, or managing a correspondent account for, or on behalf of, a North Korean financial institution. The regulations also require us to notify you that you may not provide a North Korean financial institution, including any of its branches, offices, or subsidiaries, with access to the correspondent account you hold at our financial institution. If we become aware that the correspondent account you hold at our financial institution has processed any transactions involving a North Korean financial institution, including any of its branches, offices, or subsidiaries, we will be required to take appropriate steps to prevent such access, including terminating your account.
Covered financial institutions should implement appropriate risk-based procedures to identify transactions involving a North Korean financial institution. A covered financial institution may, for example, have knowledge through transaction screening software that a correspondent processes transactions for a North Korean financial institution. The purpose of the notice requirement is to aid cooperation with correspondent account holders in preventing transactions involving a North Korean financial institution from accessing the U.S. financial system. FinCEN would not require or expect a covered financial institution to obtain a certification from any of its correspondent account holders that access will not be provided to comply with this notice requirement.
Methods of compliance with the notice requirement could include, for example, transmitting a one-time notice by mail, fax, or email. The notice should be transmitted whenever a covered financial institution knows or has reason to believe that a foreign correspondent account holder provides services to a North Korean financial institution. FinCEN specifically solicits comments on the form and scope of the notice that would be required under the rule.
The special due diligence would also include implementing risk-based procedures designed to identify any use of correspondent accounts to process transactions involving North Korean financial institutions. A covered financial institution would be expected to apply an appropriate screening mechanism to identify a funds transfer order that on its face listed a North Korean financial institution as the financial institution of the originator or beneficiary, or otherwise referenced a North Korean financial institution in a manner detectable under the financial institution's normal screening mechanisms. An appropriate screening mechanism could be the mechanisms used by a covered financial institution to comply with various legal requirements, such as the commercially available software programs used to comply with the economic sanctions programs administered by OFAC.
A covered financial institution would also be required to implement risk-based procedures to identify indirect use of its correspondent accounts, including through methods used to disguise the originator or originating institution of a transaction. Specifically, FinCEN is concerned that a North Korean financial institution may attempt to disguise its transactions by relying on types of payments and accounts, including the use of front companies, which would not explicitly identify the North Korean institution as an involved party in the transaction. A financial institution may develop a suspicion of such misuse based on other information in its possession, patterns of transactions, or any other method available to it based on its existing systems. Under the proposed rule, a covered financial institution that suspects or has reason to suspect use of a correspondent account to process a transaction involving a North Korean financial institution must take all appropriate steps to attempt to verify and prevent such use, including a notification to its correspondent account holder requesting further information regarding a transaction, requesting corrective action to address the perceived risk and, where necessary, terminating the correspondent account. A covered financial institution may re-establish an account closed under the rule if it determines that the account will not be used to process transactions involving North Korean financial institutions. FinCEN specifically solicits comments on the requirement under the proposed rule that covered financial institutions take reasonable steps to prevent any processing of transactions involving North Korean financial institutions.

3. Recordkeeping and Reporting
Section 1010.659(b)(4) of the proposed rule would clarify that paragraph (b) of the rule does not impose any reporting requirement upon any covered financial institution that is not otherwise required by applicable law or regulation. A covered financial institution must, however, document its compliance with the notification requirement under section 1010.659(b)(3)(i)(A).

IV. Request for Comments
FinCEN invites comments on all aspects of the proposal to impose the fifth special measure against North Korea and specifically invites comments on the following matters:
1. The finding that North Korea is a jurisdiction of primary money laundering concern;
2. The form and scope of the notice to certain correspondent account holders that would be required under the rule;
3. The appropriate scope of the proposed requirement for a covered financial institution to take reasonable steps to identify any use of its foreign correspondent accounts to process transactions involving North Korean financial institutions; and
4. The appropriate steps a covered financial institution should take once it identifies use of one of its foreign correspondent accounts to process transactions involving a North Korean financial institution.

V. Regulatory Flexibility Act
When an agency issues a rulemaking proposal, the Regulatory Flexibility Act (“RFA”) requires the agency to “prepare and make available for public comment an initial regulatory flexibility analysis” that will “describe the impact of the proposed rule on small entities.” (5 U.S.C. 603(a)). Section 605 of the RFA allows an agency to certify a rule, in lieu of preparing an analysis, if the proposed rulemaking is not expected to have a significant economic impact on a substantial number of small entities.

A. Proposal To Prohibit Covered Financial Institutions From Opening or Maintaining Correspondent Accounts With Certain Foreign Banks Under the Fifth Special Measure

1. Estimate of the Number of Small Entities to Whom the Proposed Fifth Special Measure Will Apply
For purposes of the RFA, both banks and credit unions are considered small entities if they have less than $550,000,000 in assets. ^{15} Of the estimated 6,192 banks, 80 percent have less than $550,000,000 in assets and are considered small entities. ^{16} Of the estimated 6,021 credit unions, 92.5 percent have less than $550,000,000 in assets. ^{17}
^{15} Table of Small Business Size Standards Matched to North American Industry Classification System Codes, Small Business Administration Size Standards (SBA Feb. 26, 2016) [hereinafter “ SBA Size Standards” ]. ( https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf ).
^{16} Federal Deposit Insurance Corporation, Find an Institution, http://www2.fdic.gov/idasp/main.asp;
select Size or Performance: Total Assets, type Equal or less than $: “550000” and select Find.
^{17} National Credit Union Administration, Credit Union Data, http://webapps.ncua.gov/customquery/; select Search Fields: Total Assets, select Operator: Less than or equal to, type Field Values: “550000000” and select Go.
Broker-dealers are defined in 31 CFR 1010.100(h) as those broker-dealers required to register with the Securities and Exchange Commission (SEC). For the purposes of the RFA, FinCEN relies on the SEC's definition of small business as previously submitted to the Small Business Administration (SBA). The SEC has defined the term small entity to mean a broker or dealer that: (1) Had total capital (net worth plus subordinated liabilities) of less than $500,000 on the date in the prior fiscal year as of which its audited financial statements, were prepared pursuant to Rule 17a-5(d) or, if not required to file such statements, a broker or dealer that had total capital (net worth plus subordinated debt) of less than $500,000 on the last business day of the preceding fiscal year (or in the time that it has been in business if shorter); and (2) is not affiliated with any person (other than a natural person) that is not a small business or small organization as defined in this release. ^{18} Based on SEC estimates, 17 percent of broker-dealers are classified as small entities for purposes of the RFA. ^{19}
^{18} 17 CFR 240.0-10(c).
^{19} 76 FR 37572, 37602 (June 27, 2011) (the SEC estimates 871 small broker-dealers of the 5,063 total registered broker-dealers).
Futures commission merchants (FCMs) are defined in 31 CFR 1010.100(x) as those FCMs that are registered or required to be registered as a FCM with the Commodity Futures Trading Commission (CFTC) under the Commodity Exchange Act (CEA), except persons who register pursuant to section 4f(a)(2) of the CEA, 7 U.S.C. 6f(a)(2). Because FinCEN and the CFTC regulate substantially the same population, for the purposes of the RFA, FinCEN relies on the CFTC's definition of small business as previously submitted to the SBA. In the CFTC's “Policy Statement and Establishment of Definitions of `Small Entities' for Purposes of the Regulatory Flexibility Act,” the CFTC concluded that registered FCMs should not be considered to be small entities for purposes of the RFA. ^{20} The CFTC's determination in this regard was based, in part, upon the obligation of registered FCMs to meet the capital requirements established by the CFTC.
^{20} 47 FR 18618, 18619 (Apr. 30, 1982).
For purposes of the RFA, an introducing broker-commodities dealer is considered small if it has less than $35,500,000 in gross receipts annually. ^{21} Based on information provided by the National Futures Association (NFA), 95 percent of introducing brokers-commodities dealers have less than $35.5 million in adjusted net capital and are considered to be small entities.
^{21} SBA Size Standards at 28.
Mutual funds are defined in 31 CFR 1010.100(gg) as those investment companies that are open-end investment companies that are registered or are required to register with the SEC. For the purposes of the RFA, FinCEN relies on the SEC's definition of small business as previously submitted to the SBA. The SEC has defined the term “small entity” under the Investment Company Act to mean “an investment company that, together with other investment companies in the same group of related investment companies, has net assets of $50 million or less as of the end of its most recent fiscal year.” ^{22} Based on SEC estimates, seven percent of mutual funds are classified as “small entities” for purposes of the RFA under this definition. ^{23}
^{22} 17 CFR 270.0-10.
^{23} 78 FR 23637, 23658 (April 19, 2013).
As noted above, 80 percent of banks, 92.5 percent of credit unions, 17 percent of broker-dealers, 95 percent of introducing broker-commodities dealers, no FCMs, and seven percent of mutual funds are small entities.

2. Description of the Projected Reporting and Recordkeeping Requirements of the Fifth Special Measure
The proposed fifth special measure would require covered financial institutions to provide a notification intended to aid cooperation from foreign correspondent account holders in preventing transactions involving North Korean financial institutions from being processed by the U.S. financial system. FinCEN estimates that the burden on institutions providing this notice is one hour. Covered financial institutions would also be required to take reasonable measures to detect use of their correspondent accounts to process transactions involving North Korean financial institutions.
All U.S. persons, including U.S. financial institutions, currently must comply with OFAC sanctions, and U.S. financial institutions have suspicious activity reporting requirements. U.S. financial institutions are currently subject to a range of sanctions prohibitions related to North Korea, which has limited their direct exposure to the North Korean financial system. More recently, on March 15, 2016, the President issued Executive Order 13722, which places additional sanctions on North Korea and has the effect of generally prohibiting U.S. financial institutions from processing transactions involving persons located in North Korea and the North Korean government, unless authorized by OFAC. ^{24} Therefore, current transactional activity between U.S. financial institutions and North Korean banks is very constricted. Further, North Korea is subject to a range of United Nations sanctions resolutions and it has been consistently called out by the FATF for its AML deficiencies. This has limited the number of foreign banking institutions that maintain ties or accounts with North Korean banks. Thus, the special due diligence that would be required under the BSA by the imposition of the fifth special measure— i.e., the one-time transmittal of notice to certain correspondent account holders, the screening of transactions to identify any use of correspondent accounts, and the implementation of risk-based measures to detect use of correspondent accounts—would not impose a significant additional economic burden upon small U.S. financial institutions.
^{24} See E.O. 13722 “Blocking Property of the Government of North Korea and the Workers Party of Korea, and Prohibiting Certain Transactions With Respect to North Korea” (2016) ( https://www.gpo.gov/fdsys/pkg/FR-2016-03-18/pdf/FR-2016-03-18.pdf ).

B. Certification
For these reasons, FinCEN certifies that the proposals contained in this rulemaking would not have a significant impact on a substantial number of small businesses.
FinCEN invites comments from members of the public who believe there would be a significant economic impact on small entities from the imposition of the fifth special measure regarding North Korea.

VI. Paperwork Reduction Act
The collection of information contained in this proposed rule is being submitted to the Office of Management and Budget for review in accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)). Comments on the collection of information should be sent to the Desk Officer for the Department of Treasury, Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project (1506), Washington, DC 20503 (or by email to oira submission@omb.eop.gov) with a copy to FinCEN by mail or email at the addresses previously specified. Comments should be submitted by one method only. Comments on the collection of information should be received by August 2, 2016. In accordance with the requirements of the Paperwork Reduction Act and its implementing regulations, 5 CFR 1320, the following information concerning the collection of information as required by 31 CFR 1010.659 is presented to assist those persons wishing to comment on the information collection.

A. Proposed Information Collection Under the Fifth Special Measure
The notification requirement in section 1010.659(b)(3)(i) is intended to aid cooperation from correspondent account holders in denying North Korea access to the U.S. financial system. The information required to be maintained by section 1010.659(b)(4)(i) would be used by federal agencies and certain self-regulatory organizations to verify compliance by covered financial institutions with the provisions of 31 CFR 1010.659. The collection of information would be mandatory.
Description of Affected Financial Institutions: Banks, broker-dealers in securities, futures commission merchants and introducing brokers- commodities, money services businesses, and mutual funds.
Estimated Number of Affected Financial Institutions: 5,000.
Estimated Average Annual Burden in Hours Per Affected Financial Institution: The estimated average burden associated with the collection of information in this proposed rule is one hour per affected financial institution.
Estimated Total Annual Burden: 5,000 hours.
FinCEN specifically invites comments on: (a) Whether the proposed collection of information is necessary for the proper performance of the mission of FinCEN, including whether the information would have practical utility; (b) the accuracy of FinCEN's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information required to be maintained; (d) ways to minimize the burden of the required collection of information, 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 report the information.
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.

VII. Executive Order 12866
Executive Orders 12866 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). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. It has been determined that the proposed rule is not a “significant regulatory action” for purposes of Executive Order 12866.

List of Subjects in 31 CFR Part 1010
Administrative practice and procedure, Banks and banking, Brokers, Counter-money laundering, Counter-terrorism, Foreign banking.

Authority and Issuance
For the reasons set forth in the preamble, part 1010, chapter X of title 31 of the Code of Federal Regulations, is proposed to be amended as follows:

PART 1010—GENERAL PROVISIONS
1. The authority citation for part 1010 is revised to read as follows:

Authority:
12 U.S.C. 1829b and 1951-1959; 31 U.S.C. 5311-5314, 5316-5332; Title III, sec. 314 Pub. L. 107-56, 115 Stat. 307.
2. Add § 1010.659 to read as follows:
§ 1010.659
Special measures against North Korea.
(a) Definitions. For purposes of this section:
(1) North Korean financial institution means all branches, offices, or subsidiaries of any foreign financial institution, as defined at § 1010.605(f), chartered or licensed by North Korea, wherever located, including any branches, offices, or subsidiaries of such financial institution operating in any jurisdiction, and any branch or office within North Korea of any foreign financial institution.
(2) Foreign banking institution has the same meaning as provided in § 1010.100(u).
(3) Correspondent account has the same meaning as provided in § 1010.605(c)(1)(i).
(4) Covered financial institution has the same meaning as provided in § 1010.605(e)(1).
(5) Subsidiary means a company of which more than 50 percent of the voting stock or analogous equity interest is owned by another company.
(b) Prohibition on accounts and due diligence requirements for covered financial institutions —(1) Opening or maintenance of correspondent accounts. A covered financial institution shall not open or maintain in the United States a correspondent account for, or on behalf of, a North Korean banking institution.
(2) Prohibition on use of correspondent accounts. A covered financial institution shall not process a transaction for the correspondent account of a foreign banking institution in the United States if such transaction involves a North Korean financial institution.
(3) Special due diligence of correspondent accounts to prohibit use. (i) A covered financial institution shall apply special due diligence to its foreign correspondent accounts that is reasonably designed to guard against their use to process transactions involving North Korean financial institutions. At a minimum, that special due diligence must include:
(A) Notifying those foreign correspondent account holders that the covered financial institution knows or has reason to believe provide services to a North Korean financial institution that such correspondents may not provide a North Korean financial institution with access to the correspondent account maintained at the covered financial institution; and
(B) Taking reasonable steps to identify any use of its foreign correspondent accounts by a North Korean financial institution, to the extent that such use can be determined from transactional records maintained in the covered financial institution's normal course of business.
(ii) A covered financial institution shall take a risk-based approach when deciding what, if any, other due diligence measures it reasonably must adopt to guard against the use of its foreign correspondent accounts to process transactions involving North Korean financial institutions.
(iii) A covered financial institution that knows or has reason to believe that a foreign banking institution's correspondent account has been or is being used to process transactions involving a North Korean financial institution shall take all appropriate steps to further investigate and prevent such access, including the notification of its correspondent account holder under paragraph (b)(3)(i)(A) of this section and, where necessary, termination of the correspondent account.
(4) Recordkeeping and reporting. (i) A covered financial institution is required to document its compliance with the notice requirement set forth in paragraph (b)(3)(i)(A) of this section.
(ii) Nothing in this paragraph (b) shall require a covered financial institution to report any information not otherwise required to be reported by law or regulation.
Jamal El-Hindi,

Acting Director, Financial Crimes Enforcement Network.
DEPARTMENT OF HOMELAND SECURITY
Coast Guard
33 CFR Part 165
[Docket Number USCG-2016-0340]
RIN 1625-AA00
Safety Zones; Safety Zones Within the Captain of the Port New Orleans Zone; New Orleans to Baton Rouge, LA

AGENCY:
Coast Guard, DHS.

ACTION:
Notice of proposed rulemaking.

SUMMARY:
The Coast Guard proposes to establish temporary safety zones for multiple locations and dates within the Captain of the Port New Orleans' zone. These safety zones are necessary to protect persons and vessels from potential safety hazards associated with fireworks displays on or over federal waterways. Entry into these zones is prohibited unless specifically authorized by the Captain of the Port New Orleans or a designated representative.

DATES:
Comments and related material must be received by the Coast Guard on or before June 20, 2016.

ADDRESSES:
You may submit comments identified by docket number USCG-2016-0340 using the Federal eRulemaking Portal at http://www.regulations.gov. See the “Public Participation and Request for Comments” portion of the SUPPLEMENTARY INFORMATION section for further instructions on submitting comments.

FOR FURTHER INFORMATION CONTACT:
If you have questions about this proposed rulemaking, call or email Lieutenant Commander (LCDR) James Gatz, Sector New Orleans, at (504) 365-2281 or James.C.Gatz@uscg.mil.

SUPPLEMENTARY INFORMATION:

I. Table of Abbreviations
BNM Broadcast Notice to Mariners
CFR Code of Federal Regulations
DHS Department of Homeland Security
FR Federal Register
MSIB Marine Safety Information Bulletin
NPRM Notice of proposed rulemaking
§ Section
U.S.C. United States Code

II. Background, Purpose, and Legal Basis
The Coast Guard proposes establishment of temporary safety zones for the following upcoming fireworks displays:
(1) A corporate event scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on June 15, 2016. The fireworks barge will be positioned adjacent to the foot of Dumaine Street in New Orleans, LA, at approximate mile marker 94.5 above Head of Passes on the Lower Mississippi River. The Coast Guard was notified about this event on April 18, 2016.
(2) The Llamasoft Convention scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on June 16, 2016. The fireworks barge will be positioned adjacent to Spanish Plaza in New Orleans, LA, at approximate mile marker 95.0 above Head of Passes on the Lower Mississippi River. The Coast Guard was notified about this event on April 1, 2016.
(3) The U.S. Travel Association's “IPW” Conference scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on June 22, 2016. The fireworks barge will be positioned adjacent to Mardi Gras World in New Orleans, LA, at approximate mile marker 96.2 above Head of Passes on the Lower Mississippi River. The Coast Guard was notified about this event on April 1, 2016.
(4) The St. John the Baptist Parish Independence Day Celebration scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on June 30, 2016. The fireworks barge will be positioned adjacent to the Parish Courthouse in Edgard, LA, at approximate mile marker 138.0 above Head of Passes on the Lower Mississippi River. The Coast Guard was notified about this event on March 15, 2016. This is an annually recurring event that is published in 33 CFR 165.801, Table 5, line no. 2. This year's occurrence is scheduled for a different date and location than currently listed in the CFR. Should a permanent change be necessary for this safety zone, we will include it in a future rulemaking proposing permanent updates to 33 CFR 165.801, Table 5.
(5) The L'Auberge Casino Independence Day Celebration scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on July 4, 2016. The fireworks barge will be positioned adjacent to the L'Auberge Casino in Baton Rouge, LA, at approximate mile marker 216.5 above Head of Passes on the Lower Mississippi River. The Coast Guard was notified about this event on January 27, 2016. This is an annually-recurring event that is not currently published in Table 5 of 33 CFR 165.801. We plan to include it in a future rulemaking proposing permanent updates to 33 CFR 165.801, Table 5.
(6) The City of Mandeville Independence Day Celebration scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on July 4, 2016. The fireworks barge will be positioned adjacent to the Mandeville City Lakefront in Mandeville, LA, at approximate position 30° 21.200 N., 90° 04.500 W. The Coast Guard was notified about this event on March 14, 2016. A safety zone was established in 2015 for a similar event. Based on the history of this event and safety zone need, we are considering making this safety zone a permanent recurring regulation, and may include it in a future rulemaking proposing permanent updates to 33 CFR 165.801, Table 5.
(7) The American Psychological Association Convention scheduled for one hour in the evening between 6:00 p.m. and 11:00 p.m. on September 23, 2016. The fireworks barge will be positioned adjacent to Dumaine Street in New Orleans, LA, at approximate mile marker 94.5 above Head of Passes on the Lower Mississippi River. The Coast Guard was notified about this event on February 24, 2016.
Due to the risks associated with aerial barge-based fireworks displays taking place on and over these sections of navigable waterways, the proposed safety zones are needed to protect persons and property. The Coast Guard would notify the public and maritime community of the proposed safety zones and their respective enforcement periods via broadcast notices to mariners (BNM). The Coast Guard proposes this rulemaking under authority in 33 U.S.C. 1231.

III. Discussion of Proposed Rule
The Coast Guard proposes to establish multiple temporary safety zones within the Captain of the Port New Orleans (COTP) Zone on several different dates and in several different locations. The safety zones to be established would be enforced on the respective dates listed above and in the proposed regulatory text as provided at the end of this document. Each safety zone will be limited to a duration of one hour, and will occur during the evenings on the dates specified, between the hours of 6:00 p.m. and 11:00 p.m. Entry into these safety zones is prohibited unless permission has been granted by the COTP New Orleans, or a designated representative.
The COTP New Orleans will inform the public through BNMs of the enforcement period for each safety zone as well as any changes in the planned schedule. Mariners and other members of the public may also contact Coast Guard Sector New Orleans Command Center to inquire about the status of the safety zone by calling (504) 365-2200.

IV. Regulatory Analyses
We developed this proposed rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive orders and we discuss First Amendment rights of protestors.

A. Regulatory Planning and Review
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This NPRM has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, the NPRM has not been reviewed by the Office of Management and Budget.
Six of these proposed safety zones would be no greater than 1 river mile in length and would restrict navigation on the Lower Mississippi River for no longer than one hour each. The remaining proposed safety zone would be limited to a circular area 1200 feet in diameter located along the North Shore of Lake Pontchartrain, in an area with ample room for other traffic to navigate around the safety zone, and would be in effect for no longer than one hour. Due to the limited scope and short duration of each proposed safety zone, the impacts on routine navigation are expected to be minimal. Additionally, the Coast Guard would issue maritime notices widely available to waterway users and deviation from the proposed safety zones may be requested and would be considered on a case-by-case basis.

B. Impact on Small Entities
The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.
While some owners or operators of vessels intending to transit the safety zones may be small entities, for the reasons stated in section IV.A above this proposed rule would not have a significant economic impact on any vessel owner or operator. If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see ADDRESSES ) explaining why you think it qualifies and how and to what degree this rule would economically affect it.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Public Law 104-121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section. The Coast Guard will not retaliate against small entities that question or complain about this proposed rule or any policy or action of the Coast Guard.

C. Collection of Information
This proposed rule would not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

D. Federalism and Indian Tribal Governments
A rule has implications for federalism under Executive Order 13132, Federalism, if it has 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. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.
Also, this proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect 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. If you believe this proposed rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

E. Unfunded Mandates Reform Act
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.

F. Environment
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule proposes to establish seven temporary safety zones within the Captain of the Port New Orleans zone. Normally such actions are categorically excluded from further review under paragraph 34(g) of Figure 2-1 of Commandant Instruction M16475.lD. A preliminary environmental analysis checklist and Categorical Exclusion Determination are available in the docket where indicated under ADDRESSES . We seek any comments or information that may lead to the discovery of a significant environmental impact from this proposed rule.

G. Protest Activities
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places, or vessels.

V. Public Participation and Request for Comments
We view public participation as essential to effective rulemaking, and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.
We encourage you to submit comments through the Federal eRulemaking Portal at http://www.regulations.gov. If your material cannot be submitted using http://www.regulations.gov, contact the person in the FOR FURTHER INFORMATION CONTACT section of this document for alternate instructions.
We accept anonymous comments. All comments received will be posted without change to http://www.regulations.gov and will include any personal information you have provided. For more about privacy and the docket, you may review a Privacy Act notice regarding the Federal Docket Management System in the March 24, 2005, issue of the Federal Register (70 FR 15086).
Documents mentioned in this NPRM as being available in the docket, and all public comments, will be in our online docket at http://www.regulations.gov and can be viewed by following that Web site's instructions. Additionally, if you go to the online docket and sign up for email alerts, you will be notified when comments are posted or a final rule is published.

List of Subjects in 33 CFR Part 165
Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:

PART 165—REGULATED NAVIGATION AREAS AND LIMITED ACCESS AREAS
1. The authority citation for part 165 continues to read as follows:

Authority:
33 U.S.C. 1231; 50 U.S.C. 191; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Department of Homeland Security Delegation No. 0170.1.
2. Add § 165.T08-0340 to read as follows:
§ 165.T08-0340
Safety Zones; Captain of the Port New Orleans Zone; New Orleans to Baton Rouge, LA.
(a) Safety zones. The following areas are safety zones:
(1) Fireworks display, New Orleans, LA. (i) Location. All waters of the Lower Mississippi River from mile marker 94.0 to mile marker 95.0 Above Head of Passes.
(ii) Effective date and time. June 15, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(2) LLamasoft Convention fireworks display, New Orleans, LA. (i) Location. All waters of the Lower Mississippi River from mile marker 94.5 to mile marker 95.5 Above Head of Passes.
(ii) Effective date and time. June 16, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(3) U.S. Travel Association fireworks display, New Orleans, LA. (i) Location. All waters of the Lower Mississippi River from mile marker 95.7 to mile marker 96.7 Above Head of Passes.
(ii) Effective date and time. June 22, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(4) St. John the Baptist Independence Day Celebration fireworks display, Edgard, LA. (i) Location. All waters of the Lower Mississippi River from mile marker 137.5 to mile marker 138.5 Above Head of Passes.
(ii) Effective date and time. June 30, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(5) L'Auberge Casino Independence Day Celebration fireworks display, Baton Rouge, LA. (i) Location. All waters of the Lower Mississippi River from mile marker 216.0 to mile 217.0 Above Head of Passes.
(ii) Effective date and time. July 4, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(6) City of Mandeville Independence Day Celebration fireworks display, Mandeville, LA. (i) Location. All waters of Lake Pontchartrain extending 600 feet in any direction from 30° 21.200 N., 090° 04.500 W.
(ii) Effective date and time. July 4, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(7) American Psychological Association Convention fireworks display, New Orleans, LA. (i) Location. All waters of the Lower Mississippi River from mile marker 94.0 to mile marker 95.0 Above Head of Passes.
(ii) Effective date and time. September 23, 2016, for one hour in the evening between the hours of 6:00 p.m. and 11:00 p.m.
(b) Regulations. (1) In accordance with the general regulations in § 165.23 of this part, entry into these zones is prohibited unless specifically authorized by the Captain of the Port (COTP) New Orleans or designated personnel. Designated personnel include commissioned, warrant and petty officers of the U.S. Coast Guard assigned to units under the operational control of USCG Sector New Orleans. For each event, the COTP New Orleans designated representative will be announced via Marine Safety Information Bulletin and Notice to Mariners.
(2) Vessels requiring deviation from this rule must request permission from the COTP New Orleans or a COTP New Orleans designated representative. They may be contacted via the U.S. Coast Guard Sector New Orleans Command Center, via VHF-FM Channel 16 or by phone at (504) 365-2200.
(3) Persons and vessels permitted to deviate from this safety zone regulation and enter the restricted areas must transit at the slowest safe speed and comply with all lawful directions issued by the COTP New Orleans or the designated representative.
(c) Information Broadcasts. The COTP New Orleans or designated representative will inform the public through broadcast notices to mariners of the enforcement periods for the safety zones as well as any changes in the planned schedules.
Dated: May 13, 2016.
P.C. Schifflin,

Captain, U.S. Coast Guard, Captain of the Port New Orleans.
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
[EPA-R06-OAR-2013-0465; FRL-9947-24-Region 6]
Approval and Promulgation of Air Quality Implementation Plans; Louisiana; Infrastructure State Implementation Plan Requirements for the National Ambient Air Quality Standards

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Proposed rule.

SUMMARY:
The Environmental Protection Agency (EPA) is proposing to approve elements of a State Implementation Plan (SIP) submission from the State of Louisiana for National Ambient Air Quality Standards (NAAQS) for fine particulate matter (PM 2.5 ), lead (Pb), ozone (O 3 ), nitrogen dioxide (NO 2 ), and sulfur dioxide (SO 2 ). This submission addresses how the existing SIP provides for implementation, maintenance, and enforcement of the NAAQS for these pollutants (also referred to as an infrastructure SIP or i-SIP). These i-SIPs ensure that the State's SIP is adequate to meet the state's responsibilities under the Federal Clean Air Act (CAA).

DATES:
Written comments must be received on or before July 5, 2016.

ADDRESSES:
Submit your comments, identified by Docket No. EPA-R06-OAR-2013-0465, at http://www.regulations.gov or via email to fuerst.sherry@epa.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 Sherry Fuerst, (214) 665-6454, fuerst.sherry@epa.gov. For the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.
Docket: The index to the docket for this action is available electronically at www.regulations.gov and in hard copy at EPA Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas. While all documents in the docket are listed in the index, some information may be publicly available only at the hard copy location ( e.g., copyrighted material), and some may not be publicly available at either location ( e.g., CBI).

FOR FURTHER INFORMATION CONTACT:
Sherry Fuerst, (214) 665-6454, fuerst.sherry@epa.gov. To inspect the hard copy materials, please schedule an appointment with her or Bill Deese at (214) 665-7253.

SUPPLEMENTARY INFORMATION:
Throughout this document “we,” “us,” or “our” mean EPA.

I. Background
On October 17, 2006, following a periodic review of the NAAQS for PM 2.5 , EPA revised the PM 2.5 NAAQS. ^1 The 24-hour standard was revised to 35 micrograms per cubic meter (μg/m ^3 ), and the annual standard was revised to 15 μg/m ^3 (71 FR 61144). On December 14, 2012, we promulgated a revised primary annual PM 2.5 NAAQS (78 FR 3086). The primary annual standard was revised to 12.0 μg/m ^3 , and we retained the 24-hour PM 2.5 standard of 35 μg/m ^3 (78 FR 3086). In 2008, following a periodic review of the NAAQS for Pb, we revised the NAAQS to 0.15 μg/m ^3 for both the primary and secondary standards (73 FR 66964). On March 27, 2008, following a periodic review, EPA revised the primary and secondary O 3 NAAQS (73 FR 16205) to establish a new primary standard of 0.075 parts per million (ppm), expressed to three decimal places, based on a 3-year average of the fourth-highest maximum 8-hour average concentration, and revised the current 8-hour standard by making it identical to the revised primary standard.
^1 Additional information on: The history of the pollutants, its levels, forms and, determination of compliance; EPA's approach for reviewing i-SIPs; the details of the SIPs submittal and EPA's evaluation; the effect of recent court decisions on i-SIPs; the statute and regulatory citations in the Louisiana SIP specific to this review; the specific i-SIP applicable CAA and EPA regulatory citation; Federal Register Louisiana minor New Source Review program and EPA approval activities; and Louisiana's Prevention of Significant Deterioration (PSD) program can be found in the Technical Support Document (TSD).
Likewise, on February 9, 2010, EPA revised the primary national ambient air quality standard for oxides of nitrogen as measured by nitrogen dioxide (NO 2 ), for 1-hour standard at a level of 100 ppb, based on the 3-year average of the 98th percentile of the yearly distribution of 1-hour daily maximum concentrations, to supplement the existing annual standard (75 FR 6474). EPA also established requirements for an NO 2 monitoring network that includes monitors at locations where maximum NO 2 concentrations are expected to occur, including within 50 meters of major roadways, as well as monitors sited to measure the area-wide NO 2 concentrations that occur more broadly across communities. (75 FR 6474).
Additionally, on June 22, 2010, the EPA revised the primary SO 2 NAAQS to establish a new 1-hour standard, with a level of 75 ppb, based on the 3-year average of the annual 99th percentile of 1-hour daily maximum concentrations (75 FR 35520).
Each state must submit an i-SIP within three years after the promulgation of a new or revised NAAQS. Section 110(a)(2) of the CAA includes a list of specific elements the i-SIP must meet. In an effort to assist states in complying with this requirement, EPA issued guidance addressing the i-SIP elements for NAAQS. ^2
^2 “Guidance on Infrastructure State Implementation Plan (SIP) Elements under Clean Air Act sections 110(a)(1) and 110(a)(2),” Memorandum from Stephen D. Page, September 13, 2013.
The Secretary of the Louisiana Department of Environmental Quality (LDEQ) submitted i-SIP revisions to address the revised NAAQS.
With the exception of the certain portions that pertain to interstate transport, EPA is proposing to approve the Louisiana i-SIP submittals for these pollutant NAAQS. ^3 The exceptions are (1) the portions of the 2008 ozone NAAQS submittal that pertain to interstate transport of Louisiana emissions which will significantly contribute to nonattainment of the NAAQS in other states, (2) the portion of the 2010 SO 2 NAAQS submittal that pertains to interstate transport of Louisiana emissions to other states, and (3) the portions which will interfere with visibility protection measures in other states for the 2006 and 2012 PM 2.5 , 2008 Pb, 2008 O 3 , 2010 NO 2 , and 2010 SO 2 NAAQS . We will take separate action on the portions of the 2008 ozone and 2010 SO 2 NAAQS submittal that pertain to significant contribution to nonattainment or interference with maintenance of the NAAQS in other states. We have disapproved portions of the Louisiana Regional Haze Plan submittal that pertain to interference with visibility protection measures in other states (77 FR 39425). LDEQ and EPA are currently working on a revised Louisiana Regional Haze Plan.
^3 Additional information on: The history of the priority pollutants, their levels, forms and, determination of compliance; EPA's approach for reviewing i-SIPs; the details of the SIP submittal and EPA's evaluation; the effect of recent court decisions on i-SIPs; the statute and regulatory citations in the Louisiana SIP specific to this review; the specific i-SIP applicable CAA and EPA regulatory citations; Federal Register Notice citations for Louisiana SIP approvals; Louisiana's minor New Source Review program and EPA approval activities; and, Louisiana`s Prevention of Significant Deterioration (PSD) program can be found in the Technical Support Document (TSD).

II. EPA's Evaluation of Louisiana's NAAQS Infrastructure Submissions
Below is a summary of EPA's evaluation of the Louisiana i-SIP for each applicable element of 110(a)(2) A-M. ^4 Louisiana provided a demonstration of how the existing Louisiana SIP meets the requirements of the 2006 PM 2.5 NAAQS, on May 11, 2011; 2008 Pb NAAQS on October 14, 2011; 2008 O 3 , 2010 NO 2 , 2010 SO 2 NAAQS on June 7, 2013 and the 2012 PM 2.5 NAAQS on December 16, 2015. The 2006 PM 2.5 , 2008 Pb, 2008 O 3 , 2010 NO 2 and 2010 SO 2 SIP submissions are complete by operation of law. ^5 The 2012 PM 2.5 submission was reviewed and determined to be complete.
^4 A detailed discussion of our evaluation can be found in the TSD for this action. The TSD can be accessed through www.regulations.gov (e-docket EPA-R06-OAR-2013-0465).
^5 These SIP submissions became complete by operation of law on November 11, 2012 (2006 PM 2.5 ), April 14, 2012 (2008 Pb), and December 7, 2013 (2008 O 3 , 2010 NO 2 , and 2010 SO 2 ). See CAA section 110(k)(1)(B).
(A) Emission limits and other control measures: The SIP must include enforceable emission limits and other control measures, means or techniques, schedules for compliance and other related matters as needed to implement, maintain and enforce each of the NAAQS. ^6 The Louisiana Air Control Law found in the Louisiana Environmental Quality Act at Louisiana Revised Statute (La R.S.)30:2054 provides the Secretary of the Department of Environmental Quality with broad legal authority. The Secretary can adopt emission standards and compliance schedules which are applicable to regulated entities; emission standards and limitations and any other measures necessary for attainment and maintenance of national standards. The Secretary can also enforce applicable laws, regulations, standards and compliance schedules, and seek injunctive relief. This authority has been employed in the past to adopt and submit multiple revisions to the Louisiana State Implementation Plan. The approved SIP for Louisiana is documented at 40 CFR part 52.970, subpart T. ^7 LDEQ's air quality rules and standards are codified at Title 33, Part III of the Louisiana Administrative Code (LAC). Numerous parts of the regulations codified into 33 LAC necessary for implementing and enforcing the NAAQS have been adopted into the SIP. ^8
^6 The specific nonattainment area plan requirements of section 110(a)(2)(I) are subject to the timing requirements of section 172, not the timing requirement of section 110(a)(1). Thus, section 110(a)(2)(A) does not require that states submit regulations or emissions limits specifically for attaining the 2006 PM 2.5 , 2008 Pb, 2008 O 3 , 2010 NO 2 , 2010 SO 2 or 2012 PM 2.5 NAAQS. Those SIP provisions are due as part of each state's attainment plan, and will be addressed separately from the requirements of section 110(a)(2)(A). In the context of an infrastructure SIP, EPA is not evaluating the existing SIP provisions for this purpose. Instead, EPA is only evaluating whether the state's SIP has basic structural provisions for the implementation of the NAAQS.
^7 http://www.ecfr.gov/cgi-bin/text-idx?SID=6e98cdf87e1b896da1b0a8cc2d2f69d6&mc=true&node=sp40.3.52.t&rgn=div6.
^8 See the TSD for additional information.
(B) Ambient air quality monitoring/data system: The SIP must provide for: Establishment and implementation of ambient air quality monitors, collection and analysis of ambient air quality data, and authority to provide such data to EPA upon request.
The La R.S. Chapter 2 provides LDEQ with the authority to collect air quality monitoring data, quality-assure the results, and report the data. LDEQ maintains and operates a monitoring network to measure levels of the pollutants in accordance with EPA regulations specifying siting and monitoring requirements. All monitoring data is measured using EPA approved methods and subject to the EPA quality assurance requirements. LDEQ submits all required data to EPA, following the EPA regulations. The monitoring network was approved into the SIP and it undergoes recurrent annual review by EPA. ^9 In addition, LDEQ conducts a recurrent assessment of its monitoring network every five years, as required by EPA rules. The most recent of these 5-year monitoring network assessments was conducted by LDEQ and approved by EPA. ^{10} The LDEQ Web site provides the monitor locations and posts past and current concentrations of criteria pollutants measured in the State's network of monitors. ^{11}
^9 A copy of the 2015 Annual Air Monitoring Network Plan and EPA's approval letter are included in the docket for this proposed rulemaking.
^{10} A copy of LDEQ's 2010 5-year ambient monitoring network assessment and EPA's approval letter are included in the docket for this proposed rulemaking.
^{11} See http://airquality.deq.louisiana.gov/ and http://www.deq.louisiana.gov/portal/DIVISIONS/Assessment/AirFieldServices/AmbientAirMonitoringProgram/AmbientAirMonitoringDataandReports.aspx.
(C) Program for enforcement of control measures: The SIP must include the following three elements: (1) A program providing for enforcement of the measures in paragraph A above; (2) a program for the regulation of the modification and construction of stationary sources as necessary to protect the applicable NAAQS ( i.e., state-wide permitting of minor sources); and (3) a permit program to meet the major source permitting requirements of the CAA (for areas designated as attainment or unclassifiable for the NAAQS in question). ^{12}
^{12} As discussed in further detail in the TSD.
(1) Enforcement of SIP Measures. As noted in ( A ), the state statutes provide authority for the LDEQ and its Secretary to enforce the requirements of the LAC, and any regulations, permits, or final compliance orders. These statutes also provide the LDEQ and its Secretary with general enforcement powers. Among other things, they can file lawsuits to compel compliance with the statutes and regulations; commence civil actions; issue field citations; conduct investigations of regulated entities; collect criminal and civil penalties; develop and enforce rules and standards related to protection of air quality; issue compliance orders; pursue criminal prosecutions; investigate, enter into remediation agreements; and issue emergency cease and desist orders. The LAC also provides additional enforcement authorities and funding mechanisms.
(2) Minor New Source Review. The SIP is required to include measures to regulate construction and modification of stationary sources to protect the NAAQS. The Louisiana minor NSR permitting requirements are approved as part of the SIP. ^{13}
^{13} EPA is not proposing to approve or disapprove the existing Louisiana minor NSR program to the extent that it may be inconsistent with EPA's regulations governing this program. EPA has maintained that the CAA does not require that new infrastructure SIP submissions correct any defects in existing EPA-approved provisions of minor NSR programs in order for EPA to approve the infrastructure SIP for element C ( e.g., 76 FR 41076-41079, July 13 2011). EPA believes that a number of states may have minor NSR provisions that are contrary to the existing EPA regulations for this program. The statutory requirements of section 110(a)(2)(C) provide for considerable flexibility in designing minor NSR programs.
(3) Prevention of Significant Deterioration (PSD) permit program. The Louisiana PSD portion of the SIP covers all NSR regulated pollutants and has been approved by EPA. ^{14}
^{14} As discussed further in the TSD.
(D)(i) Interstate Pollution Transport: The i-SIP must prohibit emissions within Louisiana from contributing significantly to the nonattainment of the NAAQS in other states, and from interfering with the maintenance of the NAAQS in other states (CAA(a)(2)(D)(i)(I)). The SIP must also prohibit emissions within Louisiana both from interfering with measures required to prevent significant deterioration in other states and from interfering with measures required to protect visibility in other states (CAA(a)(2)(D)(i)(II)).
Fine Particulate Matter: Previously we approved the portion of Louisiana's 2006 PM 2.5 NAAQS i-SIP which addressed the requirement that emissions within Louisiana be prohibited from contributing to the nonattainment of the NAAQS in other states, and from interfering with the maintenance of the NAAQS in other states (79 FR 4436). We are not acting on the nonattainment/maintenance component for the 2012 PM 2.5 NAAQS at this time. We expect to propose an action at a later date.
Based on information presented in this submission, we are approving the portion of the i-SIP submittal for both the 2006 PM 2.5 NAAQS and the 2012 PM 2.5 NAAQS which addresses the prevention of interference with PSD programs in other states. Louisiana has a fully acceptable PSD program. The program regulates all NSR pollutants, including greenhouse gas (GHG) which prevents significant deterioration in nearby states. Since Louisiana's Regional Haze Plan was not fully approved, we are disapproving the portion of the i-SIP which addresses the prevention of interference with measures required to protect visibility in other states for both the 2006 PM 2.5 NAAQS and the 2012 PM 2.5 NAAQS. We cannot ensure that Louisiana emissions will not interfere with visibility protection measures in other States.
Lead: We propose to approve the portion of the submittal which addresses the requirement that emissions within Louisiana be prohibited from contributing to the nonattainment of the Pb NAAQS in other states, and from interfering with the maintenance of the Pb NAAQS in other states. The physical properties of Pb, which is a metal and very dense, prevent Pb emissions from experiencing a significant degree of travel in the ambient air. No complex chemistry is needed to form Pb or Pb compounds in the ambient air; therefore, ambient concentrations of Pb are typically highest near Pb sources. More specifically, there is a sharp decrease in ambient Pb concentrations as the distance from the source increases. According to EPA's report entitled Our Nation's Air: Status and Trends Through 2010, Pb concentrations that are not near a source of Pb are approximately 8 times less than the typical concentrations near the source. ^{15} There are no areas within the State of Louisiana designated as nonattainment with respect to the 2008 lead NAAQS. LDEQ's 2015 ambient monitoring plan provided information on significant lead sources and their location. There are two significant sources of Pb emissions within the state that emit more than Pb in amounts equal to or exceeding 0.5 tons per year and no sources within two miles of a neighboring state line.
^{15} http://www.epa.gov/airtrends/2011/report/fullreport.pdf.
We are also proposing to approve the portion pertaining to the prevention of significant deterioration in other states for lead, as Louisiana has a fully acceptable PSD program. The program regulates all NSR pollutants, including greenhouse gas (GHG) which prevents significant deterioration in nearby States.
Significant impacts from Pb emissions from stationary sources are limited to short distances from emitting sources, therefore, visibility is not effected by lead emissions. ^{16} Given this information, we propose to approve the portion of the Pb i-SIP submittal related to the protection of visibility in other states.
^{16} More information about this is provided in the TSD.
Ozone: At this time we are not proposing action on the i-SIP submittals which address the prevention of emissions which significantly contribute to the nonattainment of the ozone NAAQS in other states, and the interference with the maintenance of the ozone NAAQS in other states. We plan to act on this portion of the i-SIP in a separate action.
Based on information presented in this submission, we are proposing to approve the portion of the submittal related to the prevention of significant deterioration in other states, as Louisiana has a fully acceptable PSD program. The program regulates all NSR pollutants, including greenhouse gas (GHG) which prevents significant deterioration in nearby states. Since Louisiana's Regional Haze Plan was not fully approved, we also are disapproving the portion of the submittal related to the protection of visibility in other states.
Nitrogen Dioxide: We propose to approve the portion of the submittal which addresses the prevention of emissions which significantly contribute to the nonattainment of the NO 2 NAAQS in other states and interfere with the maintenance of the NO 2 NAAQS in other states. On February 17, 2012, EPA designated the entire country as “unclassifiable/attainment” for the 2010 NO 2 . ^{17} The available air quality data show that all areas in the country meet the 2010 NO 2 NAAQS for 2008-2010. No state or tribal entity recommended an area be designated “nonattainment.” As listed in our NO 2 Design Values report, ^{18} only one maintenance area exists for the prior annual NO 2 NAAQS (Los Angeles, California). With no nonattainment or maintenance areas in surrounding states, Louisiana does not significantly contribute to nonattainment or maintenance of these NAAQS in any of the contiguous states. As further evidence that Louisiana's NO 2 emissions do not contribute to nonattainment or maintenance of NAAQS, we reviewed more recent monitoring data for NO 2 throughout the United States. Using previous EPA methodology, ^{19} we evaluated specific monitors identified as having nonattainment and or maintenance problems, which we refer to as “receptors”. We identify nonattainment receptors as any monitor that violated the NO 2 NAAQS in the most recent three year period. Meanwhile, we identify NO 2 maintenance receptors as any monitor that violated the NO 2 NAAQS in either of the prior monitoring cycles (2010-2012 and 2011-2013), but attained in the most recent monitoring cycle (2012-2014). During the three most recent design value periods of 2010 through 2012, 2011 through 2013 and 2012 through 2014, we found no monitors violating the 2010 NO 2 NAAQS in the U.S.
^{17} 77 FR 9532, February 17, 2012.
^{18} http://epa.gov/airtrends/values.html.
^{19} See NO X SIP call, 63 FR 57371 (October 27, 1998); CAIR, 7025172 (May 12, 2005; and Transport Rule or Cross-State Air Pollution Rule 76 FR 48208 (August 8, 2001).
We are approving the portion of the submittal related to the prevention of significant deterioration in other states, as Louisiana has a fully acceptable PSD program. The program regulates all NSR pollutants, including greenhouse gas (GHG) which prevents significant deterioration in nearby states. Since Louisiana's Regional Haze Plan was not fully approved, we also are not approving the portion of the submittal related to the protection of visibility in other states.
Sulfur Dioxide: At this time we not taking action on the portion of the submittal which addresses the prevention of emissions which significantly contribute to the nonattainment of the SO 2 NAAQS in other states and interfere with the maintenance of the SO 2 NAAQS in other states. We expect to take action on this portion of the SIP submittal at a later time.
(D)(ii) Interstate Pollution Abatement and International Air Pollution: In addition, states must comply with the requirements listed in sections 115 and 126 of the CAA which were designed to aid in the abatement of interstate and international pollution (CAA 110(a)(2)(D)(ii)). Section 126(a) requires new or modified sources to notify neighboring states of potential impacts from the source. Louisiana's PSD program contains the element pertaining to notification to neighboring states of the issuance of PSD permits. Section 115 relates to international pollution abatement. As there are no findings by EPA that air emissions originating in Louisiana affect other countries, we propose to approve the portions of the i-SIPs pertaining to CAA section 110(a)(2)(D)(ii).
(E) Adequate authority, resources, implementation, and oversight: The SIP must provide for the following: (1) Necessary assurances that the state (and other entities within the state responsible for implementing the SIP) will have adequate personnel, funding, and authority under state or local law to implement the SIP, and that there are no legal impediments to such implementation; (2) compliance with requirements relating to state boards as explained in section 128 of the CAA; and (3) necessary assurances that the state has responsibility for ensuring adequate implementation of any plan provision for which it relies on local governments or other entities to carry out. Both elements (A) and (E) address the state have adequate authority to implement and enforce the SIP without legal impediments.
The i-SIP submissions for these pollutants describe the SIP regulations governing the various functions of personnel within the LDEQ, including the administrative, technical support, planning, enforcement, and permitting functions of the program.
With respect to funding, La R.S. 30:2011 and the SIP require LDEQ to establish an emissions fee schedule for sources in order to fund the reasonable costs of administering various air pollution control programs and authorizes LDEQ to collect additional fees necessary to cover reasonable costs associated with processing of air permit applications. EPA conducts periodic program reviews to ensure that the state has adequate resources and funding to, among other things, implement and enforce the SIP.
As required by the CAA and the SIP, the majority of the members that compose any board or body which approves permits or enforcement orders must not derive any “significant portion” of their income from persons subject to permits and enforcement orders or persons who appear before the board on issues related to the CAA or the Louisiana Air Quality Rules (La. R.S. 2014.1). The members of the board or body, or the head of an agency with similar powers, are required to adequately disclose any potential conflicts of interest.
Louisiana has not delegated any authority to implement any of the provisions of its plan to local governmental entities. The LDEQ acts as the primary air pollution control agency.
(F) Stationary source monitoring system: The SIP must provide for the establishment of a system to monitor emissions from stationary sources and to submit periodic emission reports. It must require the installation, maintenance, and replacement of equipment, and the implementation of other necessary steps, by owners or operators of stationary sources, to monitor emissions from such sources. The SIP shall also require periodic reports on the nature and amounts of emissions and emissions-related data from such sources. It shall require that the state correlate the source reports with emission limitations or standards established under the CAA. These reports must be made available for public inspection at reasonable times.
LAC 33:III Chapter 9 authorizes the LDEQ to require persons engaged in operations which result in air pollution to monitor or test emissions and to file reports containing information relating to the nature and amount of emissions. There are also SIP-approved state regulations pertaining to sampling and testing and requirements for reporting of emissions inventories (60 FR 02014). In addition, SIP-approved rules establish general requirements for maintaining records and reporting emissions.
The LDEQ uses this information, in addition to information obtained from other sources, to track progress towards maintaining the NAAQS, develop control and maintenance strategies, identify sources and general emission levels, and determine compliance with SIP-approved regulations and additional EPA requirements. The SIP requires this information be made available to the public. Provisions concerning the handling of confidential data and proprietary business information are included in the SIP-approved regulations. These rules specifically exclude from confidential treatment any records concerning the nature and amount of emissions reported by sources.
(G) Emergency authority: The SIP must provide the LDEQ with authority to restrain any source from causing imminent and substantial endangerment to public health or welfare or the environment. The SIP must include an adequate contingency plan to implement LDEQ's emergency authority.
La R.S 30:2011.D.15 provides LDEQ with the required authority to address environmental emergencies, and LDEQ has contingency plans to implement the emergency episode provisions in the SIP. The LDEQ promulgated the “Prevention of Air Pollution Emergency Episodes,” which includes contingency measures, and these provisions were approved into the SIP in 1989 (54 FR 9783). The episode criteria and contingency measures are found in 33 LAC Chapter 56.
Louisiana has general emergency powers to address any possible dangerous air pollution episode if necessary to protect the environment and public health.
(H) Future SIP revisions: States must have the authority to revise their SIPs in response to changes in the NAAQS, availability of improved methods for attaining the NAAQS, or in response to an EPA finding that the SIP is substantially inadequate to attain the NAAQS.
La R.S. 30:2011 authorizes the LDEQ to revise the Louisiana SIP, as necessary, to account for revisions of an existing NAAQS, establishment of a new NAAQS, to attain and maintain a NAAQS, to abate air pollution, to adopt more effective methods of attaining a NAAQS, and to respond to EPA SIP calls concerning NAAQS adoption or implementation.
(I) Nonattainment areas: The CAA section 110(a)(2)(I) requires that in the case of a plan or plan revision for areas designated as nonattainment areas, states must meet applicable requirements of part D of the CAA, relating to SIP requirements for designated nonattainment areas.
However, as noted earlier, EPA believes that nonattainment area requirements should be treated separately from the infrastructure SIP requirements. The specific SIP submissions for designated nonattainment areas, as required under CAA title I, part D, are subject to different submission schedules than those for section 110 infrastructure elements. Instead, EPA will take action on part D attainment plan SIP submissions through a separate rulemaking process governed by the requirements for nonattainment areas, as described in part D. ^{20}
^{20} This infrastructure SIP rulemaking will not address the Louisiana program for provisions related to nonattainment areas, since EPA considers evaluation of these provisions to be outside the scope of infrastructure SIP actions.
(J) Consultation with government officials, public notification, PSD and visibility protection: The SIP must meet the following four CAA requirements: (1) Those listed in section 121 of the CAA, relating to interagency consultation; (2) those listed in section 127, relating to public notification of NAAQS exceedances and related issues; (3) prevention of significant deterioration of air quality and (4) visibility protection.
(1) Interagency consultation: As required by the LAC, there must be a public hearing before the adoption of any regulations or emission control requirements, and all interested persons are given a reasonable opportunity to review the action that is being proposed and to submit data or arguments, either orally or in writing, and to examine witnesses testifying at the hearing (La R.S. 30:2011). In addition, the LAC provides the LDEQ the power and duty to establish cooperative agreements with local authorities, and consult with other states, the federal government and other interested persons or groups in regard to matters of common interest in the field of air quality control (La. R.S. 30:2032). Furthermore, the Louisiana PSD SIP rules mandate that the LDEQ provide for public participation and notification regarding permitting applications to any other state or local air pollution control agencies, local government officials of the city or county where the source will be located, tribal authorities, and Federal Land Manager (FLMs) whose lands may be affected by emissions from the source or modification (LAC 33:III.509). Additionally, the State's PSD SIP rules require the LDEQ to consult with FLMs regarding permit applications for sources with the potential to impact Class I Federal Areas. The SIP also includes a commitment to consult continually with the FLMs on the review and implementation of the visibility program. Louisiana recognizes the expertise of the FLMs in monitoring, as well as new source review applicability analyses for visibility. The State has agreed to notify the FLMs of any advance notification or early consultation with a new or modifying source prior to the submission of a permit application. Likewise, the State's Transportation Conformity SIP rules provide for interagency consultation, resolution of conflicts, and public notification.
(2) Public Notification: On January 10, 1980, the Governor submitted final revisions to the ambient monitoring portion of the plan. These revisions were included into the SIP on August 6, 1981 (46 FR 40005). This portion of the SIP includes requirements for public notification of information related to air quality standards violation included in Part 51 in order to meet the requirements of Section 127 of the Act, requiring the LDEQ to regularly notify the public of instances or areas in which any NAAQS are exceeded. In addition, as discussed for infrastructure element B above, the LDEQ air monitoring Web site provides quality data for each of the monitoring stations in Louisiana; this data is provided instantaneously for certain pollutants, such as ozone. The Web site also provides information on the health effects of lead, ozone, particulate matter, and other criteria pollutants.
(3) PSD and Visibility Protection: The PSD requirements for this element are the same as those addressed under element (C) above. As was mentioned earlier, the State has a PSD program, so this requirement has been met. The Louisiana SIP requirements relating to visibility and regional haze are not affected when EPA establishes or revises a NAAQS. Therefore, EPA believes that there are no new visibility protection requirements due to the revision of the NAAQS, and consequently there are no newly applicable visibility protection obligations pursuant to infrastructure element (J).
(K) Air quality and modeling/data: The SIP must provide for performing air quality modeling, as prescribed by EPA, to predict the effects on ambient air quality of any emissions of any NAAQS pollutant, and for submission of such data to EPA upon request.
The LDEQ has the power and duty, under La R.S. 30:2011 et seq. to develop facts and investigate providing for the functions of environmental air quality assessment. Past modeling and emissions reductions measures have been submitted by the State and approved into the SIP. Additionally, Louisiana has the ability to perform modeling for primary and secondary NAAQS on a case by case permit basis consistent with their SIP-approved PSD rules and with EPA guidance.
The La R.S. authorizes and requires LDEQ to cooperate with the federal government and local authorities concerning matters of common interest in the field of air quality control, thereby allowing the agency to make such submissions to the EPA.
(L) Permitting Fees: The SIP must require each major stationary source to pay permitting fees to the permitting authority, as a condition of any permit required under the CAA, to cover the cost of reviewing and acting upon any application for such a permit, and, if the permit is issued, the costs of implementing and enforcing the terms of the permit. The fee requirement applies until a fee program established by the state pursuant to Title V of the CAA, relating to operating permits, is approved by EPA.
The State has met this requirement as it has a fully developed fee system in place which is outlined in LAC:III Chapter 2 and is approved as part of the SIP. See element (E) above for the description of the mandatory collection of permitting fees outlined in the SIP.
(M) Consultation/participation by affected local entities: The SIP must provide for consultation and participation by local political subdivisions affected by the SIP.
See the discussion for element (J) above for a description of the SIP's public participation process, the authority to advise and consult, and the PSD SIP's public participation requirements. Additionally, the state noted that La R.S. 30: 2011(D)(21) also requires initiation of cooperative action between local authorities and the LDEQ, between one local authority and another, or among any combination of local authorities and the LDEQ for control of air pollution in areas having related air pollution problems that overlap the boundaries of political subdivisions, and entering into agreements and compacts with adjoining states and Indian tribes, where appropriate. The transportation conformity component of the Louisiana SIP requires that interagency consultation and opportunity for public involvement be provided before making transportation conformity determinations and before adopting applicable SIP revisions on transportation-related issues. (LAC 33:III1434)

III. Proposed Action
EPA is proposing to approve in part the May 11, 2011, October 14, 2011 , June 7, 2013 and December 16, 2015 infrastructure SIP submissions from Louisiana, which address the requirements of CAA sections 110(a)(1) and (2) as applicable to the 2006 PM 2.5 , 2008 Pb, 2008 O 3 , 2010 NO 2 , 2010 SO 2 , and 2012 PM 2.5 NAAQS. The table below outlines the specific actions EPA is proposing to take.
Proposed Action on Louisiana Infrastructure SIP Submittal for Various NAAQS
Element | 2006 PM 2.5 | 2008 Pb | 2008 Ozone | 2010 NO 2 | 2010 SO 2 | 2012 PM 2.5
(A): Emission limits and other control measures | A | A | A | A | A | A
(B): Ambient air quality monitoring and data system | A | A | A | A | A | A
(C)(i): Enforcement of SIP measures | A | A | A | A | A | A
(C)(ii): PSD program for major sources and major modifications | A | A | A | A | A | A
(C)(iii): Permitting program for minor sources and minor modifications | A | A | A | A | A | A
(D)(i)(I): Contribute to nonattainment/interfere with maintenance of NAAQS (requirements 1 and 2) | A* | A | No action | A | No action | No action
| (D)(i)(II): PSD (requirement 3) | A | A | A | A | A | A
(D)(i)(II): Visibility Protection (requirement 4) | D | A | D | D | D | D
(D)(ii): Interstate and International Pollution Abatement | A | A | A | A | A | A
(E)(i): Adequate resources | A | A | A | A | A | A
(E)(ii): State boards | A | A | A | A | A | A
(E)(iii): Necessary assurances with respect to local agencies | A | A | A | A | A | A
(F): Stationary source monitoring system | A | A | A | A | A | A
(G): Emergency power | A | A | A | A | A | A
(H): Future SIP revisions | A | A | A | A | A | A
(I): Nonattainment area plan or plan revisions under part D | + | + | + | + | + | +
(J)(i): Consultation with government officials | A | A | A | A | A | A
(J)(ii): Public notification | A | A | A | A | A | A
(J)(iii): PSD | A | A | A | A | A | A
(J)(iv): Visibility protection | + | + | + | + | + | +
(K): Air quality modeling and data | A | A | A | A | A | A
(L): Permitting fees | A | A | A | A | A | A
(M): Consultation and participation by affected local entities | A | A | A | A | A | A
Key to Table 1: Proposed action on LA infrastructure SIP submittals for various NAAQS
A—Approve
A*—Approved at an earlier date
+—Not germane to infrastructure SIPs
No action—EPA is taking no action on this infrastructure requirements
NA—Not applicable
D—Disapprove
Based upon review of the state's infrastructure SIP submissions and relevant statutory and regulatory authorities and provisions referenced in these submissions or referenced in Louisiana's SIP, EPA believes that Louisiana has the infrastructure in place to address all applicable required elements of sections 110(a)(1) and (2) (except as noted in table above) to ensure that the 2006 PM 2.5 , 2008 Pb, 2008 O 3 , 2010 NO 2 , 2010 SO 2 , and 2012 PM 2.5 NAAQS are implemented in the state.

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, EPA's role is to approve state choices, provided that they meet the criteria of the Clean Air Act. Accordingly, this 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 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 CAA; and
• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
The SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the proposed 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).

List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Interstate transport of pollution, Lead, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides.

Authority:
42 U.S.C. 7401 et seq.
Dated: May 18, 2016.
Ron Curry,

Regional Administrator, Region 6.
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 1
[MD Docket Nos. 16-166; FCC 16-61]
Assessment and Collection of Regulatory Fees for Fiscal Year 2016

AGENCY:
Federal Communications Commission.

ACTION:
Notice of proposed rulemaking.

SUMMARY:
In this document, the Federal Communications Commission (Commission) will revise its Schedule of Regulatory Fees in order to recover an amount of $384,012,497 that Congress has required the Commission to collect for fiscal year 2016. Section 9 of the Communications Act of 1934, as amended, provides for the annual assessment and collection of regulatory fees under sections 9(b)(2) and 9(b)(3), respectively, for annual “Mandatory Adjustments” and “Permitted Amendments” to the Schedule of Regulatory Fees.

DATES:
Submit comments on or before June 20, 2016, and reply comments on or before July 5, 2016.

ADDRESSES:
You may submit comments, identified by MD Docket No. 16-166, by any of the following methods:
• Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments.
• Federal Communications Commission's Web site: http://www.fcc.gov/cgb/ecfs. Follow the instructions for submitting comments.
• People with Disabilities: Contact the FCC to request reasonable accommodations (accessible format documents, sign language interpreters, CART, etc.) by email: FCC504@fcc.gov or phone: 202-418-0530 or TTY: 202-418-0432.
• Email: ecfs@fcc.gov. Include MD Docket No. 16-166 in the subject line of the message.
• Mail: Commercial overnight mail (other than U.S. Postal Service Express Mail, and Priority Mail, must be sent to 9300 East Hampton Drive, Capitol Heights, MD 20743. U.S. Postal Service first-class, Express, and Priority mail should be addressed to 445 12th Street SW., Washington, DC 20554.
For detailed instructions for submitting comments and additional information on the rulemaking process, see the SUPPLEMENTARY INFORMATION section of this document.

FOR FURTHER INFORMATION CONTACT:
Roland Helvajian, Office of Managing Director at (202) 418-0444.

SUPPLEMENTARY INFORMATION:
This is a summary of the Commission's Notice of Proposed Rulemaking (NPRM), FCC 16-61, MD Docket No. 16-166, adopted on May 18, 2016, and released on May 19, 2016. The full text of this document is available for inspection and copying during normal business hours in the FCC Reference Center, 445 12th Street SW., Room CY-A257, Portals II, Washington, DC 20554, and may also be purchased from the Commission's copy contractor, BCPI, Inc., Portals II, 445 12th Street SW., Room CY-B402, Washington, DC 20554. Customers may contact BCPI, Inc. via their Web site, http://www.bcpi.com, or call 1-800-378-3160. This document is available in alternative formats (computer diskette, large print, audio record, and braille). Persons with disabilities who need documents in these formats may contact the FCC by email: FCC504@fcc.gov or phone: 202-418-0530 or TTY: 202-418-0432.

I. Procedural Matters

A. Ex Parte Rules Permit-But-Disclose Proceeding
1. This Notice of Proposed Rulemaking (FY 2016 NPRM) shall be treated as a “permit-but-disclose” proceeding in accordance with the Commission's ex parte rules. Persons making ex parte presentations must file a copy of any written presentation or a memorandum summarizing any oral presentation within two business days after the presentation (unless a different deadline applicable to the Sunshine period applies). Persons making oral ex parte presentations are reminded that memoranda summarizing the presentation must list all persons attending or otherwise participating in the meeting at which the ex parte presentation was made, and summarize all data presented and arguments made during the presentation. If the presentation consisted in whole or in part of the presentation of data or arguments already reflected in the presenter's written comments, memoranda, or other filings in the proceeding, the presenter may provide citations to such data or arguments in his or her prior comments, memoranda, or other filings (specifying the relevant page and/or paragraph numbers where such data or arguments can be found) in lieu of summarizing them in the memorandum. Documents shown or given to Commission staff during ex parte meetings are deemed to be written ex parte presentations and must be filed consistent with section 1.1206(b). In proceedings governed by section 1.49(f) or for which the Commission has made available a method of electronic filing, written ex parte presentations and memoranda summarizing oral ex parte presentations, and all attachments thereto, must be filed through the electronic comment filing system available for that proceeding, and must be filed in their native format ( e.g., .doc, .xml, .ppt, searchable .pdf). Participants in this proceeding should familiarize themselves with the Commission's ex parte rules.

B. Comment Filing Procedures
2. Comments and Replies. Pursuant to sections 1.415 and 1.419 of the Commission's rules, 47 CFR 1.415, 1.419, interested parties may file comments and reply comments on or before the dates indicated on the first page of this document. Comments may be filed using: (1) The Commission's Electronic Comment Filing System (ECFS), (2) the Federal Government's eRulemaking Portal, or (3) by filing paper copies. See Electronic Filing of Documents in Rulemaking Proceedings, 63 FR 24121 (1998).
• Electronic Filers: Comments may be filed electronically using the Internet by accessing the ECFS: http://fjallfoss.fcc.gov/ecfs2/ or the Federal eRulemaking Portal: http://www.regulations.gov.
• Paper Filers: Parties who choose to file by paper must file an original and four copies of each filing. If more than one docket or rulemaking number appears in the caption of this proceeding, filers must submit two additional copies for each additional docket or rulemaking number.
Filings can be sent by hand or messenger delivery, by commercial overnight courier, or by first-class or overnight U.S. Postal Service mail. All filings must be addressed to the Commission's Secretary, Office of the Secretary, Federal Communications Commission.
All hand-delivered or messenger-delivered paper filings for the Commission's Secretary must be delivered to FCC Headquarters at 445 12th St. SW., Room TW-A325, Washington, DC 20554. The filing hours are 8:00 a.m. to 7:00 p.m. All hand deliveries must be held together with rubber bands or fasteners. Any envelopes must be disposed of before entering the building.
Commercial overnight mail (other than U.S. Postal Service Express Mail and Priority Mail) must be sent to 9300 East Hampton Drive, Capitol Heights, MD 20743.
U.S. Postal Service first-class, Express, and Priority mail must be addressed to 445 12th Street SW., Washington, DC 20554.
People with Disabilities: To request materials in accessible formats for people with disabilities (braille, large print, electronic files, audio format), send an email to fcc504@fcc.gov or call the Consumer & Governmental Affairs Bureau at 202-418-0530 (voice), 202-418-0432 (tty).
3. Availability of Documents. Comments, reply comments, and ex parte submissions will be available for public inspection during regular business hours in the FCC Reference Center, Federal Communications Commission, 445 12th Street SW., CY-A257, Washington, DC 20554. These documents will also be available free online, via ECFS. Documents will be available electronically in ASCII, Word, and/or Adobe Acrobat.
4. Accessibility Information. To request information in accessible formats (computer diskettes, large print, audio recording, and Braille), send an email to fcc504@fcc.gov or call the Commission's Consumer and Governmental Affairs Bureau at (202) 418-0530 (voice), (202) 418-0432 (TTY). This document can also be downloaded in Word and Portable Document Format (“PDF”) at: http://www.fcc.gov.

C. Initial Regulatory Flexibility Analysis
5. An initial regulatory flexibility analysis (IRFA) is contained in this document. Comments to the IRFA must be identified as responses to the IRFA and filed by the deadlines for comments on this NPRM. The Commission will send a copy of this NPRM, including the IRFA, to the Chief Counsel for Advocacy of the Small Business Administration.

D. Initial Paperwork Reduction Act
6. This document does not contain new or modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA), Public Law 104-13. In addition, therefore, it does not contain any new or modified information collection burden for small business concerns with fewer than 25 employees, pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, see 44 U.S.C. 3506(c)(4).

II. Introduction
7. In this Notice of Proposed Rulemaking ( NPRM ), we seek comment on the Federal Communications Commission's (FCC's or Commission's) proposed regulatory fees for fiscal year (FY) 2016. Specifically, the Commission proposes to collect $384,012,497.00 in regulatory fees as detailed in the proposed fee schedule attached to this NPRM in Table 4. As explained in this NPRM, the proposed fee schedule includes adjustments to the table used to assess regulatory fees on broadcasters.

III. Background
8. The Commission is required by Congress to assess regulatory fees each year in an amount that can reasonably be expected to equal the amount of its appropriation. ^1 Regulatory fees are mandated by Congress and are collected “to recover the costs of . . . enforcement activities, policy and rulemaking activities, user information services, and international activities.” ^2 Regulatory fees are to “be derived by determining the full-time equivalent number of employees performing” these activities, “adjusted to take into account factors that are reasonably related to the benefits provided to the payer of the fee by the Commission's activities . . . .” ^3 Regulatory fees recover direct costs, such as salary and expenses; indirect costs, such as overhead functions; and support costs, such as rent, utilities, or equipment. ^4 Regulatory fees also cover the costs incurred in regulating entities that are statutorily exempt from paying regulatory fees, ^5 entities whose regulatory fees are waived, ^6 and entities that provide services for which we do not assess regulatory fees.
^1 47 U.S.C. 159(b)(1)(B). The Commission collected $7.67 million above the required regulatory fee target goal in FY 2015, which the Commission deposited into the U.S. Treasury. The cumulative over collection is $98.367 million as of September 30, 2015.
^2 47 U.S.C. 159(a).
^3 47 U.S.C. 159(b)(1)(A).
^4 Assessment and Collection of Regulatory Fees for Fiscal Year 2004, Report and Order, 19 FCC Rcd 11662, 11666, para. 11 (2004) ( FY 2004 Report and Order ).
^5 For example, governmental and nonprofit entities are exempt from regulatory fees under section 9(h) of the Communications Act of 1934, as amended (Communications Act or Act). 47 U.S.C. 159(h); 47 CFR 1.1162.
^6 47 CFR 1.1166.
9. Congress sets the amount the Commission must collect each year in the Commission's fiscal year appropriations. Section 9(a)(2) of the Communications Act, as amended (Communications Act or Act) requires the Commission to collect fees sufficient to offset the amount appropriated. ^7 To calculate regulatory fees, the Commission allocates the total collection target across all regulatory fee categories. The allocation of fees to fee categories is based on the Commission's calculation of FTEs ^8 in each regulatory fee category. FTEs are classified as “direct” if the employee is in one of the four “core” bureaus; otherwise, that employee is considered an “indirect” FTE. ^9 The total FTEs for each fee category includes the direct FTEs associated with that category, plus a proportional allocation of indirect FTEs. The Commission then allocates the total amount to be collected among the various regulatory fee categories. Each regulatee within a fee category pays its proportionate share based on an objective measure, e.g., revenues, number of subscribers, or licenses. ^{10}
^7 47 U.S.C. 159(a)(2).
^8 One FTE, a “Full Time Equivalent” or “Full Time Employee,” is a unit of measure equal to the work performed annually by a full time person (working a 40 hour workweek for a full year) assigned to the particular job, and subject to agency personnel staffing limitations established by the U.S. Office of Management and Budget.
^9 The core bureaus are the Wireline Competition Bureau (165 FTEs), Wireless Telecommunications Bureau (92 FTEs), Media Bureau (151 FTEs), and part of the International Bureau (24 FTEs), totaling 432 direct FTEs. The indirect FTEs are the employees from the following bureaus and offices: Enforcement Bureau, Consumer & Governmental Affairs Bureau, Public Safety and Homeland Security Bureau, part of the International Bureau, Chairman and Commissioners' offices, Office of the Managing Director, Office of General Counsel, Office of the Inspector General, Office of Communications Business Opportunities, Office of Engineering and Technology, Office of Legislative Affairs, Office of Strategic Planning and Policy Analysis, Office of Workplace Diversity, Office of Media Relations, and Office of Administrative Law Judges, totaling 1,046 indirect FTEs. These totals are as of Oct. 1, 2015 and exclude auctions funded FTEs.
^{10} See Procedures for Assessment and Collection of Regulatory Fees, Notice of Proposed Rulemaking, 27 FCC Rcd 8458, 8461-62, paras. 8-11 (2012) ( FY 2012 NPRM ).
10. The Commission continues to improve the regulatory fee process by ensuring a more equitable distribution of the regulatory fee burden among categories of Commission licensees under the statutory framework in section 9 of the Communications Act. Specifically, in the FY 2013 Report and Order, the Commission adopted updated FTE allocations to more accurately reflect the number of FTEs working on regulation and oversight of the regulatees in the various fee categories; ^{11} reallocated some FTEs from the International Bureau as “indirect;” ^{12} combined the UHF and VHF television stations into one regulatory fee category; ^{13} and created a regulatory fee category that included Internet Protocol Television (IPTV). ^{14} Subsequently, in the FY 2014 Report and Order and FNPRM, the Commission adopted a new fee subcategory (within the Interstate Telecommunications Service Provider (ITSP) category) for toll free numbers; ^{15} increased the de minimis threshold for annual regulatory fee payors; ^{16} and eliminated several categories from the regulatory fee schedule. ^{17} In the FY 2015 NPRM and Report and Order, the Commission added a subcategory for Direct Broadcast Satellite (DBS) providers (in the cable television and IPTV regulatory fee category) based on the finding that Media Bureau FTEs work on issues and proceedings that include DBS as well as other multichannel video programming distributors (MVPDs). ^{18} In addition, in the FY 2015 NPRM and Report and Order, we sought comment on revising the regulatory fee schedule for broadcasters. ^{19}
^{11} Assessment and Collection of Regulatory Fees for Fiscal Year 2013, Report and Order, 28 FCC Rcd 12351, 12354-58, paras 10-20 (2013) ( FY 2013 Report and Order ). This was recommended in a report issued by the Government Accountability Office (GAO) in 2012. See GAO “Federal Communications Commission Regulatory Fee Process Needs to be Updated,” GAO-12-686 (August 2012) (GAO Report) at 36, (available at http://www.gao.gov/products/GAO-12-686 ).
^{12} FY 2013 Report and Order, 28 FCC Rcd at 12355-58, paras. 13-20.
^{13} Id., 28 FCC Rcd at 12361-62, paras. 29-31.
^{14} Id., 28 FCC Rcd at 12362-63, paras. 32-33.
^{15} Assessment and Collection of Regulatory Fees for Fiscal Year 2014, Report and Order and Further Notice of Proposed Rulemaking, 29 FCC Rcd 10767, 10777-79, paras. 25-28 (2014) ( FY 2014 Report and Order and FNPRM).
^{16} FY 2014 Report and Order and FNPRM, 29 FCC Rcd at 10774-76, paras. 18-21.
^{17} Id., 29 FCC Rcd at 10776-77, paras. 22-24.
^{18} Assessment and Collection of Regulatory Fees for Fiscal Year 2015, Notice of Proposed Rulemaking, Report and Order, and Order, 30 FCC Rcd 5354, 5364-5373, paras. 28-41 (2015) ( FY 2015 NPRM and Report and Order ). We also eliminated two additional fee categories. See id., 30 FCC Rcd at 5361-62, paras. 19-22.
^{19} Id., 30 FCC Rcd at 5359, para. 13. In the FY 2015 Report and Order and FNPRM, we sought further comment on the broadcast regulatory fees issue and also sought comment on ITTA's proposal to reallocate FTEs in the Wireline Competition Bureau. Assessment and Collection of Regulatory Fees for Fiscal Year 2015, Report and Order and Further Notice of Proposed Rulemaking, 30 FCC Rcd 10268, 10279-282, paras. 27-34 (2015) ( FY 2015 Report and Order and FNPRM ).

IV. Discussion

A. Notice of Proposed Rulemaking
11. We propose to collect $384,012,497 in regulatory fees for FY 2016, pursuant to section 9 of the Communications Act. ^{20} Of this amount, we project approximately $21.4 million (5.56 percent of the total FTE allocation) in fees from the International Bureau regulatees; ^{21} $81.9 million (21.3 percent of the total FTE allocation) in fees from the Wireless Telecommunications Bureau regulatees; ^{22} $133.97 million (34.95 percent of the total FTE allocation) from the Media Bureau regulatees; ^{23} and $146.8 million (38.19 percent of the total FTE allocation) from Wireline Competition Bureau regulatees. ^{24}
^{20} 47 U.S.C. 159. The proposed regulatory fee rates for FY 2016 include $339,844,000 for operational expenses and an additional one time amount of $44,168,497 to offset facilities reduction, i.e., reduce our office space footprint and move the FCC office location if necessary. Consolidated Appropriations Act, 2016, Public Law 114-113, Dec. 18, 2015. Due to the facilities reduction, regulatees' aggregate fees by category increased on average by approximately 11-13 percent for 2016.
^{21} Includes satellites, earth stations, submarine cable, and bearer circuits.
^{22} Includes Commercial Mobile Radio Service (CMRS), CMRS messaging, Broadband Radio Service/Local Multipoint Distribution Service (BRS/LMDS), and multi-year wireless licensees.
^{23} Includes AM radio, FM radio, television, low power/FM, cable television and IPTV, DBS, and Cable Television Relay Service (CARS) licenses.
^{24} Includes Interstate Telecommunications Service Providers (ITSP) and toll free numbers.
12. These regulatory fees are mandated by Congress and are collected “to recover the costs of . . . enforcement activities, policy and rulemaking activities, user information services, and international activities.” ^{25} We seek comment on the proposed regulatory fee schedule in Table 4.
^{25} 47 U.S.C. 159(a).

1. DBS Regulatory Fees as a Subcategory in the Cable Television and IPTV Category
13. This proposed fee schedule includes an updated regulatory fee for DBS, a subcategory in the cable television and IPTV category. ^{26} In 2015, the Commission adopted the initial regulatory fee for DBS, as a subcategory in the cable television and IPTV category, of 12 cents per year per subscriber, or one cent per month. ^{27} At that time, the Commission stated that it would update the rate for FY 2016, as necessary for ensuring an appropriate level of regulatory parity and considering the resources dedicated to this subcategory. ^{28} When the Commission adopted this regulatory fee subcategory for DBS, the Commission observed that numerous regulatory developments had increased the Media Bureau FTE activity involving regulation and oversight of MVPDs, including DBS providers. ^{29} For example, DBS providers (and cable television operators) are permitted to file program access complaints ^{30} and complaints seeking relief under the retransmission consent good faith rules; ^{31} DBS providers are subject to MVPD requirements such as those pertaining to program carriage; ^{32} and they are subject to the requirement to negotiate retransmission consent in good faith. ^{33} In addition, the Commission, in recent years, adopted numerous requirements that apply to all MVPDs, and thus DBS providers, as part of its implementation of the Commercial Advertisement Loudness Mitigation Act (CALM Act), ^{34} the Twenty-First Century Communications and Video Accessibility Act of 2010 (CVAA), ^{35} as well as the Satellite Television Extension and Localism Act (STELA) Reauthorization Act of 2014 (STELAR). ^{36}
^{26} DBS also pays a regulatory per operational station in geostationary orbit.
^{27} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10276-77, paras. 19-20.
^{28} Id. , 30 FCC Rcd at 10277, para. 20.
^{29} See FY 2015 NPRM and Report and Order, 30 FCC Rcd at 5367-68, para. 31.
^{30} 47 U.S.C. 548; 47 CFR 76.1000-1004.
^{31} 47 U.S.C. 325(b)(1), (3)(C)(ii); 47 CFR 76.65(b).
^{32} 47 U.S.C. 536; 47 CFR 76.1300-1302.
^{33} 47 U.S.C. 325(b)(3)(C)(iii); 47 CFR 76.65(a)-(b).
^{34} See Implementation of the Commercial Advertisement, Loudness Mitigation (CALM) Act, Report and Order, 26 FCC Rcd 17222 (2011) ( CALM Act Report and Order ).
^{35} Public Law 111-260, 124 Stat. 2751 (2010). See also
Amendment of Twenty-First Century Communications and Video Accessibility Act of 2010, Public Law 111-265, 124 Stat. 2795 (2010) (making corrections to the CVAA); 47 CFR part 79.
^{36} The STELA Reauthorization Act of 2014 (STELAR), Public Law 113-200, 128 Stat. 2059 (2014). STELAR was enacted on December 4, 2014 (H.R. 5728, 113th Cong.). Commission work on implementation of the Act was immediate. See, e.g., Implementation of Sections 101, 103 and 105 of the STELA Reauthorization Act of 2014, Order, 30 FCC Rcd 2380 (2015) (implementing certain STELAR provisions under the “good cause” exception to the Administrative Procedure Act); Amendment to the Commission's Rules Concerning Market Modification, Implementation of Section 102 of the STELA Reauthorization Act of 2014, Report and Order, 30 FCC Rcd 10406 (2015) (adopting satellite television market modification rules to enable satellite carriers, cable operators, and commercial television stations to better serve the interests of their local communities); Implementation of Section 103 of the STELA Reauthorization Act of 2014, Notice of Proposed Rulemaking, 30 FCC Rcd 10327 (2015) (seeking comment on potential updates to the “totality of the circumstances” test for good faith negotiation of retransmission consent); Final Report of the DSTAC, available at https://transition.fcc.gov/dstac/dstac-report-final-08282015.pdf ; “Media Bureau Seeks Comment on DSTAC Report,” Public Notice, DA 15-982, 2015 WL 5164960 (MB 2015); “Media Bureau Seeks Comment for Report Required by the STELA Reauthorization Act of 2014,” Public Notice, 30 FCC Rcd 1904 (2015) (seeking information for a report to Congress on designated market areas and considerations for fostering increased localism).
14. FY 2015 was the first time the Commission assessed a regulatory fee for DBS based on Media Bureau FTEs. At that time, the Commission concluded an initial rate of 12 cents per subscriber per year was a sensible fee supported by data and analysis for FY 2015. ^{37} In adopting the regulatory fee for DBS as a subcategory of cable television and IPTV category, the Commission explained that “although DBS is not identical to cable television and IPTV, the services all receive oversight and regulation as a result of the work of Media Bureau FTEs on MVPD issues. The burden imposed on the Commission is therefore similar.” ^{38} At the same time, the Commission also explained that it would examine the appropriate allocation between and among MVPD regulatees in the coming years as the Commission implemented the new DBS fee. ^{39} Such examination is consistent with a report issued by the Government Accountability Office (GAO) in 2012, which observed it is important for the Commission to “regularly update analyses to ensure that fees are set based on relevant information.” ^{40}
^{37} See FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10276-77, para. 20. The agency is not required to calculate its costs with “scientific precision.” Central & Southern Motor Freight Tariff Ass'n v. United States, 777 F.2d 722, 736 (D.C. Cir. 1985). Reasonable approximations will suffice. Id.; Mississippi Power & Light, 601 F.2d 223, 232 (5th Cir. 1979); National Cable Television Ass'n v. FCC, 554 F.2d 1094, 1105 (D.C. Cir. 1976).
^{38} FY 2015 NPRM and Report and Order, 30 FCC Rcd at 5369, para. 33.
^{39} FY 2015 NPRM and Report and Order, 30 FCC Rcd at 5367-68, para. 34, n.129 (The Commission explained that “[e]ven when an industry has oversight generally by one organizational unit within the Commission, we are sensitive to the fact that balance between members of the same industry may require adjustments to FTE allocations.”).
^{40} GAO Report at 12.
15. In addition to the activities described in our FY 2015 regulatory fee proceeding, DBS, along with other MVPDs, continues to receive oversight and regulation as a result of the work of Media Bureau FTEs. For example, the Commission recently adopted a Report and Order requiring cable operators, DBS providers, and certain other licensees to post their public file documents to the FCC-hosted online database. ^{41} In addition, the Commission is currently reviewing a proposal by Chairman Wheeler to unlock the set-top box of cable and DBS operators. ^{42} Thus, for reasons similar to those discussed in the FY 2015 NPRM and Report and Order, ^{43} and based on the Commission's analysis of the resources dedicated to this subcategory, including the resources dedicated to the pending portfolio of MVPD proceedings, the Commission proposes to revise the DBS fee rate. Specifically, in this FY 2016 regulatory fee proceeding, the Commission seeks comment on a higher regulatory fee rate of 27 cents per subscriber per year for FY 2016, as set forth in the proposed fee schedule. This fee includes a 24 cent per subscriber baseline with a proportional adjustment of three cents per subscriber associated with the Commission's facilities reduction costs.
^{41} Expansion of Online Public File Obligations to Cable and Satellite TV Operators and Broadcast and Satellite Radio Licensees, Memorandum, Opinion and Order, FCC 16-4, 2016 WL 380814 (released January 29, 2016).
^{42} “Expanding Consumer Choice in the Video Marketplace” (January 28, 2016), available at https://www.fcc.gov/news-events/blog/2016/01/28/expanding-consumer-choice-video-marketplace.
^{43} FY 2015 NPRM and Report and Order, 30 FCC Rcd at 5367-5373, paras. 31-41.

2. Broadcaster Regulatory Fees
16. The Commission assesses regulatory fees on radio broadcasters based on type and class of service and on the population served. Upon occasion, the Commission makes adjustments to the methodology for assessing regulatory fees on radio broadcasters. For example, concerning population served, the Commission adopted a methodology that relied on the radio station's calculated field strength signal contour overlaid upon U.S. Census data to obtain an estimate of the population coverage for each station. ^{44} Subsequently, licensees complained to the Commission that the contours exaggerated actual market areas and populations served. The Commission addressed these concerns through revising the methodology for calculating the fees. ^{45} Similarly, in 2003, due to a trend toward more powerful stations and general increases in the overall population, an increasing number of stations were grouped in the one million-plus population category of the grid and the Commission expanded the AM and FM radio station grid to include wider population thresholds and extended the population category to an amount “greater than three million.” ^{46}
^{44} Assessment and Collection of Regulatory Fees for Fiscal Year 1997, Report and Order, 12 FCC Rcd 17161, 17179-17184, paras. 47-56 (1997).
^{45} Assessment and Collection of Regulatory Fees for Fiscal Year 1998, Report and Order, 13 FCC Rcd 19820, 19830-33, paras. 31-41 (1998).
^{46} Assessment and Collection of Regulatory Fees for Fiscal Year 2003, Report and Order, 18 FCC Rcd 15985, 15986-87, paras. 4-5 (2003).
17. In the FY 2015 Report and Order and FNPRM, the Commission proposed to include a higher population row in the table for AM and FM broadcasters, i.e., to divide broadcasters that serve 3,000,001-6,000,000 from those that have a higher population coverage. ^{47} Similarly in the FY 2015 Report and Order and FNPRM, the Commission also proposed to standardize the incremental increase in fees as the population served increases ^{48} and to more consistently assess fees based on the type and class of service. ^{49} No comments were received by the Commission concerning this proposal. The Commission now tentatively concludes adopting these proposals will make the regulatory fees for AM and FM radio more rational and address, in part, the problem of a large number of stations in the highest grid. ^{50} The Commission seeks comment on the following proposed table of regulatory fees for AM and FM radio broadcasters, which includes fees based on the adoption of both options.
^{47} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10280, para. 28.
^{48} Id. Specifically, we sought comment on standardizing the incremental increase in fees as radio broadcasters increase the population they serve, such as by requiring that fee adjustments between tiers monotonically increase as the population served increases. Id.
^{49} Id. We sought comment on assessing fees based on the relative type and class of service, such as by assessing FM class B, C, C0, C1, & C2 stations at twice the rate of AM class C stations, and FM class A, B1, & C3 stations assessed at 75 percent more than AM class C stations. For AM stations, we sought comment on assessing AM class A stations at 60 percent more, AM class B stations at 15 percent more, and AM class D stations at 10 percent more than AM class C stations. Id.
^{50} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10279-280, paras. 27-28.
Table 1
FY 2016 Radio station regulatory fees (proposed) | Population served | AM Class A | AM Class B | AM Class C | AM Class D | FM Classes A, B1 & C3 | FM Classes B, C, C0, C1 & C2
<=25,000 | $1,100 | $795 | $690 | $760 | $1,200 | $1,375
25,001-75,000 | 1,650 | 1,200 | 1,025 | 1,150 | 1,800 | 2,050
75,001-150,000 | 2,200 | 1,600 | 1,375 | 1,525 | 2,400 | 2,750
150,001-500,000 | 3,300 | 2,375 | 2,075 | 2,275 | 3,600 | 4,125
500,001-1,200,000 | 5,500 | 3,975 | 3,450 | 3,800 | 6,000 | 6,875
1,200,001-3,000,00 | 8,250 | 5,950 | 5,175 | 5,700 | 9,000 | 10,300
3,000,001-6,000,00 | 11,000 | 7,950 | 6,900 | 7,600 | 12,000 | 13,750
>6,000,000 | 13,750 | 9,950 | 8,625 | 9,500 | 15,000 | 17,175
18. Concerning television broadcasters, in the FY 2015 Report and Order and FNPRM , the Commission proposed to readjust the table to restore the traditional determination that Top 10 stations should pay about twice what stations in markets 26-50 pay. ^{51} The Commission did not receive comments on this proposal. At this time, the Commission tentatively concludes that this proposal will make the regulatory fees for television broadcasters more rational. Accordingly, the Commission seeks comment on the regulatory fees for television broadcasters as set forth in Table 4.
^{51} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10280-81, para. 29.
Table 2
FY 2016 Television station regulatory fees (proposed) | Digital TV (47 CFR part 73) VHF and UHF commercial | FY 2015 Fee rates | FY 2016 Proposed fee rates
Markets 1-10 | $46,825 | $60,775
Markets 11-25 | 43,200 | 45,750
Markets 26-50 | 27,625 | 30,575
Markets 51-100 | 16,275 | 15,225
Remaining Markets | 4,850 | 5,000
Construction Permits | 4,850 | 5,000
19. The Commission also recognizes that the incentive auction scheduled for 2016 is a substantial event for the television broadcast industry. As a result, in the FY 2015 Report and Order and FNPRM, the Commission sought comment on whether, when, and how the Commission should adjust its methodology for assessing regulatory fees on television stations to respond to such potential changed circumstances consistent with the provisions of section 9 of the Communications Act. ^{52} While the Commission received comments on the issue, ^{53} it is too early to revise our regulatory fee apportionment because of the uncertainty in events that have yet to happen. The Commission intends to consider any changed circumstances due to the incentive auction as part of the FY 2017 regulatory fee proceeding.
^{52} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10281, para. 30.
^{53} NAB Comments at 2-7.

3. International Services: Terrestrial and Satellite Services
20. Facilities-based common carriers must pay regulatory fees for terrestrial and satellite International Bearer Circuits (IBCs) active (used or leased) as of December 31 of the prior year in any terrestrial or satellite transmission facility for the provision of service to an end user or resale carrier. ^{54} In the FY 2015 Report and Order and FNPRM, the Commission asked facilities-based common carriers to review their reporting processes to ensure that they accurately calculate and report IBCs. ^{55} The Commission reminded facilities-based common carriers that they must include all common carrier circuits used by themselves or their affiliates when calculating the number of active circuits. The Commission also indicated that we will review the processes for reporting IBCs in the near future to ensure that all carriers are reporting IBCs in the same manner, consistent with our rules. In this regard, the Commission seeks comment on how we can ensure that all providers are calculating and reporting IBCs in the same manner. What criteria do providers use to distinguish common carrier terrestrial circuits from non-common carrier terrestrial circuits for regulatory fee purposes?
^{54} See para. 22 infra.
^{55} FY 2015 Report and Order and FNPRM, 30 FCC Rcd 10268, 10283-85, para. 40 and n.128.
21. As the Commission has stated in the past, non-common carrier terrestrial circuits play an important role in the provision of international services through microwave and fiber links across the U.S.-Canada and U.S.-Mexico borders, and the Commission regularly engages with counterparts in Canada and Mexico on a wide range of issues related to cross-border communications. ^{56} In 2009, the Commission explored whether carriers should be assessed regulatory fees for their terrestrial non-common carrier circuits, but declined to do so at that time because of the “complexity of the legal, policy and equity issues involved.” ^{57} Since that time, the telecommunications industry and Commission's rules have evolved, and the Commission now seeks comment on whether it would be more equitable to no longer distinguish common carrier terrestrial circuits from non-common carrier terrestrial circuits for regulatory fee purposes. If the Commission requires carriers providing international service over terrestrial circuits to pay IBC regulatory fees for their non-common carrier circuits, what is the least burdensome methodology for calculating fees? For example, should the Commission require carriers to report the total amount of international revenue rather than the number of circuits? How do carriers identify their international revenues? How can the Commission ensure carriers are accurately reporting both common carrier and non-common carrier terrestrial circuits? Finally, how can the Commission improve the requirements and regulatory treatment of terrestrial and satellite services for purposes of regulatory fees?
^{56} Assessment and Collection of Regulatory Fees for Fiscal Year 2009, Notice of Proposed Rulemaking and Order, 24 FCC Rcd 5966, 5971, para. 14 (2009).
^{57} Assessment and Collection of Regulatory Fees for Fiscal Year 2009, Report and Order, 24 FCC Rcd 10301, 10306-307, paras. 16-17 (2009). On March 17, 2009, the Commission adopted in the Submarine Cable Order a new submarine cable bearer circuit methodology that allocates IBC costs among service providers in an equitable and competitively neutral manner, without distinguishing between common carriers and non-common carriers, by assessing a flat per cable landing license fee for all submarine cable systems. Assessment and Collection of Regulatory Fees for Fiscal Year 2008, Second Report and Order, 24 FCC Rcd 4208, 4214-16, paras. 13-17 (2009) ( Submarine Cable Order ).

4. Other Regulatory Fee Reform

a. ITTA Proposal
22. In the FY 2015 Report and Order and FNPRM, the Commission sought comment on ITTA's proposals to combine wireless voice and wireline services into the ITSP category ^{58} or, alternatively, to re-assign certain Wireline Competition Bureau FTEs to other fee categories, for regulatory fee purposes. The Commission also sought comment on adopting a new regulatory fee category for CMRS, as a subcategory of the ITSP regulatory fee category. ^{59} The Commission has had an opportunity to further review ITTA's proposals and, as we explain below, we tentatively conclude that combining the wireline and wireless categories, reassigning Wireline Competition Bureau FTEs to the Wireless Telecommunications Bureau, and/or adopting a new subcategory for CMRS in the ITSP regulatory fee category are not consistent with Commission orders implementing section 9 of the Communications Act.
^{58} ITTA Comments at 4-9. See FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10281-82, paras. 31-34. ITTA had proposed this previously. See, e.g.,
Assessment and Collection of Regulatory Fees for Fiscal Year 2014, Notice of Proposed Rulemaking, 29 FCC Rcd 6417, 6430-31, paras. 36-39 (2014) ( FY 2014 NPRM ); Assessment and Collection of Regulatory Fees for Fiscal Year 2013, Notice of Proposed Rulemaking and Further Notice of Proposed Rulemaking, 28 FCC Rcd 7790, 7796, para. 12 (2013) ( FY 2013 NPRM); Assessment and Collection of Regulatory Fees for Fiscal Year 2008, Report and Order and Further Notice of Proposed Rulemaking, 24 FCC Rcd 6388, 6404-05, paras. 40-41 (2008) ( FY 2008 FNPRM ).
^{59} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10282, para. 34. ITTA and ACA argue that such change is supported by the fact that many proceedings in the Wireline Competition Bureau proceedings, and elsewhere, such as those involving universal service, intercarrier compensation, pole attachments, rural call completion, number portability, 911 access, and special access, affect wireless service providers. ITTA Comments at 9-10; ACA Comments at 4-7. CTIA opposes this proposal as arbitrary and capricious as well as in violation of section 9 of the Act. CTIA Comments at 2.
23. The Commission has stated that “[g]iven the significant implications of reassignment of FTEs in our fee calculation, we make changes to FTE classifications only after performing considerable analysis and finding the clearest case for reassignment.” ^{60} In this instance, ITTA contends that the Wireline Competition Bureau FTEs working on universal service issues and other proceedings benefit categories of service providers other than ITSPs, particularly CMRS providers, and therefore should be considered in calculating the CMRS regulatory fee. ^{61} Based on our own detailed analysis, as well as the fact that the Wireless Telecommunications Bureau assigns its own FTEs to coordinate with the Wireline Competition Bureau on relevant wireless issues, we tentatively conclude that a clear case for reassignment of Wireline Competition Bureau FTEs to the Wireless Telecommunications Bureau is not demonstrated in this instance. Our analysis of the Wireline Competition Bureau FTE work on wireline issues that also affect the CMRS industry does not support adopting a new subcategory for CMRS in the ITSP regulatory fee category—and thus assessing regulatory fees on CMRS based on both Wireless Telecommunications Bureau FTEs and Wireline Competition Bureau FTEs, as ITTA proposes. ^{62} Further, ITTA's proposal to combine these regulatory fee categories does not appear to address the substantial differences between the services in terms of regulatory oversight by the two bureaus. Thus, at this juncture, the Commission does not find that the “clearest case of reassignment” exists based on the considerable analysis we have conducted.
^{60} FY 2013 Report and Order, 28 FCC Rcd at 12357, para. 19. The Commission observed that the International Bureau was a “singular case” because the work of those FTEs “primarily benefits licensees regulated by other bureaus.” Id., 28 FCC Rcd at 12355, para. 14.
^{61} ITTA Comments at 10.
^{62} See Letter from Micah M. Caldwell, ITTA, to Marlene H. Dortch, Secretary, FCC (January 22, 2016).
24. The Commission nevertheless seeks comment on whether it would be appropriate to allocate some proportion of the direct FTEs that devote time to universal service and/or numbering issues as additional indirect FTEs. ^{63} Based on staff estimates looking back over a 6 to 12 month period, of the 165 FTEs in the Wireline Competition Bureau, approximately seven FTEs work on numbering issues and 52 FTEs work on universal service issues (approximately 16 on the high-cost program, 13 on the schools and libraries program, nine on the Lifeline program for low income consumers (lifeline), seven on the rural healthcare program, and seven on universal service contributions). ^{64} Of the 92 FTEs in the Wireless Telecommunications Bureau, staff estimate that the equivalent of approximately five FTEs work roughly full time on universal service issues (primarily the high-cost program). If we were to reallocate, for regulatory fee purposes, some proportion of the direct FTEs, what should that proportion be? Any proposals should demonstrate policy or legal arguments supporting reallocating some proportion of numbering and/or USF FTEs as indirect. In doing so, the Commission would invite comment on whether some or all of the FTEs that work on universal service contributions, the schools and libraries program, or the rural healthcare program, should be reallocated as indirect FTEs. Should the Commission reallocate some proportion of the FTEs from each bureau that work on the high-cost program, given the participation of non-wireline and wireless regulatees in the Connect America Fund proceedings? What proportion, if any, of the FTEs that work on numbering issues and the lifeline program should the Commission reallocate given that a significant number of regulatees benefiting from those programs are not wireline regulatees? Is there some proportion of these FTEs whose “activities benefit the Commission as a whole and are not specifically focused on [core bureau] regulatees”? ^{65} Commenters' proposals for FTE reallocation should be consistent with the section 9 requirement that regulatory fees are to “be derived by determining the full-time equivalent number of employees performing” Commission activities, “adjusted to take into account factors that are reasonably related to the benefits provided to the payer of the fee by the Commission's activities . . . .” ^{66}
^{63} Currently, indirect FTEs in various bureaus and offices work on universal service issues.
^{64} These estimates can vary as discussed above and do not represent an entire fiscal year.
^{65} FY 2013 NPRM, 28 FCC Rcd at 7803, para. 28.
^{66} 47 U.S.C. 159(b)(1)(A). (Emphasis added).
25. The Commission notes that incorrect allocation of FTEs to a particular core bureau may disproportionately impact regulatees given that indirect FTEs are allocated proportionally based on the direct FTE percentage attributable to a particular core bureau. The Commission also notes that any change in the allocation of FTEs necessarily affects the fees paid by payors in all other fee categories. We seek comment on whether this proposal is consistent with section 9 of the Act ^{67} and with the Commission's allocation policies with respect to direct and indirect FTEs. ^{68} Commenters should also address the Commission's goal of ensuring that regulatory fees are administrable and sustainable. ^{69}
^{67} Section 9 of the Communications Act requires regulatory fees collected “to recover the costs of . . . enforcement activities, policy and rulemaking activities, user information services, and international activities.” 47 U.S.C. 159(a). The regulatory fees are to “be derived by determining the full-time equivalent number of employees performing” these activities, “adjusted to take into account factors that are reasonably related to the benefits provided to the payer of the fee by the Commission's activities . . . .” 47 U.S.C. 159(b)(1)(A).
^{68} FY 2013 Report and Order, 28 FCC Rcd at 12354-55, paras. 10-12 (adopting use of current FTE data for purposes of regulatory fee calculations as opposed to 1998 FTE data previously used) ; id. at 12357-58, paras. 19-20 (“It would be inconsistent with section 9 to delay reallocating the International Bureau FTEs, where the reallocation is clearly warranted, while we engage in painstaking examinations of less clear and more factually complex situations in other bureaus. . . . At the same time, however, we recognize that a reexamination of how FTEs are allocated throughout the Commission is an indispensable part of comprehensively revising the Commission's regulatory fee program.”); FY 2013 NPRM, 28 FCC Rcd at 7793-95, 7796-99, 7803, paras. 7-10, 15-19, 29 (generally explaining prior FTE allocation methodology and proposing methodology changes).
^{69} FY 2013 Report and Order, 28 FCC Rcd at 12354, para 9.

b. Earth Stations
26. In the FY 2014 NPRM, the Commission sought comment on increasing the earth station regulatory fee allocation in order to reflect more appropriately the number of FTEs devoted to the regulation and oversight of the earth station portion of the satellite industry. ^{70} In the FY 2014 regulatory fee proceeding, the Commission increased the regulatory fees paid by earth station licensees by approximately 7.5 percent based on our analysis and review of the record. ^{71} In the FY 2015 NPRM and Report and Order, the Commission sought comment on whether to raise the earth station regulatory fees again. ^{72} We concluded, however, that the issue required further analysis, in part because the then-pending part 25 proceeding streamlining the satellite licensing rules might affect the distribution of FTE work. ^{73} An Order was adopted in that proceeding in December 2015, and accordingly it is timely to again seek comment on whether to increase the regulatory fees paid by earth station licensees. ^{74} In this context, we seek comment on EchoStar's proposal to adopt different regulatory fees for different types of earth station licenses. ^{75}
^{70} FY 2014 NPRM, 29 FCC Rcd at 6428, para. 29.
^{71} See FY 2014 Report and Order, 29 FCC Rcd at 10772-73, para. 12.
^{72} FY 2015 NPRM and Report and Order, 30 FCC Rcd at 5360, para. 14.
^{73} FY 2015 NPRM and Report and Order, 30 FCC Rcd at 5360, para. 14.
^{74} See Comprehensive Review of Licensing and Operating Rules for Satellite Services, Second Report and Order, 30 FCC Rcd 14713 (2015).
^{75} See EchoStar July 20, 2015 ex parte, filed in MD Docket No. 15-121.

V. Procedural Matters

A. Payment of Regulatory Fees

1. Payments by Check Will Not Be Accepted for Payment of Annual Regulatory Fees
27. Pursuant to an Office of Management and Budget (OMB) directive, ^{76} the Commission is moving towards a paperless environment, extending to disbursement and collection of select federal government payments and receipts. ^{77} Last year the Commission stopped accepting checks (including cashier's checks and money orders) and the accompanying hardcopy forms ( e.g., Forms 159, 159-B, 159-E, 159-W) for the payment of regulatory fees. ^{78} This new paperless procedure requires that all payments be made by online Automated Clearing House (ACH) payment, online credit card, or wire transfer. Any other form of payment ( e.g., checks, cashier's checks, or money orders) will be rejected. For payments by wire, a Form 159-E should still be transmitted via fax so that the Commission can associate the wire payment with the correct regulatory fee information. This change affects all payments of regulatory fees. ^{79}
^{76} Office of Management and Budget (OMB) Memorandum M-10-06, Open Government Directive, December 8, 2009; see also http://www.whitehouse.gov/the-press-office/2011/06/13/executive-order-13576-delivering-efficient-effective-and-accountable-gov .
^{77} See U.S. Department of the Treasury, Open Government Plan 2.1, September 2012.
^{78} FY 2015 Report and Order and FNPRM, 30 FCC Rcd at 10282-83, para. 35. See 47 CFR 1.1158.
^{79} Payors should note that this change will mean that to the extent certain entities have to date paid both regulatory fees and application fees at the same time via paper check, they will no longer be able to do so as the regulatory fees payment via paper check will no longer be accepted.

2. Revised Credit Card Transaction Levels
28. Since June 1, 2015, in accordance with U.S. Treasury Announcement No. A-2014-04 (July 2014), the amount that can be charged on a credit card for transactions with federal agencies has been reduced to $24,999.99. ^{80} Transactions greater than $24,999.99 will be rejected. This limit applies to single payments or bundled payments of more than one bill. Multiple transactions to a single agency in one day may be aggregated and treated as a single transaction subject to the $24,999.99 limit. Customers who wish to pay an amount greater than $24,999.99 should consider available electronic alternatives such as Visa or MasterCard debit cards, ACH debits from a bank account, and wire transfers. Each of these payment options is available after filing regulatory fee information in Fee Filer. Further details will be provided regarding payment methods and procedures at the time of FY 2016 regulatory fee collection in Fact Sheets, available at https://www.fcc.gov/regfees .
^{80} Customers who owe an amount on a bill, debt, or other obligation due to the federal government are prohibited from splitting the total amount due into multiple payments. Splitting an amount owed into several payment transactions violates the credit card network and Fiscal Service rules. An amount owed that exceeds the Fiscal Service maximum dollar amount, $24,999.99, may not be split into two or more payment transactions in the same day by using one or multiple cards. Also, an amount owed that exceeds the Fiscal Service maximum dollar amount may not be split into two or more transactions over multiple days by using one or more cards.

3. De Minimis Regulatory Fees
29. Regulatees whose total FY 2016 annual regulatory fee liability, including all categories of fees for which payment is due, is $500 or less are exempt from payment of FY 2016 regulatory fees. The de minimis threshold applies only to filers of annual regulatory fees (not regulatory fees paid through multi-year filings), and it is not a permanent exemption. Each regulatee will need to reevaluate their total fee liability each fiscal year to determine whether they meet the de minimis exemption.

4. Standard Fee Calculations and Payment Dates
30. The Commission will accept fee payments made in advance of the window for the payment of regulatory fees. The responsibility for payment of fees by service category is as follows:
• Media Services: Regulatory fees must be paid for initial construction permits that were granted on or before October 1, 2015 for AM/FM radio stations, VHF/UHF full service television stations, and satellite television stations. Regulatory fees must be paid for all broadcast facility licenses granted on or before October 1, 2015. For providers of Direct Broadcast Satellite (DBS) service, regulatory fees should be paid based on a subscriber count on or about December 31, 2015. In instances where a permit or license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the permit or license as of the fee due date.
• Wireline (Common Carrier) Services: Regulatory fees must be paid for authorizations that were granted on or before October 1, 2015. In instances where a permit or license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the permit or license as of the fee due date. Audio bridging service providers are included in this category. ^{81} For Responsible Organizations (RespOrgs) that manage Toll Free Numbers (TFN), regulatory fees should be paid on all working, assigned, and reserved toll free numbers as well as toll free numbers in any other status as defined in section 52.103 of the Commission's rules. ^{82} The unit count should be based on toll free numbers managed by RespOrgs on or about December 31, 2015.
^{81} Audio bridging services are toll teleconferencing services.
^{82} 47 CFR 52.103.
• Wireless Services: CMRS cellular, mobile, and messaging services (fees based on number of subscribers or telephone number count): Regulatory fees must be paid for authorizations that were granted on or before October 1, 2015. The number of subscribers, units, or telephone numbers on December 31, 2015 will be used as the basis from which to calculate the fee payment. In instances where a permit or license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the permit or license as of the fee due date.
• Wireless Services, Multi-year fees: The first eight regulatory fee categories in our Schedule of Regulatory Fees pay “small multi-year wireless regulatory fees.” Entities pay these regulatory fees in advance for the entire amount period covered by the five-year or ten-year terms of their initial licenses, and pay regulatory fees again only when the license is renewed or a new license is obtained. We include these fee categories in our rulemaking ( see Table 3) to publicize our estimates of the number of “small multi-year wireless” licenses that will be renewed or newly obtained in FY 2016.
• Multichannel Video Programming Distributor Services (cable television operators and CARS licensees): Regulatory fees must be paid for the number of basic cable television subscribers as of December 31, 2015. ^{83}
Regulatory fees also must be paid for CARS licenses that were granted on or before October 1, 2015. In instances where a permit or license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the permit or license as of the fee due date.
^{83} Cable television system operators should compute their number of basic subscribers as follows: Number of single family dwellings + number of individual households in multiple dwelling unit (apartments, condominiums, mobile home parks, etc.) paying at the basic subscriber rate + bulk rate customers + courtesy and free service. Note: Bulk-Rate Customers = Total annual bulk-rate charge divided by basic annual subscription rate for individual households. Operators may base their count on “a typical day in the last full week” of December 2015, rather than on a count as of December 31, 2015.
• International Services: Regulatory fees must be paid for (1) earth stations and (2) geostationary orbit space stations and non-geostationary orbit satellite systems that were licensed and operational on or before October 1, 2015. In instances where a permit or license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the permit or license as of the fee due date.
• International Services: (Submarine Cable Systems): Regulatory fees for submarine cable systems are to be paid on a per cable landing license basis based on circuit capacity as of December 31, 2015. In instances where a license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the license as of the fee due date. For regulatory fee purposes, the allocation in FY 2016 will remain at 87.6 percent for submarine cable and 12.4 percent for satellite/terrestrial facilities.
• International Services: ( Terrestrial and Satellite Services): Regulatory fees for Terrestrial and Satellite International Bearer Circuits (IBCs) are to be paid by facilities-based common carriers that have active (used or leased) international bearer circuits as of December 31, 2015 in any terrestrial or satellite transmission facility for the provision of service to an end user or resale carrier. When calculating the number of such active circuits, the facilities-based common carriers must include circuits used by themselves or their affiliates. In addition, non-common carrier satellite operators must pay a fee for each circuit they and their affiliates hold and each circuit sold or leased to any customer, other than an international common carrier authorized by the Commission to provide U.S. international common carrier services. For these purposes, “active circuits” include backup and redundant circuits as of December 31, 2015. Whether circuits are used specifically for voice or data is not relevant for purposes of determining that they are active circuits. ^{84} In instances where a permit or license is transferred or assigned after October 1, 2015, responsibility for payment rests with the holder of the permit or license as of the fee due date. For regulatory fee purposes, the allocation in FY 2016 will remain at 87.6 percent for submarine cable and 12.4 percent for satellite/terrestrial facilities. ^{85}
^{84} We encourage terrestrial and satellite service providers to seek guidance from the International Bureau's Telecommunications and Analysis Division to verify their particular IBC reporting processes to ensure that their calculation methods comply with our rules.
^{85} We remind facilities-based common carriers to review their reporting processes to ensure that they accurately calculate and report IBCs.

B. Commercial Mobile Radio Service (CMRS) Cellular and Mobile Services Assessments
31. The Commission will compile data from the Numbering Resource Utilization Forecast (NRUF) report that is based on “assigned” telephone number (subscriber) counts that have been adjusted for porting to net Type 0 ports (“in” and “out”). ^{86} This information of telephone numbers (subscriber count) will be posted on the Commission's electronic filing and payment system (Fee Filer) along with the carrier's Operating Company Numbers (OCNs).
^{86} See Assessment and Collection of Regulatory Fees for Fiscal Year 2005, Report and Order and Order on Reconsideration, 20 FCC Rcd 12259, 12264, paras. 38-44 (2005).
32. A carrier wishing to revise its telephone number (subscriber) count can do so by accessing Fee Filer and follow the prompts to revise their telephone number counts. Any revisions to the telephone number counts should be accompanied by an explanation or supporting documentation. ^{87} The Commission will then review the revised count and supporting documentation and either approve or disapprove the submission in Fee Filer. If the submission is disapproved, the Commission will contact the provider to afford the provider an opportunity to discuss its revised subscriber count and/or provide additional supporting documentation. If we receive no response from the provider, or we do not reverse our initial disapproval of the provider's revised count submission, the fee payment must be based on the number of subscribers listed initially in Fee Filer. Once the timeframe for revision has passed, the telephone number counts are final and are the basis upon which CMRS regulatory fees are to be paid. Providers can view their final telephone counts online in Fee Filer. A final CMRS assessment letter will not be mailed out.
^{87} In the supporting documentation, the provider will need to state a reason for the change, such as a purchase or sale of a subsidiary, the date of the transaction, and any other pertinent information that will help to justify a reason for the change.
33. Because some carriers do not file the NRUF report, they may not see their telephone number counts in Fee Filer. In these instances, the carriers should compute their fee payment using the standard methodology that is currently in place for CMRS Wireless services (i.e. , compute their telephone number counts as of December 31, 2015), and submit their fee payment accordingly. Whether a carrier reviews its telephone number counts in Fee Filer or not, the Commission reserves the right to audit the number of telephone numbers for which regulatory fees are paid. In the event that the Commission determines that the number of telephone numbers that are paid is inaccurate, the Commission will bill the carrier for the difference between what was paid and what should have been paid.

VI. Additional Tables
Table 3—Calculation of FY 2016 Revenue Requirements and Pro-Rata Fees
[Regulatory fees for the first seven categories below are collected by the Commission in advance to cover the term of the license and are submitted at the time the application is filed]
Fee category | FY 2016 payment units | Years | FY 2015 revenue estimate | Prorated FY 2016 revenue requirement | Computed FY 2016 reg. fee | Rounded FY 2016 reg. fee | Expected FY 2016 revenue
PLMRS (Exclusive Use) | 2,500 | 10 | 546,000 | 625,938 | 25 | 25 | 625,000
PLMRS (Shared use) Includes Rural Radio Service (47 CFR part 22) | 31,100 | 10 | 3,100,000 | 3,114,665 | 10 | 10 | 3,110,000
Microwave | 12,500 | 10 | 2,520,000 | 3,129,688 | 25 | 25 | 3,125,000
| Marine (Ship) | 6,900 | 10 | 945,000 | 1,036,553 | 15 | 15 | 1,035,000
Aviation (Aircraft) | 4,700 | 10 | 420,000 | 470,705 | 10 | 10 | 470,000
Marine (Coast) | 480 | 10 | 171,500 | 192,288 | 40 | 40 | 192,000
Aviation (Ground) | 1,100 | 10 | 180,000 | 220,330 | 20 | 20 | 220,000
AM Class A ^4 | 66 | 1 | 281,125 | 314,451 | 4,764 | 4,775 | 315,150
AM Class B ^4 | 1,535 | 1 | 3,499,125 | 3,893,459 | 2,536 | 2,525 | 3,875,875
AM Class C ^4 | 889 | 1 | 1,244,600 | 1,409,299 | 1,585 | 1,575 | 1,400,175
AM Class D ^4 | 1,492 | 1 | 4,103,000 | 4,607,579 | 3,088 | 3,100 | 4,625,200
FM Classes A, B1 & C3 ^4 | 3,122 | 1 | 8,613,000 | 9,652,908 | 3,092 | 3,100 | 9,678,200
FM Classes B, C, C0, C1 & C2 ^4 | 3,139 | 1 | 10,607,625 | 11,826,839 | 3,768 | 3,775 | 11,849,725
AM Construction Permits ^1 | 15 | 1 | 17,110 | 10,366 | 691 | 690 | 10,350
FM Construction Permits ^1 | 179 | 1 | 136,500 | 215,122 | 1,202 | 1,200 | 214,800
Satellite TV | 128 | 1 | 200,025 | 224,336 | 1,753 | 1,750 | 224,000
Digital TV Markets 1-10 | 139 | 1 | 6,274,550 | 8,446,540 | 60,766 | 60,775 | 8,447,725
Digital TV Markets 11-25 | 139 | 1 | 5,918,400 | 6,358,412 | 45,744 | 45,750 | 6,359,250
Digital TV Markets 26-50 | 181 | 1 | 5,000,125 | 5,532,175 | 30,565 | 30,575 | 5534,075
Digital TV Markets 51-100 | 283 | 1 | 4,605,825 | 4,311,203 | 15,234 | 15,225 | 4,308,675
Digital TV Remaining Markets | 365 | 1 | 1,838,150 | 1,827,738 | 5,008 | 5,000 | 1,825,000
Digital TV Construction Permits ^1 | 3 | 1 | 9,700 | 15,023 | 5,000 | 5,000 | 15,000
LPTV/Translators/Boosters/Class A TV | 3,924 | 1 | 1,601,600 | 1,788,098 | 456 | 455 | 1,785,420
CARS Stations | 285 | 1 | 198,000 | 221,206 | 776 | 775 | 220,875
Cable TV Systems, including IPTV | 64,100,000 | 1 | 61,920,000 | 64,196,150 | 1.0015 | 1.00 | 64,100,000
Direct Broadcast Satellite (DBS) | 34,000,000 | 1 | 4,080,000 | 9,193,770 | .2704 | .27 | 9,180,000
Interstate Telecommunication Service Providers | $38,400,000,000 | 1 | 128,428,000 | 141,908,544 | 0.0036955 | 0.00370 | 142,080,000
Toll Free Numbers | 36,500,000 | 1 | 4,380,000 | 4,752,018 | 0.1302 | 0.13 | 4,745,000
CMRS Mobile Services (Cellular/Public Mobile) | 360,000,000 | 1 | 60,180,000 | 72,108,276 | 0.2003 | 0.20 | 72,000,000
CMRS Messag. Services | 2,300,000 | 1 | 208,000 | 184,000 | 0.0800 | 0.080 | 184,000
BRS ^2 | 890 | 1 | 565,150 | 645,250 | 725 | 725 | 645,250
LMDS | 395 | 1 | 238,125 | 286,375 | 725 | 725 | 286,375
Per 64 kbps Int'l Bearer Circuits Terrestrial (Common) & Satellite (Common & Non-Common) | 22,500,000 | 1 | 657,000 | 770,617 | .0342 | .03 | 675,000
Submarine Cable Providers (see chart in Appendix B) ^3 | 39.19 | 1 | 4,652,576 | 5,444,038 | 138,914 | 138,925 | 5,444,471
Earth Stations | 3,400 | 1 | 1,023,000 | 1,174,760 | 346 | 345 | 1,173,000
Space Stations (Geostationary) | 95 | 1 | 11,438,400 | 13,174,858 | 138,683 | 138,675 | 13,174,125
Space Stations (Non-Geostationary) | 6 | 1 | 792,750 | 913,068 | 152,178 | 152,175 | 913,050
****** Total Estimated Revenue to be Collected | | | 340,593,961 | 384,196,740 | | | 384,066,766
****** Total Revenue Requirement | | | 339,844,000 | 384,012,497 | | | 384,012,497
Difference | | | 749,961 | 184,243 | | | 54,269
Notes on Table 3.
^1 The AM and FM Construction Permit revenues and the Digital (VHF/UHF) Construction Permit revenues were adjusted, respectively, to set the regulatory fee to an amount no higher than the lowest licensed fee for that class of service. Reductions in the Digital (VHF/UHF) Construction Permit revenues were also offset by increases in the revenue totals for various Digital television stations by market size, respectively.
^2 MDS/MMDS category was renamed Broadband Radio Service (BRS). See Amendment of Parts 1, 21, 73, 74 and 101 of the Commission's Rules to Facilitate the Provision of Fixed and Mobile Broadband Access, Educational and Other Advanced Services in the 2150-2162 and 2500-2690 MHz Bands, Report & Order and Further Notice of Proposed Rulemaking, 19 FCC Rcd 14165, 14169, para. 6 (2004).
^3 The chart at the end of Table 4 lists the submarine cable bearer circuit regulatory fees (common and non-common carrier basis) that resulted from the adoption of Assessment and Collection of Regulatory Fees for Fiscal Year 2008, Report and Order and Further Notice of Proposed Rulemaking, 24 FCC Rcd 6388 (2008) and Assessment and Collection of Regulatory Fees for Fiscal Year 2008, Second Report and Order, 24 FCC Rcd 4208 (2009).
^4 The fee amounts listed in the column entitled “Rounded New FY 2016 Regulatory Fee” constitute a weighted average media regulatory fee by class of service. The actual FY 2016 regulatory fees for AM/FM radio station are listed on a grid located at the end of Table 4.
Table 4—Proposed Regulatory Fees FY 2016 Schedule of Regulatory Fees
[Regulatory fees for the first eight categories below are collected by the Commission in advance to cover the term of the license and are submitted at the time the application is filed]
Fee category | Annual regulatory fee (U.S. $'s)
PLMRS (per license) (Exclusive Use) (47 CFR part 90) | 25
Microwave (per license) (47 CFR part 101) | 25
Marine (Ship) (per station) (47 CFR part 80) | 15
Marine (Coast) (per license) (47 CFR part 80) | 40
Rural Radio (47 CFR part 22) (previously listed under the Land Mobile category) | 10
PLMRS (Shared Use) (per license) (47 CFR part 90) | 10
Aviation (Aircraft) (per station) (47 CFR part 87) | 10
Aviation (Ground) (per license) (47 CFR part 87) | 20
CMRS Mobile/Cellular Services (per unit) (47 CFR parts 20, 22, 24, 27, 80 and 90) | .20
CMRS Messaging Services (per unit) (47 CFR parts 20, 22, 24 and 90) | .08
Broadband Radio Service (formerly MMDS/MDS) (per license) (47 CFR part 27) Local Multipoint Distribution Service (per call sign) (47 CFR, part 101) | 725 725
AM Radio Construction Permits | 690
FM Radio Construction Permits | 1,200
Digital TV (47 CFR part 73) VHF and UHF Commercial
Markets 1-10 | 60,775
Markets 11-25 | 45,750
Markets 26-50 | 30,575
Markets 51-100 | 15,225
Remaining Markets | 5,000
Construction Permits | 5,000
Satellite Television Stations (All Markets) | 1,750
Low Power TV, Class A TV, TV/FM Translators & Boosters (47 CFR part 74) | 455
CARS (47 CFR part 78) | 775
Cable Television Systems (per subscriber) (47 CFR part 76), Including IPTV | 1.00
Direct Broadcast Service (DBS) (per subscriber) (as defined by section 602(13) of the Act) | .27
Interstate Telecommunication Service Providers (per revenue dollar) | .00370
Toll Free (per toll free subscriber) (47 CFR section 52.101 (f) of the rules) | .13
Earth Stations (47 CFR part 25) | 345
Space Stations (per operational station in geostationary orbit) (47 CFR part 25) also includes DBS Service (per operational station) (47 CFR part 100) | 138,675
Space Stations (per operational system in non-geostationary orbit) (47 CFR part 25) | 152,175
International Bearer Circuits—Terrestrial/Satellites (per 64KB circuit) | .03
Submarine Cable Landing Licenses Fee (per cable system) | See Table Below
FY 2016 Schedule of Regulatory Fees
[Table 4 continued]
FY 2016 RADIO STATION REGULATORY FEES | Population Served | AM Class A | AM Class B | AM Class C | AM Class D | FM Classes A, B1 & C3 | FM Classes B, C, C0, C1 & C2
<=25,000 | $1,100 | $795 | $690 | $760 | $1,200 | $1,375
25,001-75,000 | 1,650 | 1,200 | 1,025 | 1,150 | 1,800 | 2,050
75,001-150,000 | 2,200 | 1,600 | 1,375 | 1,525 | 2,400 | 2,750
150,001-500,000 | 3,300 | 2,375 | 2,075 | 2,275 | 3,600 | 4,125
500,001-1,200,000 | 5,500 | 3,975 | 3,450 | 3,800 | 6,000 | 6,875
1,200,001-3,000,00 | 8,250 | 5,950 | 5,175 | 5,700 | 9,000 | 10,300
3,000,001-6,000,00 | 11,000 | 7,950 | 6,900 | 7,600 | 12,000 | 13,750
>6,000,000 | 13,750 | 9,950 | 8,625 | 9,500 | 15,000 | 17,175
FY 2016 SCHEDULE OF REGULATORY FEES
[International Bearer Circuits—Submarine Cable (Table 4 continued)]
Submarine Cable Systems (capacity as of December 31, 2015) | Fee amount
< 2.5 Gbps | $8,675
2.5 Gbps or greater, but less than 5 Gbps | 17,375
5 Gbps or greater, but less than 10 Gbps | 34,725
10 Gbps or greater, but less than 20 Gbps | 69,475
20 Gbps or greater | 138,925

Table 5—Sources of Payment Unit Estimates for FY 2016
In order to calculate individual service fees for FY 2016, we adjusted FY 2015 payment units for each service to more accurately reflect expected FY 2016 payment liabilities. We obtained our updated estimates through a variety of means. For example, we used Commission licensee data bases, actual prior year payment records and industry and trade association projections when available. The databases we consulted include our Universal Licensing System (ULS), International Bureau Filing System (IBFS), Consolidated Database System (CDBS) and Cable Operations and Licensing System (COALS), as well as reports generated within the Commission such as the Wireless Telecommunications Bureau's Numbering Resource Utilization Forecast.
We sought verification for these estimates from multiple sources and, in all cases, we compared FY 2016 estimates with actual FY 2015 payment units to ensure that our revised estimates were reasonable. Where appropriate, we adjusted and/or rounded our final estimates to take into consideration the fact that certain variables that impact on the number of payment units cannot yet be estimated with sufficient accuracy. These include an unknown number of waivers and/or exemptions that may occur in FY 2016 and the fact that, in many services, the number of actual licensees or station operators fluctuates from time to time due to economic, technical, or other reasons. When we note, for example, that our estimated FY 2016 payment units are based on FY 2015 actual payment units, it does not necessarily mean that our FY 2016 projection is exactly the same number as in FY 2015. We have either rounded the FY 2016 number or adjusted it slightly to account for these variables.
Fee category | Sources of payment unit estimates
Land Mobile (All), Microwave, Marine (Ship & Coast), Aviation (Aircraft & Ground), Domestic Public Fixed | Based on Wireless Telecommunications Bureau (WTB) projections of new applications and renewals taking into consideration existing Commission licensee data bases. Aviation (Aircraft) and Marine (Ship) estimates have been adjusted to take into consideration the licensing of portions of these services on a voluntary basis.
CMRS Cellular/Mobile Services | Based on WTB projection reports, and FY 2015 payment data.
CMRS Messaging Services | Based on WTB reports, and FY 2015 payment data.
AM/FM Radio Stations | Based on CDBS data, adjusted for exemptions, and actual FY 2015 payment units.
Digital TV Stations (Combined VHF/UHF units) | Based on CDBS data, adjusted for exemptions, and actual FY 2015 payment units.
AM/FM/TV Construction Permits | Based on CDBS data, adjusted for exemptions, and actual FY 2015 payment units.
LPTV, Translators and Boosters, Class A Television | Based on CDBS data, adjusted for exemptions, and actual FY 2015 payment units.
BRS (formerly MDS/MMDS) | Based on WTB reports and actual FY 2015 payment units.
LMDS | Based on WTB reports and actual FY 2015 payment units.
Cable Television Relay Service (CARS) Stations | Based on data from Media Bureau's COALS database and actual FY 2015 payment units.
Cable Television System Subscribers, Including IPTV Subscribers | Based on publicly available data sources for estimated subscriber counts and actual FY 2015 payment units.
Interstate Telecommunication Service Providers | Based on FCC Form 499-Q data for the four quarters of calendar year 2015, the Wireline Competition Bureau projected the amount of calendar year 2015 revenue that will be reported on 2016 FCC Form 499-A worksheets in April 2016.
Earth Stations | Based on International Bureau (IB) licensing data and actual FY 2015 payment units.
Space Stations (GSOs & NGSOs) | Based on IB data reports and actual FY 2015 payment units.
International Bearer Circuits | Based on IB reports and submissions by licensees, adjusted as necessary.
Submarine Cable Licenses | Based on IB license information.

Table 6—Factors, Measurements, and Calculations That Determines Station Signal Contours and Associated Population Coverages

AM Stations
For stations with nondirectional daytime antennas, the theoretical radiation was used at all azimuths. For stations with directional daytime antennas, specific information on each day tower, including field ratio, phase, spacing, and orientation was retrieved, as well as the theoretical pattern root-mean-square of the radiation in all directions in the horizontal plane (RMS) figure (milliVolt per meter (mV/m) @1 km) for the antenna system. The standard, or augmented standard if pertinent, horizontal plane radiation pattern was calculated using techniques and methods specified in sections 73.150 and 73.152 of the Commission's rules. Radiation values were calculated for each of 360 radials around the transmitter site. Next, estimated soil conductivity data was retrieved from a database representing the information in FCC Figure R3. Using the calculated horizontal radiation values, and the retrieved soil conductivity data, the distance to the principal community (5 mV/m) contour was predicted for each of the 360 radials. The resulting distance to principal community contours were used to form a geographical polygon. Population counting was accomplished by determining which 2010 block centroids were contained in the polygon. (A block centroid is the center point of a small area containing population as computed by the U.S. Census Bureau.) The sum of the population figures for all enclosed blocks represents the total population for the predicted principal community coverage area.

FM Stations
The greater of the horizontal or vertical effective radiated power (ERP) (kW) and respective height above average terrain (HAAT) (m) combination was used. Where the antenna height above mean sea level (HAMSL) was available, it was used in lieu of the average HAAT figure to calculate specific HAAT figures for each of 360 radials under study. Any available directional pattern information was applied as well, to produce a radial-specific ERP figure. The HAAT and ERP figures were used in conjunction with the Field Strength (50-50) propagation curves specified in 47 CFR 73.313 of the Commission's rules to predict the distance to the principal community (70 dBu (decibel above 1 microVolt per meter) or 3.17 mV/m) contour for each of the 360 radials. The resulting distance to principal community contours were used to form a geographical polygon. Population counting was accomplished by determining which 2010 block centroids were contained in the polygon. The sum of the population figures for all enclosed blocks represents the total population for the predicted principal community coverage area.

Table 7—FY 2015 Schedule of Regulatory Fees
Regulatory fees for the first eight categories below are collected by the Commission in advance to cover the term of the license and are submitted at the time the application is filed.
Fee category | Annual regulatory fee (U.S. $'s)
PLMRS (per license) (Exclusive Use) (47 CFR part 90) | 30
Microwave (per license) (47 CFR part 101) | 20
Marine (Ship) (per station) (47 CFR part 80) | 15
Marine (Coast) (per license) (47 CFR part 80) | 35
Rural Radio (47 CFR part 22) (previously listed under the Land Mobile category) | 10
PLMRS (Shared Use) (per license) (47 CFR part 90) | 10
Aviation (Aircraft) (per station) (47 CFR part 87) | 10
Aviation (Ground) (per license) (47 CFR part 87) | 20
CMRS Mobile/Cellular Services (per unit) (47 CFR parts 20, 22, 24, 27, 80 and 90) | .17
CMRS Messaging Services (per unit) (47 CFR parts 20, 22, 24 and 90) | .08
Broadband Radio Service (formerly MMDS/MDS) (per license) (47 CFR part 27), Local Multipoint Distribution Service (per call sign) (47 CFR, part 101) | 635, 635
AM Radio Construction Permits | 590
FM Radio Construction Permits | 750
Digital TV (47 CFR part 73) VHF and UHF Commercial:
Markets 1-10 | 46,825
Markets 11-25 | 43,200
Markets 26-50 | 27,625
Markets 51-100 | 16,275
Remaining Markets | 4,850
Construction Permits | 4,850
Satellite Television Stations (All Markets) | 1,575
Low Power TV, Class A TV, TV/FM Translators & Boosters (47 CFR part 74) | 440
CARS (47 CFR part 78) | 660
Cable Television Systems (per subscriber) (47 CFR part 76), Including IPTV | .96
Direct Broadcast Service (DBS) (per subscriber) (as defined by section 602(13) of the Act) | .12
Interstate Telecommunication Service Providers (per revenue dollar) | .00331
Toll Free (per toll free subscriber) (47 CFR section 52.101 (f) of the rules) | .12
Earth Stations (47 CFR part 25) | 310
Space Stations (per operational station in geostationary orbit) (47 CFR part 25) also includes DBS Service (per operational station) (47 CFR part 100) | 119,150
Space Stations (per operational system in non-geostationary orbit) (47 CFR part 25) | 132,125
International Bearer Circuits—Terrestrial/Satellites (per 64KB circuit) | .03
Submarine Cable Landing Licenses Fee (per cable system) | See Table Below.
FY 2015 Radio Station Regulatory Fees (Table 7 continued)
Population served | AM Class A | AM Class B | AM Class C | AM Class D | FM Classes A, B1 & C3 | FM Classes B, C, C0, C1 & C2
<=25,000 | $775 | $645 | $590 | $670 | $750 | $925
25,001-75,000 | 1,550 | 1,300 | 900 | 1,000 | 1,500 | 1,625
75,001-150,000 | 2,325 | 1,625 | 1,200 | 1,675 | 2,050 | 3,000
150,001-500,000 | 3,475 | 2,750 | 1,800 | 2,025 | 3,175 | 3,925
500,001-1,200,000 | 5,025 | 4,225 | 3,000 | 3,375 | 5,050 | 5,775
1,200,001-3,000,00 | 7,750 | 6,500 | 4,500 | 5,400 | 8,250 | 9,250
| >3,000,000 | 9,300 | 7,800 | 5,700 | 6,750 | 10,500 | 12,025
International Bearer Circuits—Submarine Cable (Table 7 Continued)
Submarine cable systems (capacity as of December 31, 2014) | Fee amount
<2.5 Gbps | $7,175
2.5 Gbps or greater, but less than 5 Gbps | 14,350
5 Gbps or greater, but less than 10 Gbps | 28,675
10 Gbps or greater, but less than 20 Gbps | 57,350
20 Gbps or greater | 114,700

Initial Regulatory Flexibility Analysis
1. As required by the Regulatory Flexibility Act of 1980, as amended (RFA), ^{88} the Commission prepared this Initial Regulatory Flexibility Analysis (IRFA) of the possible significant economic impact on small entities by the policies and rules proposed in the Notice of Proposed Rulemaking ( NPRM). Written comments are requested on this IRFA. Comments must be identified as responses to the IRFA and must be filed by the deadline for comments on this NPRM. The Commission will send a copy of the NPRM, including the IRFA, to the Chief Counsel for Advocacy of the Small Business Administration (SBA). ^{89} In addition, the NPRM and IRFA (or summaries thereof) will be published in the Federal Register . ^{90}
^{88} 5 U.S.C. 603. The RFA, 5 U.S.C. 601-612 has been amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), Public Law 104-121, Title II, 110 Stat. 847 (1996).
^{89} 5 U.S.C. 603(a).
^{90} Id.

A. Need for, and Objectives of, the Notice
2. The NPRM seeks comment regarding adopting proposed regulatory fees for Fiscal Year 2016. The proposed regulatory fees are attached to the NPRM in Table 4. The Commission is required by Congress to adopt regulatory fees each year “to recover the costs of . . . enforcement activities, policy and rulemaking activities, user information services, and international activities.” ^{91} The NPRM proposes no new changes in the Commission's methodology, but does seek comment on the following. (i) As Direct Broadcast Satellites (DBS), along with other Multichannel Video Programming Distributors (MVPDs), receive oversight and regulation by Media Bureau FTEs in, e.g., the implementation of the Commercial Advertisement Loudness Mitigation Act (CALM Act), ^{92} the Twenty-First Century Communications and Video Accessibility Act of 2010 (CVAA), ^{93} and the Satellite Television Extension and Localism Act (STELA) Reauthorization Act of 2014 (STELAR), the NPRM proposes an increase in the DBS fee rate to 27 cents per DBS subscriber. (ii) As radio stations expand in ever increasing large markets, the population threshold of “greater than 3,000,000” is no longer an adequate threshold. As a result, the NPRM proposes to raise the population threshold of broadcasters to “greater than 6,000,000” to reflect increases in the population in major broadcast markets. In addition, the Commission also proposes to adjust the fee rates of television stations to reflect a higher proportional fee for large markets compared to medium and smaller markets. (iii) The Commission seeks comment on how providers of international bearer circuits should count their circuits to maintain consistency across all carriers to ensure that all providers are calculating and reporting IBCs in the same manner. (iv) The Commission received a proposal from ITTA to combine CMRS and ITSP revenues together for the purpose of determining a single regulatory fee rate for the CMRS and ITSP regulatory fee categories. After reviewing ITTA's proposal, the Commission tentatively concludes not to combine wireless and interstate revenues, add a subcategory for CMRS in the ITSP fee category, or reallocate Wireline Competition Bureau FTEs to the Wireless Telecommunications Bureau for the purpose of calculating regulatory fees. The Commission does, however, seek comment on regulatory fee reform, including the reallocation of direct FTEs, including those FTEs working on universal service and numbering issues. (v) Finally, the Commission seeks comment on increasing earth station fees relative to space station fees.
^{91} 47 U.S.C. 159(a).
^{92} See Implementation of the Commercial Advertisement, Loudness Mitigation (CALM) Act, Report and Order, 26 FCC Rcd 17222 (2011) ( CALM Act Report and Order ).
^{93} Public Law Number 111-260, 124 Stat. 2751 (2010). See also
Amendment of Twenty-First Century Communications and Video Accessibility Act of 2010, Public Law Number 111-265, 124 Stat. 2795 (2010) (making corrections to the CVAA); 47 CFR part 79.

B. Legal Basis
3. This action, including publication of proposed rules, is authorized under sections (4)(i) and (j), 9, and 303(r) of the Communications Act of 1934, as amended. ^{94}
^{94} 47 U.S.C. 154(i) and (j), 159, and 303(r).

C. Description and Estimate of the Number of Small Entities to Which the Rules Will Apply
4. The RFA directs agencies to provide a description of, and where feasible, an estimate of the number of small entities that may be affected by the proposed rules and policies, if adopted. ^{95} The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.” ^{96} In addition, the term “small business” has the same meaning as the term “small business concern” under the Small Business Act. ^{97} A “small business concern” is one which: (1) Is independently owned and operated; (2) is not dominant in its field of operation; and (3) satisfies any additional criteria established by the SBA. ^{98}
^{95} 5 U.S.C. 603(b)(3).
^{96} 5 U.S.C. 601(6).
^{97} 5 U.S.C. 601(3) (incorporating by reference the definition of “small-business concern” in the Small Business Act, 15 U.S.C. 632). Pursuant to 5 U.S.C. 601(3), the statutory definition of a small business applies “unless an agency, after consultation with the Office of Advocacy of the Small Business Administration and after opportunity for public comment, establishes one or more definitions of such term which are appropriate to the activities of the agency and publishes such definition(s) in the Federal Register .”
^{98} 15 U.S.C. 632.
5. Small Entities. Our actions, over time, may affect small entities that are not easily categorized at present. We therefore describe here, at the outset, three comprehensive small entity size standards that could be directly affected by the proposals under consideration. ^{99} As of 2009, small businesses represented 99.9 percent of the 27.5 million businesses in the United States, according to the SBA. ^{100} In addition, a “small organization is generally any not-for-profit enterprise which is independently owned and operated and not dominant in its field. ^{101} Nationwide, as of 2007, there were approximately 1,621,215 small organizations. ^{102} In addition, the term “small governmental jurisdiction” is defined generally as “governments of cities, towns, townships, villages, school districts, or special districts, with a population of less than fifty thousand.” ^{103} Census Bureau data for 2011 indicate that there were 90,056 local governmental jurisdictions in the United States. ^{104} We estimate that, of this total, as many as 89,327 entities may qualify as “small governmental jurisdictions.” ^{105} Thus, we estimate that most local government jurisdictions are small. Finally, small entities may include Responsible Organizations (RespOrgs), which are entities chosen by toll free subscribers to manage and administer the appropriate records in the toll free Service Management System for the toll free subscriber. ^{106} Although RespOrgs are often wireline carriers, they can also include other non-carrier entities. Please refer to each group that is acting as a RespOrg identified in this section of the IRFA. From the data on the SMS/800 Web site, ^{107} we estimate that there are approximately 459 RespOrgs, and applying the size standard of 1500 employees is appropriate because most RespOrgs at this time, are wireline-based or wireless-based. We believe that the majority of RespOrgs are small entities under that size standard. ^{108}
^{99} See 5 U.S.C. 601(3)-(6).
^{100} See SBA, Office of Advocacy, “Frequently Asked Questions,” available at http://www.sba.gov/faqs/faqindex.cfm?arealD=24.
^{101} 5 U.S.C. 601(4).
^{102} See Independent Sector, The New Nonprofit Almanac and Desk Reference (2010).
^{103} 5 U.S.C. 601(5).
^{104} See SBA, Office of Advocacy, “Frequently Asked Questions,” available at http.www.sba.gov/sites/default/files.FAQMarch201_O.pdf.
^{105} The 2011 Census Data for small governmental organizations are not presented based on the size of the population in each organization. As stated above, there were 90,056 local governmental organizations in 2011. As a basis for estimating how many of these 90,056 local organizations were small, we note that there were a total of 729 cities and towns (incorporated places and civil divisions) with populations over 50,000. See http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?src=bkmk. If we subtract the 729 cities and towns that exceed the 50,000 population threshold, we conclude that approximately 789,237 are small.
^{106} 47 CFR 52.101(b).
^{107} https://www.somos.com/. SMS/800, Inc. is now Somos, Inc.
^{108} See, e.g., 13 CFR 121.101; NAICS Code 517110; NAICS Code 517210. For purposes of this IRFA, because a substantial percentage of RespOrgs are wireless-based or wireline-based, the standard size applicable to these carriers is referenced.
6. Wired Telecommunications Carriers. The U.S. Census Bureau defines this industry as “establishments primarily engaged in operating and/or providing access to transmission facilities and infrastructure that they own and/or lease for the transmission of voice, data, text, sound, and video using wired communications networks. Transmission facilities may be based on a single technology or a combination of technologies. Establishments in this industry use the wired telecommunications network facilities that they operate to provide a variety of services, such as wired telephony services, including VoIP services, wired (cable) audio and video programming distribution, and wired broadband internet services. By exception, establishments providing satellite television distribution services using facilities and infrastructure that they operate are included in this industry.” ^{109} The SBA has developed a small business size standard for Wired Telecommunications Carriers, which consists of all such companies having 1,500 or fewer employees. ^{110} Census data for 2007 shows that there were 3,188 firms that operated that year. Of this total, 3,144 operated with fewer than 1,000 employees. ^{111} Thus, under this size standard, the majority of firms in this industry can be considered small.
^{109} See http://www.census.gov/cgi-bin/sssd/naics/naicsrch.
^{110} See 13 CFR 120.201, NAICS Code 517110.
^{111} http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2007_US_51SSSZ5 &prodType= table.
7. Local Exchange Carriers (LECs). Neither the Commission nor the SBA has developed a size standard for small businesses specifically applicable to local exchange services. The closest applicable NAICS Code category is for Wired Telecommunications Carriers as defined in paragraph 6 of this IRFA. Under that size standard, such a business is small if it has 1,500 or fewer employees. ^{112} According to census data from 2007, there were 3,188 establishments that operated that year. Of this total, 3,144 operated with fewer than 1,000 employees. ^{113} The Commission estimates that most providers of local exchange service are small entities that may be affected by the rules and policies proposed in the NPRM.
^{112} 13 CFR 121.201, NAICS code 517110.
^{113} See id.
8. Incumbent LECs. Neither the Commission nor the SBA has developed a small business size standard specifically for incumbent local exchange services. The closest applicable NAICS Code category is Wired Telecommunications Carriers, as defined in paragraph 6 of this IRFA. Under that size standard, such a business is small if it has 1,500 or fewer employees. ^{114} According to census data from 2007, 3,188 firms operated in that year. Of this total, 3,144 operated with fewer than 1,000 employees. ^{115} According to the Industry Analysis Branch of the Wireline Competition Bureau, 1,307 carriers reported that they were incumbent local exchange service providers. ^{116} Of this total of 1,307 incumbent local exchange service providers, an estimated 1,006 operated with 1,500 or fewer employees ^{117} Consequently, the Commission estimates that most providers of incumbent local exchange service are small businesses that may be affected by the rules and policies proposed in the NPRM.
^{114} 13 CFR 121.201, NAICS code 517110.
^{115} http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2007_US_51SSSZ5 &prodType= table.
^{116} See Trends in Telephone Service, Federal Communications Commission, Wireline Competition Bureau, Industry Analysis and Technology Division at Table 5.3 (Sept. 2010) ( Trends in Telephone Service ).
^{117} See id.
9. Competitive Local Exchange Carriers (Competitive LECs), Competitive Access Providers (CAPs), Shared-Tenant Service Providers, and Other Local Service Providers. Neither the Commission nor the SBA has developed a small business size standard specifically for these service providers. The appropriate NAICS Code category is Wired Telecommunications Carriers, as defined in paragraph 6 of this IRFA. Under that size standard, such a business is small if it has 1,500 or fewer employees. ^{118} U.S. Census data for 2007 indicate that 3,188 firms operated during that year. Of that number, 3,144 operated with fewer than 1,000 employees. ^{119} Based on this data, the Commission concludes that the majority of Competitive LECs, CAPs, Shared-Tenant Service Providers, and Other Local Service Providers are small entities. According to the Commission's Industry Analysis Division of the Wireline Competition Bureau data, 1,442 carriers reported that they were engaged in the provision of either competitive local exchange services or competitive access provider services. ^{120} Of these 1,442 carriers, an estimated 1,256 have 1,500 or fewer employees. In addition, 17 carriers have reported that they are Shared-Tenant Service Providers, and all 17 are estimated to have 1,500 or fewer employees. ^{121} In addition, 72 carriers have reported that they are Other Local Service Providers. ^{122} Of this total, 70 have 1,500 or fewer employees. ^{123} Consequently, the Commission estimates that most providers of competitive local exchange service, competitive access providers, Shared-Tenant Service Providers, and Other Local Service Providers are small entities that may be affected by rules adopted pursuant to the proposals in this NPRM.
^{118} 13 CFR 121.201, NAICS code 517110.
^{119} http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2007_US_51SSSZ5&prodType=%20table.
^{120} See Trends in Telephone Service, at Table 5.3.
^{121} Id.
^{122} Id.
^{123} Id.
10. Interexchange Carriers (IXCs). Neither the Commission nor the SBA has developed a definition for Interexchange Carriers. The closest NAICS Code category is Wired Telecommunications Carriers as defined in paragraph 6 of this IRFA. The applicable size standard under SBA rules is that such a business is small if it has 1,500 or fewer employees. ^{124} According to Commission's Industry Analysis Division of the Wireline Competition Bureau data, 359 companies reported that their primary telecommunications service activity was the provision of interexchange services. ^{125} Of this total, an estimated 317 have 1,500 or fewer employees and 42 have more than 1,500 employees. ^{126} Consequently, the Commission estimates that the majority of interexchange service providers are small entities that may be affected by rules adopted pursuant to the NPRM.
^{124} 13 CFR 121.201, NAICS code 517110.
^{125} See Trends in Telephone Service, at Table 5.3.
^{126} Id.
11. Prepaid Calling Card Providers. Neither the Commission nor the SBA has developed a small business size standard specifically for prepaid calling card providers. The appropriate NAICS Code category for prepaid calling card providers is Telecommunications Resellers. This industry comprises establishments engaged in purchasing access and network capacity from owners and operators of telecommunications networks and reselling wired and wireless telecommunications services (except satellite) to businesses and households. Mobile virtual networks operators (MVNOs) are included in this industry. ^{127} Under the applicable SBA size standard, such a business is small if it has 1,500 or fewer employees. ^{128} U.S. Census data for 2007 show that 1,523 firms provided resale services during that year. Of that number, 1,522 operated with fewer than 1,000 employees. ^{129} Thus, under this category and the associated small business size standard, the majority of these prepaid calling card providers can be considered small entities. According to Commission's Industry Analysis Division of the Wireline Competition Bureau data, 193 carriers have reported that they are engaged in the provision of prepaid calling cards. ^{130} All 193 carriers have 1,500 or fewer employees. ^{131} Consequently, the Commission estimates that the majority of prepaid calling card providers are small entities that may be affected by rules adopted pursuant to the NPRM.
^{127} http://www.census.gov/cgi-bin/ssd/naics/naicsrch.
^{128} 13 CFR 121.201, NAICS code 517911.
^{129} http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2007_US_51SSSZ5&prodType=table.
^{130} See Trends in Telephone Service, at Table 5.3.
^{131} Id.
12. Local Resellers. The SBA has developed a small business size standard for the category of Telecommunications Resellers. Under that size standard, such a business is small if it has 1,500 or fewer employees. ^{132} Census data for 2007 show that 1,523 firms provided resale services during that year. Of that number, 1,522 operated with fewer than 1,000 employees. ^{133} Under this category and the associated small business size standard, the majority of these local resellers can be considered small entities. According to Commission's Industry Analysis Division of the Wireline Competition Bureau data, 213 carriers have reported that they are engaged in the provision of local resale services. ^{134} Of this total, an estimated 211 have 1,500 or fewer employees. ^{135} Consequently, the Commission estimates that the majority of local resellers are small entities that may be affected by rules adopted pursuant to the proposals in this NPRM.
^{132} 13 CFR 121.201, NAICS code 517911.
^{133} Id.
^{134} See Trends in Telephone Service, at Table 5.3.
^{135} Id.
13. Toll Resellers. The Commission has not developed a definition for Toll Resellers. The closest NAICS Code Category is Telecommunications Resellers, and the SBA has developed a small business size standard for the category of Telecommunications Resellers. Under that size standard, such a business is small if it has 1,500 or fewer employees. ^{136} Census data for 2007 show that 1,523 firms provided resale services during that year. Of that number, 1,522 operated with fewer than 1,000 employees. ^{137} Thus, under this category and the associated small business size standard, the majority of these resellers can be considered small entities. According to Commission's Industry Analysis Division of the Wireline Competition Bureau data, 881 carriers have reported that they are engaged in the provision of toll resale services. ^{138} Of this total, an estimated 857 have 1,500 or fewer employees. ^{139} Consequently, the Commission estimates that the majority of toll resellers are small entities that may be affected by our proposals in the NPRM.
^{136} 13 CFR 121.201, NAICS code 517911.
^{137} Id.
^{138} Trends in Telephone Service, at Table 5.3.
^{139} Id.
14. Other Toll Carriers. Neither the Commission nor the SBA has developed a size standard for small businesses specifically applicable to Other Toll Carriers. This category includes toll carriers that do not fall within the categories of interexchange carriers, operator service providers, prepaid calling card providers, satellite service carriers, or toll resellers. The closest applicable NAICS Code category is for Wired Telecommunications Carriers, as defined in paragraph 6 of this IRFA. Under that size standard, such a business is small if it has 1,500 or fewer employees. ^{140} Census data for 2007 shows that there were 3,188 firms that operated that year. Of this total, 3,144 operated with fewer than 1,000 employees. ^{141} Thus, under this category and the associated small business size standard, the majority of Other Toll Carriers can be considered small. According to Commission's Industry Analysis Division of the Wireline Competition Bureau data, 284 companies reported that their primary telecommunications service activity was the provision of other toll carriage. ^{142} Of these, an estimated 279 have 1,500 or fewer employees. ^{143} Consequently, the Commission estimates that most Other Toll Carriers are small entities that may be affected by the rules adopted pursuant to the NPRM.
^{140} 13 CFR 121.201, NAICS code 517110.
^{141} Id.
^{142} Trends in Telephone Service, at Table 5.3.
^{143} Id.
15. Wireless Telecommunications Carriers (except Satellite). This industry comprises establishments engaged in operating and maintaining switching and transmission facilities to provide communications via the airwaves, such as cellular services, paging services, wireless Internet access, and wireless video services. ^{144} The appropriate size standard under SBA rules is that such a business is small if it has 1,500 or fewer employees. For this industry, Census Data for 2007 show that there were 1,383 firms that operated for the entire year. Of this total, 1,368 firms had fewer than 1,000 employees. Thus under this category and the associated size standard, the Commission estimates that the majority of wireless telecommunications carriers (except satellite) are small entities. Similarly, according to internally developed Commission's Industry Analysis Division of the Wireline Competition Bureau data, 413 carriers reported that they were engaged in the provision of wireless telephony, including cellular service, Personal Communications Service (PCS), and Specialized Mobile Radio (SMR) services. ^{145} Of this total, an estimated 261 have 1,500 or fewer employees. ^{146} Consequently, the Commission estimates that approximately half of these firms can be considered small. Thus, using available data, we estimate that the majority of wireless firms can be considered small and may be affected by rules adopted pursuant to this NPRM.
^{144} NAICS Code 517210. See http://www.census.gov/cgi-bin/ssd/naics/naiscsrch.
^{145} Trends in Telephone Service, at Table 5.3.
^{146} Id.
16. Television Broadcasting. This Economic Census category “comprises establishments primarily engaged in broadcasting images together with sound. These establishments operate television broadcasting studios and facilities for the programming and transmission of programs to the public.” ^{147} The SBA has created the following small business size standard for Television Broadcasting firms: those having $14 million or less in annual receipts. ^{148} The Commission has estimated the number of licensed commercial television stations to be 1,387. ^{149} In addition, according to Commission staff review of the BIA Advisory Services, LLC's Media Access Pro Television Database on March 28, 2012, about 950 of an estimated 1,300 commercial television stations (or approximately 73 percent) had revenues of $14 million or less. ^{150} We therefore estimate that the majority of commercial television broadcasters are small entities.
^{147} U.S. Census Bureau, 2007 NAICS Definitions, “515120 Television Broadcasting” (partial definition); http://www.census.gov/naics/2007/def/ND515120.HTM#N515120.
^{148} 13 CFR 121.201, NAICS code 515120 (updated for inflation in 2010).
^{149} See FCC News Release, “Broadcast Station Totals as of December 31, 2011,” dated January 6, 2012; http://transition.fcc.gov/Daily_Releases/Daily_Business/2012/db0106/DOC-311837A1.pdf.
^{150} We recognize that BIA's estimate differs slightly from the FCC total given supra.
17. We note, however, that in assessing whether a business concern qualifies as small under the above definition, business (control) affiliations ^{151} must be included. Our estimate, therefore, likely overstates the number of small entities that might be affected by our action, because the revenue figure on which it is based does not include or aggregate revenues from affiliated companies. In addition, an element of the definition of “small business” is that the entity not be dominant in its field of operation. We are unable at this time to define or quantify the criteria that would establish whether a specific television station is dominant in its field of operation. Accordingly, the estimate of small businesses to which rules may apply does not exclude any television station from the definition of a small business on this basis and is therefore possibly over-inclusive to that extent.
^{151} “[Business concerns] are affiliates of each other when one concern controls or has the power to control the other or a third party or parties controls or has to power to control both.” 13 CFR 21.103(a)(1).
18. In addition, the Commission has estimated the number of licensed noncommercial educational (NCE) television stations to be 396. ^{152} These stations are non-profit, and therefore considered to be small entities. ^{153} There are also 2,528 low power television stations, including Class A stations (LPTV). ^{154} Given the nature of these services, we will presume that all LPTV licensees qualify as small entities under the above SBA small business size standard.
^{152} See FCC News Release, “Broadcast Station Totals as of December 31, 2011,” dated January 6, 2012; http://transition.fcc.gov/Daily_Releases/Daily_Business/2012/db0106/DOC-311837A1.pdf.
^{153} See generally 5 U.S.C. 601(4), (6).
^{154} See FCC News Release, “Broadcast Station Totals as of December 31, 2011,” dated January 6, 2012; http://transition.fcc.gov/Daily_Releases/Daily_Business/2012/db0106/DOC-311837A1.pdf.
19. Radio Broadcasting. This Economic Census category “comprises establishments primarily engaged in broadcasting aural programs by radio to the public. Programming may originate in their own studio, from an affiliated network, or from external sources. ^{155} The SBA has established a small business size standard for this category, which is: Such firms having $7 million or less in annual receipts. ^{156} According to Commission staff review of BIA Advisory Services, LLC's Media Access Pro Radio Database on March 28, 2012, about 10,759 (97%) of 11,102 commercial radio stations had revenues of $7 million or less. Therefore, the majority of such entities are small entities.
^{155} U.S. Census Bureau, 2007 NAICS Definitions, “515112 Radio Stations”; http://www.census.gov/naics/2007/def/ND515112.HTM#N515112.
^{156} 13 CFR 121.201, NAICS code 515112 (updated for inflation in 2010).
20. We note, however, that in assessing whether a business concern qualifies as small under the above size standard, business affiliations must be included. ^{157} In addition, to be determined to be a “small business,” the entity may not be dominant in its field of operation. ^{158} We note that it is difficult at times to assess these criteria in the context of media entities, and our estimate of small businesses may therefore be over-inclusive.
^{157} “Concerns and entities are affiliates of each other when one controls or has the power to control the other, or a third party or parties controls or has the power to control both. It does not matter whether control is exercised, so long as the power to control exists.” 13 CFR 121.103(a)(1) (an SBA regulation).
^{158} 13 CFR 121.102(b) (an SBA regulation).
21. Cable Television and other Subscription Programming. ^{159} Since 2007, these services have been defined within the broad economic census category of Wired Telecommunications Carriers. That category is defined as follows: “This industry comprises establishments primarily engaged in operating and/or providing access to transmission facilities and infrastructure that they own and/or lease for the transmission of voice, data, text, sound, and video using wired telecommunications networks. Transmission facilities may be based on a single technology or a combination of technologies.” ^{160} The SBA has developed a small business size standard for this category, which is: all such firms having 1,500 or fewer employees. ^{161} Census data for 2007 shows that there were 3,188 firms that operated that year. Of this total, 3,144 had fewer than 1,000 employees. ^{162} Thus under this size standard, the majority of firms offering cable and other program distribution services can be considered small and may be affected by rules adopted pursuant to the NPRM.
^{159} In 2014, “Cable and Other Subscription Programming,” NAICS Code 515210, replaced a prior category, now obsolete, which was called “Cable and Other Program Distribution.” Cable and Other Program Distribution, prior to 2014, were placed under NAICS Code 517110, Wired Telecommunications Carriers. Wired Telecommunications Carriers is still a current and valid NAICS Code Category. Because of the similarity between “Cable and Other Subscription Programming” and “Cable and other Program Distribution,” we will, in this proceeding, continue to use Wired Telecommunications Carrier data based on the U.S. Census. The alternative of using data gathered under Cable and Other Subscription Programming (NAICS Code 515210) is unavailable to us for two reasons. First, the size standard established by the SBA for Cable and Other Subscription Programming is annual receipts of $38.5 million or less. Thus to use the annual receipts size standard would require the Commission either to switch from existing employee based size standard of 1,500 employees or less for Wired Telecommunications Carriers, or else would require the use of two size standards. No official approval of either option has been granted by the Commission as of the time of the release of the Notice. Second, the data available under the size standard of $38.5 million dollars or less is not applicable at this time, because the only currently available U.S. Census data for annual receipts of all businesses operating in the NAICS Code category of 515210 (Cable and other Subscription Programming) consists only of total receipts for all businesses operating in this category in 2007 and of total annual receipts for all businesses operatin6 in this category in 2012. Hence the data do not provide any basis for determining, for either year, how many businesses were small because they had annual receipts of $38.5 million or less. http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2012_US_51I2&prodType=table.
^{160} U.S. Census Bureau, 2007 NAICS Definitions, “517110 Wired Telecommunications Carriers” (partial definition), (full definition stated in para. 6 of this IRFA) available at http://www.census.gov/cgi-bin/sssd/naics/naicsrch.
^{161} 13 CFR 121.201, NAICS code 517110.
^{162} http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2007_US-51SSSZ5&prodType=Table.
22. Cable Companies and Systems. The Commission has developed its own small business size standards for the purpose of cable rate regulation. Under the Commission's rules, a “small cable company” is one serving 400,000 or fewer subscribers nationwide. ^{163} Industry data indicate that there are currently 4,600 active cable systems in the United States. ^{164} Of this total, all but ten cable operators nationwide are small under the 400,000-subscriber size standard. ^{165} In addition, under the Commission's rate regulation rules, a “small system” is a cable system serving 15,000 or fewer subscribers. ^{166} Current Commission records show 4,600 cable systems nationwide. ^{167} Of this total, 3,900 cable systems have less than 15,000 subscribers, and 700 systems have 15,000 or more subscribers, based on the same records. ^{168} Thus, under this standard as well, the Commission estimates that most cable systems are small entities.
^{163} 47 CFR 76.901(e).
^{164} August 15, 2015 Report from the Media Bureau based on data contained in the Commission's Cable Operations And Licensing System (COALS). See www/fcc.gov/coals.
^{165} See SNL KAGAN at www.snl.com/interactiveX/top cableMSOs aspx?period2015Q1&sortcol=subscribersbasic&sortorder=desc.
^{166} 47 CFR 76.901(c).
^{167} See footnote 2, supra.
^{168} August 5, 2015 report from the Media Bureau based on its research in COALS. See www.fcc.gov/coals.
23. Cable System Operators (Telecom Act Standard). The Communications Act of 1934, as amended, also contains a size standard for small cable system operators, which is “a cable operator that, directly or through an affiliate, serves in the aggregate fewer than 1 percent of all subscribers in the United States and is not affiliated with any entity or entities whose gross annual revenues in the aggregate exceed $250,000,000 are approximately 52,403,705 cable video subscribers in the United States today. ^{169} Accordingly, an operator serving fewer than 524,037 subscribers shall be deemed a small operator if its annual revenues, when combined with the total annual revenues of all its affiliates, do not exceed $250 million in the aggregate. ^{170} Based on available data, we find that all but nine incumbent cable operators are small entities under this size standard. ^{171} We note that the Commission neither requests nor collects information on whether cable system operators are affiliated with entities whose gross annual revenues exceed $250 million. ^{172} Although it seems certain that some of these cable system operators are affiliated with entities whose gross annual revenues exceed $250,000,000, we are unable at this time to estimate with greater precision the number of cable system operators that would qualify as small cable operators under the definition in the Communications Act.
^{169} See SNL KAGAN at www.snl.com/interactivex/MultichannelIndustryBenchmarks.aspx.
^{170} 47 CFR 76.901(f) and notes ff. 1, 2, and 3.
^{171} See SNL KAGAN at www.snl.com/Interactivex/TopCableMSOs.aspx.
^{172} The Commission does receive such information on a case-by-case basis if a cable operator appeals a local franchise authority's finding that the operator does not qualify as a small cable operator pursuant to section 76.901(f) of the Commission's rules. See 47 CFR 76.901(f).
24. Direct Broadcast Satellite (DBS) Service. DBS Service is a nationally distributed subscription service that delivers video and audio programming via satellite to a small parabolic dish antenna at the subscriber's location. DBS is now included in SBA's economic census category “Wired Telecommunications Carriers.” The Wired Telecommunications Carriers industry comprises establishments primarily engaged in operating and/or providing access to transmission facilities and infrastructure that they own and/or lease for the transmission of voice, data, text, sound, and video using wired telecommunications networks. Transmission facilities may be based on a single technology or combination of technologies. Establishments in this industry use the wired telecommunications network facilities that they operate to provide a variety of services, such as wired telephony services, including VOIP services, wired (cable) audio and video programming distribution; and wired broadband internet services. By exception, establishments providing satellite television distribution services using facilities and infrastructure that they operate are included in this industry. ^{173} The SBA determines that a wireline business is small if it has fewer than 1500 employees. ^{174} Census data for 2007 indicate that 3,188 wireline companies were operational during that year. Of that number, 3,144 operated with fewer than 1,000 employees. ^{175} Based on that data, we conclude that the majority of wireline firms are small under the applicable standard. However, currently only two entities provide DBS service, which requires a great deal of capital for operation: DIRECTV (now owned by AT&T) and DISH Network. ^{176} DIRECTV and DISH Network each report annual revenues that are in excess of the threshold for a small business. Accordingly, we must conclude that internally developed FCC data are persuasive that in general DBS service is provided only by large firms.
^{173} http://www.census.gov/cgi-bin/sssd/naics/naicsrch.
^{174} NAICs CODE 517110; 13.CFR 121.201.
^{175} http://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ECN_2007_US_51SSSZ5&prodType=table .
^{176} See 15th Annual Video Competition Report, 28 FCC Rcd at 1057, Section 27. As of June 2012, DIRECTV is the largest DBS operator and the second largest MVPD in the United States, serving 19.9 million subscribers. DISH Network is the second largest DBS operator and the third largest MVPD operator, serving 14 million subscribers. Id. at 10507, 10546, section 27, 110-11.
25. All Other Telecommunications. “All Other Telecommunications” is defined as follows: This U.S. industry is comprised of establishments that are primarily engaged in providing specialized telecommunications services, such as satellite tracking, communications telemetry, and radar station operation. This industry also includes establishments primarily engaged in providing satellite terminal stations and associated facilities connected with one or more terrestrial systems and capable of transmitting telecommunications to, and receiving telecommunications from, satellite systems. Establishments providing Internet services or voice over Internet protocol (VoIP) services via client-supplied telecommunications connections are also included in this industry. ^{177} The SBA has developed a small business size standard for “All Other Telecommunications,” which consists of all such firms with gross annual receipts of $32.5 million or less. ^{178} For this category, census data for 2007 show that there were 2,383 firms that operated for the entire year. Of these firms, a total of 2,346 had gross annual receipts of less than $25 million. ^{179} Thus, a majority of “All Other Telecommunications” firms potentially affected by the proposals in the NPRM can be considered small.
^{177} http://www.census.gov/cgi-bin/ssssd/naics/naicsrch.
^{178} 13 CFR 121.201; NAICs Code 517919.
^{179} http://factfinder.census.gov/faces/tableservices.jasf/pages/productview.xhtml?pid+ECN_2007_US.51SSSZ4&prodType=table.

D. Description of Projected Reporting, Recordkeeping and Other Compliance Requirements
26. This NPRM does not propose any changes to the Commission's current information collection, reporting, recordkeeping, or compliance requirements.

E. Steps Taken To Minimize Significant Economic Impact on Small Entities, and Significant Alternatives Considered
27. The RFA requires an agency to describe any significant alternatives that it has considered in reaching its approach, which may include the following four alternatives, among others: (1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification, consolidation, or simplification of compliance or reporting requirements under the rule for small entities; (3) the use of performance, rather than design, standards; and (4) an exemption from coverage of the rule, or any part thereof, for small entities. ^{180}
^{180} 5 U.S.C. 603(c)(1)-(c)(4).
28. This NPRM seeks comment on the Commission's regulatory fee collection for Fiscal Year 2016, as required by Congress each year. Specifically, we ask for comments each year in the Regulatory Flexibility Analysis on how to minimize adverse economic impact, imposed by our proposed rules, on small entities. The regulatory fees proposed in this NPRM do not include any new fee categories. However, the proposal in FY 2016 to revise the broadcasters' fee grid to include a threshold “greater than 6,000,000”, and a change in the television fee amounts so that large markets pay a higher proportional fee than small and medium-sized markets, will provide some relief to small broadcast and television entities. The increase in the de minimis amount to $500 implemented in FY 2015 has already provided financial relief to smaller entities.

F. Federal Rules That May Duplicate, Overlap, or Conflict With the Proposed Rules
29. None.

VII. Ordering Clauses
30. Accordingly, it is ordered that, pursuant to sections 4(i) and (j), 9, and 303(r) of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 154(j), 159, and 303(r), this Notice of Proposed Rulemaking is hereby adopted.
31. It is further ordered that the Commission's Consumer and Governmental Affairs Bureau, Reference Information Center, shall send a copy of this Notice of Proposed Rulemaking, including the Initial Regulatory Flexibility Analysis, to the Chief Counsel for Advocacy of the U.S. Small Business Administration.
Federal Communications Commission.
Marlene H. Dortch,

Secretary.
DEPARTMENT OF THE INTERIOR
Fish and Wildlife Service
50 CFR Part 17
[Docket Nos. FWS-R3-ES-2016-0061; FWS-R2-ES-2016-0062] 4500030115
Endangered and Threatened Wildlife and Plants; 90-Day Findings on Two Petitions

AGENCY:
Fish and Wildlife Service, Interior.

ACTION:
Notice of petition findings and initiation of status review.

SUMMARY:
We, the U.S. Fish and Wildlife Service (Service), announce 90-day findings on two petitions to list or delist wildlife under the Endangered Species Act of 1973, as amended (Act). Based on our review, we find that one petition, which requests that we remove the golden-cheeked warbler from the Federal List of Endangered and Threatened Wildlife, does not present substantial scientific or commercial information indicating that the petitioned action may be warranted, and we are not initiating a status review in response to this petition. We refer to this as a “not-substantial petition finding.” We also find that the other petition, which requests that we list the U.S. population of northwestern moose ( Alces alces andersoni ) as an endangered or threatened distinct population segment (DPS), presents substantial scientific or commercial information indicating that the petitioned action may be warranted. Therefore, with the publication of this document, we are initiating a review of the status of this population to determine if the petitioned action is warranted. To ensure that this status review is comprehensive, we are requesting scientific and commercial data and other information regarding this subspecies. Based on the status review, we will issue a 12-month finding on the petition, which will address whether the petitioned action is warranted, as provided in section 4(b)(3)(B) of the Act.

DATES:
To allow us adequate time to conduct the status review, we request that we receive information no later than August 2, 2016. Information submitted electronically using the Federal eRulemaking Portal (see ADDRESSES , below) must be received by 11:59 p.m. Eastern Time on the closing date.

ADDRESSES:
Not-substantial petition finding: The not-substantial petition finding for the golden-cheeked warbler is available on http://www.regulations.gov under the docket number FWS-R2-ES-2016-0062. Supporting information in preparing this finding is available for public inspection, by appointment, during normal business hours by contacting the appropriate person, as specified under FOR FURTHER INFORMATION CONTACT .
Status review: You may submit information on the U.S. population of northwestern moose ( Alces alces andersoni ) by one of the following methods:
(1) Electronically: Go to the Federal eRulemaking Portal: http: //www.regulations.gov. In the Search box, enter the docket number: FWS-R3-ES-2016-0061. You may submit information by clicking on “Comment Now!” If your information will fit in the provided comment box, please use this feature of http://www.regulations.gov, as it is most compatible with our information review procedures. If you attach your information as a separate document, our preferred file format is Microsoft Word. If you attach multiple comments (such as form letters), our preferred format is a spreadsheet in Microsoft Excel.
(2) By hard copy: Submit by U.S. mail or hand-delivery to: Public Comments Processing, Attn: FWS-R3-ES-2016-0061; U.S. Fish and Wildlife Service, MS: BPHC, 5275 Leesburg Pike; Falls Church, VA 22041-3803.
We request that you send information only by the methods described above. We will post all information received on http://www.regulations.gov. This generally means that we will post any personal information you provide us (see Request for Information, below, for more details).

FOR FURTHER INFORMATION CONTACT:
For information on the golden-cheeked warbler, contact Adam Zerrenner, adam_zerrenner@fws.gov, or 512-490-0057. For information on the U.S. population of northwestern moose ( Alces alces andersoni ), contact John JaKa, jonathan_jaka@fws.gov, 612-713-5350.
If you use a telecommunications device for the deaf (TDD), please call the Federal Information Relay Service (FIRS) at 800-877-8339.

SUPPLEMENTARY INFORMATION:

Request for Information
When we make a finding that a petition presents substantial information indicating that listing, reclassification, or delisting a species may be warranted, we are required to promptly review the status of the species (status review). For the status review to be complete and based on the best available scientific and commercial data available, we request information on these species from governmental agencies, Native American Tribes, the scientific community, industry, and any other interested parties. We seek information on:
(1) The biology, range, and population trends of the U.S. population of northwestern moose ( Alces alces andersoni ), including:
(a) Habitat requirements;
(b) Genetics and taxonomy;
(c) Historical and current range, including distribution patterns;
(d) Historical and current population levels, and current and projected trends; and
(e) Past and ongoing conservation measures for the subspecies, its habitat, or both.
(2) The factors that are the basis for making a listing, reclassification, or delisting determination for a species under section 4(a) of the Act (16 U.S.C. 1531 et seq. ), which are:
(a) The present or threatened destruction, modification, or curtailment of its habitat or range (Factor A);
(b) Overutilization for commercial, recreational, scientific, or educational purposes (Factor B);
(c) Disease or predation (Factor C);
(d) The inadequacy of existing regulatory mechanisms (Factor D); or
(e) Other natural or manmade factors affecting its continued existence (Factor E).
(3) The potential effects of climate change on this subspecies and its habitat.
(4) Additional evidence of discreteness, with respect to the 1996 DPS Policy (61 FR 4722, February 7, 1996), regarding the status of the U.S. population of northwestern moose ( Alces alces andersoni ) satisfying one or both of the following conditions:
(a) It is markedly separated from other populations of the same taxon as a consequence of physical, physiological, ecological, or behavioral factors. Quantitative measures of genetic or morphological discontinuity may provide evidence of this separation.
(b) It is delimited by international governmental boundaries within which differences in control of exploitation, management of habitat, conservation status, or regulatory mechanisms exist that are significant in light of section 4(a)(1)(D) of the Act.
(5) Additional evidence of significance regarding the status of U.S. population of northwestern moose ( Alces alces andersoni ) including, but not limited to:
(a) Persistence of the discrete population segment in an ecological setting unusual or unique for the taxon,
(b) Evidence that loss of the discrete population segment would result in a significant gap in the range of a taxon, or
(c) Evidence that the discrete population segment differs markedly from other populations of the species in genetic characteristics.
If, after the status review, we determine that listing is warranted, we will propose critical habitat (see definition at section 3(5)(A) of the Act) for domestic (U.S.) species under section 4 of the Act, to the maximum extent prudent and determinable at the time we propose to list the species. Therefore, we also request data and information for the U.S. population of northwestern moose ( Alces alces andersoni ) on:
(6) What may constitute “physical or biological features essential to the conservation of the species,” within the geographical range occupied by the subspecies;
(7) Where these features are currently found;
(8) Whether any of these features may require special management considerations or protection;
(9) Specific areas outside the geographical area occupied by the subspecies that are “essential for the conservation of the species”; and
(10) What, if any, critical habitat you think we should propose for designation if the subspecies is proposed for listing, such as:
(a) Why these habitats meet the requirements of section 4 of the Act; and
(b) Any probable economic, national security, or other relevant impacts of designating any area that may be included in the proposed designation, and the benefits of including or excluding areas that exhibit these impacts.
Please include sufficient information with your submission (such as scientific journal articles or other publications, and citations to specific pages) to allow us to verify any scientific or commercial information you include.
Submissions merely stating support for or opposition to the actions under consideration without providing supporting information, although noted, will not be considered in making a determination. Section 4(b)(1)(A) of the Act directs that determinations as to whether any species is an endangered or threatened species must be made “solely on the basis of the best scientific and commercial data available.”
You may submit your information concerning this status review by one of the methods listed in ADDRESSES . If you submit information via http://www.regulations.gov, your entire submission—including any personal identifying information—will be posted on the Web site. If you submit a hardcopy that includes personal identifying information, you may request at the top of your document that we withhold this personal identifying information from public review. However, we cannot guarantee that we will be able to do so. We will post all hardcopy submissions on http://www.regulations.gov.
Information and supporting documentation that we received and used in preparing this finding will be available for you to review at http://www.regulations.gov, or you may make an appointment during normal business hours by contacting the appropriate person listed under FOR FURTHER INFORMATION CONTACT , above.

Background
Section 4(b)(3)(A) of the Act requires that we make a finding on whether a petition to list, delist, or reclassify a species presents substantial scientific or commercial information indicating that the petitioned action may be warranted. To the maximum extent practicable, we are to make this finding within 90 days of our receipt of the petition and publish our notice of the finding promptly in the Federal Register .
Our standard for substantial scientific or commercial information within the Code of Federal Regulations (CFR) with regard to a 90-day petition finding is “that amount of information that would lead a reasonable person to believe that the measure proposed in the petition may be warranted” (50 CFR 424.14(b)). If we find that substantial scientific or commercial information was presented, we are required to promptly commence a review of the status of the species, which will be subsequently summarized in our 12-month finding.
Section 4 of the Act (16 U.S.C. 1533) and its implementing regulations at 50 CFR 424 set forth the procedures for adding a species to, or removing a species from, the Federal Lists of Endangered and Threatened Wildlife and Plants. A species may be determined to be an endangered or threatened species due to one or more of the five factors described in section 4(a)(1) of the Act (see (2) under Request For Information, above).
We may delist a species according to 50 CFR 424.11(d) if the best available scientific and commercial data indicate that the species is neither endangered nor threatened for one or more of the following reasons:
(1) The species is extinct;
(2) The species has recovered and is no longer endangered or threatened; or
(3) The original scientific or commercial data used at the time the species was classified, or the interpretation of such data, were in error.
In considering what factors might constitute threats, we must look beyond the exposure of the species to a factor to evaluate whether the species may respond to the factor in a way that causes actual impacts to the species. If there is exposure to a factor and the species responds negatively, the factor may be a threat. However, the identification of factors that could affect a species negatively may not be sufficient to compel a finding that the information in the petition is substantial information indicating that the petitioned action may be warranted. Therefore, during the subsequent status review, we attempt to determine how significant a threat it is. The threat is significant if it drives, or contributes to, the risk of extinction of the species such that the species may warrant listing as endangered or threatened as those terms are defined in the Act. The information presented in the petition must include evidence sufficient to suggest that these factors may be operative threats that act on the species to the point that the species may meet the definition of an endangered or threatened species under the Act.

Evaluation of a Petition To Remove the Golden-Cheeked Warbler From the List of Endangered and Threatened Wildlife
Additional information regarding our review of this petition can be found as an appendix at http://www.regulations.gov under Docket No. FWS-R2-ES-2016-0062 under the Supporting Documents section.

Species and Range
Golden-cheeked warbler ( Dendroica chrysoparia = Setophaga chrysoparia, hereafter warbler), a migratory songbird breeding exclusively in Texas, and wintering in the highlands of Mexico (Chiapas) and Central America (Guatemala, Honduras, Nicaragua, El Salvador).

Petition History
On June 30, 2015, we received a petition dated June 29, 2015, from Nancie G. Marzulla (Marzulla Law, LLC—Washington DC) and Robert Henneke (Texas Public Policy Foundation—Austin TX) requesting that the golden-cheeked warbler be removed from the Federal List of Endangered and Threatened Wildlife (“delisted”) due to recovery or error in information. The petition clearly identified itself as a petition and included the requisite identification information for the petitioner, as required at 50 CFR 424.14(a).
On December 11, 2015, we received supplemental information from the petitioners that included additional published studies and an unpublished report. These studies, as well as others known to the Service and in our files at the time the supplement was received, were considered, as appropriate, in this finding. This finding addresses the petition.

Finding
Based on our review of the petition, sources cited in the petition, and information in our files, we find that the petition does not provide substantial scientific or commercial information indicating that the petitioned action may be warranted. No new information is presented that would suggest that the species was originally listed due to an error in information. The golden-cheeked warbler is a taxonomically unique species and was shown to be in danger of extinction at the time of the listing. The golden-cheeked warbler has not been recovered, and due to ongoing, widespread destruction of its habitat, the species continues to be in danger of extinction throughout its range (Service 2014, p. 15).
Because the petition does not present substantial information indicating that delisting the golden-cheeked warbler may be warranted, we are not initiating a status review in response to this petition. Our explanation for this finding can be found as an appendix at http://www.regulations.gov under Docket No. FWS-R2-ES-2016-0062 under the Supporting Documents section. However, we ask that the public submit to us any new information that becomes available concerning the status of, or threats to, the golden-cheeked warbler or its habitat at any time (see FOR FURTHER INFORMATION CONTACT ).

Evaluation of a Petition To List the U.S. Population of Northwestern Moose ( Alces alces andersoni ) as an Endangered or Threatened Distinct Population Segment (DPS)
Additional information regarding our review of this petition can be found as an appendix at http://www.regulations.gov under Docket No. FWS-R3-ES-2016-0061 under the Supporting Documents section.

Species and Range
U.S. population of northwestern moose ( Alces alces andersoni ); Michigan (Upper Peninsula), Minnesota, North Dakota, and Wisconsin.

Petition History
We received a petition dated July 9, 2015, from the Center for Biological Diversity and Honor the Earth, requesting that we list the U.S. population of northwestern moose ( Alces alces andersoni) under the Act. The petition clearly identified itself as such and included the requisite identification information for the petitioner, required at 50 CFR 424.14(a). This finding addresses the petition.

Finding
Based on our review of the petition and sources cited in the petition, we find that the petition presents substantial scientific or commercial information indicating that the petitioned action may be warranted for the U.S. population of the northwestern moose ( Alces alces andersoni ) based on factors A, C, D, and E.
Our explanation for this finding can be found as an appendix at http://www.regulations.gov under Docket No. FWS-R3-ES-2016-0061 under the Supporting Documents section. Thus, for the U.S. population of northwestern moose ( Alces alces andersoni), the Service requests information on the five listing factors under section 4(a)(1) of the Act, including the factors identified in this finding and explanation (see Request for Information, above).

Conclusion
On the basis of our evaluation of the information presented under section 4(b)(3)(A) of the Act, we have determined that the petition to remove the golden-cheeked warbler from the List of Endangered and Threatened Wildlife does not present substantial scientific or commercial information indicating that the requested action may be warranted. Therefore, we are not initiating a status review for this species.
We have further determined that the petition to list the U.S. population of northwestern moose ( Alces alces andersoni ) as an endangered or threatened DPS presents substantial scientific or commercial information indicating that the requested action may be warranted. Because we have found that the petition presents substantial information indicating that the petitioned action may be warranted, we are initiating a status review to determine whether this action under the Act is warranted. At the conclusion of the status review, we will issue a 12-month finding in accordance with section 4(b)(3)(B) of the Act, as to whether or not the Service believes the petitioned action is warranted.
It is important to note that the “substantial information” standard for a 90-day finding differs from the Act's “best scientific and commercial data” standard that applies to a status review to determine whether a petitioned action is warranted. A 90-day finding does not constitute a status review under the Act. In a 12-month finding, we will determine whether a petitioned action is warranted after we have completed a thorough status review of the species, which is conducted following a substantial 90-day finding. Because the Act's standards for 90-day and 12-month findings are different, as described above, a substantial 90-day finding does not mean that the 12-month finding will result in a finding that the petitioned action is warranted.

References Cited
A complete list of references cited is available for each species addressed in this document on the Internet at http://www.regulations.gov and upon request from the appropriate person listed under FOR FURTHER INFORMATION CONTACT , above.

Authors
The primary authors of this document are the staff members of the Branch of Recovery and State Grants, Ecological Services Program, U.S. Fish and Wildlife Service.

Authority
The authority for these actions is the Endangered Species Act of 1973, as amended (16 U.S.C. 1531 et seq. ).
Dated: May 25, 2016.
Stephen Guertin,

Acting Director, U.S. Fish and Wildlife Service.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
50 CFR Part 226
[Docket No. 150818735-6236-01]
RIN 0648-BF28
Endangered and Threatened Species; Designation of Critical Habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments of Atlantic Sturgeon

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

ACTION:
Proposed rule; request for comments.

SUMMARY:
We, the National Marine Fisheries Service (NMFS), propose to designate critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments (DPSs) of Atlantic sturgeon ( Acipenser oxyrinchus oxyrinchus ). The specific areas proposed for designation include approximately 244 kilometers (152 miles) of aquatic habitat in rivers in Maine, New Hampshire, and Massachusetts for the Gulf of Maine DPS, approximately 547 kilometers (340 miles) of aquatic habitat in rivers in Connecticut, Massachusetts, New York, New Jersey, Pennsylvania, and Delaware for the New York Bight DPS, and approximately 729 kilometers (453 miles) of aquatic habitat in rivers in Maryland, Virginia, and the District of Columbia for the Chesapeake Bay DPS of Atlantic sturgeon. We are soliciting comments from the public on all aspects of the proposal, including information on the economic, national security, and other relevant impacts of the proposed designations, as well as the benefits to the DPSs.

DATES:
Comments on this proposed rule must be received by September 1, 2016.
Public hearings and public information meetings: We will hold two public hearings and two public informational meetings on this proposed rule. We will hold a public informational meeting from 2 to 4 p.m., in Annapolis, Maryland on Wednesday, July 13 (see ADDRESSES ). A second public informational meeting will be held from 3 to 5 p.m., in Portland, Maine on Monday, July 18 (see ADDRESSES ). We will hold two public hearings, from 3 to 5 p.m. and 6 to 8 p.m., in Gloucester, Massachusetts on Thursday, July 21 (see ADDRESSES ).

ADDRESSES:
You may submit comments, identified by the NOAA-NMFS-2015-0107, by either of the following methods:
• Electronic Submissions: Submit all electronic public comments via the Federal eRulemaking Portal. Go to www.regulations.gov/#!docketDetail;D=NOAA-NMFS-2015-0107 , Click the “Comment Now!” icon, complete the required fields, and enter or attach your comments.
• Mail: Kimberly B. Damon-Randall, Assistant Regional Administrator, Protected Resources Division, NMFS, Greater Atlantic Regional Office, 55 Great Republic Drive, Gloucester, MA 01930.
Instructions: Comments sent by any other method, to any other address or individual, or received after the end of the comment period, may not be considered by us. All comments received are a part of the public record and will generally be posted for public viewing on www.regulations.gov without change. All personal identifying information ( e.g., name, address, etc.), confidential business information, or otherwise sensitive information submitted voluntarily by the sender will be publicly accessible. We will accept anonymous comments (enter “N/A” in the required fields if you wish to remain anonymous).
Public informational meetings and public hearings: The July 13, 2016, public informational meeting will be held at the Environmental Protection Agency, Information and Conference Center, 410 Severn Avenue, Annapolis, MD 21403. The July 18, 2016, public informational meeting will be held at the Gulf of Maine Research Institute, Cohen Center, 350 Commercial Street, Portland, Maine 04101. The July 21, 2016, public hearings will be held at the NMFS, Greater Atlantic Region Fisheries Office, 55 Great Republic Drive, Gloucester, MA 01930. People needing reasonable accommodations in order to attend and participate or who have questions about the public hearings should contact Lynn Lankshear, NMFS, Greater Atlantic Region Fisheries Office (GARFO), as soon as possible (see FOR FURTHER INFORMATION CONTACT ).

FOR FURTHER INFORMATION CONTACT:
Lynn Lankshear, NMFS, GARFO at 978-282-8473; Julie Crocker, NMFS, GARFO at 978-282-8480; or Lisa Manning, NMFS, Office of Protected Resources at 301-427-8466.

SUPPLEMENTARY INFORMATION:
In accordance with section 4(b)(2) of the ESA (16 U.S.C. 1533(b)(2)) and our implementing regulations (50 CFR 424.12), this proposed rule is based on the best scientific information available concerning the range, biology, habitat, and threats to the habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic sturgeon. We have reviewed the information ( e.g., provided in reports, peer-reviewed literature, and technical documents) and have used it to identify the physical and biological features essential to the conservation of each DPS, the specific areas within the occupied areas that contain the essential physical and biological features that may require special management protection, the federal activities that may impact those features, and the potential impacts of designating critical habitat for each DPS. We have gathered this information for all three DPSs into a single document, the Draft Biological Information and ESA section 4(b)(2) Source Document. The economic impacts of the proposed critical habitat designations for each DPS are described in the document titled, Draft Economic Impact Analysis of Critical Habitat Designation for the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments of Atlantic Sturgeon ( Acipenser oxyrinchus oxyrinchus ), which was prepared by King and Associates, Incorporated. These supporting documents are available on the Federal eRulemaking Portal at http://www.regulations.gov. Electronic copies can also be obtained at http://www.greateratlantic.fisheries.noaa.gov/protected/atlsturgeon/index.html or upon request (see ADDRESSES ).
We invite the submission of information that may help to identify other physical or biological features. For example, while we know that there are specific estuarine areas that sturgeon often use for foraging ( e.g., the mouth of the Merrimack and Saco rivers), and we can identify aggregation areas ( e.g., off of western Long Island, New York) and general movement patterns in the marine environment ( e.g., typically within the 50 meter depth contour) to and from estuarine areas, we could not identify what the specific features are of these habitats that make them important to sturgeon and that may require special management.

Background
Under section 4 of the ESA, critical habitat shall be specified to the maximum extent prudent and determinable at the time a species is listed as threatened or endangered (16 U.S.C. 1533(b)(6)(C)). We concluded that critical habitat was not determinable for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs when we published the final listing rule (77 FR 5880, February 6, 2012). However, we anticipated that critical habitat would be determinable in the future, given on-going research. We, therefore, announced in the final rule that we would propose critical habitat for each DPS in a separate rulemaking.
Section 3(5)(A) of the ESA defines critical habitat as the specific areas within the geographical area occupied by the species at the time it is listed on which are found those physical or biological features essential to the conservation of the species and which may require special management considerations or protections, and specific areas outside the geographical area occupied by the species at the time it is listed that are essential for the conservation of the species (16 U.S.C. 1532(5)(A)). Conservation is defined in section 3(3) of the ESA as “. . . to use, and the use of, all methods and procedures which are necessary to bring any endangered species or threatened species to the point at which the measures provided pursuant to this Act are no longer necessary . . .” (16 U.S.C. 1532(3)). Therefore, critical habitat is the habitat essential for the species' recovery. However, section 3(5)(C) of the ESA clarifies that except in those circumstances determined by the Secretary, critical habitat shall not include the entire geographical area which can be occupied by the threatened or endangered species.
As described in section 4(b)(2) of the ESA, we are required to designate critical habitat based on the best available scientific data and after taking into consideration the economic impact, impact on national security, and any other relevant impact, of specifying any particular area as critical habitat. Section 4(b)(2) provides us with discretion to exclude particular areas from a designation if the benefits of excluding that area outweigh the benefits of including it in the designation, unless failure to designate such areas as critical habitat will result in the extinction of the species. Finally, section 4(a)(3)(B) prohibits designating as critical habitat any lands or other geographical areas owned or controlled by the Department of Defense or designated for its use, that are subject to an Integrated Natural Resources Management Plan (INRMP) prepared under section 101 of the Sikes Act (16 U.S.C. 670a), if the Secretary determines in writing that such plan provides a conservation benefit to the species, and its habitat, for which critical habitat is proposed for designation. Although not expressly stated in section 4(b)(2), our regulations clarify that critical habitat shall not be designated within foreign countries or in other areas outside of United States jurisdiction (50 CFR 424.12(g)).
Once critical habitat is designated, section 7(a)(2) of the ESA requires Federal agencies to ensure that any action they fund, authorize or carry out is not likely to destroy or adversely modify that habitat (16 U.S.C. 1536(a)(2)). This requirement is in addition to the section 7(a)(2) requirement that Federal agencies ensure that their actions are not likely to jeopardize the continued existence of ESA-listed species. Specifying the geographic location of critical habitat also facilitates implementation of section 7(a)(1) of the ESA by identifying areas where Federal agencies can focus their conservation programs and use their authorities to further the purposes of the ESA. Critical habitat requirements do not apply to citizens engaged in activities on private land that do not involve a Federal agency. However, designating critical habitat can help focus the efforts of other conservation partners ( e.g., State and local governments, individuals and nongovernmental organizations).
Accordingly, our step-wise approach for identifying potential critical habitat areas for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs included the following: (1) Identify the physical and biological features essential to the conservation of the DPS and which may require special management considerations or protection; (2) identify specific areas where those features occur within the occupied geographic range of a particular DPS; (3) identify any unoccupied habitat essential to the conservation of a particular DPS; (4) consider economic, national security, or any other impacts of designating critical habitat and determine whether to exercise our discretion to exclude any particular areas; and (5) determine whether any area that contains essential features is covered under an INRMP that provides a conservation benefit to the DPS.

Biology and Habitat of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic Sturgeon
Although there is considerable variability among species, all sturgeon species (order Acipenseriformes ) have some common life history traits. They all: (1) Occur within the Northern Hemisphere; (2) spawn in freshwater over hard bottom substrates; (3) generally do not spawn annually; (4) are benthic foragers; (5) mature relatively late and are relatively long lived; and, (6) are relatively sensitive to low dissolved oxygen levels (Dees, 1961; Vladykov and Greeley, 1963; Klyashtorin, 1976; Bemis and Kynard, 1997; Sulak and Randall, 1999; Billard and Lecointre, 2001; Secor and Niklitschek, 2002; Pikitch et al., 2005).
Atlantic sturgeon have all of these traits. They occur along the eastern coast of North America from Hamilton Inlet, Labrador, Canada, to Cape Canaveral, Florida, USA (Bigelow and Welsh, 1924; Dees, 1961; Vladykov and Greeley, 1963; Scott and Scott, 1988; NMFS and USFWS, 2007; T. Savoy, CT DEEP, pers. comm.). They have a lifespan of up to 60 years, although the typical lifespan is probably much shorter (Sulak and Randall, 2001; Balazik et al., 2010). As described in the Status Review, Atlantic sturgeon reach maturity at about 5 to 34 years of age, after years of moving between marine waters and coastal estuaries, and spawn in freshwater of tidal-affected rivers every 1 to 5 years (males) or 2 to 5 years (females) (NMFS and USFWS, 2007). Analysis of stomach contents for adults, subadults ( i.e., sexually immature Atlantic sturgeon that have emigrated from the natal estuary), and juveniles ( i.e., sexually immature Atlantic sturgeon that have not yet emigrated from the natal estuary) confirms that Atlantic sturgeon are benthic foragers (Ryder, 1888; Bigelow and Schroeder, 1953; Johnson et al., 1997; Secor et al., 2000; NMFS and USFWS, 2007; Guilbard et al., 2007; Hatin et al., 2007; Savoy, 2007; Dzaugis, 2013; McLean et al., 2013).
An anadromous species, Atlantic sturgeon are spawned in freshwater of rivers that flow into a coastal estuary. Tagging records and the relatively low rate of gene flow reported in population genetic studies provide evidence that Atlantic sturgeon return to their natal river to spawn (NMFS and USFWS, 2007). Spawning sites are well-oxygenated areas with flowing water ranging in temperature from 13 °C to 26 °C, and hard bottom substrate such as cobble, coarse sand, hard clay, and bedrock (Ryder, 1888; Dees, 1961; Vladykov and Greeley, 1963; Scott and Crossman, 1973; Gilbert, 1989; Smith and Clugston, 1997; Bain et al. 2000; Collins et al., 2000; Caron et al., 2002; Hatin et al., 2002; Mohler, 2003; Greene et al., 2009; Balazik et al. 2012; Hager et al. 2014). Water depth leading to spawning sites may be highly variable. Since the exact location of spawning is unknown, spawning depth is also uncertain. Atlantic sturgeon in spawning condition have been tracked and captured near presumed spawning habitat at depths up to 27 m (Borodin 1925; Dees 1961; Scott and Crossman 1973; Shirey et al. 1999; Bain et al. 2000; Hatin et al., 2002; Balazik et al., 2012; Hager et al., 2014).
Within minutes of being fertilized, the eggs become sticky and adhere to the substrate for the relatively short and temperature-dependent period of larval development (Ryder, 1888; Vladykov and Greeley, 1963; Murawski and Pacheco, 1977; Smith et al., 1980; Van den Avyle, 1984; Mohler, 2003). In hatchery studies, hatching occurred approximately 60 hours after egg deposition at water temperatures of 20 °C to 21 °C and 96 hours after egg deposition with a water temperature of approximately 18 °C (Smith et al., 1980; J. Fletcher, USFWS pers. comm. in Mohler, 2003).
Larval Atlantic sturgeon ( i.e., less than 4 weeks old, with total lengths less than 30 mm; Van Eenennaam et al., 1996) are assumed to inhabit the same areas where they were spawned and live at or near the bottom (Ryder, 1888; Smith et al., 1980; Bain et al., 2000; Kynard and Horgan, 2002; Greene et al., 2009). The best available information for behavior of larval Atlantic sturgeon is described from hatchery studies. Upon hatching, larvae are nourished by the yolk sac, are mostly pelagic ( e.g., exhibit a “swim-up and drift-down” behavior in hatchery tanks; Mohler, 2003), and move away from light ( i.e. negative photo-taxis; Kynard and Horgan, 2002; Mohler, 2003). Within days, larvae exhibit more benthic behavior until the yolk sac is absorbed at about 8 to 10 days post-hatching (Kynard and Horgan, 2002; Mohler, 2003). Post-yolk sac larvae occur in the water column but feed at the bottom of the water column (Mohler, 2003; Richardson et al., 2007).
The next phase of development, referred to as the juvenile stage, lasts months to years in brackish waters of the natal estuary (Hatin et al., 2007; NMFS and USFWS, 2007; Greene et al., 2009; Calvo et al., 2010; Schueller and Peterson, 2010). Juveniles occur in oligohaline waters (salinity of 0.5 to 5 parts per thousand) and mesohaline waters (salinity of 5 to 18 parts per thousand) of the natal estuary during growth and development. They will eventually move into polyhaline waters (salinity of 18-30 parts per thousand) before emigrating to the marine environment. Larger, presumably older, juveniles occur across a broader salinity range than smaller, presumably younger, juveniles (Hatin et al., 2007; McCord et al., 2007; Munro et al., 2007; NMFS and USFWS, 2007; Sweka et al., 2007; Greene et al., 2009; Calvo et al., 2010).
The distribution of Atlantic sturgeon juveniles in the natal estuary is a function of physiological development and habitat selection based on water quality factors of temperature, salinity, and dissolved oxygen, which are inter-related environmental variables. In laboratory studies, juveniles less than a year old (also known as young-of-year) had reduced growth at 40 percent dissolved oxygen saturation with salinity of 8 and 15 parts per thousand and temperature at 12 °C, 20 °C, and 28 °C. They grew best at 70 percent dissolved oxygen saturation with salinity of 8 and 15 parts per thousand and temperature of 12 °C and 20 °C ( i.e., dissolved oxygen concentrations greater than 6.5 mg/L), and selected for conditions that supported growth (Niklitschek and Secor, 2009; Niklitschek and Secor, 2010). Similar results were obtained for age-1 juveniles ( i.e., greater than 1 year old and less than 2 years old), which have been shown to tolerate salinities of 33 parts per thousand ( e.g., a salinity level associated with seawater), but grow faster in lower salinity waters (Niklitschek and Secor, 2009; Allen et al., 2014).
Once suitably developed, Atlantic sturgeon leave the natal estuary and enter marine waters ( i.e., waters with salinity greater than 30 parts per thousand) which marks the beginning of the subadult life stage. In the marine environment, subadults mix with adults and subadults from other river systems (NMFS and USFWS, 2007; Grunwald et al., 2008; Dunton et al., 2010; Erickson et al., 2011; Dunton et al., 2012; Wirgin et al., 2012; Waldman et al., 2013; O'Leary et al., 2014, Wirgin et al., 2015a; Wirgin et al., 2015b). Atlantic sturgeon travel long distances in marine waters, aggregate in both ocean and estuarine areas at certain times of the year, and exhibit seasonal coastal movements in the spring and fall (NMFS and USFWS, 2007; Dunton et al., 2010; Dunton et al., 2012; Erickson et al., 2011; Oliver et al., 2013; Wippelhauser and Squiers, 2015). Existing and new technologies are providing additional information for the life history and distribution of the Atlantic sturgeon in marine waters (Nelson et al., 2013; Breece et al., 2016). However, there is still a paucity of data to inform distribution of subadult and adult Atlantic sturgeon within the marine environment and their habitat use.
The exact spawning locations for Gulf of Maine, New York Bight and Chesapeake Bay DPS Atlantic sturgeon are unknown but inferred based on the location of freshwater, hard substrate, water depth, tracking of adults to upriver locations and the behavior of adults at those locations, capture of young-of-year and, in limited cases, larvae, and historical accounts of where the caviar fishery occurred. Based on one or more of these lines of evidence, multiple sites have been identified within many of the rivers used for spawning (NMFS and USFWS, 2007; Simpson, 2008; Hager, 2011; Austin, 2012; Balazik et al., 2012; Breece et al., 2013). Spawning sites at different locations within the tidal-affected river would help to ensure successful spawning given annual changes in the location of the salt wedge.
Male Atlantic sturgeon in spawning condition have been observed to stage in more saline waters of the coastal estuary before moving upriver once the water temperature reaches approximately 6 °C (43 °F). They may spend weeks moving upstream and downstream of the presumed spawning area(s) before moving back downriver to the lower estuary and residing there until outmigration in the fall. In contrast, spawning females move upriver when temperatures are closer to 12 °C to 13 °C (54 ° to 55 ° F), return downriver relatively quickly, and may leave the estuary and travel to other coastal estuaries until outmigration to marine waters in the fall (Smith et al., 1982; Dovel and Berggren, 1983; Smith, 1985; Bain, 1997; Bain et al., 2000; Collins et al., 2000; NMFS and USFWS, 2007; Greene et al., 2009; Balazik et al., 2012; Breece et al., 2013).
There is a growing body of evidence that some Atlantic sturgeon river populations have two spawning seasons comprised of different spawning adults (Balazik and Musick, 2015). Evidence of fall spawning for the Carolina and South Atlantic DPSs was available when the five Atlantic sturgeon DPSs were listed under the ESA (77 FR 5914; Smith et al., 1984; NMFS and USFWS 1998; Collins et al., 2000). Since the listings, additional evidence of fall as well as spring spawning has been obtained for the Chesapeake Bay DPS (Balazik et al., 2012; Hager et al. 2014; Kahn et al., 2014). Spring is the only currently known spawning period for the Gulf of Maine and New York Bight DPSs. However, an 1870's report of Atlantic sturgeon spawning during August in the Hudson River (Dovel and Berggren, 1983) and other historical information (Borodin, 1925; Balazik and Musick, 2015) suggests spring and fall spawning runs were typical, and may still occur in many areas of the Atlantic sturgeon's range. Given seasonal changes in the location of the salt-wedge for estuarine systems, it is likely that fall spawning would occur or would have occurred further upstream than the locations for spring spawning in rivers.
In addition to providing access to spawning habitat, estuaries provide foraging opportunities for subadult and adult Atlantic sturgeon. Stomach content analysis of Atlantic sturgeon captured in coastal estuaries confirm that sturgeon are foraging in coastal estuaries (Hatin et al., 2007; Savoy, 2007; Calvo et al., 2010; Wippelhauser, 2012; Dzaugis, 2013; McLean et al., 2013; McLean et al., 2014). The occurrence of subadult and adults in association with the salt front (Brundage and Meadows, 1982; Savoy and Shake, 1993; Collins et al. 2000; Savoy and Pacileo, 2003; Hatin et al., 2007; Calvo et al., 2010; Hager, 2011; Balazik, 2012; Breece et al., 2013), a biologically-rich area of estuaries, also suggests use of estuarine waters for seasonal foraging. At least some Atlantic sturgeon subadults and adults move between estuarine environments in the spring through fall (Savoy and Pacileo, 2003; Simpson, 2008; Collins et al., 2000; Balazik et al., 2012).
The directed movement of subadult and adult Atlantic sturgeon to coastal estuaries in the spring is reversed in the fall (NMFS and USFWS, 2007; Greene et al., 2009; Hager, 2011; Erickson et al., 2011; Balazik et al., 2012; Wippelhauser, 2012; Oliver et al., 2013). The whereabouts of these fish once they leave coastal estuaries is uncertain. Atlantic sturgeon aggregate off of Long Island, New York and off of the Virginia/North Carolina coastline (Laney et al., 2007; Dunton et al., 2015). Others have been tracked to the southern extent of the range (T. Savoy, CT DEEP, pers. comm.) while at least one was tracked to the more northern area of the subspecies range, the Back River, Maine, in winter (G. Zydlewski, Univ. of Maine, pers. comm.). Two adults originally tagged in the Delaware River were detected in the Appomattox River, Virginia (C. Hager, Chesapeake Scientific, pers. comm.) during the winter. A recent study of Atlantic sturgeon tracked in the Delaware Bay found that some of the fish migrating from the estuary in the fall remained in nearby coastal marine waters within a plume of water flowing out from the estuary, suggesting a continued affinity with the estuary even after emigrating from the estuary proper (Oliver et al., 2013). Further work suggests Atlantic sturgeon distribution in the marine environment is affected more by the characteristics of the water ( e.g., eddies, coastal upwelling, temperature) than characteristics of the landscape ( e.g., depth, substrate) (Breece et al., 2016).
To identify specific habitats used by an Atlantic sturgeon DPS, we considered available information that described: (1) Capture location and/or tracking locations of a subadult or adult Atlantic sturgeon identified to its DPS by genetic analysis; (2) capture location and/or tracking locations of a subadult or adult Atlantic sturgeon identified to its DPS based on the presence of a tag that was applied when the sturgeon was captured as a juvenile in its natal estuary; (3) capture or detection location of adults in spawning condition ( i.e., extruding eggs or milt) or post-spawning condition ( e.g., concave abdomen for females); (4) capture or detection of young-of year and other juvenile age classes; and, (5) collection of eggs or larvae. In the case of estuaries of known spawning rivers, we assumed based on the available information that a portion of the subadults and adults present originated from that river and, thus, the habitats used by subadults and adults in a spawning river were indicative of habitats used by the DPS which spawned in the river. Previous studies have demonstrated that a combination of microsatellite and mitochondrial DNA analyses provide the most accurate information to identify an Atlantic sturgeon to its DPS, and using mitochondrial analysis, alone, provides much lower assignment accuracy given the prevalence of a common Atlantic sturgeon haplotype (NMFS and USFWS, 2007; Wirgin et al., 2012; Waldman et al., 2013). Therefore, when reviewing the available information on habitats used by Atlantic sturgeon, we also considered what genetic analyses were used to assign the sampled sturgeon to its DPS of origin.
The Kennebec River was the only known spawning river for the Gulf of Maine DPS when the DPS was listed as threatened (NMFS and USFWS, 2007; 77 FR 5880, February 6, 2012). Spawning has since been confirmed in the Androscoggin River (Wippelhauser, 2012). The Brunswick Dam at Pejepscot Falls, the head-of-tide, is the upstream limit of Atlantic sturgeon distribution in the Androscoggin River. The dam is located approximately 10 kilometers upstream of the confluence of the Kennebec and Androscoggin rivers (ASMFC, 1998; NMFS and USFWS, 2007; NMFS, 2013; Wippelhauser and Squiers, 2015). The Lockwood Dam at river kilometer 103 is the current upstream limit for Atlantic sturgeon in the Kennebec River; it is located at the site of a natural falls (NMFS and USFWS, 2007). From 1837 to 1999, the Edwards Dam was the upstream limit of Atlantic sturgeon in the Kennebec River. Located near the head-of-tide, approximately 29 kilometers downstream of the Lockwood Dam at Augusta, the Edwards Dam (rkm 74) prevented Atlantic sturgeon from accessing historical habitat. Sturgeon were sighted above the former Edwards Dam site after removal of the dam and in June 2005, an Atlantic sturgeon was incidentally captured at river kilometer 102 (NMFS and USFWS, 2007; Wippelhauser, 2012).
Substrate type in the Kennebec estuary is largely sand and bedrock (Fenster and Fitzgerald, 1996; Moore and Reblin, 2008). Mesohaline waters occur upstream of Doubling Point during summer low flows, transitioning to oligohaline waters and then essentially tidal freshwater from Chops Point (the outlet of Merrymeeting Bay) upriver to the head-of tide on the Kennebec and Androscoggin rivers (ASMFC, 1998; Kistner and Pettigrew, 2001). A thorough description of the Kennebec Estuary is provided in Moore and Reblin 2008.
During the period 1977-2001, Atlantic sturgeon in spawning condition ( i.e., ripe males releasing sperm) or of size presumed to be sexually mature adults ( i.e., greater than 150 cm total length) were caught between river kilometers 52.8 and 74 of the Kennebec River during the months of June and July, the likely spawning season. From 2009 to 2011, 31 sturgeon, including 6 ripe males, were caught in the Kennebec River between river kilometers 70 and 75 (Wippelhauser, 2012; Wippelhauser and Squiers, 2015). Sturgeon in the Upper Kennebec Estuary (defined as river kilometer 45 to river kilometer 74 at head-of tide in the cited document) repeatedly moved between river kilometers 48 and 75 (Wippelhauser, 2012). An additional eight sturgeon, including one ripe male, were caught in the Androscoggin in June and July of 2009-2011 (Wippelhauser, 2012). Three larvae were also captured in the Upper Kennebec Estuary, 1 to 1.6 river kilometers upstream of river kilometer 74, the former Edwards Dam site (Wippelhauser, 2012).
The Merrymeeting Bay and Lower Kennebec Estuary are used by post-spawn adults, juveniles, and other life stages at least as late as November, and some Atlantic sturgeon may overwinter in Merrymeeting Bay (Wippelhauser, 2012). Sturgeon captured and tagged in the Saco and Penobscot rivers are also detected in the Kennebec Estuary, typically Merrymeeting Bay and downstream locations, although at least one male, captured in the Saco in 2010, was the single ripe male also captured in the Androscoggin suggesting that the Saco and Penobscot are important habitat areas for the Androscoggin spawning population (Wippelhauser, 2012). However, genetic information identifying the river of origin of the Atlantic sturgeon is not yet available.
While there is no current evidence that Atlantic sturgeon are spawning in Gulf of Maine rivers other than the Kennebec and Androscoggin, captures of sturgeon in the Merrimack and Penobscot Rivers as well as the presence of the features necessary to support reproduction and recruitment in these rivers indicate that there is the potential for spawning to occur (Kieffer and Kynard, 1993; Fernandes et al., 2010; Wippelhauser, 2012). The 1998 and 2007 status reviews for Atlantic sturgeon described information for presence of Atlantic sturgeon in the Piscataqua River, including capture of a large female Atlantic sturgeon in spawning condition in 1990. The presence of this female (NMFS and USFWS, 1998; ASSRT, 2007) as well as the presence of the features necessary to support reproduction and recruitment in this river indicates that there is the potential for spawning to occur in the Piscataqua.
Genetic information is available for Atlantic sturgeon captured in six specific areas of the marine range: Minas Basin, Bay of Fundy, Canada; the Connecticut River estuary; Long Island Sound; the Atlantic Ocean off of Rockaway, New York; the Atlantic Ocean off of Delaware Bay; and, the Atlantic Ocean off of Virginia/North Carolina (Laney et al., 2007; Wirgin et al., 2012; Waldman et al., 2013; O'Leary et al., 2014; Wirgin et al., 2015a). Atlantic sturgeon belonging to the Gulf of Maine DPS comprised 35 percent of the Minas Basin, Bay of Fundy samples collected in the summer, suggesting this is an important foraging area for the Gulf of Maine DPS. The DPS comprised less than 2 percent to 14.5 percent of Atlantic sturgeon sampled in the Connecticut River, Long Island Sound, the Atlantic Ocean off of Rockaway, New York, and the Atlantic Ocean off of Delaware Bay. The DPS was not detected in the sampled Atlantic sturgeon incidentally captured during winter from waters off of Virginia/North Carolina.
At the time of listing, the Delaware and Hudson rivers were the only known spawning rivers for the New York Bight DPS of Atlantic sturgeon (Dovel and Berggren, 1983; Bain, 1998; Kahnle et al., 1998; NMFS and USFWS, 2007; Calvo et al., 2010). In spring 2014, several small Atlantic sturgeon were captured in the Connecticut River (T. Savoy, CT DEEP, pers. comm.). We presume these to be juveniles less than a year old based on their apparent size seen in a photo provided in the Connecticut Weekly Diadromous Fish Report, report date May 20, 2014. Though it was previously thought that the Atlantic sturgeon population in the Connecticut had been extirpated (Savoy and Pacileo, 2003; NMFS and USFWS, 2007), capture of these juvenile Atlantic sturgeon strongly suggests that spawning is occurring in this river. For the Housatonic River, the 1998 and 2007 status reviews for Atlantic sturgeon described information for historical presence of Atlantic sturgeon in that river, including Whitworth's (1996) reference to a large fishing industry for Atlantic sturgeon (NMFs and USFWS, 1998; NMFS and USFWS, 2007). Since the commercial fisheries targeted spawning sturgeon, historical captures of sturgeon in the Housatonic River as well as the presence of the features necessary to support reproduction and recruitment in this river indicates that there is the potential for spawning to occur in the Housatonic.
The Hudson River is one of the most studied areas for Atlantic sturgeon. The upstream limit for Atlantic sturgeon on the Hudson River is the Federal Dam at the fall line, approximately river kilometer 246 (Dovel and Berggren, 1983; Bain, 1998; Kahnle et al., 1998; Everly and Boreman, 1999). Recent tracking data indicate Atlantic sturgeon presence at this upstream limit (D. Fox, DESU, pers. comm.). Sturgeon occurring in the upstream limits of the river are suspected, but not yet confirmed, to belong to the New York Bight DPS.
Spawning may occur in multiple sites within the river (Dovel and Berggren, 1983; Van Eenennaam et al., 1996; Kahnle et al., 1998; Bain et al., 2000). The area around Hyde Park (approximately river kilometer 134) is considered a likely spawning area based on scientific studies and historical records of the Hudson River sturgeon fishery (Dovel and Berggren, 1983; Van Eenennaam et al., 1996; Kahnle et al.,
1998; Bain et al., 2000). Habitat conditions at the Hyde Park site are described as freshwater year round with substrate, including bedrock, and waters depths of 12 to 24 meters (Bain et al., 2000). Similar conditions occur at river kilometer 112, an area of freshwater and water depths of 21 to 27 meters (Bain et al., 2000).
Catches of Atlantic sturgeon less than 63 cm fork length suggest that these sexually immature fish utilize the Hudson River estuary from the Tappan Zee (river kilometer 40) through Kingston (river kilometer 148) (Dovel and Berggren, 1983; Haley, 1999; Bain et al., 2000). Seasonal movements of the immature fish are apparent as they primarily occupy waters from river kilometers 60 to 107 during summer months and then move downstream as water temperatures decline in the fall, primarily occupying waters between river kilometers 19 to 74 (Dovel and Berggren, 1983; Haley, 1999; Bain et al., 2000). In a separate study, Atlantic sturgeon ranging in size from 32 to 101 cm fork length were captured at highest concentrations during spring in soft-deep areas of Haverstraw Bay, even though this habitat type comprised only 25 percent of the available habitat in the Bay (Sweka et al., 2007).
In the Delaware River, there is evidence of Atlantic sturgeon presence from the mouth of the Delaware Bay to the head-of-tide at the fall line near Trenton on the New Jersey side and Morrisville on the Pennsylvania side of the River, a distance of 220 river kilometers (Shirey et al., 1997; Brundage and O'Herron, 2007; Simpson, 2008; Calvo et al., 2010; Fisher, 2011; Breece et al., 2013). There are no dams on the Delaware River and an Atlantic sturgeon carcass was found as far upstream as Easton, PA in 2014 (M. Fisher, DE DNREC, pers. comm.), suggesting that sturgeon can move beyond the fall line.
The presence of hard bottom habitat, the location of the salt-wedge in April through July, and tracking of adult Atlantic sturgeon in spawning condition suggests that spawning habitat for Atlantic sturgeon occurs within the Delaware River between river kilometer 125 (near Claymont, Delaware) and the fall line at river kilometer 211 (landmarks of Trenton, New Jersey, and Morrisville, Pennsylvania) (Sommerfield and Madsen, 2003; Simpson 2008; Breece et al., 2013).
Twenty Atlantic sturgeon less than 30 cm fork length (26.2 to 34.9 cm total length) and presumed to be less than one year old were captured in the Delaware River from September through November 2009 and tracked for up to one year using a passive acoustic array (Calvo et al., 2010; Fisher, 2011). The data collected indicate this life stage makes use of Delaware River habitats from river kilometers 105 to 199 with seasonal changes in distribution (Fisher, 2009; Calvo et al., 2010; Fisher, 2011). For example, during the winter months, some remained around river kilometer 134 ( i.e., the Marcus Hook area) while others moved upstream or downstream, exhibiting migrations in and out of the area (Calvo et al., 2010; Fisher, 2011). Overall, the studies demonstrated the complexity of habitat needs for juvenile Atlantic sturgeons in the natal estuary during the first 1 to 2 years. In contrast to juveniles, subadult Atlantic sturgeon occur further downriver in polyhaline waters of the Bay and River (Brundage and Meadows, 1982; Lazzari et al., 1986; Shirey et al., 1997; Shirey et al., 1999; Simpson, 2008; Brundage and O'Herron, 2009; Calvo et al., 2010; Fisher, 2011).
The Connecticut River has long been known as a seasonal aggregation area for subadult Atlantic sturgeon, and both historical and contemporary records document presence of Atlantic sturgeon in the river as far upstream as Hadley, MA (Savoy and Shake, 1993; Savoy and Pacileo, 2003; NMFS and USFWS, 2007). The Enfield Dam located along the fall line at Enfield, CT prevented upstream passage of Atlantic sturgeon from 1827 until 1977 when it was breached (NMFS and USFWS, 2007). Although Atlantic sturgeon may generally remain below the fall line, an Atlantic sturgeon was captured at the Holyoke Dam fish lift in 2006, upstream of Enfield (NMFS and USFWS, 2007). As noted previously, the capture of juvenile Atlantic sturgeon in the Connecticut River in May 2014 (T. Savoy, CT DEEP, pers. comm.; Connecticut Weekly Diadromous Fish Report, report date May 20, 2014) suggests spawning may be occurring in the river.
The genetics information for Atlantic sturgeon captured in six specific areas of the marine range demonstrated that Atlantic sturgeon belonging to the New York Bight DPS were present in each area. In addition, the New York Bight DPS was the most represented DPS in each collection, comprising 55 percent to 87 percent of the sturgeon sampled in each area, with the exception of the Minas Basin collection where the New York Bight DPS comprised only 1 to 2 percent of the sampled sturgeon (Laney et al., 2007; Wirgin et al., 2012; Waldman et al., 2013; O'Leary et al., 2014; Wirgin et al., 2015a). The results suggest that New York Bight DPS Atlantic sturgeon travel great distances, including into Canadian waters, but occur most predominantly in marine waters in areas off New York and the Mid-Atlantic Bight.
At the time of listing, the James River was the only known spawning river for the Chesapeake Bay DPS (NMFS and USFWS, 2007; Hager, 2011; Balazik et al., 2012). Since the listing, spawning has been confirmed to occur in the Pamunkey River, a tributary of the York River (Hager et al., 2014; Kahn et al., 2014). Spawning is also suspected to be occurring in Marshyhope Creek, a tributary of the Nanticoke River, based on the presence of adult sturgeon in spawning condition in areas and at times when spawning would be expected to occur (Maryland DNR, web article, September 17, 2014).
Adult Atlantic sturgeon enter the James River in the spring, with at least some eventually moving as far upstream as Richmond (river kilometer 155), which is also the head-of-tide and close to the likely upstream extent of Atlantic sturgeon in the river, given the presence of Boshers Dam at the fall line (approximately river kilometer 160) (Bushnoe et al., 2005; Hager, 2011; Balazik et al., 2012). Adults disperse through downriver sites and begin to move out of the river in late September to early October, occupy only lower river sites by November, and are undetected on tracking arrays in the lower river by December, suggesting that the sturgeon leave the river for the winter (Hager, 2011; Balazik et al., 2012).
The availability of hard-bottom habitat remains relatively limited in the James River and appears to be significantly reduced compared to the amount of available hard-bottom habitat described in historic records (Bushnoe et al., 2005; Austin, 2012). In general, tracked adults occurred further upstream during the late summer and early fall residency ( e.g., river kilometer 108 to river kilometer 132; Balazik et al., 2012) than during the spring and early summer residency ( e.g., river kilometer 29 to river kilometer 108; Hager, 2011), suggesting two different spawning areas depending on season.
The capture of adult Atlantic sturgeon in spawning condition in the low salinity waters of the Pamunkey River, a major tributary of the York River, in August 2013, and subsequent genetic testing demonstrate that there is a spawning population of Atlantic sturgeon in the Pamunkey River (Hager et al., 2014; Kahn et al., 2014). The York River is 55 kilometers long from its mouth, after which it divides into two major tributaries, the Mattaponi and the Pamunkey Rivers (Bushnoe et al., 2005; Friedrichs, 2009; Reay, 2009). The transition to freshwater typically occurs within these tributaries (Friedrichs, 2009; Reay, 2009). Bushnoe et al. (2005) previously reviewed available information on substrate, salinity, and dissolved oxygen for the Pamunkey and Mattaponi rivers and concluded that Atlantic sturgeon spawning habitat was likely present in each river.
For the Susquehanna and Potomac Rivers, the 1998 and 2007 Atlantic sturgeon status reviews provided the information for presence of Atlantic sturgeon in the rivers, including: (1) Historical newspaper accounts of large sturgeon in the lower reaches of the Susquehanna River during the period 1765 to 1895; (2) personal communication of a limited but more recent sturgeon fishery on the Susquehanna near Perryville, Maryland (R. St. Pierre, USFWS, personal comm.); (3) several sightings of sturgeon near the Susquehanna River mouth during the period 1978 to 1987; (4) a historical fishery for Atlantic sturgeon in the Potomac; and (5) observations of a large mature female Atlantic sturgeon in the Potomac River in 1970 ((NMFS and USFWS, 1998; NMFS and USFWS, 2007). Since the commercial fisheries targeted spawning sturgeon, historical captures of sturgeon in the Susquehanna and Potomac Rivers, as well as the presence of the features necessary to support reproduction and recruitment in each river, indicate that there is the potential for spawning to occur in both the Susquehanna and Potomac.
The 1998 and 2007 status reviews for Atlantic sturgeon described information for presence of Atlantic sturgeon in the Rappahannock River, including commercial landings data from the 1880s and incidental captures reported to the U.S. Fish and Wildlife Service Reward Program in the 1990's (NMFS and USFWS 1998; NMFS and USFWS, 2007). Most recently, in September 2015, researchers captured a male Atlantic sturgeon in spawning condition in the Rappahannock River (M. Balazik, Virginia Commonwealth University, pers. comm.). The historical and contemporary accounts of Atlantic sturgeon in the Rappahannock River (NMFS and USFWS, 1998; ASSRT, 2007), as well as the presence of the features necessary to support reproduction and recruitment in this river indicate that there is the potential for spawning to occur in the Rappahannock.
The condition of Atlantic sturgeon captured in the late summer-fall in the James River ( e.g., adults expressing milt or eggs), the rapid upstream movement of adults in the fall, and the aggregation of adults relative to the salt wedge provide evidence of fall spawning in the James River (NMFS and USFWS; 2007; Hager, 2011; Balazik et al., 2012). Similar evidence was found for adult sturgeon captured in the Pamunkey River in mid to late August 2013, and adult sturgeon captured in Marshyhope Creek in late August 2014 (Maryland DNR, web article, September 17, 2014). All of these instances provide evidence that Chesapeake DPS Atlantic sturgeon spawn in the fall.
The genetics information for Atlantic sturgeon captured in six specific areas of the marine range demonstrates that Atlantic sturgeon belonging to the Chesapeake Bay DPS were present in at least four of the sampled areas: The Connecticut River, Long Island Sound, the Atlantic Ocean off of Rockaway, New York, and the Atlantic Ocean off of Delaware Bay. The DPS comprised approximately 5 percent to 21 percent of the Atlantic sturgeon sampled in these areas (Waldman et al., 2013; O'Leary et al., 2014; Wirgin et al., 2015a). The Chesapeake Bay DPS was not detected in the relatively small number of samples collected from Atlantic sturgeon captured in the winter off of North Carolina (Laney et al., 2007), and comprised no more that 1 percent of Atlantic sturgeon sampled in the Minas Basin in the summer (Wirgin et al., 2012). The results suggest that Chesapeake Bay DPS Atlantic sturgeon travel great distances, including into Canadian waters, but occur most predominantly in marine waters of the New York and Mid-Atlantic Bight.

Geographical Area Occupied by Each DPS
Consistent with our past practice, we interpret “geographical area occupied” for critical habitat designations to mean the range of the listed entity ( e.g., species, subspecies or DPS) at the time of listing (45 FR 13011; February 27, 1980). In February 2016, NMFS and the USFWS published a joint final rulemaking that included a regulatory definition for “geographical area occupied” (81 FR 7417, February 11, 2016). The new definition provides clarity to the critical habitat designation process, but does not change how we approached critical habitat designations.
The marine range of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs, including coastal bays and estuaries, is Hamilton Inlet, Labrador, Canada, to Cape Canaveral, Florida (77 FR 5880, February 6, 2012). The listing rule also identified the known spawning rivers for each of these DPSs, but it did not describe the specific in-river range for any of the DPSs. Therefore, areas were considered to be within the range of a DPS if there were: (1) Presence of Atlantic sturgeon belonging to that DPS in that area; (2) presence of Atlantic sturgeon in a similar area within the boundaries of the otherwise established DPSs range; and, for rivers, (3) all areas downstream of the farthest known upstream location of Atlantic sturgeon belonging to that DPS in that river. Areas were identified as unoccupied by a DPS if the area was completely inaccessible to Atlantic sturgeon.
Genetic analyses indicate the presence of Atlantic sturgeon belonging to the Gulf of Maine, New York Bight, and Chesapeake Bay DPS in many parts of the marine range including the Bay of Fundy, the Connecticut River Estuary, Long Island Sound, the New York Bight, and coastal waters from Delaware to North Carolina (Waldman et al., 1996; Laney et al., 2007; Dunton et al., 2010; Dunton et al., 2012; Wirgin et al., 2012; Waldman et al., 2013; O'Leary et al., 2014; Wirgin et al., 2015a). In addition, tracking and tagging studies indicate the presence of Atlantic sturgeon throughout the marine range (Vladykov and Greeley, 1963; Holland and Yelverton 1973; Dovel and Berggren, 1983; Gilbert 1989; Savoy and Pacileo, 2003; Stein et al. 2004; Eyler, 2006; Laney et al., 2007; Dunton et al., 2010; Dunton et al., 2012; Oliver et al., 2013). Based on our review of the literature and other available data, we concluded that Atlantic sturgeon: Typically occur in marine waters within the 50 m depth contour, but also occur in deeper marine waters; occur in many coastal sounds and bays from the Maine/Canada border to Cape Canaveral, Florida, regardless of whether or not the sound or bay is part of an estuary of a known spawning river; and, occur in tidally-affected rivers along the coast.
The “geographical area occupied” is only aquatic habitat ( e.g., below the high tide line). In addition, certain natural features ( e.g., large waterfalls) and dams are impassable barriers to sturgeon. Therefore, we consider those parts of the range that are currently inaccessible to Atlantic sturgeon due to dams, other manmade structures, or natural features to be unoccupied, and not part of the geographic area occupied by the DPS at the time of listing.

Physical and Biological Features Essential to Conservation That May Require Special Management Considerations or Protections
As described above, critical habitat is defined as those specific areas in the geographical area occupied that (1) have the physical or biological features essential to the conservation of the listed entity, and (2) may require special management considerations or protections. Each of these two prongs must be met when designating critical habitat within the occupied geographical area. If we identify physical or biological features that are essential to the conservation of the listed entity, but there are no special management considerations or protections that may be required, then we do not designate critical habitat based on those physical or biological features. Finally, we do not designate critical habitat based solely on the presence of the listed entity. The presence of the listed entity can, however, help us identify the essential physical or biological features. For example, repeated use of an area by the listed entity suggests the presence of essential physical or biological features.
We determined that a key conservation objective for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs is to increase the abundance of each DPS by facilitating increased successful reproduction and recruitment to the marine environment. We know that each DPS is at a low level of abundance and successful reproduction and recruitment, which are essential to the conservation of the species, occur in a limited number of rivers for each DPS. Since the listing, additional rivers have either been confirmed to support spawning, or are suspected of supporting spawning for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs (Wippelhauser, 2012; Hager et al., 2014; Kahn et al., 2014; T. Savoy, CT DEEP, pers. comm.). Nevertheless, the number of known spawning rivers for each DPS is still limited compared to the four to six rivers for each DPS in which spawning occurred in the past (NMFS and USFWS, 2007). Further, we do not know how successful reproduction is for any of the known spawning rivers ( e.g., we do not have counts of the number of juveniles of each DPS or spawning river that recruit to the marine environment, compared to the number of fertilized eggs that hatched).
The term “physical or biological features” is defined as the features that support the life-history needs of the species, including, but not limited to, water characteristics, soil type, geological features, sites, prey, vegetation, symbiotic species or other features. A feature may be a single habitat characteristic or a more complex combination of habitat characteristics. Features may include habitat characteristics that support ephemeral or dynamic habitat conditions. Features may also be expressed in terms of relating to principles of conservation biology, such as patch size, distribution distances, and connectivity (50 CFR 424.02). The term “special management considerations or protection” is defined as the methods or procedures useful in protecting the physical or biological features essential to the conservation of the listed species (50 CFR 424.02). In addition, the term “may” in the phrase “may require special management considerations or protections” was the focus of two cases in Federal district courts that ruled that features can meet this provision because of either a present requirement for special management considerations or protection or possible future requirements (see Center for Biol. Diversity v. Norton, 240 F. Supp. 2d 1090 (D. Ariz. 2003); Cape Hatteras Access Preservation Alliance v. DOI, 344 F. Supp. 108 (D.D.C. 2004)).
Atlantic sturgeon are estuarine-dependent, anadromous fish that require specific estuarine habitat for successful reproduction and recruitment. Adults require unimpeded access ( e.g., suitable water depth to be able to move freely and a lack of obstructions) to and from all spawning sites. In addition, spawning males require unimpeded access to search for spawning females throughout the spawning season. Fertilized eggs require freshwater, hard, clean substrate to adhere to, and flowing water that helps to disperse and aerate the eggs. Larval Atlantic sturgeon (less than 4 weeks old and less than 30 mm total length), assumed to inhabit the same freshwater areas where they were spawned, require hard substrate with interstitial spaces that provide refuge from predators. The relatively lengthy juvenile phase requires developing Atlantic sturgeon have access to aquatic habitat with a gradual downstream salinity gradient of 0.5 to 30 parts per thousand ( e.g., inclusive of oligohaline, mesohaline, and polyhaline waters), and areas of soft substrate that provide an environment for benthic prey necessary for juvenile foraging. Last, Atlantic sturgeon juvenile rearing habitat, habitat for spawning adults and subadults, and larval habitat must have sufficient levels of dissolved oxygen both before the fish are present (to enable fish to utilize the habitat when they migrate to it) and when fish arrive since Atlantic sturgeon are particularly sensitive to low oxygen levels and, similar to other fish species, will avoid habitats that are hypoxic ( i.e., have insufficient oxygen) (Secor and Niklitschek, 2001; Breitburg, 2002; EPA, 2003). Oxygen concentrations that fish avoid are approximately equal to concentrations that reduce their growth rate, even when at concentration levels higher than necessary for their survival (Breitburg 2002; EPA, 2003). Lab studies have shown that a dissolved oxygen concentration of about 6.5 mg/L supports growth and habitat use of juvenile Atlantic sturgeon less than two years old (Niklitschek and Secor, 2009; Niklitschek and Secor, 2010; Allen et al., 2014). The complex relationship between dissolved oxygen, temperature, and salinity, as well as other factors that can affect dissolved oxygen levels in estuaries ( e.g., water depth and mixing), makes it difficult for us to specify water quality parameters necessary to support Atlantic sturgeon use of reproduction and recruitment habitat. The EPA's guidance on ambient water quality criteria for dissolved oxygen for the Chesapeake Bay recommends dissolved oxygen concentrations of greater than 6 mg/L, based on a seven-day mean, in tidal habitats with salinity of 0 to 0.5 parts per thousand for the growth of larval and juvenile tidal-fresh resident fish, including Atlantic sturgeon (EPA, 2003). This concentration has been shown to increase the likelihood of habitat use by Atlantic sturgeon juveniles less than two years old (Niklitschek and Secor 2009; Niklitscheck and Secor, 2010). Since these early age groups are more sensitive to dissolved oxygen levels than older, larger juveniles, subadults, and adults, a dissolved oxygen concentration of 6 mg/L supports habitat use by all age groups. Therefore, the physical features essential for reproduction and recruitment are:
• Hard bottom substrate ( e.g., rock, cobble, gravel, limestone, boulder, etc.) in low salinity waters ( i.e., 0.0 to 0.5 parts per thousand range) for settlement of fertilized eggs, refuge, growth, and development of early life stages;
• Aquatic habitat with a gradual downstream salinity gradient of 0.5 to 30 parts per thousand and soft substrate ( e.g., sand, mud) downstream of spawning sites for juvenile foraging and physiological development;
• Water of appropriate depth and absent physical barriers to passage ( e.g., locks, dams, reservoirs, gear, etc.) between the river mouth and spawning sites necessary to support: (1) Unimpeded movement of adults to and from spawning sites; (2) seasonal and physiologically dependent movement of juvenile Atlantic sturgeon to appropriate salinity zones within the river estuary; and (3) staging, resting, or holding of subadults or spawning condition adults. Water depths in main river channels must also be deep enough ( e.g., ≥1.2 m) to ensure continuous flow in the main channel at all times when any sturgeon life stage would be in the river; and
• Water, especially in the bottom meter of the water column, with the temperature, salinity, and oxygen values that, combined, support: (1) Spawning; (2) annual and interannual adult, subadult, larval, and juvenile survival; and (3) larval, juvenile, and subadult growth, development, and recruitment ( e.g., 13 °C to 26 °C for spawning habitat and no more than 30° C for juvenile rearing habitat, and 6 mg/L dissolved oxygen for juvenile rearing habitat).
The specific oxygen concentration and temperature values are provided as examples and guidance to inform the combinations of temperature, salinity, and oxygen that support successful reproduction and recruitment. Temperature, salinity, and oxygen are ephemeral by nature, fluctuating daily and seasonally in estuaries. Specific areas designated as critical habitat based on the four features are not expected to have water with oxygen concentration of 6 mg/L and the specific water temperatures at all times and within all parts of the area.
Barriers ( e.g., dams) and in-water structures ( e.g., tidal turbines) in rivers used by Atlantic sturgeon can damage or destroy bottom habitat needed for spawning and rearing of juveniles, as well as restrict movement of adults to and from spawning grounds, and prevent juveniles from accessing the full range of salinity exposure in the natal estuary. Land development, as well as commercial and recreational activities on the river, contribute to the persistence of nutrient loading and sediment deposition, which negatively affect the water quality necessary for successful spawning and recruitment. For example, nutrient loading can result in unnaturally enhanced growth of aquatic vegetation or phytoplankton and algal blooms, which disrupt normal functioning of the ecosystem, causing a variety of problems, including a lack of sufficient levels of oxygen that fish, such as Atlantic sturgeon, need to survive. Excessive sediment deposition reduces Atlantic sturgeon egg adherence on hard spawning substrate and reduces the interstitial spaces used by larvae for refuge from predators. Dredging to remove sediment build-up or to facilitate vessel traffic may remove or alter hard substrate that is necessary for egg adherence and as refuge for larvae, and may change the water depth, resulting in shifts in the salt wedge within the estuary or change other characteristics of the water quality ( e.g., temperature, dissolved oxygen) necessary for the developing eggs, larvae, and juveniles.
The features essential for successful Atlantic sturgeon reproduction may also require special management considerations or protection as a result of global climate change. Many communities and commercial facilities withdraw water from the rivers containing the features essential to Atlantic sturgeon reproduction. Water withdrawals during times of low flow can affect the position of the salt wedge, impact the water depth necessary for successful sturgeon reproduction, and affect water flow. Because dissolved oxygen concentrations increase wherever the water flow becomes turbulent, decreasing flow can result in decreases in dissolved oxygen concentrations. Attempts to control water during very high flows ( e.g., spilling water from dams upriver of Atlantic sturgeon spawning and rearing habitat) can create barriers ( e.g., from debris) to upstream and downstream passage of adults and juveniles. Therefore, we concluded that the features essential to the conservation of each of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs may require special management considerations or protections.
For the reasons provided above, we have concluded that the habitat features that support successful spawning and recruitment of Atlantic sturgeon juveniles to the marine environment are: Essential to the conservation of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs; within the geographical area occupied by each DPS; and, may require special management considerations or protection. As such, we used these features to identify specific areas as potential critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic sturgeon.
We determined another conservation objective for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs is to increase the abundance of each DPS by facilitating increased survival of subadults and adults. The ability of subadults to find food is necessary for continued survival, growth, and physiological development to the adult life stage. Likewise, given that Atlantic sturgeon mature late and do not necessarily spawn annually, increased adult survival would improve the chances that adult Atlantic sturgeon spawn more than once.
We considered all studies that have collected Atlantic sturgeon stomach contents. All of the prey species identified are indicative of benthic foraging, and all of the identified prey are found in soft substrates. However, different types of prey were consumed, and different soft substrates were identified for the areas where Atlantic sturgeon were foraging (Bigelow and Schroeder, 1953; Johnson et al., 1997; NMFS and USFWS, 2007; Guilbard et al., 2007; Savoy, 2007; Dzaugis, 2013; McLean et al., 2013). No data are available to differentiate areas of preferred prey items or higher prey abundance within or across estuaries. Adding to our uncertainty of the essential features that support successful foraging for growth and survival of subadults and adults, Atlantic sturgeon move between estuarine environments in the spring through fall, and can occur in estuarine environments during the winter as well (Savoy and Pacileo, 2003; Simpson, 2008; Collins et al., 2000; Balazik et al., 2012). For example, subadult Atlantic sturgeon spawned in one riverine system may utilize multiple estuaries for foraging and growth, including those not directly connected to their natal river. Due to the paucity of data on their estuarine needs and specific habitat or resource utilization, we could not at this time identify the physical or biological features of estuaries for foraging and growth that are essential to the conservation of the Gulf of Maine, New York Bight or Chesapeake Bay DPSs.
Subadult and adult Atlantic sturgeon use marine waters to traverse between estuarine areas, particularly within the 50 meter depth contour. In addition, several congregations of Atlantic sturgeon in the marine environment are known to occur. However, the exact importance of those areas is not known, nor whether Atlantic sturgeon are drawn to particular areas based on physical or biological features of the habitat. Therefore, while we can identify general movement patterns and behavior in the marine environment ( e.g., aggregating behavior) that may contribute to subadult and adult survival, due to the paucity of data on each DPSs' needs and specific habitat utilization in the marine environment, we could not at this time identify physical or biological features in the marine environment essential to conservation of the Gulf of Maine, New York Bight or Chesapeake Bay DPSs.

Unoccupied Areas
As mentioned, the definition of critical habitat includes areas outside of the geographical area occupied by the listed entity ( i.e., unoccupied areas) at the time it is listed if these areas are essential to the conservation of the listed entity. We do not need to identify physical or biological features requiring special management consideration or protection within the unoccupied areas in order to designate unoccupied areas as critical habitat. However, the area must be essential to the conservation of the listed species.
There are riverine areas outside of the geographical area occupied by the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs as a result of dams and natural falls. We considered whether these unoccupied areas were essential to the conservation of the respective DPS and concluded that they were not essential because nearly all known historical habitat is accessible to the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs (NMFS and USFWS, 2007; 77 FR 5880, February 6, 2012).

Critical Habitat Units
Critical habitat must be defined by specific limits using reference points and lines as found on standard topographic maps of the area, and cannot use ephemeral reference points (50 CFR 424.12(c)). When several habitats, each satisfying the requirements for designation as critical habitat, are located in proximity to one another, an inclusive area may be designated as critical habitat (50 CFR 424.12(d)).
The habitat containing the physical features essential to the conservation of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs and that may require special management or protection is aquatic habitat of main stem rivers flowing into a coastal estuary. We are designating only occupied habitat. Atlantic sturgeon typically cannot pass dams or natural features such as waterfalls and rapids found at the fall line of rivers from Maine through Virginia. Therefore, we are defining each critical habitat unit by an upriver landmark on the main stem river ( e.g., the most downriver dam or a bridge immediately downriver of the fall line of that river) and all waters of the main stem downriver of that landmark to where the waters empty at its mouth into an identified water body.

Identified Critical Habitat for Each DPS
Based on the physical features that we identified as essential for successful spawning and recruitment and the best available information, we identified five critical habitat units for the Gulf of Maine DPS as follows: (1) Penobscot River main stem from the Milford Dam downstream for 53 river kilometers to where the main stem river drainage discharges at its mouth into Penobscot Bay; (2) Kennebec River main stem from the Ticonic Falls/Lockwood Dam downstream for 103 river kilometers to where the main stem river discharges at its mouth into the Atlantic Ocean; (3) Androscoggin River main stem from the Brunswick Dam downstream for 10 river kilometers to where the main stem river drainage discharges into Merrymeeting Bay; (4) Piscataqua River from its confluence with the Salmon Falls and Cocheco rivers downstream for 19 river kilometers to where the main stem river discharges at its mouth into the Atlantic Ocean as well as the waters of the Cocheco River from its confluence with the Piscataqua River and upstream 5 river kilometers to the Cocheco Falls Dam, and waters of the Salmon Falls River from its confluence with the Piscataqua River and upstream 6 river kilometers to the Route 4 Dam; and (5) Merrimack River from the Essex Dam (also known as the Lawrence Dam) downstream for 48 river kilometers to where the main stem river discharges at its mouth into the Atlantic Ocean. In total, these designations encompass approximately 244 kilometers (152 miles) of aquatic habitat.
The physical features essential for successful reproduction and recruitment may require special management or protection in these specific areas because of potential adverse impacts from activities such as the operation of dams, dredging operations, other construction ( e.g., bridge construction or repair), and impacts from development along the river that includes wastewater treatment and water withdrawals (Ceasar et al., 1976; Short, 1992; Kistner and Pettigrew, 2001; Odell et al., 2006; NMFS and USFWS, 2007; Mohlar, 2008; Moore and Reblin, 2008; McFarlane, 2012).
We identified four critical habitat units for the New York Bight DPS: (1) Connecticut River from the Holyoke Dam downstream for 140 river kilometers to where the main stem river discharges at its mouth into Long Island Sound; (2) Housatonic River from the Derby Dam downstream for 24 river kilometers to where the main stem discharges at its mouth into Long Island Sound; (3) Hudson River from the Troy Lock and Dam (also known as the Federal Dam) downstream for 246 river kilometers to where the main stem river discharges at its mouth into New York City Harbor; and (4) Delaware River from the crossing of the Trenton-Morrisville Route 1 Toll Bridge, downstream for 137 river kilometers to where the main stem river discharges at its mouth into Delaware Bay. In total, these designations encompass approximately 547 kilometers (340 miles) of aquatic habitat.
The physical features that are essential to successful reproduction and recruitment may require special management or protection in these specific areas because of potential adverse impacts from, for example, the operation of dams, dredging operations, other construction ( e.g., bridge construction or repair), and impacts from development along the river that includes wastewater treatment and water withdrawals (Hammerson, 2004; NMFS and USFWS, 2007; Henshaw, 2011; Breece et al., 2013; 78 FR 1145).
We identified five critical habitat units for the Chesapeake Bay DPS: (1) Susquehanna River from the Conowingo Dam downstream for 16 river kilometers to where the main stem river discharges at its mouth into the Chesapeake Bay; (2) Potomac River from the Little Falls Dam downstream for 189 river kilometers to where the main stem river discharges at its mouth into the Chesapeake Bay; (3) Rappahannock River from the U.S. Highway 1 Bridge, downstream for 172 river kilometers to where the river discharges at its mouth into the Chesapeake Bay; (4) York River from its confluence with the Mattaponi and Pamunkey rivers downstream to where the main stem river discharges at its mouth into the Chesapeake Bay as well as the waters of the Mattaponi River from its confluence with the York River and upstream to the Virginia State Route 360 Bridge crossing of the Mattaponi River, and waters of the Pamunkey River from its confluence with the York River and upstream to the Virginia State Route 360 Bridge crossing of the Pamunkey River for a total of 192 kilometers of aquatic habitat, (5) James River from Boshers Dam downstream for 160 river kilometers to where the main stem river discharges at its mouth into the Chesapeake Bay at Hampton Roads. In total, these designations encompass approximately 729 kilometers (453 miles) of aquatic habitat.
The physical features essential for successful spawning and recruitment may require special management or protection in these specific areas because of potential adverse impacts from activities such as the operation of dams, dredging operations, other construction ( e.g., bridge construction or repair), and impacts from development along the river that includes wastewater treatment and water withdrawals (Bushnoe et al., 2005; CBF, 2006; NMFS and USFWS, 2007; Friedrichs, 2009; Reay, 2009; Austin, 2012; SRBC, 2013; Potomac Conservancy, 2014).

Military Lands
Section 4(a)(3)(B) of the ESA prohibits designating as critical habitat any lands or other geographical areas owned or controlled by the Department of Defense, or designated for its use, that are subject to an INRMP prepared under section 101 of the Sikes Act (16 U.S.C. 670a), if the Secretary determines in writing that such a plan provides a benefit to the species for which critical habitat is proposed for designation.
In February 2014, we requested information from the Department of Defense to assist in our analysis. Specifically, we asked for a list of facilities that occur within the potential critical habitat areas and available INRMPs for those facilities. There are a limited number of facilities with INRMPs that overlap with the potential critical habitat areas for the New York Bight and Chesapeake Bay DPSs. The Department of the Army identified the U.S. Military Academy—West Point, New York as a facility that overlapped with the Hudson River Critical Habitat Unit of the New York Bight DPS. The Department of the Air Force identified Joint Base Langley—Eustis, Virginia as a facility that overlapped with the James River Critical Habitat Unit of the Chesapeake Bay DPS. The Navy identified Marine Corps Base Quantico, Virginia, and Naval Support Facility Dahlgren as facilities that overlapped with the Potomac River Critical Habitat Unit, and identified Naval Weapons Station Yorktown, a complex of three facilities, as facilities that overlapped with the York River Critical Habitat Unit of the Chesapeake Bay DPS. We reviewed the INRMP for each facility and concluded that each INRMP provides a benefit to Atlantic sturgeon and its habitat belonging to the respective DPS. Therefore, in accordance with section 4(a)(3)(B) of the ESA, the particular areas of each facility with an approved INRMP that overlaps with a proposed critical habitat unit will not be part of the designated critical habitat unit. No Department of Defense facilities were identified as overlapping with potential critical habitat areas of the Gulf of Maine DPS.

Economic, National Security, and Other Relevant Impacts
The administrative cost of conducting ESA section 7 consultations was determined to be the primary source of economic impacts as a result of designating critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs. We used the consultation record over the past 10 years to identify the types of Federal activities that may affect proposed Atlantic sturgeon critical habitat if implemented in the future. We also requested that federal action agencies provide us with information on future consultations if we omitted any future actions likely to affect the proposed critical habitat. Of the types of past consultations that “may affect” some or all of the essential features in any unit of proposed critical habitat, we determined that no activities would solely affect the essential features. That is, all categories of the activities identified have potential routes of adverse effects to both Atlantic or shortnose sturgeon and the critical habitat.
There were no section 7 consultations for activities in the Housatonic River over the past ten years. Activities that have occurred did not trigger the need for section 7 consultation for a listed ESA species under NMFS jurisdiction ( e.g., shortnose sturgeon), and there is no critical habitat designated in the Housatonic River for any other ESA-listed species under NMFS jurisdiction. Based on this information, the projected administrative cost of section 7 consultations likely to occur over the next ten years as a result of designating the Housatonic River Critical Habitat Unit was zero. However, the potential Housatonic River Critical Habitat Unit contains a federal navigation channel as well as a major highway bridge. Channel dredging, bridge maintenance, and bridge replacement are activities likely to trigger section 7 consultation if critical habitat for Atlantic sturgeon are designated in the Housatonic River. We expect the federal navigation channel will require periodic dredging. Bridge replacement has recently occurred (78 FR 1145; January 8, 2013), but we expect that routine maintenance will be required within the next 10 years. Therefore, the administrative section 7 costs as a result of designating the Housatonic River Critical Habitat Unit are unlikely to be zero. Based on the past history and the likely need for maintenance, we anticipate up to three formal consultations will occur over the next 10 years for federal agency actions that affect the features of the Housatonic River Critical Habitat Unit. However, consultation would also assess whether the proposed actions may affect one or more of the Atlantic sturgeon DPSs. Therefore, no incremental administrative impacts are anticipated as a result of designating critical habitat in the Housatonic River.
Nine nationwide consultations with EPA are also expected to occur within the next 10 years. These consultations will involve all listed species and designated critical habitat under NMFS's jurisdiction, and thus costs attributable solely to this proposed rule are expected to be very small. To be conservative, we added nine consultations to each critical habitat unit, and nine to each DPS's total number of consultations. We spread the costs of these consultations ($5,080 each) evenly across all critical habitat units included in this proposed rule and the companion proposed rule to designate critical habitat for the Carolina and South Atlantic DPSs. This resulted in a total cost of $1,474.84 per critical habitat unit.
We cannot be certain that the numbers of informal and formal consultations involving Atlantic sturgeon critical habitat in the future will be exactly the same as the number that would have occurred during the past ten years if critical habitat was designated at the time. We also have no information about the scope, methods, exact location or timing of future actions, which are key factors for determining whether an action may adversely affect critical habitat, which essential features may be affected, and whether the action may also affect Atlantic sturgeon. Similar to economic analyses for other NMFS critical habitat designations ( e.g., for Gulf sturgeon (IEc, 2003), and for the southern DPS of green sturgeon (IEc, 2009)), uncertainty was addressed by presenting three cost estimate scenarios: Consultations of low, medium, or high complexity. These cost estimate scenarios help to demonstrate how changes in the number of informal and formal consultations and differing percentages of coextensive and incremental consultations could influence the cost projections. The scenarios are: (1) Low administrative section 7 cost estimates, which are based on the assumption that the numbers of informal and formal consultations in the future will be the same as they were in the past, and that half of the consultations will be co-extensive ( i.e., initiated as a result of listing and critical habitat designation) and half will be incremental ( i.e., initiated as a result of the critical habitat designation); (2) medium administrative section 7 cost estimates, which are based on the assumption that the numbers of informal and formal consultations in the future will be the same as they were in the past, and that they will all be incremental; and, (3) high administrative section 7 cost estimates, which are based on the assumption that all consultations in the next ten years will be formal and incremental.
The regulatory baseline conditions, including the listing of the Atlantic sturgeon, will greatly affect the number of incremental consultations. Specifically, the number of incremental consultations will likely be relatively small, because Atlantic sturgeon of a given life stage are likely to be either directly or indirectly affected by the federal activities projected to occur within the proposed critical habitat. In general, we expect Atlantic sturgeon of a given life stage could occur year round in the particular areas proposed for designation. Therefore, the section 7 consultations we anticipate to occur will need to evaluate potential effects to both the Atlantic sturgeon DPS present in the area and the critical habitat since impacts will be co-extensive. Because the high and medium administrative costs estimates both assumed that all project consultations would be incremental, we consider the low administrative cost estimates to be the most realistic costs estimates.
Based on the Draft Economic Impacts Analysis, the projected low administrative costs of designating all of the Gulf of Maine DPS critical habitat units total $816,574.20. The individual low costs for the five critical habitat units range from $54,274.84 for the Piscataqua River Critical Habitat Unit to $305,874.84 for the Kennebec River Critical Habitat Unit. The medium and high administrative costs for the Gulf of Maine DPS critical habitat units total $1,625,774.20 and $2,707,374.20, respectively. The projected low administrative costs for the New York Bight DPS critical habitat units total $1,418,299.301. The individual low costs for the four critical habitat units range from 31,474.84 for the Housatonic River Critical Habitat Unit to $752,674.84 for the Hudson River Critical Habitat Unit. The medium and high administrative costs for the New York Bight DPS critical habitat units total $2,830,699.30 and $5,565,899.30, respectively. The projected low administrative costs of designating all of the Chesapeake Bay DPS critical habitat units total $524,974.20. The individual low costs for the five critical habitat units range from $45,474.84 for the Rappahannock River Critical habitat Unit to $276,274.84 for the Potomac River Critical Habitat Unit. The medium and high administrative costs for the Chesapeake Bay DPS critical habitat units total $1,042,574.20 and $1,947,374.20, respectively.
Currently, there is no information indicating that any of the section 7 consultations expected to result from the critical habitat designations will result in project modifications. However, there is potential that section 7 consultation stemming from these designations may, sometime in the future, result in project modifications and associated costs. Therefore, for illustrative purposes, the draft economic analysis similarly presents low, medium, and high cost estimate scenarios for project modifications that may need to be made to specific projects as a result of section 7 consultation. The same caveats noted above apply to costs associated with modifications, i.e., while the three broad categories of costs based on broad assumptions provide a potential range of costs, in most instances, modifications will occur as a result of coextensive impacts. It is extremely unlikely that modifications that would be required to avoid destruction or adverse modification of critical habitat would not also be required because of adverse effects to the species. Details of the cost projections and the number of past formal and informal consultations for each critical habitat unit of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs are provided in the draft economic analysis and the Draft Biological Information and 4(b)(2) Source Document.
The Navy expressed concern that designating the Kennebec River and Piscataqua River critical habitat units, including the area of the Kennebec River adjacent to the location of Bath Iron Works, a private shipbuilder for the Navy, and the area of the Piscataqua River surrounding Portsmouth Naval Shipyard on Seavey Island at the mouth of the Piscataqua River, will impact the national security. The Navy described the activities likely to occur in one or both of the particular areas as: Flooding and dewatering dry docks, updating and maintaining pier structures including pile driving, and dredging activities to maintain proper channel and berthing depths.
We considered the impact these activities are likely to have on the physical features. The physical features of critical habitat in the areas requested for exclusion are salinity suitable for older juveniles, open passage for juveniles suitably developed to leave the natal river, open passage for adults traveling through the area to and from spawning areas, open passage for subadults traveling through the area, and soft substrate. Withdrawing water from the river to flood dry docks and returning that water to the river would not change the salinity or substrate in the river and would have no impact on open passage. Maintaining and/or updating the pier structures is not likely to adversely affect salinity, but may affect open passage and substrate ( e.g., placing more pier structures in the area, altering the substrate to make it more suitable for the pier structure). Similarly, dredging activities to maintain proper channel and berthing depths may affect ( e.g., remove) the substrate that supports foraging, and change the depth affecting salinity ( e.g., as a result of changes to mixing in the estuarine river or the extent of saltwater intrusion). However, dredging and maintaining and/or updating the pier structures also may affect the species. For example, construction to maintain and/or update pier structures can produce sounds that disrupt normal behaviors such as sturgeon foraging, staging, and spawning. Dredging may injure or kill sturgeon that come into contact with the gear ( e.g., older juveniles passing through as they leave the natal river, adults traveling through the area to and from spawning areas, and subadults traveling through the area). Therefore, we determined that any resulting consultations will likely be coextensive.
The Navy expressed concern that designating the Delaware River critical habitat unit in the area surrounding the Philadelphia Naval Yard Annex (three specific areas), will impact national security. The Navy described the activities likely to occur in the particular areas as: updating and maintaining pier structures including pile driving, dredging activities to maintain proper channel and berthing depths, barge loading and unloading, and fuel unloading.
We considered the impact these activities are likely to have on the physical features. The physical features of critical habitat in the areas requested for exclusion are salinity suitable for younger juveniles, open passage for juveniles to access all parts of the estuary needed for development, open passage for adults traveling through the area to and from spawning areas, and soft substrate. The activities described by the Navy may affect salinity, open passage, and substrate. Maintaining and/or updating the pier structures may affect open passage and substrate ( e.g., placing more pier structures in the area, and altering the substrate to make it more suitable for the pier structure). Dredging activities to maintain proper channel and berthing depths may affect ( e.g., remove) the substrate that supports foraging and spawning. Changing the depth could affect salinity ( e.g., as a result of changes to mixing in the estuarine river or the extent of saltwater intrusion). Barge loading and unloading, and fuel unloading may affect water quality ( e.g., as a result of spills). Maintaining and/or updating the pier structures, dredging, and barge traffic also may affect the species. For example, maintaining and/or updating pier structures can produce sounds that harass sturgeon and disrupt normal behaviors such as foraging, staging, and spawning. Dredging may result in injury or death of sturgeon that come into contact with the gear ( e.g., older juveniles passing through as they leave the natal river, adults traveling through the area to and from spawning areas, and subadults traveling through the area). Vessels for fuel deliveries and barge traffic can strike sturgeon resulting in injuries and mortality. Since the activities described by the Navy are also likely to impact the species ( e.g., juveniles and spawning adults), we expect consultations will be coextensive.
The Navy also expressed concern that designating the Rappahannock and James River critical habitat units will impact national security. The activities conducted in these areas are in-water training on the Rappahannock, including small boat tactic, amphibious landings, and helicopter rope suspension techniques, and training activities on the lower James River, which include underwater diving and salvage operations, helicopter rope suspension techniques, small boat launch and recovery, high-speed boat tactics training, small boat defense drills, visit, board, search and seizure drills, integrated swimmer defense, submarine maintenance and system upgrades, sonar testing, towing of in-water devices, unmanned vehicle testing, and mine countermeasure testing.
The physical features of critical habitat in the areas requested for exclusion are salinity suitable for older juveniles, open passage for juveniles to access all parts of the estuary needed for development, open passage for adults traveling through the area to and from spawning areas, open passage for subadults traveling through the area, and soft substrate. The described training activities are not likely to adversely affect salinity, but may affect open passage and substrate ( e.g., from placement of structures, activities resulting in increased siltation or erosion of substrate). However, the training activities also may affect the species. For example, sonar testing and various in-water testing can produce sounds that harass sturgeon and disrupt normal behaviors such as foraging and staging. Small and large vessel operations can result in vessel strikes to sturgeon. Since the activities described by the Navy are also likely to impact the species ( e.g., juveniles, subadults, and adults), we expect consultations will be coextensive.
There are a number of potential beneficial impacts of designating critical habitat that extend beyond the conservation benefits to Atlantic sturgeon. For example, protecting essential features of sturgeon habitat, including preserving water quality and natural flow regimes, will benefit other organisms that are co-located in these areas. Benefits can result from additional protections in the form of project modifications or conservation measures due to section 7 consultations or, conversely, a benefit of excluding an area from designation could be avoiding the costs associated with those protections (78 FR 53058, August 28, 2013). Because it is often difficult to quantify the benefits of designating critical habitat, Executive Order (EO) 12866, Regulatory Planning and Review, provides guidance on assessing costs and benefits. The EO directs Federal agencies to assess all costs and benefits of available regulatory alternatives, and to select those approaches that maximize net benefits.
The designation of critical habitat will provide conservation benefits such as improved education and outreach by informing the public about areas and features important to the conservation of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs. As stated in the Background, specifying the geographic location of critical habitat facilitates implementation of section 7(a)(1) of the ESA by identifying areas where Federal agencies can focus their conservation programs and use their authorities to further the purposes of the ESA. Designating critical habitat can also help focus the efforts of other conservation partners ( e.g., State and local governments, individuals and nongovernmental organizations).

Discretionary Exclusion Analysis
Based on our consideration of impacts above, we are not excluding any particular areas from the critical habitat designation based on economic, national security, or other relevant impacts. Section 4(b)(2) of the ESA provides the Secretary with broad discretion to exclude any area from critical habitat if she determines that the benefits of such exclusion outweigh the benefits of specifying such area as part of the critical habitat, unless it is determined, based on the best scientific and commercial data available, that the failure to designate such area as critical habitat will result in the extinction of the species concerned. The agency has considerable discretion in evaluating the various impacts and determining how the impacts will be considered and weighed in deciding whether to exclude any particular area.
We have analyzed the economic, national security, and other relevant impacts of designating critical habitat. Although we have used the best available information and an approach designed to avoid underestimating economic impacts, many of the potential impacts are speculative and may not occur in the future. Our conservative identification of potential, incremental, economic impacts indicates that any such impacts, if they were to occur, would be very small. Any incremental economic impacts will consist solely of the administrative costs of consultation; no project modifications are projected to be required to address impacts solely to the proposed critical habitat. The Navy requested exclusion of two areas within the Gulf of Maine DPS proposed critical habitat units, three areas within the New York Bight critical habitat units, and two areas within the Chesapeake Bay critical habitat units. As noted above, no impacts to national security are expected as a consequence of the proposed critical habitat. Other relevant impacts include conservation benefits of the designation, both to the species and to society. The designation of critical habitat will provide conservation benefits such as improved education and outreach by informing the public about areas and features important to the conservation of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs. There are also a number of potential beneficial impacts of designating critical habitat that extend beyond the conservation benefits to Atlantic sturgeon. For example, protecting essential features of sturgeon habitat, including preserving water quality and natural flow regimes, will benefit other organisms that are co-located in these areas. While we cannot quantify nor monetize the benefits, we believe they are not negligible and would be an incremental benefit of this designation. Therefore, we have concluded that there is no basis to exclude any particular area from the proposed critical habitat units.

Activities That May Be Affected
Section 4(b)(8) of the ESA requires that any proposed or final regulation to designate critical habitat describe briefly and evaluate those activities that may adversely modify such habitat or that may be affected by such designation. A wide variety of activities may affect critical habitat and, when carried out, funded, or authorized by a Federal agency, will require an ESA section 7 consultation. Such activities (detailed in the economic analysis) include in-water construction, dredging, bridge, culvert, and road projects ( e.g., for restoration projects), hydropower (unknown capacity), utility lines, sand and gravel mining, and activities requiring National Pollutant Discharge Elimination System permits. Private entities may also be affected by these proposed critical habitat designations if a Federal permit is required, Federal funding is received, or the entity is involved in or receives benefits from a Federal project. These activities will need to be evaluated with respect to their potential to destroy or adversely modify critical habitat. Specifically, as discussed above, activities (dredging, mining, utility lines, in water construction, placement of dams and tidal turbines) may adversely modify the substrate essential feature by removing or altering the substrate. The open passage feature may also be adversely modified by the placement of structures such as dams and tidal turbines. The salinity feature may be adversely affected by activities that impact fresh water input, such as operation of water control structures and water withdrawals, and activities that impact water depth, such as dredging. The water quality feature may be adversely affected by land development, and commercial and recreational activities on rivers may adversely affect the water quality feature by contributing to the persistence of nutrient loading, resulting in decreased dissolved oxygen levels and increased water temperature, and by increasing sediment deposition, which reduces Atlantic sturgeon egg adherence on hard spawning substrate and reduces the interstitial spaces used by larvae for refuge from predators. Dredging to remove sediment build-up or to facilitate vessel traffic may remove or alter the hard substrate that is necessary for egg adherence and as refuge for larvae, and may change the water depth, resulting in shifts in the salt wedge within the estuary or changes to other characteristics of the water quality ( e.g., temperature, dissolved oxygen) necessary for the developing eggs, larvae, and juveniles. These activities would require ESA section 7 consultation when they are implemented, funded, or carried out by a federal agency.
Questions regarding whether specific activities will constitute destruction or adverse modification of critical habitat should be directed to NMFS (see ADDRESSES and FOR FURTHER INFORMATION CONTACT ).

Public Comments Solicited
We request that interested persons submit comments, information, and suggestions concerning this proposed rule during the comment period (see DATES ). We are soliciting comments or suggestions from the public, other concerned governments and agencies, the scientific community, industry, or any other interested party concerning this proposed rule, including any foreseeable economic, national security, or other relevant impact resulting from the proposed designations. You may submit your comments and materials concerning this proposal by any one of several methods (see ADDRESSES ). Copies of the proposed rule and supporting documentation can be found on the NMFS Greater Atlantic Region Web site at www.greateratlantic.fisheries.noaa.gov/. We will consider all comments pertaining to this designation received during the comment period in preparing the final rule. Accordingly, the final designation may differ from this proposal.

Information Quality Act and Peer Review
The data and analyses supporting this proposed action have undergone a pre-dissemination review and have been determined to be in compliance with applicable information quality guidelines implementing the Information Quality Act (IQA) (Section 515 of Pub. L. 106-554). On July 1, 1994, a joint USFWS/NMFS policy for peer review was issued stating that the Services would solicit independent peer review to ensure the best biological and commercial data is used in the development of rulemaking actions and draft recovery plans under the ESA (59 FR 34270). In addition, on December 16, 2004, the Office of Management and Budget (OMB) issued its Final Information Quality Bulletin for Peer Review (Bulletin). The Bulletin was published in the Federal Register on January 14, 2005 (70 FR 2664), and went into effect on June 16, 2005. The primary purpose of the Bulletin is to improve the quality and credibility of scientific information disseminated by the Federal government by requiring peer review of `influential scientific information” and “highly influential scientific information” prior to public dissemination. “Influential scientific information” is defined as “information the agency reasonably can determine will have or does have a clear and substantial impact on important public policies or private sector decisions.” The Bulletin provides agencies broad discretion in determining the appropriate process and level of peer review. Stricter standards were established for the peer review of “highly influential scientific assessments,” defined as information whose “dissemination could have a potential impact of more than $500 million in any one year on either the public or private sector or that the dissemination is novel, controversial, or precedent-setting, or has significant interagency interest.”
The Draft Biological Information and 4(b)(2) Source Document (NMFS, 2015) and the Draft Economic Impact Analysis (King and Associates Inc., 2014) supporting this proposed critical habitat rule are considered influential scientific information and subject to peer review. To satisfy our requirements under the OMB Bulletin, we obtained independent peer review of these draft documents, and incorporated the peer review comments prior to dissemination of this proposed rulemaking. For this action, compliance with the OMB Peer Review Bulletin satisfies any peer review requirements under the 1994 joint peer review policy. The Draft Biological Information and 4(b)(2) Source Document and the Draft Economic Impact Analysis prepared in support of this proposal are available on our Web site at www.greateratlantic.fisheries.noaa.gov. Comments received from peer reviewers on these documents will also be made available via our Web site at the time of publication of the proposed rule.

Classification

Takings (Executive Order 12630)
Under E.O. 12630, Federal agencies must consider the effects of their actions on constitutionally protected private property rights and avoid unnecessary takings of property. A taking of property includes actions that result in physical invasion or occupancy of private property, and regulations imposed on private property that substantially affect its value or use. In accordance with E.O. 12630, this proposed rule would not have significant takings implications. The designation of critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic sturgeon are not expected to impose additional burdens on land use or affect property values. Therefore, a takings implication assessment is not required.

Regulatory Planning and Review (Executive Order 12866)
This proposed rule has been determined to be significant for purposes of E.O. 12866. A draft economic report has been prepared to support an impacts analysis under section 4(b)(2) of the ESA.

Federalism (Executive Order 13132)
Pursuant to the Executive Order on Federalism, E.O. 13132, we determined that this proposed rule does not have significant Federalism effects and that a Federalism assessment is not required. However, in keeping with Department of Commerce policies and consistent with ESA regulations at 50 CFR 424.16(c)(1)(ii), we will request information for this proposed rule from state resource agencies in Maine, New Hampshire, Massachusetts, Connecticut, New York, New Jersey, Delaware, Maryland, and Virginia as well as appropriate authorities for the District of Columbia. The proposed designations may have some benefit to state and local resource agencies in that the proposed rule more clearly defines the physical and biological features essential to the conservation of the species and the areas on which those features are found.

Energy Supply, Distribution, and Use (Executive Order 13211)
Executive Order 13211 requires agencies to prepare Statements of Energy Effects when undertaking an action expected to lead to the promulgation of a final rule or regulation that is a significant regulatory action under E.O. 12866 and is likely to have a significant adverse effect on the supply, distribution, or use of energy. OMB Guidance on Implementing E.O. 13211 (July 13, 2001) states that significant adverse effects could include any of the following outcomes compared to a world without the regulatory action under consideration: (1) Reductions in crude oil supply in excess of 10,000 barrels per day; (2) reductions in fuel production in excess of 4,000 barrels per day; (3) reductions in coal production in excess of 5 million tons per year; (4) reductions in natural gas production in excess of 25 million mcf per year; (5) reductions in electricity production in excess of 1 billion kilowatt-hours per year or in excess of 500 megawatts of installed capacity; (6) increases in energy use required by the regulatory action that exceed any of the thresholds above; (7) increases in the cost of energy production in excess of one percent; (8) increases in the cost of energy distribution in excess of one percent; or (9) other similarly adverse outcomes. A regulatory action could also have significant adverse effects if it: (1) Adversely affects in a material way the productivity, competition, or prices in the energy sector; (2) adversely affects in a material way productivity, competition or prices within a region; (3) creates a serious inconsistency or otherwise interferes with an action taken or planned by another agency regarding energy; or (4) raises novel legal or policy issues adversely affecting the supply, distribution or use of energy arising out of legal mandates, the President's priorities, or the principles set forth in E.O. 12866 and 13211.
This rule, if finalized, will not have a significant adverse effect on the supply, distribution, or use of energy. Therefore, we have not prepared a Statement of Energy Effects.

Regulatory Flexibility Act (5 U.S.C. 601 et seq. )
We prepared an initial regulatory flexibility analysis (IRFA) pursuant to section 603 of the Regulatory Flexibility Act (RFA) (5 U.S.C. 601, et seq. ). The IRFA analyzes the impacts of this proposed rule, if enacted, on small entities. Specifically, the IRFA describes the economic impact on small entities in those areas where critical habitat is proposed, and is included as Appendix A of the Draft Biological Information and 4(b)(2) Source Document available at the location identified in the ADDRESSES section. A summary of the IRFA follows.
We determined that the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic sturgeon warranted listing under the Endangered Species Act (ESA) and published notice of that decision on February 6, 2012 (77 FR 5880). We are required to designate critical habitat for each of the DPSs of Atlantic sturgeon (16 U.S.C. 1533(a)(3)). The critical habitat provisions of the ESA are intended to promote recovery of the ESA-listed species by prohibiting federal agency actions from destroying or adversely modifying the physical or biological features that are essential to conservation of the listed entity.
The ESA section 7 consultation requirement for critical habitat does not apply to citizens engaged in activities on private land that do not involve a Federal agency. However, there may be an impact to private citizens and small entities that are engaged in activities that involve a Federal agency action. For example, small businesses involved in construction activities such as breakwater, dock, pier, and harbor construction may be impacted if a federal agency must issue a permit for the work to be conducted, will provide funds for the work, or will otherwise be involved in carrying out the work. Such involvement by a federal agency triggers the need for section 7 consultation.
We considered three alternatives: (1) No action, (2) designating some of the identified critical habitat areas, or (3) designating all critical habitat areas identified for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic sturgeon. Under the “no action” alternative, we would not designate critical habitat for the Gulf of Maine, New York Bight or Chesapeake Bay DPSs. By comparison, designating some of the identified critical habitat areas ( i.e., Alternative 2) could result in an increase in the number of section 7 consultations required to avoid adverse impacts relative to the “no action” alternative, while Alternative 3 would likely result in the greatest number of section 7 consultations relative to the other alternatives.
We have determined that the physical features forming the basis for our proposed critical habitat designations are essential to the conservation of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs. Therefore, we rejected the no action alternative and Alternative 2. We have analyzed the economic, national security, and other relevant impacts of designating all critical habitat identified for the DPSs. Our conservative identification of potential, incremental economic impacts indicates that any such impacts, if they were to occur, would be very small. Any incremental economic impacts will consist solely of the administrative costs of consultation; no project modifications are projected to be required to address impacts solely to the proposed critical habitat. No impacts to national security are expected as a consequence of the proposed critical habitat. Other relevant impacts include conservation benefits of the designation, both to the species and to society. While we cannot quantify or monetize the benefits, we believe that the benefits of this critical habitat designation would be incremental, and that they are not negligible.
The Small Business Administration has established numerical definitions of small businesses, or “size standards,” for all for-profit industries. Based on these size standards ( e.g., in millions of dollars or number of employees), King and Associates, Inc. (2014), concluded a high percent of business entities located in the counties that include one or more of the critical habitat units, an average of 99.8% across all units, are small businesses. However, data are not available to determine the location of these small business entities within each county in order to determine how many are located in or near areas proposed as critical habitat. Therefore, for purposes of projecting the impacts of administrative section 7 costs on small businesses in each critical habitat unit, King and Associates assumed that the percentage of private entities involved in those consultations that are small entities is the same as the percentage of businesses that are small entities in the counties that include critical habitat units.
The same approach that was used by King and Associates to estimate low, medium, and high overall ESA section 7 administrative costs was used as a basis for developing low, medium, and high estimates of section 7 impacts on small entities. Impacted small entities may include contractors involved in construction activities such as breakwater, dock, pier, bridge, and harbor construction, contractors involved in restoration activities such as culvert replacements, and marina owners who must maintain pier and dock structures. King and Associates concluded that costs to small entities associated with the designation range from about $16,500 to $47,250 annually in the Gulf of Maine DPS, about $30,000 to $96,000 annually in the New York Bight DPS, and about $11,000 to $34,000 annually in the Chesapeake Bay DPS (King and Associates, Inc., 2014). We found no data to suggest that the designation would place small entities at a competitive disadvantage compared to large entities.

Coastal Zone Management Act
Under section 307(c)(1)(A) of the Coastal Zone Management Act (CZMA) (16 U.S.C. 1456(c)(1)(A)) and its implementing regulations, each Federal activity within or outside the coastal zone that has reasonably foreseeable effects on any land or water use or natural resource of the coastal zone shall be carried out in a manner which is consistent to the maximum extent practicable with the enforceable policies of approved State coastal management programs. We have determined that any effects of this proposed designation of critical habitat on coastal uses and resources in Maine, New Hampshire, Massachusetts, Connecticut, New York, New Jersey, Delaware, Pennsylvania, Maryland, and Virginia are not reasonably foreseeable at this time. This proposed designation may trigger ESA section 7 obligations for federal agencies. These consultations will consider effects of Federal actions on coastal uses and resources to the extent they overlap with critical habitat. We considered the range of Federal actions that this designation may affect ( e.g., dredging, bridge construction/repair, water withdrawals) and which may affect coastal uses and resources in the affected States. However, we do not have sufficient information on the specifics of any future activities ( e.g., when, where and how they will be carried out) to characterize any of these as reasonable foreseeable. Therefore, because the effects are not reasonably foreseeable, we cannot make a determination as to whether the Federal activities will be consistent with any enforceable policies of approved State coastal management programs. Through the consultation process, we will receive information on proposed Federal actions and their effects on listed species and the designated critical habitat upon. We base any biological opinions on this information. It will then be up to the Federal action agencies to decide how to comply with the ESA in light of our biological opinion, as well as to ensure that their actions comply with the CZMA's Federal consistency requirement. At this time, we do not anticipate that this designation is likely to result in any additional management measures by other Federal agencies.

Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. )
This proposed rule does not contain any new or revised collection of information. This rule, if adopted, would not impose recordkeeping or reporting requirements on State or local governments, individuals, businesses, or organizations.

Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq. )
This proposed rule will not produce a Federal mandate. The designation of critical habitat does not impose a legally-binding duty on non-Federal government entities or private parties. The only regulatory effect is that Federal agencies must ensure that their actions do not destroy or adversely modify critical habitat under section 7 of the ESA. Non-Federal entities which receive Federal funding, assistance, permits or otherwise require approval or authorization from a Federal agency for an action may be indirectly impacted by the designation of critical habitat but, the Federal agency has the legally binding duty to avoid destruction or adverse modification of critical habitat.
We do not anticipate that this rule, if finalized, will significantly or uniquely affect small governments. Therefore, a Small Government Action Plan is not required.

Consultation and Coordination With Indian Tribal Governments (Executive Order 13175)
The longstanding and distinctive relationship between the Federal and tribal governments is defined by treaties, statutes, executive orders, judicial decisions, and agreements, which differentiate tribal governments from the other entities that deal with, or are affected by, the Federal Government. This relationship has given rise to a special Federal trust responsibility involving the legal responsibilities and obligations of the United States toward Indian Tribes and the application of fiduciary standards of due care with respect to Indian lands, tribal trust resources, and the exercise of tribal rights.
Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, outlines the responsibilities of the Federal Government in matters affecting tribal interests. If NMFS issues a regulation with tribal implications (defined as having a substantial direct effect 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) we must consult with those governments or the Federal Government must provide funds necessary to pay direct compliance costs incurred by tribal governments. The proposed critical habitat designations for Gulf of Maine, New York Bight, and Chesapeake Bay Atlantic sturgeon DPSs do not have tribal implications.

References Cited
A complete list of all references cited in this rulemaking can be found at www.greateratlantic.fisheries.noaa.gov, and is available upon request from the NMFS Greater Atlantic Region Fisheries Office in Gloucester, Massachusetts (see ADDRESSES ).

List of Subjects in 50 CFR Part 226
Endangered and threatened species.
Dated: May 24, 2016.
Samuel D. Rauch, III,

Deputy Assistant Administrator for Regulatory Programs, National Marine Fisheries Service.
For the reasons set out in the preamble, we propose to amend 50 CFR part 226 as follows:

PART 226—DESIGNATED CRITICAL HABITAT
1. The authority citation for part 226 continues to read as follows:

Authority:
16 U.S.C. 1533.
2. Add § 226.225 to read as follows:
§ 226.225
Critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments of Atlantic Sturgeon.
Critical habitat is designated for the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments (DPSs) of Atlantic sturgeon as described in paragraphs (a) through (c) of this section. The textual descriptions in paragraphs (c) through (f) of this section are the definitive source for determining the critical habitat boundaries.
(a) The physical features essential for the conservation of Atlantic sturgeon belonging to the Gulf of Maine, New York Bight, and Chesapeake Bay Distinct Population Segments are those habitat components that support successful reproduction and recruitment. These are:
(1) Hard bottom substrate ( e.g., rock, cobble, gravel, limestone, boulder, etc.) in low salinity waters ( i.e., 0.0-0.5 parts per thousand range) for settlement of fertilized eggs, refuge, growth, and development of early life stages;
(2) Aquatic habitat with a gradual downstream salinity gradient of 0.5-30 parts per thousand and soft substrate ( e.g., sand, mud) downstream of spawning sites for juvenile foraging and physiological development;
(3) Water of appropriate depth and absent physical barriers to passage ( e.g., locks, dams, reservoirs, gear, etc.) between the river mouth and spawning sites necessary to support:
(i) Unimpeded movement of adults to and from spawning sites;
(ii) Seasonal and physiologically dependent movement of juvenile Atlantic sturgeon to appropriate salinity zones within the river estuary; and
(iii) Staging, resting, or holding of subadults or spawning condition adults. Water depths in main river channels must also be deep enough ( e.g., ≥1.2 m) to ensure continuous flow in the main channel at all times when any sturgeon life stage would be in the river;
(4) Water, especially in the bottom meter of the water column, with the temperature, salinity, and oxygen values that, combined, support:
(i) Spawning;
(ii) Annual and interannual adult, subadult, larval, and juvenile survival; and
(iii) Larval, juvenile, and subadult growth, development, and recruitment ( e.g., 13 °C to 26 °C for spawning habitat and no more than 30 °C for juvenile rearing habitat, and 6 mg/L dissolved oxygen for juvenile rearing habitat).
(b) Critical habitat is designated for the following DPSs in the following states and counties:
DPS | State/district—counties
Gulf of Maine | ME—Androscoggin, Cumberland, Kennebec, Lincoln, Penobscot, Sagadahoc, Somerset, Waldo, York. NH—Rockingham, Stafford. MA—Essex.
New York Bight | CT—Fairfield, Hartford, Litchfield, Middlesex, New Haven, New London, Tolland. NJ—Bergen, Burlington, Camden, Cape May, Cumberland, Gloucester, Hudson, Mercer, Monmouth, Salem. NY—Albany, Bronx, Columbia, Dutchess, Greene, Kings, New York, Orange, Putnam, Queens, Rensselaer, Richmond, Rockland, Saratoga, Ulster, Westchester. DE—Kent, New Castle, Sussex. PA—Bucks, Delaware, Philadelphia.
Chesapeake Bay | D.C.—District of Columbia. MD—Charles, Montgomery, Prince George's, St. Mary's. VA—Arlington, Caroline, Charles City, Chesterfield, Dinwiddie, Essex, Fairfax, Gloucester, Hanover, Henrico, Isle of Wight, King George, James City, King and Queen, King William, Lancaster, Loudoun, Middlesex, New Kent, Northumberland, Prince George, Prince William, Richmond, Spotsylvania, Stafford, Surry, Westmoreland, York.
(c) Critical habitat boundaries for the Gulf of Maine DPS. Critical habitat for the Gulf of Maine DPS of Atlantic sturgeon is the waters of:
(1) Penobscot River main stem from the Milford Dam downstream to where the main stem river drainage discharges at its mouth into Penobscot Bay;
(2) Kennebec River main stem from the Ticonic Falls/Lockwood Dam downstream to where the main stem river discharges at its mouth into the Atlantic Ocean;
(3) Androscoggin River main stem from the Brunswick Dam downstream to where the main stem river drainage discharges into Merrymeeting Bay;
(4) Piscataqua River from its confluence with the Salmon Falls and Cocheco rivers downstream to where the main stem river discharges at its mouth into the Atlantic Ocean as well as the waters of the Cocheco River from its confluence with the Piscataqua River and upstream to the Cocheco Falls Dam, and waters of the Salmon Falls River from its confluence with the Piscataqua River and upstream to the Route 4 Dam; and,
(5) Merrimack River from the Essex Dam (also known as the Lawrence Dam) downstream to where the main stem river discharges at its mouth into the Atlantic Ocean.
(d) Critical Habitat Boundaries of the New York Bight DPS. Critical habitat for the New York Bight DPS of Atlantic sturgeon is the waters of:
(1) Connecticut River from the Holyoke Dam downstream to where the main stem river discharges at its mouth into Long Island Sound;
(2) Housatonic River from the Derby Dam downstream to where the main stem discharges at its mouth into Long Island Sound;
(3) Hudson River from the Troy Lock and Dam (also known as the Federal Dam) downstream to where the main stem river discharges at its mouth into New York City Harbor; and
(4) Delaware River at the crossing of the Trenton-Morrisville Route 1 Toll Bridge, downstream to where the main stem river discharges at its mouth into Delaware Bay.
(e) Critical Habitat Boundaries of the Chesapeake Bay DPS. Critical habitat for the Chesapeake Bay DPS of Atlantic sturgeon is the waters of:
(1) Susquehanna River from the Conowingo Dam downstream to where the main stem river discharges at its mouth into the Chesapeake Bay;
(2) Potomac River from the Little Falls Dam downstream to where the main stem river discharges at its mouth into the Chesapeake Bay;
(3) Rappahannock River from the U.S. Highway 1 Bridge, downstream to where the river discharges at its mouth into the Chesapeake Bay;
(4) York River from its confluence with the Mattaponi and Pamunkey rivers downstream to where the main stem river discharges at its mouth into the Chesapeake Bay as well as the waters of the Mattaponi River from its confluence with the York River and upstream to the Virginia State Route 360 Bridge of the Mattaponi River, and waters of the Pamunkey River from its confluence with the York River and upstream to the Virginia State Route 360 Bridge crossing of the Pamunkey River; and
(5) James River from Boshers Dam downstream to where the main stem river discharges at its mouth into the Chesapeake Bay at Hampton Roads.
(f) Sites owned or controlled by the Department of Defense. Critical habitat for the New York Bight and Chesapeake Bay DPSs of Atlantic sturgeon do not include the following areas owned or controlled by the Department of Defense, or designated for its use, in the States of New York and Virginia.
(1) The Department of the Army, U.S. Military Academy—West Point, NY;
(2) The Department of the Air Force, Joint Base Langley—Eustis, VA;
(3) The Department of the Navy, Marine Corps Base Quantico, VA;
(4) The Department of the Navy, Naval Weapons Station Yorktown, VA; and,
(5) The Department of the Navy, Naval Support Facility Dahlgren, VA.
(g) Maps of the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs follow:
81
107
Friday, June 3, 2016
Notices
DEPARTMENT OF AGRICULTURE
Forest Service
Sabine-Angelina Resource Advisory Committee

AGENCY:
Forest Service, USDA.

ACTION:
Notice of meeting.

SUMMARY:
The Sabine-Angelina Resource Advisory Committee (RAC) will meet in Hemphill, Texas. The committee is authorized under the Secure Rural Schools and Community Self-Determination Act (the Act) and operates in compliance with the Federal Advisory Committee Act. The purpose of the committee is to improve collaborative relationships and to provide advice and recommendations to the Forest Service concerning projects and funding consistent with Title II of the Act. RAC information can be found at the following Web site: http://cloudapps-usda-gov.force.com/FSSRS/RAC_Page?id=001t0000002JcvCAAS.

DATES:
The meeting will be held on Thursday, July 14, 2016, at 5:00 p.m. All RAC meetings are subject to cancellation. For status of meeting prior to attendance, please contact the person listed under FOR FURTHER INFORMATION CONTACT .

ADDRESSES:
The meeting will be held at Sabine Ranger District, 5050 State Highway 21 East, Hemphill, Texas.
Written comments may be submitted as described under SUPPLEMENTARY INFORMATION . All comments, including names and addresses when provided, are placed in the record and are available for public inspection and copying. The public may inspect comments received at Sabine Ranger District. Please call ahead to facilitate entry into the building.

FOR FURTHER INFORMATION CONTACT:
Becky Nix, RAC Coordinator, by phone at 409-625-1940 or via email at bnix@fs.fed.us.
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8:00 a.m. and 8:00 p.m., Eastern Standard Time, Monday through Friday.

SUPPLEMENTARY INFORMATION:
The purpose of the meeting is to:
1. Introduce new members and provide them with materials to assist them in their transition into the RAC; and
2. Determine the time to present projects for approval.
The meeting is open to the public. The agenda will include time for people to make oral statements of three minutes or less. Individuals wishing to make an oral statement should request in writing by Friday, July 8, 2016, to be scheduled on the agenda. Anyone who would like to bring related matters to the attention of the committee may file written statements with the committee staff before or after the meeting. Written comments and requests for time for oral comments must be sent to Becky Nix, RAC Coordinator, Sabine-Angelina Resource Advisory Committee, 5050 State Highway 21 E, Hemphill, Texas 75948; by email to bnix@fs.fed.us, or via facsimile to 409-625-1953.
Meeting Accommodations: If you are a person requiring reasonable accommodation, please make requests in advance for sign language interpreting, assistive listening devices, or other reasonable accommodation. For access to the facility or proceedings, please contact the person listed in the section titled FOR FURTHER INFORMATION CONTACT . All reasonable accommodation requests are managed on a case by case basis.
Dated: May 25, 2016.
Kimpton M. Cooper,

Designated Federal Officer, Sabine-Angelina RAC.
DEPARTMENT OF COMMERCE
National Institute of Standards and Technology
Open Meeting of the Commission on Enhancing National Cybersecurity

AGENCY:
National Institute of Standards and Technology, Commerce.

ACTION:
Notice.

SUMMARY:
The Commission on Enhancing National Cybersecurity will meet Tuesday, June 21, 2016, from 8:30 a.m. until 5:00 p.m. Pacific Time at the University of California, Berkeley in the Chevron Auditorium at the International House located at 2299 Piedmont Ave, Berkeley CA 94720. The primary purpose of the meeting is to discuss the opportunities for and challenges to innovation and collaboration to strengthen cybersecurity in the digital economy. The meeting will support detailed recommendations to strengthen cybersecurity in both the public and private sectors while protecting privacy, ensuring public safety and economic and national security, fostering discovery and development of new technical solutions, and bolstering partnerships between Federal, State, local, tribal and territorial governments and the private sector in the development, promotion, and use of cybersecurity technologies, policies, and best practices. All sessions will be open to the public.

DATES:
The meeting will be held on Tuesday, June 21, 2016, from 8:30 a.m. until 5:00 p.m. Pacific Time.

ADDRESSES:
The meeting will be held at the University of California, Berkeley in the Chevron Auditorium at the International House located at 2299 Piedmont Ave, Berkeley CA 94720. The meeting is open to the public and interested parties are requested to contact Sara Kerman at the contact information indicated in the FOR FURTHER INFORMATION CONTACT section of this notice in advance of the meeting for building entrance requirements.

FOR FURTHER INFORMATION CONTACT:
Sara Kerman, Information Technology Laboratory, National Institute of Standards and Technology, 100 Bureau Drive, Stop 2000, Gaithersburg, MD 20899-8900, telephone: 301-975-4634, or by email at: eo-commission@nist.gov. Please use subject line “ Open Meeting of the Commission on Enhancing National Cybersecurity—CA”.

SUPPLEMENTARY INFORMATION:
Pursuant to the Federal Advisory Committee Act, as amended, 5 U.S.C. App., notice is hereby given that the Commission on Enhancing National Cybersecurity (“the Commission”) will meet Tuesday, June 21, 2016, from 8:30 a.m. until 5:00 p.m. Pacific Time. All sessions will be open to the public. The Commission is authorized by Executive Order 13718, Commission on Enhancing National Cybersecurity. ^1 The Commission was established by the President and will make detailed recommendations to strengthen cybersecurity in both the public and private sectors while protecting privacy, ensuring public safety and economic and national security, fostering discovery and development of new technical solutions, and bolstering partnerships between Federal, State, local, tribal and territorial governments and the private sector in the development, promotion, and use of cybersecurity technologies, policies, and best practices.
^1 https://www.federalregister.gov/articles/2016/02/12/2016-03038/commission-on-enhancing-national-cybersecurity.
The agenda is expected to include the following items:
—Introductions
—Panel discussions on addressing cybersecurity challenges to the digital economy
—Panel discussions on innovating and collaborating to secure the digital economy
—Conclusion
Note that agenda items may change without notice. The final agenda will be posted on http://www.nist.gov/cybercommission. Seating will be available for the public and media. No registration is required to attend this meeting.
Public Participation: The Commission agenda will include a period of time, not to exceed fifteen minutes, for oral comments from the public on Tuesday, June 21, 2016, from 4:45 p.m. until 5:00 p.m. Pacific Time. Speakers will be selected on a first-come, first-served basis. Each speaker will be limited to five minutes. Questions from the public will not be considered during this period. Members of the public who are interested in speaking are requested to contact Sara Kerman at the contact information indicated in the FOR FURTHER INFORMATION CONTACT section of this notice.
Speakers who wish to expand upon their oral statements, those who had wished to speak but could not be accommodated on the agenda, and those who were unable to attend in person are invited to submit written statements. In addition, written statements are invited and may be submitted to the Commission at any time. All written statements should be directed to the Commission Executive Director, Information Technology Laboratory, 100 Bureau Drive, Stop 8900, National Institute of Standards and Technology, Gaithersburg, MD 20899-8900.
Kent Rochford,

Associate Director for Laboratory Programs.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
RIN 0648-XE607
International Trade Data System Test Concerning the Electronic Submission of Certain Data Required for Exports

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

ACTION:
Notice; request for comments.

SUMMARY:
NMFS announces, in consultation with U.S. Customs and Border Protection (CBP), a test of the International Trade Data System (ITDS) involving the electronic submission of forms and/or data, related to exportation of fish products regulated by NMFS, using the export Partner Government Agency (PGA) data set of the Automated Export System (AES) Trade Interface Requirements, AES Direct via the Automated Commercial Environment (ACE) Secure Web Portal (Portal) and the Document Image System (DIS). CBP and NMFS have developed a plan to test and assess the electronic transmission of export and re-export data for tunas, swordfish and toothfish.
The test will involve using the above referenced methods to transmit the data required for processing exports or re-exports of tunas, swordfish and toothfish. Under this test, data may be submitted for the covered fish products exported from any operational port.

DATES:
The test will commence after June 1, 2016, and will continue until concluded by publication of a notice in the Federal Register ending the test. Participants should consult the following Web site to determine which ports are operational for the test and the date that they become operational: https://www.cbp.gov/trade/ace/features (see the PGA Integration tab). Comments on the submission and processing of export data will be accepted throughout the duration of the test.

ADDRESSES:
To submit comments concerning this test program, send an email to Josephine Baiamonte ( Josephine.Baiamonte@dhs.gov ), Director, Business Transformation, ACE Business Office (ABO), Office of International Trade. In the subject line of an email, please use, “ Comment on NMFS Export Test FRN”.
Any party seeking to participate in this test should contact their client representative. Interested parties without an assigned client representative should submit an email to Steven Zaccaro at steven.j.zaccaro@cbp.dhs.gov with the subject heading “ NMFS Export FRN-Request to Participate”.

FOR FURTHER INFORMATION CONTACT:
For technical questions related to the Automated Commercial Environment (ACE) or AES transmissions, contact your assigned client representative. Interested parties without an assigned client representative should direct their questions to Steven Zaccaro at steven.j.zaccaro@cbp.dhs.gov. For PGA reporting related questions, contact Emi Wallace (CBP) at emi.r.wallace@cbp.dhs.gov and for NMFS program related questions, contact Dale Jones (NMFS) at dale.jones@noaa.gov.

SUPPLEMENTARY INFORMATION:

Background

I. The Automated Commercial Environment
ACE is an automated and electronic system for commercial trade processing, which is intended to streamline business processes, facilitate growth in trade, ensure cargo security, and foster participation in global commerce, while ensuring compliance with U.S. laws and regulations and reducing costs for CBP and all of its communities of interest. The ability to meet these objectives depends on successfully modernizing CBP's business functions and the information technology that supports those functions.
CBP's modernization efforts are accomplished through phased releases of ACE component functionality designed to replace a specific function of the legacy Automated Commercial System (ACS) function. Each release will begin with a test and will end with mandatory use of the new ACE feature, thus retiring the legacy ACS function. Each release builds on previous releases and sets the foundation for subsequent releases. AES allows participants to electronically file required export data with CBP in ACE.

II. International Trade Data System
This test is in furtherance of the ITDS, which is statutorily authorized by section 405 of the Security and Accountability for Every (SAFE) Port Act of 2006, Public Law 109-347. The purpose of ITDS, as defined by section 4 of the SAFE Port Act of 2006, is to eliminate redundant information filing requirements, efficiently regulate the flow of commerce, and effectively enforce laws and regulations relating to international trade, by establishing a single portal system, operated by CBP, for the collection and distribution of standard electronic import and export data required by all participating Federal agencies.

III. AES, the ACE Secure Web Data Portal and the Document Image System
AES is the electronic method for the U.S. Principal Party in Interest (USPPI) or their authorized agent to file export commodity and transportation information, known as Electronic Export Information (EEI), directly with CBP and the Census Bureau. EEI is the electronic equivalent to the Shipper's Export Declaration (SED), a paper form previously used by exporters to report export information. The purpose of AES is to be the central point through which CBP collects and maintains export data and related records to facilitate CBP's law enforcement and border security missions. CBP uses EEI to further its mission of ensuring the safety and security of cargo and preventing smuggling, expediting legitimate international trade and enforcing export and other applicable U.S. laws. The Census Bureau uses EEI to compile and publish export trade statistics.
On April 5, 2014, AES was re-engineered and incorporated into ACE. General information and a list of AES certified software vendors is available on the following Web site: http://www.cbp.gov/trade/aes. That Web site also has information regarding AES Trade Interface Requirements (AESTIR) and the American National Standards Institute standard known as ANSI X.12, which together contain the formatting requirements for the electronic transmission of commodity and transportation export data to CBP via AES.
AES offers several options for transmitting export commodity and transportation data, which includes the choice of using software developed by the user, software purchased from a vendor, a Value Added Network (VAN) electronic mailbox, the facilities of a port authority or service center, or AESDirect, a free internet application supported by the Census Bureau. AESDirect came on-line in October 1999 and allowed USPPIs or their authorized agents to file EEI free of charge using a variety of electronic transmission methods, the most popular of which is a web-based portal through which users may file any required EEI. AESDirect also provided USPPIs or their authorized agents with access to export reports that compiled the data from EEI filings associated with a user account.
In the fall of 2015, CBP announced the establishment of the ACE Exporter Account Portal enabling USPPIs or their authorized agents to transmit EEI by selecting the “Submit AESDirect Filings” link in the exporter view (see 80 FR 63817, October 21, 2015). Selecting this link allows USPPIs or their authorized agents to gain access to the AESDirect portal in ACE that will allow them to file their required EEI. ACE AESDirect has replaced the legacy AESDirect operated by the Census Bureau and provides online internet filing and upload capabilities to facilitate the transmission of EEI.
In addition, test participants may transmit required PGA forms using the DIS. For information regarding the use of DIS, and for a list of NMFS forms and documents which may be transmitted to ACE using DIS, please see http://www.cbp.gov/trade/ace/features (see the PGA Integration tab).
At this time, ACE is prepared to accept certain PGA data elements for NMFS regulated fish products exported or re-exported from ports included in the test. The PGA data elements comprising the test are generally those found in the current paper forms (Bluefin Tuna Catch Document, Swordfish Statistical Document, Bigeye Statistical Document, Dissostichus Catch Document, and the associated re-export certificates, if any), which are currently filed via fax, email, and/or paper communications directly with NMFS. These data elements are set forth in the AESTIR (see https://www.cbp.gov/trade/aes ).
Upon commencement of this test, operational ports will begin accepting the transmission of this data and DIS documents and forms. A list of those ports and the date they become operational is provided on the following Web site: https://www.cbp.gov/trade/ace/features (see the PGA Integration tab). Test participants and interested parties should consult the above-referenced Web site for changes/additions to the list of ports where NMFS data and DIS forms and documents may be sent.

IV. The National Marine Fisheries Service Test
This ITDS test is in furtherance of key CBP ITDS initiatives as provided in the SAFE Port Act of 2006. The goal is to establish ACE as the “single window” for the Government and trade community by automating and enhancing the interaction between international trade partners, CBP, and PGAs by facilitating electronic collection, processing, sharing, and review of trade data and documents required by Federal agencies during the cargo import and export process. Processing trade data through ITDS and ACE will significantly increase efficiency and reduce costs over the manual, paper-based interactions that are currently in place. The transmission of this data will improve communication between NMFS and exporters, and will allow test participants to submit the required data once rather than submitting data separately to CBP and NMFS, resulting in quicker processing. During this test, participants will collaborate with CBP and NMFS to examine the effectiveness of the “single window” capability.
Currently, NMFS programmatic requirements for exports are separated into two different programs: The Highly Migratory Species (HMS) Program which includes various tunas and swordfish, and the Antarctic Marine Living Resources (AMLR) program which covers fresh and frozen toothfish ( Dissostichus species). Under this test, NMFS required data will be transmitted electronically through ACE for any merchandise or combination thereof covered by any of these programs.
For approved participants, the test may include all modes of transport at the selected port(s), and all commodities regulated under the two NMFS export monitoring programs when exported at one of the selected ports. The export declaration process for NMFS will require the submission of specifically designated data/information. Both the transmission of the required data for NMFS and DIS will be utilized to collect the specified information that is required by NMFS.
The data will be transmitted in ACE through the use of AES at the time of the filing in addition to the CBP required export data. Scanned copies of specific documents required will be submitted at the time of filing to the CBP DIS, either through uploading the file copies to the AES system or by sending them to the DIS as email attachments.
Examples of the kind of data that will be transmitted as part of this test are: the exporter's permit number and a document number for the catch certificate or re-export certificate. Examples of the types of scanned images that will be submitted to the DIS are: the international statistical documents pertaining to the harvest, re-export documents for product imported and re-exported from another country before shipment to the United States, or other specific and required catch/harvest documentation pertaining to the product being exported. Note that in cases where an electronic bluefin tuna catch document (eBCD) has been created in the centralized system implemented by the International Commission for the Conservation of Atlantic Tunas, a reduced data set consisting of the eBCD number and the exporter permit number would suffice as an export filing, without need for any forms submitted via DIS.
For information regarding fish products regulated by NMFS and data, information, forms and documents required by NMFS, see the implementation guidelines for the NMFS at: https://www.cbp.gov/trade/aes.

V. Test Participation Criteria and Participation Procedure
Any party seeking to participate in this test must provide CBP, in their request to participate, their filer code and the port(s) at which they are interested in filing the appropriate PGA data set and DIS information. Requests to participate in this test will be accepted throughout the duration of the test. To be eligible to apply for this test, the applicant must be a self-filing exporter who has the ability to file AES export declarations or a broker who has the ability to file AES export declarations; and the applicant files declarations for NMFS commodities that are the subject of this test. All test participants are required to use a software program that has completed ACE certification testing for export data. At this time, data and DIS submissions may be submitted for exports filed at any operational port. Test participants should contact their client representative regarding export declarations eligible for the test and operational ports (see ADDRESSES ). A current listing of the participating ports and the date each port becomes operational for the test may be found on the designated Web site (see DATES ).

VI. Anticipated Process Changes
The current paper process for reporting exports under the NMFS Highly Migratory Species (HMS) and the Antarctic Marine Living Resources (AMLR) Programs will be replaced by the submittal of data and scanned document images through a combination of AESTIR data transmission and DIS. A proposed rule to address this planned transition was published on December 29, 2015 (80 FR 81251). This test covers communication and coordination among the agencies and the filers for the exportation of these fisheries products. The agencies will also be testing new operational processes in real time with actual ACE filings in the production environment that include test messages to communicate errors in filing and release status updates to the port and to the filer.

VII. Confidentiality
All data submitted and entered into ACE is subject to the Trade Secrets Act (18 U.S.C. 1905) and is considered confidential, except to the extent as otherwise provided by law. As stated in previous notices, participation in this or any of the previous ACE tests is not confidential and upon a written Freedom of Information Act (FOIA) request, a name(s) of an approved participant(s) will be disclosed by CBP in accordance with 5 U.S.C. 552.
Dated: May 27, 2016.
Jeffrey Weir,

Acting Director, Office for International Affairs and Seafood Inspection, National Marine Fisheries Service.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
RIN 0648-XE665
New England Fishery Management Council; Public Meeting

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

ACTION:
Notice of public meeting.

SUMMARY:
The New England Fishery Management Council (Council, NEFMC) will hold a three-day meeting to consider actions affecting New England fisheries in the exclusive economic zone (EEZ).

DATES:
The meeting will be held on Tuesday, Wednesday and Thursday, June 21, 22, and 23, 2016. It will start at 9 a.m. on June 21, 8:30 a.m. on June 22, and at 8 a.m. on June 23.

ADDRESSES:
The meeting will be held at the Holiday Inn by the Bay, 88 Spring Street, Portland, ME 04101; telephone: (800) 345-5050; or online at http://www.innbythebay.com/.
Council address: New England Fishery Management Council, 50 Water Street, Mill 2, Newburyport, MA 01950; telephone: (978) 465-0492.

FOR FURTHER INFORMATION CONTACT:
Thomas A. Nies, Executive Director, New England Fishery Management Council; telephone: (978) 465-0492, ext. 113.

SUPPLEMENTARY INFORMATION:

Agenda

Tuesday, June 21, 2016
After introductions and any announcements, the Council meeting will open with brief reports from the NEFMC Chairman and Executive Director, the NOAA Regional Administrator for the Greater Atlantic Region (GAR), Northeast Fisheries Science Center and Mid-Atlantic Fishery Management Council liaisons, NOAA General Counsel and Office of Law Enforcement representatives, and staff from the Atlantic States Marine Fisheries Commission and the U.S Coast Guard. Following these reports, the Enforcement/VMS Committee will review feedback from other species committees on the Office of Law Enforcement's priorities, as well as recommendations on other issues. A public comment period is then scheduled during which any member of the public may bring issues forward that relate to Council business but are not included on the published agenda for this meeting. Next, BOEM will update the Council on the status of offshore wind leasing in the Atlantic and discuss a request for comments on the site assessment and site characterization activities proposed off NY. After a lunchbreak, the NEFMC's Small Mesh Multispecies will review a progress report on the small-mesh multispecies (whiting/hake) fishery fleet history to develop limited access alternatives for Amendment 22, and reconsider proceeding with development of this action. Next, the Northeast Fisheries Science Center will provide a presentation on its Draft Climate Regional Action Plan. Under the Scientific and Statistical Committee report the Council will receive an update on SSC discussions about improving groundfish catch advice, provide its comments on the Risk Policy Working Group's “roadmap,” its comments on the five-year review of the scallop limited access general category ITQ program, and comments on the Draft Northeast Regional Climate Science Action Plan. Before adjourning for the day the Council will develop NEFMC comments on this plan.

Wednesday, June 22, 2016
The second day of the meeting will begin with a review of NOAA Fisheries' proposed rule for Atlantic sturgeon critical habitat. During this morning session, the Scallop Committee will discuss initiating Framework Adjustment 28—fishery specifications for 2017-18, and discuss management alternatives that may be considered in the action. These will include measures to: (1) Restrict the possession of shell stock inshore of the days-at-sea demarcation line north of 42°20′ N; (2) modify the process for setting scallop fishery annual catch limits; (3) modify scallop access areas consistent with potential changes to habitat and groundfish mortality closed areas; and (4) modify gear to further protect small scallops. The committee also will ask for approval of priorities for the 2017-18 research set-aside program (RSA). The Council may also discuss modifying its Scallop RSA policy. The Groundfish Committee will then review a progress report on a draft white paper about monitoring strategies for the commercial groundfish fishery. The committee will ask the Council to initiate Framework Adjustment 56, an action to set specifications for the US/CA stocks and witch flounder for fishing years 2017-18, modify the process used to set recreational management measures, establish a sub-annual catch limit for northern windowpane flounder in the scallop fishery, allocate northern windowpane flounder to groundfish sectors, modify the groundfish monitoring program, and possibly other measures. The committee will ask for approval of the range of alternatives to consider in a framework adjustment that would revise the Georges Bank haddock catch cap for the herring fishery and associated accountability measures. After lunch the Council will continue with the groundfish report and complete the discussion of the Georges Bank haddock catch cap in the Atlantic herring fishery. Last, the Atlantic Herring Committee will review outcomes of a recent workshop on an Atlantic herring acceptable biological catch control rule management strategy evaluation (MSE), and approve fishery objectives, performance metrics and features of control rules to be evaluated in the MSE.

Thursday, June 23, 2016
The final meeting day will begin with the Omnibus Industry-Funded Monitoring Amendment. The Council intends to select preferred alternatives for monitoring coverage targets in the Atlantic herring fishery and approve the draft Environmental Assessment for public comment. The Council chair will then give an update on the recent Trawl Survey Advisory Panel meeting. The Council will review an update to NOAA's Catch Share Guidance document and review/approve any new NEFMC comments on the revised draft, if necessary. The Council will discuss and approve comments on the Northeast Regional Planning Body's draft Northeast Regional Ocean Plan. Lastly, the Risk Policy Working Group will review final guidance on implementation of the NEFMC's approved risk policy. The Council will adjourn after it addresses any other outstanding business during the afternoon of June 23rd.
Although other non-emergency issues not contained in this agenda may come before this Council for discussion, those issues may not be the subject of formal action during this meeting. Council action will be restricted to those issues specifically listed in this notice and any issues arising after publication of this notice that require emergency action under section 305(c) of the Magnuson-Stevens Act, provided that the public has been notified of the Council's intent to take final action to address the emergency.

Special Accommodations
This meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Thomas A. Nies (see ADDRESSES ) at least 5 days prior to the meeting date.
Dated: May 31, 2016.
Tracey L. Thompson,

Acting Deputy Director, Office of Sustainable Fisheries, National Marine Fisheries Service.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
Notice of Sites Added to the Inventory of Possible Areas for Designation as New National Marine Sanctuaries

AGENCY:
Office of National Marine Sanctuaries (ONMS), National Ocean Service (NOS), National Oceanic and Atmospheric Administration (NOAA), Department of Commerce (DOC).

ACTION:
Notice of sites added to the Sanctuary Nomination Process inventory of possible areas for designation as new national marine sanctuaries.

SUMMARY:
On June 13, 2014, NOAA published a final rule re-establishing the Sanctuary Nomination Process (SNP) which allows communities to submit nominations to NOAA for consideration as new national marine sanctuaries. The rule included the final review process, national significance criteria, and management considerations that NOAA uses to evaluate community nominations for inclusion in the inventory of areas that could be considered for designation as national marine sanctuaries. The rule also states that NOAA will publish a Federal Register notice when areas have been added to the inventory. This notice announces that NOAA has added four sanctuary nominations to the SNP inventory between June 2014 and April 2016.

FOR FURTHER INFORMATION CONTACT:
Annie Sawabini, NOAA Office of National Marine Sanctuaries, 1305 East West Highway, Silver Spring MD 20910.

SUPPLEMENTARY INFORMATION:

I. Background
The National Marine Sanctuaries Act (NMSA) (16 U.S.C. 1431 et seq. ) authorizes the Secretary of Commerce to identify and designate as national marine sanctuaries areas of the marine environment, including the Great Lakes, which are of special national significance; to manage these areas as the National Marine Sanctuary System; and to provide for the comprehensive and coordinated conservation and management of these areas and the activities affecting them in a manner which complements existing regulatory authorities. Section 303 of the NMSA provides national marine sanctuary designation standards and factors required in determining whether an area qualifies for consideration as a potential national marine sanctuary, and section 304 establishes procedures for national marine sanctuary designation and implementation. Regulations implementing the NMSA and each national marine sanctuary are codified in Part 922 of Title 15 of the Code of Federal Regulations.
On June 28, 2013, NOAA issued a proposed rule to re-establish the Sanctuary Nomination Process (SNP) and requested public comment on the proposed amendments to ONMS regulations (78 FR 38848). On June 13, 2014, NOAA issued a final rule addressing the nearly 18,000 comments NOAA received on the proposed rule, and finalized the national significance criteria, management considerations, and process to nominate areas of the marine and Great Lakes environments for potential addition to the inventory of areas that may be considered for future designation as a national marine sanctuary (79 FR 33851).
As described in that rule, the final step of the SNP is the addition of specific areas to the inventory. Nominations that the ONMS Director deems to have successfully completed the reviews for sufficiency, national significance, and management considerations are added to an inventory of areas NOAA could consider for national marine sanctuary designation. For these nominations, NOAA sends a letter of notification to the nominator, and publishes a Federal Register notice when areas have been added to the inventory on a periodic basis. The inventory and notification letters are also posted on the ONMS Web site ( http://www.nominate.noaa.gov ). If NOAA takes no designation action on a nomination in the inventory, the nomination expires after five years from the time it is accepted to the inventory.
NOAA is not designating any new national marine sanctuaries with this action. Any designations resulting from the nomination process would be conducted by NOAA as a separate process as directed by the NMSA, Administrative Procedure Act (5 U.S.C. Subchapter II), and National Environmental Policy Act (42 U.S.C. § 4321 et seq. ). NOAA follows all standards and requirements identified in the NMSA when it considers a nomination for designation.

II. Sanctuary Nominations Added to the Inventory
The following nominations have successfully completed the SNP review process and have been added to the inventory of possible areas for designation as new national marine sanctuaries:

1. Mallows Bay-Potomac River National Marine Sanctuary Nomination
The nomination for NOAA to consider the Mallows Bay area of the Potomac River as a new national marine sanctuary was submitted on September 16, 2014. The nomination was added to the inventory of successful nominations on January 12, 2015.
The Mallows Bay area of the tidal Potomac River nominated as a national marine sanctuary is an area 40 miles south of Washington, DC off the Nanjemoy Peninsula of Charles County, MD. The nominated area includes approximately 14 square miles of Maryland state waters. The designation of a national marine sanctuary would focus on conserving the collection of maritime heritage resources (shipwrecks) in the area as well as expand the opportunities for public access, recreation, tourism, research, and education. More information can be found in the nomination: http://www.nominate.noaa.gov/nominations/nomination_maryland_mallows_bay_potomac_river.pdf.

2. Lake Michigan—Wisconsin National Marine Sanctuary Nomination
The nomination for NOAA to consider a Lake Michigan-Wisconsin national marine sanctuary was submitted on December 2, 2014. The nomination was added to the inventory of successful nominations on February 5, 2015.
The area nominated as a national marine sanctuary is a region that includes 875 square miles of Wisconsin's Lake Michigan waters and bottomlands adjacent to Manitowoc, Sheboygan, and Ozaukee counties and the cities of Port Washington, Sheboygan, Manitowoc, and Two Rivers. It includes 80 miles of shoreline and extends 9 to 14 miles from the shoreline. The area contains an extraordinary collection of submerged maritime heritage resources (shipwrecks) as demonstrated by the listing of 15 shipwrecks on the National Register of Historic Places. The area includes 39 known shipwrecks, 123 reported vessel losses, numerous other historic maritime-related features, and is adjacent to communities that have embraced their centuries-long relationship with Lake Michigan. More information can be found in the nomination: http://www.nominate.noaa.gov/nominations/nomination_lake_michigan_wisconsin.pdf.

3. Chumash Heritage National Marine Sanctuary Nomination
The nomination for NOAA to consider the Chumash Heritage area off the central coast of California as a national marine sanctuary was submitted on July 17, 2015. The nomination was added to the inventory of successful nominations on October 5, 2015.
The area proposed for the national marine sanctuary stretches from the southern border of Monterey Bay National Marine Sanctuary in Cambria along approximately 140 miles of coastline to Gaviota Creek in Santa Barbara. The area includes both state waters of California and federal waters. The proposed boundary extends westward 60 to 80 miles to include the submerged Santa Lucia Bank, Arguello Canyon and Rodriguez Seamount. The area is characterized by converging oceanographic currents and persistent upwelling, creating highly productive conditions centered at the prominent ecological transition zone Point Conception. These combined features—high productivity and the ecological transition zone—mean many invertebrate, fish and algal species begin or end their natural ranges within the proposed sanctuary, thereby creating high biodiversity. The area's productive ecosystem also supports high densities of numerous marine mammal and bird species. Numerous cultural heritage resources are found throughout the proposed area, including more than 40 shipwrecks, as well as areas culturally significant to Native Americans, such as Point Conception, referred to as the Western Gate by the Chumash, and possibly submerged ancient villages on the continental shelf. More information can be found in the nomination: http://www.nominate.noaa.gov/nominations/nomination_chumash_heritage_071715.pdf.

4. Lake Erie Quadrangle National Marine Sanctuary Nomination
The nomination for NOAA to consider the Pennsylvania waters in Lake Erie for an area known as the Lake Erie Quadrangle as a national marine sanctuary was submitted on December 31, 2015. The nomination was added to the inventory of successful nominations on February 22, 2016.
The nominated site encompasses approximately 759 square miles of Pennsylvania state waters, and includes an estimated 196 shipwrecks. In addition to the historical significance of the shipwrecks themselves, this area has other nationally significant qualities. The area played an integral role in our nation's history during the War of 1812. The port of Erie, PA was a key shipbuilding port from the late 1700s through the early 20th century. It was the location where Commodore Oliver Hazard Perry's fleet was constructed for one of the most significant battles of the 1812 war. In addition, prior to the Civil War, Pennsylvania's Lake Erie waters housed the nation's largest fleet of steamboats, and were a major hub on the Underground Railroad. More information can be found in the nomination: http://www.nominate.noaa.gov/nominations/lake-erie-proposal.pdf.

III. Active National Marine Sanctuary Designations
While the addition of a nomination to the inventory does not designate any new national marine sanctuaries, two (2) of the successful nominations in the list above have subsequently been selected for designation by NOAA, and have begun the designation processes as outlined in the NMSA including NEPA analysis. The notice of intent to conduct scoping and begin the designation process for the Proposed Mallows Bay-Potomac River National Marine Sanctuary was announced in the Federal Register on October 7, 2015 (80 FR 60634). The notice of intent to conduct scoping and begin the designation process for the Proposed Wisconsin-Lake Michigan National Marine Sanctuary was announced in the Federal Register on October 7, 2015 (80 FR 60631).

IV. Classification

A. National Environmental Policy Act
NOAA has concluded that this action will not have a significant effect, individually or cumulatively, on the human environment, because this action is not creating or designating any new national marine sanctuaries. Therefore, this action is categorically excluded from the requirement to prepare an environmental assessment or environmental impact statement in accordance with Section 6.03c.3(i) of NOAA Administrative Order 216-6. Specifically, this action is a notice of an administrative and legal nature. Should NOAA decide to designate a national marine sanctuary, and in cases where NOAA has decided to begin active designation as a national marine sanctuary, each individual national marine sanctuary designation will be subject to case-by-case analysis, as required under NEPA and as outlined in section 304(a)(2)(A) of the NMSA.

B. Paperwork Reduction Act
Notwithstanding any other provisions 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 Paperwork Reduction Act (PRA), 44 U.S.C. 3501 et seq., unless that collection of information displays a currently valid Office of Management and Budget (OMB) control number. Nominations for national marine sanctuaries discussed in this notice involve a collection-of-information requirement subject to the requirements of the PRA. OMB has approved this collection-of-information requirement under OMB control number 0648-0682.

Authority:
16 U.S.C. 1431 et seq.
Dated: May 23, 2016.
John Armor,

Acting Director, Office of National Marine Sanctuaries.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
RIN 0648-XE460
Takes of Marine Mammals Incidental to Specified Activities; Sand Quality Study Activities at the Children's Pool Beach, La Jolla, California

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

ACTION:
Notice; issuance of an Incidental Harassment Authorization (IHA).

SUMMARY:
In accordance with the Marine Mammal Protection Act (MMPA) as amended, notification is hereby given that NMFS has issued an IHA to the City of San Diego to take small numbers of marine mammals, by Level B harassment, incidental to the conduct of sand quality study activities at the Children's Pool Beach in La Jolla, California.

DATES:
Effective June 1, 2016 through May 30, 2017.

FOR FURTHER INFORMATION CONTACT:
Dale Youngkin, 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 (Secretary) to allow, upon request, the incidental, but not intentional, taking of small numbers of marine mammals, by United States 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.
Authorization for the 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.”
Section 101(a)(5)(D) of the MMPA established an expedited process by which citizens of the United States can apply for an authorization to incidentally take small numbers of marine mammals by harassment. Section 101(a)(5)(D) of the MMPA establishes a 45-day time limit for NMFS's review of an application followed by a 30-day public notice and comment period on any proposed authorizations for the incidental harassment of small numbers of marine mammals. Within 45 days of the close of the public comment period, NMFS must either issue or deny the authorization.
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].

Summary of Request
On December 14, 2015, NMFS received an application from the City of San Diego, Transportation & Storm Water Department, Storm Water Division, requesting an IHA for the taking of marine mammals incidental to the conduct of sand quality study activities. NMFS determined that the IHA application was adequate and complete on February 25, 2016. NMFS published a notice making preliminary determinations and proposing to issue an IHA on April 4, 2016 (81 FR 19137). The notice initiated a 30 day comment period.
The City of San Diego will undertake the proposed sand quality sampling activities between June 1, 2016 and December 14, 2016 at the Children's Pool Beach in La Jolla, California. Visual stimuli due to the presence of technicians on the beach and their sand sampling collection activities during the study have the potential to result in the take of marine mammals through behavioral disturbance. The IHA authorizes the take, by Level B (behavioral) harassment, of small numbers of Pacific harbor seals ( Phoca vitulina richardii ), California sea lions ( Zalophus californianus ), and northern elephant seals ( Mirounga angustirostris ) incidental to sand quality sampling activities of the Children's Pool Beach at La Jolla, CA. Additional information on the sand quality sampling activities at the Children's Pool Beach is contained in the IHA application, which is available at the NMFS Web site: http://www.nmfs.noaa.gov/pr/permits/incidental.

Description of the Specified Activity
A detailed description of the sand sampling project is provided in the Federal Register notice for the proposed IHA (81 FR 19137, April 4, 2016). Since that time, no changes have been made to the planned activities. Therefore, a detailed description is not provided here. Please refer to that Federal Register notice for the description of the specific activity.

Comments and Responses
A notice of preliminary determinations and proposed IHA for the City of San Diego's sand quality study activities was published in the Federal Register on April 4, 2016 (81 FR 19137). During the 30-day public comment period, NMFS received comments from the Marine Mammal Commission (Commission). The comments are posted online at: http://www.nmfs.noaa.gov/pr/permits/incidental/construction.html. Following are the substantive comments and NMFS's responses:
Comment 1: The Commission concurs with NMFS's preliminary findings and recommends that NMFS issue the requested IHA, subject to inclusion of the proposed mitigation, monitoring, and reporting measures.
Response: NMFS concurs with the Commission's recommendation and has issued the IHA to the City of San Diego.

Description of Marine Mammals in the Specified Geographic Area of the Proposed Specified Activity
Information on marine mammal species for which take is authorized is included below. Further information on the biology and local distribution of these marine mammal species and others in the region can be found in the NMFS Marine Mammal Stock Assessment Reports, which are available online at: http://www.nmfs.noaa.gov/pr/sars/.
Three species of pinnipeds are known to occur in the Children's Pool proposed action area and off the Pacific coastline (see Table 1 below). Pacific harbor seals are the most common species likely to be found within the immediate vicinity of the activity area. California sea lions and northern elephant seals may also be found within the immediate vicinity of the activity area, but are more rare occurrences than harbor seals. Northern fur seals and Guadalupe fur seals are even more rarely observed at this location (Northern and Guadalupe fur seals have been seen observed at nearby beaches on rare occasions, and a northern fur seal was observed hauled out at La Jolla Cove, which is less than a mile from Children's Pool, per a personal communication with Dr. Hanan [February 4, 2016], a scientist with extensive knowledge of the area and the species occurring there). Fur seals are not known to haul out in such urban mainland beaches, and their presence would likely be attributed to sickness or injury if they were observed in this location. Therefore, only three species are considered to be potentially exposed to effects of the proposed sand sampling activities, as sand sampling activities will not be conducted if fur seals were present and coordination with the stranding network would commence. A variety of other marine mammal species have on occasion been reported in the coastal waters off southern California. However, none of these species have been reported to occur in the immediate proposed action area of the Children's Pool Beach.
Therefore, NMFS does not expect, and does not propose to authorize, incidental take of marine mammal species other than Pacific harbor seals, California sea lions, and northern elephant seals from the proposed specified activities. Table 1 below provides information on these marine mammal species, their habitat, and conservation status in the nearshore area of the general region of the proposed project area.
Table 1—The Habitat, Abundance, and Conservation Status of Pacific Harbor Seals, California Sea Lions, and Northern Elephant Seals
Species | Habitat | Occurrence | Range | Best population estimate (minimum) ^1 | ESA ^2 | MMPA ^3
Pacific harbor seal ( Phoca vitulina richardii ) | Coastal | Common | Coastal temperate to polar regions in Northern Hemisphere | 30,968 (27,348)—California stock | NL | NC
Northern elephant seal ( Mirounga angustirostris ) | Coastal, pelagic when not migrating | Common | Eastern and Central North Pacific—Alaska to Mexico | 179,000 (81,368)—California breeding stock | NL | NC
California sea lion ( Zalophus californianus ) | Coastal, shelf | Common | Eastern North Pacific Ocean—Alaska to Mexico | 296,750 (153,337)—U.S. stock | NL | NC
NA = Not available or not assessed.
^1 NMFS Marine Mammal Stock Assessment Reports.
^2 U.S. Endangered Species Act: EN = Endangered, T = Threatened, DL = Delisted, and NL = Not listed.
^3 U.S. Marine Mammal Protection Act: D = Depleted, S = Strategic, and NC = Not classified.
A detailed description of the of the species likely to be affected by the sand sampling project, including introductions to the species and relevant stocks as well as available information regarding population trends and threats, and information regarding local occurrence, were provided in the Federal Register notice for the proposed IHA (81 FR 19137; April 4, 2016); since that time, we are not aware of any changes in the status of these species and stocks; therefore, detailed descriptions are not provided here. Please refer to that Federal Register notice for these descriptions. Please also refer to NMFS' Web site ( www.nmfs.noaa.gov/pr/species/mammals/ ) for generalized species accounts.

Potential Effects of the Specified Activity on Marine Mammals
The effects of visual stimuli from the planned project have the potential to result in behavioral harassment of marine mammals in the project area. The Federal Register notice for the proposed IHA (81 FR 19137; April 4, 2016) included a discussion of the effects of visual stimuli on marine mammals, therefore that information is not repeated here; please refer to the Federal Register notice (81 FR 19137; April 4, 2016) for that information. No instances of hearing injury, serious injury, or mortality are expected as a result of the sand sampling activities.

Anticipated Effects on Marine Mammal Habitat
The primary anticipated adverse impact from the planned project upon habitat consists of the removal of sand from the beach. This change is minor, temporary, and limited in duration to the period of the sand sampling activities. Although sand will be collected from the beach, the total volume removed over the course of the study is estimated to be less than one cubic foot. Therefore, we do not anticipate impacts to marine mammal habitat. The Federal Register notice for the proposed IHA (81 FR 19137; April 4, 2016) included a discussion of the effects of the sand sampling activities on marine mammal habitat, therefore that information is not repeated here; please refer to the Federal Register notice (81 FR 19137; April 4, 2016) for that information.

Mitigation Measures
In order to issue an Incidental Take Authorization (ITA) under section 101(a)(5)(D) of the MMPA, NMFS must prescribe, where applicable, the permissible methods of taking pursuant to such activity, and other means of effecting the least practicable impact on such species or stock and its habitat, paying particular attention to rookeries, mating grounds, and areas of similar significance, and on the availability of such species or stock for taking for certain subsistence uses (where relevant).
The planned activities include a variety of measures to minimize potential impacts on marine mammals, including:

Prohibition of Sand Sampling During Pupping Season
Sand sampling activities shall be prohibited during the Pacific harbor seal pupping season (December 15th to May 15th), and for an additional two weeks thereafter to accommodate lactation and weaning of late season pups. Thus, sand quality study activities shall be prohibited until June 1, 2016 and will be required to end before December 15, 2016.

Limiting Activity to Daylight Hours
Sand sampling activities shall be conducted during daylight hours only. As Protected Species Observers (PSOs) will be required to monitor the sand sampling activities (see discussion below), conducting the sampling events during daylight hours with adequate visibility will allow observers to adequately observe and record activities.

Daily Sand Sampling Timing
Sand sampling activities shall be scheduled, to the maximum extent practicable, during the daily period of lowest haul-out occurrence, from approximately 8:30 a.m. to 3:30 p.m., as harbor seals typically have the highest daily or hourly haul-out period during the afternoon from 3 p.m. to 6 p.m. However, sand sampling activities may be extended from 7 a.m. to 7 p.m. to help assure that the project can be completed at a time with low numbers of seals hauled out.

Avoidance/Minimization of Interaction With Pinnipeds
As stated in the FR notice for the proposed IHA (81 FR 19137; April 4, 2016), per Dr. Doyle Hanan, ongoing observations of harbor seals at Children's Pool have indicated a habituation to the presence of people to some degree and therefore, generally show signs of disturbance when people are very close to them on the beach (generally less than two to three meters). Sand sampling activities will be conducted such that humans remain at least three meters from hauled out pinnipeds at all times. While the study calls for taking samples along transects, there is enough flexibility to allow for variation from the transect line to collect samples and still allow for minimizing approach to pinnipeds on the beach. Therefore, hauled out pinnipeds will be minimized or avoided, and efforts will be made to avoid disturbing/alerting/flushing them.

Protected Species Observers
Trained PSOs will be used to detect, document, and minimize impacts to marine mammals. More information about this measure is contained in the “Proposed Monitoring” section (below).

Mitigation Conclusions
NMFS has carefully evaluated the applicant's mitigation measures and considered a range of other measures in the context of ensuring that NMFS prescribes the means of effecting the least practicable impact on the affected marine mammal species and stocks and their habitat. NMFS's evaluation of potential measures included consideration of the following factors in relation to one another:
• The manner in which, and the degree to which, the successful implementation of the measure is expected to minimize adverse impacts to marine mammals;
• The proven or likely efficacy of the specific measure to minimize adverse impacts as planned; and
• The practicability of the measure for applicant implementation, including consideration of personnel safety, practicality of implementation, and impact on the effectiveness of the activity.
Any mitigation measure(s) prescribed by NMFS should be able to accomplish, have a reasonable likelihood of accomplishing (based on current science), or contribute to the accomplishment of one or more of the general goals listed below:
(1) Avoidance or minimization of injury or death of marine mammals wherever possible (goals 2, 3, and 4 may contribute to this goal).
(2) A reduction in the numbers of marine mammals (total number or number at biologically important time or location) exposed to visual or auditory stimuli associated with the proposed sand quality study, or other activities expected to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing harassment takes only).
(3) A reduction in the number of times (total number or number at biologically important time or location) individuals would be exposed to visual or auditory stimuli associated with the proposed sand quality study, or other activities expected to result in the take of marine mammals (this goal may contribute to 1, above, or to reducing harassment takes only).
(4) A reduction in the intensity of exposures (either total number or number at biologically important time or location) to visual or auditory stimuli associated with the proposed sand quality study, or other activities expected to result in the take of marine mammals (this goal may contribute to a, above, or to reducing the severity of harassment takes only).
(5) Avoidance of minimization of adverse effects to marine mammal habitat, paying special attention to the food base, activities that block or limit passage to or from biologically important areas, permanent destruction of habitat, or temporary destruction/disturbance of habitat during a biologically important time.
(6) For monitoring directly related to mitigation—an increase in the probability of detecting marine mammals, thus allowing for more effective implementation of the mitigation.
Based on NMFS's evaluation of the applicant's planned measures, as well as other measures considered by NMFS, NMFS has determined that the mitigation measures provide the means of effecting the least practicable impact on marine mammal species or stocks and their habitat, paying particular attention to rookeries, mating grounds, and areas of similar significance.

Monitoring and Reporting
In order to issue an ITA for an activity, section 101(a)(5)(D) of the MMPA states that NMFS must, where applicable, set forth “requirements pertaining to the monitoring and reporting of such taking.” The MMPA implementing regulations at 50 CFR 216.104 (a)(13) require that requests for ITAs include the suggested means of accomplishing the necessary monitoring and reporting that will result in increased knowledge of the species and of the level of taking or impacts on populations of marine mammals that are expected to be present in the action area.
Monitoring measures prescribed by NMFS should accomplish one or more of the following general goals:
(1) An increase in the probability of detecting marine mammals, both within the mitigation zone (thus allowing for more effective implementation of the mitigation) and in general to generate more data to contribute to the analyses mentioned below;
(2) An increase in our understanding of how many marine mammals are likely to be exposed to visual or auditory stimuli associated with the proposed sand quality study that we associate with specific adverse effects, such as behavioral harassment;
(3) An increase in our understanding of how marine mammals respond to stimuli expected to result in take and how anticipated adverse effects on individuals (in different ways and to varying degrees) may impact the population, species, or stock (specifically through effects on annual rates of recruitment or survival) through any of the following methods:
• Behavioral observations in the presence of stimuli compared to observations in the absence of stimuli (need to be able to accurately predict distance from source, and other pertinent information);
• Physiological measurements in the presence of stimuli compared to observations in the absence of stimuli (need to be able to accurately predict distance from the source, and other pertinent information);
• Distribution and/or abundance comparisons in times or areas with concentrated stimuli versus times or areas without stimuli;
(4) An increased knowledge of the affected species;
(5) An increase in our understanding of the effectiveness of certain mitigation and monitoring measures; and
(6) An increase in our level of knowledge regarding the overall health of the monitored species, particularly in light of recent local UMEs and observations of malnutrition increases in the area.

Monitoring
The City of San Diego has developed a monitoring plan based on discussions between the City of San Diego and NMFS, as well as review of past IHAs granted to the City of San Diego. The plan was included as an Appendix to our Environmental Assessment (EA) for issuance of the IHA for the sand quality study activities (see National Environmental Policy Act section below). No changes to the monitoring plan were made based on comments received during the public review period. The monitoring plan has also been included as an attachment to the IHA issued to the City of San Diego. The City of San Diego will ensure that the requirements of the IHA and monitoring plan are explained to all workers associated with sand quality study activities at Children's Pool Beach, and a copy of the IHA will be posted at a prominent location at the site of the activities.
The monitoring plan involves PSOs surveying and conducting hourly visual counts beginning prior to sand sampling activities (beginning at least 30 minutes prior to sampling activities), monitoring during sampling activities, and post-sand sampling monitoring (continuing for at least 30 minutes after sand sampling activities have ended). During each sample collection event, the PSO will conduct continuous monitoring from a vantage point along the seawall (weather permitting) or along the bluff above the beach, such that the full study area is in view. During the planned sand sampling activities, monitoring shall assess behavior and potential behavioral responses to noise and visual stimuli due to the proposed activities. As noted above, if northern fur seals or Guadalupe fur seals are observed prior to commencement of activities, the activities will not occur and coordination with the stranding network will be initiated.
Counts will be performed by species for three zones: pinnipeds hauled out on the sandy beach area, pinnipeds observed in the water within approximately 30 meters of the beach, and pinnipeds hauled out on the reef/rocks just off the beach (including Seal Rock). Total counts, counts of juveniles (yearlings and pups), and counts of males/females (when possible) will be recorded. In addition to counts, continuous behavioral monitoring will be conducted for the duration of the sampling event to document any behavioral responses to visual (or other) stimuli, as noted in Table 2 below. When responses are observed, the type of take ( i.e., alert and flush, movement of more than one meter, or change in direction of movement) and the assumed cause (whether related to sample collection activities or not) will be noted by species. Photographs and/or video will be taken to document these responses.
Table 2—Seal Response to Disturbance
Level | Type of response | Definition
1 | Alert | Seal head orientation or brief movement in response to disturbance, which may include turning head towards the disturbance, craning head and neck while holding the body rigid in a u-shaped position, changing from a lying to a sitting position, or brief movement of less than twice the animal's body length. Alerts will be recorded, but not counted as a ‘take’.
2 | Movement | Movements away from the source of disturbance, ranging from short withdrawals at least twice the animal's body length to longer retreats over the beach including changing direction of travel, or movement along the beach from a resting position. These movements will be recorded and counted as a ‘take’.
| 3 | Flush | All retreats (flushes) to the water. Flushing into the water will be recorded and counted as a ‘take’.
Additional parameters will be recorded during the first and last count of each sampling event including Beaufort sea state; atmospheric conditions; cloud cover; visibility conditions; air and water temperature; tide height; and number of public visitors present by location at Children's Pool.
Field observations will be documented on Field Monitoring Forms, and all observations and associated data, including daily monitoring reports, will be maintained on City of San Diego computers. A report summarizing mitigation and monitoring for the duration of the Children's Pool Beach sand quality study will be prepared and submitted by the City of San Diego to NMFS following completion of sand sampling activities for the 2016 sampling season.
The following marine mammal monitoring and reporting shall be performed for the proposed action:
(1) The PSO shall be selected prior to sand sampling activities.
(2) The NMFS-approved PSO shall attend the project site prior to, during, and after sand sampling activities cease each day that the sand sampling activities occur.
(3) The PSO shall search for marine mammals within the Children's Pool area.
(4) The PSO shall be present during sand sampling activities to observe for the presence of marine mammals in the vicinity of the specified activity. All such activity will occur during daylight hours ( i.e., 30 minutes after sunrise and 30 minutes before sunset). If inclement weather limits visibility within the area of effect, the PSO will perform visual scans to the extent conditions allow.
(5) If marine mammals are sighted by the PSO, the PSO shall record the number of marine mammals and the duration of their presence while the sand sampling activity is occurring. The PSO will also note whether the marine mammals appeared to respond to the noise/visual stimuli and, if so, the nature of that response. The PSO shall record the following information: date and time of initial sighting, tidal stage, weather conditions, Beaufort sea state, species, behavior (activity, group cohesiveness, direction and speed of travel, etc.), number, group composition, distance between sampling personnel and pinniped(s), number of animals impacted, sampling activities occurring at time of sighting (walking, taking surface sample, or pounding core sampler), and monitoring and mitigation measures implemented (or not implemented). The observations will be reported to NMFS.
(6) To avoid takes of northern fur seals and Guadalupe fur seals, if fur seals are observed to be hauled out on the beach, or in the water/rocks at the Children's Pool Beach prior to the initiation of sand collection activities, sand sampling activities will not commence. PSOs will alert the stranding network, as the occurrence of these species would typically indicate a sick/injured animal. Recommendations of the stranding coordinator will be followed, which may include a 24-hour or 48-hour waiting and observation period, and sand sampling will not commence until the animal(s) either vacate the area on its own, or is collected by the stranding network
(7) A final report will be submitted summarizing all effects from sand sampling activities and marine mammal monitoring during the time of the authorization.
A written log of dates and times of monitoring activity will be kept. The log shall report the following information:
• Time of observer arrival on site;
• Time of the commencement of sand sampling activities;
• Distances to all marine mammals relative to the stimuli;
• For harbor seal, northern elephant seal, and California sea lion observations, notes on behavior during sand sampling activity, as described above, and on the number and distribution observed in the project vicinity;
• For observations of all marine mammals other than harbor seals, northern elephant seals, and California sea lions, the time and duration of each animal's presence in the project vicinity; the number of animals observed; the behavior of each animal, including any response to sand sampling activities;
• Time of the cessation of sand sampling activities; and
• Time of observer departure from site.
All monitoring data collected during sand sampling events will be included in the biological monitoring notes to be submitted. A final report summarizing the sand sampling monitoring and any general trends observed will also be submitted to NMFS within 90 days after monitoring has ended during the period of the sand quality study or 45 days prior to the date by which any subsequent IHA is requested by the City of San Diego, whichever comes first.

Reporting
A draft final report must be submitted to NMFS within 90 days after the conclusion of the final sand sampling activities of the Children's Pool Beach. The report will include a summary of the information gathered pursuant to the monitoring requirements set forth in the IHA, including dates and times of operations and all marine mammal sightings (dates, times, locations, species, behavioral observations [activity, group cohesiveness, direction and speed of travel, etc.], tidal stage, weather conditions, Beaufort sea state and wind force, associated sand sampling activities). A final report must be submitted within 30 days after receiving comments from NMFS on the draft final report. If no comments are received from NMFS, the draft final report would be considered to be the final report.
While the IHA does not authorize injury ( i.e., Level A harassment), serious injury, or mortality, should the applicant, contractor, monitor or any other individual associated with the sand quality study observe an injured or dead marine mammal, the incident (regardless of cause) will immediately be reported to NMFS stranding coordinator. The report should include species or description of animal, condition of animal, location, time first found, observed behaviors (if alive) and photo or video, if available.
In the unanticipated event that the City of San Diego discovers a live stranded marine mammal (sick and/or injured, or if any fur seals are observed) at Children's Pool, they shall immediately contact Sea World's stranded animal hotline at 1-800-541-7235. Sea World shall also be notified if a dead stranded pinniped is found so that a necropsy can be performed. In all cases, NMFS stranding coordinator shall be notified as well, but for immediate response purposes, Sea World shall be contacted first.
Reporting Prohibited Take —In the unanticipated event that the specified activity clearly causes the take of a marine mammal in a manner prohibited by this IHA, such as an injury (Level A harassment), serious injury, or mortality, the City of San Diego shall immediately cease the specified activities and immediately report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS, and the West Coast Regional Stranding Coordinator. The report must include the following information:
• Time, date, and location (latitude/longitude) of the incident;
• The type of activity involved;
• Description of the circumstances during and leading up to the incident;
• Water depth; environmental conditions ( e.g., wind speed and direction, Beaufort sea state, cloud cover, and visibility);
• Description of marine mammal observations in the 24 hours preceding the incident; species identification or description of the animal(s) involved;
• The fate of the animal(s); and photographs or video footage of the animal (if equipment is available).
Activities shall not resume until NMFS is able to review the circumstances of the prohibited take. NMFS shall work with the City of San Diego to determine the action necessary to minimize the likelihood of further prohibited take and ensure MMPA compliance. The City of San Diego may not resume its activities until notified by NMFS via letter, email, or telephone.
Reporting an Injured or Dead Marine Mammal with an Unknown Cause of Death —In the event that the City of San Diego discovers an injured or dead marine mammal, and the lead PSO determines that the cause of the injury or death is unknown and the death is relatively recent ( i.e., in less than a moderate state of decomposition as described in the next paragraph), the City of San Diego will immediately report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS, and the West Coast Regional Stranding Coordinator. The report must include the same information identified above. Activities may continue while NMFS reviews the circumstances of the incident. NMFS will work with the City of San Diego to determine whether modification of the activities is appropriate.
Reporting an Injured or Dead Marine Mammal Not Related to the Activities —In the event that the City of San Diego discovers an injured or dead marine mammal, and the lead PSO determines that the injury or death is not associated with or related to the activities authorized ( e.g., previously wounded animal, carcass with moderate to advanced decomposition, or scavenger damage), the City of San Diego shall report the incident to the Chief of the Permits and Conservation Division, Office of Protected Resources, NMFS, and the West Coast Regional Stranding Coordinator within 24 hours of the discovery. The City of San Diego shall provide photographs or video footage (if available) or other documentation of the stranded animal sighting to NMFS and the Marine Mammal Stranding Network. Activities may continue while NMFS reviews the circumstances of the incident.

Monitoring Results From Previously Authorized Activities

2013 to 2014
Hanan & Associates, Inc., on behalf of the City of San Diego, conducted marine mammal and in-air sound monitoring at six locations during demolition and construction activities at the Children's Pool Lifeguard Station in La Jolla, California from June 3, 2013 to February 12, 2014. Demolition and construction activities began on July 10, 2013 and were halted for the Pacific harbor seal pupping season (December 15, 2013 to May 30, 2014). During 115 days of visual and acoustic observations, Hanan & Associates counted a total of 61,631 Pacific harbor seals and 26,037 people. During the 2013 demolition and construction activities, Hanan & Associates observed a total of 5,793 takes by Level B harassment ( i.e., movements, and flushes) that could be attributed to demolition and construction activities (1,371 takes), the general public (3,536 takes), and other sources (886 takes). As of April 15, 2014, at least 60 harbor seal pups (including 2 still births) have been born at the Children's Pool and there has been no indication of abandonment. In addition to the Pacific harbor seal sightings, PSOs recorded three sightings of California sea lions (1 juvenile, 3 adult), and 2 northern elephant seals (both juveniles) at the Children's Pool.

2014 to 2015
Hanan & Associates, Inc., on behalf of the City of San Diego, conducted marine mammal monitoring at seven locations during demolition and construction activities at the Children's Pool Lifeguard Station in La Jolla, California from August 6, 2014 to March 15, 2015. Construction activities began on August 6, 2014 and were halted for the Pacific harbor seal pupping season (December 15, 2014 to May 30, 2015). During 127 days of visual and acoustic observations, Hanan & Associates counted a total of 63,598 Pacific harbor seals and 27,844 people. During the 2014 demolition and construction activities, Hanan & Associates observed a total of 6,787 takes by Level B harassment ( i.e., movements, and flushes) that could be attributed to demolition and construction activities (1,790 takes), the general public (3,914 takes), and other sources (1,083 takes). As of March 13, 2015, at least 60 harbor seal pups (including 6 still or premature births) have been born at the Children's Pool and there has been no indication of abandonment. In addition to the Pacific harbor seal sightings, 366 sightings of California sea lions (93 at Children's Pool beach; others were at Seal Rock, South Casa Beach, and on the reef), and 1 northern elephant seal (juvenile). One dead adult and one dead juvenile California sea lion were sighted on the Children's Pool beach after the start of the beach closure and after the construction activities stopped for the pupping season. These strandings were reported to NMFS.
More information on the monitoring results from the City of San Diego's previous demolition and construction activities at the La Jolla Children's Pool Lifeguard Station can be found in the final monitoring reports. The 2013 to 2014 and 2014 to 2015 monitoring reports can be found online at: http://www.nmfs.noaa.gov/pr/permits/incidental/construction.htm#childrenspool.

Estimated Take by Incidental Harassment
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].
The City of San Diego and NMFS anticipate takes of Pacific harbor seals, California sea lions, and northern elephant seals by Level B (behavioral) harassment only incidental to visual disturbance associated with the sand quality study sand sampling activities at the Children's Pool Beach. No takes by injury (Level A harassment), serious injury, or mortality are expected. NMFS will consider pinnipeds behaviorally reacting to the sand sampling activities by flushing into the water, moving more than twice the animal's body length but not into the water; becoming alert and moving more than twice its body length; and changing direction of current movements by individuals as behavioral criteria for take by Level B harassment.
With planned sand sampling activities scheduled to begin in June 2016, the City of San Diego expects a range of harbor seals to be present daily during June with a maximum of up to 190 individuals and a seasonal decline through November to about 0 to 50 harbor seals present daily. As not all of the sampling activities have been planned, and there is uncertainty regarding the timing and number of all activities, we have assumed the maximum number of authorized sampling activities (16) occurring during the maximum haul out month (June) in order to estimate take numbers. If all of the estimated harbor seals present are taken by incidental harassment each day, there could be a maximum of 3,040 incidences of take over the entire duration of the activities. An unknown portion of the incidental takes will be from repeated exposures as harbor seals leave and return to the Children's Pool area.
Very few California sea lions or northern elephant seals are ever observed at the Children's Pool Beach. As noted above, Children's Pool is almost exclusively a harbor seal haul-out site and on rare occasions, one or two California sea lions or a single juvenile elephant seal have been observed on the sand or rocks at, or near, Children's Pool. However, as noted above, an UME has been in place since 2013 for California sea lions. According to the NMFS West Coast Region, California sea lion strandings in January-May of 2015 were over 10 times the average stranding level for the same five-month period during 2004-2012. The City of San Diego has requested take for these species due to their potential occurrence at this location and past monitoring experience at this location. As the previous IHA authorized take of two individual sea lions incidental to construction activities at Children's Pool, and numbers of sea lion sightings have been over 10 times the average, we estimate that up to 20 individuals may be incidentally taken by Level B harassment equating to 320 exposures (conservatively assuming 20 × 16 sampling events). As only one or two northern elephant seals are known to occur rarely at Children's Pool Beach, it was conservatively estimated that 16 individuals would be exposed to Level B harassment for a total of 16 takes (assuming one present for each of the 16 sampling events). Therefore, NMFS authorizes the following numbers of incidental takes ( i.e., Level B harassment): 3,040 Pacific harbor seals (600 individuals), 320 California sea lions (20 individuals), and 16 northern elephant seals (16 individuals). More information on the number of takes authorized, and the approximate percentage of the stock for the three species in the proposed action area can be found in Table 3 (below).
Table 3—Summary of the Authorized Incidental Take by Level B Harassment of Pinnipeds for the City of San Diego's Proposed Sand Quality Study Activities Generating Visual and Auditory Stimuli at the Children's Pool Beach in La Jolla, CA
Species | Take authorization (Number of exposures) | Estimated number of individuals taken | Abundance | Approximate percentage of estimated stock (Takes authorized/ population) | Population trend
Pacific harbor seal | 3,040 | 600 | 30,968—California stock | 10 | Increased in California 1981 to 2004.
California sea lion | 320 | 20 | 296,750—U.S. stock | 0.1 | Increasing.
Northern elephant seal | 16 | 16 | 179,000—California breeding stock | <0.01 | Increasing 3.8% annually since 1988.

Analysis and Determinations

Negligible Impact
Negligible impact is “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” (50 CFR 216.103). A negligible impact finding is based on the lack of likely adverse effects on annual rates of recruitment or survival ( i.e., population-level effects). An estimate of the number of Level B harassment takes, alone, is not enough information on which to base an impact determination. In addition to considering estimates of the number of marine mammals that might be “taken” through behavioral harassment, NMFS must consider other factors, such as the likely nature of any responses (their intensity, duration, etc.), the context of any responses (critical reproductive time or location, migration, etc.), as well as the number and nature of estimated Level A harassment takes, the number of estimated mortalities, and effects on habitat.
In making a negligible impact determination, NMFS evaluated factors such as:
(1) The number of anticipated injuries, serious injuries, or mortalities;
(2) The number, nature, and intensity, and duration of Level B harassment; and
(3) The context in which the takes occur ( i.e., impacts to areas of significance, impacts to local populations, and cumulative impacts when taking into account successive/contemporaneous actions when added to baseline data);
(4) The status of the stock or species of marine mammals ( i.e., depleted, not depleted, decreasing, increasing, stable, impact relative to the size of the population);
(5) Impacts on habitat affecting rates of recruitment/survival; and
(6) The effectiveness of monitoring and mitigation measures.
Behavioral disturbance may potentially occur incidental to the visual presence of humans and sand sampling activities; however, pinnipeds at this site have likely adapted or become acclimated to human presence to some degree at this site. The City of San Diego has designated Children's Pool Beach as a shared use beach. Many activities currently take place at Children's Pool Beach and the surrounding shoreline areas including swimming, SCUBA diving, surfing, kayaking, tide pooling, and nature watching. These “urbanized” harbor seals do not exhibit sensitivity at a level similar to that noted in harbor seals in some other regions affected by human disturbance (Allen et al., 1984; Suryan and Harvey, 1999; Henry and Hammil, 2001; Johnson and Acevedo-Gutierrez, 2007; Jansen et al., 2006; Hanan & Associates, 2011). For example, during monitoring for construction for the Children's Pool Lifeguard Station, equipment noise and visual cues at times have caused seals to alert/flush, while at other times the same stimuli have produced no reaction (City of San Diego, 2015). Per the City of San Diego (2015), “[a]t the individual level, a newly arrived seal (which swam in from another area) may not have habituated to humans and noise as have seals that have been onsite for a while. These recent arrivals may alert to visual stimuli, perhaps flushing to the water. But after a few days using this beach during the non-pupping season (when humans are also present on the beach), we would expect them to habituate and generally not react to humans unless very close to them (Hanan 2004, Hanan & Associates 2011, Hanan and Hanan 2014).” Therefore, there is a high likelihood that many of the harbor seals present during the planned sand sampling activities would not be flushed off of the beach or rocks, as pinnipeds at this site are conditioned to human presence to some degree (Hanan, 2004; Hanan & Associates, 2011) (see http://www.youtube.com/watch?v=4IRUYVTULsg ), and it is anticipated that takes would likely be of lesser intensity than would be expected at other locations.
No injuries (Level A harassment), serious injuries, or mortalities are anticipated to occur as a result of the City of San Diego's sand sampling activities, and none are proposed for authorization by NMFS. The planned activities are not expected to result in the alteration of reproductive behaviors or parenting because of the moratorium on access to the beach during the pupping season, and the potentially affected species would be subjected to only temporary and minor behavioral impacts.
As discussed in detail above, the project scheduling avoids sensitive life stages for Pacific harbor seals. Project activities will commence June 1 and end by December 15. The commencement date occurs after the end of the pupping season, affords additional time to accommodate lactation and weaning of late-season pups, and takes into account periods of lowest haul-out occurrence. The end date falls approximately two weeks prior to January 1, the time after which most births occur, providing protection for pregnant and nursing harbor seals that may give birth before January 1.
Table 3 of this document outlines the number of Level B harassment takes that are anticipated as a result of these proposed activities. Due to the nature, degree, and context of Level B (behavioral) harassment anticipated and described (see “Potential Effects on Marine Mammals” section above) in this notice, this activity is not expected to impact rates of annual recruitment or survival for the affected species or stock ( i.e., California stock of Pacific harbor seals, U.S. stock of California sea lions, and California breeding stock of northern elephant seals), particularly given the mitigation, monitoring, and reporting measures that will be implemented to minimize impacts to marine mammals.
The Children's Pool is one of the three known haul-out sites for Pacific harbor seal in San Diego County and the only rookery in San Diego County and the only mainland rookery on the U.S. west coast for this species between the border of Mexico and Point Mugu in Ventura County, CA. For the other marine mammal species that may occur within the action area ( i.e., California sea lions and northern elephant seals), there are no known designated or important feeding and/or reproductive areas at the project site. Many animals perform vital functions, such as feeding, resting, traveling, and socializing, on a diel cycle ( i.e., 24 hour cycle). Behavioral reactions (such as disruption of critical life functions, displacement, or avoidance of important habitat) are more likely to be significant if they last more than one diel cycle or recur on subsequent days (Southall et al., 2007). However, Pacific harbor seals have been hauling-out at Children's Pool during the year for many years (including during pupping season and while females are pregnant) while being exposed to anthropogenic sound sources such as vehicle traffic, human voices, etc. and other stimuli from human presence. The Pacific harbor seals have repeatedly hauled-out to pup over many years and the NMFS Stock Assessment Reports for this stock have shown that the population is increasing and is considered stable (NMFS, 2014). Additionally, the proposed sand sampling activities would generally not take place on subsequent days for long durations, as a maximum of up to 16 sampling events (lasting approximately 4 hours each) are planned for the sand quality study, which would take place over the six-months of the study.
None of the potentially affected marine mammal species under NMFS jurisdiction in the action area (Pacific harbor seals, California sea lions, and northern elephant seals) are listed as threatened or endangered under the ESA. To protect these animals (and other marine mammals in the action area), the City of San Diego shall schedule sand sampling activities during the daily period of lowest haul-out occurrence; limit activities to the hours of daylight; ensuring that technicians performing sand sampling remain at least three meters from any hauled out pinnipeds; use PSOs, prohibit sand sampling activities in the unlikely event that fur seals are present, and prohibit sand sampling activities during harbor seal pupping season.
Although behavioral modifications, including temporarily vacating the area during the proposed sand sampling activities, may be made by these species, the sand quality sampling activities will be fairly sporadic and will be of relatively short duration. NMFS believes that the time period of the sand sampling activities, the requirement to implement mitigation measures ( e.g., prohibiting sand sampling activities during pupping season, scheduling operations to periods of the lowest haul-out occurrence, and ensuring a buffer of at least three meters between sampling technicians and hauled out pinnipeds), and the inclusion of the monitoring and reporting measures, will reduce the amount and severity of the potential impacts from the activity.
Based on the analysis contained herein of the likely effects of the specified activity on marine mammals and their habitat, and taking into consideration the implementation of monitoring and mitigation measures, NMFS finds that the total marine mammal take from the City of San Diego's activities would have a negligible impact on the affected marine mammal species or stocks.

Small Numbers
As mentioned previously, NMFS estimates that three species of marine mammals under its jurisdiction could be potentially affected by Level B harassment over the course of the IHA. It is conservatively estimated that the instances of take by Level B harassment (amounting to 3,040 for Pacific harbor seals, 320 for California sea lions, and 16 for northern elephant seals) would be approximately 10%, 0.1%, and less than 0.01% of the respective California, U.S., and California breeding stocks. The population estimates for the marine mammal species that may be taken by Level B harassment were provided in Table 3 of this document.
Based on the analysis contained herein of the likely effects of the specified activity on marine mammals and their habitat, and taking into consideration the implementation of the mitigation and monitoring measures, NMFS determined that small numbers of marine mammals will be taken relative to the populations of the affected species or stocks. See Table 3 for the authorized take numbers of marine mammals.

Impact on Availability of Affected Species or Stock for Taking for Subsistence Uses
Section 101(a)(5)(D) of the MMPA requires NMFS to determine that the authorization will not have an unmitigable adverse effect on the availability of marine mammal species or stocks for subsistence use. There are not relevant subsistence uses of marine mammals implicated by this action. Therefore, NMFS has determined that the total taking of affected species or stocks would not have an unmitigable adverse impact on the availability of such species or stocks for subsistence purposes.

Endangered Species Act
NMFS (Permits and Conservation Division) has determined that an ESA section 7 consultation for the issuance of an IHA under section 101(a)(5)(D) of the MMPA for this activity is not necessary for the Guadalupe fur seal. This species is rare at Children's Pool Beach. Due to the fact that sightings have occurred in the area, and due to the declaration of a UME for this species in the area, ESA consultation was considered. However, it was determined that the sand sampling activities would have no potential to affect the Guadalupe fur seal because these activities would not occur if this species were present at Children's Pool Beach. No other ESA-listed species are expected to occur in the proposed project area.

National Environmental Policy Act
To meet NMFS's National Environmental Policy Act (NEPA; 42 U.S.C. 4321 et seq. ) requirements for the issuance of an IHA to the City of San Diego, NMFS prepared an Environmental Assessment (EA) titled Draft Environmental Assessment of the Issuance of an Incidental Harassment Authorization to the City of San Diego to Take Marine Mammals by Harassment Incidental to Sand Quality Study Activities at the Children's Pool Beach in La Jolla, California to comply with the Council of Environmental Quality (CEQ) regulations and NOAA Administrative Order (NAO) 216-6. NMFS prepared and signed a Finding of No Significant Impact (FONSI) determining that preparation of an Environmental Impact Statement (EIS) was not required. The FONSI was signed on May 26, 2016 prior to the issuance of the IHA for the City of San Diego's sand quality study activities from June 2016 to June 2017. A copy of the EA and FONSI is available upon request (see ADDRESSES ).

Authorization
NMFS has issued an IHA to the City of San Diego for conducting sand quality study activities at the Children's Pool Beach in La Jolla, CA, provided the previously mentioned mitigation, monitoring, and reporting requirements are incorporated.
Dated: May 27, 2016.
Donna S. Wieting,

Director, Office of Protected Resources, National Marine Fisheries Service.
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
Interagency Working Group on the Harmful Algal Bloom and Hypoxia Research and Control Amendments Act

AGENCY:
National Ocean Service, National Oceanic and Atmospheric Administration, U.S. Department of Commerce.

ACTION:
Notices; publication of report and plan summary.

SUMMARY:
The National Ocean Service (NOS) of the National Oceanic and Atmospheric Administration (NOAA) publishes this notice to announce the publication of a detailed outline summarizing the intent of the Great Lakes Plan on Harmful Algal Blooms (HABs) and Hypoxia.
Notice is also hereby given of the publication of “HABs and Hypoxia Comprehensive Research Plan and Action Strategy: An Interagency Report.”

FOR FURTHER INFORMATION CONTACT:
Caitlin Gould ( Caitlin.gould@noaa.gov , 240-533-0290) or Stacey DeGrasse ( Stacey.Degrasse@fda.hhs.gov, 240-402-1470)

SUPPLEMENTARY INFORMATION:

I. Background
HABS and hypoxia can have detrimental impacts to human and animal health, local and regional economies, and long-term national security. In response, the Harmful Algal Bloom and Hypoxia Research and Control Amendments Act of 2014 (HABHRCA) establishes a national program and Federal interagency task force to advance the understanding of HABs and hypoxia events, and to respond to, detect, predict, control, and mitigate these events to the greatest extent practicable.
Section 8 of the HABHRCA requires NOAA, as the lead federal agency of the task force and Interagency Working Group on HABHRCA (IWG-HABHRCA), to develop and submit to Congress a plan for reducing, mitigating, and controlling HABs and hypoxia in the Great Lakes, and publish a summary of the plan in the Federal Register prior to submission. The plan builds upon the Great Lakes HABs and Hypoxia Integrated Assessment contained in “HABs and Hypoxia Comprehensive Research Plan and Action Strategy: An Interagency Report”, referenced herein, and builds upon the work of the International Joint Commission ( e.g., reports entitled A Balanced Diet for Lake Erie: Reducing Phosphorous Loadings and Harmful Algal Blooms and Human Health Effects from Harmful Algal Blooms: a Synthesis ) and the Great Lakes Water Quality Agreement ( e.g. Annex Four). The Plan also addresses key aspects of Federal Activities to better understand and address HABs and hypoxia in the Great Lakes. Those efforts include establishing HAB and hypoxia forecast products through comprehensive monitoring integrated with satellite coverage and modeling of coastal, and freshwater zones; and developing and deploying lower cost, easy to use, and real-time sensors for early detection of hypoxia and HAB cells and toxins. The Plan further reflects significant engagement between IWG-HABHRCA agencies and a wide variety of stakeholders. Stakeholder engagement provides the IWG with information and perspective that enhances Federal data collection efforts.

II. Summary of the Great Lakes Plan on Harmful Blooms and Hypoxia
The IWG-HABHRCA is producing the Great Lakes Plan on Harmful Algal Blooms and Hypoxia: An Interagency Report (hereafter: The “Plan”), which will assess the current state of the science on causes and impacts of harmful algal blooms (HABs) and hypoxia in the Great Lakes, highlight progress to date and current challenges, and propose next actions.
An overview of the current state of science in the Plan will discuss challenges and recommendations related to HABs and hypoxia, addressing improving scientific understanding; prediction, modeling, and monitoring; mitigating the causes and impacts; social science; and engagement, communications, and outreach. Throughout, the report will consider prevention, control, and mitigation as related to HABs and hypoxia in the region. It will also discuss Federal progress and successes.

Scientific Understanding: Requirements for Understanding, Verifying, and Characterizing HABs and Hypoxia
The section on improving scientific understanding will synthesize existing knowledge regarding bloom toxicity and the detection and mapping of HAB and hypoxia extent. It also will review causes of HABs and hypoxia, including the role of phosphorus and nitrogen, invasive species, herbicides, climate change, and other environmental drivers, as well as how these factors influence the duration and intensity of HAB and hypoxia events. It also will review questions related to the timing of events and causes of HAB toxicity.

Monitoring
Expanded and coordinated monitoring and data aggregation efforts, as well as advances in monitoring technologies, can help answer pressing questions at a variety of spatial and temporal scales. The report will discuss how scientific understanding and nutrient mitigation strategies for HABs and hypoxia can be improved with additional environmental monitoring. It also will discuss how partnerships between agencies and non-Federal groups play a role in enhancing the efficiency of monitoring efforts.

Modeling
The prediction and modeling section will discuss the methods and technology that are being developed to provide advanced warnings of HAB and hypoxic events, forecast recovery efforts related to nutrient abatement, and raise awareness of HABs and hypoxia in order to reduce risk to public health. Methods and technology discussed in the report will include data, calibration, and validation needs related to HAB and hypoxia models.

Impacts and Assessments
Mitigating the causes and impacts of HABs and hypoxia will encompass best management practices (BMPs) for addressing HABs and hypoxia, as well as BMPs during HAB and hypoxic events to minimize potential human health and socioeconomic risk. Mitigation challenges will include, but are not limited to, implementing new programs that reduce nutrient inputs, along with monitoring and modeling to determine BMP effectiveness.
Sections discussing challenges related to socioeconomics, engagement, communications, and outreach of these issues in the region will include information on health impacts for humans, the aquatic ecosystem, pets, and wildlife, as well as information on cost-benefit analyses, valuation of ecosystem services, and risk assessment. It will also discuss how to better communicate between Federal agencies and with non-Federal stakeholders.

Timeline and Budget
Recommendations for actions in each of the themes will be included in the report. The specific timeline and budgetary requirements for the deployment of future assets are subject to the availability of appropriations.
This report will consider HAB and hypoxic events that occur throughout the Great Lakes, such as those in Lake Erie's western basin and Sandusky Bay, Lake Huron's Saginaw Bay, and Lake Michigan's Green Bay. Stakeholder engagement and consultation will play a significant role in informing the content of the report; the IWG is soliciting input from academics, agricultural interests, industry, state and international agencies, and other stakeholder groups. To ensure that the Plan is technically sound and cost-effective, interagency collaborations and other partnerships will be identified as possible opportunities for leveraging resources, including areas of expertise, workforce, funding, or equipment. The Plan will refer to existing reports for information, such as the International Joint Commission's A Balanced Diet for Lake Erie: Reducing Phosphorous Loadings and Harmful Algal Blooms, and Annex Four of the Great Lakes Water Quality Agreement. The Plan will expand upon relevant topics as they relate to current challenges and recommendations for future efforts.

Other Information
The IWG-HABHRCA is comprised of representatives from NOAA, United States Environmental Protection Agency (USEPA), Food and Drug Administration (FDA), United States Department of Agriculture (USDA), United States Geological Survey (USGS), National Aeronautics and Space Administration (NASA), United States Navy, National Institute of Environmental Health Sciences (NIEHS), National Science Foundation (NSF), United States Food and Drug Administration (FDA), National Park Service (NPS), Centers for Disease Control and Prevention (CDC), National Aeronautics and Space Administration (NASA), United States Corps of Engineers (USACE), and the Bureau of Ocean Energy Management (BOEM).

Other Information
Stakeholders are invited to submit questions and provide input related to concerns and successes pertaining to HABs and hypoxia in the Great Lakes region. The IWG-HABHRCA continues to seek general and technical feedback on topics including:
• Regional, Great Lakes-specific priorities for:
○ Ecological, economic, and social research on the causes and impacts of HABs and hypoxia;
○ Approaches to improving monitoring and early warnings, scientific understanding, prediction and modeling, and socioeconomics of these events; and
○ Mitigating the causes and impacts of HABs and hypoxia.
• Communication and information dissemination methods that state, tribal, local, and international governments and organizations may undertake to educate and inform the public concerning HABs and hypoxia in the Great Lakes; and
• Perceived needs for handling Great Lakes HAB and hypoxia events, as well as an action strategy for managing future situations.
Inquiries and comments may be submitted via email ( IWG-HABHRCA@noaa.gov ) or via U.S. mail to Caitlin Gould at NOAA, National Centers for Coastal Ocean Science, SSMC-4, #8237, 1305 East-West Highway, Silver Spring, MD 20910. Technical feedback in the form of brief annotated bibliographic entries would be welcome. The Interagency Working Group will gladly accept public input at any time; however, only those that are received on or before May 15, 2016, will be considered when the Interagency Working Group finalizes the plan.

Other Information
Paperwork Reduction Act: 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, unless that collection displays a currently valid OMB Control Number.
Dated: May 26, 2016.
Mary C. Erickson,

Director, National Centers for Coastal Ocean Science, National Ocean Service, National Oceanic and Atmospheric Administration.
COMMITTEE FOR PURCHASE FROM PEOPLE WHO ARE BLIND OR SEVERELY DISABLED
Procurement List; Additions

AGENCY:
Committee for Purchase From People Who Are Blind or Severely Disabled.

ACTION:
Additions to the Procurement List.

SUMMARY:
This action adds services to the Procurement List that will be provided by nonprofit agencies employing persons who are blind or have other severe disabilities.

DATES:
Effective July 3, 2016.

ADDRESSES:
Committee for Purchase From People Who Are Blind or Severely Disabled, 1401 S. Clark Street, Suite 715, Arlington, Virginia, 22202-4149.

FOR FURTHER INFORMATION CONTACT:
Barry S. Lineback, Telephone: (703) 603-7740, Fax: (703) 603-0655, or email CMTEFedReg@AbilityOne.gov.

SUPPLEMENTARY INFORMATION:

Additions
On October 30, 2015 (80 FR 66880) and April 29, 2016 (81 FR 25652), the Committee for Purchase From People Who Are Blind or Severely Disabled published notices of proposed additions to the Procurement List.
After consideration of the material presented to it concerning capability of qualified nonprofit agencies to provide the services and impact of the additions on the current or most recent contractors, the Committee has determined that the services listed below are suitable for procurement by the Federal Government under 41 U.S.C. 8501-8506 and 41 CFR 51-2.4.

Regulatory Flexibility Act Certification
I certify that the following action will not have a significant impact on a substantial number of small entities. The major factors considered for this certification were:
1. The action will not result in any additional reporting, recordkeeping or other compliance requirements for small entities other than the small organizations that will provide the services to the Government.
2. The action will result in authorizing small entities to provide the services to the Government.
3. There are no known regulatory alternatives which would accomplish the objectives of the Javits-Wagner-O'Day Act (41 U.S.C. 8501-8506) in connection with the services proposed for addition to the Procurement List.

End of Certification
Accordingly, the following services are added to the Procurement List:

Services:
Service Type: Laundry Service.
Mandatory for: Virginia Army National Guard, Central Issue Facility, Defense Supply Center Richmond, Warehouse 15, Richmond, VA.
Mandatory Source(s) of Supply: Rappahannock Goodwill Industries, Inc., Fredericksburg, VA.
Contracting Activity: Dept of the Army, W7N5 USPFO ACTIVITY VA ARNG, Blackstone, VA.
Service Type: Furniture Design, Configuration and Installation Service.
Mandatory for: US Department of the Interior, Stewart Lee Udall, Department of the Interior Building, 1849 C St. & South Interior Building, 1951 Constitution Ave. NW., Washington, DC.
Mandatory Source(s) of Supply: Industries for the Blind, Inc., West Allis, WI, Contracting Activity: Office of Policy, Management, and Budget, NBC Acquisition Services Directorate, Herndon, VA.
Barry S. Lineback,

Director, Business Operations.
COMMITTEE FOR PURCHASE FROM PEOPLE WHO ARE BLIND OR SEVERELY DISABLED
Procurement List; Proposed Additions and Deletions

AGENCY:
Committee for Purchase From People Who Are Blind or Severely Disabled.

ACTION:
Proposed additions to and deletions from the Procurement List.

SUMMARY:
The Committee is proposing to add products and services to the Procurement List that will be furnished by nonprofit agencies employing persons who are blind or have other severe disabilities, and deletes products and services previously furnished by such agencies.

DATES:
Comments must be received on or before: July 3, 2016.

ADDRESSES:
Committee for Purchase From People Who Are Blind or Severely Disabled, 1401 S. Clark Street, Suite 715, Arlington, Virginia, 22202-4149.

FOR FURTHER INFORMATION CONTACT:
Barry S. Lineback, Telephone: (703) 603-7740, Fax: (703) 603-0655, or email CMTEFedReg@AbilityOne.gov.

SUPPLEMENTARY INFORMATION:
This notice is published pursuant to 41 U.S.C. 8503 (a)(2) and 41 CFR 51-2.3. Its purpose is to provide interested persons an opportunity to submit comments on the proposed actions.

Additions
If the Committee approves the proposed additions, the entities of the Federal Government identified in this notice will be required to procure the products and services listed below from nonprofit agencies employing persons who are blind or have other severe disabilities.
The following products and services are proposed for addition to the Procurement List for production by the nonprofit agencies listed:

Products :

NSN(s)—Product Name(s)
MR 10732—Hershey's Lava Cake Maker, Shipper 20732
MR 10733—Reese's Lava Cake Maker, Shipper 20732
MR 10738—Holder, Pot Lid and Utensil, Includes Shipper 20738
MR 10739—Herb Stripper, Includes Shipper 20739
Mandatory Source(s) of Supply : Winston-Salem Industries for the Blind, Inc., Winston-Salem, NC.
Mandatory for : The requirements of military commissaries and exchanges in accordance with the Code of Federal Regulations, Chapter 51, 51-6.4.
Contracting Activity : Defense Commissary Agency.
Distribution : C-List.

Services :
Service Type : Custodial and Related Service.
Mandatory for : GSA PBS Region 1, Thomas P. O'Neill, Jr. Federal Office Building, 10 Causeway Street, Boston, MA.
Mandatory Source(s) of Supply : Work, Incorporated, Dorchester, MA.
Contracting Activity : GSA PBS Region 1, Boston, MA.
Service Type : Base Supply Center.
Mandatory for : US Army, Walter Reed Army Institute of Research, 503 Robert Grant Avenue, Silver Spring, MD.
Mandatory Source(s) of Supply : Industries for the Blind, Inc., West Allis, WI.
Contracting Activity : Dept of the Army, W4PZ USA MED RSCH ACQUIS ACT, Fort Detrick, MD.

Deletions
The following products and services are proposed for deletion from the Procurement List:

Products:

NSN(s)—Product Name(s)
MR 305—Melamine Dinner Plate
MR 306—Melamine Fruit Plate
MR 307—21oz Melamine Tumbler
MR 308—Bamboo Placemat
MR 1121—Bag, Storage, Vacuum Sealed, Club Pack
MR 1130—4-Section Tray, Holiday, Melamine
MR 1131—Serving Tray, Holiday, Melamine 18” x 13”
MR 1132—Serving Bowl, Holiday, Melamine
MR 1135—Set, Spreader, 4Pc
MR 1150—Set, Mold, Cupcake, Red, Giant Cupcake, 3pc
MR 1151—Set, Pan, Bake, Perfect Brownie Pan, 3pc
MR 1152—Set, Pasta Cooker, Blue, Pasta Express, 7pc
MR 1153—Basket, Cooking, Steel, Multipurpose
MR 1155—Glove, Oven, Flexi
MR 1156—Device, Cutting, Multi-Use, Green, Snip It
MR 1157—Set, Knife and Peeler, Ceramic, Kitchen Samurai
MR 1158—Set, Meatloaf Pan and Aerated Tray
MR 1168—Carrier, Cake and Cupcake, Collapsible
MR 1169—Set, Bowl and Lid, Blue, 4 Piece
Mandatory Source(s) of Supply :
Industries for the Blind, Inc., West Allis, WI.
MR 1053—Mop, Sponge, Triple Action
MR 1083—Mop, Ratchet, Twist Action, Cotton
MR 1084—Refill, Mop, Ratchet, Twist Action, Cotton
Mandatory Source(s) of Supply : LC Industries, Inc., Durham, NC.
Contracting Activity : Defense Commissary Agency.

Services:
Service Type: Switchboard Operation Service
Mandatory for: US Air Force, Patrick Air Force Base, 1225 Pershing Place, Patrick AFB, FL
Mandatory Source(s) of Supply: Brevard Achievement Center, Inc., Rockledge, FL
Contracting Activity: Dept of the Air Force, FA252145 CONS LGC, Patrick Air Force Base, FL
Service Type: Switchboard Operation Service
Mandatory for: Keesler Air Force Base, Keesler AFB, MS
Mandatory Source(s) of Supply: Mississippi Goodworks, Inc., Gulfport, MS
Contracting Activity: Dept of the Air Force, FA7014 AFDW PK, Andrews Air Force Base, MD
Barry S. Lineback,

Director, Business Operations.
CONSUMER PRODUCT SAFETY COMMISSION
[CPSC Docket No. 16-C0003]
Teavana Corporation, Provisional Acceptance of a Settlement Agreement and Order

AGENCY:
Consumer Product Safety Commission.

ACTION:
Notice.

SUMMARY:
It is the policy of the Commission to publish settlements which it provisionally accepts under the Consumer Product Safety Act in the Federal Register in accordance with the terms of the Consumer Product Safety Commission's regulations. Published below is a provisionally-accepted Settlement Agreement with Teavana Corporation containing a civil penalty in the amount of three million, seven hundred fifty thousand U.S. dollars (US $3,750,000) within thirty (30) days of service of the Commission's final Order accepting the Settlement Agreement.

DATES:
Any interested person may ask the Commission not to accept this agreement or otherwise comment on its contents by filing a written request with the Office of the Secretary by June 20, 2016.

ADDRESSES:
Persons wishing to comment on this Settlement Agreement should send written comments to the Comment 16-C0003, Office of the Secretary, Consumer Product Safety Commission, 4330 East West Highway, Room 820, Bethesda, Maryland 20814-4408.

FOR FURTHER INFORMATION CONTACT:
Leah Wade, Trial Attorney, Division of Compliance, Office of the General Counsel, Consumer Product Safety Commission, 4330 East West Highway, Bethesda, Maryland 20814-4408; telephone (301) 504-7225.

SUPPLEMENTARY INFORMATION:
The text of the Agreement and Order ^1 appears below.
^1 The Commission voted (3-2) to provisionally accept the Settlement Agreement and Order regarding Teavana Corporation. Chairman Kaye, Commissioner Adler, Commissioner Robinson voted to provisionally accept the Settlement Agreement and Order. Commissioner Buerkle and Commissioner Mohorovic voted to reject the Settlement Agreement and Order. Commissioner Mohorovic filed a statement regarding this matter. The statement is available at the Office of the Secretary or the CPSC Web site, www.cpsc.gov.
Dated: May 27, 2016.
Todd A. Stevenson,

Secretary.

UNITED STATES OF AMERICA CONSUMER PRODUCT SAFETY COMMISSION
In the Matter of: TEAVANA CORPORATION, CPSC Docket No.: 16-C0003

SETTLEMENT AGREEMENT
1. In accordance with the Consumer Product Safety Act, 15 U.S.C. 2051−2089 (“CPSA”) and 16 CFR 1118.20, Teavana Corporation (“Teavana”), and the United States Consumer Product Safety Commission (“Commission”), through its staff, hereby enter into this Settlement Agreement (“Agreement”). The Agreement, and the incorporated attached Order, resolve staff's charges that Teavana is subject to civil penalties in this matter, under section 20 of the CPSA, 15 U.S.C. 2069, as set forth below.

THE PARTIES
2. The Commission is an independent federal regulatory agency, established pursuant to, and responsible for, the enforcement of the CPSA, 15 U.S.C. 2051−2089. By executing the Agreement, staff is acting on behalf of the Commission, pursuant to 16 CFR 1118.20(b). The Commission issues the Order under the provisions of the CPSA.
3. Teavana Corporation was incorporated in Georgia, and, at the time of the matters recited in this Agreement, its principal place of business was in Atlanta, Georgia.

STAFF CHARGES
4. Between August 2007 and April 2013, Teavana imported for sale approximately 445,000 Double-Walled Glass Tea Tumblers (“Tumblers”) in the United States. Most of the models of the Tumblers are designed to hold hot beverages, and one model was intended for cold beverages.
5. The Tumblers are a “consumer product” that was “distributed in commerce,” as those terms are defined or used in sections 3(a)(5) and (8) of the CPSA, 15 U.S.C. 2052(a)(5) and (8). Teavana was a “manufacturer,” “distributor” and “retailer” of the Tumblers, as such terms are defined in sections 3(a)(7), (11) and (13) of the CPSA, 15 U.S.C. 2052(a)(7), (11) and (13).
6. Teavana had information reasonably supporting the conclusion that the Tumblers are defective or created an unreasonable risk of serious injury or death because they can unexpectedly explode, shatter, or break during normal use, posing a laceration and burn hazard.
7. Between January 2010 and March 2013, Teavana received numerous reports of the Tumblers unexpectedly exploding, shattering or breaking, including reports of six injuries to consumers who were cut by broken glass or burned by hot liquid while holding a Tumbler that exploded, shattered, or broke.
8. Despite having information reasonably supporting the conclusion that the Tumblers contained a defect which could create a substantial product hazard or create an unreasonable risk of serious injury or death, Teavana did not notify the Commission immediately of such defect or risk, as required by sections 15(b)(3) and (4) of the CPSA, 15 U.S.C. 2064(b)(3) and (4).
9. In failing to immediately inform the Commission about the defect or unreasonable risk associated with the Tumblers, Teavana knowingly violated section 19(a)(4) of the CPSA, 15 U.S.C. 2068(a)(4), as the term “knowingly” is defined in section 20(d) of the CPSA, 15 U.S.C. 2069(d).
10. Pursuant to section 20 of the CPSA, 15 U.S.C. 2069, Teavana is subject to civil penalties for its knowing violation of section 19(a)(4) of the CPSA, 15 U.S.C. 2068(a)(4).

RESPONSE OF TEAVANA
11. Teavana's settlement of this matter does not constitute an admission of staff's charges as set forth in paragraphs 4 through 10 above.
12. In March 2013, Teavana notified the Commission pursuant to section 15(b) of the CPSA, 15 U.S.C. 2064(b) concerning Teavana's receipt of complaints and incident reports about the Tumblers.
13. On May 20, 2013, in conjunction with the Commission, Teavana voluntarily announced a recall of eleven different models of double-walled borosilicate glass Tumblers (made by three different manufacturers), including a Tumbler model for which Teavana had received no complaints or incident reports, and some Tumbler models for which only a few complaints were received.
14. The voluntary recall of the Tumblers, as well as the section 15(b) reporting, by Teavana was conducted out of an abundance of caution and without Teavana having determined or concluded that any of the eleven different models of Tumblers contained a defect, posed a substantial product hazard, or created an unreasonable risk of serious injury or death.
15. The Tumblers were all well-constructed using a high quality glass with superior hardness and resistance to temperature shock.

AGREEMENT OF THE PARTIES
16. Under the CPSA, the Commission has jurisdiction over the matter involving the Tumblers and over Teavana.
17. The parties enter into the Agreement for settlement purposes only. The Agreement does not constitute an admission by Teavana or a determination by the Commission that Teavana violated the CPSA's reporting requirements.
18. In settlement of staff's charges, and to avoid the cost, distraction, delay, uncertainty, and inconvenience of protracted litigation, Teavana shall pay a civil penalty in the amount of three million, seven hundred and fifty thousand U.S. dollars (US $3,750,000) within thirty (30) calendar days after receiving service of the Commission's final Order accepting the Agreement. All payments to be made under the Agreement shall constitute debts owing to the United States and shall be made by electronic wire transfer to the United States via: http://www.pay.gov for allocation to, and credit against, the payment obligations of Teavana under this Agreement. Failure to make such payment by the date specified in the Commission's Order shall constitute Default.
19. All unpaid amounts, if any, due and owing under the Agreement, shall constitute a debt due and immediately owing by Teavana to the United States, and interest shall accrue and be paid by Teavana at the federal legal rate of interest set forth at 28 U.S.C. 1961(a) and (b) from the date of Default, until all amounts due have been paid in full (hereinafter “Default Payment Amount” and “Default Interest Balance”). Teavana shall consent to a Consent Judgment in the amount of the Default Payment Amount and Default Interest Balance, and the United States, at its sole option, may collect the entire Default Payment Amount and Default Interest Balance, or exercise any other rights granted by law or in equity, including, but not limited to, referring such matters for private collection; and Teavana agrees not to contest, and hereby waives and discharges any defenses, to any collection action undertaken by the United States, or its agents or contractors, pursuant to this paragraph. Teavana shall pay the United States all reasonable costs of collection and enforcement under this paragraph, respectively, including reasonable attorney's fees and expenses.
20. After staff receives this Agreement executed on behalf of Teavana, staff shall promptly submit the Agreement to the Commission for provisional acceptance. Promptly following provisional acceptance of the Agreement by the Commission, the Agreement shall be placed on the public record and published in the Federal Register , in accordance with the procedures set forth in 16 CFR 1118.20(e). If the Commission does not receive any written request not to accept the Agreement within fifteen (15) calendar days, the Agreement shall be deemed finally accepted on the 16th calendar day after the date the Agreement is published in the Federal Register , in accordance with 16 CFR 1118.20(f).
21. This Agreement is conditioned upon, and subject to, the Commission's final acceptance, as set forth above, and it is subject to the provisions of 16 CFR 1118.20(h). Upon the later of: (i) Commission's final acceptance of this Agreement and service of the accepted Agreement upon Teavana, and (ii) the date of issuance of the final Order, this Agreement shall be in full force and effect and shall be binding upon the parties.
22. Effective upon the later of: (i) The Commission's final acceptance of the Agreement and service of the accepted Agreement upon Teavana, and (ii) and the date of issuance of the final Order, for good and valuable consideration, Teavana hereby expressly and irrevocably waives and agrees not to assert any past, present, or future rights to the following, in connection with the matter described in this Agreement: (i) An administrative or judicial hearing; (ii) judicial review or other challenge or contest of the Commission's actions; (iii) a determination by the Commission of whether Teavana failed to comply with the CPSA and the underlying regulations; (iv) a statement of findings of fact and conclusions of law; and (v) any claims under the Equal Access to Justice Act.
23. Teavana represents and agrees that it will comply with and maintain the comprehensive compliance program of its parent corporation designed to ensure compliance with the CPSA and regulations enforced by the Commission. That program includes written standards, policies and procedures to ensure relevant reports and complaints are sent to compliance personnel, recalled goods are properly disposed of, employees have a confidential process to report compliance-related issues to officials with authority to act, CPSA compliance responsibility is exercised with due care by senior management, company policies are communicated to applicable personnel, records are retained for five years, and compliance program documents will be made available to staff upon reasonable request.
24. Teavana represents and agrees that it will comply with and maintain the comprehensive system of internal controls and procedures of its parent corporation. These procedures are designed to ensure Teavana discloses to the Commission information in accordance with applicable law, reports information in a timely, truthful, complete and accurate manner as required by the CPSA, and periodically evaluates these controls and procedures to ensure they are adequate to allow Teavana to report to the Commission in accordance with applicable law.
25. The parties acknowledge and agree that the Commission may publicize the terms of the Agreement and the Order.
26. Teavana represents that the Agreement: (i) Is entered into freely and voluntarily, without any degree of duress or compulsion whatsoever; (ii) has been duly authorized; and (iii) constitutes the valid and binding obligation of Teavana, enforceable against Teavana in accordance with its terms. The individuals signing the Agreement on behalf of Teavana represent and warrant that they are duly authorized by Teavana to execute the Agreement.
27. The signatories represent that they are authorized to execute this Agreement.
28. The Agreement is governed by the laws of the United States.
29. The Agreement and the Order shall apply to, and be binding upon, Teavana and each of its parents, successors, transferees, and assigns, and a violation of the Agreement or Order may subject Teavana, and each of its parents, successors, transferees, and assigns, to appropriate legal action.
30. The Agreement and the Order constitute the complete agreement between the parties on the subject matter contained therein.
31. The Agreement may be used in interpreting the Order. Understandings, agreements, representations, or interpretations apart from those contained in the Agreement and the Order may not be used to vary or contradict their terms. For purposes of construction, the Agreement shall be deemed to have been drafted by both of the parties and shall not, therefore, be construed against any party, for that reason, in any subsequent dispute.
32. The Agreement may not be waived, amended, modified, or otherwise altered, except as in accordance with the provisions of 16 CFR 1118.20(h). The Agreement may be executed in counterparts.
33. If any provision of the Agreement or the Order is held to be illegal, invalid, or unenforceable under present or future laws effective during the terms of the Agreement and the Order, such provision shall be fully severable. The balance of the Agreement and the Order shall remain in full force and effect, unless the Commission and Teavana agree in writing that severing the provision materially affects the purpose of the Agreement and the Order.

TEAVANA CORPORATION
Dated: May 19, 2016
By:
Bernard Acoca
President, Teavana Corporation
Dated: May 19, 2016
By:
Georgia C. Ravitz
Arent Fox LLP
1717 K Street, NW
Washington, D.C. 20006-5344
Counsel to Teavana Corporation

U.S. CONSUMER PRODUCT SAFETY COMMISSION
Mary T. Boyle
Acting General Counsel
Mary B. Murphy
Assistant General Counsel
Dated: May 19, 2016
By:
Leah Wade
Trial Attorney
Division of Compliance
Office of the General Counsel

UNITED STATES OF AMERICA CONSUMER PRODUCT SAFETY COMMISSION
In the Matter of: TEAVANA CORPORATION, CPSC Docket No.: 16-C0003

ORDER
Upon consideration of the Settlement Agreement entered into between Teavana Corporation (“Teavana”), and the U.S. Consumer Product Safety Commission (“Commission”), and the Commission having jurisdiction over the subject matter and over Teavana, and it appearing that the Settlement Agreement and the Order are in the public interest, it is:
ORDERED that the Settlement Agreement be, and is, hereby, accepted; and it is
FURTHER ORDERED that Teavana shall comply with the terms of the Settlement Agreement and shall pay a civil penalty in the amount of three million, seven hundred fifty thousand U.S. dollars (US $3,750,000) within thirty (30) days after service of the Commission's final Order accepting the Settlement Agreement. The payment shall be made by electronic wire transfer to the Commission via: http://www.pay.gov. Upon the failure of Teavana to make the foregoing payment when due, interest on the unpaid amount shall accrue and be paid by Teavana at the federal legal rate of interest set forth at 28 U.S.C. 1961(a) and (b). If Teavana fails to make such payment or to comply in full with any other provision of the Settlement Agreement, such conduct will be considered a violation of the Settlement Agreement and Order.
Provisionally accepted and provisional Order issued on the 27th day of May, 2016.
BY ORDER OF THE COMMISSION:
Todd A. Stevenson,

Secretary, U.S. Consumer Product Safety Commission.
DEPARTMENT OF DEFENSE
Office of the Secretary
[Docket ID: DoD-2015-OS-0004]
Proposed Collection; Comment Request

AGENCY:
Office of the Under Secretary of Defense for Personnel and Readiness, DoD.

ACTION:
Notice.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995, the Office of the Under Secretary of Defense for Personnel and Readiness 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 August 2, 2016.

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 Deputy Chief Management Officer, Directorate for Oversight and Compliance, 4800 Mark Center Drive, Mailbox #24, 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.
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at http://www.regulations.gov for submitting comments. Please submit comments on any given form identified by docket number, form number, and title.

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 Deputy Assistant Secretary of Defense, Military Community and Family Policy, ATTN: Casualty Affairs, 4000 Defense Pentagon, Washington, DC 20301-4000.

SUPPLEMENTARY INFORMATION:
Title; Associated Form; and OMB Number: Mortuary Affairs Forms; Statement of Disposition of Military Remains, DD Form X634; Disposition of Remains Election Statement Initial Notification of Identified Partial Remains, DD Form X635; Disposition of Remains Election Statement Notification of Subsequently Identified Partial Remains, DD Form X636; Disposition of Organs Retained for Extended Examination, DD Form X637; Advanced Restorative Art of Remains, DD Form X638; Election for Air Transportation of Remains of Casualties Dying in a Theater of Combat Operations, DD Form X639; OMB Control Number 0704-XXXX.
Needs and Uses: The information collection requirement is necessary to obtain the election (as applicable) of the Person Authorized to Direct Disposition (PADD) or the Person Authorized to Effect Disposition (PAED) of the remains of the decedent. These forms were directed by the Secretary of Defense for transparency and standardization of the mortuary procedures as part of the Final Report of the Dover Port Mortuary Independent Review Subcommittee Implementation Plan and 180-day study. The applicable form(s) is included in the individual case file of the decedent.
Affected Public: Business or other for profit; Individuals or Household.
Annual Burden Hours: 225.
Number of Respondents: 900.
Responses per Respondent: 1.
Annual Responses: 900.
Average Burden Per Response: 15 minutes.
Frequency: On occasion.
The respondents are the PADD or PAED of the decedent for whom mortuary services as described on the applicable form (DD Form X634; DD Form X635; DD Form X636; DD Form X637; DD Form X638; or DD Form X639) is recommended or required, and the witness to that election. The PADD or PAED documents their election, and the PADD or PAED and witness sign the applicable form to formalize this process and document the election of the PADD or PAED as applicable. These forms become a part of the Official Individual Deceased Personnel File. If the PADD or PAED does not sign these forms, then the Department cannot provide mortuary and transportation services as requested by the PADD or PAED. Currently there is a lack of standardization across the Military Services, as each Service currently utilizes different forms for these elections and they do not all capture the same information even on similar forms. Standardizing the information collected is essential in maintaining the transparency and integrity of the mortuary affairs process.
Dated: May 31, 2016.
Aaron Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF DEFENSE
Office of the Secretary
Charter Renewal of Department of Defense Federal Advisory Committees

AGENCY:
Department of Defense.

ACTION:
Renewal of Federal Advisory Committee.

SUMMARY:
The Department of Defense (DoD) is publishing this notice to announce that it is renewing the charter for the Board of Visitors for the Western Hemisphere Institute for Security Cooperation (“the Board”).

FOR FURTHER INFORMATION CONTACT:
Jim Freeman, Advisory Committee Management Officer for the Department of Defense, 703-692-5952.

SUPPLEMENTARY INFORMATION:
The Board's charter is being renewed in accordance with the Federal Advisory Committee Act (FACA) of 1972 (5 U.S.C., Appendix, as amended) and 41 CFR 102-3.50(d). The Board's charter and contact information for the Board's Designated Federal Officer (DFO) can be found at http://www.facadatabase.gov/.
The Board provides the Secretary of Defense and the Deputy Secretary of Defense, through the Secretary of the Army, with independent advice and recommendations on matters pertaining to the operations and management of the Western Hemisphere Institute for Security Cooperation (“the Institute”).
The Board will be composed of 14 members, 6 of whom are designated by the Secretary of Defense including, to the extent practicable, persons from academia, religious institutions, and human rights communities. The Secretary of Defense will also affirm the appointments, designated in statute, of the senior military officer responsible for training and doctrine in the U.S. Army (or designee) and the Commanders of the Combatant Commands with geographic responsibility for the Western Hemisphere (U.S. Northern Command and U.S. Southern Command) (or the designees of those officers). The Board will also be composed of:
a. Two Members of the Senate (the Chair and Ranking Member of the Armed Services Committee or a designee of either of them);
b. Two Members of the House of Representatives (the Chair and Ranking Member of the Armed Services Committee or a designee of either of them); and
c. One person designated by the Secretary of State (10 U.S.C. 2166(e)(1)).
Members of the Board who are not full-time or permanent part-time Federal officers or employees will be appointed as experts or consultants pursuant to 5 U.S.C. 3109 to serve as special government employee (SGE) members. Board members who are full-time or permanent part-time Federal officers or employees will be appointed pursuant to 41 CFR 101-3.130(a) to serve as RGE members.
All members of the Board are appointed to provide advice on behalf of the Government on the basis of their best judgment without representing any particular point of view and in a manner that is free from conflict of interest. Except for reimbursement of official Board-related travel and per diem, Board members serve without compensation.
The DoD, as necessary and consistent with the Board's mission and DoD policies and procedures, may establish subcommittees, task forces, or working groups to support the Board, and all subcommittees must operate under the provisions of FACA and the Government in the Sunshine Act. Subcommittees will not work independently of the Board and must report all recommendations and advice solely to the Board for full deliberation and discussion. Subcommittees, task forces, or working groups have no authority to make decisions and recommendations, verbally or in writing, on behalf of the Board. No subcommittee or any of its members can update or report, verbally or in writing, directly to the DoD or any Federal officers or employees.
The Board has two permanent subcommittees, whose members will be composed of individuals with professional experience in academia, religious institutions, and human rights communities. Each subcommittee will be composed of no more than eight members.
a. Subcommittee on Education: Provides independent advice and recommendations for the Board's consideration on the Institute's curriculum and the current challenges faced by our international partners' government, military, and law enforcement agencies, to determine if new topics should be considered for inclusion; and also makes recommendations on adjustments to the curriculum or courses that are no longer applicable.
b. Subcommittee on Outreach: Provides independent advice and recommendations for the Board's consideration on developing an outreach plan of action to strengthen support for the Institute among influential officials from our international partners to increase student and instructor attendance and encourage burden sharing; strengthen support for the Institute from key U.S. military, civilian, governmental and interagency personnel to sustain funding levels and expand the Institute's role; and develop an outreach plan to identify new partner nations that may be interested in sending students, instructors, guest lectures, or liaison officers to the Institute. The Board's DFO, pursuant to DoD policy, must be a full-time or permanent part-time DoD employee, and must be in attendance for the duration of each and every Board/subcommittee meeting. The public or interested organizations may submit written statements to the Board membership about the Board's mission and functions. Such statements may be submitted at any time or in response to the stated agenda of planned Board. All written statements must be submitted to the Board's DFO who will ensure the written statements are provided to the membership for their consideration.
Dated: May 27, 2016.
Aaron Siegel,

Alternate OSD Federal Register Liaison Officer, Department of Defense.
DEPARTMENT OF DEFENSE
Department of the Army, U.S. Army Corps of Engineers
DEPARTMENT OF THE INTERIOR
Bureau of Reclamation
Notice of Availability of the Draft Environmental Impact Statement for the Lower Yellowstone Intake Diversion Dam Fish Passage Project, Dawson County, Montana

AGENCIES:
Department of the Army, U.S. Army Corps of Engineers, DoD; Bureau of Reclamation, Interior.

ACTION:
Notice.

SUMMARY:
The U.S. Army Corps of Engineers (Corps) and Reclamation, as joint lead agencies, have made available for public review and comment the Lower Yellowstone Intake Diversion Dam Fish Passage Project Draft Environmental Impact Statement (Draft EIS). The Draft EIS analyzes and discloses potential effects associated with the proposed Federal action to improve passage for endangered pallid sturgeon and other native fish at Intake Diversion Dam in the lower Yellowstone River while continuing the effective and viable operation of the Lower Yellowstone Project.

DATES:
Submit written comments on the Draft EIS on or before July 18, 2016.
Two public meetings to share information and for the public to provide oral or written comments will be held on:
• Tuesday, June 28, 2016, 5:30 p.m. to 9:00 p.m., in Sidney, MT and
• Wednesday, June 29, 2016, 5:30 p.m. to 9:00 p.m., in Glendive, MT.
Each meeting will begin with an open house at 5:30 p.m. followed by a formal presentation at 6:00 p.m.

ADDRESSES:
Send written comments, requests to be added to the mailing list, or requests for sign language interpretation for the hearing impaired or other special assistance needs to U.S. Army Corps of Engineers Omaha District, ATTN: CENWO-PM-AA, 1616 Capitol Ave, Omaha, NE 68102; or email to cenwo-planning@usace.army.mil.
The public meetings will be held at the following locations:
• Richland County Fair Event Center, 5th Street SW., Sidney, MT.
• Dawson County High School Auditorium, 900 N. Merrill Ave., Glendive, MT.

FOR FURTHER INFORMATION CONTACT:
Ms. Tiffany Vanosdall, U.S. Army Corps of Engineers, 1616 Capitol Ave, Omaha, NE 68102, or tiffany.k.vanosdall@usace.army.mil.

SUPPLEMENTARY INFORMATION:
The Corps and Reclamation are issuing this notice pursuant to section 102(2)(c) of the National Environmental Policy Act of 1969 (NEPA), as amended, 42 U.S.C. 4321 et seq.; the Council on Environmental Quality's (CEQ) regulations for implementing the procedural provisions of NEPA, 43 CFR parts 1500 through 1508; the Department of the Interior's NEPA regulations, 43 CFR part 46.
Background Information. Reclamation's Lower Yellowstone Project is located in eastern Montana and western North Dakota. Intake Diversion Dam is located approximately 70 miles upstream of the confluence of the Yellowstone and Missouri rivers near Glendive, Montana. The Lower Yellowstone Project was authorized by the Secretary of the Interior on May 10, 1904. Construction of the Lower Yellowstone Project began in 1905 and included Intake Diversion Dam (also known as Yellowstone River Diversion Dam)—a wood and stone diversion dam that spans the Yellowstone River and diverts water into the Main Canal for irrigation. The Lower Yellowstone Project was authorized to provide a dependable water supply sufficient to irrigate approximately 54,000 acres of land on the benches above the west bank of the Yellowstone River. Water is also supplied to irrigate approximately 830 acres in the Intake Irrigation Project and 2,200 acres in the Savage Unit. The average annual volume of water diverted for these projects is 327,046 acre-feet.
The U.S. Fish and Wildlife Service (Service) listed the pallid sturgeon as endangered under the Endangered Species Act (ESA) in 1990. The best available science suggests Intake Diversion Dam impedes upstream migration of pallid sturgeon and their access to spawning and larval drift habitats. The lower Yellowstone River is considered by the Service to provide one of the best opportunities for recovery of pallid sturgeon.
Section 7(a)(2) requires each Federal agency to consult on any action authorized, funded, or carried out by the agency to ensure it does not jeopardize the continued existence of any endangered or threatened species. Reclamation has been in formal consultation with the Service to identify potential conservation measures to minimize adverse effects to pallid sturgeon associated with continued operation of the Lower Yellowstone Project. The Pallid Sturgeon Recovery Plan specifically identifies providing passage at Intake Diversion Dam to protect and restore pallid sturgeon populations. By providing passage at Intake Diversion Dam, approximately 165 river miles of spawning and larval drift habitat would become accessible in the Yellowstone River.
Section 3109 of the 2007 Water Resources Development Act authorizes the Corps to use funding from the Missouri River Recovery and Mitigation Program to assist Reclamation in the design and construction of Reclamation's Lower Yellowstone Project at Intake, Montana for the purpose of ecosystem restoration. Planning and construction of the Intake Project is a Reasonable and Prudent Alternative for the Corps in the 2003 Missouri River Amended Biological Opinion as amended by letter exchange in 2009, 2010, and 2013. The Reclamation Act/Newlands Act of 1902 (Pub. L. 161) authorizes Reclamation to construct and maintain the facilities associated with the Lower Yellowstone Project, which includes actions or modifications necessary to comply with Federal law such as the ESA.
This notice announces the availability of the Draft EIS for the Lower Yellowstone Intake Diversion Dam Fish Passage Project and begins a 45-day public comment period on the range of alternatives and effects analysis. Analysis in the Draft EIS will support a decision on the selection of an alternative. Current and past project information and analyses can be accessed at: www.usbr.gov/gp/mtao/loweryellowstone.
The Corps and Reclamation are serving as joint lead Federal agencies for the NEPA analysis process and preparation of the Draft EIS. The Corps is the administrative lead for NEPA compliance activities during the preparation of the Draft EIS. State, Federal, and local agencies with specialized expertise or jurisdictional responsibilities are participating as cooperating agencies. Cooperating agencies include the U.S. Fish and Wildlife Service; Western Area Power Administration; Montana Fish, Wildlife and Parks; Montana Department of Natural Resources and Conservation; and the Lower Yellowstone Irrigation Project.
The purpose of the Lower Yellowstone Intake Diversion Dam Fish Passage Project is to improve passage for the endangered pallid sturgeon while continuing the effective and viable operation of the Lower Yellowstone Project. The Draft EIS analyzes six alternatives which includes a No Action Alternative.
The No Action Alternative would continue the ongoing operations, maintenance, and rehabilitation of the Lower Yellowstone Project including diversion up to 1,374 cubic feet per second (cfs) of water through the screened headworks; rocking of the weir as needed to continue diversions during low flow periods; routine maintenance of the headworks, weir, and irrigation distribution facilities and pumps; rehabilitation of the trolley; and associated activities to comply with state and Federal law.
The Rock Ramp Alternative includes abandonment of the existing weir; construction of a new concrete weir and shallow sloped rock ramp to improve instream fish passage; maintenance of the new weir and rock ramp, continued diversion up to 1,374 cfs through the screened headworks; and continued operation and maintenance of the irrigation distribution facilities and pumps.
The Bypass Channel Alternative (Preferred Alternative) includes abandonment of the existing weir; construction of a new concrete weir; construction, operation, and maintenance of a two-mile long bypass channel for fish passage around the weir; placement of fill in the upstream portion of existing side channel for stabilization; continued diversion up to 1,374 cfs through the screened headworks; and continued operation and maintenance of the irrigation distribution facilities and pumps.
The Modified Side Channel Alternative includes operation, maintenance, and rehabilitation of the existing weir and trolley; construction, operation, and maintenance of a 4.5-mile long bypass channel created by modifying the existing high-flow channel for fish passage around the weir; continued diversion up to 1,374 cfs through the screened headworks; construction, operation, and maintenance of an access bridge spanning the high-flow bypass channel; and continued operation and maintenance of the irrigation distribution facilities and pumps.
The Multiple Pump Alternative includes the construction, operation, and maintenance of 5 screened surface pumping stations; removal of the existing weir; improved power infrastructure to increase capacity; land acquisition as necessary for power infrastructure and pump stations; continued diversion up to 1,374 cfs through the screened headworks; and continued operation and maintenance of the irrigation distribution facilities and existing pumps.
The Multiple Pumps with Conservation Measures Alternative includes the construction, operation, and maintenance of seven pumping stations each with six Ranney Wells (total of 42 Ranney Wells); removal of the existing weir; construction, operation, and maintenance of wind turbines and infrastructure to provide power to pumping stations; land acquisition as necessary for power infrastructure and pump stations; diversion up to 608 cfs through the screened headworks or by pumping depending upon river flow; reconstruction of the Main Canal; installation of water conservation measures such as conversion of flood irrigation to sprinkler, lining canals, and piping laterals; and continued operation and maintenance of the irrigation distribution facilities and existing pumps.
The Draft EIS evaluates the potential effects on the human environmental associated with each of the alternatives. Issues addressed include: Land use and vegetation; social and economic conditions; recreation; visual resources; water resources; air quality; climate change; biological resources; cultural resources; geomorphology; utilities and infrastructure; noise; Indian trust assets; and environmental justice.
Schedule. A 45-day public comment period will begin June 3, 2016. Comments on the Draft EIS must be received by July 18, 2016. The Corps and Reclamation will consider and respond to all comments received on the Draft EIS when preparing the Final EIS. The Corps and Reclamation expect to issue the Final EIS in fall 2016, at which time a Notice of Availability will be published in the Federal Register . A Record of Decision is expected in winter 2016.
The public meeting date or location may change based on inclement weather or exceptional circumstances. If the meeting date or location is changed, the Corps and Reclamation will issue a press release and post it on the web at www.usbr.gov/gp/mtao/loweryellowstone to announce the updated meeting details.
Special Assistance for Public Meeting. The meeting facility is physically accessible to people with disabilities. People needing special assistance to attend and/or participate in the meeting should contact: U.S. Army Corp of Engineers Omaha District, ATTN: CENWO-PM-AA, 1616 Capitol Ave, Omaha, NE 68102; or email to cenwo-planning@usace.army.mil. To allow sufficient time to process special requests, please contact no later than one week before the public meeting.
Public Disclosure Statement. If you wish to comment, you may mail or email your comments as indicated under the ADDRESSES section of this notice. Before including your address, phone number, email address, or any other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made available to the public at any time. While you can request in your comment for us to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
Arlo J. Reese,

Major, Corps of Engineers, Deputy District Commander.
John F. Soucy,

Deputy Regional Director, Great Plains Region, Bureau of Reclamation.
DEPARTMENT OF DEFENSE
Department of the Army, Corps of Engineers
Availability of a Draft Integrated Feasibility Report (Feasibility Report/Environmental Impact Statement), Flood Risk Management Study, Little Colorado River at Winslow, Navajo County, AZ

AGENCY:
Department of the Army, U.S. Army Corps of Engineers, DoD.

ACTION:
Notice of availability.

SUMMARY:
The U.S. Army Corps of Engineers (Corps), in cooperation with Navajo County Flood Control District, announces the availability of a Draft Integrated Feasibility Report (Draft IFR) including Feasibility Report and Environmental Impact Statement (EIS) for the Little Colorado River at Winslow Flood Risk Management Study, Navajo County, AZ for review and comment. The study evaluates alternatives to reduce the risk of damages and to reduce the life, safety, and health risks caused by flooding of the Little Colorado River (LCR) to the City of Winslow, surrounding community, and public and private infrastructure. A Notice of Intent to prepare the Draft EIS was published in the Federal Register on February 27, 2009 (74 FR 8918).

DATES:
The Draft IFR is available for a 45-day review period pursuant to the National Environmental Policy Act (NEPA). Written comments pursuant to the NEPA will be accepted until the close of public review at close of business on July 18, 2016.

ADDRESSES:
Questions or comments concerning the Draft IFR may be directed to: Eduardo T. De Mesa; Chief, Planning Division; U.S. Army Corps of Engineers; Los Angeles District; 915 Wilshire Boulevard, Suite 930; ATTN: Mr. Kirk C. Brus, CESPL-PD-RL; Los Angeles, CA 90017-3401 or LCRWinslow@usace.army.mil.

FOR FURTHER INFORMATION CONTACT:
Mr. Richard Legere, U.S. Army Corps of Engineers, Los Angeles District, phone number (602) 230-6907, and Mr. Kirk C. Brus, U.S. Army Corps of Engineers, Los Angeles District, phone number (213) 452-3876.

SUPPLEMENTARY INFORMATION:
As part of the public involvement process, notice is hereby given by the Corps Los Angeles District of public meetings to be held at the Church of Jesus Christ of Latter-day Saints, 205 Lee Street, Winslow, AZ 86047, from 3:00 p.m. to 5:00 p.m. and 6:30 p.m. to 9:30 p.m. on Thursday, June 9, 2016. The public meeting will allow participants the opportunity to comment on the IFR. Attendance at the public hearing is not necessary to provide comments. Written comments may also be given to the contacts listed under ADDRESSES .
The document is available for review at:
(1) Online at: http://www.spl.usace.army.mil/Missions/CivilWorks/ProjectsStudies/LittleColoradoRiverWinslow.aspx.
(2) Navajo County Library District; 121 W. Buffalo Street; Holbrook, AZ 86025; 1 CD and 1 Hard Copy.
(3) Winslow Public Library; 420 W. Gilmore Street; Winslow, AZ 86047; 1 CD and 1 Hard Copy.
(4) Holbrook Public Library; 403 Park St.; Holbrook, AZ 86025.
(5) Hopi Public Library; 1 Main Street; c/o Hopi Education Dept.; Kykotsmovi, AZ 86039; 1 CD and 1 Hard Copy.
(6) Navajo County Flood Control District, 100 W. Public Works Drive; Holbrook, AZ 86025.
(7) U.S. Army Corps of Engineers, Los Angeles District; 915 Wilshire Blvd., Los Angeles, CA 90017.
Dated: May 25, 2016.
Kirk E. Gibbs,

Colonel, U.S. Army Commander and District Engineer.
DEPARTMENT OF EDUCATION
[Docket No. ED-2016-ICCD-0065]
Agency Information Collection Activities; Comment Request; Study of the Turnaround School Leaders Program

AGENCY:
Department of Education (ED), Office of Planning, Evaluation and Policy Development (OPEPD).

ACTION:
Notice.

SUMMARY:
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501 et seq. ), ED is proposing a new information collection.

DATES:
Interested persons are invited to submit comments on or before August 2, 2016.

ADDRESSES:
To access and review all the documents related to the information collection listed in this notice, please use http://www.regulations.gov by searching the Docket ID number ED-2016-ICCD-0065. Comments submitted in response to this notice should be submitted electronically through the Federal eRulemaking Portal at http://www.regulations.gov by selecting the Docket ID number or via postal mail, commercial delivery, or hand delivery. Please note that comments submitted by fax or email and those submitted after the comment period will not be accepted. Written requests for information or comments submitted by postal mail or delivery should be addressed to the Director of the Information Collection Clearance Division, U.S. Department of Education, 400 Maryland Avenue SW., LBJ, Room, 2E-103, Washington, DC 20202-4537.

FOR FURTHER INFORMATION CONTACT:
For specific questions related to collection activities, please contact Ivy Morgan, 202-401-7767.

SUPPLEMENTARY INFORMATION:
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology. Please note that written comments received in response to this notice will be considered public records.
Title of Collection: Study of the Turnaround School Leaders Program.
OMB Control Number: 1875-NEW.
Type of Review: A new information collection.
Respondents/Affected Public: State, Local, and Tribal Governments.
Total Estimated Number of Annual Responses: 62.
Total Estimated Number of Annual Burden Hours: 60.
Abstract: The study will examine the implementation of the Turnaround School Leaders Program (TSLP) and provide information on how grantees (1) identify, develop, and support leaders and aspiring leaders of low-performing schools; (2) adjust their project plans, (3) use data to examine progress, and (4) work with project partners to meet goals. The ultimate purpose of the study is to glean specific lessons learned for turnaround leadership development (for the field), program improvement (for program staff), and program design (for policy makers). The study will include surveys of all (12) Cohort 1 grantees; case studies of seven Cohort 1 grantees, including each grantees' partners; and an analysis of extant data, including grantee applications, early outcomes data, and other relevant project-specific data.
Dated: May 31, 2016.
Kate Mullan,

Acting Director, Information Collection Clearance Division, Office of the Chief Privacy Officer, Office of Management.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
Combined Notice of Filings #2
Take notice that the Commission received the following exempt wholesale generator filings:
Docket Numbers: EG16-108-000.
Applicants: Deepwater Wind Block Island, LLC.
Description: Notice of Self-Certification of Exempt Wholesale Generator Status of Deepwater Wind Block Island, LLC.
Filed Date: 5/27/16.
Accession Number: 20160527-5165.
Comments Due: 5 p.m. ET 6/17/16.
Take notice that the Commission received the following electric rate filings:
Docket Numbers: ER16-938-003.
Applicants: Arizona Public Service Company.
Description: Compliance filing: Compliance Filing—OATT Revisions to be effective 5/1/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5160.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1343-001.
Applicants: Midcontinent Independent System Operator, Inc.
Description: Tariff Amendment: 2016-05-27_SA 2909 Amended Certificate of Conurrence METC-ITCI IA to be effective 6/1/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5167.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1801-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-27 IMM Response Period Filing to be effective 5/28/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5096.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1802-000.
Applicants: Hermiston Generating Company, L.P.
Description: § 205(d) Rate Filing: Hermiston Generating Company, L.P. MBR Amendment to be effective 7/1/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5103.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1803-000.
Applicants: Southern California Edison Company.
Description: § 205(d) Rate Filing: LGIA, Service Agreement No. 176 to be effective 6/1/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5104.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1804-000.
Applicants: Deepwater Wind Block Island, LLC.
Description: Baseline eTariff Filing: MBR Application to be effective 7/27/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5154.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1805-000.
Applicants: Duke Energy Ohio, Inc.
Description: § 205(d) Rate Filing: Georgetown Filing Added Facilities Letter Agreement to be effective 5/31/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5175.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1806-000.
Applicants: Entergy Louisiana, LLC, Entergy Texas, Inc., Entergy New Orleans, Inc.
Description: Tenth Annual filing implementing Service Schedule MSS-3 Rough Production Cost Equalization Bandwidth Calculation of Entergy Services, Inc. on behalf of the Entergy Operating Companies.
Filed Date: 5/27/16.
Accession Number: 20160527-5176.
Comments Due: 5 p.m. ET 6/17/16.
Docket Numbers: ER16-1807-000.
Applicants: FirstEnergy Solutions Corp.
Description: Compliance filing: Compliance filing 2016 to be effective 1/27/2016.
Filed Date: 5/27/16.
Accession Number: 20160527-5199.
Comments Due: 5 p.m. ET 6/17/16.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
Dated: May 27, 2016.
Nathaniel J. Davis, Sr.,

Deputy 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: ER10-2437-006
Applicants: Arizona Public Service Company.
Description: Notice of Non-Material Change in Status of Arizona Public Service Company.
Filed Date: 5/26/16.
Accession Number: 20160526-5304.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-695-005.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-695 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5276.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-696-005.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-696 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5277.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-697-006.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-697 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5278.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-699-006.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-699 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5279.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-700-007.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-700 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5281.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-701-005.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-701 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5283.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-702-005.
Applicants: Entergy Arkansas, Inc.
Description: Compliance filing: LBA Compliance ER14-702 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5275.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-703-005.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-703 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5282.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER14-704-005.
Applicants: Entergy Services, Inc.
Description: Compliance filing: LBA Compliance ER14-704 5-26-2016 to be effective 12/19/2013.
Filed Date: 5/26/16.
Accession Number: 20160526-5284.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-425-001.
Applicants: New York Independent System Operator, Inc.
Description: Response to Data Request of New York Independent System Operator, Inc.
Filed Date: 5/26/16.
Accession Number: 20160526-5299.
Comments Due: 5 p.m. ET 6/6/16.
Docket Numbers: ER16-1796-000.
Applicants: New York State Electric & Gas Corporation.
Description: § 205(d) Rate Filing: Executed Operations and Maintenance Agreement with New York Transco LLC to be effective 5/27/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5261.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1797-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-26_CMP Baseline Filing—MISO-SPP JOA to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5268.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1798-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-26_CMP Baseline Filing—MISO-PJM JOA to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5270.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1799-000.
Applicants: Southwest Power Pool, Inc.
Description: § 205(d) Rate Filing: SPP-MISO JOA Congestion Management Process Revisions to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5273.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1800-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-27_SA 2900 Cedar Falls-Western Minnesota Municipal 1st Rev. GIA (J329) to be effective 5/28/2016 .
Filed Date: 5/27/16.
Accession Number: 20160527-5059.
Comments Due: 5 p.m. ET 6/17/16.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
Dated: May 27, 2016.
Nathaniel J. Davis, Sr.,

Deputy 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: ER14-1641-001.
Applicants: Entergy Louisiana, LLC.
Description: Request for Temporary and Limited Waiver of Entergy Louisiana, LLC [containing unrelated Pro Forma sheets].
Filed Date: 5/25/16.
Accession Number: 20160525-5199.
Comments Due: 5 p.m. ET 6/15/16.
Docket Numbers: ER14-1643-001.
Applicants: Entergy New Orleans, Inc.
Description: Compliance filing: System Agreement—Compliance Update (MSS-3) to be effective 5/31/2014.
Filed Date: 5/25/16.
Accession Number: 20160525-5147.
Comments Due: 5 p.m. ET 6/15/16.
Docket Numbers: ER14-1644-001.
Applicants: Entergy Texas, Inc.
Description: Compliance filing: System Agreement—Compliance Update (MSS-3) to be effective 5/31/2014.
Filed Date: 5/25/16.
Accession Number: 20160525-5148.
Comments Due: 5 p.m. ET 6/15/16.
Docket Numbers: ER16-453-002.
Applicants: Northeast Transmission Development, LLC, PJM Interconnection, L.L.C.
Description: Compliance filing: NTD submits compliance filing per 4/26/2016 order in Docket No. ER16-453 to be effective 2/1/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5090.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1039-001.
Applicants: Midcontinent Independent System Operator, Inc.
Description: Compliance filing: 2016-05-26_DA Market Ext Reopening Compliance Filing to be effective 4/29/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5087.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1290-001.
Applicants: Southwest Power Pool, Inc.
Description: Tariff Amendment: 1628R9 Western Farmers Electric Cooperative NITSA—Amended to be effective 3/1/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5227.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1785-001.
Applicants: New York Independent System Operator, Inc.
Description: Tariff Amendment: NYISO refiling of the Operating Agreement to provide a full set of Attachments to be effective 5/23/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5165.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1786-000.
Applicants: California Independent System Operator Corporation.
Description: § 205(d) Rate Filing: 2016-05-25 Amdt—Variable Energy Resource Settlement & Bid-Cost Recovery Rules to be effective 10/1/2016.
Filed Date: 5/25/16.
Accession Number: 20160525-5146.
Comments Due: 5 p.m. ET 6/15/16.
Docket Numbers: ER16-1787-000.
Applicants: Citizens Sunrise Transmission LLC.
Description: § 205(d) Rate Filing: Annual Operating Cost True-Up Adjustment Informational Filing to be effective 6/1/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5078.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1789-000.
Applicants: ISO New England Inc., New England Power Pool Participants Committee.
Description: § 205(d) Rate Filing: Revisions to Schedule 2—Reactive Supply and Voltage Control Service to be effective 7/26/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5151.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1790-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: Request for a limited waiver of Midcontinent Independent System Operator, Inc.
Filed Date: 5/26/16.
Accession Number: 20160526-5163.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1791-000.
Applicants: PJM Interconnection, L.L.C.
Description: § 205(d) Rate Filing: Revisions to MISO/PJM JOA—CMP and ICP Baseline Changes to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5211.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1792-000.
Applicants: El Paso Electric Company.
Description: § 205(d) Rate Filing: Concurrence of EPE to APS Rate Schedule No. 222 to be effective 7/13/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5233.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1793-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-26_CMP Baseline Filing—Attachment LL Revisions to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5245.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1794-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-26_CMP Baseline Filing—RS 8 MISO-Manitoba Hydro SOA to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5253.
Comments Due: 5 p.m. ET 6/16/16.
Docket Numbers: ER16-1795-000.
Applicants: Midcontinent Independent System Operator, Inc.
Description: § 205(d) Rate Filing: 2016-05-26_CMP Baseline Filing—RS 46 Minnkota-MISO Coordination Operating Agr to be effective 7/25/2016.
Filed Date: 5/26/16.
Accession Number: 20160526-5258.
Comments Due: 5 p.m. ET 6/16/16.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) 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.
Dated: May 26, 2016.
Nathaniel J. Davis, Sr.,

Deputy Secretary.
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. RP16-958-000]
Peak Reliability; Request for Clarification of Peak Reliability
Take notice that on May 12, 2016 Peak Reliability (Peak) requested clarification that, consistent with Order No. 787, ^1 interstate natural gas pipelines may share non-public, operational information with Peak in connection with its performance of its Reliability Coordinator duties, subject to any appropriate non-disclosure agreements.
^1 Communication of Operational Information Between Natural Gas Pipelines and Transmission Operators, Order No. 787, 78 FR 70,163 (Nov. 22, 2013), FERC Stats. & Regs. ¶ 31,350 (cross-referenced at 145 FERC ¶ 61,134 (2013)), order on reh'g, Order No. 787-A, 147 FERC ¶ 61,228 (2014), order dismissing request for clarification, 152 FERC ¶ 61,051 (2015).
Any person desiring to intervene or to protest in this proceeding must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests must be filed on or before the comment date. Anyone filing a motion to intervene or protest must serve a copy of that document on the Petitioner.
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 should submit an original and 5 copies of the intervention or protest to the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
The filings in the above proceeding are accessible in the Commission's eLibrary system by clicking on the appropriate link in the above list. They are also available for review in the Commission's Public Reference Room in Washington, DC. There is an eSubscription link on the Web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email FERCOnlineSupport@ferc.gov. or call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.
Comment Date: 5:00 p.m. Eastern time on June 3, 2016.
Dated: May 26, 2016.
Nathaniel J. Davis, Sr.,

Deputy Secretary.
ENVIRONMENTAL PROTECTION AGENCY
[EPA-HQ-OW-2009-0297; FRL-9947-20-OW]
Request for Nominations for Peer Reviewers for EPA's Draft Biologically Based Dose-Response (BBDR) Model for Perchlorate, Draft Model Support Document and Draft Approach for Deriving a Maximum Contaminant Level Goal (MCLG) for Perchlorate in Drinking Water

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Request for nominations for peer reviewers.

SUMMARY:
The Environmental Protection Agency (EPA) is expanding the scope of the request for nominations announced in the Federal Register on March 1, 2016. Requested nominations are for an external peer review of the draft Biologically Based Dose-Response model and the draft model support document for perchlorate in drinking water. The expanded scope will include the review of the application of the draft Biologically Based Dose-Response Model to develop a perchlorate maximum contaminant level goal. EPA is combining the two panels to achieve efficiency and transparency in evaluating the development and application of key scientific products for analyzing perchlorate in drinking water. EPA invites the public to nominate scientific experts for the peer review. Persons nominated during the previous nomination period requested in the March 1, 2016, Federal Register notice do not need to be renominated under this notice and will be considered for selection for the interim and final list of peer reviewers.

DATES:
The nomination period for scientific experts begins on June 3, 2016 and ends on July 5, 2016.

ADDRESSES:
Any interested person or organization may nominate scientific experts to be considered as peer reviewers. Nominations should be submitted in time to arrive no later than July 5, 2016. Self-nominations will also be accepted. Nominations should be submitted to the EPA contractor, Versar, Inc., using the following email address: perchlorate@versar.com (the subject line should read: BBDR Model Peer Review and Peer Review of Approach for Deriving a Perchlorate MCLG). Nominations will also be accepted via the U.S. Postal Service mail or by an overnight/priority mail service. Mailed nominations should be addressed to Versar, Inc., 6850 Versar Center, Springfield, VA 22151 (Attention: David Bottimore). Nominations should include all nominee information outlined in section II of the SUPPLEMENTARY INFORMATION section of this document.

FOR FURTHER INFORMATION CONTACT:
Questions concerning the nomination process should be directed to the EPA contractor, Versar, Inc., at 6850 Versar Center, Springfield, VA 22151; by email to perchlorate@versar.com (the subject line should read: BBDR Model Peer Review and Peer Review of Approach for Deriving a Perchlorate MCLG); or by phone: (703) 642-6815 (ask for David Bottimore). For additional information concerning the draft Biologically Based Dose-Response Model, the draft Model Support Document and the draft approach for deriving a perchlorate MCLG, please contact Russ Perkinson at the U.S. Environmental Protection Agency, Office of Ground Water and Drinking Water, Standards and Risk Management Division, (Mail Code 4607M), 1200 Pennsylvania Avenue NW., Washington, DC 20460; telephone: 202-564-4901; or email: perkinson.russ@epa.gov.

SUPPLEMENTARY INFORMATION:

I. Information on the Draft Biologically Based Dose-Response (BBDR) Model, the Draft Model Support Document for Perchlorate and the Draft Approach for Deriving a Perchlorate Maximum Contaminant Level Goal (MCLG)
EPA has begun the process for developing a National Primary Drinking Water Regulation (NPDWR) for Perchlorate in accordance with the requirements under the Safe Drinking Water Act (SDWA). Among these requirements are that the agency must request comment from EPA's Science Advisory Board (SAB) prior to proposal of an MCLG and a NPDWR. 42 U.S.C. 1412(e). For additional background information, refer to the March 1, 2016, Federal Register notice (81 FR 10617).
Based on the SAB's recommendations, EPA, with contributions from Food and Drug Administration (FDA) scientists, developed a draft BBDR model to determine under what conditions of iodine nutrition and exposure to perchlorate across sensitive life stages low serum free and total thyroxine would result. The draft BBDR model integrates physiologically-based pharmacokinetic models for perchlorate with iodine models for thyroid hormones in formula-fed and nursing infants, as well as lactating women. The draft model predicts the effects of perchlorate on serum thyroid hormone concentrations in infants exposed via ingestion of formula mixed with contaminated drinking water or breast milk.
EPA is considering deriving a perchlorate MCLG by linking BBDR model output to alterations in thyroid hormone status that result in alterations in neurodevelopment. The draft approach for deriving a perchlorate MCLG outlines an assessment of the literature linking alterations in thyroid hormone status to alterations in neurodevelopment. Based on the results of this literature review, the report describes potential approaches to set the MCLG based on the availability of the current literature and the output of the BBDR model, predicting the effects of perchlorate on serum thyroid hormone concentrations in infants exposed via ingestion of formula mixed with contaminated drinking water or breast milk (see 81 FR 10617, March 1, 2016). The draft approach will be approximately 100 pages in length with approximately 7-10 figures and 10-15 tables. The draft approach describes application of the BBDR model to the development of a perchlorate MCLG and the appropriateness of the process under SDWA guidelines.
EPA anticipates releasing the draft BBDR model, draft model support document, and draft approach for peer review and public comment in the near future (the exact date to be determined).

II. How To Submit Nominations for Peer Reviewers
Expanded Expertise Sought: EPA is seeking candidates who are nationally and/or internationally recognized scientific experts to serve as external peer reviewers for the draft BBDR model, the draft model support document, and the draft approach to derive a perchlorate MCLG. Nominees should possess and demonstrate background knowledge and experience in one or more of the following areas of risk assessment to include: An understanding of thyroid function (preferably in the sensitive life stages of interest), the importance of maternal thyroid hormone homeostasis in each stage of gestation, hypothyroxinemia, neurodevelopmental assessment indices for young children including the Bayley's Scale, the toxicity of perchlorate, epidemiological assessment techniques, and statistics.
Expanded Selection Criteria: Selection criteria for individuals nominated to serve as external peer reviewers of the draft BBDR model, draft model support document, and draft approach to derive an MCLG for perchlorate include the following: (1) Demonstrated expertise through relevant peer reviewed publications, (2) professional accomplishments and recognition by professional societies, (3) demonstrated ability to work constructively and effectively in a committee setting, (4) absence of financial conflicts of interest, (5) no actual conflicts of interest or the appearance of lack of impartiality, (6) willingness to commit adequate time for the thorough review of the draft BBDR model, the draft model support document and the draft approach for deriving a perchlorate MCLG, commencing approximately during the summer of 2016 (exact date to be determined), and (7) availability to participate in person in a two-day peer review meeting in the Washington, DC metro area, projected to occur during the fall of 2016 (exact date will be published in the Federal Register at least 30 days prior to the external peer review meeting). Further logistical information regarding the external peer review meeting will be announced at a later date in the Federal Register .
Expanded Required Nominee Information: To receive full consideration, the following information should be submitted to Versar ( perchlorate@versar.com ) (the subject line should read: BBDR Model Peer Review and Peer Review of Approach for Deriving a Perchlorate MCLG): (1) Contact information for the person making the nomination; (2) contact information for the nominee; (3) the disciplinary and specific areas of expertise of the nominee; (4) the nominee's curriculum vitae; and (5) a biographical sketch of the nominee indicating current position, educational background, past and current research activities, recent service on other advisory committees, peer review panels, editorial boards or professional organizations, sources of recent grant and/or contract support and other comments on the relevance of the nominee's expertise to this peer review topic. Compensation for non-federal peer reviewers will be provided by Versar.
Expanded Selection Process: EPA's contractor, Versar, will notify candidates of selection or non-selection. Versar may also conduct an independent search for candidates to assemble a balanced group representing the expertise needed to fully evaluate EPA's draft BBDR model, draft model support document for perchlorate, and draft approach for deriving a perchlorate MCLG. The contractor will consider and screen all candidates against the criteria previously listed. Following the screening process, the contractor will narrow the list of potential reviewers to approximately 12-18 interim candidates. Prior to selecting the final peer reviewers, a Federal Register notice will be published (exact date to be determined) to solicit comments on the interim list of candidates. In that notice, the public will be requested to provide relevant information or documentation on the nominees within 30 days of the announcement of the interim list of candidates. Once the contractor has considered the public comments on the interim list of candidates, the contractor will select the final list of peer reviewers based on who, collectively, will best provide expertise spanning the disciplines listed above and (to the extent feasible) best provide a balance of perspectives.
Dated: May 23, 2016.
Joel Beauvais,

Deputy Assistant Administrator.
ENVIRONMENTAL PROTECTION AGENCY
[ER-FRL-9027-4]
Environmental Impact Statements; Notice of Availability
Responsible Agency: Office of Federal Activities, General Information (202) 564-7146 or http://www.epa.gov/nepa.
Weekly receipt of Environmental Impact Statements (EISs)
Filed 05/23/2016 Through 05/27/2016
Pursuant to 40 CFR 1506.9.

Notice
Section 309(a) of the Clean Air Act requires that EPA make public its comments on EISs issued by other Federal agencies. EPA's comment letters on EISs are available at: http://www.epa.gov/compliance/nepa/eisdata.html.
EIS No. 20160112, Draft, USFS, MT, Galton Vegetation Management, Comment Period Ends: 07/25/2016, Contact: Ron Komac 406-296-2536 x7130.
EIS No. 20160113, Draft, USFS, MT, Flathead National Forest Plan Revision and Northern Continental Divide Ecosystem Grizzly Bear Conservation Strategy Forest Plan Amendments to the Lolo, Helena, Lewis & Clark, and Kootenai National Forests, Comment Period Ends: 10/03/2016, Contact: Joe Krueger 406-758-5243.
EIS No. 20160114, Final, FHWA, TX, Grand Parkway (State Highway 99) Segment B, Review Period Ends: 07/05/2016, Contact: Carlos Swonke 512-416-2734.
EIS No. 20160115, Draft, DOD, Other, Continental United States (CONUS) Interceptor Site, Comment Period Ends: 07/18/2016, Contact: Christopher Johnson 571-231-8212.
EIS No. 20160116, Final, USACE, FL, Herbert Hoover Dike Dam Safety Modification Study, Review Period Ends: 07/05/2016, Contact: Stacie Auvenshine 904-232-3694.
EIS No. 20160117, Draft, BR, USACE, MT, Lower Yellowstone Intake Diversion Dam Fish Passage Project, Comment Period Ends: 07/18/2016, Contact: Tiffany Vanosdall 402-995-2695.
The U.S. Army Corps of Engineers and the U.S. Department of the Interior's Bureau of Reclamation are joint lead agencies for this project.
EIS No. 20160118, Draft, BLM, CO, Uncompahgre Draft Resource Management Plan, Comment Period Ends: 09/01/2016, Contact: Gina Jones 970-240-5381.
EIS No. 20160119, Draft, USFS, OR, Green Mountain Project, Comment Period Ends: 07/18/2016, Contact: Elysia Retzlaff 541-822-7214.
EIS No. 20160120, Final, USFWS, CA, South Bay Salt Pond Restoration Project Phase 2, Review Period Ends: 07/05/2016, Contact: Chris Barr 510-792-0222.
EIS No. 20160121, Draft, USACE, AZ, Little Colorado River, Winslow, Arizona, Flood Risk Management Project, Comment Period Ends: 07/18/2016, Contact: Kirk Brus 213-452-3876.
EIS No. 20160122, Draft, USFS, AK, Wrangell Island Project, Comment Period Ends: 07/18/2016, Contact: Andrea Slusser 907-874-2323.
EIS No. 20160123, Final, USFS, CO, Spruce Beetle Epidemic and Aspen Decline Management Response, Review Period Ends: 07/05/2016, Contact: Samantha Staley 970-874-6666.
Dated: May 31, 2016.
Dawn Roberts,

Management Analyst, NEPA Compliance Division, Office of Federal Activities.
ENVIRONMENTAL PROTECTION AGENCY
[EPA-HQ-OECA-2005-0062; FRL-9027-3]
Proposed Information Collection Request Submitted to OMB for Review and Approval; Comment Request; Procedures for Implementing the National Environmental Policy Act and Assessing the Environmental Effects Abroad of EPA Actions (Renewal)

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice.

SUMMARY:
The Environmental Protection Agency is planning to submit an information collection request (ICR), Procedures for Implementing the National Environmental Policy Act and Assessing the Environmental Effects Abroad of EPA Actions (EPA ICR No. 2243.08, OMB Control No. 2020-0033) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act.. Before doing so, EPA is soliciting public comments on specific aspects of the proposed information collection as described below. This is a proposed extension of the ICR, which is currently approved through October 31, 2016. 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.

DATES:
Comments must be submitted on or before Tuesday, August 2, 2016.

ADDRESSES:
Submit your comments, referencing Docket ID No. EPA-HQ-OECA-2005-0062 online using www.regulations.gov (our preferred method), by email to docket.oeca@epa.gov, or by mail to: EPA Docket Center, Environmental Protection Agency, Mail Code 28221T, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.

FOR FURTHER INFORMATION CONTACT:
Jessica Trice, Office of Federal Activities, Mail Code 2252A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-6646; fax number: (202) 564-0072; email address: trice.jessica@epa.gov.

SUPPLEMENTARY INFORMATION:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at www.regulations.gov or in person at the EPA Docket Center, WJC West, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The telephone number for the Docket Center is 202-566-1744. For additional information about EPA's public docket, visit http://www.epa.gov/dockets.
Pursuant to section 3506(c)(2)(A) of the PRA, EPA is soliciting comments and information to enable it to: (i) 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; (ii) 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; (iii) enhance the quality, utility, and clarity of the information to be collected; and (iv) 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. 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. At that time, EPA will issue another Federal Register notice to announce the submission of the ICR to OMB and the opportunity to submit additional comments to OMB.
Abstract: The National Environmental Policy Act of 1969 (NEPA), 42 U.S.C. 4321-4347 establishes a national policy for the environment. The Council on Environmental Quality (CEQ) oversees the NEPA implementation. CEQ's Regulations at 40 CFR parts 1500 through 1508 set the standard for NEPA compliance. They also require agencies to establish their own NEPA implementing procedures. EPA's procedures for implementing NEPA are found in 40 CFR part 6. Through this part, EPA adopted the CEQ Regulations and supplemented those regulations for actions by EPA that are subject to NEPA requirements. EPA actions subject to NEPA include the award of wastewater treatment construction grants under Title II of the Clean Water Act, EPA's issuance of new source National Pollutant Discharge Elimination System (NPDES) permits under section 402 of the Clean Water Act, certain research and development projects, development and issuance of regulations, EPA actions involving renovations or new construction of facilities, and certain grants awarded for projects authorized by Congress through the Agency's annual Appropriations Act. EPA is collecting information from certain applicants as part of the process of complying with either NEPA or Executive Order 12114 (“Environmental Effects Abroad of Major Federal Actions”). EPA's NEPA regulations apply to the actions of EPA that are subject to NEPA in order to ensure that environmental information is available to the Agency's decision-makers and the public before decisions are made and before actions are taken. When EPA conducts an environmental assessment pursuant to its Executive Order 12114 procedures, the Agency generally follows its NEPA procedures. Compliance with the procedures is the responsibility of EPA's Responsible Officials, and for applicant proposed actions applicants may be required to provide environmental information to EPA as part of the environmental review process. For this Information Collection Request (ICR), applicant-proposed projects subject to either NEPA or Executive Order 12114 (and that are not addressed in other EPA programs' ICRs) are addressed through the NEPA process.
Form Numbers: None.
Respondents/affected entities: Entities potentially affected by this action are certain grant or permit applicants who must submit environmental information documentation to EPA for their projects to comply with NEPA or Executive Order 12114, including Wastewater Treatment Construction Grants Program facilities, State and Tribal Assistance Grant recipients and new source National Pollutant Discharge Elimination System permittees.
Respondent's obligation to respond: Voluntary.
Estimated number of respondents: 312 (total).
Frequency of response: On occasion.
Total estimated burden: 37,525 hours (per year). Burden is defined at 5 CFR 1320.03(b).
Total estimated cost: $3,607,085 (per year), includes $8,452 annualized capital or operation & maintenance costs.
Changes in Estimates: The above estimates are based on information and data available through the current ICR supporting documentation. However, it is anticipated that there will be slight decrease in hours in the total estimated respondent burden compared with the ICR currently approved by OMB. This slight decrease is due to changes in the number of respondents and their associated EPA actions eligible for categorical exclusions which results in a reduction in total hours and burden.
Dated: Tuesday, May 31, 2016.
Karin Leff,

Acting Director, NEPA Compliance Division, Office of Federal Activities.
ENVIRONMENTAL PROTECTION AGENCY
[EPA-HQ-OAR-2016-0204; FRL-9946-70-OAR]
Proposed Information Collection Request; Comment Request; Information Collection Effort for Oil and Gas Facilities

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice.

SUMMARY:
The Environmental Protection Agency (EPA) is planning to submit an information collection request (ICR), “Information Collection Effort for Oil and Gas Facilities” (EPA ICR No. 2548.01, OMB Control No. 2060-NEW) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (PRA) (44 U.S.C. 3501 et seq. ). Before doing so, the EPA is soliciting public comments on specific aspects of the proposed information collection as described below. This is a request for approval of a new collection of information. 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.

DATES:
Comments must be submitted on or before August 2, 2016.

ADDRESSES:
Submit your comments, referencing Docket ID No. EPA-HQ-OAR-2016-0204, online using http://www.regulations.gov (our preferred method), or by mail to: EPA Docket Center (EPA/DC), Environmental Protection Agency, Mail Code 28221T, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.

FOR FURTHER INFORMATION CONTACT:
Ms. Brenda Shine, Sector Policies and Programs Division, Refining and Chemicals Group (E143-01), Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, NC 27711; telephone number: (919) 541-3608; fax number: (919) 541-0246; email address: shine.brenda@epa.gov.

SUPPLEMENTARY INFORMATION:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this notice. The docket can be viewed online at http://www.regulations.gov or in person at the EPA Docket Center (EPA/DC, EPA WJC West Building, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The telephone number for the Docket Center is 202-566-1742. The telephone number for the public reading room is 202-566-1744. For additional information about EPA's public docket, visit http://www.epa.gov/dockets.
Pursuant to section 3506(c)(2)(A) of the PRA, the EPA is soliciting comments and information to enable it to: (i) 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; (ii) 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; (iii) enhance the quality, utility, and clarity of the information to be collected; and (iv) 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. The EPA will consider the comments received and may amend the ICR as appropriate. The final ICR package will then be submitted to OMB for review and approval. At that time, the EPA will issue another Federal Register notice to announce the submission of the ICR to OMB and the opportunity to submit additional comments to OMB.
Abstract: Collectively, oil and gas facilities are the largest industrial emitters of methane in the U.S. In January 2015, as part of the Obama Administration's commitment to addressing climate change, the EPA outlined a number of steps it plans to take to address methane and smog-forming volatile organic compound (VOC) emissions from the oil and gas industry. Concurrently with this action, the EPA has promulgated new source performance standards (NSPS) for the oil and gas industry to achieve both methane reductions and additional reductions in VOCs (40 CFR part 60, subpart OOOOa). The EPA has also committed to require standards of performance for existing oil and gas sources. Section 111(d) of the Clean Air Act (CAA), as amended, provides a cooperative federalism approach to establishing standards of performance for existing sources. Under this approach, the EPA establishes guidelines that identify the emission performance states must require their sources to achieve, and states then submit plans for EPA review and approval, which establish standards of performance that achieve that emissions performance.
While a great deal of information is available on the oil and gas industry and has to date provided a strong technical foundation to support the Agency's recent actions, the EPA is now seeking more specific information that would be of critical use in addressing CAA section 111(d). Taking into account the large number of sources that a national regulation development effort would need to consider, and the potential for taking a different approach to addressing co-located existing sources than was taken with new and modified sources, the EPA requires information that will enable the development of effective standards for this entire industry under CAA section 111(d). For new sources, the CAA requires that standards apply to each new affected facility upon startup. Conversely, without information allowing for development of a pathway for phasing in standards, existing source standards will likely apply to all regulated units at approximately the same time. Currently there are hundreds of thousands of pieces of equipment across the country in all kinds of different situations and configurations. To determine how to efficiently and effectively address emissions from this volume of sources in a timely, but administrable manner, we need more comprehensive information that will improve our understanding of what emission controls are being used (and perhaps shared) in the field, how those are configured, the difficulty of replacing or upgrading controls, how much time will be needed to retrofit, what the likely costs of retrofitting are, whether electricity or generating capacity is available, and how often sites are staffed or visited. Such information will, for example, allow us to ascertain if there are effective ways for affected facilities at well sites, or other co-located facilities, to share emission controls, how to balance the level of emission reductions with administering a program of this size, and potential phase in opportunities. Additional information will also support the Agency's effort to explore proposing standards for new and modified units not currently covered by NSPS OOOOa. Specifically, before proposing standards the EPA must assure that it has adequate information to determine “the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated,” (BSER) as well as the “degree of emission limitation achievable through the application of” such system. Currently, the EPA collects information on the greenhouse gas (GHG) emissions from oil and gas facilities under 40 CFR part 98, subpart W, of the Greenhouse Gas Reporting Program (GHGRP). However, the GHGRP does not collect information on design, performance, and costs of emission controls. Such information is necessary to evaluate the scope, design, and potential impact of future standards of performance for existing oil and gas facility sources. There are also differences in the definition of “facility” in the GHGRP for oil and gas production facilities as compared to the way we have defined facility under our regulations. As previously stated, “the EPA's definition of `facility' for purposes of 40 CFR part 98 in no way impacts the `facility' definition for similar sources under existing CAA programs.” 80 FR 64262, 64271. Additionally, certain states have moved forward with their own rules and have developed information needed for their own purposes, but this information is not sufficient for a national rulemaking. Thus, it is necessary to collect specific information from oil and gas production facilities both for existing sources and sources not covered by the standards of performance for new and modified sources to understand the number of affected facilities and to estimate the facility-level impacts of potentially implementing existing source standards of various designs.
There will be two parts to the information collection. Part 1, referred to as the operator survey, is specifically designed to obtain information from onshore oil and gas production facilities to better understand the number and types of equipment at production facilities. Part 1 seeks to collect facility-level information ( e.g., facility name, location, contact information, and number of wells, tanks, and compressors) using the definition of facility commonly employed when permitting new and existing sources ( i.e., all buildings, equipment, structures, and other stationary equipment that are located on one or more contiguous or adjacent properties and that are under common ownership or control). Part 1 will be sent to all known operators of oil and gas production wells and will allow the Agency to obtain the information necessary to identify and categorize all potentially affected oil and gas production facilities. The operators will complete the Part 1 survey, including providing equipment counts for all production facilities that they operate with the exception of facilities selected to complete Part 2. Part 1 is not expected to contain any CBI. This operator survey may be submitted either electronically or through hard copy responses. The submission requires the owner or operator to certify that the information being provided is accurate and complete.
Part 2, referred to as the detailed facility survey, will be sent to selected oil and gas facilities across the different industry segments. Specifically, these industry segments include onshore production, gathering and boosting, processing, compression/transmission, pipeline, natural gas storage, and liquefied natural gas (LNG) storage and import/export facilities. This ICR will not collect information from offshore production facilities or from local natural gas distribution facilities. Due to the large number of potentially affected facilities, Part 2 uses a statistical sampling method considering each industry segment (and groupings of facilities in the production segment) to be separate sampling populations. Thus, a statistically significant number of facilities within each industry segment (or “population”) will be required to complete the Part 2 detailed facility survey.
Developing an appropriate sampling size for the onshore production industry is complicated by the number of factors that could impact the types of processes or equipment present at the site and the magnitude of emissions from these sources. Therefore, the Agency considered further stratification of the production industry segment into separate populations based on differences in the type of well (oil or natural gas, vertical or horizontal drilling, or further distinctions based on gas-to-oil ratio), the type of formation, and the production basin. At this time, the Agency has limited information on means to characterize individual facilities or wells by formation type or well drilling type (vertical versus horizontal wells). However, the Agency does have estimates of the number of wells in a given basin and has estimates of the gas-to-oil ratio (GOR), from which we designate well type for nearly all wells. Therefore, the Agency considered two options for establishing different populations within the production segment: Option 1, which is based on the well type using GOR ranges, and Option 2, which is based on regional groupings of basins.
Option 1, which considers populations based on well types, defines the following five populations based on GOR:
1. Heavy Oil (GOR ≤ 300 standard cubic feet per barrel, scf/bbl)
2. Light Oil (300 < GOR ≤ 100,000 scf/bbl)
3. Wet Gas (100,000 < GOR ≤ 1,000,000 scf/bbl)
4. Dry Gas (GOR > 1,000,000 scf/bbl)
5. Coal Bed Methane
Most of these well type categories have historical significance, such as the GOR of 300 scf/bbl included in the applicability of the Oil and Gas NSPS requirements for well completions (40 CFR part 60, subpart OOOOa) and the GOR of 100,000 scf/bbl delineation between oil and gas wells used in the U.S. Emissions Inventory for GHG Sources and Sinks. The delineation between “wet” and “dry” gas wells was developed for this ICR to gain information on “wet” gas wells because these gas wells have been found to have higher VOC content and, as such, are of particular interest in this information collection effort.
Option 2, which considers regional groupings of basins, defines the following five populations based on basins (geological provinces) defined by the American Association of Petroleum Geologists:
1. East: Basins 100 to 190
2. South: Basins 200 to 290 and Basin 400
3. Midwest: Basins 300 to 395
4. West Texas: Basins 405 to 440
5. West: Basins 445 to 895
Option 1 (populations based on well type) will ensure that a statistically significant number of each well type is sampled. This is important because there are fewer wet gas wells and coal bed methane gas wells than heavy oil, light oil, or dry gas wells. However, because of the differences in the number of wells within each population, analyses using the data must use these classifications (or weighting factors) to develop nationwide assessments. The regional populations are more similar to each other in terms of the number of wells in each region, but weighting factors would still be required to perform nationwide assessments separate from these defined regions.
Based on a desire to have no more than a 10-percent error ( i.e., +/−10 percent) in the estimate of an average value at a 95-percent confidence interval and 90-percent power to differentiate an effect size of 0.2, the target number of samples required for large populations was determined to be 385 (additional detail regarding the determination of the target sample size using the statistical sampling approach is provided in Part B of the Supporting Statement for this ICR, which is included in Docket ID No. EPA-HQ-OAR-2016-0204 at http://www.regulations.gov ). Consequently, because the number of production facilities in each population is relatively large compared to the target sample size, the overall costs of the two survey options for production facilities are nearly identical. We are specifically requesting comment on these two options for developing population categories within the production industry. We recognize that other alternatives may be viable, such as defining the entire production industry as one population and developing sampling requirements based on the accuracy and precision needed to characterize any subcategory of the production population that represents, for example, 20 percent of the total production wells. In this example, 1,925 (5 × 385) samples from the production population would be required. All respondents would have equal weight, so analyses could be conducted without having to consider weighting factors, but analyses for categories of wells with less than 20 percent of the population would have less accuracy and precision. As there are many potential factors to consider for the production population, we also request comment on other potential methods to define populations of production wells in order to adequately characterize the various potentially important differences in production facilities.
Part 2 will collect detailed unit-specific information on emission sources at the facility and any emission control devices or management practices used to reduce emissions. Most of the information requested under Part 2 is expected to be available from company records and would not require additional measurements to be performed. However, selected data elements must be completed based on actual component equipment counts (specifically, pneumatic device counts and equipment leak component counts) or measurement data (specifically, separator/storage vessel flash analyses). If this information is not directly available for a facility, the respondent will be required to collect and report this information (count equipment components and/or sample and analyze tank feed streams) as part of this information collection. Part 2 is expected to include information that oil and gas facilities consider to be confidential and the survey must be completed and submitted electronically via the EPA's Electronic Greenhouse Gas Reporting Tool (e-GGRT).
The data collected throughout this process will be used to determine the number of potentially affected emission sources and the types and prevalence of emission controls or emission reduction measures used for these sources at existing oil and gas facilities, among other purposes. This information may also be used to fill data gaps, to evaluate the emission and cost impacts of various regulatory options, and to establish appropriate standards of performance for oil and gas facilities.
If OMB approves this ICR, respondents will be required to respond under the authority of section 114 of the CAA. The EPA anticipates issuing the CAA section 114 letters by October 30, 2016. These letters would require the owner/operator of an oil and gas facility to complete the Part 1 survey within 30 days of receipt of the survey, and would require facilities to complete the Part 2 survey with 120 days of receipt.
The Agency has reviewed the draft surveys applying the confidentiality determination methods established for data reporting under the GHGRP as a model, as well as the policy notice entitled “Disclosure of Emission Data Claimed as Confidential Under Sections 110 and 114(c) of the Clean Air Act (56 FR 7042, February 21, 1991.) The EPA has developed proposed determinations of the data elements in the surveys that may be considered CBI. These proposed determinations are included in the information being supplied for public review and comment in Docket ID No. EPA-HQ-OAR-2016-0204 at http://www.regulations.gov. Confidentiality designations will be made according to the provisions set forth in title 40, Code of Regulations part 2, subpart B—Confidentiality of Business Information. Any information subsequently determined to constitute a trade secret will be protected under 18 U.S.C. 1905.
Form Numbers: Production Operator Survey (Part 1); Detailed Facility Survey (Part 2).
Respondents/affected entities: Respondents affected by this action are owners/operators of oil and natural gas facilities. Part 1 of this ICR is specifically requesting information for facilities in the onshore petroleum and natural gas production industry segment. Part 2 of this ICR is specifically requesting information for facilities in the following industry segments: Onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas processing, onshore natural gas transmission compression, onshore natural gas transmission pipelines, underground natural gas storage, LNG storage and LNG import and export equipment. The ICR is not requesting information for the offshore petroleum and natural gas production industry segment or from the natural gas (local) distribution industry segment.
Respondent's obligation to respond: The information collection in Parts 1 and 2 is being conducted by the EPA's Office of Air and Radiation pursuant to section 114 of the CAA, to assist the Administrator of the EPA in developing emissions standards for oil and natural gas facilities pursuant to the CAA.
Estimated number of respondents: The estimated number of respondents for Part 1 is 22,500 operators representing approximately 698,800 facilities (total). The estimated number of respondents for Part 2 is 3,385.
Frequency of response: This is a one-time survey.
Total estimated burden: The estimated industry burden is 116,438 hours for Part 1 and 111,485 hours for Part 2. Therefore, the cumulative industry burden for all parts of this ICR is estimated to be 227,923 hours. The estimated cumulative Agency burden to administer this ICR (all parts) is 17,947 hours. Burden is defined at 5 CFR 1320.03(b).
Total estimated cost: The estimated costs for the oil and natural gas industry is $16,476,182 for Part 1 and $23,673,312 for Part 2. The resulting total industry costs for all parts of this ICR is estimated to be $40,149,494, which includes $11,302,500 in operating and maintenance (O&M) costs to cover mailing hard copies of Part 1 responses and contracting services for storage vessel feed material flashing analyses as part of Part 2 responses. The estimated cumulative Agency costs to administer this ICR (all parts) is $960,793, which includes $144,618 in O&M costs to send certified CAA section 114 letters to all respondents selected for Part 1 and Part 2 surveys with electronic return receipt.
Changes in Estimates: This is a new ICR, so this section does not apply.
Dated: May 12, 2016.
Peter Tsirigotis,

Director, Sector Policies and Programs Division, Office of Air Quality Planning and Standards.
ENVIRONMENTAL PROTECTION AGENCY
[EPA-HQ-OPP-2016-0242; FRL-9946-52]
Pesticides; Draft Guidance for Pesticide Registrants on Pesticide Resistance Management Labeling

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice of availability.

SUMMARY:
The Agency is announcing the availability of and seeking public comment on a draft Pesticide Registration Notice (PR Notice) entitled “Guidance for Pesticide Registrants on Pesticide Resistance Management Labeling.” PR Notices are issued by the Office of Pesticide Programs (OPP) to inform pesticide registrants and other interested persons about important policies, procedures, and registration related decisions, and serve to provide guidance to pesticide registrants and OPP personnel. This draft PR Notice provides guidance for registrants to follow when developing resistance management information to include on their pesticide labels. This draft PR Notice would update the guidance in PR Notice 2001-5.

DATES:
Comments must be received on or before August 2, 2016.

ADDRESSES:
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPP-2016-0242, by one of the following methods:
• Federal eRulemaking Portal: http://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.
• Mail: OPP Docket, Environmental Protection Agency Docket Center (EPA/DC), (28221T), 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001.
• Hand Delivery: To make special arrangements for hand delivery or delivery of boxed information, please follow the instructions at http://www.epa.gov/dockets/contacts.html. Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at http://www.epa.gov/dockets.

FOR FURTHER INFORMATION CONTACT:
Nikhil Mallampalli, Biological and Economic Analysis Division (7503P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; telephone number: (703) 308-1924; email address: mallampalli.nikhil@epa.gov.
SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?
This action is directed to the public in general. Although this action may be of particular interest to those persons who are required to submit data under the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) or are required to register pesticides. Since other entities may also be interested, the Agency has not attempted to describe all the specific entities that may be affected by this action.

B. What should I consider as I prepare my comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.
2. Tips for preparing your comments. When preparing and submitting your comments, see the commenting tips at http://www.epa.gov/dockets/comments.html.

C. How can I get copies of this document and other related information?
A copy of the draft PR Notice “Guidance for Pesticide Registrants on Pesticide Resistance Management Labeling” and any related or supporting information are available in the docket under docket identification (ID) number EPA-HQ-OPP-2016-0242.

II. Overview of the Agency's Effort To Address Pesticide Resistance
Pesticides can be used to control a variety of pests, such as insects, weeds, rodents, bacteria, fungi, etc. Over time many pesticides have gradually lost their effectiveness because pests have developed resistance—a significant decrease in sensitivity to a pesticide, which reduces the field performance of these pesticides. The Agency is concerned about resistance issues and believes that managing the development of pesticide resistance, in conjunction with alternative pest-management strategies and Integrated Pest Management programs, is an important part of sustainable pest management. To address the growing issue of resistance and preserve the useful life of pesticides, the Agency is beginning to embark on a more widespread effort and several activities that are aimed at combating and slowing the development of pesticide resistance.
One such activity, which is the subject of this FR Notice, is today's release and request for comment on draft PR Notice 2016-X, “Guidance for Pesticide Registrants on Pesticide Resistance Management Labeling.” Draft PR Notice 2016-X updates PR Notice 2001 and applies to all conventional, agricultural pesticides ( i.e., herbicides, fungicides, bactericides, insecticides, and acaricides). This draft PR Notice focuses on pesticide labels and is aimed at improving information about how pesticide users can minimize and manage pest resistance.
Another such activity, involves the release of draft PR Notice 2016-XX, “Guidance for Herbicide Resistance Management Labeling, Education, Training, and Stewardship.” Draft PR Notice 2016-XX applies to herbicides, and communicates the Agency's current thinking and approach to address herbicide-resistant weeds by providing guidance on labeling, education, training, and stewardship for herbicides undergoing registration review or registration ( i.e., new herbicide actives, new uses proposed for use on herbicide-resistant crops, or other case-specific registration actions). Draft PR Notice 2016-XX will also be published in today's Federal Register . In the future, the Agency plans to evaluate other types of pesticides ( e.g. fungicides, bactericides, insecticides, and acaricides) to determine whether and what guidance may be appropriate for these types pesticides. If the Agency releases future guidance on these other types of pesticides, we plan to seek input from the public.

III. What guidance does this PR Notice provide?
Draft PR Notice 2016-X, which revises and updates PR Notice 2001-5, applies to all conventional, agricultural pesticides ( i.e., herbicides, fungicides, bactericides, insecticides and acaricides). The updates in draft PR Notice 2016-X focus on pesticides labels and are aimed at improving information about how pesticide users can minimize and manage pest resistance. The draft PR Notice 2016-X updates PR Notice 2001-5 with the following three categories of changes:
• Provides additional guidance, and recommended format, for resistance management statements or information to place on labels.
• Includes references to external technical resources for guidance on resistance management ( e.g., professional scientific societies, resistance action committees for different types of pesticides).
• Updates the instructions on how to submit changes to existing labels in order to enhance resistance management language.
This draft PR Notice also references draft revisions to Chapter 11.VI.G of EPA's Label Review Manual (LRM), which illustrates the generic format for resistance management labeling along with examples of various labeling scenarios that registrants may encounter. The Agency requests comments on the updates to this draft PR Notice and this chapter of the LRM.

IV. Do PR Notices contain binding requirements?
The PR Notice discussed in this notice is intended to provide guidance to EPA personnel and decision-makers, as well as pesticide registrants. While the requirements in the statute and Agency regulations are binding on EPA and the applicants, this PR Notice is not binding on either EPA or pesticide registrants, and EPA may depart from the guidance where circumstances warrant and without prior notice. Likewise, pesticide registrants may assert that the guidance is not appropriate generally or not applicable to a specific pesticide or situation.

Authority:
7 U.S.C. 136 et seq.
Dated: May 23, 2016.
Jack E. Housenger,

Director, Office of Pesticide Programs.
ENVIRONMENTAL PROTECTION AGENCY
[EPA-HQ-OPP-2016-0226; FRL-9946-53]
Pesticides; Draft Guidance for Pesticide Registrants on Herbicide Resistance Management Labeling, Education, Training, and Stewardship

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Notice of availability.

SUMMARY:
The Agency is announcing the availability of and seeking public comment on a draft Pesticide Registration Notice (PR Notice) entitled “Guidance for Herbicide Resistance Management Labeling, Education, Training, and Stewardship.” PR Notices are issued by the Office of Pesticide Programs (OPP) to inform pesticide registrants and other interested persons about important policies, procedures, and registration-related decisions, and serve to provide guidance to pesticide registrants and OPP personnel. This draft PR Notice (2016-XX) communicates the Agency's approach to addressing herbicide-resistant weeds by providing guidance on labeling, education, training, and stewardship for herbicides undergoing registration review or registration ( i.e., new herbicide and actives, new uses proposed for use on herbicide-resistant crops, or other case-specific registration actions.

DATES:
Comments must be received on or before August 2, 2016.

ADDRESSES:
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPP-2016-0226, by one of the following methods:
• Federal eRulemaking Portal: http://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.
• Mail: OPP Docket, Environmental Protection Agency Docket Center (EPA/DC), (28221T), 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001.
• Hand Delivery: To make special arrangements for hand delivery or delivery of boxed information, please follow the instructions at http://www.epa.gov/dockets/contacts.html.
Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at http://www.epa.gov/dockets.

FOR FURTHER INFORMATION CONTACT:
Bill Chism, Biological and Economic Analysis Division (7503P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; telephone number: (703) 308-8136; email address: chism.bill@epa.gov.

SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?
This action is directed to the public in general. Although this action may be of particular interest to those persons who are required to submit data under the Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) or are required to register pesticides. Since other entities may also be interested, the Agency has not attempted to describe all the specific entities that may be affected by this action.

B. What should I consider as I prepare my comments for EPA?
1. Submitting CBI. Do not submit this information to EPA through regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.
2. Tips for preparing your comments. When preparing and submitting your comments, see the commenting tips at http://www.epa.gov/dockets/comments.html.

C. How can I get copies of this document and other related information?
A copy of draft PR Notice 2016-XX, “Guidance for Herbicide Resistance Management Labeling, Education, Training, and Stewardship” and any related or supporting information are available in the docket under docket identification (ID) number EPA-HQ-OPP-2016-0226.

II. Overview of the Agency's Effort to Address Pesticide Resistance
Pesticides can be used to control a variety of pests, such as insects, weeds, rodents, bacteria, fungi, etc. Over time many pesticides have gradually lost their effectiveness because pests have developed resistance—a significant decrease in sensitivity to a pesticide, which reduces the field performance of these pesticides. The Agency is concerned about resistance issues and believes that managing the development of pesticide resistance, in conjunction with alternative pest-management strategies and Integrated Pest Management programs, is an important part of sustainable pest management. To address the growing issue of resistance and preserve the useful life of pesticides, the Agency is beginning to embark on a more widespread effort and several activities that are aimed at combating and slowing the development of pesticide resistance.
One such activity, which is the subject of this FR Notice, is today's release and request for comment on draft PR Notice 2016-XX, “Guidance for Herbicide Resistance Management Labeling, Education, Training, and Stewardship.” Draft PR Notice 2016-XX, which only applies to herbicides, communicates the Agency's current thinking and approach to address herbicide-resistant weeds by providing guidance on labeling, education, training, and stewardship for herbicides undergoing registration review or registration ( i.e., new herbicide actives, new uses proposed for use on herbicide-resistant crops, or other case-specific registration actions). It is part of a holistic, proactive approach to slow the development and spread of herbicide-resistant weeds, and prolong the useful lifespan of herbicides and related technology. The Agency is focusing on the more holistic guidance for herbicides first because they are the most widely used agricultural chemicals, no new herbicide mechanism of action has been developed in last 30 years, and herbicide-resistant weeds are rapidly increasing. In the future, the Agency plans to evaluate other types of pesticides ( e.g., fungicides, bactericides, insecticides, and acaricides) to determine whether and what guidance may be appropriate for these types pesticides. If the Agency releases future guidance on these other types of pesticides, we plan to seek input from the public.
Another such activity, involves the release of draft PR Notice 2016-X, “Guidance for Pesticide Registrants on Pesticide Resistance Management Labeling. Draft PR Notice 2016-X, which updates PR Notice 2001-5, applies to all conventional, agricultural pesticides ( i.e., herbicides, fungicides, bactericides, insecticides, and acaricides). Draft PR Notice 2016-X focuses on pesticide labels and is aimed at improving information about how pesticide users can minimize and manage pest resistance. This draft PR Notice will also be published in today's Federal Register .

III. Background on Herbicide Resistance
For the purposes of draft PR Notice 2016-XX and this FR Notice, the Agency defines herbicide resistance as the inherited ability of a plant to survive and reproduce following exposure to a dose of herbicide normally lethal to the wild type. Resistance may be naturally occurring or induced by such techniques as genetic engineering or selection of variants produced by tissue culture or mutagenesis.
The development and spread of herbicide-resistant weeds in agriculture is a widespread problem that has the potential to fundamentally change production practices in United States agriculture. While herbicide-resistant weeds have been known since the 1950s, the number of species and their geographical extent, has been increasing rapidly in the last decade. As of March 2016, Heap reports that there are 249 weed species with confirmed herbicide resistance worldwide and 80 unique weed species with herbicide resistance in the United States (Heap, 2016). Considering that some weed species have developed resistance to more than one mechanism of action (MOA) independently, there are 155 weed species/MOA combinations with confirmed resistance (Heap, 2016). These 155 combinations have shown resistance to herbicides with 18 different MOAs. In the United States, 48 states have reported the presence of herbicide-resistant weeds and there are over 80 crops and sites ( e.g. roadsides, pastures, and railways) with herbicide-resistant weeds.
As noted earlier, draft PR Notice 2016-XX primarily focuses on herbicides at this time for several reasons. First, herbicides are the most widely used agricultural chemicals. Over 285 million acres were treated on nearly 800,000 farm operations in 2012 (USDA, 2014). Second, unlike fungicides and insecticides, there have been no new herbicide MOAs developed in the last 30 years. Therefore, users do not have a new MOA to control herbicide-resistant weeds and it's important to protect the long term efficacy of these chemistries. Third, the number of herbicide-resistant weeds and the affected acreage infested is rapidly increasing. Finally, growers are facing severe economic impacts from herbicide-resistant weeds with up to 100% crop loss in some cases.

IV. What guidance does this PR Notice provide?
This draft PR Notice communicates the Agency's approach to addressing herbicide-resistant weeds by providing guidance on labeling, education, training, and stewardship for herbicides undergoing registration or registration review. The Agency's guidance divides 28 herbicide MOAs into three categories of concern (low, moderate, high) based on the risk of developing herbicide-resistant weeds. The guidance also provides 11 elements that are focused on labeling, education, training, and stewardship strategies. Herbicides with the least concern for developing herbicide-resistant weeds will have the fewest resistance management elements, and herbicides with the greatest concern will have the most elements. The guidance in this draft PR Notice 2016-XX is intended to provide herbicide users and registrants with useful strategies that, when implemented, will slow herbicide resistance and prolong the useful life of herbicides. The beneficiaries of this draft PR Notice will be growers of crops that are, or may be, affected by herbicide-resistant weed and the registrants of herbicides. This draft PR Notice is applicable to all herbicides regulated by the Agency. Once the Agency receives and considers public comments on this draft PR Notice, we expect to revise and finalize the draft PR Notice by late 2016.

V. Do PR Notices contain binding requirements?
The PR Notice discussed in this FR Notice is intended to provide guidance to EPA personnel and decision-makers, as well as pesticide registrants. While the requirements in the statute and Agency regulations are binding on EPA and the applicants, this PR Notice is not binding on either EPA or pesticide registrants, and EPA may depart from the guidance where circumstances warrant and without prior notice. Likewise, pesticide registrants may assert that the guidance is not appropriate generally or not applicable to a specific pesticide or situation.

VI. References
The following is a listing of the documents that are specifically referenced in this document. The docket includes these documents and other information considered by EPA, including documents that are referenced within the documents that are included in the docket, even if the referenced document is not physically located in the docket. For assistance in locating these other documents, please consult the person listed under FOR FURTHER INFORMATION CONTACT .
1. Heap, I. 2016. International Survey of Herbicide-resistant Weeds. March 11, 2016. http://www.weedscience.org.
2. USDA. 2014. 2012 Census of Agriculture. United States Department of Agriculture.

Authority:
7 U.S.C. 136 et seq.
Dated: May 23, 2016.
Jack E. Housenger,

Director, Office of Pesticide Programs.
FEDERAL COMMUNICATIONS COMMISSION
Deletion of Consent Agenda Items From Sunshine Act Meeting
May 25, 2016.
The following consent agenda has been deleted from the list of items scheduled for consideration at the Wednesday, May 25, 2016, Open Meeting and previously listed in the Commission's Notice of May 18, 2016. Items 1, 5 and 6 on the consent agenda have been adopted by the Commission.
Consent Agenda
1 | MEDIA | TITLE: PMCM TV, LLC Licensee of Station WJLP(TV), Middletown Township, New Jersey. SUMMARY: The Commission will consider an Order concerning a Consent Decree entered into between the Commission and PMCM TV, LLC regarding compliance with children's programming requirements.
2 | ENFORCEMENT | TITLE: Enforcement Bureau Action. SUMMARY: The Commission will consider whether to take an enforcement action.
3 | ENFORCEMENT | TITLE: Enforcement Bureau Action. SUMMARY: The Commission will consider whether to take an enforcement action.
4 | ENFORCEMENT | TITLE: Enforcement Bureau Action. SUMMARY: The Commission will consider whether to take an enforcement action.
5 | ENFORCEMENT | TITLE: Enforcement Bureau Action. SUMMARY: The Commission will consider whether to take an enforcement action.
6 | ENFORCEMENT | TITLE: Enforcement Bureau Action. SUMMARY: The Commission will consider whether to take an enforcement action.
Federal Communication Commission.
Marlene H. Dortch,

Secretary.
GULF COAST ECOSYSTEM RESTORATION COUNCIL
[Docket No.: 106032016-1111-02]
Notice of Funding Availability for the Spill Impact Component of the RESTORE Act

AGENCY:
Gulf Coast Ecosystem Restoration Council (Council).

ACTION:
Notice.

SUMMARY:
The Gulf Coast Ecosystem Restoration Council (Council) announces the Notice of Funding Availability for the Spill Impact Component of the of the Resources and Ecosystems Sustainability, Tourist Opportunities, and Revived Economies of the Gulf Coast States Act of 2012 (RESTORE Act), 33 U.S.C. 1321(t)(3).

DATES:
State Expenditure Plans (SEPs), the first step in the process, will be accepted on a rolling basis, starting with the date of publication of the NOFA on Grants.gov , May 25, 2016.

FOR FURTHER INFORMATION CONTACT:
Kristin Smith, Council staff, telephone number: 504-444-3558.

SUPPLEMENTARY INFORMATION:
The Council is authorized to award grants pursuant to the Spill Impact Component of the Resources and Ecosystems Sustainability, Tourist Opportunities, and Revived Economies of the Gulf Coast States Act of 2012 (RESTORE Act),33 U.S.C. 1321(t)(3). The Council announces the Spill Impact Component Notice of Funding Availability (NOFA). The NOFA provides guidance to eligible entities on the steps necessary to submit an SEP for approval in the first phase as required by the RESTORE Act and to complete the second phase of submitting their grant applications for individual projects and programs contained in the State's approved SEP. Only projects contained in an approved SEP are eligible. The full text of the NOFA can be found at www.grants.gov and at https://www.restorethegulf.gov/spill-impact-component.
Will D. Spoon,

Program Analyst, Gulf Coast Ecosystem Restoration Council.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Centers for Medicare & Medicaid Services
[CMS-7041-N]
Health Insurance Marketplace ^{SM} , Medicare, Medicaid, and Children's Health Insurance Program; Meeting of the Advisory Panel on Outreach and Education (APOE), June 22, 2016

AGENCY:
Centers for Medicare & Medicaid Services (CMS), HHS.

ACTION:
Notice of meeting.

SUMMARY:
This notice announces the new meeting of the Advisory Panel on Outreach and Education (APOE) (the Panel) in accordance with the Federal Advisory Committee Act. The Panel advises and makes recommendations to the Secretary of the U.S. Department of Health and Human Services (HHS) and the Administrator of the Centers for Medicare & Medicaid Services (CMS) on opportunities to enhance the effectiveness of Health Insurance Marketplace ^{SM} , ^1 Medicare, Medicaid, and Children's Health Insurance Program (CHIP) consumer education strategies. This meeting is open to the public.
^1 Health Insurance Marketplace ^{SM} and Marketplace ^{SM} are service marks of the U.S. Department of Health & Human Services.

DATES:
Meeting Date: Wednesday, June 22, 2016 8:30 a.m. to 4:00 p.m. eastern daylight time (e.d.t).
Deadline for Meeting Registration, Presentations, Special Accommodations and Comments: Wednesday, June 8, 2016, 5:00 p.m., eastern daylight time (e.d.t.).

ADDRESSES:
Meeting Location: U.S. Department of Health & Human Services, Hubert H. Humphrey Building, 200 Independence Avenue SW., Room 425A, Conference Room, Washington, DC 20201.
Presentations and Written Comments: Presentations and written comments should be submitted to: Abigail Huffman, Designated Federal Official (DFO), Division of Forum and Conference Development, Office of Communications, Centers for Medicare & Medicaid Services, 7500 Security Boulevard, Mailstop S1-05-06, Baltimore, MD 21244-1850 or via email at Abigail.Huffman1@cms.hhs.gov.
Registration: The meeting is open to the public, but attendance is limited to the space available. Persons wishing to attend this meeting must register at the Web site https://www.regonline.com/apoejune2016meeting or, by contacting the DFO as listed in the FOR FURTHER INFORMATION CONTACT section of this notice, by the date listed in the DATES section of this notice. Individuals requiring sign language interpretation or other special accommodations should contact the DFO at the address listed in the ADDRESSES section of this notice by the date listed in the DATES section of this notice.

FOR FURTHER INFORMATION CONTACT:
Abigail Huffman, Designated Federal Official, Office of Communications, CMS, 7500 Security Boulevard, Mail Stop S1-05-06, Baltimore, MD 21244, 410-786-0897, email Abigail.Huffman1@cms.hhs.gov. Additional information about the APOE is available on the Internet at: http://www.cms.gov/Regulations-and-Guidance/Guidance/FACA/APOE.html. Press inquiries are handled through the CMS Press Office at (202) 690-6145.

SUPPLEMENTARY INFORMATION:

I. Background
The Advisory Panel for Outreach and Education (APOE) (the Panel) is governed by the provisions of Federal Advisory Committee Act (FACA) (Pub. L. 92-463), as amended (5 U.S.C. Appendix 2), which sets forth standards for the formation and use of federal advisory committees. The Panel is authorized by section 1114(f) of the Social Security Act (42 U.S.C. 1314(f)) and section 222 of the Public Health Service Act (42 U.S.C. 217a).
The Secretary of the U.S. Department of Health and Human Services (HHS) (the Secretary) signed the charter establishing the Citizen's Advisory Panel on Medicare Education ^2 (the predecessor to the APOE) on January 21, 1999 (64 FR 7899, February 17, 1999) to advise and make recommendations to the Secretary and the Administrator of the Centers for Medicare & Medicaid Services (CMS) on the effective implementation of national Medicare education programs, including with respect to the Medicare+Choice (M+C) program added by the Balanced Budget Act of 1997 (Pub. L. 105-33).
^2 We note that the Citizen's Advisory Panel on Medicare Education is also referred to as the Advisory Panel on Medicare Education (65 FR 4617). The name was updated in the Second Amended Charter approved on July 24, 2000.
The Medicare Modernization Act of 2003 (MMA) (Pub. L. 108-173) expanded the existing health plan options and benefits available under the M+C program and renamed it the Medicare Advantage (MA) program. We have had substantial responsibilities to provide information to Medicare beneficiaries about the range of health plan options available and better tools to evaluate these options. The successful MA program implementation required CMS to consider the views and policy input from a variety of private sector constituents and to develop a broad range of public-private partnerships.
In addition, Title I of the MMA authorized the Secretary and the Administrator of CMS (by delegation) to establish the Medicare prescription drug benefit. The drug benefit allows beneficiaries to obtain qualified prescription drug coverage. In order to effectively administer the MA program and the Medicare prescription drug benefit, we have substantial responsibilities to provide information to Medicare beneficiaries about the range of health plan options and benefits available, and to develop better tools to evaluate these plans and benefits.
The Affordable Care Act (Patient Protection and Affordable Care Act, Pub. L. 111-148, and Health Care and Education Reconciliation Act of 2010, Pub. L. 111-152) expanded the availability of other options for health care coverage and enacted a number of changes to Medicare as well as to Medicaid and the Children's Health Insurance Program (CHIP). Qualified individuals and qualified employers are now able to purchase private health insurance coverage through competitive marketplaces, called Affordable Insurance Exchanges (we also call an Exchange a Health Insurance Marketplace ^{SM} or Marketplace ^{SM} ). In order to effectively implement and administer these changes, we must provide information to consumers, providers, and other stakeholders through education and outreach programs regarding how existing programs will change and the expanded range of health coverage options available, including private health insurance coverage through the Marketplace ^{SM} . The APOE (the Panel) allows us to consider a broad range of views and information from interested audiences in connection with this effort and to identify opportunities to enhance the effectiveness of education strategies concerning the Affordable Care Act.
The scope of this panel also includes advising on issues pertaining to the education of providers and stakeholders with respect to the Affordable Care Act and certain provisions of the Health Information Technology for Economic and Clinical Health (HITECH) Act enacted as part of the American Recovery and Reinvestment Act of 2009 (ARRA).
On January 21, 2011, the Panel's charter was renewed and the Panel was renamed the Advisory Panel for Outreach and Education. The Panel's charter was most recently renewed on January 21, 2015, and will terminate on January 21, 2017 unless renewed by appropriate action.
Under the current charter, the APOE will advise the Secretary and the Administrator on optimal strategies for the following:
• Developing and implementing education and outreach programs for individuals enrolled in, or eligible for, Medicare, Medicaid, and the Children's Health Insurance Program (CHIP), or coverage available through the Health Insurance Marketplace ^{SM} .
• Enhancing the federal government's effectiveness in informing Health Insurance Marketplace ^{SM} , Medicare, Medicaid, and CHIP consumers, issuers, providers, and stakeholders, through education and outreach programs, on issues regarding these programs, including the appropriate use of public-private partnerships to leverage the resources of the private sector in educating beneficiaries, providers, and stakeholders.
• Expanding outreach to vulnerable and underserved communities, including racial and ethnic minorities, in the context of Health Insurance Marketplace ^{SM} , Medicare, Medicaid, and CHIP education programs.
• Assembling and sharing an information base of “best practices” for helping consumers evaluate health coverage options.
• Building and leveraging existing community infrastructures for information, counseling, and assistance.
• Drawing the program link between outreach and education, promoting consumer understanding of health care coverage choices, and facilitating consumer selection/enrollment, which in turn support the overarching goal of improved access to quality care, including prevention services, envisioned under the Affordable Care Act.
The current members of the Panel are: Kellan Baker, Associate Director, Center for American Progress; Robert Blancato, President, Matz, Blancato & Associates; Dale Blasier, Professor of Orthopedic Surgery, Department of Orthopedics, Arkansas Children's Hospital; Deborah Britt, Executive Director of Community & Public Relations, Piedmont Fayette Hospital; Deena Chisolm, Associate Professor of Pediatrics & Public Health, The Ohio State University, Nationwide Children's Hospital; Josephine DeLeon, Director, Anti-Poverty Initiatives, Catholic Charities of California; Robert Espinoza, Vice President of Policy, Paraprofessional Healthcare Institute; Jennifer Gross, Manager of Political Field Operations, Planned Parenthood of Montana; Louise Scherer Knight, Director, The Sidney Kimmel Comprehensive Cancer Center at Johns Hopkins; Miriam Mobley-Smith, Dean, Director of Strategic Alliances, Pharmacy Technician Certification Board; Roanne Osborne-Gaskin, M.D., Senior Medical Director, MDWise, Inc.; Cathy Phan, Outreach and Education Coordinator, Asian American Health Coalition DBA HOPE Clinic; Kamilah Pickett, Litigation Support, Independent Contractor; Brendan Riley, Outreach and Enrollment Coordinator, NC Community Health Center Association; Alvia Siddiqi, Medicaid Managed Care Community Network (MCCN) Medical Director, Advocate Physician Partners, Carla Smith, Executive Vice President, Healthcare Information and Management Systems Society (HIMSS); Tobin Van Ostern, Vice President and Co-Founder, Young Invincible Advisors; and Paula Villescaz, Senior Consultant, Assembly Health Committee, California State Legislature.

II. Meeting Agenda
In accordance with section 10(a) of the FACA, this notice announces a meeting of the APOE. The agenda for the June 22, 2016 meeting will include the following:
• Welcome and listening session with CMS leadership
• Recap of the previous (January 13, 2016) meeting
• Affordable Care Act initiatives
• An opportunity for public comment
• Meeting summary, review of recommendations, and next steps
Individuals or organizations that wish to make a 5-minute oral presentation on an agenda topic should submit a written copy of the oral presentation to the DFO at the address listed in the ADDRESSES section of this notice by the date listed in the DATES section of this notice. The number of oral presentations may be limited by the time available. Individuals not wishing to make an oral presentation may submit written comments to the DFO at the address listed in the ADDRESSES section of this notice by the date listed in the DATES section of this notice.

III. Security, Building, and Parking Guidelines
This meeting will be held in a federal government building; therefore, federal security measures are applicable. The Real ID Act, enacted in 2005, establishes minimum standards for the issuance of state-issued driver's licenses and identification (ID) cards. It prohibits Federal agencies from accepting an official driver's license or ID card from a state unless the Department of Homeland Security determines that the state meets these standards. Beginning October 2015, photo IDs (such as a valid driver's license) issued by a state or territory not in compliance with the Real ID Act will not be accepted as identification to enter Federal buildings. Visitors from these states/territories will need to provide alternative proof of identification (such as a valid passport) to gain entrance into CMS buildings. The current list of states from which a Federal agency may accept driver's licenses for an official purpose is found at http://www.dhs.gov/real-id-enforcement-brief. We recommend that confirmed registrants arrive reasonably early, but no earlier than 45 minutes prior to the start of the meeting, to allow additional time to clear security. Security measures include the following:
• Presentation of government issued photographic identification to the Federal Protective Service or Guard Service personnel.
• Inspection of vehicle's interior and exterior (this includes engine and trunk inspection) at the entrance to the grounds. Parking permits and instructions will be issued after the vehicle inspection.
• Inspection, via metal detector or other applicable means, of all persons entering the building. We note that all items brought into CMS, whether personal or for the purpose of presentation or to support a presentation, are subject to inspection. We cannot assume responsibility for coordinating the receipt, transfer, transport, storage, set up, safety, or timely arrival of any personal belongings or items used for presentation or to support a presentation.
Note: Individuals who are not registered in advance will not be permitted to enter the building and will be unable to attend the meeting. The public may not enter the building earlier than 45 minutes prior to the convening of the meeting.
All visitors must be escorted in areas other than the lower and first floor levels in the Central Building.

Authority:
Sec. 222 of the Public Health Service Act (42 U.S.C. 217a) and sec. 10(a) of Pub. L. 92-463 (5 U.S.C. App. 2, sec. 10(a) and 41 CFR 102-3).
Dated: May 26, 2016.
Andrew M. Slavitt,

Acting Administrator, Centers for Medicare & Medicaid Services.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Centers for Medicare & Medicaid Services
[CMS-1666-N]
Medicare, Medicaid, and Children's Health Insurance Programs; Announcement of the Advisory Panel on Clinical Diagnostic Laboratory Tests Meeting on July 18, 2016

AGENCY:
Centers for Medicare & Medicaid Services (CMS), HHS.

ACTION:
Notice.

SUMMARY:
This notice announces the next public meeting date of the Advisory Panel on Clinical Diagnostic Laboratory Tests (the Panel) on Monday, July 18, 2016. The purpose of the Panel is to advise the Secretary of the Department of Health and Human Services (DHHS) and the Administrator of the Centers for Medicare & Medicaid Services (CMS) (the Administrator) on issues related to clinical diagnostic laboratory tests.

DATES:
Meeting Date: The meeting of the Panel is scheduled for Monday, July 18, 2016 beginning at 9:00 a.m., Eastern Daylight Time (EDT). The morning session will be held jointly with the Public Meeting on New and Reconsidered Clinical Diagnostic Laboratory Test Codes for the Clinical Laboratory Fee Schedule (CLFS) for Calendar Year (CY) 2017 (the 2016 Laboratory Public Meeting) ( see 81 FR 29863, May 13, 2016 for notice of the 2016 Laboratory Public Meeting). During the afternoon session, the Panel will deliberate and make recommendations regarding the new and reconsidered laboratory codes for CY 2017. The Panel may also hear public presentations on additional issues concerning the CY 2017 CLFS that are designated in the Panel's charter and specified in the Panel meeting agenda for the afternoon session.
Meeting Registration: The public may attend the Panel meeting in-person, view via webcast, or listen via teleconference. Beginning Monday, June 6, 2016 and ending Friday, July 1, 2016 at 5:00 p.m. EDT, registration to attend the Panel meeting in-person may be completed online at http://cms.gov/Regulations-and-Guidance/Guidance/FACA/AdvisoryPanelonClinicalDiagnosticLaboratoryTests.html. On this Web page, under “Related Links,” double-click the “Clinical Diagnostic Laboratory Tests FACA Panel Meeting Registration” link and enter the required information. All the following information must be submitted when registering:
• Name.
• Company name.
• Address.
• Email addresses.

Note:
Participants who do not plan to attend the Panel meeting in-person on July 18, 2016 should not register. No registration is required for participants who plan to view the Panel meeting via webcast or listen via teleconference. Participants planning to attend only the morning session which includes the 2016 Laboratory Public Meeting, or both the morning and afternoon sessions, should register only once, for the 2016 Laboratory Public Meeting ( see instructions for registering for the 2016 Laboratory Public Meeting at 81 FR 29863). Participants planning to attend only the afternoon session of the Panel meeting must register using the above link and instructions.
Presenter Registration and Submission of Presentations and Comments: In the morning session only, we are interested in in-person presentations concerning the payment methodologies for new or reconsidered laboratory codes. The instructions for submitting such comments and presentations are also included in 2016 Laboratory Public Meeting notice (81 FR 29863). Although these comments and presentations will be made during the morning joint session of the 2016 Laboratory Public Meeting and Panel Meeting, the Panel may wish to ask follow-up questions to presenters at the afternoon session of the Panel Meeting.
As previously mentioned, additional issues concerning the calendar year (CY) 2017 clinical laboratory fee schedule (CLFS) that are designated in the Panel's charter and specified in the meeting agenda, may also be discussed at the afternoon session of the Panel meeting. Any such issues to be discussed will be specified in the Panel meeting agenda, to be published approximately 3 weeks before the meeting (A preliminary agenda is described in section II. of this notice.) Should issues be added to the agenda, we would be interested in public comments or presentations related to those issues. The comments and presentations should not address issues not specified in the agenda for the Panel meeting. The deadline to register to be a presenter and to submit written presentations for agenda items for the Panel's afternoon session (that is, presentations on issues other than payment for new and reconsidered laboratory codes for CY 2017) is 5:00 p.m. EDT July 1, 2016. Presenters may register by email by contacting the person listed in the FOR FURTHER INFORMATION CONTACT section of this notice. Presentations should be sent via email to the same person's email address.
Meeting Location, Webcast, and Teleconference: The Panel meetings will be held in the Auditorium of the CMS, Central Office, 7500 Security Boulevard, Baltimore, Maryland 21244-1850. Alternately, the public may either view the Panel meetings via a webcast or listen by teleconference. During the scheduled Panel meeting, webcasting is accessible online at http://cms.gov/live. Teleconference dial-in information will appear on the final Panel meeting agenda, which will be posted on the CMS Web site when available at http://cms.gov/Regulations-and-Guidance/Guidance/FACA/AdvisoryPanelonClinicalDiagnosticLaboratoryTests.html.
Meeting Format: This Panel meeting is open to the public. The on-site check-in for visitors will be held from 8:30 a.m. to 9:00 a.m. on Monday, July 18, 2016, preceding the morning session of the 2016 Laboratory Public Meeting, and again at 12:30 p.m. for visitors attending only the Panel meeting (afternoon session).
During the morning session, the Panel, along with the public, will hear and pose questions to presenters recommending crosswalks or gapfilling for new and reconsidered laboratory codes for calendar year (CY) 2017. During the afternoon session, the Panel will deliberate and make recommendations to the Secretary of HHS and the Acting Administrator of CMS regarding crosswalks or gapfilling for new and reconsidered laboratory codes discussed during the morning session. The Panel may also hear public presentations (for a total time period of no more than one hour) and provide input on other CY 2017 CLFS issues that are designated in the Panel's charter and specified on meeting agenda. Both the morning and afternoon sessions are open to the public.

ADDRESSES:
Web site: For additional information on the Panel, please refer to our Web site at https://www.cms.gov/Regulations-and-Guidance/Guidance/FACA/AdvisoryPanelonClinicalDiagnosticLaboratoryTests.html .

FOR FURTHER INFORMATION CONTACT:
Glenn C. McGuirk, Designated Federal Official (DFO), Center for Medicare, Division of Ambulatory Services, CMS, 7500 Security Boulevard, Mail Stop C4-01-26, Baltimore, MD 21244, 410-786-5723, email CDLTPanel@cms.hhs.gov or Glenn.McGuirk@cms.hhs.gov. Press inquiries are handled through the CMS Press Office at (202) 690-6145.

SUPPLEMENTARY INFORMATION:

I. Background
The Advisory Panel on Clinical Diagnostic Laboratory Tests is authorized by section 1834A(f)(1) of the Social Security Act (the Act) (42 U.S.C. 1395m-1), as established by section 216(a) of the Protecting Access to Medicare Act of 2014 (PAMA) (Pub. L. 113-93, enacted April 1, 2014).The Panel is subject to the Federal Advisory Committee Act (FACA), as amended (5 U.S.C. Appendix 2), which sets forth standards for the formation and use of advisory panels.
Section 1834A(f)(1) of the Act directs the Secretary of the Department of Health and Human Services (the Secretary) to consult with an expert outside advisory panel established by the Secretary, composed of an appropriate selection of individuals with expertise in issues related to clinical diagnostic laboratory tests. Such individuals may include molecular pathologists, clinical laboratory researchers, and individuals with expertise in laboratory science or health economics.
The Panel will provide input and recommendations to the Secretary and the Acting Administrator of CMS, on the following:
• The establishment of payment rates under section 1834A of the Act for new clinical diagnostic laboratory tests, including whether to use crosswalking or gapfilling processes to determine payment for a specific new test;
• The factors used in determining coverage and payment processes for new clinical diagnostic laboratory tests; and
• Other aspects of the upcoming new payment system, to be based on private payor rates, under section 1834A of the Act.
A notice announcing the establishment of the Panel and soliciting nominations for members was published in the October 27, 2014 Federal Register (79 FR 63919 through 63920). In the August 7, 2015 Federal Register (80 FR 47491), we announced membership appointments to the Panel along with the first public meeting date for the Panel, which was held on August 26, 2015.
The Panel charter provides that panel meetings will be held up to four times annually. The Panel consists of 15 individuals and a Chair. The Panel Chair facilitates the meeting and the Designated Federal Official (DFO) or DFO's designee must be present at all meetings.

II. Agenda
The Agenda for the July 18, 2016, Panel meeting will provide for discussion and comment on the following topics as designated in the Panel's Charter:
• CY 2017 CLFS new and reconsidered test codes which were posted on May 12, 2016, on our Web site at https://www.cms.gov/Medicare/Medicare-Fee-for-Service-Payment/ClinicalLabFeeSched/Laboratory_Public_Meetings.html
• Other CY 2017 CLFS issues designated in the Panel's charter and further described on our Agenda.
A detailed Agenda will be posted approximately 3 weeks before the meeting, on our Web site at http://cms.gov/Regulations-andGuidance/Guidance/FACA/AdvisoryPanelonClinicalDiagnosticLaboratoryTests.html.

III. Meeting Attendance
The Panel's meeting on July 18, 2016, is open to the public. Priority will be given to those who pre-register and attendance may be limited based on the number of registrants and the space available.
Persons wishing to attend this meeting, which is located on federal property, must register by following the instructions in the “Meeting Registration” section of this notice. A confirmation email will be sent to the registrants shortly after completing the registration process.

IV. Security, Building, and Parking Guidelines
The following are the security, building, and parking guidelines:
• Persons attending the meeting, including presenters, must be pre-registered and on the attendance list by the prescribed date.
• Individuals who are not pre-registered in advance may not be permitted to enter the building and may be unable to attend the meeting.
• Attendees must present a government-issued photo identification to the Federal Protective Service or Guard Service personnel before entering the building. Without a current, valid photo ID, persons may not be permitted entry to the building.
• Security measures include inspection of vehicles, inside and out, at the entrance to the grounds.
• All persons entering the building must pass through a metal detector.
• All items brought into CMS including personal items, for example, laptops and cell phones, are subject to physical inspection.
• The public may enter the building 30 to 45 minutes before the meeting convenes each day.
• All visitors must be escorted in areas other than the lower and first-floor levels in the Central Building.
• The main-entrance guards will issue parking permits and instructions upon arrival at the building.

V. Special Accommodations
Individuals requiring special accommodations must include the request for these services during registration.

VI. Panel Recommendations and Discussions
The Panel's recommendations will be posted after the meeting on our Web site at http://cms.gov/Regulations-andGuidance/Guidance/FACA/AdvisoryPanelonClinicalDiagnosticLaboratoryTests.html.

VIII. Copies of the Charter
The Secretary's Charter for the Advisory Panel on Clinical Diagnostic Laboratory Tests is available on our Web site at http://cms.gov/Regulations-and-Guidance/Guidance/FACA/AdvisoryPanelonClinicalDiagnosticLaboratoryTests.html or you may obtain a copy of the charter by submitting a request to the contact listed in the FOR FURTHER INFORMATION CONTACT section of this notice.

IX. 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. ).
Dated: May 25, 2016.
Andrew M. Slavitt,

Acting Administrator, Centers for Medicare & Medicaid Services.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Administration for Children and Families
Proposed Information Collection Activity; Comment Request
Title: Migrant and Seasonal Head Start Study.
OMB No.: New Collection.
Description: The Office of Planning, Research and Evaluation (OPRE), Administration for Children and Families (ACF), U.S. Department of Health and Human Services, is proposing an information collection activity for the Migrant and Seasonal Head Start (MSHS) Study.
The MSHS Study will describe the characteristics and experiences of the children and families who enroll in MSHS and the practices and services of the MSHS programs that serve them. The findings will provide up-to-date information to the Office of Head Start, other federal government agencies, local MSHS programs, and the public. The study will be the first national MSHS study to include direct child assessments, which will provide information about MSHS children that programs can use to inform program, center and classroom practices.
Data collection will involve mail surveys to selected MSHS center directors and all MSHS program directors nationwide about operational characteristics, program- and center-level policies and practices, and services and resources offered to MSHS families. The study will also conduct on-site data collection with children, parents, teachers, and classrooms in a nationally-representative sample of MSHS centers. The on-site data collection will include classroom observations, teacher surveys, child reports and child assessments.
Respondents: MSHS program directors, center directors, teachers, assistant teachers, parents, and children.
Annual Burden Estimates
Instrument | Total number of respondents | Number of responses per respondent | Average burden hours per response | Estimated annual burden hours
Program Director survey | 53 | 1 | 0.5 | 27
Center Director survey | 253 | 1 | 0.5 | 127
Call script for Program Directors | 24 | 1 | 1 | 24
Form for Program Directors to verify key information for selected centers | 24 | 1 | 0.5 | 12
Call script for Center Directors | 53 | 1 | 1 | 53
Call script for On Site Coordinators | 53 | 1 | 1 | 53
Classroom sampling form | 53 | 1 | 0.5 | 27
Child roster form | 53 | 3 | 0.25 | 40
Teacher survey | 159 | 1 | 0.5 | 80
Teacher child report | 159 | 8 | 0.25 | 318
Assistant Teacher survey | 159 | 1 | 0.25 | 40
Parent consent form | 1,018 | 1 | 0.25 | 255
Child assessments (preschoolers and older toddlers only) | 848 | 1 | 0.75 | 636
Parent interview (including Parent child report) | 1,018 | 1 | 1 | 1,018
Estimated Total Annual Burden Hours: 2,710.
In compliance with the requirements of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Administration for Children and Families is soliciting public comment on the specific aspects of the information collection described above. Copies of the proposed collection of information can be obtained and comments may be forwarded by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 330 C Street SW., Washington, DC 20201, Attn: OPRE Reports Clearance Officer. Email address: OPREinfocollection@acf.hhs.gov. All requests should be identified by the title of the information collection.
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.
Robert Sargis,

ACF Certifying Officer.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
[Docket No. FDA-2016-N-0628]
Agency Information Collection Activities; Submission for Office of Management and Budget Review; Comment Request; Reporting Associated With New Animal Drug Applications

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Notice.

SUMMARY:
The Food and Drug Administration (FDA) is announcing that a proposed collection of information has been submitted to the Office of Management and Budget (OMB) for review and clearance under the Paperwork Reduction Act of 1995.

DATES:
Fax written comments on the collection of information by July 5, 2016.

ADDRESSES:
To ensure that comments on the information collection are received, OMB recommends that written comments be faxed to the Office of Information and Regulatory Affairs, OMB, Attn: FDA Desk Officer, FAX: 202-395-7285, or emailed to oira_submission@omb.eop.gov. All comments should be identified with the OMB control number 0910-0032. Also include the FDA docket number found in brackets in the heading of this document.

FOR FURTHER INFORMATION CONTACT:
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002, PRAStaff@fda.hhs.gov.

SUPPLEMENTARY INFORMATION:
In compliance with 44 U.S.C. 3507, FDA has submitted the following proposed collection of information to OMB for review and clearance.

Reporting Associated With New Animal Drug Applications (NADA)—21 CFR 514.1, 514.4, 514.5, 514.6, 514.8, 514.11, 558.5—OMB Control Number 0910-0032—Extension
Under Section 512(b)(1) of the Federal Food, Drug, and Cosmetic Act (the FD&C Act) (21 U.S.C. 360b(b)(1)), any person may file a new animal drug application (NADA) seeking our approval to legally market a new animal drug. Section 512(b)(1) sets forth the information required to be submitted in a NADA. Sections 514.1, 514.4, 514.6, 514.8, and 514.11 of our regulations (21 CFR 514.1, 514.4, 514.6, 514.8, and 514.11) further specify the information that the NADA must contain. The application must include safety and effectiveness data, proposed labeling, product manufacturing information and, where necessary, complete information on food safety (including microbial food safety) and any methods used to determine residues of drug chemicals in edible tissue from food producing animals. FDA Guidance #152 outlines a risk assessment approach for evaluating the microbial food safety of antimicrobial new animal drugs. We request that applicants utilize Form FDA 356V, as appropriate, to ensure efficient and accurate processing of information to support new animal drug approval.
Under section 512(b)(3) of the FD&C Act, any person intending to file a NADA or supplemental NADA or a request for an investigational exemption under section 512(j) of the FD&C Act is entitled to one or more conferences with us prior to making a submission. Section 514.5 of our regulations (21 CFR 514.5) describes the procedures for requesting, conducting, and documenting pre-submission conferences. We have found that these meetings have increased the efficiency of the drug development and drug review processes. We encourage sponsors to submit data for review at the most appropriate and productive times in the drug development process. Rather than submitting all data for review as part of a complete application, we have found that the submission of data supporting discrete technical sections during the investigational phase of the new animal drug is the most appropriate and productive. This “phased review” of data submissions has created efficiencies for both us and the animal pharmaceutical industry.
Finally, § 558.5(i) of our regulations (21 CFR 558.5(i)) describes the procedure for requesting a waiver of the labeling requirements of § 558.5(h) in the event that there is evidence to indicate that it is unlikely a new animal drug would be used in the manufacture of a liquid medicated feed.
The reporting associated with NADAs and related submissions is necessary to ensure that new animal drugs are in compliance with section 512(b)(1) of the FD&C Act. We use the information collected to review the data, labeling, and manufacturing controls and procedures to evaluate the safety and effectiveness of the proposed new animal drug.
In the Federal Register of March 2, 2016 (81 FR 10871), FDA published a 60-day notice requesting public comment on the proposed collection of information. No comments were received.
We estimate the burden of this collection of information as follows:
Table 1—Estimated Annual Reporting Burden ^1
21 CFR Section; Activity | Number of respondents | Number of responses per respondent | Total annual responses | Avg. burden per response | Total hours
514.1 & 514.6; applications and amended applications | 182 | .05 | 9 | 212 | 1,908
514.1(b)(8) and 514.8(c)(1) ^2 ; evidence to establish safety and effectiveness | 182 | .10 | 19 | 90 | 1,710
514.5(b), (d), (f); requesting presubmission conferences | 182 | .49 | 89 | 50 | 4,450
514.8(b); manufacturing changes to an approved application | 182 | 1.40 | 255 | 35 | 8,925
514.8(c)(1); labeling and other changes to an approved application | 182 | .05 | 10 | 71 | 710
514.8(c)(2) & (3); labeling and other changes to an approved application | 182 | .43 | 79 | 20 | 1,580
514.11; submission of data, studies and other information | 182 | .09 | 16 | 1 | 16
558.5(i); requirements for liquid medicated feed | 182 | .01 | 1 | 5 | 5
Form FDA 356V | 182 | 2.92 | 531 | 5 | 2,655
TOTAL | | | 1009 | | 21,959
^1 There are no capital costs or operating and maintenance costs associated with this collection of information.
^2 NADAs and supplements regarding antimicrobial animal drugs that use a recommended approach to assessing antimicrobial concerns as part of the overall pre-approval safety evaluation.
Based on the number of sponsors subject to animal drug user fees, we estimate an average of 182 annual respondents during the 5 fiscal years, from October 1, 2010, through September 30, 2014, on which these estimates were made. We use this estimate consistently throughout the table and calculate the “annual frequency per respondent” by dividing the total annual responses by the total number of respondents. We base our estimates of the average burden per response on our experience with NADAs and related submissions.
Dated: May 27, 2016.
Leslie Kux,

Associate Commissioner for Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
[Docket No. FDA-2015-D-0268]
Individual Patient Expanded Access Applications: Form FDA 3926; Guidance for Industry; Availability

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Notice of availability.

SUMMARY:
The Food and Drug Administration (FDA or Agency) is announcing the availability of a guidance for industry entitled “Individual Patient Expanded Access Applications: Form FDA 3926.” The guidance describes Form FDA 3926 (Individual Patient Expanded Access—Investigational New Drug Application (IND)), which is available for licensed physicians to use for expanded access requests for individual patient INDs. Individual patient expanded access allows for the use of an investigational new drug outside of a clinical investigation, or the use of an approved drug where availability is limited by a risk evaluation and mitigation strategy (REMS), for an individual patient who has a serious or immediately life-threatening disease or condition when there is no comparable or satisfactory alternative therapy to diagnose, monitor, or treat the disease or condition. Form FDA 3926 provides a streamlined alternative for submitting an IND for use in cases of individual patient expanded access, including for emergency use. This guidance finalizes the draft guidance issued in February 2015.

DATES:
Submit either electronic or written comments on Agency guidances at any time.

ADDRESSES:
You may submit comments as follows:

Electronic Submissions
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
http://www.regulations.gov. Follow the instructions for submitting comments. Comments submitted electronically, including attachments, to http://www.regulations.gov will be posted to the docket unchanged. Because your comment will be made public, you are solely responsible for ensuring that your comment does not include any confidential information that you or a third party may not wish to be posted, such as medical information, your or anyone else's Social Security number, or confidential business information, such as a manufacturing process. Please note that if you include your name, contact information, or other information that identifies you in the body of your comments, that information will be posted on http://www.regulations.gov.
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).

Written/Paper Submissions
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
Instructions: All submissions received must include the Docket No. FDA-2015-D-0268 for “Individual Patient Expanded Access Applications: Form FDA 3926; Guidance for Industry; Availability.” Received comments will be placed in the docket and, except for those submitted as “Confidential Submissions,” publicly viewable at http://www.regulations.gov or at the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on http://www.regulations.gov. Submit both copies to the Division of Dockets Management. If you do not wish your name and contact information to be made publicly available, you can provide this information on the cover sheet and not in the body of your comments and you must identify this information as “confidential.” Any information marked as “confidential” will not be disclosed except in accordance with 21 CFR 10.20 and other applicable disclosure law. For more information about FDA's posting of comments to public dockets, see 80 FR 56469, September 18, 2015, or access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm.
Docket: For access to the docket to read background documents or the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in the heading of this document, into the “Search” box and follow the prompts and/or go to the Division of Dockets Management, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
Submit written requests for single copies of this guidance to the Division of Drug Information, Center for Drug Evaluation and Research, Food and Drug Administration, 10001 New Hampshire Ave., Hillandale Building, 4th Floor, Silver Spring, MD 20993-0002; or to the Office of Communication, Outreach and Development, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 3128, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the SUPPLEMENTARY INFORMATION section for electronic access to the guidance document.

FOR FURTHER INFORMATION CONTACT:
Larry Lim, Center for Drug Evaluation and Research, Food and Drug Administration, 10001 New Hampshire Ave., Hillandale Bldg., Rm. 4134, Silver Spring, MD 20993, 301-796-3146; or Stephen Ripley, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 7301, Silver Spring, MD 20993-0002, 240-402-7911.

SUPPLEMENTARY INFORMATION:

I. Background
FDA is announcing the availability of a guidance for industry entitled “Individual Patient Expanded Access Applications: Form FDA 3926.” The guidance describes Form FDA 3926, which is available for licensed physicians to use for expanded access requests for individual patient INDs. FDA's current expanded access regulations (21 CFR part 312, subpart I) went into effect on October 13, 2009 (74 FR 40900). Expanded access refers to the use of an investigational drug when the primary purpose is to diagnose, monitor, or treat a patient rather than to obtain the kind of information about the drug that is generally derived from clinical trials. Under the regulations, there are three categories of expanded access: (1) Expanded access for individual patients, including for emergency use; (2) expanded access for intermediate-size patient populations (generally smaller than those typical of a treatment IND or treatment protocol—a treatment protocol is submitted as a protocol amendment to an existing IND by the sponsor of the existing IND); and (3) expanded access for widespread treatment use through a treatment protocol or treatment IND (designed for use in larger patient populations). The regulations are intended to facilitate the availability of investigational new drugs outside of a clinical investigation, or approved drugs where availability is limited by a REMS, to patients with serious or immediately life-threatening diseases or conditions when there is no comparable or satisfactory alternative therapy to diagnose, monitor, or treat the disease or condition.
Elsewhere in this issue of the Federal Register, FDA is announcing the availability of a guidance for industry entitled “Expanded Access to Investigational Drugs for Treatment Use—Questions and Answers,” which provides answers to questions concerning the implementation of FDA's regulations on expanded access to investigational drugs for treatment use (21 CFR part 312, subpart I). (FDA's guidance documents are available at http://www.fda.gov/Drugs/GuidanceComplianceRegulatoryInformation/Guidances/default.htm. FDA has verified the Web site addresses throughout this document, as of the date this document publishes in the Federal Register , but Web sites are subject to change over time.)
Additionally, in this issue of the Federal Register , FDA is announcing the availability of a guidance for industry entitled “Charging for Investigational Drugs Under an IND—Questions and Answers,” which provides information about the implementation of FDA's regulation on charging for investigational drugs under an IND, including investigational drugs made available for expanded access use.
FDA may permit expanded access to an investigational new drug outside of a clinical investigation, or to an approved drug where availability is limited by a REMS, for an individual patient when the applicable criteria in § 312.305(a) (which apply to all types of expanded access) and in § 312.310(a) (which apply specifically to individual patient expanded access, including for emergency use) are met. In addition, § 312.305(b) sets forth the submission requirements for all types of expanded access use requests. One of the requirements under § 312.305(b)(2) is that a “cover sheet” must be included “meeting the requirements of § 312.23(a).” This provision applies to several types of submissions under part 312, ranging from commercial INDs under § 312.23 that involve large groups of patients enrolled in clinical trials to requests from physicians to use an investigational drug for an individual patient. Form FDA 1571 is currently used by sponsors for all types of IND submissions. However, FDA is concerned that physicians requesting expanded access for an individual patient may have encountered difficulty in completing Form FDA 1571 and providing the associated documents because Form FDA 1571 is not tailored to requests for individual patient expanded access.
To streamline the submission process for individual patient expanded access INDs, FDA developed Form FDA 3926, which is available for licensed physicians to use to request expanded access to an investigational drug outside of a clinical investigation, or to an approved drug where availability is limited by a REMS, for an individual patient who has a serious or immediately life-threatening disease or condition when there is no comparable or satisfactory alternative therapy to diagnose, monitor, or treat the disease or condition.
In an emergency situation that requires the patient to be treated before a written submission can be made, the request to use the investigational drug for individual patient expanded access may be made by telephone (or other rapid means of communication) to the appropriate FDA review division. Authorization of the emergency use may be given by an FDA official by telephone, provided the physician explains how the expanded access use will meet the requirements of §§ 312.305 and 312.310 and agrees to submit an expanded access request within 15 working days of FDA's initial authorization of the expanded access use (§ 312.310(d)). The physician may choose to use Form FDA 3926 for the expanded access application.
In the Federal Register of February 10, 2015 (80 FR 7318), FDA announced the availability of the draft guidance. FDA received several comments on the draft guidance and those comments were considered as the guidance was finalized. Both the guidance and Form FDA 3926 were revised based on public comments and editorial changes were made primarily for clarification. One notable change includes the ability to use Form FDA 3926 for subsequent submissions to an existing individual patient expanded access IND.
This guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The guidance represents the current thinking of FDA on the use of Form FDA 3926 by licensed physicians to submit requests for individual patient expanded access INDs. It does not establish any rights for any person and is not binding on FDA or the public. You can use an alternative approach if it satisfies the requirements of the applicable statutes and regulations.

II. Paperwork Reduction Act of 1995
This guidance contains information collection provisions that are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The collection of information in this guidance was approved under OMB control number 0910-0814.
This guidance also refers to previously approved collections of information found in FDA regulations. The collections of information in 21 CFR part 312 have been approved under OMB control number 0910-0014.

III. Electronic Access
Persons with access to the Internet may obtain the document at http://www.fda.gov/RegulatoryInformation/Guidances/default.htm, http://www.fda.gov/BiologicsBloodVaccines/GuidanceComplianceRegulatoryInformation/Guidances/default.htm, or http://www.regulations.gov.
Dated: May 31, 2016.
Leslie Kux,

Associate Commissioner for Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
[Docket No. FDA-2013-D-0446]
Expanded Access to Investigational Drugs for Treatment Use—Questions and Answers; Guidance for Industry; Availability

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Notice of availability.

SUMMARY:
The Food and Drug Administration (FDA or Agency) is announcing the availability of a guidance for industry entitled “Expanded Access to Investigational Drugs for Treatment Use—Questions and Answers.” The guidance provides information for industry, researchers, physicians, institutional review boards (IRBs), and patients about the implementation of FDA's regulations on expanded access to investigational drugs for treatment use under an investigational new drug application (IND). FDA received a number of questions concerning implementation of its expanded access regulations and is providing guidance in a question and answer format to address the most frequently asked questions. This guidance finalizes the draft guidance issued in May 2013.

DATES:
Submit either electronic or written comments on Agency guidances at any time.

ADDRESSES:
You may submit comments as follows:

Electronic Submissions
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
http://www.regulations.gov . Follow the instructions for submitting comments. Comments submitted electronically, including attachments, to http://www.regulations.gov will be posted to the docket unchanged. Because your comment will be made public, you are solely responsible for ensuring that your comment does not include any confidential information that you or a third party may not wish to be posted, such as medical information, your or anyone else's Social Security number, or confidential business information, such as a manufacturing process. Please note that if you include your name, contact information, or other information that identifies you in the body of your comments, that information will be posted on http://www.regulations.gov .
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).

Written/Paper Submissions
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
Instructions: All submissions received must include the Docket No. FDA-2013-D-0446 for “Expanded Access to Investigational Drugs for Treatment Use—Questions and Answers; Guidance for Industry; Availability.” Received comments will be placed in the docket and, except for those submitted as “Confidential Submissions,” publicly viewable at http://www.regulations.gov or at the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on http://www.regulations.gov . Submit both copies to the Division of Dockets Management. If you do not wish your name and contact information to be made publicly available, you can provide this information on the cover sheet and not in the body of your comments and you must identify this information as “confidential.” Any information marked as “confidential” will not be disclosed except in accordance with 21 CFR 10.20 and other applicable disclosure law. For more information about FDA's posting of comments to public dockets, see 80 FR 56469, September 18, 2015, or access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm .
Docket: For access to the docket to read background documents or the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in the heading of this document, into the “Search” box and follow the prompts and/or go to the Division of Dockets Management, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
Submit written requests for single copies of this guidance to the Division of Drug Information, Center for Drug Evaluation and Research, Food and Drug Administration, 10001 New Hampshire Ave., Hillandale Building, 4th Floor, Silver Spring, MD 20993-0002 or to the Office of Communication, Outreach and Development, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 3128, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the SUPPLEMENTARY INFORMATION section for electronic access to the guidance document.

FOR FURTHER INFORMATION CONTACT:
Ebla Ali Ibrahim, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 6302, Silver Spring, MD 20993, 301-796-3691; or Stephen Ripley, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 7301, Silver Spring, MD 20993-0002, 240-402-7911.

SUPPLEMENTARY INFORMATION:

I. Background
FDA is announcing the availability of a guidance for industry entitled “Expanded Access to Investigational Drugs for Treatment Use—Questions and Answers.” FDA's expanded access regulations (21 CFR part 312, subpart I) went into effect on October 13, 2009 (74 FR 40900). Expanded access refers to the use of an investigational drug when the primary purpose is to diagnose, monitor, or treat a patient rather than to obtain the kind of information about the drug that is generally derived from clinical trials. Under the regulations, there are three categories of expanded access: (1) Expanded access for individual patients, including for emergency use; (2) expanded access for intermediate-size patient populations (generally smaller than those typical of a treatment IND or treatment protocol—a treatment protocol is submitted as a protocol amendment to an existing IND by the sponsor of the existing IND); and (3) expanded access for widespread treatment use through a treatment IND or treatment protocol (designed for use in larger patient populations). The regulations are intended to facilitate, when appropriate, the availability of investigational new drugs outside of a clinical investigation or approved drugs where availability is limited by a risk evaluation and mitigation strategy (REMS) to patients with serious or immediately life-threatening diseases or conditions who lack other therapeutic options.
Elsewhere in this issue of the Federal Register , FDA is announcing the availability of a guidance for industry entitled “Charging for Investigational Drugs Under an IND—Questions and Answers,” which provides information about the implementation of FDA's regulation on charging for investigational drugs under an IND, including investigational drugs made available for expanded access use. (FDA's guidance documents are available at http://www.fda.gov/Drugs/GuidanceComplianceRegulatoryInformation/Guidances/default.htm . FDA has verified the Web site addresses throughout this document, as of the date this document publishes in the Federal Register , but Web sites are subject to change over time.)
Additionally, in this issue of the Federal Register , FDA is announcing the availability of a guidance for industry entitled “Individual Patient Expanded Access Applications: Form FDA 3926.” The guidance describes Form FDA 3926 (Individual Patient Expanded Access—Investigational New Drug Application (IND)), which is available for licensed physicians to use for expanded access requests for individual patient INDs as a streamlined alternative to Form FDA 1571 (Investigational New Drug Application (IND)), and describes the process for submitting expanded access requests for individual patient expanded access INDs.
One of FDA's major goals in promulgating the expanded access regulations was to make expanded access a more transparent process by increasing awareness and knowledge about expanded access and the procedures for obtaining investigational drugs for treatment use. Since the expanded access regulations went into effect in 2009, FDA has received a number of questions concerning implementation of the regulations. Consistent with the goal of making expanded access processes more transparent, FDA is providing guidance in a question and answer format to address questions about how FDA is implementing its expanded access regulations, including questions about when it is appropriate to request expanded access under each of the three expanded access categories, the types and content of expanded access submissions, IRB review of individual patient expanded access, and the onset and duration of expanded access use.
In the Federal Register of May 9, 2013 (78 FR 27115), FDA announced the availability of the draft guidance entitled “Expanded Access to Investigational Drugs for Treatment Use—Questions & Answers.” FDA received several comments on the draft guidance, and those comments were considered as the guidance was finalized. Based on public comments, in addition to editorial changes made primarily for clarification, the final guidance includes significant clarification on the types of expanded access and when each type should be used.
This guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The guidance represents the current thinking of FDA on expanded access to investigational drugs for treatment use. It does not establish any rights for any person and is not binding on FDA or the public. You can use an alternative approach if it satisfies the requirements of the applicable statutes and regulations.

II. Paperwork Reduction Act of 1995
This guidance refers to previously approved collections of information found in FDA regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The collections of information in 21 CFR part 312 have been approved under OMB control number 0910-0014, and the collection of information resulting from the submission of Form FDA 3926 has been approved under OMB control number 0910-0814.

III. Electronic Access
Persons with access to the Internet may obtain the document at http://www.fda.gov/RegulatoryInformation/Guidances/default.htm, http://www.fda.gov/BiologicsBloodVaccines/GuidanceComplianceRegulatoryInformation/Guidances/default.htm or http://www.regulations.gov .
Dated: May 31, 2016.
Leslie Kux,

Associate Commissioner for Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
[Docket No. FDA-2013-D-0447]
Charging for Investigational Drugs Under an Investigational New Drug Application—Questions and Answers; Guidance for Industry; Availability

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Notice of availability.

SUMMARY:
The Food and Drug Administration (FDA or Agency) is announcing the availability of a guidance for industry entitled “Charging for Investigational Drugs Under an IND—Questions and Answers.” The guidance provides information for industry, researchers, physicians, institutional review boards (IRBs), and patients about the implementation of FDA's regulation on charging for investigational drugs under an investigational new drug application (IND) for the purpose of either clinical trials or expanded access for treatment use. FDA received a number of questions concerning its implementation of the charging regulation. FDA is providing guidance in a question and answer format to address the most frequently asked questions about charging for investigational drugs under an IND. This guidance finalizes the draft guidance issued in May 2013.

DATES:
Submit either electronic or written comments on Agency guidances at any time.

ADDRESSES:
You may submit comments as follows:

Electronic Submissions
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
http://www.regulations.gov . Follow the instructions for submitting comments. Comments submitted electronically, including attachments, to http://www.regulations.gov will be posted to the docket unchanged. Because your comment will be made public, you are solely responsible for ensuring that your comment does not include any confidential information that you or a third party may not wish to be posted, such as medical information, your or anyone else's Social Security number, or confidential business information, such as a manufacturing process. Please note that if you include your name, contact information, or other information that identifies you in the body of your comments, that information will be posted on http://www.regulations.gov .
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).

Written/Paper Submissions
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
Instructions: All submissions received must include the Docket No. FDA-2013-D-0447 for “Charging for Investigational Drugs Under an IND—Questions and Answers; Guidance for Industry; Availability.” Received comments will be placed in the docket and, except for those submitted as “Confidential Submissions,” publicly viewable at http://www.regulations.gov or at the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on http://www.regulations.gov . Submit both copies to the Division of Dockets Management. If you do not wish your name and contact information to be made publicly available, you can provide this information on the cover sheet and not in the body of your comments and you must identify this information as “confidential.” Any information marked as “confidential” will not be disclosed except in accordance with 21 CFR 10.20 and other applicable disclosure law. For more information about FDA's posting of comments to public dockets, see 80 FR 56469, September 18, 2015, or access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm .
Docket: For access to the docket to read background documents or the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in the heading of this document, into the “Search” box and follow the prompts and/or go to the Division of Dockets Management, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
Submit written requests for single copies of this guidance to the Division of Drug Information, Center for Drug Evaluation and Research, Food and Drug Administration, 10001 New Hampshire Ave., Hillandale Building, 4th Floor, Silver Spring, MD 20993-0002; or to the Office of Communication, Outreach and Development, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 3128, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the SUPPLEMENTARY INFORMATION section for electronic access to the guidance document.

FOR FURTHER INFORMATION CONTACT:
Ebla Ali Ibrahim, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 6302, Silver Spring, MD 20993, 301-796-3691; or Stephen Ripley, Center for Biologics Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 71, Rm. 7301, Silver Spring, MD 20993-0002, 240-402-7911.

SUPPLEMENTARY INFORMATION:

I. Background
FDA is announcing the availability of a guidance for industry entitled “Charging for Investigational Drugs Under an IND—Questions and Answers.” In 2009, FDA amended the regulation concerning charging for investigational new drugs under an IND (74 FR 40872, August 13, 2009). The new regulation, which went into effect on October 13, 2009, removed paragraph (d) of § 312.7 (21 CFR 312.7(d)) and replaced it with new § 312.8. The guidance clarifies the circumstances in which charging for an investigational drug under an IND for the purpose of clinical trials is appropriate and also sets forth criteria for charging for an investigational drug for the three types of expanded access for treatment use described in 21 CFR part 312, subpart I, and clarifies what costs can be recovered for an investigational drug.
Elsewhere in this issue of the Federal Register , FDA is announcing the availability of a guidance for industry entitled “Expanded Access to Investigational Drugs for Treatment Use—Questions and Answers,” which provides answers to questions concerning the implementation of FDA's regulations on expanded access to investigational drugs for treatment use (part 312, subpart I). (FDA's guidance documents are available at http://www.fda.gov/Drugs/GuidanceComplianceRegulatoryInformation/Guidances/default.htm . FDA has verified the Web site addresses throughout this document, as of the date this document publishes in the Federal Register , but Web sites are subject to change over time.)
Additionally, in this issue of the Federal Register , FDA is announcing the availability of a guidance for industry entitled “Individual Patient Expanded Access Applications: Form FDA 3926.” That guidance describes Form FDA 3926 (Individual Patient Expanded Access—Investigational New Drug Application (IND)), which is available for licensed physicians to use for expanded access requests for individual patient INDs as a streamlined alternative to Form FDA 1571 (IND), and describes the process for submitting expanded access requests for individual patient INDs.
Since § 312.8 has been in effect, FDA has received numerous questions about its implementation of the charging regulation. Consistent with the goal of clarifying the requirements for charging for an investigational drug and the types of costs that can be recovered, FDA is providing guidance in a question and answer format, addressing the most frequently asked questions and answers about charging for an investigational drug under an IND.
In the Federal Register of May 9, 2013 (78 FR 27116), FDA announced the availability of the draft guidance entitled “Charging for Investigational Drugs Under an IND—Qs & As.” FDA received several comments on the draft guidance, and those comments were considered as the guidance was finalized. Based on public comments, in addition to editorial changes primarily for clarification, the major changes made to the guidance include adding clarification about charging for certain administrative costs in individual patient expanded access INDs and protocols, and the timing for submitting a request to FDA to reauthorize charging.
This guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The guidance represents the current thinking of FDA on charging for investigational drugs under an IND. It does not establish any rights for any person and is not binding on FDA or the public. You can use an alternative approach if it satisfies the requirements of the applicable statutes and regulations.

II. Paperwork Reduction Act of 1995
This guidance refers to previously approved collections of information found in FDA regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The collections of information in 21 CFR 312.8 and 312.320 have been approved under OMB control number 0910-0014.

III. Electronic Access
Persons with access to the Internet may obtain the document at http://www.fda.gov/RegulatoryInformation/Guidances/default.htm, http://www.fda.gov/BiologicsBloodVaccines/GuidanceComplianceRegulatoryInformation/Guidances/default.htm, or http://www.regulations.gov .
Dated: May 31, 2016.
Leslie Kux,

Associate Commissioner for Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
[Docket No. FDA-2016-D-1255]
E18 Genomic Sampling and Management of Genomic Data; International Council for Harmonisation; Draft Guidance for Industry; Availability

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Notice of availability.

SUMMARY:
The Food and Drug Administration (FDA or Agency) is announcing the availability of a draft guidance entitled “E18 Genomic Sampling and Management of Genomic Data.” The draft guidance was prepared under the auspices of the International Council for Harmonisation (ICH), formerly the International Conference on Harmonisation. The draft guidance pertains to genomic sampling and to the management of genomic data in clinical studies. The focus of this draft guidance is on the general principles of collecting, processing, transporting, storing, and disposing of genomic samples or data. The technical aspects of genomic sampling and research are also discussed when appropriate, recognizing the rapidly evolving technological advances in these areas. The draft guidance is intended to provide harmonized principles of genomic sampling and of managing genomic data in clinical studies.

DATES:
Although you can comment on any guidance at any time (see 21 CFR 10.115 (g)(5)), to ensure that the Agency considers your comment on this draft guidance before it begins work on the final version of the guidance, submit either electronic or written comments on the draft guidance by August 2, 2016.

ADDRESSES:
You may submit comments as follows:

Electronic Submissions
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
http://www.regulations.gov . Follow the instructions for submitting comments. Comments submitted electronically, including attachments, to http://www.regulations.gov will be posted to the docket unchanged. Because your comment will be made public, you are solely responsible for ensuring that your comment does not include any confidential information that you or a third party may not wish to be posted, such as medical information, your or anyone else's Social Security number, or confidential business information, such as a manufacturing process. Please note that if you include your name, contact information, or other information that identifies you in the body of your comments, that information will be posted on http://www.regulations.gov .
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).

Written/Paper Submissions
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
Instructions: All submissions received must include the Docket No. FDA-2016-D-1255 for “E18 Genomic Sampling and Management of Genomic Data.” Received comments will be placed in the docket and, except for those submitted as “Confidential Submissions,” publicly viewable at http://www.regulations.gov or at the Division of Dockets Management between 9 a.m. and 4 p.m., Monday through Friday.
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on http://www.regulations.gov . Submit both copies to the Division of Dockets Management. If you do not wish your name and contact information to be made publicly available, you can provide this information on the cover sheet and not in the body of your comments and you must identify this information as “confidential.” Any information marked as “confidential” will not be disclosed except in accordance with 21 CFR 10.20 and other applicable disclosure law. For more information about FDA's posting of comments to public dockets, see 80 FR 56469, September 18, 2015, or access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm .
Docket: For access to the docket to read background documents or the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in the heading of this document, into the “Search” box and follow the prompts and/or go to the Division of Dockets Management, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
Submit written requests for single copies of this draft guidance to the Division of Drug Information, Center for Drug Evaluation and Research (CDER), Food and Drug Administration, 10001 New Hampshire Ave., Hillandale Building, 4th Floor, Silver Spring, MD 20993-0002, or the Office of Communication, and Education, (CDRH), Division of Industry and Consumer Education, Center for Devices and Radiological Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 4621, Silver Spring, MD 20993-0002. Send one self-addressed adhesive label to assist that office in processing your requests. See the SUPPLEMENTARY INFORMATION section for electronic access to the guidance document.

FOR FURTHER INFORMATION CONTACT:
Regarding the draft guidance: Christian Grimstein, Center for Drug Evaluation and Research (CDER), Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 3116, Silver Spring, MD 20993-0002, 301-796-5189; or Eunice Lee, Center for Devices and Radiological Health (CDRH), Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 66, Rm. 5546, Silver Spring, MD 20993-0002, 301-796-4808.
Regarding the ICH: Amanda Roache, Center for Drug Evaluation and Research (CDER), Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 1128, Silver Spring, MD 20993-0002, 301-796-4548.

SUPPLEMENTARY INFORMATION:

I. Background
In recent years, many important initiatives have been undertaken by regulatory authorities and industry associations to promote international harmonization of regulatory requirements. FDA has participated in many meetings designed to enhance harmonization and is committed to seeking scientifically based harmonized technical procedures for pharmaceutical development. One of the goals of harmonization is to identify and then reduce differences in technical requirements for drug development among regulatory agencies.
ICH was organized to provide an opportunity for harmonization initiatives to be developed with input from both regulatory and industry representatives. FDA also seeks input from consumer representatives and others. ICH is concerned with harmonization of technical requirements for the registration of pharmaceutical products for human use among regulators around the world. The six founding members of the ICH are the European Commission; the European Federation of Pharmaceutical Industries Associations; the Japanese Ministry of Health, Labour, and Welfare; the Japanese Pharmaceutical Manufacturers Association; CDER and CDRH, FDA; and the Pharmaceutical Research and Manufacturers of America. The standing members of the ICH Association include Health Canada and Swissmedic. Any party eligible as a member in accordance with the ICH Articles of Association can apply for membership in writing to the ICH Secretariat. The ICH Secretariat, which coordinates the preparation of documentation, operates as an international nonprofit organization and is funded by the members of the ICH Association.
The ICH Assembly includes representatives from each of the ICH members, as well as observers from the World Health Organization and Drug Regulatory Authorities and Regional Harmonization Initiatives from around the world.
In December 2015, the ICH Assembly endorsed the draft guidance entitled “E18 Genomic Sampling and Management of Genomic Data” and agreed that the guidance should be made available for public comment. The draft guidance is the product of the Efficacy Expert Working Group of the ICH. Comments about this draft will be considered by FDA and the Efficacy Expert Working Group.
The draft guidance provides guidance on genomic sampling and management of genomic data from interventional and non-interventional clinical studies. The draft guidance addresses use of genomic samples and data irrespective of the timing of analyses and both pre-specified and non-pre-specified use. The focus is on the general principles of collecting, processing, transporting, storing and disposing of genomic samples or data, within the scope of an informed consent. The technical aspects of genomic sampling and research are also discussed when appropriate, recognizing the rapidly evolving technological advances in these areas.
This draft guidance is being issued consistent with FDA's good guidance practices regulation (21 CFR 10.115). The draft guidance, when finalized, will represent the current thinking of FDA on “E18 Genomic Sampling and Management of Genomic Data.” It does not establish any rights for any person and is not binding on FDA or the public. You can use an alternative approach if it satisfies the requirements of the applicable statutes and regulations.

II. Electronic Access
Persons with access to the Internet may obtain the document at http://www.regulations.gov, http://www.fda.gov/Drugs/GuidanceComplianceRegulatoryInformation/Guidances/default.htm, or http://www.fda.gov/MedicalDevices/deviceregulationandguidance/guidancedocuments/default.htm.
Dated: May 31, 2016.
Leslie Kux,

Associate Commissioner for Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Food and Drug Administration
[Docket No. FDA-2016-N-0001]
Pharmacy Compounding Advisory Committee; Notice of Meeting

AGENCY:
Food and Drug Administration, HHS.

ACTION:
Notice.

SUMMARY:
The Food and Drug Administration (FDA) announces a forthcoming public advisory committee meeting of the Pharmacy Compounding Advisory Committee. The general function of the committee is to provide advice on scientific, technical, and medical issues concerning drug compounding under sections 503A and 503B of the Federal Food, Drug, and Cosmetic Act (FD&C Act), and, as required, any other product for which FDA has regulatory responsibility, and make appropriate recommendations to the Agency. The meeting will be open to the public.

DATES:
The meeting will be held on June 23, 2016, from 8:30 a.m. to 5 p.m.

ADDRESSES:
FDA White Oak Campus, 10903 New Hampshire Ave., Bldg. 31 Conference Center, the Great Room (Rm. 1503), Silver Spring, MD 20993-0002. Answers to commonly asked questions including information regarding special accommodations due to a disability, visitor parking, and transportation may be accessed at: http://www.fda.gov/AdvisoryCommittees/AboutAdvisoryCommittees/ucm408555.htm.

FOR FURTHER INFORMATION CONTACT:
Cindy Hong, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 31, Rm. 2417, Silver Spring, MD 20993-0002, 301-796-9001, FAX: 301-847-8533, email: PCAC@fda.hhs.gov, or FDA Advisory Committee Information Line, 1-800-741-8138 (301-443-0572 in the Washington, DC area). A notice in the Federal Register about last minute modifications that impact a previously announced advisory committee meeting cannot always be published quickly enough to provide timely notice. Therefore, you should always check the Agency's Web site at http://www.fda.gov/AdvisoryCommittees/default.htm and scroll down to the appropriate advisory committee meeting link, or call the advisory committee information line to learn about possible modifications before coming to the meeting.
Background: Section 503A of the FD&C Act (21 U.S.C. 353a) describes the conditions that must be satisfied for human drug products compounded by a licensed pharmacist or licensed physician to be exempt from the following three sections of the FD&C Act: (1) Section 501(a)(2)(B) (21 U.S.C. 351(a)(2)(B)) (concerning current good manufacturing practice (CGMP)); (2) section 502(f)(1) (21 U.S.C. 352(f)(1)) (concerning the labeling of drugs with adequate directions for use); and (3) section 505 (21 U.S.C. 355) (concerning the approval of human drug products under new drug applications (NDAs) or abbreviated new drug applications (ANDAs)).
One of the conditions that must be satisfied to qualify for the exemptions under section 503A of the FD&C Act is that a bulk drug substance (active pharmaceutical ingredient) used in a compounded drug product must meet one of the following criteria: (1) Complies with the standards of an applicable United States Pharmacopoeia (USP) or National Formulary monograph, if a monograph exists, and the USP chapter on pharmacy compounding; (2) if an applicable monograph does not exist, is a component of a drug approved by the Secretary of Health and Human Services (the Secretary); or (3) if such a monograph does not exist and the drug substance is not a component of a drug approved by the Secretary, appears on a list (the “section 503A bulk drug substances list”) developed by the Secretary through regulations issued by the Secretary (see section 503A(b)(1)(A)(i) of the FD&C Act).
FDA will discuss with the committee drugs proposed for inclusion on the section 503A bulk drug substances list.
Agenda: The committee intends to discuss six bulk drug substances nominated for inclusion on the section 503A bulk drug substances list. FDA intends to discuss the following nominated bulk drug substances: Chrysin, cesium chloride, sodium dichloroacetate, pyruvic acid, tea tree oil, and 2,3-Dimercapto-1-propanesulfonic acid (DMPS). The nominators of these substances will be invited to make a short presentation supporting the nomination. During the afternoon session, the committee will receive updates on certain issues to follow up on discussions from previous meetings, including the option for obtaining access to investigational new drugs under expanded access.
FDA intends to make background material available to the public no later than 2 business days before the meeting. If FDA is unable to post the background material on its Web site prior to the meeting, the background material will be made publicly available at the location of the advisory committee meeting, and the background material will be posted on FDA's Web site after the meeting. Background material is available at http://www.fda.gov/AdvisoryCommittees/Calendar/default.htm. Scroll down to the appropriate advisory committee meeting link.
Procedure: Interested persons may present data, information, or views, orally or in writing, on issues pending before the committee. Written submissions may be made to the contact person on or before June 15, 2016. Oral presentations from the public will be scheduled between approximately 9:30 a.m. and 9:40 a.m., 10:35 a.m. and 10:45 a.m., 11:40 a.m. and 11:50 a.m., 2:15 p.m. and 2:25 p.m., 3:20 p.m. and 3:30 p.m., and 4:40 p.m. and 4:50 p.m. Those individuals interested in making formal oral presentations should notify Cindy Hong and submit a brief statement of the general nature of the evidence or arguments they wish to present, the names and addresses of proposed participants, and an indication of the approximate time requested to make their presentation on or before June 10, 2016. Time allotted for each presentation may be limited. If the number of registrants requesting to speak is greater than can be reasonably accommodated during the scheduled open public hearing session, FDA may conduct a lottery to determine the speakers for the scheduled open public hearing session. The contact person will notify interested persons regarding their request to speak by June 13, 2016.
Persons attending FDA's advisory committee meetings are advised that the Agency is not responsible for providing access to electrical outlets.
FDA welcomes the attendance of the public at its advisory committee meetings and will make every effort to accommodate persons with disabilities. If you require accommodations due to a disability, please contact Cindy Hong at least 7 days in advance of the meeting.
FDA is committed to the orderly conduct of its advisory committee meetings. Please visit our Web site at http://www.fda.gov/AdvisoryCommittees/AboutAdvisoryCommittees/ucm111462.htm for procedures on public conduct during advisory committee meetings.
Notice of this meeting is given under the Federal Advisory Committee Act (5 U.S.C. app. 2).
Dated: May 31, 2016.
Leslie Kux,

Associate Commissioner for Policy.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Health Resources and Services Administration
National Vaccine Injury Compensation Program; List of Petitions Received

AGENCY:
Health Resources and Services Administration, HHS.

ACTION:
Notice.

SUMMARY:
The Health Resources and Services Administration (HRSA) is publishing this notice of petitions received under the National Vaccine Injury Compensation Program (the Program), as required by Section 2112(b)(2) of the Public Health Service (PHS) Act, as amended. While the Secretary of Health and Human Services (HHS) is named as the respondent in all proceedings brought by the filing of petitions for compensation under the Program, the United States Court of Federal Claims is charged by statute with responsibility for considering and acting upon the petitions.

SUPPLEMENTARY INFORMATION:
The Program provides a system of no-fault compensation for certain individuals who have been injured by specified childhood vaccines. Subtitle 2 of Title XXI of the PHS Act, 42 U.S.C. 300aa-10 et seq. provides that those seeking compensation are to file a petition with the U.S. Court of Federal Claims and to serve a copy of the petition on the Secretary of HHS, who is named as the respondent in each proceeding. The Secretary has delegated this responsibility under the Program to HRSA. The Court is directed by statute to appoint special masters who take evidence, conduct hearings as appropriate, and make initial decisions as to eligibility for, and amount of, compensation.
A petition may be filed with respect to injuries, disabilities, illnesses, conditions, and deaths resulting from vaccines described in the Vaccine Injury Table (the Table) set forth at 42 CFR 100.3. This Table lists for each covered childhood vaccine the conditions that may lead to compensation and, for each condition, the time period for occurrence of the first symptom or manifestation of onset or of significant aggravation after vaccine administration. Compensation may also be awarded for conditions not listed in the Table and for conditions that are manifested outside the time periods specified in the Table, but only if the petitioner shows that the condition was caused by one of the listed vaccines.
Section 2112(b)(2) of the PHS Act, 42 U.S.C. 300aa-12(b)(2), requires that “[w]ithin 30 days after the Secretary receives service of any petition filed under section 2111 the Secretary shall publish notice of such petition in the Federal Register .” Set forth below is a list of petitions received by HRSA on April 1, 2016, through April 30, 2016. This list provides the name of petitioner, city and state of vaccination (if unknown then city and state of person or attorney filing claim), and case number. In cases where the Court has redacted the name of a petitioner and/or the case number, the list reflects such redaction.
Section 2112(b)(2) also provides that the special master “shall afford all interested persons an opportunity to submit relevant, written information” relating to the following:
1. The existence of evidence “that there is not a preponderance of the evidence that the illness, disability, injury, condition, or death described in the petition is due to factors unrelated to the administration of the vaccine described in the petition,” and
2. Any allegation in a petition that the petitioner either:
a. “[S]ustained, or had significantly aggravated, any illness, disability, injury, or condition not set forth in the Vaccine Injury Table but which was caused by” one of the vaccines referred to in the Table, or
b. “[S]ustained, or had significantly aggravated, any illness, disability, injury, or condition set forth in the Vaccine Injury Table the first symptom or manifestation of the onset or significant aggravation of which did not occur within the time period set forth in the Table but which was caused by a vaccine” referred to in the Table.
In accordance with Section 2112(b)(2), all interested persons may submit written information relevant to the issues described above in the case of the petitions listed below. Any person choosing to do so should file an original and three (3) copies of the information with the Clerk of the U.S. Court of Federal Claims at the address listed above (under the heading For Further Information Contact ), with a copy to HRSA addressed to Director, Division of Injury Compensation Programs, Healthcare Systems Bureau, 5600 Fishers Lane, 08N146B, Rockville, MD 20857. The Court's caption (Petitioner's Name v. Secretary of Health and Human Services) and the docket number assigned to the petition should be used as the caption for the written submission. Chapter 35 of title 44, United States Code, related to paperwork reduction, does not apply to information required for purposes of carrying out the Program.

FOR FURTHER INFORMATION CONTACT:
For information about requirements for filing petitions, and the Program in general, contact the Clerk, United States Court of Federal Claims, 717 Madison Place NW., Washington, DC 20005, (202) 357-6400. For information on HRSA's role in the Program, contact the Director, National Vaccine Injury Compensation Program, 5600 Fishers Lane, Room 08N146B, Rockville, MD 20857; (301) 443-6593, or visit our Web site at: http://www.hrsa.gov/vaccinecompensation/index.html.
Dated: May 26, 2016.
James Macrae,

Acting Administrator.

List of Petitions Filed
1. Christopher Stephen Fennell; Sun City West, Arizona; Court of Federal Claims No: 16-0413V
2. Willie Johnson; Dublin, Georgia; Court of Federal Claims No: 16-0415V
3. Maria Villanueva; Utuado, Puerto Rico; Court of Federal Claims No: 16-0416V
4. Laura Friedel; Woodstock, Illinois; Court of Federal Claims No: 16-0417V
5. Kathleen Mosier; Akron, Ohio; Court of Federal Claims No: 16-0418V
6. Christina Osenbach and Bryan Osenbach on behalf of B. O.; Boston, Massachusetts; Court of Federal Claims No: 16-0419V
7. Meredith Pyers; Columbus, Ohio; Court of Federal Claims No: 16-0421V
8. Alexandria Skeens; Granville, Ohio; Court of Federal Claims No: 16-0423V
9. Marsha Crawford; Paris, Kentucky; Court of Federal Claims No: 16-0428V
10. Edward McMahon; Tucson, Arizona; Court of Federal Claims No: 16-0429V
11. Kristina Raab on behalf of J. R.; San Diego, California; Court of Federal Claims No: 16-0431V
12. Pella Parker; Los Angeles, California; Court of Federal Claims No: 16-0433V
13. Michele Jacob and Craig Jacob on behalf of Ryan Jacob; New York, New York; Court of Federal Claims No: 16-0434V
14. Jason Guido on behalf of D. G.; Rochester, Pennsylvania; Court of Federal Claims No: 16-0435V
15. Carl L. Anderson; Baltimore, Maryland; Court of Federal Claims No: 16-0436V
16. Kelsi Amen; Grand Island, Nebraska; Court of Federal Claims No: 16-0437V
17. Martin Rausch; Avery, North Carolina; Court of Federal Claims No: 16-0438V
18. Timothy Koller; Neenah, Wisconsin; Court of Federal Claims No: 16-0439V
19. Christian Geideman and Erinn Geideman on behalf of H. G. G.; Menlo Park, California; Court of Federal Claims No: 16-0443V
20. Vilma Espada Cubano; San Juan, Puerto Rico; Court of Federal Claims No: 16-0444V
21. Regina Murrell; Jackson, Mississippi; Court of Federal Claims No: 16-0445V
22. Kristen Bell; Alpharetta, Georgia; Court of Federal Claims No: 16-0450V
23. Lorraine Sofia; Lyndhurst, New Jersey; Court of Federal Claims No: 16-0452V
24. Arlene Sandman; Boston, Massachusetts; Court of Federal Claims No: 16-0453V
25. Frederick Green; Newport, Rhode Island; Court of Federal Claims No: 16-0454V
26. Linda Commesso; Boston, Massachusetts; Court of Federal Claims No: 16-0455V
27. Isaac Watson; Indianapolis, Indiana; Court of Federal Claims No: 16-0456V
28. Patricia Swanson; Beverly, Massachusetts; Court of Federal Claims No: 16-0457V
29. Betty D. Backman; Manhattan, Kansas; Court of Federal Claims No: 16-0458V
30. Sandra E. Williams on behalf of Richard Williams, Deceased; Surprise, Arizona; Court of Federal Claims No: 16-0459V
31. Linda K. Russell; Tampa, Florida; Court of Federal Claims No: 16-0460V
32. Steven Patton; Vienna, Virginia; Court of Federal Claims No: 16-0461V
33. Scott Cipa; Vienna, Virginia; Court of Federal Claims No: 16-0462V
34. Jessica Buckingham; New Castle, Delaware; Court of Federal Claims No: 16-0463V
35. Mette Rose and Soren Rose Kjaer on behalf of F. R. K.; New York, New York; Court of Federal Claims No: 16-0465V
36. Mette Rose and Soren Rose Kjaer on behalf of M. R. K.; New York, New York; Court of Federal Claims No: 16-0466V
37. Victoria Pusateri; Southgate, Michigan; Court of Federal Claims No: 16-0467V
38. Nathaniel Paul; Fairfax, Virginia; Court of Federal Claims No: 16-0468V
39. Rebecca S. Melgares; Milwaukee, Wisconsin; Court of Federal Claims No: 16-0470V
40. Arthur L. Trollinger; Graham, North Carolina; Court of Federal Claims No: 16-0473V
41. Tracy E. Carrozza; Princeton, New Jersey; Court of Federal Claims No: 16-0474V
42. Allen O. Cabansag; Spring Valley, California; Court of Federal Claims No: 16-0475V
43. Luciana Desa; Washington, District of Columbia; Court of Federal Claims No: 16-0476V
44. Deborah Tebault on behalf of J. T.; Phoenix, Arizona; Court of Federal Claims No: 16-0478V
45. Stephen Vasas; Ann Arbor, Michigan; Court of Federal Claims No: 16-0479V
46. Theresa Hibbs; Shepherdsville, Kentucky; Court of Federal Claims No: 16-0481V
47. Stephanie Gilbert on behalf of P. L.; Vienna, Virginia; Court of Federal Claims No: 16-0484V
48. Sonya Tabor; Beverly Hills, California; Court of Federal Claims No: 16-0485V
49. The Estate of Frank Lee Kapp, Jr., Deceased; Salisbury, North Carolina; Court of Federal Claims No: 16-0487V
50. Leslie Lewis; Lexington, South Carolina; Court of Federal Claims No: 16-0488V
51. Christine Benshoff; Orwigsburg, Pennsylvania; Court of Federal Claims No: 16-0489V
52. Robert Hearn; Jackson, Mississippi; Court of Federal Claims No: 16-0493V
53. John Neukom; Normangee, Texas; Court of Federal Claims No: 16-0495V
54. Heather Wright on behalf of B. W.; Washington, District of Columbia; Court of Federal Claims No: 16-0498V
55. Julian Henley; Scottsbluff, Nebraska; Court of Federal Claims No: 16-0499V
56. Misty Pasco on behalf of M. P.; Phoenix, Arizona; Court of Federal Claims No: 16-0500V
57. Janis Pool; Lawrence, Kansas; Court of Federal Claims No: 16-0503V
58. Jeffrey A. Bales; Greensboro, North Carolina; Court of Federal Claims No: 16-0505V
59. Terry Bartee; Antioch, California; Court of Federal Claims No: 16-0506V
60. Linda Barton; Lancaster, Pennsylvania; Court of Federal Claims No: 16-0508V
61. Richard George Laux; Farmington Hills, Michigan; Court of Federal Claims No: 16-0509V
62. Judith A. Pannick; Flint, Michigan; Court of Federal Claims No: 16-0510V
63. Laura Kerrin; Philadelphia, Pennsylvania; Court of Federal Claims No: 16-0511V
64. Rev. Andrew Thomas Moody on behalf of E. G. M.; Houston, Texas; Court of Federal Claims No: 16-0513V
65. James Ritchie; Ponte Vedra Beach, Florida; Court of Federal Claims No: 16-0514V
66. Thomas Smith; Weston, West Virginia; Court of Federal Claims No: 16-0520V
67. Shahid Mahroof; Stony Brook, New York; Court of Federal Claims No: 16-0521V
68. Stephanie Smith; Allentown, Pennsylvania; Court of Federal Claims No: 16-0522V
69. Monika Piatek on behalf of N. P.; Chicago, Illinois; Court of Federal Claims No: 16-0524V
70. Patricia Rubio; Bedford, New Hampshire; Court of Federal Claims No: 16-0525V
71. Frederick Morrison; Gulf Breeze, Florida; Court of Federal Claims No: 16-0526V
72. Gary Schilling; Boston, Massachusetts; Court of Federal Claims No: 16-0527V
73. Tiffany Harris on behalf of A. H.; Boston, Massachusetts; Court of Federal Claims No: 16-0528V
74. Lianna Roberts; Boston, Massachusetts; Court of Federal Claims No: 16-0529V
75. Jennifer Young; Canton, Michigan; Court of Federal Claims No: 16-0530V
76. Scott Pudalov; Boulder, Colorado; Court of Federal Claims No: 16-0532V
77. Tracy Butler; Denver, Colorado; Court of Federal Claims No: 16-0534V
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Office of the Secretary
Findings of Research Misconduct

AGENCY:
Office of the Secretary, HHS.

ACTION:
Notice.

SUMMARY:
Notice is hereby given that the Office of Research Integrity (ORI) has taken final action in the following case:
Karen M. D'Souza, Ph.D., University of Chicago: Based on the report of an investigation conducted by the University of Chicago (UC) and additional analysis conducted by ORI in its oversight review, ORI found that Dr. Karen M. D'Souza, former Research Professional Associate, Department of Surgery, UC, engaged in research misconduct in research supported by National Heart, Lung, and Blood Institute (NHLBI), National Institutes of Health (NIH), grants K08 HL081472 and R01 HL107949.
ORI found that falsified and/or fabricated data were included in the following one (1) funded NIH grant, two (2) publications, two (2) posters, and one (1) presentation:
• R01 HL107949-01
• J Biol Chem. 285(18):13748-60, 2010 Apr 30 (hereafter referred to as “ JBC 2010”)
• J Biol Chem. 286(17):15507-16, 2011 Apr 29 (hereafter referred to as “ JBC 2011”)
• Gordon Conference 2006 poster: “Regulation of Myocardial β-Adrenergic Receptor Signaling By Protein Kinase C” (hereafter referred to as “GC2006”)
• Huggins 2010 poster: Gαq-mediated activation of GRK2 by mechanical stretch in cardiac myocytes; the role of protein kinase C” (hereafter referred to as “HP2010”)
• Cardiac Research Day 2009 presentation: “Regulation of G protein-coupled receptor signaling by mechanical stretch in cardiac myocytes” (hereafter referred to as “CR2009”)
ORI found that Respondent reused and falsely relabeled and/or falsely spliced Western blot images, falsified the related densitometry measurements based on the falsified Western blots, and falsified and/or fabricated data for experiments that were not performed or from unrelated experiments.
Specifically, Respondent falsified and/or fabricated data in the following:
• R01 HL107949-01 for:
Figure 1B for Western blots of α-smooth muscle actin (α-SMA), Vimentin, Collagen I and Glyceraldehyde 3-Phosphate Dehydrogenase (GAPDH) expression in human cardiac fibroblasts isolated from failing left ventricles (HF) and non-failing heart controls (CF)
Figure 2A for Western blots of G protein-coupled receptor kinase-2 (GRK2) and GAPDH expression in HF and CF, and the related densitometric analysis
• JBC 2011 for:
Figure 1A for a Western blot of Vimentin expression in HF and CF, and the related densitometric analysis
Figures 1D and 2D for Western blots of GAPDH expression in HF and CF, and the related densitometric analyses
• JBC 2010 for:
Figure 7A for Western blots of phosphorylated Rhodopsin (Rho) and GRK2 expression in non-transgenic (NTG) (lanes 1-4) and Protein Kinase Cα cardiac-specific activation (PKCαAC) transgenic (lanes 5-6) mice, and Figure 7B for the related densitometric analysis
• GC2006, Figure 7, HP2010, Figure 5, and CR2009, Slide 15 for:
Western blots of phosphorylated Rho and GRK2 expression in NTG and PKCαAC transgenic mice, and the related densitometric analysis
• HP2010 for:
Figure 5 for a Western blot of GRK2 expression in NTG and PKCαAC transgenic mice, and the related densitometric analysis
Dr. D'Souza has entered into a Voluntary Settlement Agreement with ORI, in which she voluntarily agreed to the administrative actions set forth below:
(1) Respondent agreed that for two (2) years beginning on May 6, 2016, any institution employing her shall submit in conjunction with each application for U.S. Public Health Service (PHS) funds, or report, manuscript, or abstract involving PHS-supported research in which Respondent is involved, a supervision plan to ORI. Respondent agreed that prior to the submission of an application for PHS support for a research project on which the Respondent's participation is proposed and prior to Respondent's participation in any capacity on PHS-supported research, any institution employing her shall ensure that a plan for supervision of her duties is submitted to ORI for approval. The supervision plan must be designed to ensure the scientific integrity of Respondent's PHS-supported research contribution and include the specific elements as outlined below. Respondent agreed that she shall not participate in any PHS-supported research until such a supervision plan is submitted to and approved by ORI. Respondent agreed to maintain responsibility for compliance with the agreed upon supervision plan.
(2) The requirements for Respondent's supervision plan are as follows:
i. A committee of senior faculty members and officials at the institution who are familiar with Respondent's field of research, but not including Respondent's supervisor or collaborators, will provide oversight and guidance for two (2) years beginning on May 6, 2016. The committee will review PHS-supported primary data from Respondent and submit a report to ORI at six (6) month intervals, setting forth the committee meeting dates, Respondent's compliance with appropriate research standards, and confirming the integrity of Respondent's PHS-supported research.
ii. The committee will conduct an advance review of any PHS grant application (including supplements, resubmissions, etc.), manuscripts reporting PHS-funded research submitted for publication, and abstracts. The review will include a discussion with Respondent of the primary data represented in those documents and will include a certification that the data presented in the proposed application/publication is supported by the research record.
(3) Respondent agreed that for two (2) years beginning on May 6, 2016, any institution employing her shall submit, in conjunction with each application for PHS funds, or report, manuscript, or abstract involving PHS-supported research in which Respondent is involved, a certification to ORI at that the data provided by Respondent are based on actual experiments or are otherwise legitimately derived and that the data, procedures, and methodology are accurately reported in the application, report, manuscript, or abstract.
(4) Respondent agreed to exclude herself voluntarily from serving in any advisory capacity to PHS including, but not limited to, service on any PHS advisory committee, board, and/or peer review committee, or as a consultant for a period of two (2) years, beginning on May 6, 2016.
(5) As a condition of the Agreement, Respondent agreed to the retraction of the JBC 2010 publication.

FOR FURTHER INFORMATION CONTACT:
Director, Office of Research Integrity, 1101 Wootton Parkway, Suite 750, Rockville, MD 20852, (240) 453-8200.
Kathryn M. Partin,

Director, Office of Research Integrity.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
Indian Health Service
Notice of Tribal Consultation and Urban Confer Sessions on the State of the Great Plains Area Indian Health Service

AGENCY:
Indian Health Service (IHS), Department of Health and Human Services.

ACTION:
Notice of Tribal consultation and urban confer sessions on the state of the Great Plains Area IHS.

SUMMARY:
Notice is hereby given that the Indian Health Service will conduct a 90 day tribal consultation and urban confer regarding the State of the Great Plains Area IHS. The IHS will conduct two telephone tribal consultation and urban confer sessions on June 22, 2016 and August 10, 2016. The IHS will also conduct two on-site tribal consultation and urban confer sessions on July 13, 2016 in Aberdeen, South Dakota and on August 30, 2016 in Rapid City, South Dakota.

DATES:
The IHS will conduct two telephone Tribal consultation and urban confer sessions on June 22, 2016 and August 10, 2016. The IHS will also conduct two on-site Tribal consultation and urban confer sessions on July 13, 2016 in Aberdeen, South Dakota, and on August 30, 2016 in Rapid City, SD.
The on-site meetings in Aberdeen and Rapid City, South Dakota will be conducted at the addresses noted below. Written comments must be received on or before September 1, 2016 at the address below.
Conference Call Information: 1-800-369-1747; Pass Code: 1381519.

ADDRESSES:
The meetings will be held at The Dakota Event Center located at 720 Lamont Street, Aberdeen, South Dakota; and at the Rushmore Plaza Holiday Inn Convention Center located at 505 N. Fifth Street, Rapid City, SD 57701, during the 13th Annual Direct Service Tribes National Meeting.
Written Comments: For Tribes: consultation@ihs.gov.
For Urbans: urbanconfer@ihs.gov.

FOR FURTHER INFORMATION CONTACT:
CAPT Chris Buchanan, Acting Director, Great Plains Area, Indian Health Service, 115 4th Ave. SE Suite 309 Aberdeen, South Dakota, (605) 226-7584, Fax (605) 226-7541.

SUPPLEMENTARY INFORMATION:
These meetings are in follow-up to the April 5-7, 2016 IHS Tribal Leaders Briefing in Sioux Falls, South Dakota. The IHS would like to invite the Great Plains Area Tribal Leaders to participate in formal consultation and interested urban Indian organizations to confer with IHS leadership to discuss the state of the Great Plains Area IHS.
The purpose of these sessions are to receive feedback on the organization of the IHS Great Plains Area Office in an effort to continue to become more patient-focused in order to better meet the needs of the American Indians in the Great Plains Area. Specific topics will include geographic location of the Great Plains Area Office, centralization or further decentralization of area office services, staffing, budget, local involvement, transparency and oversight, partnerships, accountability, and monitoring.
Tribal leaders and designated representatives as well as urban Indian organizations that are interested in submitting written testimony for the on-site or telephonic consultation and urban confer sessions can provide written comments to the following: For Tribes— consultation@ihs.gov. For Urbans— urbanconfer@ihs.gov.
The Tribal consultation and urban confer sessions will be conducted with elected or appointed leaders of Tribal governments and their designated representatives [42 U.S.C. 9835, Section 640(l)(4)(A)], and recognized representatives from urban Indian organizations, as defined by 25 U.S.C. 1603(29). Representatives from other Tribal organizations and Native non-profit organizations are welcome to attend as observers. Those wishing to participate in the discussions must have a copy of a letter signed by an elected or appointed official or their designee, which authorizes them to serve as a representative of the Tribe. This should be submitted no later than three days in advance of the Tribal consultation and urban confer session to CAPT Chris Buchanan at (605) 226-7541 (fax).
A detailed report of all written comments and comments received through the Tribal consultation and urban confer sessions will be prepared and made available within 90 days of the close of the comment period to all Tribal governments and interested urban Indian organizations within the Great Plains Area.
Dated: May 27, 2016.
Mary Smith,

Principal Deputy Director, Indian Health Service.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
Government-Owned Inventions; Availability for Licensing

AGENCY:
National Institutes of Health, HHS.

ACTION:
Notice.

SUMMARY:
The invention listed below is owned by an agency of the U.S. Government and is available for licensing and/or co-development in the U.S. in accordance with 35 U.S.C. 209 and 37 CFR part 404 to achieve expeditious commercialization of results of federally-funded research and development. Foreign patent applications are filed on selected inventions to extend market coverage for companies and may also be available for licensing and/or co-development.

ADDRESSES:
Invention Development and Marketing Unit, Technology Transfer Center, National Cancer Institute, 9609 Medical Center Drive, Mail Stop 9702, Rockville, MD 20850-9702.

FOR FURTHER INFORMATION CONTACT:
Information on licensing and co-development research collaborations, and copies of the U.S. patent applications listed below, may be obtained by contacting: Attn. Invention Development and Marketing Unit, Technology Transfer Center, National Cancer Institute, 9609 Medical Center Drive, Mail Stop 9702, Rockville, MD 20850-9702, Tel. 240-276-5515 or email ncitechtransfer@mail.nih.gov. A signed Confidential Disclosure Agreement may be required to receive copies of the patent applications.

SUPPLEMENTARY INFORMATION:
Technology description follows.
Title of invention: Chimeric Antigen Receptors to CD276 for treating Cancer.
Description of Technology: Chimeric antigen receptors (CARs) are hybrid proteins consisting of an antibody binding fragment fused to protein signaling domains that cause T-cells which express the CAR to become cytotoxic. Once activated, these cytotoxic T-cells can selectively eliminate the cells which they recognize via the antibody binding fragment of the CAR. By engineering a T-cell to express a CAR that is specific for a certain cell surface protein, it is possible to selectively target those cells for destruction. This is a promising new therapeutic approach known as adoptive cell therapy.
CD276 (a.k.a., B7-H3) is a tumor-associated antigen that is expressed on the cell surface of several cancers, including neuroblastomas, prostate cancer, ovarian cancer and some lung cancers. This technology concerns the development of CARs comprising an antigen-binding fragment derived from the MGA271 antibody. The resulting CARs can be used in adoptive cell therapy treatment for neuroblastoma and other tumors which express CD276.
Potential Commercial Applications:
• Treatment of cancers associated with expression of CD276.
• Specific cancers include neuroblastoma, prostate cancer, ovarian cancer, lung cancer and other solid tumors.
Value Proposition:
• MGA271 is a well characterized anti-CD276 antibody, making it a known quantity regarding safety issues.
• High affinity of the MGA271 antibody for CD276 increases the likelihood of successful targeting.
• Targeted therapy decreases non-specific killing of healthy, essential cells, resulting in fewer non-specific side-effects and healthier patients.
Development Stage: Discovery (Lead ID).
Inventor(s): Crystal Mackall.
Intellectual Property: HHS No. E-243-2015/0-US-01 U.S. Provisional Application 62/216,447 (E-243-2015/0-US-01) filed 9/10/2015 titled “Anti-CD276 Chimeric Antigen Receptors”.
Publications: None applicable.
Collaboration Opportunity: Researchers at the NCI seek licensing for chimeric antigen receptors to CD276 for treating cancer.
Contact Information: Requests for copies of the patent application or inquiries about licensing, research collaborations, and co-development opportunities should be sent to John D. Hewes, Ph.D., email: john.hewes@nih.gov.
Dated: May 31, 2016.
John D. Hewes,

Technology Transfer Specialist, Technology Transfer Center, National Cancer Institute.
DEPARTMENT OF HEALTH AND HUMAN SERVICES
National Institutes of Health
Proposed Collection; 60-Day Comment Request: Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery, National Institute of Neurological Disorders and Stroke (NINDS)

SUMMARY:
In compliance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, for opportunity for public comment on proposed data collection projects, the National Institute of Dental Craniofacial Research (NIDCR), National Institutes of Health (NIH), will publish periodic summaries of proposed projects to be submitted to the Office of Management and Budget (OMB) for review and approval.
Written comments and/or suggestions from the public and affected agencies are invited on one or more of the following points: (1) Whether the proposed collection of information is necessary for the proper performance of the function of the agency, including whether the information will have practical utility; (2) 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; (3) Ways to enhance the quality, utility, and clarity of the information to be collected; and (4) Ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology.
To Submit Comments and for Further Information: To obtain a copy of the data collection plans and instruments, submit comments in writing, or request more information on the proposed project, contact: Dr. Sophia Jeon, Health Science Policy Analyst, Office of Science Policy and Planning, OSPP, NINDS, NIH, 31 Center Drive, Building 31, Room 8A03, Bethesda, MD 20892, or call non-toll-free number (301) 435-7571, or Email your request, including your address to: sophia.jeon@nih.gov . Formal requests for additional plans and instruments must be requested in writing.
Comment Due Date: Comments regarding this information collection are best assured of having their full effect if received within 60 days of the date of this publication.
Proposed Collection: Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery, National Institute of Neurological Disorders and Stroke (NINDS), 0925-0678, Expiration Date 08/31/2016—EXTENSION, National Institute of Neurological Disorders and Stroke (NINDS), National Institutes of Health (NIH).
Need and Use of Information Collection: The information collection activity will garner qualitative customer and stakeholder feedback in an efficient, timely manner, in accordance with the Administration's commitment to improving service delivery. By qualitative feedback we mean information that provides useful insights on perceptions and opinions, but are not statistical surveys that yield quantitative results that can be generalized to the population of study. This feedback will provide insights into customer or stakeholder perceptions, experiences and expectations, provide an early warning of issues with service, or focus attention on areas where communication, training or changes in operations might improve delivery of products or services. These collections will allow for ongoing, collaborative and actionable communications between the Agency and its customers and stakeholders. It will also allow feedback to contribute directly to the improvement of program management.
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address: the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
OMB approval extension is requested for 3 years. There are no costs to respondents other than their time. The total estimated annualized burden hours are 5750.
Estimated Annualized Burden Hours
Type of collection | Type of respondent | Number of respondents | Annual frequency per response | Hours per response | Total hours
Surveys (various programs) | Individuals, Households, Businesses, Organizations, State, Local or Tribal Government | 3500 | 1 | 15/60 | 875
Surveys (electronic communications/outreach) | Same as above | 6000 | 2 | 15/60 | 3000
In-Depth Interviews | Same as above | 100 | 1 | 90/60 | 150
Focus groups and/or small discussion groups | Same as above | 400 | 1 | 120/60 | 800
Website and/or Software Usability Tests (including web surveys) | Same as above | 600 | 1 | 90/60 | 900
Intercept testing | Same as above | 100 | 1 | 15/60 | 25
Total | | 10700 | 16700 | | 5750
Dated: May 26, 2016.
Walter Koroshetz,

Director, National Institute of Neurological Disorders and Stroke, NIH.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Internal Agency Docket No. FEMA-4268-DR; Docket ID FEMA-2016-0001]
Mississippi; Amendment No. 6 to Notice of a Major Disaster Declaration

AGENCY:
Federal Emergency Management Agency, DHS.

ACTION:
Notice.

SUMMARY:
This notice amends the notice of a major disaster declaration for the State of Mississippi (FEMA-4268-DR), dated March 25, 2016, and related determinations.

DATES:
Effective May 19, 2016.

FOR FURTHER INFORMATION CONTACT:
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.

SUPPLEMENTARY INFORMATION:
The notice of a major disaster declaration for the State of Mississippi is hereby amended to include the following areas among those areas determined to have been adversely affected by the event declared a major disaster by the President in his declaration of March 25, 2016.
Issaquena and Lawrence Counties for Public Assistance.
The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
W. Craig Fugate,

Administrator, Federal Emergency Management Agency.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Internal Agency Docket No. FEMA-4250-DR; Docket ID FEMA-2016-0001]
Missouri; Amendment No. 3 to Notice of a Major Disaster Declaration

AGENCY:
Federal Emergency Management Agency, DHS.

ACTION:
Notice.

SUMMARY:
This notice amends the notice of a major disaster declaration for State of Missouri (FEMA-4250-DR), dated January 21, 2016, and related determinations.

DATES:
Effective May 13, 2016.

FOR FURTHER INFORMATION CONTACT:
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.

SUPPLEMENTARY INFORMATION:
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, William L. Vogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.
This action terminates the appointment of Michael L. Parker as Federal Coordinating Officer for this disaster.
The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
W. Craig Fugate,

Administrator, Federal Emergency Management Agency.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Internal Agency Docket No. FEMA-4271-DR; Docket ID FEMA-2016-0001]
Montana; Major Disaster and Related Determinations

AGENCY:
Federal Emergency Management Agency, DHS.

ACTION:
Notice.

SUMMARY:
This is a notice of the Presidential declaration of a major disaster for the State of Montana (FEMA-4271-DR), dated May 24, 2016, and related determinations.

DATES:
Effective Date: May 24, 2016.

FOR FURTHER INFORMATION CONTACT:
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.

SUPPLEMENTARY INFORMATION:
Notice is hereby given that, in a letter dated May 24, 2016, the President issued a major disaster declaration under the authority of the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”), as follows:
I have determined that the damage in certain areas of the State of Montana resulting from a severe winter storm and straight-line winds during the period of April 15-16, 2016, is of sufficient severity and magnitude to warrant a major disaster declaration under the Robert T. Stafford Disaster Relief and Emergency Assistance Act, 42 U.S.C. 5121 et seq. (the “Stafford Act”). Therefore, I declare that such a major disaster exists in the State of Montana.
In order to provide Federal assistance, you are hereby authorized to allocate from funds available for these purposes such amounts as you find necessary for Federal disaster assistance and administrative expenses.
You are authorized to provide Public Assistance in the designated areas and Hazard Mitigation throughout the State. Consistent with the requirement that Federal assistance be supplemental, any Federal funds provided under the Stafford Act for Hazard Mitigation will be limited to 75 percent of the total eligible costs. Federal funds provided under the Stafford Act for Public Assistance also will be limited to 75 percent of the total eligible costs, with the exception of projects that meet the eligibility criteria for a higher Federal cost-sharing percentage under the Public Assistance Alternative Procedures Pilot Program for Debris Removal implemented pursuant to section 428 of the Stafford Act.
Further, you are authorized to make changes to this declaration for the approved assistance to the extent allowable under the Stafford Act.
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, Thomas J. McCool, of FEMA is appointed to act as the Federal Coordinating Officer for this major disaster.
The following areas of the State of Montana have been designated as adversely affected by this major disaster:
Glacier, Liberty, Pondera, Teton, and Toole Counties for Public Assistance.
All areas within the State of Montana are eligible for assistance under the Hazard Mitigation Grant Program.
The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
W. Craig Fugate,

Administrator, Federal Emergency Management Agency.
DEPARTMENT OF HOMELAND SECURITY
Federal Emergency Management Agency
[Internal Agency Docket No. FEMA-4238-DR; Docket ID FEMA-2016-0001]
Missouri; Amendment No. 2 to Notice of a Major Disaster Declaration

AGENCY:
Federal Emergency Management Agency, DHS.

ACTION:
Notice.

SUMMARY:
This notice amends the notice of a major disaster declaration for State of Missouri (FEMA-4238-DR), dated August 7, 2015, and related determinations.

DATES:
Effective Date: May 13, 2016.

FOR FURTHER INFORMATION CONTACT:
Dean Webster, Office of Response and Recovery, Federal Emergency Management Agency, 500 C Street SW., Washington, DC 20472, (202) 646-2833.

SUPPLEMENTARY INFORMATION:
The Federal Emergency Management Agency (FEMA) hereby gives notice that pursuant to the authority vested in the Administrator, under Executive Order 12148, as amended, William L. Vogel, of FEMA is appointed to act as the Federal Coordinating Officer for this disaster.
This action terminates the appointment of Michael L. Parker as Federal Coordinating Officer for this disaster.
The following Catalog of Federal Domestic Assistance Numbers (CFDA) are to be used for reporting and drawing funds: 97.030, Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis Counseling; 97.033, Disaster Legal Services; 97.034, Disaster Unemployment Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048, Disaster Housing Assistance to Individuals and Households in Presidentially Declared Disaster Areas; 97.049, Presidentially Declared Disaster Assistance—Disaster Housing Operations for Individuals and Households; 97.050, Presidentially Declared Disaster Assistance to Individuals and Households—Other Needs; 97.036, Disaster Grants—Public Assistance (Presidentially Declared Disasters); 97.039, Hazard Mitigation Grant.
W. Craig Fugate,

Administrator, Federal Emergency Management Agency.
DEPARTMENT OF HOUSING AND URBAN DEVELOPMENT
[Docket No. FR-5907-N-23]
Federal Property Suitable as Facilities To Assist the Homeless

AGENCY:
Office of the Assistant Secretary for Community Planning and Development, HUD.

ACTION:
Notice.

SUMMARY:
This Notice identifies unutilized, underutilized, excess, and surplus Federal property reviewed by HUD for suitability for possible use to assist the homeless.

FOR FURTHER INFORMATION CONTACT:
Juanita Perry, Department of Housing and Urban Development, 451 Seventh Street SW., Room 7262, Washington, DC 20410; telephone (202) 402-3970; TTY number for the hearing- and speech-impaired (202) 708-2565, (these telephone numbers are not toll-free), or call the toll-free Title V information line at 800-927-7588.

SUPPLEMENTARY INFORMATION:
In accordance with the December 12, 1988 court order in National Coalition for the Homeless v. Veterans Administration, No. 88-2503-OG (D.D.C.), HUD publishes a Notice, on a weekly basis, identifying unutilized, underutilized, excess and surplus Federal buildings and real property that HUD has reviewed for suitability for use to assist the homeless. Today's Notice is for the purpose of announcing that no additional properties have been determined suitable or unsuitable this week.
Dated: May 26, 2016.
Brian P. Fitzmaurice,

Director, Division of Community Assistance, Office of Special Needs Assistance Programs.
DEPARTMENT OF THE INTERIOR
Fish and Wildlife Service
[FWS-R8-R-2016-N076]; [FXRS282108E8PD0-167-F2013227943]
South Bay Salt Pond Restoration Project, Phase 2; Don Edwards National Wildlife Refuge; Final Environmental Impact Statement/Environmental Impact Report

AGENCY:
Fish and Wildlife Service, Interior.

ACTION:
Notice of availability; final environmental impact statement and environmental impact report.

SUMMARY:
We, the U.S. Fish and Wildlife Service (USFWS) and the California State Coastal Conservancy, announce that the Final Environmental Impact Statement/Environmental Impact Report (FEIS/EIR) for Phase 2 of the South Bay Salt Pond Restoration Project (SBSP) at the Don Edwards National Wildlife Refuge (Refuge) in Alameda, Santa Clara, and San Mateo Counties, California, is now available. The FEIS/EIR, which we prepared and now announce in accordance with the National Environmental Policy Act of 1969 (NEPA), describes the alternatives analyzed for Phase 2 of the South Bay Salt Pond Restoration Project, including the preferred alternative.

ADDRESSES:
Document Availability: You may obtain copies of the document in the following places:
Internet: http://www.southbayrestoration.org/planning/phase2/.
Libraries:
• San Francisco Bay National Wildlife Refuge Complex Headquarters, 1 Marshlands Rd., Fremont, CA 94555.
• Alviso Branch Library, 5050 N. First St., San Jose, CA 95002.
• Biblioteca Latino America, 921 S. First St., San Jose, CA 95110.
• California State University Library, 25800 Carlos Bee Blvd., Hayward, CA 94542.
• Fremont Main Library, 2400 Stevenson Blvd., Fremont, CA 94538.
• Menlo Park Library, 800 Alma St., Menlo Park, CA 94025.
• Mountain View Library, 585 Franklin St., Mountain View, CA 94041.
• Rinconada Library, 1213 Newell Rd., Palo Alto, CA 94303.
• King Library, 150 E. San Fernando St., San Jose, CA 95112.
• Redwood City Main Library, 1044 Middlefield Rd., Redwood City, CA 94063.
• San Mateo County East Palo Alto Library, 2415 University Ave., East Palo Alto, CA 94303.
• Santa Clara County Milpitas Library, 160 N. Main St., Milpitas, CA 95035.
• Santa Clara Public Library, 2635 Homestead Rd., Santa Clara, CA 95051.
• Sunnyvale Public Library, 665 W. Olive Ave., Sunnyvale, CA 94086.
• Natural Resources Library, U.S. Department of the Interior, 1849 C Street NW., Washington, DC 20240-0001.

FOR FURTHER INFORMATION CONTACT:
Chris Barr, Deputy Project Leader, USFWS, 510-792-0222 (phone).

SUPPLEMENTARY INFORMATION:

Background
In December 2007, the USFWS and the California Department of Fish and Wildlife (CDFW) published a Final EIS/EIR for the SBSP Restoration Project at the Don Edwards San Francisco Bay National Wildlife Refuge (Refuge) and the CDFW Eden Landing Ecological Reserve (December 19, 2007; 72 FR 71937). The overall south bay salt pond restoration area includes 15,100 acres, which the USFWS and the CDFW acquired from Cargill, Inc., in 2003. The lands acquired from Cargill are divided into three pond complexes: The Ravenswood Pond Complex, in San Mateo County, managed by the USFWS; the Alviso Pond complex, also managed by the USFWS, which is mostly in Santa Clara County, with five ponds in Alameda County; and the Eden Landing Pond Complex, in Alameda County, which is owned and managed by the CDFW. The SBSP Restoration Project presented in the Final EIS/EIR was both programmatic, covering a 50-year period, and project-level, addressing the specific components and implementation of Phase 1.
In January 2008, we signed a Record of Decision selecting the Tidal Emphasis Alternative (Alternative C) for implementation. This alternative will result in 90 percent of the USFWS's ponds on the Refuge being restored to tidal wetlands and 10 percent converted to managed ponds. Under Phase 1 of Alternative C, we restored ponds E8A, E8X, E9, E12, and E13 at the Eden Landing complex; A6, A8, A16, and A17 at the Alviso complex; and SF2 at the Ravenswood complex. We also added several trails, interpretive features, and other recreational access points. Construction was completed on the USFWS ponds in 2013.
We now propose restoration or enhancement of over 2,000 acres of former salt ponds in the second phase of the SBSP Restoration Project. In the Phase 2 DEIS/EIR, we provided project-level analysis of proposed restoration or enhancement of portions of the following three geographically separate pond clusters: The Ravenswood Pond Complex (R3, R4, R5, and S5), the Alviso Pond Complex—Mountain View Ponds (A1 and A2W), the Alviso Pond Complex—A8 Ponds (A8 and A8S), and the Alviso Pond Complex—Island Ponds (A19, A20, and A21). These pond clusters are illustrated in Figures 1-5 on the SBSP Restoration Project Web site at http://www.southbayrestoration.org/planning/phase2/.
Phase 2 of the SBSP Restoration Project is intended to restore and enhance tidal wetlands and managed pond habitats in South San Francisco Bay while providing for flood management and wildlife-oriented public access and recreation. In this Phase 2 document, we would continue habitat restoration activities in both USFWS pond complexes, while also providing recreation and public access opportunities at two sets of ponds and maintaining or improving current levels of flood protection in the surrounding communities.
The Draft EIS/EIR was available for a 60-day public review and comment period, which we announced via several methods, including public notices in local newspapers and a notice in the Federal Register (80 FR 44103; July 24, 2015). We held a public meeting to solicit comments on the Draft EIS/EIR on August 4, 2015. We identified and analyzed a range of alternatives by pond cluster alternatives in the Draft EIS/EIR.

Alternatives
We considered a range of alternatives and their impacts in the DEIS/EIR, including No Action Alternatives for each group of ponds. The range of alternatives included varying approaches to restoring tidal marshes (including number and location of breaches and other levee modifications), habitat enhancements (islands, transition zones, and channels), modifications to existing levees and berms to maintain or improve flood protection, and recreation and public access components (including trails, boardwalks, and viewing platforms) which correspond to the project objectives.
The alternatives for each group of ponds, or pond cluster, are described below. The No Action Alternatives are described together, followed by the Action Alternatives that were considered for each pond cluster.

Alviso—Island Ponds, Alviso—Mountain View Ponds, Alviso—A8 Ponds, and Ravenswood Ponds—Alternatives A (No Action)
Under Alternatives Island A, Mountain View A, A8 A, and Ravenswood A (the No Action Alternative at each of these pond clusters), no new activities would be implemented as part of Phase 2. The pond clusters would continue to be monitored and managed through the activities described in the Adaptive Management Plan (AMP) and in accordance with current USFWS practices.

Alviso—Island Ponds

Alternative Island B
Alternative Island B would breach Pond A19's northern levee and remove or lower levees between Ponds A19 and A20 to increase connectivity and improve the ecological function of both ponds.

Alternative Island C
Alternative Island C would include the components of Alternative Island B with the addition of levee breaches on the north sides of Ponds A20 and A21, lowering of portions of levees around Pond A20, pilot channels in Pond A19, and widening the existing breaches on the southern levee of Pond A19.

Alviso—Mountain View Ponds

Alternative Mountain View B
Under Alternative Mountain View B, Ponds A1 and A2W levees would be breached at several points to introduce tidal flow in the ponds. Portions of Pond A1's western levee would be built up to maintain current levels of flood protection provided by the pond itself. Habitat transition zones and habitat islands would be constructed in the ponds to increase habitat complexity and quality for special-status species. A new trail and viewing platform would be installed to improve recreation and public access at these ponds.

Alternative Mountain View C
Under Alternative Mountain View C, levees would be breached and lowered to increase tidal flows in Pond A1, Pond A2W, and Charleston Slough. The inclusion of Charleston Slough (by breaching and lowering much of Pond A1's western levee) is the primary distinguishing feature between Alternative Mountain View B and Alternative Mountain View C. Several additional new trails and viewing platforms would be installed or replaced to improve recreation and public access at the pond cluster. To continue providing water to the City of Mountain View's Shoreline Park sailing lake, a new water intake would be constructed at the proposed breach between Pond A1 and Charleston Slough.

Alviso—A8 Ponds

Alternative A8 B
Alternative A8 B proposes the construction of habitat transition zones in Pond A8S's southwest corner, southeast corner, or both, depending on the amount of material available.

Ravenswood Ponds

Alternative Ravenswood B
Alternative Ravenswood B would open Pond R4 to tidal flows, improve levees to provide additional flood protection, create habitat transition zone along the western edge of Pond R4, establish managed ponds to improve habitat for diving and dabbling birds, increase pond connectivity, and add a viewing platform to improve recreation and public access.

Alternative Ravenswood C
Alternative Ravenswood C would be similar to Alternative Ravenswood B, with the following exceptions: Ponds R5 and S5 would be converted to a particular type of managed pond that is operated to maintain intertidal mudflat elevation; water control structures would be installed on Pond R3 to allow for improvement to the habitat for western snowy plover; an additional habitat transition zone would be constructed; and two public access and recreational trails and additional viewing platforms would be constructed.

Alternative Ravenswood D
Alternative Ravenswood D would open Pond R4 to tidal flows, improve levees to provide additional flood protection, create two habitat transition zones in Pond R4, establish enhanced managed ponds in Ponds R5 and S5, increase pond connectivity, enhance Pond R3 for western snowy plover habitat, remove the levees within and between Ponds R5 and S5, and improve recreation and public access. Alternative Ravenswood D would also allow temporary stormwater detention into Ponds R5 and S5 via connections with the City of Redwood City's Bayfront Canal and Atherton Channel Project. This would treat a residual salinity problem in Ponds R5 and S5.
Following public review of the Draft EIS/EIR, USFWS and the California State Coastal Conservancy, in coordination with the Project Management Team and other project partners, identified the preferred alternative, which is based on restoration enhancements at all four pond clusters, as well as maintained or increased flood protection and additional public access and recreation features at two of the Phase 2 pond clusters.
Preferred Alternative: The preferred alternative at each pond cluster is as follows:
• At the Island Ponds it is Alternative Island B, with one restoration component of Alternative Island C included, which is to widen only the westernmost of the two existing breaches on the south side of Pond A19.
• At the Mountain View Ponds it is essentially Alternative Mountain View B, with the substitution of one habitat enhancement (do not include Charleston Slough in tidal marsh restoration but do construct a habitat transition zone across the entire southern extent of Pond A1, but only across central portion of A2W) and the addition of one public access component drawn from Mountain View C (add recreational trail on eastern levee of Pond A2W to the northeast corner of Pond A2W). There is also a modification of one of the flood protection features presented in the two action alternatives (raise the Coast Casey Forebay levee along southern border of Charleston Slough and maintain necessary access to existing utilities adjacent to that levee).
• At the A8 Ponds it is Alternative A8 B, except that the top elevation of the proposed transition zones has been increased to provide greater erosion protection.
• At the Ravenswood Ponds it is similar to Alternative Ravenswood B, in its restoration goals and features for Ponds R3, R4, R5, and S5, but it also includes an additional habitat transition zone and a trail on the eastern edge of Ponds R5 and S5, all of which were included in Alternatives Ravenswood C and D.

NEPA Compliance
We will make a decision no sooner than 30 days after the publication of the final EIS/EIR. We anticipate issuing a Record of Decision in the summer of 2016.
We provide this notice under regulations in the Code of Federal Regulations (CFR) for implementing the National Environmental Policy Act (40 CFR 1506.6).
Dated: May 20, 2016.
Ren Lohoefener,

Regional Director, Pacific Southwest Region.
DEPARTMENT OF THE INTERIOR
Fish and Wildlife Service
[Docket No. FWS-HQ-IA-2016-0071; FXIA16710900000-156-FF09A30000]
Endangered Species; Receipt of Applications for Permit

AGENCY:
Fish and Wildlife Service, Interior.

ACTION:
Notice of receipt of applications for permit.

SUMMARY:
We, the U.S. Fish and Wildlife Service, invite the public to comment on the following applications to conduct certain activities with endangered species. With some exceptions, the Endangered Species Act (ESA) prohibits activities with listed species unless Federal authorization is acquired that allows such activities.

DATES:
We must receive comments or requests for documents on or before July 5, 2016.

ADDRESSES:
Submitting Comments: You may submit comments by one of the following methods:
• Federal eRulemaking Portal: http://www.regulations.gov. Follow the instructions for submitting comments on Docket No. FWS-HQ-IA-2016-0071.
• U.S. mail or hand-delivery: Public Comments Processing, Attn: Docket No. FWS-HQ-IA-2016-0071; U.S. Fish and Wildlife Service Headquarters, MS: BPHC; 5275 Leesburg Pike, Falls Church, VA 22041-3803.
When submitting comments, please indicate the name of the applicant and the PRT# you are commenting on. We will post all comments on http://www.regulations.gov. This generally means that we will post any personal information you provide us (see the Public Comments section below for more information). Viewing Comments: Comments and materials we receive will be available for public inspection on http://www.regulations.gov, or by appointment, between 8 a.m. and 4 p.m., Monday through Friday, except Federal holidays, at the U.S. Fish and Wildlife Service, Division of Management Authority, 5275 Leesburg Pike, Falls Church, VA 22041-3803; telephone 703-358-2095.

FOR FURTHER INFORMATION CONTACT:
Brenda Tapia, (703) 358-2104 (telephone); (703) 358-2281 (fax); DMAFR@fws.gov (email).

SUPPLEMENTARY INFORMATION:

I. Public Comment Procedures

A. How do I request copies of applications or comment on submitted applications?
Send your request for copies of applications or comments and materials concerning any of the applications to the contact listed under ADDRESSES . Please include the Federal Register notice publication date, the PRT-number, and the name of the applicant in your request or submission. We will not consider requests or comments sent to an email or address not listed under ADDRESSES . If you provide an email address in your request for copies of applications, we will attempt to respond to your request electronically.
Please make your requests or comments as specific as possible. Please confine your comments to issues for which we seek comments in this notice, and explain the basis for your comments. Include sufficient information with your comments to allow us to authenticate any scientific or commercial data you include.
The comments and recommendations that will be most useful and likely to influence agency decisions are: (1) Those supported by quantitative information or studies; and (2) Those that include citations to, and analyses of, the applicable laws and regulations. We will not consider or include in our administrative record comments we receive after the close of the comment period (see DATES ) or comments delivered to an address other than those listed above (see ADDRESSES ).

B. May I review comments submitted by others?
Comments, including names and street addresses of respondents, will be available for public review at the street address listed under ADDRESSES . The public may review documents and other information applicants have sent in support of the application unless our allowing viewing would violate the Privacy Act or Freedom of Information Act. 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.

II. Background
To help us carry out our conservation responsibilities for affected species, and in consideration of section 10(a)(1)(A) of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531 et seq. ), along with Executive Order 13576, “Delivering an Efficient, Effective, and Accountable Government,” and the President's Memorandum for the Heads of Executive Departments and Agencies of January 21, 2009—Transparency and Open Government (74 FR 4685; January 26, 2009), which call on all Federal agencies to promote openness and transparency in Government by disclosing information to the public, we invite public comment on these permit applications before final action is taken.

III. Permit Applications

Endangered Species

Applicant: San Diego Zoo, San Diego, CA; PRT-68861B
The applicant requests an amendment of their permit to export one male yellow-footed rock wallaby ( Petrogale xanthopus xanthopus ) for the purpose of enhancement of the survival of the species. This notification covers activities to be conducted by the applicant over a 1-year period.

Applicant: Greenville Zoo, Greenville, SC; PRT-91101B
The applicant requests a permit to import one male captive-bred, Amur leopard ( Panthera pardus orientalis ) for the purpose of enhancement of the survival of the species. This notification covers activities to be conducted by the applicant over a 1-year period.

Applicant: Zoological Society of San Diego, San Diego, CA; PRT-88300B
The applicant requests a permit to import two female captive-bred Amur leopards ( Panthera pardus orientalis ) for the purpose of enhancement of the survival of the species. This notification covers activities to be conducted by the applicant over a 1-year period.

Applicant: Micanopy Zoological Preserve, Micanopy, FL; PRT-84541B
The applicant requests a permit to import one female captive-bred babirusa ( Babyrousa celebensis ) for the purpose of enhancement of the survival of the species through captive propagation and zoological display.

Applicant: Tiger World Inc., Rockwell, NC; PRT-97961A
The applicant requests an amendment of their captive-bred wildlife registration under 50 CFR 17.21(g) for the following species to enhance species propagation or survival: African lion ( Panthera leo ), black-and-white ruffed lemur ( Varecia variegata ), ring-tailed lemur ( Lemur catta ), red ruffed lemur ( Varecia rubra ), mandrill ( Mandrillus sphinx ), lar gibbon ( Hylobates lar ), clouded leopard ( Neofelis nebulosa ), leopard ( Panthera pardus ), snow leopard ( Uncia uncia ), Galapagos tortoise ( Chelonoidis nigra ), and radiated tortoise ( Astrochelys radiata ). This notification covers activities to be conducted by the applicant over a 5-year period.

Applicant: Milwaukee County Zoological Gardens, Milwaukee, WI; PRT-85795B
On April 22, 2016, we published a Federal Register notice inviting the public to comment for a permit to conduct certain activities with endangered species (78 FR 23745). We are now reopening the comment period to allow the public the opportunity to review additional information that was mistakenly omitted from the application for the request for a permit to import one female captive-bred snow leopard ( Uncia uncia ) for the purpose of enhancement of the survival of the species. This notification covers activities to be conducted by the applicant over a 1-year period.
Brenda Tapia,

Program Analyst/Data Administrator, Branch of Permits, Division of Management Authority.
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
[LLCOS05000 L16100000.DP0000]
Notice of Availability of the Draft Resource Management Plan and Draft Environmental Impact Statement for the Uncompahgre Field Office, Colorado

AGENCY:
Bureau of Land Management, Interior.

ACTION:
Notice.

SUMMARY:
In accordance with the National Environmental Policy Act of 1969, as amended, and the Federal Land Policy and Management Act of 1976, as amended, the Bureau of Land Management (BLM) has prepared a Draft Resource Management Plan (RMP) and Draft Environmental Impact Statement (EIS) for the Uncompahgre Planning Area and by this notice is announcing the opening of the public comment period.

DATES:
To ensure that comments will be considered, the BLM must receive written comments on the Draft RMP/EIS within 90 days following the date the Environmental Protection Agency publishes this notice of the Draft RMP/EIS in the Federal Register . The BLM will announce future meetings or hearings and any other public participation activities at least 15 days in advance through public notices, media releases, and/or mailings.

ADDRESSES:
You may submit comments related to the Uncompahgre Draft RMP/EIS by any of the following methods:
• Email: uformp@blm.gov .
• Mail: Uncompahgre RMP, 2465 South Townsend Avenue, Montrose, CO 81401.
• Fax: 970-240-5368.
Copies of the Uncompahgre Draft RMP/EIS are available in the Uncompahgre Field Office at the above address or on the RMP Web site at: http://www.blm.gov/co/st/en/fo/ufo/uncompahgre_rmp.htm; or at: www.uformp.com.

FOR FURTHER INFORMATION CONTACT:
Gina Jones, Southwest District NEPA Coordinator; telephone 970-240-5300; see above for address and email. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to contact the above individual during normal business hours. The FIRS is available 24 hours a day, seven days a week, to leave a message or question with the above individual. You will receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:
The BLM prepared the Uncompahgre Draft RMP/EIS to evaluate and revise the management strategy for resources, resource uses, and special designations within the Uncompahgre planning area. Existing management decisions for public lands and resources in the Uncompahgre planning area are described in two documents: the 1985 San Juan/San Miguel RMP, as amended; and the 1989 Uncompahgre Basin RMP, as amended.
The Uncompahgre planning area includes approximately 3.1 million acres of land managed by the BLM, U.S. Forest Service (portions of the Grand Mesa, Uncompahgre and Gunnison National Forest), National Park Service (Black Canyon of the Gunnison National Park, and portions of Curecanti National Recreation Area), U.S. Bureau of Reclamation, State of Colorado (including Ridgway, Crawford, and Paonia State Parks), and local and private lands all of which are located in southwestern Colorado, in Montrose, Delta, Gunnison, Ouray, San Miguel and Mesa counties. The Gunnison Gorge National Conservation Area (NCA) and the Dominguez-Escalante NCA are not within the planning area for this Draft RMP/EIS. The Uncompahgre RMP will determine management for approximately 675,800 acres of BLM-administered surface lands and for approximately 971,220 acres of Federal mineral estate.
The formal public scoping process for the Uncompahgre RMP began February 25, 2010, with the publication of a Notice of Intent in the Federal Register
(75 FR 8739) . The BLM held seven scoping open houses in January and February 2010. The BLM used public scoping comments to help identify planning issues that led to the formulation of alternatives and framed the scope of analysis in the Draft RMP/EIS. The BLM also used the scoping process to introduce the public to the preliminary planning criteria, which set limits on the scope of the Draft RMP/EIS.
Major issues considered in the Draft RMP/EIS include management of biological resources including special status species, renewable and non-renewable energy, minerals, human activities and uses including livestock and recreation, utility/energy corridors and rights-of-way (ROW), and cultural resources. The RMP also addresses decisions regarding Wild and Scenic Rivers, the Old Spanish National Historic Trail, and lands with wilderness characteristics. The Draft RMP/EIS evaluates in detail the No Action Alternative (Alternative A), three action alternatives (Alternatives B, C and D), and sub-alternative (B.1). The BLM identified Alternative D as the Preferred Alternative. This alternative, however, does not represent the final agency direction, and the Proposed RMP may reflect changes or adjustments based on information received during public comment on the Draft RMP/EIS, new information, or changes in the BLM policies or priorities. The Proposed RMP may include objectives and actions described in any of the alternatives analyzed in the Draft.
Alternative A retains the current management goals, objectives, and direction specified in the 1985 San Juan/San Miguel RMP and the 1989 Uncompahgre Basin RMP. Alternative B emphasizes improving, rehabilitating and restoring resources; sustaining the ecological integrity of habitats for all priority plant, wildlife and fish species; and allowing appropriate development scenarios for allowable uses (such as mineral leasing, locatable mineral development, recreation, communication sites and livestock grazing). Alternative B.1 is a subset of Alternative B, and specifically addresses oil and gas leasing and development in the North Fork and Smith Fork drainages of the Gunnison River. Certain areas would be closed to oil and gas leasing and this alternative would impose development setbacks with strict surface use restrictions in places where leasing might be allowed to occur. Alternative C emphasizes the appropriate mix of uses that maximize utilization of resources while protecting land health. The appropriate development scenarios for allowable uses emphasize maximizing resource production in an environmentally responsible manner, while maintaining the basic protection needed to sustain resources, including mitigating impacts on land health. Alternative D emphasizes balancing resources and resource use among competing human interests, land uses, and the conservation of natural and cultural resource values, while sustaining and enhancing ecological integrity across the landscape, including plant, wildlife, and fish habitat. This alternative incorporates a balanced level of protection, restoration, enhancement and use of resources and services to meet ongoing programs and land uses.
Pursuant to 43 CFR 3461.2-1(a)(2), this notice announces a concurrent public comment period on the application of unsuitability criteria to lands with coal development potential. Maps and other information describing the results of the application of unsuitability criteria are available at the BLM Uncompahgre Field Office.
The Uncompahgre planning area has all or portions of five Wilderness Study Areas (Needle Rock, Adobe Badlands, Camel Back, Sewemup Mesa, Dolores River Canyons), as well as the congressionally designated Tabeguache Area. This RMP analyses seven areas identified as lands with wilderness characteristics. Also, this RMP analyzes eligible water segments for recommendation for inclusion in the National Wild and Scenic River System.
Pursuant to 43 CFR 1610.7-2(b), this notice announces a concurrent public comment period on the proposed Areas of Critical Environmental Concern (ACEC). The BLM analyzed 19 potential ACECs meeting the relevance and importance criteria within the range of alternatives. The alternative where each ACEC is considered, as well as the largest size and most restrictive limitations under consideration for each potential ACEC within the range of alternatives are as follows:
• Adobe Badlands ACEC, 6,370 acres, Alternatives A, C, D: ROW avoidance; close to coal leasing; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; close to motorized and mechanized travel; Visual Resource Management (VRM) Class I; close to major utility development; manage for day use only; prohibit camping and campfires; No Surface Occupancy (NSO) for fluid minerals; Site Specific Relocation (SSR) for non-fluid mineral activities.
• Fairview South ACEC, up to 4,250 acres, Alternatives A, B, C, D: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; close to motorized and mechanized travel; designated trail systems for non-motorized and non-mechanized travel; VRM Class III; close to sheep and cattle grazing; day use only; prohibit camping and campfires; prohibit wood collecting; close to wood product sales and/or harvest; NSO for fluid minerals; No Ground Disturbance (NGD) for non-fluid mineral activities.
• Needle Rock ACEC, 80 acres, Alternatives A, B, C, D: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; close to livestock grazing; limit motorized and mechanized travel to designated routes; VRM Class I; day use only; prohibit camping, prohibit open campfires (require use of stoves or grills); prohibit wood collecting; close to wood product sales and/or harvest; prohibit rock climbing; provide adequate protection (signing, stipulations, barricades and fences) to protect sensitive species and their habitats; NSO for fluid minerals; SSR for non-fluid mineral activities.
• San Miguel River ACEC, up to 35,480 acres, Alternatives A, B, C, D: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; close to coal leasing; VRM Class II and III; close to wood product sales and/or harvest; allow on-site collection of dead and downed wood for campfires (fire pans required); close to livestock grazing; limit camping to designated sites and areas; limit camping to no longer than 7 consecutive days at any one location and prohibit return to that location for 30 days; prohibit target shooting; close to recreational mining; limit motorized and mechanized travel to designated routes; locate facility development outside the 100-year floodplain; prohibit BLM-permitted actions (such as ROWs, bike trails and camping areas) in relic riparian communities; close to fluid mineral leasing and geophysical exploration; provide informational and interpretive signs; designated trail systems, restrooms, barricades and fences, as needed for enhanced visitor use, enjoyment, and safety and to protect sensitive species and their habitats.
• Coyote Wash ACEC, 2,100 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class II; NSO for fluid minerals; NGD for non-fluid mineral activities; provide facilities ( e.g., informational and interpretive signs, designated trail systems, camping areas, restrooms, barricades and fences) for resource protection.
• Dolores River Slickrock Canyon ACEC, up to 10,670 acres, Alternatives B, D: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class II; close to recreational mining; close to motorized and mechanized travel; provide facilities (informational/interpretive signs, designated trail systems, camping areas, restrooms, barricades, fences) as needed for resource protection; camping only in designated sites and areas, prohibit open campfires (fire pans, stoves, or grills required); close to wood product sales and/or harvest; require porta-potties for overnight use if restroom is not available; no leasing of fluid minerals; NGD for non-fluid mineral activities.
• East Paradox ACEC, 7,360 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class III; limit motorized and mechanized travel to designated routes; close to camping; close to coal leasing; NSO for fluid minerals; NGD for non-fluid mineral activities; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive species and their habitats; on 1,810 acres limit all travel (motorized, mechanized, pedestrian and equestrian) to designated routes.
• Biological Soil Crust ACEC, 1,900 acres, Alternative D: ROW exclusion; close to mineral materials disposal; close to non-energy solid mineral leasing; recommend for withdrawal from locatable mineral entry; VRM Class II; locate livestock salt/mineral supplement sites and water sites farther than 0.25 mile from the boundary of the gypsipherous soils (allow existing livestock watering reservoirs closer than 0.25 mile from the gypsipherous soils to remain); limit motorized and mechanized travel to designated routes; manage for day use only; prohibit camping; NSO for fluid minerals; SSR for non-fluid mineral activities.
• La Sal Creek ACEC, 10,490 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class II; limit motorized and mechanized travel to designated routes; allow camping only in designated sites and areas; provide facilities ( e.g., informational and interpretive signs, designated trail systems, camping areas, restrooms, barricades and fences, as needed) for resource protection; NSO for fluid minerals; NGD for non-fluid mineral activities.
• Lower Uncompahgre Plateau ACEC, 31,810 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class III; limit motorized and mechanized travel to designated routes; provide facilities ( e.g., informational and interpretive signs, designated trail systems, camping areas, restrooms, barricades and fences, as needed) to provide resource protection; NSO for fluid minerals; NGD for non-fluid mineral activities.
• Paradox Rock Art ACEC, 1,080 acres, Alternatives B, D: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class II; limit motorized and mechanized travel to designated routes; provide facilities ( e.g., informational and interpretive signs, designated trail systems and camping areas, and restrooms, as needed) for resource protection; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sites; allow camping only in designated sites and areas; prohibit target shooting; close to rock climbing; issue no Special Recreation Permits (SRP); NSO for fluid minerals; NGD for non-fluid mineral activities.
• Roubideau-Potter-Monitor ACEC, 20,430 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class II; limit motorized and mechanized travel to designated routes; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive species and their habitats; issue no SRP for competitive events; prohibit target shooting; close to wood product sales and/or harvest and Christmas tree cutting; close to recreational mining; close to fluid mineral leasing; NGD for non-fluid mineral activities.
• Roubideau Corridors ACEC, 8,720 acres, Alternative D: ROW avoidance; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class III; limit motorized and mechanized travel to designated routes; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive species and their habitats; close to wood product sales and/or harvest and Christmas tree cutting; NSO for fluid minerals; SSR for non-fluid mineral activities.
• Salt Desert Shrub Ecosystem ACEC, 34,510 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class III; limit motorized and mechanized travel to designated routes; provide such facilities as informational and interpretive signs, barricades and fences, as needed to protect resources; manage for day use only: Prohibit camping and open campfires (require use of stoves or grills); prohibit wood collecting; close to coal leasing; NSO for fluid minerals; NGD for non-fluid mineral activities.
• San Miguel Gunnison Sage-Grouse ACEC, 470 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; manage as VRM Class III; limit motorized and mechanized travel to designated routes; close to motorized and mechanized travel April 1 to July 15 (during sage-grouse strutting, nesting and brood-rearing season) to prevent disturbance to breeding sage-grouse; follow recommendations in San Miguel Basin Gunnison Sage-Grouse Conservation Plan (San Miguel Basin Gunnison Sage-Grouse Working Group 2009); manage vegetation for optimal Gunnison Sage-Grouse habitat; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive species and their habitats; close to leasing for fluid minerals; NGD for non-fluid mineral activities.
• Sims-Cerro Gunnison Sage-Grouse ACEC, 25,620 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class III; manage vegetation for optimal Gunnison Sage-Grouse habitat; limit motorized and mechanized travel to designated routes; close to motorized and mechanized travel April 1 to July 15 (during sage-grouse strutting, nesting and brood-rearing season); provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive species and their habitats; develop a Sims-Cerro Gunnison Sage-Grouse Conservation Plan; close to leasing for fluid minerals; NGD for non-fluid mineral activities.
• Tabeguache Pueblos and Tabeguache Caves ACEC, 26,400 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class I (5,260 acres),VRM Class II (21,140 acres); limit motorized and mechanized travel to designated routes; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive sites; NSO for fluid minerals; NGD for non-fluid mineral activities.
• Tabeguache Creek ACEC, 560 acres, Alternative A: VRM Class II; close to Off-Road Vehicle use; NSO for fluid minerals.
• West Paradox ACEC, 5,190 acres, Alternative B: ROW exclusion; recommend for withdrawal from locatable mineral entry; close to mineral materials disposal; close to non-energy solid mineral leasing; VRM Class III; limit motorized and mechanized travel to designated routes; close to rock climbing during peregrine falcon breeding season (March 1 to August 15) if birds are present; provide facilities ( e.g., informational and interpretive signs, designated trail systems, camping areas and restrooms, as needed) for resource protection; provide adequate protection (signs, use stipulations, barricades and fences, as needed) to protect sensitive species and their habitats; allow camping only in designated sites and areas; NSO for fluid minerals; NGD for non-fluid mineral activities.
Please note that public comments and information submitted including names, street addresses, and email addresses of persons who submit comments will be available for public review and disclosure at the above address during regular business hours (8 a.m. to 4 p.m.), Monday through Friday, except holidays.
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.

Authority:
40 CFR 1506.6, 40 CFR 1506.10, 43 CFR 1610.2, 43 CFR 1610.5.
Ruth Welch,

BLM Colorado State Director.
DEPARTMENT OF THE INTERIOR
Bureau of Land Management
[LLORM05000.L63340000.DU0000.16XL1116AF; HAG 16-0047]
Notice of Availability of the Draft Medford District Resource Management Plan Amendment and Environmental Assessment: Table Rocks Area of Critical Environmental Concern Proposed Boundary Change and Supplementary Rules

AGENCY:
Bureau of Land Management, Interior.

ACTION:
Notice.

SUMMARY:
In accordance with the National Environmental Policy Act of 1969, as amended, and the Federal Land Policy and Management Act of 1976, as amended, the Bureau of Land Management (BLM) has prepared a Draft Resource Management Plan (RMP) Amendment and Draft Environmental Assessment (EA) titled Medford District RMP Amendment and EA: Table Rocks Area of Critical Environmental Concern (ACEC) Proposed Boundary Change and Supplementary Rules and, by this notice, is announcing the opening of the comment period.

DATES:
To ensure that comments will be considered, the BLM must receive written comments on the Draft RMP Amendment/Draft EA within 60 days following the date the BLM publishes its notice of the Draft RMP Amendment/Draft EA in the Federal Register . The BLM will announce future meetings or hearings and any other public participation activities at least 15 days in advance through public notices, media releases, and/or mailings.

ADDRESSES:
You may submit comments related to the Medford District RMP Amendment and EA: Table Rocks ACEC Proposed Boundary Change and Supplementary Rules by any of the following methods:
• Web site: https://eplanning.blm.gov/epl-front-office/eplanning/nepa/nepa_register.do .
• Email: BLM_OR_MD_Mail@blm.gov .
• Fax: (541) 618-2400.
• Mail: 3040 Biddle Road, Medford, OR 97504.
Copies of the Medford District RMP Amendment and EA: Table Rocks ACEC Proposed Boundary Change and Supplementary Rules are available in the Medford District Office at the above address.

FOR FURTHER INFORMATION CONTACT:
Anthony Kerwin, District Planning and Environmental Coordinator; telephone (541) 618-2402; address 3040 Biddle Road, Medford, OR 97504; email BLM_OR_MD_Mail@blm.gov. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to contact the above individual during normal business hours. The FIRS is available 24 hours a day, 7 days a week, to leave a message or question with the above individual. You will receive a reply during normal business hours.

SUPPLEMENTARY INFORMATION:
The proposed action includes the following:
• Add to Table Rocks ACEC designation 863 acres the BLM has acquired since the original 1986 ACEC designation. The parcels include 40 acres on Lower Table Rock in Township 36 South, Range 2 West, Section 4; 557 acres on Upper Table Rock in Township 35 South, Range 2 West, Sections 25, 26, 35, & 36; and 266 acres on Upper Table Rock in Township 36 South, Range 2 West, Section 2.
• Remove from ACEC designation 0.9 acres located in Township 36 South, Range 2 West, Section 1, located across Modoc Road from the Upper Table Rock trailhead parking lot (Map 2 inset).
• Establish the ACEC boundary around an area totaling 4,864 acres which would encompass contiguous BLM and TNC lands and lands under conservation easement. The establishment of the larger ACEC boundary would not establish an ACEC or authorize any BLM decisions or actions on non-BLM lands (including existing TNC lands).
• In the future, incorporate lands acquired within or adjacent to the expanded ACEC boundary if they meet the relevance and importance criteria for the Table Rocks ACEC and require special management attention.
• Establish the following supplemental rules:
a. No discharge of firearms, or discharge of gas or air powered weapons, including paintball and paintball-like weapons.
b. No motorized vehicles or non-motorized mechanized vehicles that are propelled or powered by any means.
c. No dogs or other domestic animals outside of trailhead parking areas, except on trails signed as allowing leashed dogs in the Camp White zone.
d. No metal detectors or digging, scraping, disturbing, or removing natural land features for any purpose.
e. No campfires or overnight camping.
The ACEC boundary and designation changes would amend the 1995 Medford RMP. The adoption of the supplementary rules is an implementation-level action.
The supplementary rules would make permanent the Temporary Restrictions that were implemented in 2014 to protect the resource values of the 1,243 acres of ACEC lands and the 852 acres of acquired BLM lands. Those restrictions were published in the Federal Register on March 26, 2014, and prohibited the above-mentioned activities in the Table Rocks ACEC and associated, acquired lands.
The Table Rocks ACEC was designated in 1986 by an amendment to the Medford District Management Framework Plan. The area, which includes 1,003 acres on Upper Table Rock and 240 acres on Lower Table Rock, was designated an ACEC to recognize and protect botanical and geological features, threatened and endangered and special status species, and natural systems. The vernal pools, ecology, Limnanthes pumila ssp. pumila (plant species: Dwarf woolly meadowfoam), and geology met the criteria for relevance and importance to qualify the area as an ACEC.
Between 1979 and 2009, TNC acquired several parcels on the Table Rocks which they have managed as the Table Rocks Preserve. In 1980, TNC was granted a perpetual conservation easement on 795 acres of private land on Lower Table Rock. In 2009, TNC purchased a parcel with funds provided in part by the Oregon Watershed Enhancement Board (OWEB). As a condition of the OWEB grant, TNC granted OWEB a perpetual easement on 898 acres of the purchased lands on both Table Rocks. The Nature Conservancy's management objectives are to protect ecological diversity and to provide scenic and biologic continuity between the Table Rocks and the Rogue River while protecting the area from potential development.
As of 2012, the BLM and TNC own all vernal pool habitats on the summits and most of the flanks of the Table Rocks, totaling 4,864 acres. Since the 1986 ACEC designation, the BLM has acquired three parcels from TNC—40 acres on Lower Table Rock to develop trailhead facilities and 823 acres in two separate parcels on Upper Table Rock. The BLM anticipates acquiring a fourth acquisition from TNC in 2016 consisting of five parcels totaling 221 acres. These parcels were evaluated in 2013 in an ACEC review and were determined to contain ecological, historical, cultural and scenic resources, and potential recreational values similar and supplemental to the original ACEC. They meet the criteria for relevance and importance for an ACEC and are under temporary management consistent with management of the rest of the Table Rocks ACEC until they are officially designated as part of the ACEC. While these lands are within the proposed ACEC boundary, they will not be part of the ACEC; however, this allows the BLM to incorporate lands we expect to acquire in the future within this boundary into the ACEC without having to prepare another RMP Amendment.
The BLM issued a Notice of Intent to Prepare an RMP Amendment on September 8, 2014. Publication of the Notice of Intent initiated the public scoping process, with public comments accepted until October 8, 2014. The BLM also sent 366 letters to various agencies, organizations, and landowners located within the planning area. Over 70 responses were received, and many requested a public meeting. On October 16, approximately 50 people attended an evening open house held at the BLM Medford District Office. Because of the interest in the project, the public comment period was extended to November 25, 2015. Another 26 comments were received. The main issue raised by the public during scoping was opposition to the scale and scope of the proposed 13,556-acre ACEC and concern over what the proposed ACEC boundary would mean to private property rights within the boundary. In response, the BLM decreased the size of the proposed boundary in the current proposed action to only include BLM- and TNC-administered lands. No other unresolved issues were identified during scoping.
Scoping conducted for the Table Rocks Temporary Restrictions EA in 2013 was also considered during development of the Draft Plan Amendment and EA. Scoping for the temporary restrictions included visitor surveys conducted at the Table Rocks in 2011 by the Southern Oregon Research Center at Southern Oregon University; discussing hunting issues with representatives from Oregon Department of Fish and Wildlife, Rocky Mountain Elk Foundation, and Oregon Hunters Association; and meeting with the Jackson County Commissioners, who submitted a comment that generated local newspaper and television interest. One comment on the EA was received from the Jackson County Office of County Council which proposed that the BLM should consider implementing temporary restrictions only on the BLM lands that were previously owned by TNC.
This notice begins the 30-day comment period for the Draft Medford District RMP Amendment and EA: Table Rocks Area of Critical Environmental Concern (ACEC) Proposed Boundary Change and Supplementary Rules. Please note that public comments and information submitted—including names, street addresses, and email addresses of persons who submit comments—will be available for public review and disclosure at the above-address during regular business hours (8:00 a.m. to 4:00 p.m.), Monday through Friday, except holidays.
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.

Authority:
40 CFR 1506.6, 40 CFR 1506.10, 43 CFR 1610.2
Jamie E. Connell,

Acting State Director, Oregon/Washington.
DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
[Docket ID: BSEE-2016-0007; OMB Control Number 1014-0006; 16XE1700DX EX1SF0000.DAQ000 EEEE500000]
Information Collection Activities: Sulphur Operations, Proposed Collection; Comment Request

AGENCY:
Bureau of Safety and Environmental Enforcement, Interior.

ACTION:
60-day Notice.

SUMMARY:
To comply with the Paperwork Reduction Act of 1995 (PRA), BSEE is inviting comments on a collection of information that we will submit to the Office of Management and Budget (OMB) for review and approval. The information collection request (ICR) concerns a renewal to the paperwork requirements in the regulations under, Subpart P, Sulphur Operations.

DATES:
You must submit comments by August 2, 2016.

ADDRESSES:
You may submit comments by either of the following methods listed below.
• Electronically: Go to www.regulations.gov and search for BSEE-2016-0007. Follow the instructions to submit public comments and view all related materials. We will post all comments.
• Email: regs@bsee.gov. Mail or hand-carry comments to the Department of the Interior; BSEE; Regulations and Standards Branch; Attention: Kelly Odom; 45600 Woodland Road, Suite 105, Sterling, VA 20166. Please reference ICR 1014-0006 in your comment and include your name and return address.

FOR FURTHER INFORMATION CONTACT:
Kelly Odom, Regulations and Standards Branch at (703) 787-1775 to request additional information about this ICR.

SUPPLEMENTARY INFORMATION:
Title: 30 CFR 250, Subpart P, Sulphur Operations.
OMB Control Number: 1014-0006.
Abstract: The Outer Continental Shelf (OCS) Lands Act, as amended (43 U.S.C. 1331 et seq. and 43 U.S.C. 1801 et seq. ), authorizes the Secretary of the Interior to prescribe rules and regulations necessary for the administration of the leasing provisions of that Act related to mineral resources on the OCS. Such rules and regulations will apply to all operations conducted under a lease. Operations on the OCS must preserve, protect, and develop mineral resources in a manner that is consistent with the need to make such resources available to meet the Nation's energy needs as rapidly as possible; to balance orderly energy resource development with protection of human, marine, and coastal environments; to ensure the public a fair and equitable return on the resources of the OCS; and to preserve and maintain free enterprise competition.
Section 5(a) of the OCS Lands Act requires the Secretary to prescribe rules and regulations “to provide for the prevention of waste, and conservation of the natural resources of the Outer Continental Shelf, and the protection of correlative rights therein” and to include provisions “for the prompt and efficient exploration and development of a lease area.” These authorities and responsibilities are among those delegated to BSEE to ensure that operations in the OCS will meet statutory requirements; provide for safety and protection of the environment; and result in diligent exploration, development, and production of OCS leases.
In addition to the general rulemaking authority of the OCSLA at 43 U.S.C. 1334, section 301(a) of the Federal Oil and Gas Royalty Management Act (FOGRMA), 30 U.S.C. 1751(a), grants authority to the Secretary to prescribe such rules and regulations as are reasonably necessary to carry out FOGRMA's provisions. While the majority of FOGRMA is directed to royalty collection and enforcement, some provisions apply to offshore operations. For example, section 108 of FOGRMA, 30 U.S.C. 1718, grants the Secretary broad authority to inspect lease sites for the purpose of determining whether there is compliance with the mineral leasing laws. Section 109(c)(2) and (d)(1), 30 U.S.C. 1719(c)(2) and (d)(1), impose substantial civil penalties for failure to permit lawful inspections and for knowing or willful preparation or submission of false, inaccurate, or misleading reports, records, or other information. Because the Secretary has delegated some of the authority under FOGRMA to BSEE, 30 U.S.C. 1751 is included as additional authority for these requirements.
This ICR addresses the regulations at 30 CFR 250, Subpart P, Sulphur Operations, and any associated supplementary Notices to Lessees and Operators (NTLs) intended to provide clarification, description, or explanation of these regulations.
Currently, there are no active sulphur lease operations on the OCS. Therefore, this ICR and its relevant hours represent one potential respondent.
Regulations at 30 CFR 250, Subpart P, implement these statutory requirements. The BSEE uses the information collected to ascertain the condition of drilling sites for the purpose of preventing hazards inherent in sulphur drilling and production operations and to evaluate the adequacy of equipment and/or procedures to be used during the conduct of drilling, well-completion, well-workover, and production operations. The BSEE uses the information to:
• Ascertain that a discovered sulphur deposit can be classified as capable of production in paying quantities.
• Ensure accurate and complete measurement of production to determine the amount of sulphur royalty payments due the United States; and that the sale locations are secure, production has been measured accurately, and appropriate follow-up actions are initiated.
• Ensure the adequacy and safety of firefighting plans; the drilling unit is fit for the intended purpose; and the adequacy of casing for anticipated conditions.
• Review drilling, well-completion, well-workover diagrams and procedures, as well as production operation procedures to ensure the safety of the proposed sulphur drilling, well-completion, well-workover and proposed production operations.
• Monitor environmental data during sulphur operations in offshore areas where such data are not already available to provide a valuable source of information to evaluate the performance of drilling rigs under various weather and ocean conditions. This information is necessary to make reasonable determinations regarding safety of operations and environmental protection.
The BSEE will protect proprietary information according to the Freedom of Information Act (5 U.S.C. 552) and its implementing regulations (43 CFR 2); 30 CFR 250.197, Data and information to be made available to the public or for limited inspection; and 30 CFR part 252, OCS Oil and Gas Information Program. No items of a sensitive nature are collected. Responses are mandatory.
Frequency: Occasional and varies by section, but information concerning drilling, well-completion, and well-workover operations and production is collected only once for each particular activity.
Estimated Number and Description of Respondents: Approximately 1 Federal OCS sulphur lessee.
Estimated Reporting and Recordkeeping Hour Burden: The currently approved annual reporting burden for this collection is 903 hours. The following chart details the individual components and respective hour burden estimates of this ICR. In calculating the burdens, we assumed that respondents perform certain requirements in the normal course of their activities. We consider these to be usual and customary and took that into account in estimating the burden.
Citation 30 CFR 250 | Reporting and recordkeeping requirement | Hour burden | Average number of annual reponses | Annual burden hours
General
1605(b)(3); 1617; 1622(b) | These sections contain references to information, approvals, requests, payments, etc., which are submitted with an APD, the burdens for which are covered under its own information collection | APD burden covered under 1014-xxxx
1618(a), (b); 1619(b); 1622(a), (b), (c) | These sections contain references to information, approvals, requests, payments, etc., which are submitted with an APM, the burdens for which are covered under its own information collection | APM burden covered under 1014-xxxx
Submittals/Notifications
1600; 1617 | Submit exploration or development and production plan, under 30 CFR 550, Subpart B | Burden covered under (1010-0151). | 0
1605(d) | Submit results of additional surveys and soil borings upon request | 1 | 1 submission | 1
1605(f) | Submit application for installation of fixed drilling platforms or structures | Burden covered under (1014-0011). | 0
1608(a), (c) | Submit well casing and cementing plan or modification | 5 | 1 plan | 5
1619(b); 1622(c) | Submit form BSEE-0125 (End of Operations Report); and all supporting documentation | Burden covered under (1014-0018). | 0
1619(c), (d), (e) | Submit copies of records, logs, reports, charts, etc., upon request | 1 | 8 submissions | 8
1628(b), (d) | Submit application for design and installation features of sulphur production facilities and fuel gas safety system; certify new installation conforms to approved design | 4 | 1 application | 4
1630(a)(6) | Notify BSEE of pre-production test and inspection of safety system and commencement of production | 0.5 | 2 notifications | 1
1633(b) | Submit application for method of production measurement | 2 | 1 application | 2
Subtotal | | | 14 responses | 21
| Requests
1603(a) | Request determination whether sulphur deposit can produce in paying quantities | 1 | 1 request | 1
1605(e)(5) | Request copy of directional survey (by holder of adjoining lease) | 1 | 1 request | 1
1607 | Request establishment, amendment, or cancellation of field rules for drilling, well-completion, or well-workover | 8 | 2 requests | 16
1610(d)(7), (8) | Request exception to ram-type blowout preventer (BOP) system components rated working pressure | 1 | 1 request | 1
1611(b); 1625(b) | Request exception to water-rated working pressure to test ram-type and annular BOPs and choke manifold | 1 | 1 request | 1
1611(f); 1625(f) | Request exception to recording pressure conditions during BOP tests on pressure charts; certify by representative | 1 | 1 request | 1
1612 | Request exception to § 250.462 requirements for well-control drills | 1 | 1 request | 1
1615 | Request exception to blind-shear ram or pipe rams and inside BOP to secure wells | 1 | 1 request | 1
1629(b)(3) | Request approval of firefighting systems; post firefighting system diagram | 4 | 1 request | 4
1608(b), (c); 1629(b)(3); 1600-1634 | General departure and/or alternative compliance requests not specifically covered elsewhere in Subpart P | 2 | 1 request | 2
Subtotal | | | 11 responses | 29
Record/Retain
1604(f) | Check traveling-block safety device for proper operation weekly and after each drill-line slipping; enter results in log | 0.25 | 1 lessee × 52 wks × 2 rigs = 104 | 26
1605(c) | Report oceanographic, meteorological, and drilling unit performance data upon request | 1 | 1 report | 1
1609(a) | Pressure test casing; record time, conditions of testing, and test results in log | 2 | 1 lease × 60 tests/records = 60 | 120
1611(d)(3); 1625(d)(3) | Record in driller's report the date, time, and reason for postponing pressure testings | 0.17 | 1 lessee × 6 recordings = 6 | 1
1611(f), (g); 1625(f), (g) | Conduct tests, actuations, inspections, maintenance, and crew drills of BOP systems at least weekly; record results in driller's report; certify by representative; retain records for 2 years following completion of drilling activity | 6 | 1 lessee × 52 weeks = 52 | 312
1613(d) | Pressure test diverter sealing element/valves weekly; actuate diverter sealing element/valves/control system every 24 hours; test diverter line for flow every 24 hours; record test times and results in driller's report | 2 | 1 lessee (daily/weekly during drilling) × 2 rigs × 52 weeks = 104 | 208
1616(c) | Retain training records for lessee and drilling contractor personnel | Burden covered under 1014-0008. |
1619(a); 1623(c) | Retain records for each well and all well operations for 2 years; calculate well-control fluid volume and post near operators' station | 12 | 1 lessee | 12
1621 | Conduct safety meetings prior to well-completion or well-workover operations; record date and time | 1 | 1 lessee × 50 meetings/records = 50 | 50
1628(b), (d) | Maintain information on approved design and installation features for the life of the facility | 1 | 1 lessee | 1
1629(b)(1)(ii) | Retain pressure-recording charts used to determine operating pressure ranges for 2 years | 12 | 1 lessee | 12
1630(b) | Maintain records for each safety device installed for 2 years; make available for review | 1 | 1 lessee | 1
1631 | Conduct safety device training prior to production operations and periodically thereafter; record date and time | 1 | 1 lessee × 52 train/records × 2 rigs = 104 | 104
1634(b) | Report evidence of mishandling of produced sulphur or tampering or falsifying any measurement of production | 1 | 1 report | 1
| Subtotal | | | 486 responses | 849
Total Burden | | | 511 responses | 899 Hours
Estimated Reporting and Recordkeeping Non-Hour Cost Burden: There are no non-hour cost burdens associated with this collection.
Public Disclosure Statement: The PRA (44 U.S.C. 3501, et seq. ) provides that an agency may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. Until OMB approves a collection of information, you are not obligated to respond.
Comments: Before submitting an ICR to OMB, PRA section 3506(c)(2)(A) requires each agency “. . . to provide notice . . . and otherwise consult with members of the public and affected agencies concerning each proposed collection of information . . .”. Agencies must specifically solicit comments to: (a) Evaluate whether the collection is necessary or useful; (b) evaluate the accuracy of the burden of the proposed collection of information; (c) enhance the quality, usefulness, and clarity of the information to be collected; and (d) minimize the burden on the respondents, including the use of technology.
Agencies must also estimate the non-hour paperwork cost burdens to respondents or recordkeepers resulting from the collection of information. Therefore, if you have other than hour burden costs to generate, maintain, and disclose this information, you should comment and provide your total capital and startup cost components or annual operation, maintenance, and purchase of service components. For further information on this burden, refer to 5 CFR 1320.3(b)(1) and (2), or contact the Bureau representative listed previously in this notice.
We will summarize written responses to this notice and address them in our submission for OMB approval. As a result of your comments, we will make any necessary adjustments to the burden in our submission to OMB.
Public Comment Procedures: 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.
BSEE Information Collection Clearance Officer: Nicole Mason, (703) 787-1607.
Dated: May 27, 2016.
L. Keith Good,

Senior Advisor, Office of Offshore Regulatory Programs.
INTERNATIONAL TRADE COMMISSION
Notice of Receipt of Complaint; Solicitation of Comments Relating to the Public Interest

AGENCY:
U.S. International Trade Commission.

ACTION:
Notice.

SUMMARY:
Notice is hereby given that the U.S. International Trade Commission has received a complaint entitled Certain Silicon-on-Insulator Wafers, DN 3153; the Commission is soliciting comments on any public interest issues raised by the complaint or complainant's filing under section 210.8(b) of the Commission's Rules of Practice and Procedure (19 CFR § 210.8(b)).

FOR FURTHER INFORMATION CONTACT:
Lisa R. Barton, Secretary to the Commission, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000. The public version of the complaint can be accessed on the Commission's Electronic Document Information System (EDIS) at EDIS, ^1 and will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000.
^1 Electronic Document Information System (EDIS): http://edis.usitc.gov.
General information concerning the Commission may also be obtained by accessing its Internet server at United States International Trade Commission (USITC) at USITC. ^2 The public record for this investigation may be viewed on the Commission's Electronic Document Information System (EDIS) at EDIS. ^3 Hearing-impaired persons are advised that information on this matter can be obtained by contacting the Commission's TDD terminal on (202) 205-1810.
^2 United States International Trade Commission (USITC): http://edis.usitc.gov.
^3 Electronic Document Information System (EDIS): http://edis.usitc.gov.

SUPPLEMENTARY INFORMATION:
The Commission has received a complaint and a submission pursuant to section 210.8(b) of the Commission's Rules of Practice and Procedure filed on behalf of Silicon Genesis Corporation on May 26, 2016. The complaint alleges violations of section 337 of the Tariff Act of 1930 (19 U.S.C. § 1337) in the importation into the United States, the sale for importation, and the sale within the United States after importation of certain silicon-on-insulator wafers. The complaint names as respondent Soitec, S.A. of France. The complainant requests that the Commission issue a limited exclusion order, a cease and desist order, and impose a bond upon respondents' alleged infringing articles during the 60-day Presidential review period pursuant to 19 U.S.C. § 1337(j).
Proposed respondents, other interested parties, and members of the public are invited to file comments, not to exceed five (5) pages in length, inclusive of attachments, on any public interest issues raised by the complaint or section 210.8(b) filing. Comments should address whether issuance of the relief specifically requested by the complainant in this investigation would affect the public health and welfare in the United States, competitive conditions in the United States economy, the production of like or directly competitive articles in the United States, or United States consumers.
In particular, the Commission is interested in comments that:
(i) explain how the articles potentially subject to the requested remedial orders are used in the United States;
(ii) identify any public health, safety, or welfare concerns in the United States relating to the requested remedial orders;
(iii) identify like or directly competitive articles that complainant, its licensees, or third parties make in the United States which could replace the subject articles if they were to be excluded;
(iv) indicate whether complainant, complainant's licensees, and/or third party suppliers have the capacity to replace the volume of articles potentially subject to the requested exclusion order and/or a cease and desist order within a commercially reasonable time; and
(v) explain how the requested remedial orders would impact United States consumers.
Written submissions must be filed no later than by close of business, eight calendar days after the date of publication of this notice in the Federal Register . There will be further opportunities for comment on the public interest after the issuance of any final initial determination in this investigation.
Persons filing written submissions must file the original document electronically on or before the deadlines stated above and submit 8 true paper copies to the Office of the Secretary by noon the next day pursuant to section 210.4(f) of the Commission's Rules of Practice and Procedure (19 CFR § 210.4(f)). Submissions should refer to the docket number (“Docket No. 3153”) in a prominent place on the cover page and/or the first page. ( See Handbook for Electronic Filing Procedures, Electronic Filing Procedures ^4 ). Persons with questions regarding filing should contact the Secretary (202-205-2000).
^4 Handbook for Electronic Filing Procedures: http://www.usitc.gov/secretary/fed_reg_notices/rules/handbook_on_electronic_filing.pdf.
Any person desiring to submit a document to the Commission in confidence must request confidential treatment. All such requests should be directed to the Secretary to the Commission and must include a full statement of the reasons why the Commission should grant such treatment. See 19 CFR § 201.6. Documents for which confidential treatment by the Commission is properly sought will be treated accordingly. All nonconfidential written submissions will be available for public inspection at the Office of the Secretary and on EDIS. ^5
^5 Electronic Document Information System (EDIS): http://edis.usitc.gov .
This action is taken under the authority of section 337 of the Tariff Act of 1930, as amended (19 U.S.C. § 1337), and of sections 201.10 and 210.8(c) of the Commission's Rules of Practice and Procedure (19 CFR § § 201.10, 210.8(c)).
By order of the Commission.
Issued: May 27, 2016.
Lisa R. Barton,

Secretary to the Commission.
INTERNATIONAL TRADE COMMISSION
Notice of Receipt of Complaint; Solicitation of Comments Relating to the Public Interest

AGENCY:
U.S. International Trade Commission.

ACTION:
Notice.

SUMMARY:
Notice is hereby given that the U.S. International Trade Commission has received a complaint entitled Certain Magnetic Data Storage Tapes and Cartridges Containing the Same, DN 3155; the Commission is soliciting comments on any public interest issues raised by the complaint or complainant's filing under section 210.8(b) of the Commission's Rules of Practice and Procedure (19 CFR § 210.8(b)).

FOR FURTHER INFORMATION CONTACT:
Lisa R. Barton, Secretary to the Commission, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000. The public version of the complaint can be accessed on the Commission's Electronic Document Information System (EDIS) at EDIS, ^1 and will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000.
^1 Electronic Document Information System (EDIS): http://edis.usitc.gov.
General information concerning the Commission may also be obtained by accessing its Internet server at United States International Trade Commission (USITC) at USITC. ^2 The public record for this investigation may be viewed on the Commission's Electronic Document Information System (EDIS) at EDIS. ^3 Hearing-impaired persons are advised that information on this matter can be obtained by contacting the Commission's TDD terminal on (202) 205-1810.
^2 United States International Trade Commission (USITC): http://edis.usitc.gov.
^3 Electronic Document Information System (EDIS): http://edis.usitc.gov.

SUPPLEMENTARY INFORMATION:
The Commission has received a complaint and a submission pursuant to section 210.8(b) of the Commission's Rules of Practice and Procedure filed on behalf of FUJIFILM Corporation and FUJIFILM Recording Media U.S.A., Inc. on May 27, 2016. The complaint alleges violations of section 337 of the Tariff Act of 1930 (19 U.S.C. § 1337) in the importation into the United States, the sale for importation, and the sale within the United States after importation of certain magnetic data storage tapes and cartridges containing the same. The complaint names as respondents Sony Corporation of Japan; Sony Corporation of America of New York, NY; and Sony Electronics Inc. of San Diego, CA. The complainant requests that the Commission issue a limited exclusion order, cease and desist orders and impose a bond upon respondents' alleged infringing articles during the 60-day Presidential review period pursuant to 19 U.S.C. § 1337(j).
Proposed respondents, other interested parties, and members of the public are invited to file comments, not to exceed five (5) pages in length, inclusive of attachments, on any public interest issues raised by the complaint or section 210.8(b) filing. Comments should address whether issuance of the relief specifically requested by the complainant in this investigation would affect the public health and welfare in the United States, competitive conditions in the United States economy, the production of like or directly competitive articles in the United States, or United States consumers.
In particular, the Commission is interested in comments that:
(i) explain how the articles potentially subject to the requested remedial orders are used in the United States;
(ii) identify any public health, safety, or welfare concerns in the United States relating to the requested remedial orders;
(iii) identify like or directly competitive articles that complainant, its licensees, or third parties make in the United States which could replace the subject articles if they were to be excluded;
(iv) indicate whether complainant, complainant's licensees, and/or third party suppliers have the capacity to replace the volume of articles potentially subject to the requested exclusion order and/or a cease and desist order within a commercially reasonable time; and
(v) explain how the requested remedial orders would impact United States consumers.
Written submissions must be filed no later than by close of business, eight calendar days after the date of publication of this notice in the Federal Register . There will be further opportunities for comment on the public interest after the issuance of any final initial determination in this investigation.
Persons filing written submissions must file the original document electronically on or before the deadlines stated above and submit 8 true paper copies to the Office of the Secretary by noon the next day pursuant to section 210.4(f) of the Commission's Rules of Practice and Procedure (19 CFR 210.4(f)). Submissions should refer to the docket number (“Docket No. 3155”) in a prominent place on the cover page and/or the first page. ( See Handbook for Electronic Filing Procedures, Electronic Filing Procedures ^4 ). Persons with questions regarding filing should contact the Secretary (202-205-2000).
^4 Handbook for Electronic Filing Procedures: http://www.usitc.gov/secretary/fed_reg_notices/rules/handbook_on_electronic_filing.pdf .
Any person desiring to submit a document to the Commission in confidence must request confidential treatment. All such requests should be directed to the Secretary to the Commission and must include a full statement of the reasons why the Commission should grant such treatment. See 19 CFR 201.6. Documents for which confidential treatment by the Commission is properly sought will be treated accordingly. All nonconfidential written submissions will be available for public inspection at the Office of the Secretary and on EDIS. ^5
^5 Electronic Document Information System (EDIS): http://edis.usitc.gov .
This action is taken under the authority of section 337 of the Tariff Act of 1930, as amended (19 U.S.C. § 1337), and of sections 201.10 and 210.8(c) of the Commission's Rules of Practice and Procedure (19 CFR § § 201.10, 210.8(c)).
By order of the Commission.
Issued: May 27, 2016.
Lisa R. Barton,

Secretary to the Commission.
INTERNATIONAL TRADE COMMISSION
Notice of Receipt of Complaint; Solicitation of Comments Relating to the Public Interest

AGENCY:
U.S. International Trade Commission.

ACTION:
Notice.

SUMMARY:
Notice is hereby given that the U.S. International Trade Commission has received a complaint entitled Certain Inkjet Printers, Printheads, and Ink Cartridges, Components Thereof, and Products Containing Same, DN 3154; the Commission is soliciting comments on any public interest issues raised by the complaint or complainant's filing under section 210.8(b) of the Commission's Rules of Practice and Procedure (19 CFR § 210.8(b)).

FOR FURTHER INFORMATION CONTACT:
Lisa R. Barton, Secretary to the Commission, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000. The public version of the complaint can be accessed on the Commission's Electronic Document Information System (EDIS) at EDIS, ^1 and will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000.
^1 Electronic Document Information System (EDIS): http://edis.usitc.gov.
General information concerning the Commission may also be obtained by accessing its Internet server at United States International Trade Commission (USITC) at USITC. ^2 The public record for this investigation may be viewed on the Commission's Electronic Document Information System (EDIS) at EDIS. ^3 Hearing-impaired persons are advised that information on this matter can be obtained by contacting the Commission's TDD terminal on (202) 205-1810.
^2 United States International Trade Commission (USITC): http://edis.usitc.gov.
^3 Electronic Document Information System (EDIS): http://edis.usitc.gov.

SUPPLEMENTARY INFORMATION:
The Commission has received a complaint and a submission pursuant to section 210.8(b) of the Commission's Rules of Practice and Procedure filed on behalf of HP Inc. on May 27, 2016. The complaint alleges violations of section 337 of the Tariff Act of 1930 (19 U.S.C. § 1337) in the importation into the United States, the sale for importation, and the sale within the United States after importation of certain inkjet printers, printheads, and ink cartridges, components thereof, and products containing same. The complaint names as respondents Memjet, Ltd. of Ireland; Memjet US Services, Inc. of San Diego, CA; Memjet Home and Office, Inc. of Eagle, ID; Memjet North Ryde Pty Ltd. of Australia; Memjet Technology Ltd. of Ireland; Memjet Holdings Ltd. of Ireland; Afinia LLC (d/b/a Afinia Label) of Chanhassen, MN; Astro Machine Corporation of Elk Grove Village, IL; Colordyne Technologies, LLC of Brookfield, WI; Formax Technologies, Inc. of Dover, NH; Neopost USA, Inc. (d/b/a Neopost Northwest, Neopost Northeast, Neopost Priority Systems, and/or Neopost Southeast) of Milford, CT; Printware LLC of Eagan, MN; VIPColor Technologies USA, Inc. of Newark, CA; ABC Office (d/b/a Brent Barlow) of Kaysville, UT; All for Mailers, Inc. of Feasterville, PA; Fernqvist Labeling Solutions, Inc. of Mountain View, CA; Information Management Services LLC (d/b/a MyBinding.com) of Hillsboro, OR; JMP Business Systems, Inc. of Clovis, CA; Mono Machines LLC of New York, NY; Ordway Corporation (d/b/a Print & Finishing Solutions) of Placentia, CA; Pacific Barcode Inc. of Temecula, CA; Pacific Code & Label, Inc. of Portland, OR; Parts Now! LLC of Madison, WI; Trademark Copysystems Inc. (d/b/a Addrex—Addresser Sales Company of Cleveland, OH; and Vivid Data Group LLC of Dallas, TX. The complainant requests that the Commission issue a general exclusion order, issue a limited exclusion order, cease and desist orders and impose a bond upon respondents' alleged infringing articles during the 60-day Presidential review period pursuant to 19 U.S.C. § 1337(j).
Proposed respondents, other interested parties, and members of the public are invited to file comments, not to exceed five (5) pages in length, inclusive of attachments, on any public interest issues raised by the complaint or section 210.8(b) filing. Comments should address whether issuance of the relief specifically requested by the complainant in this investigation would affect the public health and welfare in the United States, competitive conditions in the United States economy, the production of like or directly competitive articles in the United States, or United States consumers.
In particular, the Commission is interested in comments that:
(i) explain how the articles potentially subject to the requested remedial orders are used in the United States;
(ii) identify any public health, safety, or welfare concerns in the United States relating to the requested remedial orders;
(iii) identify like or directly competitive articles that complainant, its licensees, or third parties make in the United States which could replace the subject articles if they were to be excluded;
(iv) indicate whether complainant, complainant's licensees, and/or third party suppliers have the capacity to replace the volume of articles potentially subject to the requested exclusion order and/or a cease and desist order within a commercially reasonable time; and
(v) explain how the requested remedial orders would impact United States consumers.
Written submissions must be filed no later than by close of business, eight calendar days after the date of publication of this notice in the Federal Register . There will be further opportunities for comment on the public interest after the issuance of any final initial determination in this investigation.
Persons filing written submissions must file the original document electronically on or before the deadlines stated above and submit 8 true paper copies to the Office of the Secretary by noon the next day pursuant to section 210.4(f) of the Commission's Rules of Practice and Procedure (19 CFR § 210.4(f)). Submissions should refer to the docket number (“Docket No. 3154”) in a prominent place on the cover page and/or the first page. ( See Handbook for Electronic Filing Procedures, Electronic Filing Procedures ^4 ). Persons with questions regarding filing should contact the Secretary (202-205-2000).
^4 Handbook for Electronic Filing Procedures: http://www.usitc.gov/secretary/fed_reg_notices/rules/handbook_on_electronic_filing.pdf.
Any person desiring to submit a document to the Commission in confidence must request confidential treatment. All such requests should be directed to the Secretary to the Commission and must include a full statement of the reasons why the Commission should grant such treatment. See 19 CFR § 201.6. Documents for which confidential treatment by the Commission is properly sought will be treated accordingly. All nonconfidential written submissions will be available for public inspection at the Office of the Secretary and on EDIS. ^5
^5 Electronic Document Information System (EDIS): http://edis.usitc.gov
This action is taken under the authority of section 337 of the Tariff Act of 1930, as amended (19 U.S.C. § 1337), and of sections 201.10 and 210.8(c) of the Commission's Rules of Practice and Procedure (19 CFR §§ 201.10, 210.8(c)).
By order of the Commission.
Issued: May 27, 2016.
Lisa R. Barton,

Secretary to the Commission.
DEPARTMENT OF LABOR
Office of the Secretary
Agency Information Collection Activities; Submission for OMB Review; Comment Request; Standard on 4,4'-Methylenedianiline for General Industry

ACTION:
Notice.

SUMMARY:
The Department of Labor (DOL) is submitting the Occupational Safety and Health Administration (OSHA) sponsored information collection request (ICR) titled, “Standard on 4,4'-Methylenedianiline for General Industry,” to the Office of Management and Budget (OMB) for review and approval for continued use, without change, in accordance with the Paperwork Reduction Act of 1995 (PRA), 44 U.S.C. 3501 et seq. Public comments on the ICR are invited.

DATES:
The OMB will consider all written comments that agency receives on or before July 5, 2016.

ADDRESSES:
A copy of this ICR with applicable supporting documentation; including a description of the likely respondents, proposed frequency of response, and estimated total burden may be obtained free of charge from the RegInfo.gov Web site at http://www.reginfo.gov/public/do/PRAViewICR?ref_nbr=201604-1218-004 (this link will only become active on the day following publication of this notice) or by contacting Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at DOL_PRA_PUBLIC@dol.gov.
Submit comments about this request by mail or courier to the Office of Information and Regulatory Affairs, Attn: OMB Desk Officer for DOL-OSHA, Office of Management and Budget, Room 10235, 725 17th Street NW., Washington, DC 20503; by Fax: 202-395-5806 (this is not a toll-free number); or by email: OIRA_submission@omb.eop.gov. Commenters are encouraged, but not required, to send a courtesy copy of any comments by mail or courier to the U.S. Department of Labor-OASAM, Office of the Chief Information Officer, Attn: Departmental Information Compliance Management Program, Room N1301, 200 Constitution Avenue NW., Washington, DC 20210; or by email: DOL_PRA_PUBLIC@dol.gov.

FOR FURTHER INFORMATION CONTACT:
Contact Michel Smyth by telephone at 202-693-4129, TTY 202-693-8064, (these are not toll-free numbers) or by email at DOL_PRA_PUBLIC@dol.gov.

Authority:
44 U.S.C. 3507(a)(1)(D).

SUPPLEMENTARY INFORMATION:
This ICR seeks to extend PRA authority for the Standard on 4,4'-Methylenedianiline (MDA) for General Industry information collection requirements codified in regulations 29 CFR 1910-1050. The Standard protects workers from adverse health effects associated with occupational exposure to MDA in general industry. An Occupational Safety and Health Act (OSH Act) covered employer subject to the Standard must monitor worker exposure, ensure worker exposure is within permissible limits, provide workers with medical examinations and training, and establish and maintain worker exposure-monitoring and medical records. OSH Act sections 2(b)(9), 6, and 8(c) authorize this information collection. See 29 U.S.C. 651(b)(9), 655, and 657.
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 it is approved by the OMB under the PRA 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 Control Number. See 5 CFR 1320.5(a) and 1320.6. The DOL obtains OMB approval for this information collection under Control Number 1218-0184.
OMB authorization for an ICR cannot be for more than three (3) years without renewal, and the current approval for this collection is scheduled to expire on June 30, 2016. The DOL seeks to extend PRA authorization for this information collection for three (3) more years, without any change to existing requirements. The DOL notes that existing information collection requirements submitted to the OMB receive a month-to-month extension while they undergo review. For additional substantive information about this ICR, see the related notice published in the Federal Register on March 11, 2016 (81 FR 12966).
Interested parties are encouraged to send comments to the OMB, Office of Information and Regulatory Affairs at the address shown in the ADDRESSES section within thirty (30) days of publication of this notice in the Federal Register . In order to help ensure appropriate consideration, comments should mention OMB Control Number 1218-0184. The OMB 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
• 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.
Agency: DOL-OSHA.
Title of Collection: Standard on 4,4'-Methylenedianiline for General Industry.
OMB Control Number: 1218-0184.
Affected Public: Private Sector—businesses or other for-profits.
Total Estimated Number of Respondents: 10.
Total Estimated Number of Responses: 574.
Total Estimated Annual Time Burden: 334 hours.
Total Estimated Annual Other Costs Burden: $24,180.
Dated: May 27, 2016.
Michel Smyth,

Departmental Clearance Officer.
NATIONAL SCIENCE FOUNDATION
Notice of Intent To Request New Information Collection

AGENCY:
National Science Foundation.

ACTION:
Notice and request for comments.

SUMMARY:
The National Science Foundation (NSF) is announcing plans to request renewal of the Early Career Doctorates Survey (OMB Control Number 3145-0235). In accordance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, (Pub. L. 104-13), we are providing opportunity for public comment on this action. After obtaining and considering public comment, NSF will prepare the submission requesting that OMB approve clearance of this collection for three years.
Comments: Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the NSF, 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 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.

DATES:
Written comments on this notice must be received by August 2, 2016, to be assured consideration. Comments received after that date will be considered to the extent practicable. Send comments to address below.
For Additional Information or Comments: Contact Suzanne H. Plimpton, the NSF Reports Clearance Officer, National Science Foundation, 4201 Wilson Boulevard, Suite 295, Arlington, Virginia 22230; telephone (703) 292-7556; or send email to splimpto@nsf.gov. Individuals who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1- 800-877-8339, which is accessible 24 hours a day, 7 days a week, 365 days a year (including Federal holidays).

SUPPLEMENTARY INFORMATION:
Title of Collection: Early Career Doctorates Survey.
OMB Approval Number: 3145-0235.
Expiration Date: June 30, 2017.
Type of Request: Intent to seek approval to extend an information collection for three years.
Abstract: Established within the NSF by the America COMPETES Reauthorization Act of 2010 § 505, codified in the National Science Foundation Act of 1950, as amended, the National Center for Science and Engineering Statistics (NCSES) serves as a central Federal clearinghouse for the collection, interpretation, analysis, and dissemination of objective data on science, engineering, technology, and research and development for use by practitioners, researchers, policymakers, and the public. The Early Career Doctorates Survey (ECDS) will become part of an integrated survey system that meets the human resources statistics part of this mission.
The Early Career Doctorates Project was established to gather in-depth information about early career doctorates (ECDs), including postdoctoral researchers (postdocs). Early career doctorates are critical to the success of the U.S. scientific enterprise and will influence U.S. and global scientific markets for years to come. Despite their importance, current surveys of this population are limited, and extant workforce studies are insufficient for all doctorates who contribute to the U.S. economy. The NSF's Survey of Earned Doctorates and the Survey of Doctorate Recipients are limited to individuals who received research doctorates from U.S. academic institutions, thereby excluding individuals who earned professional doctorates and those who earned doctorates from institutions outside the United States but are currently employed in the United States. The NSF's Survey of Graduate Students and Postdoctorates in Science and Engineering (GSS) provides aggregate level data for all postdocs and nonfaculty researchers regardless of where they earned the degree. However, the GSS is limited to science, engineering, and selected health (SEH) fields in U.S. academic institutions and their related research facilities and is collected at the program rather than the individual level.
Through its multi-year Postdoc Data Project, NCSES determined the need for and the feasibility of gathering information about postdocs working in the United States. However, efforts to reliably identify and gather information about postdocs proved difficult due to substantial variation in how institutions characterize postdoc appointments. As a result, NCSES expanded the target population to include all individuals who earned their first doctorate within the past 10-years. Expanding the population to doctoral degree holders ensures a larger, more consistent and reliable target population. Unique in scope, the key goals of the ECD Project are:
• To broaden the scope and depth of national statistics on the ECD population both U.S. degreed and non-U.S. degreed, across employment sectors and fields of discipline
• To collect nationally representative data from ECDs that can be used by funding agencies, policy makers, and other researchers to better understand the labor market and work experiences of recent doctorate recipients
• To gather the diverse definitions for ECDs to allow for analysis within and across employment sectors
The current focus of the ECD Project is to conduct a survey of ECDs working in three areas of employment: U.S. academic institutions in the GSS, Federally Funded Research and Development Centers, and the National Institutes of Health Intramural Research Programs. NCSES, under full clearance (OMB #3145-0235), has conducted a pilot survey with data collection period spanning July 2014 to March 2015. The Pilot ECDS data will be released in 2016.
Beginning in November 2016, NSF will request lists of ECDs from approximately 390 institutions nationwide, and sample 24,000 individuals from these lists. Sample members will be invited to participate in a 40-minute web-based questionnaire. The survey topics cover: Educational achievement, professional activities, employer demographics, professional and personal life balance, mentoring, training and research opportunities, and career paths and plans. Participation in the survey is voluntary.
The survey will be collected in conformance with the Privacy Act of 1974 and the Confidential Information Protection and Statistical Efficiency Act (CIPSEA). The NSF will ensure that all individually identifiable information collected will be kept strictly confidential and will be used for research or statistical purposes.
Use of the Information: The NSF will publish statistics from the survey in several reports, including the National Science Board's Science and Engineering Indicators and NCSES's Women, Minorities, and Persons with Disabilities in Science and Engineering. These reports will be made available electronically on the NSF Web site. Restricted-use and public use data files will also be developed, and will be made available to interested researchers from government, professional associations, and other organizations. Restricted-use data may be obtained under a license agreement.
Expected Respondents: There are four groups who contribute to the estimated total burden hours of the ECDS data collection. Three groups assist in the development of an accurate list of ECDs: Institutional high authority (HA), communication coordinator (CC), and list coordinator (LC). The fourth group is the individual early career doctorate (ECD). At the first stage of sampling, the ECDS will select 390 institutions. At each institution, a high authority (HA) will authorize the institution's participation in the study, designate a list coordinator (LC) and a communication coordinator (CC), and provide a letter of support for the survey. The primary responsibility of the LC is to prepare a list of ECD working at the institution. The LC will provide a list of all ECD, that is, individuals working at their institution who earned their first doctorate or doctorate-equivalent degree within the past 10 years, including postdocs, nonfaculty researchers, tenured or tenure-track faculty members. The primary responsibility of the CC is to coordinate all communications at the institution. In the second stage, the HA, with the help of the CC, will notify the sampled individuals of their selection and NSF will survey these individuals.
Estimate of Burden: In the Pilot ECDS, HAs required 30 minutes on average to complete their tasks while CCs required 90 minutes on average to complete their tasks. We estimate a maximum total burden of 195 hours for HAs and 585 hours for CCs across both stages of data collection. LCs in participating institutions required an average of 8 hours to fulfill their duties during the Pilot ECDS. We estimate the maximum total LC burden to be 3,120 hours during stage 1. NCSES estimates that respondents will take 40 minutes on average to complete the questionnaire based on the time to completion data from the Pilot ECDS. We estimate the maximum total ECD burden to be 16,000 hours.
Taking into account all four groups (HA, CC, LC, and ECD), we estimate the maximum total respondent burden to be 19,900 hours. The below table shows the estimated burden by stage and respondent type.
ECDS Estimated Burden by Stage and Respondent Type
Respondent type | Sample members | Minutes per respondent | Estimated total burden hours
Stage 1: Frame Creation:
High Authority (HA) | 390 | 20 | 130
Communication Coordinator (CC) | 390 | 60 | 390
List Coordinator (LC) | 390 | 480 | 3,120
Subtotal | | | 3,640
Stage 2: Individual Survey:
High Authority (HA) | 390 | 10 | 65
Communication Coordinator (CC) | 390 | 30 | 195
Early Career Doctorate (ECD) | 24,000 | 40 | 16,000
Subtotal | | | 16,260
Total ^1 | - | - | 19,900
^1 This is an initial estimated burden hours which is based on preliminary sample design. NCSES anticipates the final burden hours to be at or below this initial estimate.
Dated: May 27, 2016.
Suzanne H. Plimpton,

Reports Clearance Officer, National Science Foundation.
POSTAL REGULATORY COMMISSION
[Docket No. CP2016-186; Order No. 3332]
New Postal Product

AGENCY:
Postal Regulatory Commission.

ACTION:
Notice.

SUMMARY:
The Commission is noticing a recent Postal Service filing concerning an additional Global Expedited Package Services 3 negotiated service agreement. This notice informs the public of the filing, invites public comment, and takes other administrative steps.

DATES:
Comments are due: June 7, 2016.

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. Notice of Commission Action
III. Ordering Paragraphs

I. Introduction
On May 27, 2016, the Postal Service filed notice that it has entered into an additional Global Expedited Package Services 3 (GEPS 3) negotiated service agreement (Agreement). ^1
^1 Notice of United States Postal Service of Filing a Functionally Equivalent Global Expedited Package Services 3 Negotiated Service Agreement and Application for Non-Public Treatment of Materials Filed Under Seal, May 27, 2016 (Notice).
To support its Notice, the Postal Service filed a copy of the Agreement, a copy of the Governors' Decision authorizing the product, a certification of compliance with 39 U.S.C. 3633(a), and an application for non-public treatment of certain materials. It also filed supporting financial workpapers.

II. Notice of Commission Action
The Commission establishes Docket No. CP2016-186 for consideration of matters raised by the Notice.
The Commission invites comments on whether the Postal Service's filing is consistent with 39 U.S.C. 3632, 3633, or 3642, 39 CFR part 3015, and 39 CFR part 3020, subpart B. Comments are due no later than June 7, 2016. The public portions of the filing can be accessed via the Commission's Web site ( http://www.prc.gov ).
The Commission appoints Katalin K. Clendenin to serve as Public Representative in this docket.

III. Ordering Paragraphs
It is ordered:
1. The Commission establishes Docket No. CP2016-186 for consideration of the matters raised by the Postal Service's Notice.
2. Pursuant to 39 U.S.C. 505, Katalin K. Clendenin is appointed to serve as an officer of the Commission to represent the interests of the general public in this proceeding (Public Representative).
3. Comments are due no later than June 7, 2016.
4. The Secretary shall arrange for publication of this order in the Federal Register .
By the Commission.
Stacy L. Ruble,

Secretary.
POSTAL REGULATORY COMMISSION
[Docket No. CP2016-187; Order No. 3333]
New Postal Product

AGENCY:
Postal Regulatory Commission.

ACTION:
Notice.

SUMMARY:
The Commission is noticing a recent Postal Service filing concerning notice to enter into a Priority Mail International Regional Rate Boxes Contract 1 negotiated service agreement. This notice informs the public of the filing, invites public comment, and takes other administrative steps.

DATES:
Comments are due: June 7, 2016.

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. Notice of Commission Action
III. Ordering Paragraphs

I. Introduction
On May 27, 2016, the Postal Service filed notice that it has entered into a Priority Mail International Regional Rate Boxes Contract 1 negotiated service agreement (Agreement). ^1
^1 Notice of United States Postal Service of Filing a Functionally Equivalent Priority Mail International Regional Rate Boxes 1 Negotiated Service Agreement and Application for Non-Public Treatment of Materials Filed Under Seal, May 27, 2016 (Notice).
To support its Notice, the Postal Service filed a copy of the Agreement, a copy of the Governors' Decision authorizing the product, a certification of compliance with 39 U.S.C. 3633(a), and an application for non-public treatment of certain materials. It also filed supporting financial workpapers.

II. Notice of Commission Action
The Commission establishes Docket No. CP2016-187 for consideration of matters raised by the Notice.
The Commission invites comments on whether the Postal Service's filing is consistent with 39 U.S.C. 3632, 3633, or 3642, 39 CFR part 3015, and 39 CFR part 3020, subpart B. Comments are due no later than June 7, 2016. The public portions of the filing can be accessed via the Commission's Web site ( http://www.prc.gov ).
The Commission appoints Katalin K. Clendenin to serve as Public Representative in this docket.

III. Ordering Paragraphs
It is ordered:
1. The Commission establishes Docket No. CP2016-187 for consideration of the matters raised by the Postal Service's Notice.
2. Pursuant to 39 U.S.C. 505, Katalin K. Clendenin is appointed to serve as an officer of the Commission to represent the interests of the general public in this proceeding (Public Representative).
3. Comments are due no later than June 7, 2016.
4. The Secretary shall arrange for publication of this order in the Federal Register .
By the Commission.
Stacy L. Ruble,

Secretary.
POSTAL SERVICE
Product Change—Priority Mail Negotiated Service Agreement

AGENCY:
Postal Service TM .

ACTION:
Notice.

SUMMARY:
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.

DATES:
Effective date: June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Elizabeth A. Reed, 202-268-3179.

SUPPLEMENTARY INFORMATION:
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on May 26, 2016, it filed with the Postal Regulatory Commission a Request of the United States Postal Service to Add Priority Mail Contract 223 to Competitive Product List. Documents are available at www.prc.gov, Docket Nos. MC2016-146, CP2016-183.
Stanley F. Mires,

Attorney, Federal Compliance.
POSTAL SERVICE
Product Change—First-Class Package Service Negotiated Service Agreement

AGENCY:
Postal Service TM .

ACTION:
Notice.

SUMMARY:
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.

DATES:
Effective date: June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Elizabeth A. Reed, 202-268-3179.

SUPPLEMENTARY INFORMATION:
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on May 26, 2016, it filed with the Postal Regulatory Commission a Request of the United States Postal Service to Add First-Class Package Service Contract 55 to Competitive Product List. Documents are available at www.prc.gov, Docket Nos. MC2016-148, CP2016-185.
Stanley F. Mires,

Attorney, Federal Compliance.
POSTAL SERVICE
Product Change—Parcel Select Negotiated Service Agreement

AGENCY:
Postal Service TM .

ACTION:
Notice.

SUMMARY:
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.

DATES:
Effective date: June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Elizabeth A. Reed, 202-268-3179.

SUPPLEMENTARY INFORMATION:
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on May 26, 2016, it filed with the Postal Regulatory Commission a Request of the United States Postal Service to Add Parcel Select Contract 16 to Competitive Product List. Documents are available at www.prc.gov, Docket Nos. MC2016-147, CP2016-184.
Stanley F. Mires,

Attorney, Federal Compliance.
POSTAL SERVICE
Product Change—Priority Mail Negotiated Service Agreement

AGENCY:
Postal Service TM .

ACTION:
Notice.

SUMMARY:
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.

DATES:
Effective date: June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Elizabeth A. Reed, 202-268-3179.

SUPPLEMENTARY INFORMATION:
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on May 26, 2016, it filed with the Postal Regulatory Commission a Request of the United States Postal Service to Add Priority Mail Contract 221 to Competitive Product List. Documents are available at www.prc.gov, Docket Nos. MC2016-144, CP2016-181.
Stanley F. Mires,

Attorney, Federal Compliance.
POSTAL SERVICE
Product Change—Priority Mail Negotiated Service Agreement

AGENCY:
Postal Service TM .

ACTION:
Notice.

SUMMARY:
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.

DATES:
Effective date: June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Elizabeth A. Reed, 202-268-3179.

SUPPLEMENTARY INFORMATION:
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on May 26, 2016, it filed with the Postal Regulatory Commission a Request of the United States Postal Service to Add Priority Mail Contract 222 to Competitive Product List. Documents are available at www.prc.gov, Docket Nos. MC2016-145, CP2016-182.
Stanley F. Mires,

Attorney, Federal Compliance.
POSTAL SERVICE
Product Change—Priority Mail Negotiated Service Agreement

AGENCY:
Postal Service TM .

ACTION:
Notice.

SUMMARY:
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.

DATES:
Effective date: June 3, 2016.

FOR FURTHER INFORMATION CONTACT:
Elizabeth A. Reed, 202-268-3179.

SUPPLEMENTARY INFORMATION:
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on May 26, 2016, it filed with the Postal Regulatory Commission a Request of the United States Postal Service to Add Priority Mail Contract 220 to Competitive Product List. Documents are available at www.prc.gov, Docket Nos. MC2016-143, CP2016-180.
Stanley F. Mires,

Attorney, Federal Compliance.
SECURITIES AND EXCHANGE COMMISSION
Sunshine Act Meeting
Notice is hereby given, pursuant to the provisions of the Government in the Sunshine Act, Public Law 94-409, that the Securities and Exchange Commission Investor Advisory Committee will hold a telephonic meeting on Tuesday, June 7, 2016. The meeting will begin at 11:00 a.m. (ET) and conclude at 12:30 p.m. and will be open to the public via telephone at 1-888-240-3210, participant code 7250901.
On May 19, 2016, the Commission issued notice of the Committee meeting (Release No. 33-10079), indicating that the meeting is open to the public, and inviting the public to submit written comments to the Committee. This Sunshine Act notice is being issued because a quorum of the Commission may attend the meeting.
The agenda for the meeting includes: A discussion of Market Structure subcommittee recommendations to enhance information for bond market investors; and a discussion regarding the Commission's concept release on business and financial disclosure required by Regulation S-K (which may include a recommendation of the Investor as Owner subcommittee).
For further information, please contact the Office of the Secretary at (202) 551-5400.
Dated: May 31, 2016.
Brent J. Fields,

Secretary.
DEPARTMENT OF STATE
[Public Notice 9596]
U.S. Department of State Advisory Committee on Private International Law: Public Meeting on Online Dispute Resolution
The Office of the Assistant Legal Adviser for Private International Law, Department of State, hereby gives notice that the Online Dispute Resolution (ODR) Study Group of the Advisory Committee on Private International Law (ACPIL) will hold a public meeting. The ACPIL ODR Study Group will meet to discuss the draft instrument entitled “Technical Notes on Online Dispute Resolution” which has been submitted to the UN Commission on International Trade Law (UNCITRAL) for consideration at its 2016 plenary session (June 27-July 15, 2016). This is not a meeting of the full Advisory Committee.
At the July 2015 plenary session of UNCITRAL, the ODR Working Group was instructed to prepare a non-binding descriptive document reflecting elements of an ODR process, on which elements the Working Group had previously reached consensus, and excluding the question of the final stage of the ODR process (arbitration/nonarbitration). Report of the United Nations Commission on International Trade Law, 48th Session (29 June-16 July 2015), A/70/17, para. 352. The Working Group based its deliberations on a proposal for Technical Notes on Online Dispute Resolution submitted by Colombia and the United States. A/CN.9/WG.III/XXXII/CRP.3. The proposal by Colombia and the United States, as well as the reports of the Working Group are available at the following link: http://www.uncitral.org/uncitral/commission/working__groups/3Online_Dispute_Resolution.html. The draft Technical Notes on Online Dispute Resolution are available at http://undocs.org/A/CN.9/888.
Time and Place: The meeting of the ACPIL ODR Study Group will take place on Thursday June 16 from 10 a.m. to 12 noon EST at 2430 E Street NW., South Building (SA 4S) State Department Annex 4A (Navy Hill), Room 356. Participants should arrive at Navy Hill before 9:45 a.m. for visitor screening. Participants will be met at the Navy Hill gate at 23rd and D Streets NW., for visitor screening and will be escorted to the South Building. Persons arriving later will need to make arrangements for entry using the contact information provided below. If you are unable to attend the public meeting and would like to participate from a remote location, teleconferencing will be available.
Public Participation: This meeting is open to the public, subject to the capacity of the meeting room. Access to the building is strictly controlled. For pre-clearance purposes, those planning to attend should email pil@state.gov providing full name, address, date of birth, citizenship, driver's license or passport number, and email address. This information will greatly facilitate entry into the building. A member of the public needing reasonable accommodation should email pil@state.gov not later than June 10th. Requests made after that date will be considered, but might not be able to be fulfilled. If you would like to participate by telephone, please email pil@state.gov to obtain the call-in number and other information.
Data from the public is requested pursuant to Public Law 99-399 (Omnibus Diplomatic Security and Antiterrorism Act of 1986), as amended; Public Law 107-56 (USA PATRIOT Act); and E.O. 13356. The purpose of the collection is to validate the identity of individuals who enter Department facilities.
The data will be entered into the Visitor Access Control System (VACS-D) database. Please see the Security Records System of Records Notice (State-36) at https://foia.state.gov/_docs/SORN/State-36.pdf for additional information.
Dated: May 25, 2016.
Michael J. Dennis,

Attorney-Adviser, Office of Private International Law, Office of the Legal Adviser, U.S. Department of State.
SURFACE TRANSPORTATION BOARD
[Docket No. FD 36002]
WRL, LLC—Modified Rail Certificate of Public Convenience and Necessity—Adams and Grant Counties, Wash.
WRL, LLC (WRL), a noncarrier, filed a notice for a modified certificate of public convenience and necessity under 49 CFR Part 1150 subpart C— Modified Certificate of Public Convenience and Necessity, to lease and operate a line of railroad (the Line) owned by the Port of Royal Slope (Port), a Washington State municipal corporation. The total distance of the Line is approximately 26 miles: (1) Originating at milepost 1989.06, near Othello, Adams County, Wash., and continuing west for 20.44 miles to milepost 2009, at Royal City Junction, Grant County, Wash.; and then (2) proceeding north a distance of 5.2 miles, terminating at an industrial siding at milepost 5.2 near Royal City, Grant County, Wash. ^1
^1 This proceeding is related to Paul Didelius—Continuance in Control Exemption—WRL, LLC, Docket No. FD 36003, in which Paul Didelius filed an exemption to continue in control of WRL upon WRL's becoming a Class III rail carrier. Notice of the continuance in control exemption was served and published in the Federal Register on May 20, 2016 (81 FR 32,004).
WRL states that the Line was authorized for abandonment by a decision of the Interstate Commerce Commission in Docket No. AB 7 (Sub-No. 86) served on January 30, 1980, though the abandonment of the Line was never consummated. WRL states that the Line was acquired by the Port in 1982, “came under the control” of Sunfresh, Inc., in 1992, ^2 was purchased by the Washington State Department of Transportation in 1993, and was reacquired by the Port in 2015.
^2 According to WRL, Sunfresh, Inc., was the guarantor of a Federal Railroad Administration loan upon which the Port defaulted in 1992.
Pursuant to an Operating Lease Agreement, WRL, as lessee, and the Port, as owner, have agreed that WRL will commence freight rail operation upon this exemption taking effect on or after June 5, 2016, for an initial term of five years, which may be extended upon the agreement of both parties for additional five-year terms. WRL states that the Line's only interline connection is with Columbia Basin Railroad (CBRW) at milepost 1989.06 in Othello, Wash. WRL states that it expects to enter into an agreement with CBRW imposing no interchange commitments.
The Line qualifies for a modified certificate of public convenience and necessity. See Common Carrier Status of States, State Agencies & Instrumentalities & Political Subdivisions, FD 28990F (ICC served July 16, 1981) and 49 CFR 1150.22.
WRL states that no subsidy is involved and that there are no preconditions for shippers to meet in order to receive rail service. WRL also states that Operating Lease Agreement requires it to obtain property and liability insurance coverage.
This notice will be served on the Association of American Railroads (Car Service Division), as agent for all railroads subscribing to the car-service and car-hire agreement, at 425 Third Street SW., Suite 1000, Washington, DC 20024; and on the American Short Line and Regional Railroad Association at 50 F Street NW., Suite 7020, Washington, DC 20001.
Board decisions and notices are available on our Web site at WWW.STB.DOT.GOV.
Decided: May 31, 2016.
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Brendetta S. Jones,

Clearance Clerk.
SURFACE TRANSPORTATION BOARD
60-Day Notice of Intent to Seek Extension of Approval: Household Goods Movers' Disclosure Requirements

ACTION:
Notice and request for comments.

AGENCY:
Surface Transportation Board.

SUMMARY:
As required by the Paperwork Reduction Act of 1995, 44 U.S.C. 3501-3521 (PRA), the Surface Transportation Board (STB or Board) gives notice of its intent to seek approval from the Office of Management and Budget (OMB) for an extension of the information collections (here, third-party disclosures) required by the Board's decisions in Released Rates of Motor Common Carriers of Household Goods, RR 999 (Amendment No. 5) (STB served Jan. 21, 2011); Released Rates of Motor Common Carriers of Household Goods, RR 999 (Amendment No. 5) (STB served Jan.10, 2012).
Congress, in the Safe, Accountable, Flexible, Efficient Transportation Equity Act: A Legacy for Users, section 4215, Public Law 109-59, 119 Stat. 1144, 1760 (2005), directed the Board to review consumer protection regulations concerning the loss or damage that occurs during interstate household goods moves. In Docket No. RR 999, the Board required household goods motor carriers and freight forwarders (together, Movers) to provide their customers with clear written information concerning the two available cargo-liability options, if they desired to offer a rate limiting their liability on interstate moves to anything less than replacement value of the goods. Movers were required to provide this information on the standard written estimate form, which the Federal Motor Carrier Safety Administration (FMCSA) already required Movers to provide to their household goods moving customers. See 49 CFR 375.213(c).

DATES:
Comments on this information collection should be submitted by August 2, 2016.

ADDRESSES:
Direct all comments to Chris Oehrle, Surface Transportation Board, 395 E Street SW., Washington, DC 20423-0001, or to PRA@stb.dot.gov. When submitting comments, please refer to “Paperwork Reduction Act Comments, Household Goods Movers' Disclosure Requirements.” For further information regarding this collection, contact Michael Higgins at (202) 245-0284 or at michael.higgins@stb.dot.gov. [Assistance for the hearing impaired is available through the Federal Information Relay Service (FIRS) at 1-800-877-8339.]

SUPPLEMENTARY INFORMATION:
Under the PRA, a federal agency that conducts or sponsors a collection of information must display a currently valid OMB control number. A collection of information, which is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c), includes agency requirements that persons submit reports, keep records, or provide information to the agency, third parties, or the public. Under 44 U.S.C. 3506(c)(2)(A), federal agencies are required to provide, prior to an agency's submitting a collection to OMB for approval, a 60-day notice and comment period through publication in the Federal Register concerning each proposed collection of information, including each proposed extension of an existing collection of information.
Comments are requested concerning: (1) The accuracy of the Board's burden estimates; (2) ways to enhance the quality, utility, and clarity of the information collected; (3) ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology, when appropriate; and (4) whether the collection of information is necessary for the proper performance of the functions of the Board, including whether the collection has practical utility. Submitted comments will be summarized and included in the Board's request for OMB approval.

Description of Collections
Title: Household Goods Movers' Disclosure Requirements.
OMB Control Number: 2140-0027.
STB Form Number: None.
Type of Review: Extension with change.
Respondents: Movers that desire to offer a rate limiting their liability on interstate moves to anything less than replacement value of the goods.
Number of Respondents: 7,000 (approximate number of Movers involved in authorized for-hire household goods carriage in the United States according to American Moving and Storage Association).
Frequency: Occasionally.
Total Burden Hours: None. The change to the estimate form was a one-time, start-up cost, which was considered in the cost analysis of the Board's previous approval for this collection. Therefore, there is no longer an hourly burden.
Total “Non-hour Burden” Cost: None. Movers may provide these forms to shippers electronically. Further, as with the burden hours above, the one-time, start-up costs that were previously considered no longer apply. Therefore, there is no non-hourly burden to respondents.
Needs and Uses: Moving companies must inform consumers of their rights and obtain a signed waiver if the consumer elects anything other than full-value protection. See Released Rates of Motor Common Carriers of Household Goods, RR 999 (Amendment No. 4) (STB served June 13, 2007). Previously, consumers were sometimes confused and did not realize that they had waived full-value protection until after they had experienced damage to or loss of their goods. The information collection that is the subject of this notice is intended to correct this problem by providing early notice regarding the two liability options (full-value protection and the lower released-rate protection), as well as adequate time and information to help consumers decide which option to choose.
Dated: May 26, 2016.
Brendetta S. Jones,

Clearance Clerk.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
[Summary Notice No. 2016-70]
Petition for Exemption; Summary of Petition Received; Falcon Skydiving Team

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Notice.

SUMMARY:
This notice contains a summary of a petition seeking relief from specified requirements of Title 14 of the Code of Federal Regulations. The purpose of this notice is to improve the public's awareness of, and participation in, the FAA's exemption process. Neither publication of this notice nor the inclusion or omission of information in the summary is intended to affect the legal status of the petition or its final disposition.

DATES:
Comments on this petition must identify the petition docket number and must be received on or before June 23, 2016.

ADDRESSES:
Send comments identified by docket number FAA-2016-6374 using any of the following methods:
• Federal eRulemaking Portal: Go to http://www.regulations.gov and follow the online instructions for sending your comments electronically.
• Mail: Send comments to Docket Operations, M-30; U.S. Department of Transportation (DOT), 1200 New Jersey Avenue SE., Room W12-140, West Building Ground Floor, Washington, DC 20590-0001.
• Hand Delivery or Courier: Take comments to Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
• Fax: Fax comments to Docket Operations at 202-493-2251.
Privacy: In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to http://www.regulations.gov, as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at http://www.dot.gov/privacy.
Docket: Background documents or comments received may be read at http://www.regulations.gov at any time. Follow the online instructions for accessing the docket or go to the Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

FOR FURTHER INFORMATION CONTACT:
Alphonso Pendergrass, Federal Aviation Administration, 800 Independence Ave. SW., Washington DC 20591. Email Alphonso.pendergrass@faa.gov, phone (202) 267-4713.
This notice is published pursuant to 14 CFR 11.85.
Issued in Washington, DC, on May 24, 2016.
Lirio Liu,

Director, Office of Rulemaking.

Petition for Exemption
Docket No.: FAA-2016-6374
Petitioner: Falcon Skydiving Team
Section(s) of 14 CFR Affected: § 65.115 and 105.45(b)(1)
Description of Relief Sought: Falcon Skydiving Team (FST) request an exemption to permit FST to train “non-certificated person(s)” to pack main parachutes of tandem parachute systems and main parachutes of sport parachute systems without the direct supervision of a certificated parachute rigger.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
Public Notice For Waiver for Aeronautical Land-Use Assurance at Pleasanton Municipal Airport, Pleasanton, TX

AGENCY:
Federal Aviation Administration, DOT.

ACTION:
Notice of intent for waiver of aeronautical land-use.

SUMMARY:
The Federal Aviation Administration (FAA) is considering a proposal to change a portion of the airport from aeronautical use to nonaeronautical use and to authorize the conversion of the airport property. The proposal consists of one parcel of land containing a total of approximately 1.6 acres to be used for a fire station. Additionally, the change-in-use of 0.19 acres from aeronautical to non-aeronautical use, approved in 1999 for a fire station that was never constructed, will now revert back to aeronautical use.
The property was acquired in 1973 by grant funds. The land comprising this parcel is outside the forecasted need for aviation development and, thus, is no longer needed for indirect or direct aeronautical use. The airport wishes to develop this land for a fire station. The income from the conversion of this parcel will benefit the aviation community by reinvestment in the airport.
Approval does not constitute a commitment by the FAA to financially assist in the conversion of the subject airport property nor a determination of eligibility for grant-in-aid funding from the FAA. The disposition of proceeds from the conversion of the airport property will be in accordance with FAA's Policy and Procedures Concerning the Use of Airport Revenue, published in the Federal Register on February 16, 1999. In accordance with Section 47107(h) of Title 49, United States Code, this notice is required to be published in the Federal Register 30 days before modifying the land-use assurance that requires the property to be used for an aeronautical purpose.

DATES:
Comments must be received on or before July 5, 2016.

ADDRESSES:
Send comments on this document to Mr. Cameron Bryan, Federal Aviation Administration, Acting Manager, Texas Airports Development Office, 10101 Hillwood Parkway, Fort Worth, TX 76177.

FOR FURTHER INFORMATION CONTACT:
Mr. Bruce Pearson, City Manager, City of Pleasanton, P.O. Box 209 Pleasanton, TX 78064, telephone (830) 569-3867, or Mr. Anthony Mekhail, Federal Aviation Administration, Texas Airports Development Program Manager, 10101 Hillwood Parkway, Fort Worth, TX 76177, telephone (817) 222-5663, FAX (817) 222-5989. Documents reflecting this FAA action may be reviewed at the above locations.
Issued in Fort Worth, Texas on May 26, 2016.
Ignacio Flores,

Manager, Airports Division, FAA, Southwest Region.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
Public Notice For Waiver of Aeronautical Land-Use Assurance; Former Willmar Municipal Airport Willmar, MN

AGENCY:
Federal Aviation Administration, DOT.

ACTION:
Notice of intent of waiver with respect to land.

SUMMARY:
The Federal Aviation Administration (FAA) is considering a proposal to authorize the release of approximately 482.21 acres of the airport property at the Former Willmar Municipal Airport, Willmar MN.
The acreage being released is not needed for aeronautical use as the City built a new replacement airport that became operational in 2006.
The acreage was originally acquired with local, State of Minnesota, and federal funds. The federal funds associated with the land came from a Federal Aid to Airports Grant in 1957 (Grant Number 9-21-040-5702). The FAA approved a Finding of No Significant Impact for the release of the former Willmar Municipal Airport on September 20, 2013. Approval does not constitute a commitment by the FAA to financially assist in the disposal of the subject airport property nor a determination of eligibility for grant-in-aid funding from the FAA. The disposition of proceeds from the disposal of the airport property will be in accordance with FAA's Policy and Procedures Concerning the Use of Airport Revenue, published in the Federal Register on February 16, 1999.
In accordance with section 47107(h) of title 49, United States Code, this notice is required to be published in the Federal Register 30 days before modifying the land-use assurance that requires the property to be used for an aeronautical purpose.

DATES:
Comments must be received on or before July 5, 2016.

ADDRESSES:
Ms. Nancy Nistler, Program Manager, Federal Aviation Administration, Airports District Office, 6020 28th Avenue South, Room 102, Minneapolis, MN 55450-2706. Telephone Number (612)253-4638/FAX Number (612)253-4611. Documents reflecting this FAA action and the legal description of the property may be reviewed at this same location or at the Minnesota Department of Transportation, 222 East Plato Blvd., St. Paul MN, 55107

FOR FURTHER INFORMATION CONTACT:
Ms. Nancy Nistler, Program Manager, Federal Aviation Administration, Airports District Office, 6020 28th Avenue South, Room 102, Minneapolis, MN 55450-2706. Telephone Number (612)253-4638/FAX Number (612)253-4611. Documents reflecting this FAA action and the legal description of the property may be reviewed at this same location or at the Minnesota Department of Transportation, 222 East Plato Blvd., St. Paul MN, 55107.

SUPPLEMENTARY INFORMATION:
Following is a description of the subject airport property to be released at Former Willmar Municipal Airport in Willmar, Minnesota and described as follows:
Approximately 482.21 acres of airport property at the Former Willmar Municipal Airport which includes the land encompassing the runway area of the former airport that is east and west of County Road 55, north of Minnesota State Highway 40 (MN-40) and east of County Road 5; land for the former airport terminal building and extending east to 18th Street SW and South to 15th Avenue SW; a parcel of land south of US Highway 12 and east of County Road 5, and a parcel of land south of MN-40 and east of County Road 55.
Said parcel subject to all easements, restrictions, and reservations of record.
Issued in Minneapolis, MN on May 18, 2016.
Andy Peek,

Manager, Dakota-Minnesota Airports District Office, FAA, Great Lakes Region.
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
[Summary Notice No. PE-2016-0037]
Petition for Exemption; Summary of Petition Received; AeroLogix Consulting Inc.: Correction

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Notice: correction.

SUMMARY:
This notice contains a corrected summary of a petition seeking relief from specified requirements of Title 14 of the Code of Federal Regulations. The purpose of this notice is to improve the public's awareness of, and participation in, the FAA's exemption process. Neither publication of this notice nor the inclusion or omission of information in the summary is intended to affect the legal status of the petition or its final disposition.

DATES:
Comments on this petition must identify the petition docket number and must be received on or before June 23, 2016.

ADDRESSES:
Send comments identified by docket number FAA-2015-0094 using any of the following methods:
• Federal eRulemaking Portal: Go to http://www.regulations.gov and follow the online instructions for sending your comments electronically.
• Mail: Send comments to Docket Operations, M-30; U.S. Department of Transportation (DOT), 1200 New Jersey Avenue SE., Room W12-140, West Building Ground Floor, Washington, DC 20590-0001.
• Hand Delivery or Courier: Take comments to Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
• Fax: Fax comments to Docket Operations at 202-493-2251.
Privacy: In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to http://www.regulations.gov, as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at http://www.dot.gov/privacy.
Docket: Background documents or comments received may be read at http://www.regulations.gov at any time. Follow the online instructions for accessing the docket or go to the Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

FOR FURTHER INFORMATION CONTACT:
Dan Ngo (202) 267-4264, Office of Rulemaking, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 20591.
This notice is published pursuant to 14 CFR 11.85.
Issued in Washington, DC, on May 24, 2016.
Lirio Liu,

Director, Office of Rulemaking.

Petition for Exemption
Docket No.: FAA-2015-0094
Petitioner: AeroLogix Consulting Inc.
Section(s) of 14 CFR Affected: Part 21, Subpart H, §§ 45.23; 45.25; 45.29; 61.113; 61.133; 91.417(a)(b); 91.409(a)(1)(2); 91.407(a)(1); 91.405(a); 91.307(a); 91.151(a)(1); 91.121; 91.9(b)(2); 91.7(a); 91.203(a)(1); 91.207(a)(1).
Description of Relief Sought: The petitioner is seeking relief to amend Exemption No. 11370 to operate higher than 400 feet AGL (Condition No. 4), proximity to nonparticipating persons, vessels, vehicles, and structures (Condition No. 26), and changes to permissions to operate over private or controlled-access property (Condition No. 27).
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
[Summary Notice No. PE-2016-46]
Petition for Exemption; Summary of Petition Received; Aviation Systems Engineering Company: Extension

AGENCY:
Federal Aviation Administration (FAA), DOT.

ACTION:
Notice: extension.

SUMMARY:
This notice contains a summary of a petition seeking relief from specified requirements of Title 14 of the Code of Federal Regulations. The purpose of this notice is to extend the comment period to improve the public's awareness of, and participation in, the FAA's exemption process. Neither publication of this notice nor the inclusion or omission of information in the summary is intended to affect the legal status of the petition or its final disposition.

DATES:
Comments on this petition must identify the petition docket number and must be received on or before June 23, 2016.

ADDRESSES:
Send comments identified by docket number FAA-2015-0481 using any of the following methods:
• Federal eRulemaking Portal: Go to http://www.regulations.gov and follow the online instructions for sending your comments electronically.
• Mail: Send comments to Docket Operations, M-30; U.S. Department of Transportation (DOT), 1200 New Jersey Avenue SE., Room W12-140, West Building Ground Floor, Washington, DC 20590-0001.
• Hand Delivery or Courier: Take comments to Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.
• Fax: Fax comments to Docket Operations at 202-493-2251.
Privacy: In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to http://www.regulations.gov, as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at http://www.dot.gov/privacy.
Docket: Background documents or comments received may be read at http://www.regulations.gov at any time. Follow the online instructions for accessing the docket or go to the Docket Operations in Room W12-140 of the West Building Ground Floor at 1200 New Jersey Avenue SE., Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays.

FOR FURTHER INFORMATION CONTACT:
Dan Ngo, 202-267-4264, 800 Independence Avenue SW., Washington, DC 20591.
This notice is published pursuant to 14 CFR 11.85.
Issued in Washington, DC, on May 24, 2016.
Lirio Liu,

Director, Office of Rulemaking.

Petition for Exemption
Docket No.: FAA-2015-0481.
Petitioner: Aviation Systems Engineering Company.
Section(s) of 14 CFR Affected: §§ 91.119(c) and 91.151(a)(1).
Description of Relief Sought: The petitioner is seeking relief to amend Exemption No. 11509 to operate within 500 feet from nonparticipating persons, as well as relief from the minimum fuel requirement.
DEPARTMENT OF TRANSPORTATION
Federal Railroad Administration
[Docket Number FRA-2016-0002-N-13]
Proposed Agency Information Collection Activities; Comment Request

AGENCY:
Federal Railroad Administration (FRA), U.S. Department of Transportation (DOT).

ACTION:
Notice and request for comments.

SUMMARY:
In compliance with the Paperwork Reduction Act of 1995 (PRA), FRA is forwarding the Information Collection Request (ICR) renewals abstracted below to the Office of Management and Budget (OMB) for review and comment. The ICRs describe the nature of the information collections and their expected burden.

DATES:
Comments must be submitted on or before July 5, 2016.

FOR FURTHER INFORMATION CONTACT:
Mr. Robert Brogan, Information Collection Clearance Officer, Office of Railroad Safety, Safety Regulatory Analysis Division, RRS-21, Federal Railroad Administration, 1200 New Jersey Avenue SE., Mail Stop 25, Washington, DC 20590, (202) 493-6292; or Ms. Kimberly Toone, Information Collection Clearance Officer, Office of Information Technology, RAD-20, Federal Railroad Administration, 1200 New Jersey Avenue SE., Mail Stop 35, Washington, DC 20590, (202) 493-6132. These telephone numbers are not toll-free.

SUPPLEMENTARY INFORMATION:
The PRA, 44 U.S.C. 3501-3520, and its implementing regulations, 5 Code of Federal Regulations (CFR) part 1320, require Federal agencies to issue two notices seeking public comment on information collection activities before OMB may approve paperwork packages. See 44 U.S.C. 3506, 3507; 5 CFR 1320.5, 1320.8(d)(1), and 1320.12. On February 24, 2016, FRA published a 60-day notice in the Federal Register soliciting comment on those ICRs for which the agency is now seeking OMB approval. See 80 FR 81423. FRA received no comments in response to that notice.
Before OMB decides whether to approve these proposed collections of information, it must provide 30 days for public comment. See 44 U.S.C. 3507(b); 5 CFR 1320.12(d). Federal law requires OMB to approve or disapprove paperwork packages between 30 and 60 days after the 30-day notice is published. See 44 U.S.C. 3507(b)-(c); 5 CFR 1320.12(d); and 60 FR 44978, 44983, Aug. 29, 1995. OMB believes the 30-day notice informs the regulated community to file relevant comments and affords the agency adequate time to digest public comments before it renders a decision. See 60 FR 44983, Aug. 29, 1995. Therefore, respondents should submit their respective comments to OMB within 30 days of publication of this notice to best ensure having their full consideration. See 5 CFR 1320.12(c) and 60 FR 44983.
The summaries below describe the nature of the ICRs and their expected burdens. FRA is submitting the renewal requests for clearance by OMB as required by the PRA.
(1) Title: Designation of Qualified Persons.
OMB Control Number: 2130-0511.
Abstract: The collection of information is used to prevent the unsafe movement of defective freight cars. Railroads must inspect freight cars for compliance and when noncompliance is found, determine proper restrictions for the movement of defective cars.
Type of Request: Extension without change of a currently approved information collection.
Affected Public: Businesses (railroads).
Form(s): N/A.
Total Annual Estimated Responses: 1,200.
Total Annual Estimated Burden: 40 hours.
(2) Title: Qualification and Certification of Locomotive Engineers.
OMB Control Number: 2130-0533.
Abstract: Section 4 of the Rail Safety Improvement Act of 1988, Public Law 100-342, 102 Statute 624 (June 22, 1988), later amended and re-codified by Public Law 103-272, 108 Statute 874 (July 5, 1994), required FRA to issue regulations establishing a program for certifying or licensing locomotive engineers. FRA uses the collection of information to ensure railroads employ and properly train qualified individuals as locomotive engineers and designated supervisors of locomotive engineers. FRA also uses the collection of information to verify railroads have established required certification programs for locomotive engineers and that those programs fully conform to the standards specified in the regulation.
Type of Request: Extension without change of a currently approved information collection.
Form(s): N/A.
Total Annual Estimated Responses: 216,863.
Total Annual Estimated Burden: 272,672 hours.
Addressee: Send comments regarding these information collections to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 Seventeenth Street NW., Washington, DC 20503, Attention: FRA Desk Officer. Comments may also be sent via email to OMB at oira_submissions@omb.eop.gov.
Comments are invited on the following: Whether the ICRs are necessary for DOT to properly perform its functions, including whether the information will have practical utility; the accuracy of DOT's estimates of the burden of the ICRs; ways to enhance the quality, utility, and clarity of the information to be collected; and ways to minimize the burden of the ICRs on respondents, including using automated collection techniques or other forms of information technology.
A comment to OMB is best assured of having its full effect if OMB receives it within 30 days of publication of this notice in the Federal Register .

Authority:
44 U.S.C. 3501-3520.
Issued in Washington, DC, on May 31, 2016.
Corey Hill,

Executive Director.
DEPARTMENT OF TRANSPORTATION
Federal Railroad Administration
[Docket Number FRA 2016-0002-N-15]
Proposed Agency Information Collection Activities; Comment Request

AGENCY:
Federal Railroad Administration (FRA), U.S. Department of Transportation (DOT).

ACTION:
Notice and request for comments.

SUMMARY:
In accordance with the Paperwork Reduction Act of 1995 (PRA) and its implementing regulations, FRA seeks the Office of Management and Budget's (OMB) approval of the proposed information collection activities abstracted below. However, before submitting this proposed information collection request (ICR) to OMB, FRA is soliciting public comment on specific aspects of the activities identified below.

DATES:
Comments must be received no later than August 2, 2016.

ADDRESSES:
Submit written comments on any or all of the information activities described in this notice by mail to either Mr. Robert Brogan, Information Collection Clearance Officer, Office of Railroad Safety, Regulatory Safety Analysis Division, RRS-21, FRA, 1200 New Jersey Avenue SE., Mail Stop 25, Washington, DC 20590; or Ms. Kimberly Toone, Information Collection Clearance Officer, Office of Information Technology, RAD-20, FRA, 1200 New Jersey Avenue SE., Mail Stop 35, Washington, DC 20590. Commenters requesting that FRA acknowledge receipt of their respective comments must include a self-addressed stamped postcard stating, “Comments on OMB Control Number 2130-New,” and should also include the title of the collection of information. Alternatively, comments may be faxed to (202) 493-6216 or (202) 493-6497, or emailed to Mr. Brogan at Robert.Brogan@dot.gov, or Ms. Toone at Kimberly.Toone@dot.gov. Please refer to the assigned OMB control number in any correspondence submitted. FRA will summarize comments received in response to this notice in a subsequent notice and include them in its information collection submission to OMB for approval.

FOR FURTHER INFORMATION CONTACT:
Mr. Robert Brogan, at (202) 493-6292, or Ms. Kimberly Toone, at (202) 493-6132. These telephone numbers are not toll-free.

SUPPLEMENTARY INFORMATION:
The PRA, 44 U.S.C. 3501-3520, and its implementing regulations, 5 Code of Federal Regulations (CFR) part 1320, Rulemaking Procedures, require Federal agencies to provide 60 days' notice to the public for comment on information collection activities before seeking OMB approval. See 44 U.S.C. 3506(c)(2)(A); 5 CFR 1320.8(d)(1), 1320.10(e)(1), and 1320.12(a). Specifically, FRA invites interested respondents to comment on the following summary of proposed information collection activities regarding: (1) Whether the information collection activities are necessary for FRA to properly execute its functions, including whether the activities will have practical utility; (2) the accuracy of FRA's estimates of the burden of the information collection activities, including the validity of the methodology and assumptions used to determine the estimates; (3) ways FRA can enhance the quality, utility, and clarity of the information being collected; and (4) ways FRA can minimize the burden of information collection activities on the public by automated, electronic, mechanical, or other technological collection techniques or other forms of information technology ( e.g., permitting electronic submission of responses). See 44 U.S.C. 3506(c)(2)(A); 5 CFR 1320.8(d)(1).
FRA believes soliciting public comment will promote its efforts to reduce the administrative and paperwork burdens associated with the collection of information Federal regulations mandate, including: (1) Reducing reporting burdens; (2) organizing information collection requirements in a “user friendly” format to improve the use of such information; and (3) accurately assessing the resources expended to retrieve and produce information requested. See 44 U.S.C. 3501.
Below is a brief summary of the proposed ICR that FRA will submit for OMB approval as required under the PRA:
Title: Survey of Plant and Insular Tourist Railroads subject to FRA Bridge Safety Standards (Title 49 CFR part 237).
OMB Control Number: 2130-New.
Abstract: FRA Bridge Safety Standards regulations (49 CFR part 237) require all owners of railroad track with a gage of 2 feet or more supported by a bridge to comply with this part. This includes track owners with bridges located within an industrial installation (plant) that is not part of the general railroad system of transportation (general system) but over which railroad equipment is moved by a general system railroad. To identify track owners subject to the requirements of part 237, Bridge Safety Standards, FRA relies on the railroad accident/incident reports (49 CFR part 225) to be filed monthly. However, plant and insular tourist railroads are exempt from the part 225, Railroad Accidents/Incidents: Reports Classification, and Investigations, reporting requirements.
FRA will request any railroad serving a plant and moving railroad equipment over bridges within the plant, or the plant itself, to advise FRA by email that there are railroad bridges within the installation potentially subject to FRA Bridge Safety Standards. FRA will also request insular tourist railroads, whose tracks are supported by one or more bridges, to advise FRA of their existence by email. The email notification should include the name of the installation or insular tourist railroad, address including city and State, contact name, telephone number, and email address. This survey will be ongoing with initial approval requested for 3 years.
FRA desires to identify plant and insular tourist railroads that may be subject to part 237 requirements, but are exempt from the part 225 reporting requirement to analyze risks these entities pose to railroad bridge safety and aid in planning bridge safety oversight activities and allocating resources.
Affected Public: Freight railroads, industrial installations (plants), insular tourist railroads.
Respondent Universe: 689 railroads, 500 industrial installations (estimated), 20 insular tourist railroads (estimated).
Frequency of Submission: On occasion.
Reporting Burden:
CFR section | Respondent universe | Total annual responses (emails) | Average time per response (minutes) | Total annual burden hours
Notification of Industrial Installations potentially subject to part 237 | Railroads, Industrial Installations | 200 | 15 | 50
Notification of Insular Tourist Railroads subject to part 237 | Insular Tourist Railroads | 10 | 15 | 2.5
Total Responses: 210.
Estimated Total Annual Burden: 53 hours.
Type of Request: Approval of a new information collection.
Status: Regular Review.
Under 44 U.S.C. 3507(a) and 5 CFR 1320.5(b) and 1320.8(b)(3)(vi), FRA informs all interested parties that FRA may not conduct or sponsor, and a respondent is not required to respond to, a collection of information unless it displays a currently valid OMB control number.

Authority:
44 U.S.C. 3501-3520.
Issued in Washington, DC, on May 31, 2016.
Corey Hill,

Executive Director.
DEPARTMENT OF THE TREASURY
Community Development Financial Institutions Fund
Information Collection: Capital Magnet Fund Application; Capital Magnet Fund Annual Report

ACTION:
Notice and request for public comment.

SUMMARY:
The U.S. Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act (PRA) of 1995, 44 U.S.C. 3506(c)(2)(A). Currently, the Community Development Financial Institutions (CDFI) Fund, Department of the Treasury, is soliciting comments concerning the Capital Magnet Fund (CMF) Application (hereafter, the Application) and comments concerning reporting and record retention requirements of the Capital Magnet Fund Annual Report (hereafter, Annual Report).

DATES:
Written comments must be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Submit your comments via email to Marcia Sigal, CMF Program Manager, CDFI Fund, at cmf@cdfi.treas.gov.

FOR FURTHER INFORMATION CONTACT:
Marcia Sigal, CMF Program Manager, CDFI Fund, U.S. Department of the Treasury, 1500 Pennsylvania Avenue NW., Washington, DC 20220 (202) 653-0375 (not a toll free number). Other information regarding the CDFI Fund and its programs may be obtained through the CDFI Fund's Web site at http://www.cdfifund.gov.
The Application may be obtained from the CMF program page of the CDFI Fund's Web site at https://www.cdfifund.gov/Documents/FY2016%20CMF%20Application%20Instructions_Final_Updated%203.23.2016.pdf. The Capital Magnet Fund Awardee Annual Report can be found at https://www.cdfifund.gov/programs-training/Programs/cmf/Pages/compliance-step.aspx#step5.

SUPPLEMENTARY INFORMATION:
Title: Capital Magnet Fund Application; Capital Magnet Fund Annual Report.
OMB Numbers: 1559-0036; 1559-0043.
Abstract: The Capital Magnet Fund (CMF) was established through the Housing and Economic Recovery Act of 2008 (Pub. L. 110-289) or HERA, as a trust fund to be used to carry out a competitive grant program administered by the CDFI Fund. Through the CMF, the CDFI Fund is authorized to administer a competitive application process to make financial assistance grants to Certified Community Development Financial Institutions (CDFIs) and qualified Nonprofit Organizations that have the development or management of affordable housing as one of their principal purposes. CMF Awards must be used to attract private financing for and increase investment in (i) the Development, Preservation, Rehabilitation, and Purchase of Affordable Housing for primarily Extremely Low-, Very Low-, and Low-Income Families; and (ii) Economic Development Activities which, In Conjunction With Affordable Housing Activities will implement a Concerted Strategy to stabilize or revitalize a Low-Income area or an Underserved Rural Area.
CMF Award Recipients will be competitively selected after a careful review of their applications for program funding. The Application requires the submission of information about the Applicant's track record, proposed pipeline, as well as data and narrative strategies for four main sections: Business Strategy, Leveraging Strategy, Community Impact, and Organizational Capacity. As part of the Award selection process, the CDFI Fund will conduct a quantitative review and a subsequent external substantive review of each Application in two parts (Phase 1 and Phase 2) as defined in a Notice of Funds Availability for each round.
The CMF Award Recipients will enter into Assistance Agreements with the CDFI Fund that set forth certain required terms and conditions of the award, including reporting and data collection requirements. The Assistance Agreement requires the collection of annual reports that are used to collect information for compliance monitoring and program evaluation purposes. This information is reviewed to ensure the Awardee's compliance with its performance goals and contractual obligations as well as the overall performance of the program.
The CDFI Fund published a Notice of Funds Availability for the Capital Magnet Fund on February 8, 2016 (81 Federal Register 6585). The NOFA provides application guidance for the FY 2016 CMF funding round. The CDFI Fund sought and received emergency PRA approval from Office of Management and Budget (OMB) for the CMF Application that is currently being used for the FY 2016 CMF funding round.
This request for public comment seeks to consolidate all CMF-related forms under OMB control number 1559-0036. Therefore, 1559-0036 will include both the CMF Application, currently 1559-0036, and 1559-0043 the Capital Magnet Fund Awardee Annual Report.
Title: Capital Magnet Fund Application.
OMB Number: 1559-0036.
Current Actions: Renewal of existing Information Collection.
Type of Review: Regular Review.
Affected Public: Certified CDFIs and qualified Nonprofit Organizations.
Estimated Number of Respondents: 150.
Estimated Annual Time per Respondent: 100.
Estimated Total Annual Burden Hours: 15,000.
Title: Capital Magnet Fund Annual Report.
OMB Number: 1559-0043.
Current Actions: Reinstatement.
Type of Review: Regular Review.
Affected Public: Eligible Certified CDFIs and Nonprofit Organizations participating in CMF.
Estimated Number of Respondents: 60.
Estimated Annual Time per Respondent: 40 hours per year.
Estimated Total Annual Burden Hours: 2,400 hours per year.
Requests for Comments: Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval. All comments will become a matter of public record and may be published on the CDFI Fund's Web site at http://www.cdfifund.gov.
The CDFI Fund is seeking input on the content of the CMF Application with regards to the following: (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 technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services required to provide information.
Additionally, the CDFI Fund specifically requests comments concerning the following questions:
(1) Is the information that is currently collected by the Application necessary and appropriate for the CDFI Fund to consider for the purpose of making award decisions?
(2) Are there questions or tables that are redundant or unnecessary?
(3) Are there questions or tables that should be added to ensure collection of relevant information?
(4) CMF Awards may be used to finance Affordable Housing Activities (both rental and Homeownership), as well as certain Economic Development Activities. Is the data and information requested in the Application about proposed Affordable Housing Activities and Economic Development Activities appropriate to these different activities or housing tenure types?
(5) What, if any, additional data and information should be collected on any of these different activities or housing tenure types?
(6) Question 5 asks Applicants to provide the Service Areas that they propose to serve through CMF Awards. Do the answer options in Question 5 allow for sufficient flexibility to encompass the Service Areas in which Certified CDFIs and Non-Profit Organizations operate?
(7) Per HERA, the CDFI Fund is required to fund CMF activities in geographically diverse areas of economic distress. The CDFI Fund publishes a list of areas of “High Housing Need” based on data from the U.S. Census as a way for Applicants to identify their intent to fund activities in areas of economic distress. In the FY 2016 CMF funding round, areas of High Housing Need are defined as census tracts where: (i) At least 20 percent of households are Very Low-Income renters paying more than half their income for rent; or (ii) are high poverty neighborhoods (where greater than 20 percent of households have incomes below the poverty rate) with a rental vacancy rate of at least 10 percent; or (iii) are Underserved Rural Areas. What other sources of data or indicators could the CDFI Fund use to identify areas of high housing need or areas of economic distress?
(8) How, if at all, should the CDFI Fund consider the energy efficiency and/or environmental impacts of properties as part of the Application process?
(9) Tables A1, A2, and C1 ask for certain data that will be used to assess an Applicant's track record. Is the data collected in these three tables appropriate to assess an Applicant's track record? Is there other information not requested in the Application that could demonstrate an Applicant's track record?
(10) Tables B2, B3, and C2 ask for certain data and information that will be used to assess an Applicant's projected deployment and production. Is the data collected in these three tables appropriate to assess an Applicant's projected deployment of its CMF Award and production? Is there other information not requested in the Application that would demonstrate an Applicant's projected deployment of its CMF Award and production?
(11) Are there requests for data in the Application that Applicants (either Certified CDFIs or Non-Profit Organizations) do not have readily available or that are too overly burdensome to obtain and/or calculate ( e.g., Exhibit 3 Application Financial Data)?
(12) What data and information about an Applicant's loan portfolio and organizational finances should be requested in the Application in order to evaluate whether Applicants are in adequate financial health and have the capacity to successfully deploy a CMF Award?
The CDFI Fund is also seeking input on the content of the Capital Magnet Fund Annual Report. The CMF Assistance Agreement requires the collection of annual reports that are used to collect information for compliance monitoring and program evaluation purposes. This information is reviewed to ensure the Recipient's compliance with its performance goals and contractual obligations and the overall performance of the program. The Annual Report represents a revised annual information collection as compared to the version posted in December 2012. This information collection request incorporates four new fields to report funding from related public sources and related private sources, and funding from third-party public sources and third-party private sources. In addition, this version incorporates prior public comments and technical corrections from current users to improve validation and reduce reporting burdens for program Recipients. The CDFI Fund proposes to add additional fields to the posted data collection instrument to show how the Applicant has met its Application commitment to leverage a CMF Award with the specified pre-investment funds. The reporting template can be viewed on the CDFI Fund Web site at https://www.cdfifund.gov/programs-training/Programs/cmf/Pages/compliance-step.aspx#step5. Comments concerning the Annual Report 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 technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services required to provide information.

Authority:
Pub. L. 110-289, 12 CFR 1807.
Mary Ann Donovan,

Director, Community Development Financial Institutions Fund.
DEPARTMENT OF THE TREASURY
Community Development Financial Institutions Fund; Notice and Request for Comments

ACTION:
Notice and request for comments.

SUMMARY:
The U.S. Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the Community Development Financial Institutions Fund (CDFI Fund), U.S. Department of the Treasury, is soliciting comments concerning the Secondary Loan Commitment Form (SLCF) for the CDFI Bond Guarantee Program (BG Program).

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Submit your comments via email Lisa Jones, CDFI Bond Guarantee Program Manager, at bgp@cdfi.treas.gov.

FOR FURTHER INFORMATION CONTACT:
Lisa Jones, CDFI Bond Guarantee Program Manager, CDFI Fund, U.S. Department of the Treasury, 1500 Pennsylvania Avenue NW., Washington, DC 20220, or by facsimile to (202) 508-0083 (not a toll free number). Additional information regarding the BG Program and the SLCF may be obtained from the BG Program page of the CDFI Fund's Web site at http://www.cdfifund.gov/bond.

SUPPLEMENTARY INFORMATION:
Title: CDFI Bond Guarantee Program Secondary Loan Commitment Form.
OMB Number: 1559-0044.
Abstract: The purpose of the BG Program is to support CDFI lending by providing Guarantees for Bonds issued by Qualified Issuers as part of a Bond Issue for Eligible Community or Economic Development Purposes. The BG Program provides CDFIs with a source of long-term capital and furthers the mission of the CDFI Fund to increase economic opportunity and promote community development investments for underserved populations and distressed communities in the United States. The CDFI Fund achieves its mission by promoting access to capital and local economic growth by investing in, supporting, and training CDFIs.
In compliance with OMB Circular A-129 and the BG Program's interim rule (12 CFR 1808), the BG Program will collect all necessary information to monitor compliance, manage the portfolio effectively, and track progress towards policy goals and statutory and regulatory requirements. The proposed SLCF will add significantly to the Department of the Treasury's review and impact analysis on the current and proposed use of Bond Proceeds in underserved communities and support the CDFI Fund in proactively managing regulatory compliance. Risk detection and mitigation are crucial activities for the long-term operation and viability of the BG Program. The specified data collection area and parameters are consistent with the requirements contained in 12 CFR part 1808.307(b).
Current Actions: New Collection.
Type of Review: Regular Review.
Affected Public: Eligible CDFIs participating in the BG Program.
Estimated Number of Respondents: 25.
Estimated Annual Time per Respondent: 4 hours.
Estimated Total Annual Burden Hours: 100 hours.
Requests for Comments: Comments submitted in response to this notice will be summarized and/or included in the request for Office of Management and Budget approval. All comments will become a matter of public record and may be published on the CDFI Fund Web site at http://www.cdfifund.gov. Comments are invited on: (a) Whether the collection of information is necessary for the proper performance of the functions of the CDFI Fund, including whether the information will have practical utility; (b) the accuracy of the CDFI Fund'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 technology; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
The CDFI Fund specifically requests comments concerning the following questions:
(1) Does the proposed SLCF and certification form provide clarity on the expectations for meeting the requirements contained in 12 CFR part 1808.307(b)?
(2) Is there additional information or guidance that the CDFI Fund can provide to clarify the commitment test review process?
(3) Does the proposed SLCF and certification contain the appropriate data points to ensure that Eligible CDFIs have executed Secondary Loan documents (in the form of promissory notes) with Secondary Borrowers as follows: (1) Not later than 12 months after the Bond Issue Date, Secondary Loan documents representing at least 50 percent of such Eligible CDFI's Bond Loan proceeds allocated for Secondary Loans; and (2) not later than 24 months after the Bond Issue Date, Secondary Loan documents representing 100 percent of such Eligible CDFI's Bond Loan proceeds allocated for Secondary Loans?

Authority:
12 CFR part 1808.
Mary Ann Donovan,

Director, Community Development Financial Institutions Fund.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Regulation Project

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning TD 9633, Limitations on Duplication of Net Built-in Losses.

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of this regulation should be directed to Martha R. Brinson, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at Martha.R.Brinson@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Limitations on Duplication of Net Built-in Losses.
OMB Number: 1545-2247.
Regulation Project Number: TD 9633.
Abstract: These regulations will provide guidance for applying 26 U.S.C. 362(e)(2), relating to the limitation on transfer of built-in losses.
Current Actions: There is no change in the paperwork burden previously approved by OMB.
Type of Review: Extension of a currently approved collection.
Affected Public: Business or other for-profit organizations.
Estimated Time per Respondents: 100,000.
Estimated Time per Respondent: 45 minutes.
Estimated Total Annual Burden Hours: 75,000.
The following paragraph applies to all of 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 as long as 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: May 24, 2016.
Tuawana Pinkston,

IRS Reports Clearance Officer.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Regulation Project

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning netting rule for certain conversion transactions.

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of the information collection should be directed to Allan Hopkins, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet, at Allan.M.Hopkins@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Regulations Under Section 1258 of the Internal Revenue Code of 1986; Netting Rule for Certain Conversion Transactions.
OMB Number: 1545-1452.
Regulation Project Number: FI-43-94.
Abstract: Internal Revenue Code section 1258 recharacterizes capital gains from conversion transactions as ordinary income to the extent of the time value element. This regulation provides that certain gains and losses may be netted for purposes of determining the amount of gain recharacterized. To be eligible for netting relief, the taxpayer must identify on its books and records all the positions that are part of the conversion transaction. This must be done before the close of the day on which the positions become part of the conversion transaction.
Current Actions: There is no change to this existing regulation.
Type of Review: Extension of a currently approved collection.
Affected Public: Business or other for-profit organizations, and not-for-profit institutions.
Estimated Number of Respondents: 50,000.
Estimated Time per Respondent: 6 minutes.
Estimated Total Annual Burden Hours: 5,000.
The following paragraph applies to all of 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 as long as 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: May 27, 2016.
Allan Hopkins,

Tax Analyst.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Revenue Procedure 2000-42

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2000-42, Section 1503(d) Closing Agreement Requests.

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of the regulations should be directed to Allan Hopkins at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet at Allan.M.Hopkins@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Section 1503(d) Closing Agreement Requests.
OMB Number: 1545-1706.
Revenue Procedure Number: Revenue Procedure 2000-42.
Abstract: Revenue Procedure 2000-42 informs taxpayers of the information they must submit to request a closing agreement under regulation section 1.1503-2(g)(2)(iv)(B)(i) to prevent the recapture of dual consolidated losses upon the occurrence of certain triggering events.
Current Actions: There are no changes being made to the revenue procedure at this time.
Type of Review: Extension of a currently approved collection.
Affected Public: Business or other for-profit organizations.
Estimated Number of Respondents: 20.
Estimated Average Time per Respondent: 100 hours.
Estimated Total Annual Burden Hours: 2,000.
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 as long as 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: May 27, 2016.
Allan Hopkins,

Tax Analyst.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Form 5578

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 5578, Annual Certification of Racial Nondiscrimination for a Private School Exempt From Federal Income Tax.

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of the form and instructions should be directed to Martha R. Brinson, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at Martha.R.Brinson@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Annual Certification of Racial Nondiscrimination for a Private School Exempt From Federal Income Tax.
OMB Number: 1545-0213.
Form Number: Form 5578.
Abstract: Every organization that claims exemption from Federal income tax under Internal Revenue Code section 501(c)(3) and that operates, supervises, or controls a private school must file a certification of racial nondiscrimination. Such organizations, if they are not required to file Form 990, must provide the certification on Form 5578. The Internal Revenue Service uses the information to help ensure that the school is maintaining nondiscriminatory policy in keeping with its exempt status.
Current Actions: There are no changes being made to the form at this time.
Type of Review: Extension of a currently approved collection.
Affected Public: Not-for-profit institutions.
Estimated Number of Respondents: 1,000.
Estimated Time per Respondent: 3 hours, 44 minutes.
Estimated Total Annual Burden Hours: 3,730.
The following paragraph applies to all of 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 as long as 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: May 23, 2016.
Tuawana Pinkston,

IRS Reports Clearance Officer.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Regulation Project

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning TD 8786, Source of Income From Sales of Inventory Partly From Sources Within a Possession of the United States; Also, Source of Income Derived From Certain Purchases From a Corporation Electing Section 936.

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of this regulation should be directed to Martha R. Brinson, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at Martha.R.Brinson@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Source of Income From Sales of Inventory Partly From Sources Within a Possession of the United States; Also, Source of Income Derived From Certain Purchases From a Corporation Electing Section 936.
OMB Number: 1545-1556. Regulation Project Number: TD 8786.
Abstract: The information requested in section 1.863-3(f)(6) is necessary for the Service to audit taxpayers' return to ensure taxpayers are properly determining the source of their income.
Current Actions: There is no change in the paperwork burden previously approved by OMB.
Type of Review: Extension of a currently approved collection.
Affected Public: Business or other for-profit organizations.
Estimated Time per Respondents: 200.
Estimated Time per Respondent: 2 hours., 30 minutes.
Estimated Total Annual Burden Hours: 500.
The following paragraph applies to all of 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 as long as 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: May 24, 2016.
Tuawana Pinkston,

IRS Reports Clearance Officer.
DEPARTMENT OF THE TREASURY
Internal Revenue Service
Proposed Collection; Comment Request for Revenue Procedure 2010-13

AGENCY:
Internal Revenue Service (IRS), Treasury.

ACTION:
Notice and request for comments.

SUMMARY:
The Department of the Treasury, 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 proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2010-13, Section 469 Grouping activities.

DATES:
Written comments should be received on or before August 2, 2016 to be assured of consideration.

ADDRESSES:
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.

FOR FURTHER INFORMATION CONTACT:
Requests for additional information or copies of notice should be directed to Sara Covington, at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the internet, at Sara.L.Covington@irs.gov.

SUPPLEMENTARY INFORMATION:
Title: Section 469 Grouping activities.
OMB Number: 1545-2156.
Notice Number: Revenue Procedure 2010-13.
Abstract: This revenue procedure requires taxpayers to report to the Internal Revenue Service their groupings and regroupings of activities and the addition of specific activities within their existing groupings of activities for purposes of section 469 of the Internal Revenue Code and § 1.469-4 of the Income Tax Regulations.
Current Actions: Revision of currently approved collection. There are corrections made to the burden estimates of this notice.
Type of Review: Revision of currently approved collection.
Affected Public: Business and for-profit.
Estimated Number of Respondents: 144,000.
Estimated Average Time per Respondent: 15 mins.
Estimated Total Annual Burden Hours: 36,000 hrs.
The following paragraph applies to all of 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 as long as 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: May 25, 2016.
Sara Covington,

IRS Tax Analyst.
81
107
Friday, June 3, 2016
Presidential Documents
Memorandum of May 24, 2016

Delegation of Authority Under Section 106 of the Bipartisan Congressional Trade Priorities and Accountability Act of 2015

Memorandum for the Secretary of State
By the authority vested in me as President by the Constitution and the laws of the United States of America, including section 301 of title 3, United States Code, I hereby delegate to you the functions and authorities vested in the President by section 106(b)(6)(B) and (C) of the Bipartisan Congressional Trade Priorities and Accountability Act of 2015 (Public Law 114-26, title I) (the “Act”), as added by section 914(e) of the Trade Facilitation and Trade Enforcement Act of 2015 (Public Law 114-125). In carrying out these functions, you will inform the United States Trade Representative at the earliest possible time of a decision to invoke an exception under section 106(b)(6)(B) of the Act.
In exercising authority delegated by or performing functions assigned in this memorandum, you may redelegate authority delegated by this memorandum and may further assign functions assigned by this memorandum to officers of any other department or agency within the executive branch to the extent permitted by law.
You are authorized and directed to publish this memorandum in the Federal Register.
THE WHITE HOUSE,
Washington, May 24, 2016
81
107
Friday, June 3, 2016
Rules and Regulations
Part II
Environmental Protection Agency
40 CFR Part 60

Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Final Rule
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2010-0505; FRL-9944-75-OAR]
RIN 2060-AS30
Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
This action finalizes amendments to the current new source performance standards (NSPS) and establishes new standards. Amendments to the current standards will improve implementation of the current NSPS. The new standards for the oil and natural gas source category set standards for both greenhouse gases (GHGs) and volatile organic compounds (VOC). Except for the implementation improvements, and the new standards for GHGs, these requirements do not change the requirements for operations covered by the current standards.

DATES:
This final rule is effective on August 2, 2016.
The incorporation by reference (IBR) of certain publications listed in the regulations is approved by the Director of the Federal Register as of August 2, 2016.

ADDRESSES:
The Environmental Protection Agency (EPA) has established a docket for this action under Docket ID No. EPA-HQ-OAR-2010-0505. All documents in the docket are listed on the http://www.regulations.gov Web site. 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 electronically through http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:
For further information concerning this action, contact Ms. Amy Hambrick, Sector Policies and Programs Division (E143-05), Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541-0964; facsimile number: (919) 541-3470; email address: hambrick.amy@epa.gov or Ms. Lisa Thompson, Sector Policies and Programs Division (E143-05), Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541-9775; facsimile number: (919) 541-3470; email address: thompson.lisa@epa.gov. For other information concerning the EPA's Oil and Natural Gas Sector regulatory program, contact Mr. Bruce Moore, Sector Policies and Programs Division (E143-05), Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541-5460; facsimile number: (919) 541-3470; email address: moore.bruce@epa.gov.

SUPPLEMENTARY INFORMATION:
Outline. The information presented in this preamble is presented as follows:
I. Preamble Acronyms and Abbreviations
II. General Information
A. Executive Summary
B. Does this action apply to me?
C. Where can I get a copy of this document?
D. Judicial Review
III. Background
A. Statutory Background
B. Regulatory Background
C. Other Notable Events
D. Stakeholder Outreach and Public Hearings
E. Related State and Federal Regulatory Actions
IV. Regulatory Authority
A. The Oil and Natural Gas Source Category Listing Under CAA Section 111(b)(1)(A)
B. Impacts of GHGs, VOC and SO 2 Emissions on Public Health and Welfare
C. GHGs, VOC and SO 2 Emissions From the Oil and Natural Gas Source Category
D. Establishing GHG Standards in the Form of Limitations on Methane Emissions
V. Summary of Final Standards
A. Control of GHG and VOC Emissions in the Oil and Natural Gas Source Category—Overview
B. Centrifugal Compressors
C. Reciprocating Compressors
D. Pneumatic Controllers
E. Pneumatic Pumps
F. Well Completions
G. Fugitive Emissions From Well Sites and Compressor Stations
H. Equipment Leaks at Natural Gas Processing Plants
I. Liquids Unloading Operations
J. Recordkeeping and Reporting
K. Reconsideration Issues Being Addressed
L. Technical Corrections and Clarifications
M. Prevention of Significant Deterioration and Title V Permitting
N. Final Standards Reflecting Next Generation Compliance and Rule Effectiveness
VI. Significant Changes Since Proposal
A. Centrifugal Compressors
B. Reciprocating Compressors
C. Pneumatic Controllers
D. Pneumatic Pumps
E. Well Completions
F. Fugitive Emissions From Well Sites and Compressor Stations
G. Equipment Leaks at Natural Gas Processing Plants
H. Reconsideration Issues Being Addressed
I. Technical Corrections and Clarifications
J. Final Standards Reflecting Next Generation Compliance and Rule Effectiveness
K. Provision for Equivalency Determinations
VII. Prevention of Significant Deterioration and Title V Permitting
A. Overview
B. Applicability of Tailoring Rule Thresholds Under the PSD Program
C. Implications for Title V Program
VIII. Summary of Significant Comments and Responses
A. Major Comments Concerning Listing of the Oil and Natural Gas Source Category
B. Major Comments Concerning EPA's Authority To Establish GHG Standards in the Form of Limitations on Methane Emissions
C. Major Comments Concerning Compressors
D. Major Comments Concerning Pneumatic Controllers
E. Major Comments Concerning Pneumatic Pumps
F. Major Comments Concerning Well Completions
G. Major Comments Concerning Fugitive Emissions From Well Sites and Compressor Stations
H. Major Comments Concerning Final Standards Reflecting Next Generation Compliance and Rule Effectiveness Strategies
IX. Impacts of the Final Amendments
A. What are the air impacts?
B. What are the energy impacts?
C. What are the compliance costs?
D. What are the economic and employment impacts?
E. What are the benefits of the final standards?
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act of 1995(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 Risks 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
K. Congressional Review Act (CRA)

I. Preamble Acronyms and Abbreviations
Several acronyms and terms are included in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, the following terms and acronyms are defined here:
API American Petroleum Institute
bbl Barrel
boe Barrels of Oil Equivalent
BSER Best System of Emissions Reduction
BTEX Benzene, Toluene, Ethylbenzene and Xylenes
CAA Clean Air Act
CBI Confidential Business Information
CFR Code of Federal Regulations
CO 2 Eq. Carbon dioxide equivalent
DCO Document Control Officer
EIA Energy Information Administration
EPA Environmental Protection Agency
GHG Greenhouse Gases
GHGRP Greenhouse Gas Reporting Program
GOR Gas to Oil Ratio
HAP Hazardous Air Pollutants
LDAR Leak Detection and Repair
Mcf Thousand Cubic Feet
NEI National Emissions Inventory
NEMS National Energy Modeling System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NSPS New Source Performance Standards
NTTAA National Technology Transfer and Advancement Act of 1995
OAQPS Office of Air Quality Planning and Standards
OGI Optical Gas Imaging
OMB Office of Management and Budget
PRA Paperwork Reduction Act
PTE Potential to Emit
REC Reduced Emissions Completion
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
scf Standard Cubic Feet
scfh Standard Cubic Feet per Hour
scfm Standard Cubic Feet per Minute
SO 2 Sulfur Dioxide
tpy Tons per Year
TSD Technical Support Document
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
VCS Voluntary Consensus Standards
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit

II. General Information

A. Executive Summary

1. Purpose of This Regulatory Action
The Environmental Protection Agency (EPA) proposed amendments to the New Source Performance Standards (NSPS) at subpart OOOO and proposed new standards at subpart OOOOa on September 18, 2015 (80 FR 56593). The purpose of this action is to finalize both the amendments and the new standards with appropriate adjustments after full consideration of the comments received on the proposal. Prior to proposal, we pursued a structured engagement process with states and stakeholders. Prior to that process, we issued draft white papers addressing a range of technical issues and then solicited comments on the white papers from expert reviewers and the public.
These rules are designed to complement other federal actions as well as state regulations. In particular, the EPA worked closely with the Department of Interior's Bureau of Land Management (BLM) during development of this rulemaking in order to avoid conflicts in requirements between the NSPS and BLM's proposed rulemaking. ^1 Additionally, we evaluated existing state and local programs when developing these federal standards and attempted, where possible, to limit potential conflicts with existing state and local requirements.
^1 81 FR 6616, February 8, 2016, Waste Prevention, Production Subject to Royalties, and Resource Conservation, Proposed Rule.
As discussed at proposal, prior to this final rule, the EPA had established standards for emissions of VOC and sulfur dioxide (SO 2 ) for several sources in the source category. In this action, the EPA finalizes standards at subpart OOOOa, based on our determination of the best system of emissions reduction (BSER) for reducing emissions of greenhouse gases (GHGs), specifically methane, as well as VOC across a variety of additional emission sources in the oil and natural gas source category ( i.e., production, processing, transmission, and storage). The EPA includes requirements for methane emissions in this action because methane is one of the six well-mixed gases in the definition of GHGs and the oil and natural gas source category is one of the country's largest industrial emitters of methane. In 2009, the EPA found that by causing or contributing to climate change, GHGs endanger both the public health and the public welfare of current and future generations.
In addition to finalizing standards for VOC and GHGs, the EPA is finalizing amendments to improve several aspects of the existing standards at 40 CFR part 60, subpart OOOO related to implementation. These improvements and the setting of standards for GHGs in the form of limitations on methane result from reconsideration of certain issues raised in petitions for reconsideration that were received by the Administrator on the August 16, 2012, NSPS (77 FR 49490) and on the September 13, 2013, amendments (78 FR 58416). These implementation improvements do not change the requirements for operations and equipment covered by the current standards at subpart OOOO.

2. Summary of 40 CFR Part 60, Subpart OOOOa Major Provisions
The final requirements include standards for GHG emissions (in the form of methane emission limitations) and standards for VOC emissions. The NSPS includes both VOC and GHG emission standards for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas source category. These emission sources include the following:
• Sources that are unregulated under the current NSPS at subpart OOOO (hydraulically fractured oil well completions, pneumatic pumps, and fugitive emissions from well sites and compressor stations);
• Sources that are currently regulated at subpart OOOO for VOC, but not for GHGs (hydraulically fractured gas well completions and equipment leaks at natural gas processing plants);
• Certain equipment that is used across the source category, for which the current NSPS at subpart OOOO regulates emissions of VOC from only a subset (pneumatic controllers, centrifugal compressors, and reciprocating compressors), with the exception of compressors located at well sites.
Table 1 below summarizes these sources and the final standards for GHGs (in the form of methane limitations) and VOC emissions. See sections V and VI of this preamble for further discussion.
Table 1—Summary of BSER and Final Subpart OOOO a Standards for Emission Sources
Source | BSER | Final standards of performance for GHGs and VOC
Wet seal centrifugal compressors (except for those located at well sites) ^2 | Capture and route to a control device | 95 percent reduction.
Reciprocating compressors (except for those located at well sites) ^2 | Regular replacement of rod packing ( i.e., approximately every 3 years) | Replace the rod packing on or before 26,000 hours of operation or 36 calendar months or route emissions from the rod packing to a process through a closed vent system under negative pressure.
Pneumatic controllers at natural gas processing plants | Instrument air systems | Zero natural gas bleed rate.
Pneumatic controllers at locations other than natural gas processing plants | Installation of low-bleed pneumatic controllers | Natural gas bleed rate no greater than 6 standard cubic feet per hour (scfh).
Pneumatic pumps at natural gas processing plants | Instrument air systems in place of natural gas driven pumps | Zero natural gas emissions.
Pneumatic pumps at well sites | Route to existing control device or process | 95 percent control if there is an existing control or process on site. 95 percent control not required if (1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process (non-greenfield sites only).
Well completions (subcategory 1: Non-wildcat and non-delineation wells) | Combination of Reduced Emission Completion (REC) and the use of a completion combustion device | REC in combination with a completion combustion device; venting in lieu of combustion where combustion would present safety hazards.
| | Initial flowback stage: Route to a storage vessel or completion vessel (frac tank, lined pit, or other vessel) and separator.
| | Separation flowback stage: Route all salable gas from the separator to a flow line or collection system, re-inject the gas into the well or another well, use the gas as an onsite fuel source or use for another useful purpose that a purchased fuel or raw material would serve. If technically infeasible to route recovered gas as specified above, recovered gas must be combusted. All liquids must be routed to a storage vessel or well completion vessel, collection system, or be re-injected into the well or another well.
| | The operator is required to have a separator onsite during the entire flowback period.
Well completions (subcategory 2: Exploratory and delineation wells and low pressure wells) | Use of a completion combustion device | The operator is not required to have a separator onsite. Either: (1) Route all flowback to a completion combustion device with a continuous pilot flame; or (2) Route all flowback into one or more well completion vessels and commence operation of a separator unless it is technically infeasible for a separator to function. Any gas present in the flowback before the separator can function is not subject to control under this section. Capture and direct recovered gas to a completion combustion device with a continuous pilot flame.
| | For both options (1) and (2), combustion is not required in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways.
Fugitive emissions from well sites and compressor stations | For well sites: Monitoring and repair based on semiannual monitoring using optical gas imaging (OGI) ^3 | Monitoring and repair of fugitive emission components using OGI with Method 21 as an alternative at 500 parts per million (ppm).
| For compressor stations: Monitoring and repair based on quarterly monitoring using OGI | A monitoring plan must be developed and implemented and repair of the sources of fugitive emissions must be completed within 30 days of finding fugitive emissions.
| Equipment leaks at natural gas processing plants | Leak detection and repair at 40 CFR part 60, subpart VVa level of control | Follow requirements at NSPS part 60, subpart VVa level of control as in the 2012 NSPS.
Reconsiderationissues being addressed. As fully detailed in sections V and VI of this preamble and the Response to Comment (RTC) document , the EPA granted reconsideration of several issues raised in the administrative reconsideration petitions submitted on the 2012 NSPS and subsequent amendments (subpart OOOO). In this final rule, in addition to the new standards described above, the EPA includes certain amendments to the 2012 NSPS at subpart OOOO based on reconsideration of those issues. The amendments to the subpart OOOO requirements are effective on August 2, 2016 and, therefore, do not affect compliance activities completed prior to that date.
^2 See sections VI and VIII of this preamble for detailed discussion on emission sources.
^3 The final fugitive standards apply to low production wells. For the reasons discussed in section VI of the preamble, we are not finalizing the proposed exemption of low production wells from these requirements.
These provisions are: Requirements for storage vessel control device monitoring and testing; initial compliance requirements for a bypass device that could divert an emission stream away from a control device; recordkeeping requirements for repair logs for control devices failing a visible emissions test; clarification of the due date for the initial annual report; flare design and operation standards; leak detection and repair (LDAR) for open-ended valves or lines; the compliance period for LDAR for newly affected units; exemption to the notification requirement for reconstruction; disposal of carbon from control devices; the definition of capital expenditure; and continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities. We are finalizing changes to address these issues to clarify the current NSPS requirements, improve implementation, and update procedures.

3. Costs and Benefits
The EPA has carefully reviewed the comments and additional data submitted on the costs and benefits associated with this rule. Our conclusion and responses are summarized in section IX of the preamble and addressed in greater detail in the Regulatory Impact Analysis (RIA) and RTC. The measures finalized in this action achieve reductions of GHG and VOC emissions through direct regulation and reduction of hazardous air pollutant (HAP) emissions as a co-benefit of reducing VOC emissions. The data show that these are cost-effective measures to reduce emissions and the rule's benefits outweigh these costs.
The EPA has estimated emissions reductions, benefits, and costs for 2 years of analysis: 2020 and 2025. Therefore, the emissions reductions, benefits, and costs by 2020 and 2025 ( i.e., including all emissions reductions, costs, and benefits in all years from 2016 to 2025) would be potentially significantly greater than the estimated emissions reductions, benefits, and costs provided within this rule. Actions taken to comply with the final NSPS are anticipated to prevent significant new emissions in 2020, including 300,000 tons of methane; 150,000 tons of VOC; and 1,900 tons of HAP. The emission reductions anticipated in 2025 are 510,000 tons of methane; 210,000 tons of VOC; and 3,900 tons of HAP. Using a 100-year global warming potential (GWP) of 25, the carbon dioxide-equivalent (CO 2 Eq.) methane emission reductions are estimated to be 6.9 million metric tons CO 2 Eq. in 2020 and 11 million metric tons CO 2 Eq. in 2025. The methane-related monetized climate benefits are estimated to be $360 million in 2020 and $690 million in 2025 using a 3-percent discount rate (model average). ^4
^4 We estimate methane benefits associated with four different values of a 1 ton methane reduction (model average at 2.5-percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For the purposes of this summary, we present the benefits associated with the model average at a 3-percent discount rate. However, we emphasize the importance and value of considering the full range of social cost of methane values. We provide estimates based on additional discount rates in preamble section IX and in the RIA.
While the only benefits monetized for this rule are GHG-related climate benefits from methane reductions, the rule will also yield benefits from reductions in VOC and HAP emissions and from reductions in methane as a precursor to global background concentrations of tropospheric ozone. The EPA was unable to monetize the benefits of VOC reductions due to the difficulties in modeling the impacts with the current data available. A detailed discussion of these unquantified benefits appears in section IX of this preamble, as well as in the RIA available in the docket.
Several VOC that are commonly emitted in the oil and natural gas source category are HAP listed under Clean Air Act (CAA) section 112(b), including benzene, toluene, ethylbenzene and xylenes (this group is commonly referred to as “BTEX”) and n-hexane. These pollutants and any other HAP included in the VOC emissions controlled under the NSPS, including requirements for additional sources being finalized in this action, are controlled to the same degree. The co-benefit HAP reductions for the final measures are discussed in the RIA and in the technical support document (TSD), which are included in the public docket for this action.
The HAP reductions from these standards will be meaningful in local communities, as members of these communities and other stakeholders across the country have reported significant concerns to the EPA regarding potential adverse health effects resulting from exposure to HAP emitted from oil and natural gas operations. Importantly, these communities include disadvantaged populations.
The EPA estimates the total capital cost of the final NSPS will be $250 million in 2020 and $360 million in 2025. The estimate of total annualized engineering costs of the final NSPS is $390 million in 2020 and $640 million in 2025 when using a 7-percent discount rate. When estimated revenues from additional natural gas are included, the annualized engineering costs of the final NSPS are estimated to be $320 million in 2020 and $530 million in 2025, assuming a wellhead natural gas price of $4/thousand cubic feet (Mcf). These compliance cost estimates include revenues from recovered natural gas, as the EPA estimates that about 16 billion cubic feet in 2020 and 27 billion cubic feet in 2025 of natural gas will be recovered by implementing the NSPS.
Considering all the costs and benefits of this rule, including the revenues from recovered natural gas that would otherwise be vented, this rule results in a net benefit. The quantified net benefits (the difference between monetized benefits and compliance costs) are estimated to be $35 million in 2020 and $170 million in 2025 using a 3-percent discount rate (model average) for climate benefits in both years. ^5 All dollar amounts are in 2012 dollars.
^5 Figures may not sum due to rounding.

B. Does this action apply to me?
Categories and entities potentially affected by this action include:
Table 2—Industrial Source Categories Affected by This Action
Category | NAICS code ^1 | Examples of regulated entities
Industry | 211111 | Crude Petroleum and Natural Gas Extraction.
| 211112 | Natural Gas Liquid Extraction.
| 221210 | Natural Gas Distribution.
| 486110 | Pipeline Distribution of Crude Oil.
| 486210 | Pipeline Transportation of Natural Gas.
Federal government | | Not affected.
State/local/tribal government | | Not affected.
^1 North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that the EPA is now aware could potentially be affected by this action. Other types of entities not listed in the table could also be regulated. To determine whether your entity is regulated by this action, you should carefully examine the applicability criteria found in the final rule. 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, your air permitting authority, or your EPA Regional representative listed in 40 CFR 60.4 (General Provisions).

C. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of the final action is available on the Internet through the Technology Transfer Network (TTN) Web site. Following signature by the Administrator, the EPA will post a copy of this final action at http://www3.epa.gov/airquality/oilandgas/actions.html. The TTN provides information and technology exchange in various areas of air pollution control. Additional information is also available at the same Web site.

D. Judicial Review
Under section 307(b)(1) of the CAA, judicial review of this final rule is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by August 2, 2016. Moreover, under section 307(b)(2) of the CAA, the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements. Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for the EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, EPA WJC, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

III. Background

A. Statutory Background
The EPA's authority for this rule is CAA section 111, which requires the EPA to first establish a list of source categories to be regulated under that section and then establish emission standards for new sources in that source category. Specifically, CAA section 111(b)(1)(A) requires that a source category be included on the list if, “in [the EPA Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both of the “causes or contributes significantly to” component and the “endanger public health or welfare” component of the determination. Once a source category is listed, CAA section 111(b)(1)(B) requires that the EPA propose and then promulgate “standards of performance” for new sources in such source category. Other than the endangerment finding for listing the source category, CAA section 111(b) gives no direction or enumerated criteria concerning what constitutes a source category or what emission sources or pollutants from a given source category should be the subject of standards. Therefore, as long as the EPA makes the requisite endangerment finding for the source category to be listed, CAA section 111 leaves the EPA with the authority and discretion to define the source category, determine the pollutants for which standards should be developed, and identify the emission sources within the source category for which standards of performance should be established.
CAA section 111(a)(1) defines “a standard of performance” as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated.” This definition makes clear that the standard of performance must be based on controls that constitute “the best system of emission reduction . . . adequately demonstrated.”
In determining whether a given system of emission reduction qualifies as a BSER, CAA section 111(a)(1) requires that the EPA take into account, among other factors, “the cost of achieving such reduction.” As described in section VIII.A of the proposal preamble, ^6 in several cases the DC Circuit has elaborated on this cost factor and formulated the cost standard in various ways, stating that the EPA may not adopt a standard the cost of which would be “exorbitant,” ^7 “greater than the industry could bear and survive,” ^8 “excessive,” ^9 or “unreasonable.” ^{10} For convenience, in this rulemaking, we use “reasonableness” to describe costs, which is well within the bounds established by this jurisprudence.
^6 80 FR 56593, 56616 (September 18, 2015).
^7 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999).
^8 Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975).
^9 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
^{10} Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
CAA Section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, again affording the EPA considerable discretion in choosing a means of cost consideration. ^{11} In this rulemaking, we evaluated whether a control cost is reasonable under a number of approaches that we find appropriate for assessing the types of controls at issue. Specifically, we considered a control's cost effectiveness under a “single pollutant cost-effectiveness” approach and a “multipollutant cost-effectiveness” approach. ^{12} We also evaluated costs on an industry basis by assessing the new capital expenditures (compared to overall capital expenditures) and the annual compliance costs (compared to overall annual revenue) if the rule were to require such control. For a detailed discussion of these cost approaches, please see section VIII.A of the proposal preamble.
^{11} See, e.g.,
Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, the EPA may make a reasoned choice as to how to analyze costs).
^{12} As discussed in the proposed rule preamble, we believe that both the single and multipollutant approaches are appropriate for assessing the reasonableness of the multipollutant controls considered in this action. The EPA has considered similar approaches in the past when considering multiple pollutants that are controlled by a given control option. See e.g., 73 FR 64079-64083 and EPA Document ID Nos. EPA-HQ-OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR-2004-0022-0448.
The standard that the EPA develops, based on the BSER, is commonly a numerical emissions limit, expressed as a performance level (in other words, a rate-based standard). As provided in CAA section 111(b)(5), the EPA does not prescribe a particular technological system that must be used to comply with a standard of performance. Rather, sources can select any measure or combination of measures that will achieve the emissions level of the standard.
CAA section 111(h)(1) authorizes the Administrator to promulgate “a design, equipment, work practice, or operational standard, or combination thereof” if in his or her judgment, “it is not feasible to prescribe or enforce a standard of performance.” CAA section 111(h)(2) provides the circumstances under which prescribing or enforcing a standard of performance is “not feasible”: Such as, when the pollutant cannot be emitted through a conveyance designed to emit or capture the pollutant, or when there is no practicable measurement methodology for the particular class of sources.
CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years review and, if appropriate, revise” performance standards unless the “Administrator determines that such review is not appropriate in light of readily available information on the efficacy” of the standard. As mentioned above, once the EPA lists a source category under CAA section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA discretion to determine the pollutants and sources to be regulated. In addition, concurrent with the 8-year review (and though not a mandatory part of the 8-year review), EPA may examine whether to add standards for pollutants or emission sources not currently regulated for that source category.

B. Regulatory Background
In 1979, the EPA published a list of source categories, which include “crude oil and natural gas production,” for which the EPA would promulgate standards of performance under CAA section 111(b) of the CAA. See Priority List and Additions to the List of Categories of Stationary Sources , 44 FR 49222 (August 21, 1979) (“1979 Priority List”). That list included, in the order of priority for promulgating standards, source categories that the EPA Administrator had determined, pursuant to CAA section 111(b)(1)(A), contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. See 44 FR at 49223, August 21, 1979; see also, 49 FR 2636-37, January 20, 1984.
On June 24, 1985 (50 FR 26122), the EPA promulgated an NSPS for the source category that addressed VOC emissions from leaking components at onshore natural gas processing plants (40 CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), a second NSPS was promulgated for the source category that regulates SO 2 emissions from natural gas processing plants (40 CFR part 60, subpart LLL). In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to review and, if appropriate, revise NSPS, the EPA published the final rule, “Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution” (40 CFR part 60, subpart OOOO) (“2012 NSPS”). The 2012 NSPS updated the SO 2 standards for sweetening units and VOC standards for equipment leaks at onshore natural gas processing plants. In addition, it established VOC standards for several oil and natural gas-related operations not covered by 40 CFR part 60, subparts KKK and LLL, including gas well completions, centrifugal and reciprocating compressors, natural gas-operated pneumatic controllers, and storage vessels. In 2013 and 2014, the EPA made certain amendments to the 2012 NSPS in order to improve implementation of the standards (78 FR 58416, September 23, 2013, and 79 FR 79018, December 31, 2014). The 2013 amendments focused on storage vessel implementation issues; the 2014 amendments provided clarification of well completion provisions which became fully effective on January 1, 2015. The EPA received petitions for both judicial review and administrative reconsiderations for the 2012 NSPS as well as the subsequent amendments in 2013 and 2014. The litigations are stayed pending the EPA's reconsideration process. ^{13}
^{13} In 2015, the EPA made further amendments to provisions relative to storage vessels and well completions (in particular low pressure wells). No judicial review or administrative reconsideration was sought for the 2015 amendments.
In this rulemaking, the EPA is addressing a number of issues raised in the administrative reconsideration petitions. ^{14} In addition to addressing the petitions requesting we reconsider our decision to defer regulation of GHGs, these topics, which mostly address implementation in 40 CFR part 60, subpart OOOO, are: Storage vessel control device monitoring and testing provisions; initial compliance requirements for a bypass device that could divert an emission stream away from a control device; recordkeeping requirements for repair logs for control devices failing a visible emissions test; clarification of the due date for the initial annual report; emergency flare exemption from routine compliance tests; LDAR for open-ended valves or lines; compliance period for LDAR for newly affected process units; exemption to notification requirement for reconstruction of most types of facilities; and disposal of carbon from control devices.
^{14} The EPA intends to complete its reconsideration process in a subsequent notice.

C. Other Notable Events
To provide relevant context to this final rule, EPA will discuss several notable events. First, in 2009 the EPA found that six well-mixed GHGs—carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 )—endanger both the public health and the public welfare of current and future generations by causing or contributing to climate change. Oil and natural gas operations are significant emitters of methane. According to data from the Greenhouse Gas Reporting Program (GHGRP), oil and natural gas operations are the second largest stationary source of GHG emissions in the United States (when including both methane emissions and combustion-related GHG emissions at oil and natural gas facilities), second only to fossil fuel electricity generation. See section IV of this preamble which discusses, among other issues, this endangerment finding in more detail.
Second, on August 16, 2012, the EPA published the 2012 NSPS (77 FR 49490). The 2012 NSPS included VOC standards for a number of emission sources in the oil and natural gas source category. Using information available at the time, the EPA also evaluated methane emissions and reductions during the 2012 NSPS rulemaking as a potential co-benefit of regulating VOC. Although information at the time indicated that methane emissions could be significant, the EPA did not take final action in the 2012 NSPS with respect to the regulation of GHG emissions; the EPA noted the impending collection of a large amount of GHG emissions data for this industry through the GHGRP (40 CFR part 98) and expressed its intent to continue its evaluation of methane. As stated previously, the 2012 NSPS was the subject of a number of petitions for judicial review and administrative reconsideration. Litigation is currently stayed pending the EPA's reconsideration process. Controlling methane emissions is an issue raised in several of the administrative petitions for the EPA's reconsideration.
Third, in June 2013, President Obama issued his Climate Action Plan, which included direction to the EPA and five other federal agencies to develop a comprehensive interagency strategy to reduce methane emissions. The plan recognized that methane emissions constitute a significant percentage of domestic GHG emissions, highlighted reductions in methane emissions since 1990, and outlined specific actions that could be taken to achieve additional progress.
Fourth, as a follow-up to the 2013 Climate Action Plan , the Administration issued the Climate Action Plan: Strategy to Reduce Methane Emissions (the Methane Strategy) in March 2014. The focus on reducing methane emissions reflects the fact that methane is a potent GHG with a 100-year GWP that is 28-36 times greater than that of carbon dioxide. ^{15} The GWP is a measure of how much additional energy the earth will absorb over 100 years as a result of emissions of a given gas, in relation to carbon dioxide. Methane has an atmospheric life of about 12 years, and because of its potency as a GHG and its atmospheric life, reducing methane emissions is an important step that can be taken to achieve a near-term beneficial impact in mitigating global climate change. The Methane Strategy instructed the EPA to release a series of white papers on several potentially significant sources of methane in the oil and natural gas sector and to solicit input from independent experts. The white papers were released in April 2014 and are discussed in more detail in section III.D of this preamble. 16 17
^{15} IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 1535 pp. For the analysis supporting this regulation, we used the methane 100-year GWP of 25 to be consistent with and comparable to key Agency emission quantification programs such as the Inventory of Greenhouse Gas Emissions and Sinks (GHG Inventory), and the Greenhouse Gas Reporting Program (GHGRP). For more information see Preamble section Methane Emissions in the United States and from the Oil and Natural Gas Industry.
^{16} http://www.epa.gov/airquality/oilandgas/methane.html.
^{17} Public comments on the white papers are available in the EPA's nonregulatory docket at http://www.regulations.gov , Docket ID No. EPA-HQ-OAR-2014-0557.
Finally, following the Climate Action Plan and the Methane Strategy, in January 2015, the Administration announced a new goal to cut methane emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025 and steps to put the United States on a path to achieve this ambitious goal. These actions encompass both commonsense standards and cooperative engagement with states, tribes, and industry. Building on prior actions by the Administration and leadership in states and industry, the announcement laid out a plan for the EPA to address, and if appropriate, propose and set standards for methane and ozone-forming emissions from new and modified sources and to issue Control Technique Guidelines (CTG) to assist states in reducing ozone-forming pollutants from existing oil and natural gas systems in areas that do not meet the health-based standard for ozone.

D. Stakeholder Outreach and Public Hearings

1. White Papers
As mentioned, the Methane Strategy was released in March 2014, as a follow-up to the 2013 Climate Action Plan , and directed the EPA to release a series of white papers on several potentially significant sources of methane in the oil and natural gas sector and solicit input from independent experts. The papers were released in April 2014, and the peer review process was completed on June 16, 2014.
The peer review, consisting of 26 sets of comments and more than 43,000 public comment submissions on the white papers, included additional technical information that further clarified our understanding of the emission sources and emission control options. ^{18} The comments also provided additional data on emissions and the number of sources and pointed out newly published studies that further informed our emission rate estimates. Where appropriate, we used the information and data provided to adjust the control options considered and the impacts estimates that are presented in the TSD to this final rule.
^{18} The comments received from the peer reviewers are available on the EPA's oil and natural gas white paper Web site ( http://www.epa.gov/airquality/oilandgas/methane.html ). Public comments on the white papers are available in the EPA's nonregulatory docket at www.regulations.gov , docket ID #EPA-HQ-OAR-2014-0557.

2. Outreach to State, Local and Tribal Governments
Throughout the rulemaking process, the EPA collaborated with state, local, and tribal governments to hear how they have managed regulatory issues and to receive feedback that would help us develop the rule. As discussed in the proposal, 12 states, three tribes, and several local air districts participated in several teleconferences in March and April 2015. The EPA hosted additional teleconferences in September 2015 with the same group of states, tribes, and air districts that the EPA spoke with earlier in the year. In September 2015, the EPA also hosted a webinar series with states, tribes, and interested communities to provide an overview of the proposed rule and an opportunity to ask clarifying questions on the proposal. ^{19}
^{19} See 80 FR 56609, September 18, 2015.
The EPA specifically consulted with tribal officials under the “EPA Policy on Consultation and Coordination with Indian Tribes” early in the process of developing this regulation to provide them with the opportunity to have meaningful and timely input into its development. Additionally, the EPA spoke with tribal stakeholders throughout the rulemaking process and updated the National Tribal Air Association on the Methane Strategy. Consistent with previous actions affecting the oil and natural gas sector, significant tribal interest exists because of the growth of oil and natural gas production in Indian country.

3. Public Hearings
The EPA hosted three public hearings on the proposed rule in September 2015. ^{20} The public hearings addressed this rule's proposal and two related actions. ^{21} All combined, approximately 329 people gave verbal testimony. The transcripts and written comments collected at the hearings are in the public docket for this final rule. ^{22}
^{20} See 80 FR 51991, August 27, 2015.
^{21} Source Determination for Certain Emission Units in the Oil and Natural Gas Sector; Review of New Sources and Modifications in Indian Country: Federal Implementation Plan for Managing Air Emissions from True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country.
^{22} See EPA Docket ID No. EPA-HQ-OAR-2010-0505.

E. Related State and Federal Regulatory Actions
As mentioned, these rules are designed to complement current state and other federal regulations. We carefully evaluated existing state and local programs when developing these federal standards and attempted, where possible, to limit potential conflicts with existing state and local requirements. We recognize that, in some cases, these federal rules may be more stringent than existing programs and, in other cases, may be less stringent than existing programs. We received over 900,000 comments on the proposed rule. After careful consideration of the comments, we are finalizing the standards with revisions where appropriate to reduce emissions of harmful air pollutants, promote gas capture and beneficial use, and provide opportunity for flexibility and expanded transparency in order to yield a consistent and accountable national program that provides a clear path for states and other federal agencies to further align their programs.
During development of these NSPS requirements, we were mindful that some facilities that will be subject to the standards will also be subject to current or future requirements of the Department of Interior's Bureau of Land Management (BLM) rules covering production of natural gas on federal lands. ^{23} To minimize confusion and unnecessary burden on the part of owners and operators, the EPA and the BLM have maintained an ongoing dialogue during development of this action to identify opportunities for aligning requirements and will continue to coordinate through BLM's final rulemaking and through the agencies' implementation of their respective rules. While we intend for our rule to complement the BLM's action, it is important to recognize that the EPA and the BLM are each operating under different statutory authorities and mandates in developing and implementing their respective rules.
^{23} See 81 FR 6616, February 8, 2016.
In addition to this final rule, the EPA is working to finalize other related actions. The EPA will finalize the Source Determination for Certain Emissions Units in the Oil and Natural Gas Sector rule, which will clarify the EPA's air permitting rules as they apply to the oil and natural gas industry. Additionally, the EPA plans to finalize the federal implementation plan for the EPA's Indian Country Minor New Source Review (NSR) program for oil and natural gas production sources and natural gas processing sources, which will require compliance with various federal regulations and streamline the permitting process for this rapidly growing industry in Indian country. Lastly, the EPA will also issue Control Techniques Guidelines (CTG) for reducing VOC emissions from existing oil and gas sources in certain ozone nonattainment areas and states in the Ozone Transport Region. This suite of requirements together will help combat climate change, reduce air pollution that harms public health, and provide greater certainty about CAA permitting requirements for the oil and natural gas industry.
Other related programs include the EPA's GHGRP, which requires annual reporting of GHG data and other relevant information from large sources and suppliers in the United States. On October 30, 2009, the EPA published 40 CFR part 98 for collecting information regarding GHG emissions from a broad range of industry sectors (74 FR 56260). Although reporting requirements for petroleum and natural gas systems (40 CFR part 98, subpart W) were originally proposed to be part of 40 CFR part 98 (75 FR 16448, April 10, 2009), the final October 2009 rule did not include the petroleum and natural gas systems source category as one of the 29 source categories for which reporting requirements were finalized. The EPA reproposed subpart W in 2010 (79 FR 18608, April 12, 2010), and a subsequent final rule was published on November 30, 2010, with the requirements for the petroleum and natural gas systems source category at 40 CFR part 98, subpart W (75 FR 74458). Following promulgation, the EPA finalized actions revising subpart W (76 FR 22825, April 25, 2011; 76 FR 59533, September 27, 2011; 76 FR 80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750, October 24, 2014; 79 FR 70352, November 25, 2014; 80 FR 64262, October 22, 2015).
40 CFR part 98, subpart W includes a wide range of operations and equipment, from wells to processing facilities, to transmission and storage and through to distribution pipelines. Subpart W consists of emission sources in the following segments of the petroleum and natural gas industry: Onshore petroleum and natural gas production, offshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas processing plants, onshore natural gas transmission compression, onshore natural gas transmission pipeline, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export equipment, and natural gas distribution.
On March 10, 2016, the EPA announced the next step in reducing emissions of GHGs, specifically methane, from the oil and natural gas industry: Moving to regulate emissions from existing sources. The Agency will begin with a formal process to require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce GHG emissions. ^{24} An Information Collection Request (ICR) will enable the EPA to gather important information on existing sources of GHG emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and natural gas sector. There are hundreds of thousands of existing oil and natural gas sources across the country; some emit small amounts of GHGs, but others emit very large quantities. Through the ICR, the EPA will be seeking a broad range of information that will help us determine how to effectively reduce emissions, including information such as how equipment and emissions controls are, or can be, configured, and what installing those controls entails. The EPA will also be seeking information that will help the Agency identify sources with high emissions and the factors that contribute to those emissions. The ICR will likely apply to the same types of sources covered by the 40 CFR part 60, subparts OOOO and OOOOa, as well as additional sources.
^{24} https://www3.epa.gov/airquality/oilandgas/pdfs/20160310fs.pdf.

IV. Regulatory Authority
In this section, we describe our authority under CAA section 111(b) to regulate emissions from operations and equipment used across the oil and natural gas industry.

A. The Oil and Natural Gas Source Category Listing Under CAA Section 111(b)(1)(A)
In 1979, the EPA published a list of source categories, including “crude oil and natural gas production,” for which the EPA would promulgate standards of performance under section 111(b) of the CAA. Priority List and Additions to the List of Categories of Stationary Sources, 44 FR 49222 (August 21, 1979) (“1979 Priority List”). The EPA published the 1979 Priority List as directed by a then new section 111(f) under the CAA amendments of 1977. Clean Air Act section 111(f) set a schedule for the EPA to promulgate regulations under CAA section 111(b)(1)(A); listing “categories of major stationary sources” and establishing standards of performance for the listed source categories in the order of priority as determined by the criteria set forth in CAA section 111(f). The 1979 Priority List included, in the order of priority for promulgating standards, source categories that the EPA Administrator had determined, pursuant to CAA section 111(b)(1)(A), to contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. See 44 FR 49222, August 21, 1979; see also 49 FR 2636-37, January 20, 1984. In developing the 1979 Priority List, the EPA first analyzed the data to identify “major source categories” and then ranked them in the order of priority for setting standards. Id. Although the EPA defined a “major source category” in that listing action as “those categories for which an average size plant has the potential to emit 100 tons or more per year of any one pollutant,” ^{25} the EPA provided notice in that action that “certain new sources of smaller than average size within these categories may have less than a 100 ton per year emission potential.” 43 FR 38872, 38873 (August 31, 1978). The EPA thus made clear that sources included within the listed source categories in the 1979 Priority List were not limited to sources that emit at or above the 100 ton level. The EPA's decision to not exclude smaller sources in the 1979 Priority List was consistent with CAA section 111(b), the statutory authority for that listing action and the required standard setting to follow. In requiring that the EPA list source categories and establish standards for the new sources within the listed source categories, CAA section 111(b) does not distinguish between “major” or other sources. Similarly, as an example, CAA section 111(e), which prohibits violation of an applicable standard upon its effective date, applies to “any new source,” not just major new sources.
^{25} 44 FR 49222, August 21, 1979.
As mentioned above, one of the source categories listed in that 1979 Priority List generally covers the oil and natural gas industry. Specifically, with respect to the natural gas industry, it includes production, processing, transmission, and storage. The 1979 Priority List broadly covered the natural gas industry, ^{26} which was evident in the EPA's analysis at the time of listing. ^{27} For example, the priority list analysis indicated that the EPA evaluated emissions from various segments of the natural gas industry, such as production and processing. The analysis also showed that the EPA evaluated equipment, such as stationary pipeline compressor engines that are used in various segments of the natural gas industry. The scope of the 1979 Priority List is further demonstrated by the Agency's pronouncements during the NSPS rulemaking that followed the listing. Specifically, in its description of this listed source category in the 1984 preamble to the proposed NSPS for equipment leaks at natural gas processing plants, the EPA described the major emission points of this source category to include process, storage, and equipment leaks; these emissions can be found throughout the various segments of the natural gas industry. 49 FR 2637, January 20, 1984. In addition, the EPA identified emission points not covered by that rulemaking, such as “well systems field oil and gas separators, wash tanks, settling tanks and other sources.” Id. The EPA explained in that action that it could not regulate these emissions at that time because “best demonstrated control technology has not been identified.” Id.
^{26} The process of producing natural gas for distribution involves operations in the various segments of the natural gas industry described above. In contrast, oil production involves drilling/extracting oil, which is immediately followed by distribution offsite to be made into different products.
^{27} See Standards of Performance for New Stationary Sources, 43 FR 38872 (August 31, 1978) and Priority List and Additions to the List of Categories of Stationary Sources, 44 FR 49222 (August 21, 1979).
The inclusion of various segments of the natural gas industry into the source category listed in 1979 is consistent with this industry's operations and equipment. Operations at production, processing, transmission, and storage facilities are a sequence of functions that are interrelated and necessary for getting the recovered gas ready for distribution. ^{28} Because they are interrelated, segments that follow others are faced with increases in throughput caused by growth in throughput of the segments preceding ( i.e., feeding) them. For example, the relatively recent substantial increases in natural gas production brought about by hydraulic fracturing and horizontal drilling result in increases in the amount of natural gas needing to be processed and moved to market or stored. These increases in production and throughput can cause increases in emissions across the entire natural gas industry. We also note that some equipment ( e.g., storage vessels, pneumatic pumps, compressors) are used across the oil and natural gas industry, which further supports considering the industry as one source category. For the reasons stated above, the 1979 Priority List broadly includes the various segments of the natural gas industry (production, processing, transmission, and storage).
^{28} The crude oil production segment of the source category, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline, is more limited in scope than the segments of the natural gas value chain included in the source category. However, increases in production at the well and/or increases in the number of wells coming on line, in turn increase throughput and resultant emissions, similarly to the natural gas segments in the source category.
Since issuing the 1979 Priority List, which broadly covers the oil and natural gas industry as explained above, the EPA has promulgated performance standards to regulate SO 2 emissions from natural gas processing and VOC emissions from certain operations and equipment in this industry. In this action, the EPA is regulating an additional pollutant ( i.e. , GHGs) as well as additional sources from this industry.
As explained above, the EPA, in 1979, determined under section 111(b)(1)(A) that the listed oil and natural gas source category contributes significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. Therefore, the 1979 listing of this source category provides sufficient authority for this action. The listed oil and natural gas source category includes oil ^{29} and natural gas production, processing, transmission, and storage. For the reasons stated above, the EPA believes that the 1979 listing of this source category provides sufficient authority for this action. However, to the extent that there is any ambiguity in the prior listing, the EPA hereby finalizes, as an alternative, its proposed revision of the category listing to broadly include the oil and natural gas industry. As revised, the listed oil and natural gas source category includes oil ^{30} and natural gas production, processing, transmission, and storage. In support, the EPA has included in this action the requisite finding under section 111(b)(1)(A) that, in the Administrator's judgment, this source category, as defined above, contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.
^{29} For the oil industry, the listing includes production, as explained above in footnote 27.
^{30} For the oil industry, the listing includes production, as explained above in footnote 27.
To be clear, the EPA's view is that no revision is required for the standards established in this final rule. But even assuming it is, for the reason stated below, there is ample evidence that this source category as a whole (oil and natural gas production, processing, transmission, and storage) contributes significantly to air pollution that may reasonably be anticipated to endanger public health and welfare.
First, through the 1979 Priority List, the EPA determined that the oil and natural gas industry contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. To the extent that the EPA's 1979 determination looked only at certain emissions sources in the industry, clearly the much greater emissions from the broader source category, as defined under a revised listing, would provide even more support for a conclusion that emissions from this category endanger public health or welfare. In addition, the EPA has included immediately below information and analyses regarding public health and welfare impacts from GHGs, VOC, and SO 2 emissions, three of the primary pollutants emitted from the oil and natural gas industry, and the estimated emissions of these pollutants from the oil and natural gas source category. It is evident from this information and analyses that the oil and natural gas source category contributes significantly to air pollution which may reasonably be anticipated to endanger public health and welfare. Therefore, to the extent such a finding were necessary, pursuant to section 111(b)(1)(A), the Administrator hereby determines that, in her judgment, this source category, as defined above, contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.
Provided below are the supporting information and analyses referenced above. Specifically, section IV.B of this preamble describes the public health and welfare impacts from GHGs, VOC and SO 2 . Section IV.C of this preamble analyzes the emission contribution of these three pollutants by the oil and natural gas industry.

B. Impacts of GHGs, VOC and SO 2 Emissions on Public Health and Welfare
The oil and natural gas industry emits a wide range of pollutants, including GHGs (such as methane and CO 2 ), VOC, SO 2 , nitrogen oxides (NO X ), hydrogen sulfide (H 2 S), carbon disulfide (CS 2 ) and carbonyl sulfide (COS). See 49 FR 2636, 2637 (January 20, 1984). Although all of these pollutants have significant impacts on public health and welfare, an analysis of every one of these pollutants is not necessary for the Administrator to make a determination under CAA section 111(b)(1)(A); as shown below, the EPA's analysis of GHGs, VOC, and SO 2 , three of the primary emissions from the oil and natural gas source category, is sufficient for the Administrator to determine under CAA section 111(b)(1)(A) that the oil and natural gas source category contributes significantly to air pollution which may reasonably be anticipated to endanger public health and welfare. ^{31}
^{31} We note that the EPA's focus on GHG (in particular methane), VOC, and SO 2 in these analyses, does not in any way limit the EPA's authority to promulgate standards that would apply to other pollutants emitted from the oil and natural gas source category, if the EPA determines in the future that such action is appropriate.

1. Climate Change Impacts From GHG Emissions
In 2009, based on a large body of robust and compelling scientific evidence, the EPA Administrator issued the Endangerment Finding under CAA section 202(a)(1). ^{32} In the 2009 Endangerment Finding, the Administrator found that the current, elevated concentrations of GHGs in the atmosphere—already at levels unprecedented in human history—may reasonably be anticipated to endanger the public health and welfare of current and future generations in the United States. We summarize these adverse effects on public health and welfare briefly here.
^{32} “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 74 FR 66496 (December 15, 2009) (“2009 Endangerment Finding”).

a. Public Health Impacts Detailed in the 2009 Endangerment Finding
Climate change caused by manmade emissions of GHGs threatens the health of Americans in multiple ways. By raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses. 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. Compared to a future without climate change, climate change is expected to increase ozone pollution over broad areas of the United States, especially on the highest ozone days and in the largest metropolitan areas with the worst ozone problems, and thereby increase the risk of morbidity and mortality. Climate change is also expected to cause more intense hurricanes and more frequent and intense storms 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. Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects.

b. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
Climate change impacts touch nearly every aspect of public welfare. Among the multiple threats caused by manmade emissions of GHGs, climate changes are expected to place large areas of the country at serious risk of reduced water supplies, increased water pollution, and increased occurrence of extreme events such as floods and droughts. Coastal areas are expected to face a multitude of increased risks, particularly from rising sea level and increases in the severity of storms. These communities face storm and flooding damage to property, or even loss of land due to inundation, erosion, wetland submergence, and habitat loss.
Impacts of climate change on public welfare also include threats to social and ecosystem services. Climate change is expected to result in an increase in peak electricity demand. Extreme weather from climate change threatens energy, transportation, and water resource infrastructure. Climate change may also exacerbate ongoing environmental pressures in certain settlements, particularly in Alaskan indigenous communities, and is very likely to fundamentally rearrange United States ecosystems over the 21st century. Though some benefits may help balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on United States food production, agriculture, and forest productivity as temperatures continue to rise. These impacts are global and may exacerbate problems outside the United States that raise humanitarian, trade, and national security issues for the United States.

c. New Scientific Assessments and Observations
Since the administrative record concerning the 2009 Endangerment Finding closed following the EPA's 2010 Reconsideration Denial, the climate has continued to change, with new records being set for a number of climate indicators such as global average surface temperatures, Arctic sea ice retreat, methane and other GHG concentrations, and sea level rise. Additionally, a number of major scientific assessments have been released that improve understanding of the climate system and strengthen the case that GHGs endanger public health and welfare both for current and future generations. These assessments, from the Intergovernmental Panel on Climate Change (IPCC), United States Global Change Research Program (USGCRP), and National Research Council (NRC), include: IPCC's 2012 Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (SREX) and the 2013-2014 Fifth Assessment Report (AR5), USGCRP's 2014 National Climate Assessment, Climate Change Impacts in the United States (NCA3), and the NRC's 2010 Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean (Ocean Acidification), 2011 Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia (Climate Stabilization Targets), 2011 National Security Implications for U.S. Naval Forces (National Security Implications), 2011 Understanding Earth's Deep Past: Lessons for Our Climate Future (Understanding Earth's Deep Past), 2012 Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future, 2012 Climate and Social Stress: Implications for Security Analysis (Climate and Social Stress), and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) assessments.
The EPA has carefully reviewed these recent assessments in keeping with the same approach outlined in section VIII.A of the 2009 Endangerment Finding, which was to rely primarily upon the major assessments by the USGCRP, IPCC, and the NRC to provide the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of United States government review.
The findings of the recent scientific assessments confirm and strengthen the conclusion that GHGs endanger public health, now and in the future. The NCA3 indicates that human health in the United States will be impacted by “increased extreme weather events, wildfire, decreased air quality, threats to mental health, and illnesses transmitted by food, water, and disease-carriers such as mosquitoes and ticks.” The most recent assessments now have greater confidence that climate change will influence production of pollen that exacerbates asthma and other allergic respiratory diseases such as allergic rhinitis, as well as effects on conjunctivitis and dermatitis. Both the NCA3 and the IPCC AR5 found that increased temperature lengthens the allergenic pollen season for ragweed and that increased CO 2 by itself elevates production of plant-based allergens.
The NCA3 also finds that climate change, in addition to chronic stresses such as extreme poverty, is negatively affecting indigenous peoples' health in the United States through impacts such as reduced access to traditional foods, decreased water quality, and increasing exposure to health and safety hazards. The IPCC AR5 finds that climate change-induced warming in the Arctic and resultant changes in environment ( e.g., permafrost thaw, effects on traditional food sources) have significant impacts, observed now and projected, on the health and well-being of Arctic residents, especially indigenous peoples. Small, remote, predominantly indigenous communities are especially vulnerable given their “strong dependence on the environment for food, culture, and way of life; their political and economic marginalization; existing social, health, and poverty disparities; as well as their frequent close proximity to exposed locations along ocean, lake, or river shorelines.” ^{33} In addition, increasing temperatures and loss of Arctic sea ice increases the risk of drowning for those engaged in traditional hunting and fishing.
^{33} IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, 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, p. 1581.
The NCA3 also finds that children's unique physiology and developing bodies contribute to making them particularly vulnerable to climate change. Impacts on children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. The IPCC AR5 indicates that children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. The IPCC finds that 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.
Both the NCA3 and IPCC AR5 conclude that climate change will increase health risks that the elderly will face. Older people are at much higher risk of mortality during extreme heat events. Pre-existing health conditions also make older adults more susceptible to cardiac and respiratory impacts of air pollution and to more severe consequences from infectious and waterborne diseases. Limited mobility among older adults can also increase health risks associated with extreme weather and floods.
The new assessments also confirm and strengthen the conclusion that GHGs endanger public welfare and emphasize the urgency of reducing GHG emissions due to their projections that show GHG concentrations climbing to ever-increasing levels in the absence of mitigation. The NRC assessment, Understanding Earth's Deep Past, stated that “the magnitude and rate of the present GHG increase place the climate system in what could be one of the most severe increases in radiative forcing of the global climate system in Earth history.” ^{34} Because of these unprecedented changes, several assessments state that we may be approaching critical, poorly understood thresholds. As stated in the NRC assessment, Understanding Earth's Deep Past, “[a]s Earth continues to warm, it may be approaching a critical climate threshold beyond which rapid and potentially permanent—at least on a human timescale—changes not anticipated by climate models tuned to modern conditions may occur.” The NRC Abrupt Impacts report analyzed abrupt climate change in the physical climate system and abrupt impacts of ongoing changes that, when thresholds are crossed, can cause abrupt impacts for society and ecosystems. The report considered destabilization of the West Antarctic Ice Sheet (which could cause 3 to 4 meters (m) of potential sea level rise) as an abrupt climate impact with unknown but low probability of occurring this century. The report categorized a decrease in ocean oxygen content (with attendant threats to aerobic marine life); increase in intensity, frequency, and duration of heat waves; and increase in frequency and intensity of extreme weather events (droughts, floods, hurricanes, and major storms) as climate impacts with moderate risk of an abrupt change within this century. The NRC Abrupt Impacts report also analyzed the threat of rapid state changes in ecosystems and species extinctions as examples of an irreversible impact that is expected to be exacerbated by climate change. Species at most risk include those whose migration potential is limited, whether because they live on mountaintops or fragmented habitats with barriers to movement, or because climatic conditions are changing more rapidly than the species can move or adapt. While the NRC determined that it is not presently possible to place exact probabilities on the added contribution of climate change to extinction, they did find that there was substantial risk that impacts from climate change could, within a few decades, drop the populations in many species below sustainable levels, thereby committing the species to extinction. Species within tropical and subtropical rainforests, such as the Amazon, and species living in coral reef ecosystems were identified by the NRC as being particularly vulnerable to extinction over the next 30 to 80 years, as were species in high latitude and high elevation regions. Moreover, due to the time lags inherent in the Earth's climate, the NRC Climate Stabilization Targets assessment notes that the full warming from increased GHG concentrations will not be fully realized for several centuries, underscoring that emission activities today carry with them climate commitments far into the future.
^{34} National Research Council, Understanding Earth's Deep Past, p. 138.
Future temperature changes will depend on what emission path the world follows. In its high emission scenario, the IPCC AR5 projects that global temperatures by the end of the century will likely be 2.6 °Celsius to 4.8 °Celsius (4.7° to 8.6 °F) warmer than today. Temperatures on land and in northern latitudes will likely warm even faster than the global average. However, according to the NCA3, significant reductions in emissions would lead to noticeably less future warming beyond mid-century and, therefore, less impact to public health and welfare.
While the amount of rainfall may not change significantly when looked at from the standpoint of global and annual averages, there are expected to be substantial shifts in where and when that precipitation falls. According to the NCA3, regions closer to the poles will see more precipitation while the dry subtropics are expected to expand (colloquially, this has been summarized as wet areas getting wetter and dry regions getting drier). In particular, the NCA3 notes that the western United States, and especially the Southwest, is expected to become drier. This projection is consistent with the recent observed drought trend in the West. At the time of publication of the NCA3, even before the last 2 years of extreme drought in California, tree ring data were already indicating that the region might be experiencing its driest period in 800 years. Similarly, the NCA3 projects that heavy downpours are expected to increase in many regions, with precipitation events in general becoming less frequent but more intense. This trend has already been observed in regions such as the Midwest, Northeast, and upper Great Plains. Meanwhile, the NRC Climate Stabilization Targets assessment found that the area burned by wildfire is expected to grow by 2 to 4 times for 1 °Celsius (1.8 °Fahrenheit) of warming. For 3 °Celsius of warming, the assessment found that nine out of 10 summers would be warmer than all but the 5 percent of warmest summers today; leading to increased frequency, duration, and intensity of heat waves. Extrapolations by the NCA3 also indicate that Arctic sea ice in summer may essentially disappear by mid-century. Retreating snow and ice, and emissions of carbon dioxide and methane released from thawing permafrost, will also amplify future warming.
Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple NRC assessments have projected future rates of sea level rise that are 40 percent larger to more than twice as large as the previous estimates from the 2007 IPCC 4th Assessment Report. This is due, in part, to improved understanding of the future rate of melt of the Antarctic and Greenland ice sheets. The NRC Sea Level Rise assessment projects a global sea level rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) by 2100. An NRC national security implications assessment suggests that “the Department of the Navy should expect roughly 0.4 to 2 meters (1.3 to 6.6 feet) global average sea-level rise by 2100,” ^{35} and the NRC Climate Stabilization Targets assessment states that an increase of 3 °Celsius will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 feet) by 2100. These assessments continue to recognize that there is uncertainty inherent in accounting for ice sheet processes: It is possible that the ice sheets could melt more quickly than expected, leading to more sea level rise than currently projected. Additionally, local sea level rise can differ from the global total depending on various factors: The east coast of the United States in particular is expected to see higher rates of sea level rise than the global average. For comparison, the NCA3 states that “five million Americans and hundreds of billions of dollars of property are located in areas that are less than four feet above the local high-tide level,” and the NCA3 finds that “[c]oastal infrastructure, including roads, rail lines, energy infrastructure, airports, port facilities, and military bases, are increasingly at risk from sea level rise and damaging storm surges.” ^{36} Also, because of the inertia of the oceans, sea level rise will continue for centuries after GHG concentrations have stabilized (though reducing GHG emissions will slow the rate of sea level rise and, therefore, reduce the associated risks and impacts). Additionally, there is a threshold temperature above which the Greenland ice sheet will be committed to inevitable melting: According to the NCA3, some recent research has suggested that even present day CO 2 levels could be sufficient to exceed that threshold.
^{35} NRC, 2011: National Security Implications of Climate Change for U.S. Naval Forces. The National Academies Press, p. 28.
^{36} Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. United States Global Change Research Program, p. 9.
In general, climate change impacts are expected to be unevenly distributed across different regions of the United States and have a greater impact on certain populations, such as indigenous peoples and the poor. The NCA3 finds climate change impacts such as the rapid pace of temperature rise, coastal erosion, and inundation related to sea level rise and storms, ice and snow melt, and permafrost thaw are affecting indigenous people in the United States. Particularly in Alaska, critical infrastructure and traditional livelihoods are threatened by climate change and, “[i]n parts of Alaska, Louisiana, the Pacific Islands, and other coastal locations, climate change impacts (through erosion and inundation) are so severe that some communities are already relocating from historical homelands to which their traditions and cultural identities are tied.” ^{37} The IPCC AR5 notes, “Climate-related hazards exacerbate other stressors, often with negative outcomes for livelihoods, especially for people living in poverty (high confidence). Climate-related hazards affect poor people's lives directly through impacts on livelihoods, reductions in crop yields, or destruction of homes and indirectly through, for example, increased food prices and food insecurity.” ^{38}
^{37} Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. United States Global Change Research Program, p. 17.
^{38} IPCC, 2014: 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, p. 796.
The impacts of climate change outside the United States, as also pointed out in the 2009 Endangerment Finding, will also have relevant consequences on the United States and our citizens. The NRC Climate and Social Stress assessment concluded that it is prudent to expect that some climate events “will produce consequences that exceed the capacity of the affected societies or global systems to manage and that have global security implications serious enough to compel international response.” The NRC National Security Implications assessment recommends preparing for increased needs for humanitarian aid; responding to the effects of climate change in geopolitical hotspots, including possible mass migrations; and addressing changing security needs in the Arctic as sea ice retreats.
In addition to future impacts, the NCA3 emphasizes that climate change driven by manmade emissions of GHGs is already happening now and that it is currently having effects in the United States. According to the IPCC AR5 and the NCA3, there are a number of climate-related changes that have been observed recently, and these changes are projected to accelerate in the future. The planet warmed about 0.85 °Celsius (1.5 °Fahrenheit) from 1880 to 2012. It is extremely likely (greater than 95-percent probability) that human influence was the dominant cause of the observed warming since the mid-20th century, and likely (greater than 66-percent probability) that human influence has more than doubled the probability of occurrence of heat waves in some locations. In the Northern Hemisphere, the last 30 years were likely the warmest 30 year period of the last 1,400 years. United States average temperatures have similarly increased by 1.3° to 1.9 °F since 1895, with most of that increase occurring since 1970. Global sea levels rose 0.19 meters (7.5 inches) from 1901 to 2010. Contributing to this rise was the warming of the oceans and melting of land ice. It is likely that 275 gigatons per year of ice melted from land glaciers (not including ice sheets) since 1993, and that the rate of loss of ice from the Greenland and Antarctic ice sheets increased substantially in recent years, to 215 gigatons per year and 147 gigatons per year, respectively, since 2002. For context, 360 gigatons of ice melt is sufficient to cause global sea levels to rise 1 millimeter (mm). Annual mean Arctic sea ice has been declining at 3.5 to 4.1 percent per decade, and Northern Hemisphere snow cover extent has decreased at about 1.6 percent per decade for March and 11.7 percent per decade for June. Permafrost temperatures have increased in most regions since the 1980s by up to 3 °Celsius (5.4 °Fahrenheit) in parts of northern Alaska. Winter storm frequency and intensity have both increased in the Northern Hemisphere. The NCA3 states that the increases in the severity or frequency of some types of extreme weather and climate events in recent decades can affect energy production and delivery, causing supply disruptions, and compromise other essential infrastructure such as water and transportation systems.
In addition to the changes documented in the assessment literature, there have been other climate milestones of note. According to the National Oceanic and Atmospheric Administration (NOAA), atmospheric methane concentrations in 2014 were about 1,823 parts per billion, 150 percent higher than methane concentrations were in the year 1750. After a few years of nearly stable concentrations from 1999 to 2006, methane concentrations have resumed increasing at about 5 parts per billion per year. Concentrations today are likely higher than they have been for at least the past 800,000 years. Arctic sea ice has continued to decline, with September of 2012 marking a new record low in terms of Arctic sea ice extent, 40 percent below the 1979 to 2000 median. Sea level has continued to rise at a rate of 3.2 mm per year (1.3 inches/decade) since satellite observations started in 1993, more than twice the average rate of rise in the 20th century prior to 1993. ^{39} Also, 2015 was the warmest year globally in the modern global surface temperature record, going back to 1880, breaking the record previously held by 2014; this now means that the last 15 years have been 15 of the 16 warmest years on record. ^{40}
^{39} Blunden, J., and D.S. Arndt, Eds., 2015: State of the Climate in 2014. Bull. Amer. Meteor. Soc., 96 (7), S1-S267.
^{40} http://www.ncdc.noaa.gov/sotc/global/201513 .
These assessments and observed changes make it clear that reducing emissions of GHGs across the globe is necessary in order to avoid the worst impacts of climate change and underscore the urgency of reducing emissions now. The NRC Committee on America's Climate Choices listed a number of reasons “why it is imprudent to delay actions that at least begin the process of substantially reducing emissions.” ^{41} For example:
^{41} NRC, 2011: America's Climate Choices, The National Academies Press.
• The faster emissions are reduced, the lower the risks posed by climate change. Delays in reducing emissions could commit the planet to a wide range of adverse impacts, especially if the sensitivity of the climate to GHGs is on the higher end of the estimated range.
• Waiting for unacceptable impacts to occur before taking action is imprudent because the effects of GHG emissions do not fully manifest themselves for decades and, once manifested, many of these changes will persist for hundreds or even thousands of years.
• In the committee's judgment, the risks associated with doing business as usual are a much greater concern than the risks associated with engaging in strong response efforts.
Methane is also a precursor to ground-level ozone, which can cause a number of harmful effects on health and the environment (see section IV.B.2 of this preamble). Additionally, ozone is a short-lived climate forcer that contributes to global warming. In remote areas, methane is a dominant precursor to tropospheric ozone formation. ^{42} Approximately 50 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane. ^{43} Projections of future emissions also indicate that methane is likely to be a key contributor to ozone concentrations in the future. ^{44} Unlike NO X and VOC, which affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane's relatively long atmospheric lifetime compared to these other ozone precursors. ^{45} Reducing methane emissions, therefore, will contribute to efforts to reduce global background ozone concentrations that contribute to the incidence of ozone-related health effects. 46 47 48 The benefits of such reductions are global and occur in both urban and rural areas.
^{42} U.S. EPA. 2013. “Integrated Science Assessment for Ozone and Related Photochemical Oxidants (Final Report).” EPA-600-R-10-076F. National Center for Environmental Assessment—RTP Division. Available at http://www.epa.gov/ncea/isa/ .
^{43} Myhre, G., D. Shindell, F.-M. Bréon, W. Collins, J. Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza, T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013: Anthropogenic and Natural Radiative Forcing. In: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. Pg. 680.
^{44} Ibid.
^{45} Ibid.
^{46} West, J.J., Fiore, A.M. 2005. “Management of tropospheric ozone by reducing methane emissions.” Environ. Sci. Technol. 39:4685-4691.
^{47} Anenberg, S.C., et al. 2009. “Intercontinental impacts of ozone pollution on human mortality,” Environ. Sci. & Technol. 43: 6482-6487.
^{48} Sarofim, M.C., Waldhoff, S.T., Anenberg, S.C. 2015. “Valuing the Ozone-Related Health Benefits of Methane Emission Controls,” Environ. Resource Econ. DOI 10.1007/s10640-015-9937-6.

2. VOC
Many VOC can be classified as HAP ( e.g., benzene ^{49} ) which can lead to a variety of health concerns such as cancer and noncancer illnesses ( e.g., respiratory, neurological). Further, VOC are one of the key precursors in the formation of ozone. Tropospheric, or ground-level, ozone is formed through reactions of VOC and NO X in the presence of sunlight. Ozone formation can be controlled to some extent through reductions in emissions of ozone precursors VOC and NO X . A significantly expanded body of scientific evidence shows that ozone can cause a number of harmful effects on health and the environment. Exposure to ozone can cause respiratory system effects such as difficulty breathing and airway inflammation. For people with lung diseases such as asthma and chronic obstructive pulmonary disease (COPD), these effects can lead to emergency room visits and hospital admissions. Studies have also found that ozone exposure is likely to cause premature death from lung or heart diseases. In addition, evidence indicates that long-term exposure to ozone is likely to result in harmful respiratory effects, including respiratory symptoms and the development of asthma. People most at risk from breathing air containing ozone include: Children; people with asthma and other respiratory diseases; older adults; and people who are active outdoors, especially outdoor workers. An estimated 25.9 million people have asthma in the United States, including almost 7.1 million children. Asthma disproportionately affects children, families with lower incomes, and minorities, including Puerto Ricans, Native Americans/Alaska Natives, and African-Americans. ^{50}
^{49} Benzene IRIS Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276 .
^{50} National Health Interview Survey (NHIS) Data, 2011. http://www.cdc.gov/asthma/nhis/2011/data.htm .
Scientific evidence also shows that repeated exposure to ozone can reduce growth and have other harmful effects on sensitive plants and trees. These types of effects have the potential to impact ecosystems and the benefits they provide.

3. SO 2
Current scientific evidence links short-term exposures to SO 2 , ranging from 5 minutes to 24 hours, with an array of adverse respiratory effects including bronchoconstriction and increased asthma symptoms. These effects are particularly important for asthmatics at elevated ventilation rates ( e.g., while exercising or playing).
Studies also show an association between short-term exposure and increased visits to emergency departments and hospital admissions for respiratory illnesses, particularly in at-risk populations including children, the elderly, and asthmatics.
SO 2 in the air can also damage the leaves of plants, decrease their ability to produce food—photosynthesis—and decrease their growth. In addition to directly affecting plants, SO 2 , when deposited on land and in estuaries, lakes, and streams, can acidify sensitive ecosystems resulting in a range of harmful indirect effects on plants, soils, water quality, and fish and wildlife ( e.g., changes in biodiversity and loss of habitat, reduced tree growth, loss of fish species). Sulfur deposition to waterways also plays a causal role in the methylation of mercury. ^{51}
^{51} U.S. EPA. Intergrated Science Assessment (ISA) for Oxides of Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S. Envieronmental Protection Agency, Washington, DC, EPA/600/R-08/082F, 2008.

C. GHGs, VOC and SO 2 Emissions From the Oil and Natural Gas Source Category
The previous section explains how GHGs, VOCs, and SO 2 emissions are “air pollution” that may reasonably be anticipated to endanger public health and welfare. This section provides estimated emissions of these substances from the oil and natural gas source category.

1. Methane Emissions in the United States and From the Oil and Natural Gas Industry
The GHGs addressed by the 2009 Endangerment Finding consist of six well-mixed gases, including methane. For the analysis supporting this regulation, we used the methane 100-year GWP of 25 to be consistent with and comparable to key Agency emission quantification programs such as the Inventory of United States Greenhouse Gas Emissions and Sinks (GHG Inventory), and the GHGRP. ^{52} The use of the 100-year GWP of 25 for methane value is currently required by the United Nations Framework Convention on Climate Change (UNFCCC) for reporting of national inventories, such as the United States GHG Inventory. Updated estimates for methane GWP have been developed by IPCC (2013). ^{53} The most recent 100-year GWP estimates for methane range from 28 to 36. In discussing the science and impacts of methane emissions generally, here we use the GWP range of 28 to 36. When presenting emissions estimates, we use the GWP of 25 for consistency and comparability with other emissions estimates in the United States and internationally. Methane has an atmospheric life of about 12 years.
^{52} See, for example, Table A-1 to subpart A of 40 CFR part 98.
^{53} IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 1535pp.
Official United States estimates of national level GHG emissions and sinks are developed by the EPA for the United States GHG Inventory to comply with commitments under the UNFCCC. The United States GHG Inventory, which includes recent trends, is organized by industrial sectors. Natural gas and petroleum systems are the largest emitters of methane in the United States. These systems emit 32 percent of United States anthropogenic methane.
Table 3 below presents total United States anthropogenic methane emissions for the years 1990, 2005, and 2014.
Table 3—United States Methane Emissions by Sector
[Million metric ton carbon dioxide equivalent (MMT CO 2 Eq.)]
Sector | 1990 | 2005 | 2014
Oil and Natural Gas Production, and Natural Gas Processing and Transmission | 201 | 203 | 232
Landfills | 180 | 154 | 148
Enteric Fermentation | 164 | 169 | 164
Coal Mining | 96 | 64 | 68
Manure Management | 37 | 56 | 61
Other Methane Sources ^{54} | 95 | 71 | 57
Total Methane Emissions | 774 | 717 | 731
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15, 2016), calculated using GWP of 25. Note: Totals may not sum due to rounding.
Oil and natural gas production and natural gas processing and transmission systems encompass wells, natural gas gathering and processing facilities, storage, and transmission pipelines. These components are all important aspects of the natural gas cycle—the process of getting natural gas out of the ground and to the end user. In the oil industry, some underground crude oil contains natural gas that is entrained in the oil at high reservoir pressures. When oil is removed from the reservoir, associated natural gas is produced.
^{54} Other sources include remaining natural gas distribution, petroleum transport and petroleum refineries, forest land, wastewater treatment, rice cultivation, stationary combustion, abandoned coal mines, petrochemical production, mobile combustion, composting, and several sources emitting less than 1 MMT CO 2 Eq. in 2013.
Methane emissions occur throughout the natural gas industry. They primarily result from normal operations, routine maintenance, fugitive leaks, and system upsets. As gas moves through the system, emissions occur through intentional venting and unintentional leaks. Venting can occur through equipment design or operational practices, such as the continuous bleed of gas from pneumatic controllers (that control gas flows, levels, temperatures, and pressures in the equipment), or venting from well completions during production. In addition to vented emissions, methane losses can occur from leaks (also referred to as fugitive emissions) in all parts of the infrastructure, from connections between pipes and vessels, to valves and equipment.
In petroleum systems, methane emissions result primarily from field production operations, such as venting of associated gas from oil wells, oil storage tanks, and production-related equipment such as gas dehydrators, pig traps, and pneumatic devices.
Tables 4 (a) and (b) below present total methane emissions from natural gas and petroleum systems, and the associated segments of the sector, for years 1990, 2005, and 2014, in MMT CO 2 Eq. (Table 4 (a)) and kilotons (or thousand metric tons) of methane (Table 4 (b)).
Table 4( a )—United States Methane Emissions From Natural Gas and Petroleum Systems
[MMT CO 2 ]
Sector | 1990 | 2005 | 2014
Oil and Natural Gas Production and Natural Gas Processing and Transmission (Total) | 201 | 203 | 232
Natural Gas Production | 83 | 108 | 109
Natural Gas Processing | 21 | 16 | 24
Natural Gas Transmission and Storage | 59 | 31 | 32
Petroleum Production | 38 | 48 | 67
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15, 2016), calculated using GWP of 25. Note: Totals may not sum due to rounding.
Table 4( b )—United States Methane Emissions From Natural Gas and Petroleum Systems
[kt CH 4 ]
Sector | 1990 | 2005 | 2014
Oil and Natural Gas Production and Natural Gas Processing and Transmission (Total) | 8,049 | 8,131 | 9,295
Natural Gas Production | 3,335 | 4,326 | 4,359
Natural Gas Processing | 852 | 655 | 960
Natural Gas Transmission and Storage | 2,343 | 1,230 | 1,282
Petroleum Production | 1,519 | 1,921 | 2,694
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15, 2016), in kt (1,000 tons) of CH 4 . Note: Totals may not sum due to rounding.

2. United States Oil and Natural Gas Production and Natural Gas Processing and Transmission GHG Emissions Relative to Total United States GHG Emissions
Relying on data from the United States GHG Inventory, we compared United States oil and natural gas production and natural gas processing and transmission GHG emissions to total United States GHG emissions as an indication of the role this source plays in the total domestic contribution to the air pollution that is causing climate change. In 2014, total United States GHG emissions from all sources were 6,871 MMT CO 2 Eq.
Table 5—Comparisons of United States Oil and Natural Gas Production and Natural Gas Processing and Transmission CH 4 Emissions to Total United States GHG Emissions
| 2010 | 2011 | 2012 | 2013 | 2014
Total U.S. Oil & Gas Production and Natural Gas Processing & Transmission methane Emissions (MMT CO 2 Eq.) | 207.0 | 214.3 | 218.8 | 228.0 | 232.4
Share of Total U.S. GHG Inventory | 3.0% | 3.1% | 3.3% | 3.4% | 3.4%
Total U.S. GHG Emissions (MMT CO 2 Eq.) | 6,985 | 6,865 | 6,643 | 6,800 | 6,870
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15, 2016), calculated using CH 4 GWP of 25. Note: Totals may not sum due to rounding.
In 2014, emissions from oil and natural gas production sources and natural gas processing and transmission sources accounted for 232.4 MMT CO 2 Eq. methane emissions (using a GWP of 25 for methane), accounting for 3.4 percent of total United States domestic GHG emissions. The natural gas and petroleum systems source is the largest emitter of methane in the United States. The sector also emitted 43 MMT of CO 2 , mainly from acid gas removal during natural gas processing (24 MMT) and flaring in oil and natural gas production (18 MMT). In total, these emissions (CH 4 and CO 2 ) account for 4.0 percent of total United States domestic GHG emissions.
Methane is emitted in significant quantities from the oil and natural gas production sources and natural gas processing and transmission sources that are being addressed within this rule.

3. United States Oil and Natural Gas Production and Natural Gas Processing and Transmission GHG Emissions Relative to Total Global GHG Emissions
Table 6—Comparisons of United States Oil and Natural Gas Production and Natural Gas Processing and Transmission CH 4 Emissions to Total Global GHG Emissions
| 2010 | 2011 | 2012 | 2013 | 2014
Total U.S. Oil & Gas Production and Natural Gas Processing & Transmission methane Emissions (MMT CO 2 Eq.) | 207.0 | 214.3 | 218.8 | 228.0 | 232.4
Share of Total U.S. GHG Inventory | 3.0% | 3.1% | 3.3% | 3.4% | 3.4%
Total U.S. GHG Emissions (MMT CO 2 Eq.) | 6,985 | 6,865 | 6,643 | 6,800 | 6,870
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15, 2016), calculated using CH 4 GWP of 25.
For additional background information and context, we used 2012 World Resources Institute/Climate Analysis Indicators Tool (WRI/CAIT) and International Energy Agency (IEA) data to make comparisons between United States oil and natural gas production and natural gas processing and transmission emissions and the emissions inventories of entire countries and regions. Though the United States methane emissions from oil and natural gas production and natural gas processing and transmission are a seemingly small fraction (0.5 percent) of total global emissions of all GHG from all sources, ranking United States emissions of methane from oil and natural gas production and natural gas processing and transmission against total GHG emissions for entire countries (using 2012 WRI/CAIT data), shows that these emissions are comparatively large as they exceed the national-level emissions totals for all GHG and all anthropogenic sources for Greece, the Czech Republic, Chile, Belgium, and about 150 other countries. ^{55} Furthermore, United States emissions of methane from oil and natural gas production and natural gas processing and transmission are greater than the sum of total emissions of 54 of the lowest-emitting countries, using the 2012 WRI/CAIT data set. ^{56}
^{55} WRI CAIT Climate Data Explorer. http://cait.wri.org/ . Accessed March 30, 2016.
^{56} Ibid.

4. Global GHG Emissions
Table 7—Comparisons of United States Oil and Natural Gas Production and Natural Gas Processing and Transmission CH 4 Emissions to Total Global Greenhouse Gas Emissions in 2012
| 2012 (MMT CO 2 Eq.) | Total U.S. oil and natural gas production and natural gas processing and transmission share (%)
Total Global GHG Emissions | 44,816 | 0.5
As illustrated by the domestic and global GHG comparison data summarized above, the collective GHG emissions from the oil and natural gas source category are significant, whether the comparison is domestic (where this sector is the largest source of methane emissions, accounting for 32 percent of United States methane and 3.4 percent of total United States emissions of all GHG), global (where this sector, while accounting for 0.5 percent of all global GHG emissions, emits more than the total national emissions of over 150 countries, and combined emissions of over 50 countries), or when both the domestic and global GHG emissions comparisons are viewed in combination. Consideration of the global context is important. GHG emissions from United States oil and natural gas production and natural gas processing and transmission will become globally well-mixed in the atmosphere, and thus will have an effect on the United States regional climate, as well as the global climate as a whole for years and indeed many decades to come.
As was the case in 2009, no single GHG source category dominates on the global scale. While the oil and natural gas source category, like many (if not all) individual GHG source categories, could appear small in comparison to total emissions, in fact, it is a very important contributor in terms of both absolute emissions, and in comparison to other source categories globally or within the United States.

5. VOC Emissions
The EPA National Emissions Inventory (NEI) estimated total VOC emissions from the oil and natural gas sector to be 2,729,942 tons in 2011. This ranks second of all the sectors estimated by the NEI and first of all the anthropogenic sectors in the NEI. These facts only serve to further the notion that emissions from the oil and natural gas sector contribute significantly to harmful air pollution.

6. SO 2 Emissions
The NEI estimated total SO 2 emissions from the oil and natural gas sector to be 74,266 tons in 2011. This ranks 13th of the sectors estimated by the NEI. Again, it is clear that emissions from the oil and natural gas sector contribute significantly to dangerous air pollution.

7. Conclusion
In summary, the 1979 Priority List broadly covers the oil and natural gas industry, including the production, processing, transmission, and storage of natural gas. As such, the 1979 Priority List covers all segments that we are regulating in this rule. To the extent that there is any ambiguity in the prior listing, the EPA hereby finalizes as an alternative its proposed revision of the category listing to broadly include the oil and natural gas industry. As revised, the listed oil and natural gas source category includes oil ^{57} and natural gas production, processing, transmission, and storage. Pursuant to CAA section 111(b)(1)(A), the Administrator has determined that, in her judgment, this source category, as defined above, contributes significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. In support, the EPA notes its previous determination under CAA section 111(b)(1)(A) for the oil and natural gas source category. In addition, the EPA provides in this section information and analyses detailing the public health and welfare impacts of GHG, VOC and SO 2 emissions and the amount of these emission from the oil and natural gas source category (in particular from the various segments of the natural gas industry). Although the EPA does not believe the revision to the category listing is required for the standards we are promulgating in this action, even assuming it is, the revision is well justified.
^{57} For the oil industry, the listing includes production, as explained above in footnote 27.

D. Establishing GHG Standards in the Form of Limitations on Methane Emissions
A petition for reconsideration of the 2012 NSPS urged that “EPA must reconsider its failure to adopt standards for the methane pollution released by the oil and gas sector.” ^{58} Upon reconsidering the issue, and with the benefit of additional information now available to us, the EPA is establishing GHG standards, in the form of limitations on methane emissions, throughout the oil and natural gas source category.
^{58} Sierra Club et al., Petition for Reconsideration, In the Matter of: Final Rule Published at 77 FR 49490 (August 16, 2012), titled “Oil and Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews; Final Rule,” Docket ID No. EPA-HQ-OAR-2010-0505, RIN 2060-AP76 (2012).
During the 2012 oil and natural gas NSPS rulemaking, we had a considerable amount of data and a good understanding of VOC emissions from the oil and natural gas industry and the available control options, but data on methane emissions were just emerging at that time. In light of the rapid expansion of this industry and the growing concern with the associated emissions, the EPA proceeded to establish a number of VOC standards in the 2012 NSPS, while indicating in the 2012 rulemaking an intent to revisit methane at a later date when additional information was available from the GHGRP.
We have since received and evaluated considerable additional data, which confirms that the oil and natural gas industry is one of the largest emitters of methane in the United States. As discussed in more detail in section IV.C of this preamble above, the current methane emissions from this industry contribute substantially to nationwide GHG emissions. And these emissions are expected to increase as a result of the rapid growth of this industry.
While the controls used to meet the VOC standards in the 2012 NSPS also reduce methane emissions incidentally, in light of the current and projected future GHG emissions from the oil and natural gas industry, reducing GHG emissions from this source category should not be treated simply as an incidental benefit to VOC reduction; rather, it is something that should be directly addressed through GHG standards in the form of limits on methane emissions under CAA section 111(b) based on direct evaluation of the extent and impact of GHG emissions from this source category and the emission reductions that can be achieved through the best system for their reduction. The standards detailed in this final action will achieve meaningful GHG reductions and will be an important step towards mitigating the impact of GHG emissions on climate change.
In addition, while many of the currently regulated emission sources are equipment used throughout the oil and natural gas industry ( e.g., pneumatic controllers, compressors) that emit both VOCs and methane, the VOC standards established in the 2012 NSPS apply only to the equipment located in the production and processing segments. As explained in the 2012 final rule, while our analysis suggested that the remaining pieces of equipment ( i.e., those in the transmission and storage segments) are also important to regulate, given the large number of these pieces of equipment and the relatively low level of VOC from individual equipment, the EPA decided that further evaluation is appropriate before taking final action. 77 FR 49490, 49521-2 (August 16, 2012). Based on its analyses in the current rulemaking, the EPA is taking final action to regulate VOC emitted from these remaining pieces of equipment. In addition, the EPA is setting GHG standards (by setting limitations on methane) for these pieces of equipment across the industry. As shown in the TSD, there are cost-effective controls that can simultaneously reduce both methane and VOC emissions from these equipment across the industry, and in many instances, they are cost effective even if all the costs are attributed to methane reduction. ^{59} Moreover, in addition to the reductions to be achieved, establishing both GHG and VOC standards for equipment across the industry will also promote consistency by providing the same regulatory regime for this equipment throughout the oil and natural gas source category for both VOC and GHG, thereby facilitating implementation and enforcement. ^{60} Therefore, based on the EPA's evaluation of methane reduction to address the impact of GHGs on climate change in conjunction with VOC reduction, the oil and gas NSPS, as finalized in this action, includes both VOC and GHG standards (in the form of limitations on methane) for a number of equipment across the oil and natural gas industry. It also includes VOC and GHG standards for a number of previously unregulated sources ( i.e., oil well completions, fugitive emissions at well sites and compressor stations, and pneumatic pumps).
^{59} In this action, we evaluated the controls under different approaches, including a single pollutant approach and a multi-pollutant approach, which are described in detail in the preamble to the proposed rule and the final TSD. Under a single pollutant approach, we attribute all costs to one pollutant and zero to the other.
^{60} While this final rule will result in additional reductions, as specified in sections II and IX of this preamble, the EPA often revises standards even where the revision will not lead to any additional reductions of a pollutant because another standard regulates a different pollutant using the same control equipment. For example, in 2014, the EPA revised the Kraft Pulp Mill NSPS in 40 CFR part 60 subpart BB published at 70 FR 18952 (April 4, 2014) to align the NSPS standards with the National Emission Standards for Hazardous Air Pollutants (NESHAP) standards for those sources in 40 CFR part 63, subpart S. Although no previously unregulated sources were added to the Kraft Pulp Mill NSPS, several emission limits were adjusted downward. The revised NSPS did not achieve additional reductions beyond those achieved by the NESHAP, but aligning the NSPS with the NEHSAP eased the compliance burden for the sources.
With respect to the GHG standards contained in this final rule, the EPA identifies the air pollutant as the pollutant GHGs. However, the standards in this rule that are specific to GHGs are expressed in the form of limits on emissions of methane, and not the other constituent gases of the air pollutant GHGs. ^{61} In this action, we are not establishing a limit on aggregate GHGs or separate emission limits for other GHGs that are not methane. This rule focuses on methane because, among other reasons, it is a GHG that is emitted in large quantities from the oil and gas industry, as explained above in section IV.C of this preamble. Notwithstanding this form of the standard, consistent with other EPA regulations addressing GHGs, the air pollutant regulated in this rule is GHGs; methane is limited as a constituent of the regulated pollutant, GHGs, not as a separate pollutant. This approach is consistent with the approach EPA followed in setting limits for new electric generating units. ^{62} Additional regulatory language has been added to 40 CFR 60.5360a to clarify and confirm that GHGs is the regulated pollutant.
^{61} In the 2009 GHG Endangerment Finding, the EPA defined the relevant “air pollution” as the atmospheric mix of six long-lived and directly emitted GHGs: CO 2 , CH 4 , N 2 O, HFCs, PFCs, and SF 6 . 74 FR 66497, December 15, 2009.
^{62} See 80 FR 64510 (October 23, 2015).
The EPA's authority for regulating GHGs in this rule is CAA section 111(b)(1). As discussed above, under the statutory structure of CAA section 111(b), the Administrator first lists source categories pursuant to CAA section 111(b)(1)(A), and then promulgates, under CAA section 111(b)(1)(B), “standards of performance for new sources within such category.”
In this rule, the EPA is establishing standards under CAA section 111(b)(1)(B) for a source category that it has previously listed and regulated for other pollutants and which now is being regulated for an additional pollutant. ^{63} Because of this, there are two aspects of CAA section 111(b)(1) that warrant particular discussion.
^{63} As explained in more detail in section IV.A of this preamble, the EPA interprets the 1979 category listing to broadly cover the oil and natural gas industry. Thus, this discussion focuses on EPA's authority to regulate an additional pollutant (specifically GHG) emitted from a previously listed source category. However, to the extent that any ambiguity exists in the 1979 listing, and as also explained above, EPA is finalizing its alternative proposal to revise the category listing to broadly cover the oil and natural gas industry. In support, the Administrator has determined in this action, pursuant to CAA section 111(b)(1)(A), that the listed source category, as defined in the revision, contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, the category listing and the Administrator's determination (to the extent they are necessary) provide authority for standards we are promulgating in this final rule, including the standards for GHG.
First, because the EPA is not listing a new source category in this rule, ^{64} the EPA is not required to make a new endangerment finding with regard to the oil and natural gas source category in order to establish standards of performance for an additional pollutant from those sources. Under the plain language of CAA section 111(b)(1)(A), an endangerment finding is required only to list a source category. Though the endangerment finding is based on determinations as to the health or welfare impacts of the pollution to which the source category's pollutants contribute, and as to the significance of the amount of such contribution, the statute is clear that the endangerment finding is made with respect to the source category; CAA section 111(b)(1)(A) does not provide that an endangerment finding is made as to specific pollutants. This contrasts with other CAA provisions that do require the EPA to make endangerment findings for each particular pollutant that the EPA regulates under those provisions ( e.g., CAA sections 202(a)(1), 211(c)(1), 231(a)(2)(A). See American Electric Power v. Connecticut, 131 S. Ct. 2527, 2539 (2011) (“the Clean Air Act directs EPA to establish emissions standards for categories of stationary sources that, ‘in [the Administrator's] judgment,’ ‘caus[e], or contribut[e] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.’ § 7411(b)(1)(A).”) (emphasis added).
^{64} See section IV.A of this preamble.
Second, once a source category is listed, the CAA does not specify what pollutants should be the subject of standards from that source category. The statute, in CAA section 111(b)(1)(B) simply directs the EPA to propose and then promulgate regulations “establishing Federal standards of performance for new sources within such category.” In the absence of specific direction or enumerated criteria in the statute concerning what pollutants from a given source category should be the subject of standards, it is appropriate for the EPA to exercise its authority to adopt a reasonable interpretation of this provision. Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 (1984). ^{65}
^{65} In Chevron, the United States Supreme Court held that an agency must, at Step 1, determine whether Congress's intent as to the specific matter at issue is clear, and, if so, the agency must give effect to that intent. If Congressional intent is not clear, then, at Step 2, the agency has discretion to fashion an interpretation that is a reasonable construction of the statute.
The EPA has previously interpreted this provision as granting it the discretion to determine which pollutants should be regulated. See Standards of Performance for Petroleum Refineries, 73 FR 35838, 35858 (June 24, 2008) (concluding the statute provides “the Administrator with significant flexibility in determining which pollutants are appropriate for regulation under section 111(b)(1)(B)” and citing cases). Further, in directing the Administrator to propose and promulgate regulations under CAA section 111(b)(1)(B), Congress provided that the Administrator should take comment and then finalize the standards with such modifications “as [s]he deems appropriate.” The D.C. Circuit has considered similar statutory phrasing from CAA section 231(a)(3) and concluded that “[t]his delegation of authority is both explicit and extraordinarily broad.” National Assoc. of Clean Air Agencies v. EPA , 489 F.3d 1221, 1229 (D.C. Cir. 2007).
In exercising its discretion with respect to which pollutants are appropriate for regulation under CAA section 111(b)(1)(B), the EPA has in the past provided a rational basis for its decisions. See National Lime Assoc . v. EPA , 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (court discussed, but did not review, the EPA's reasons for not promulgating standards for NO X , SO 2 , and CO from lime plants); Standards of Performance for Petroleum Refineries, 73 FR 35859-60 (June 24, 2008) (providing reasons why the EPA was not promulgating GHG standards for petroleum refineries as part of that rule). Though these previous examples involved the EPA providing a rational basis for not setting standards for a given pollutant, a similar approach is appropriate where the EPA determines that it should set a standard for an additional pollutant for a source category that was previously listed and regulated for other pollutants. The EPA took this approach in setting limits for new electric generating units. ^{66} The EPA interprets CAA section 111(b)(1)(B) to provide authority to establish a standard for performance for any pollutant emitted by that source category as long as the EPA has a rational basis for setting a standard for the pollutant. In making such determination, we have generally considered a number of factors to help inform our decision. These include the amount of the pollutant that is being emitted from the source category, the availability of technically feasible control options, and the costs of those control options. ^{67}
^{66} 80 FR 64510, 64529-30, October 23, 2015.
^{67} See 80 FR 56593, 56600-09, (section VI of the proposed rule) and 56616-45, September 18, 2015 (section VIII of the proposed rule).
In this rulemaking, the EPA has a rational basis for concluding that GHGs from the oil and natural gas source category, which is a large category of sources of GHG emissions, merit regulation under CAA section 111. In making this determination, the EPA focuses on methane emissions from this category. The information summarized here and discussed in other sections of this preamble provides the rational basis for the GHG standards, expressed as limitations on methane, established in this action. ^{68}
^{68} Specifically, Sections IV.B and C, V, and VI of this final rule.
In 2009, the EPA made a finding that GHG air pollution may reasonably be anticipated to endanger public health or welfare under section 202(a) of the CAA ^{69} and, in 2010, the EPA denied petitions to reconsider that finding. The EPA extensively reviewed the available science concerning GHG pollution and its impacts in taking those actions. In 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the finding and the denial of petitions to reconsider. ^{70} In addition, assessments released by the Intergovernmental Panel on Climate Change (IPCC), the USGCRP, and the NRC, and other organizations published after 2010 lend further credence to the validity of the 2009 Endangerment Finding. No information that commenters have presented or that the EPA has reviewed provides a basis for reaching a different conclusion for purposes of this action. Indeed, current and evolving science discussed in detail in sections IV.B and C of this preamble is confirming and enhancing our understanding of the near- and longer-term impacts that elevated concentrations of GHGs, including methane, are having on Earth's climate and the adverse public health, welfare, and economic consequences that are occurring and are projected to occur as a result.
^{69} 74 FR 66496 (December 15, 2009).
^{70} Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 119-126 (D.C. Circuit 2012).
Moreover, the high quantities of methane emissions from the oil and natural gas source category demonstrate that it is rational for the EPA to set methane limitations to regulate GHG emissions from this sector. The oil and natural gas source category is the largest emitter of methane in the United States, contributing about 29 percent of total United States methane emissions. The methane that this source category emits accounts for 3 percent of all United States GHG emissions. As shown in Tables 4 and 5 in this preamble, oil and gas sources are very large emitters of methane: In fact, GWP-weighted emissions of methane from these sources are larger than emissions of all GHGs from about 150 countries. Methane is a GHG with a global warming potential 28 to 36 times greater than that of CO 2 . ^{71} When considered in total, the facts presented in sections IV.B and C of this preamble, along with prior EPA analysis, including that found in the 2009 Endangerment Finding, provide a rational basis for regulating GHG emissions from affected oil and gas sources by expressing GHG limitations in the form of limits on methane emissions.
^{71} IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 1535 pp. Note that for purposes of inventories and reporting, GWP values from the 4th Assessment Report may be used. For the purposes of calculating GHG emissions, the GWP value published on Table A-1 to subpart A of 40 CFR part 98 should still be used.
To reiterate, the “air pollution” defined in the 2009 Endangerment Finding is the atmospheric mix of six long-lived and directly emitted GHGs: CO 2 , CH 4 , N 2 O, HFCs, PFCs, and SF 6 . ^{72} This is the same pollutant that is regulated by this rule. However, the standards of performance adopted in the present rulemaking address only one constituent gas of this air pollution: Methane. This is reasonable, given that methane is the constituent gas emitted in the largest volume by the source category and for which there are available controls that are technically feasible and cost effective. There is no requirement that standards of performance address each component of an air pollutant. Clean Air Act section 111(b)(1)(B) requires the EPA to establish “standards of performance” for listed source categories, and the definition of “standard of performance” in CAA section 111(a)(1) does not specify which air pollutants must be controlled. So, while the limitations in this rule are expressed as limits on methane, the pollutant regulated is GHGs.
^{72} See 74 FR 66496, 66497 (December 15, 2009).
Some commenters have argued that the EPA is required to make a new endangerment finding before it may set limitations for methane from the oil and natural gas source category. We disagree, for the reasons discussed above. Moreover, even if CAA section 111 required the EPA to make an endangerment finding as a prerequisite for this rulemaking, then, the information and conclusions described above in sections IV.B and C of this preamble should be considered to constitute the requisite finding (which includes a finding of endangerment as well as a cause-or-contribute significantly finding). The same facts that support our rational basis determination would support such a finding. The EPA's rational basis for regulating GHGs, by setting methane limitations, under CAA section 111 is based primarily on the analysis and conclusions in the EPA's 2009 Endangerment Finding and 2010 denial of petitions to reconsider that Finding, coupled with the subsequent assessments from the IPCC, USGCRP, and NRC that describe scientific developments since those EPA actions and other facts contained herein.
More specifically, our approach here—reflected in the information and conclusions described above—is substantially similar to that reflected in the 2009 Endangerment Finding and the 2010 denial of petitions to reconsider. The D.C. Circuit upheld that approach in Coalition for Responsible Regulation v. EPA , 684 F.3d 102, 117-123 (D.C. Cir. 2012) (noting, among other things, the “substantial . . . body of scientific evidence marshaled by EPA in support of the Endangerment Finding” (id. at 120); the “substantial record evidence that anthropogenic emissions of greenhouse gases very likely caused warming of the climate over the last several decades” (id. at 121); “substantial scientific evidence . . . that anthropogenically induced climate change threatens both public health and public welfare . . . [through] extreme weather events, changes in air quality, increases in food- and water-borne pathogens, and increases in temperatures” (id.); and “substantial evidence . . . that the warming resulting from the greenhouse gas emissions could be expected to create risks to water resources and in general to coastal areas. . . .” (id.)). The facts, unfortunately, have only grown stronger and the potential adverse consequences of GHG to public health and the environment more dire in the interim. ^{73} The facts also demonstrate that the current methane emissions from oil and natural gas production sources and natural gas processing and transmission sources contribute substantially to nationwide GHG emissions.
^{73} Nor does the EPA consider the cost of potential standards of performance in making this finding. Like the endangerment finding under section 202(a) at issue in State of Massachusetts v. EPA, 549 U.S. 497 (2007), the pertinent issue is a scientific inquiry as to whether an endangerment to public health or welfare from the relevant air pollution may reasonably be anticipated. Where, as here, the scientific inquiry conducted by the EPA indicates that these statutory criteria are met, the Administrator does not have discretion to decline to make a positive endangerment finding to serve other policy grounds. Id. at 532-35. In this regard, an endangerment finding is analogous to setting national ambient air quality standards under CAA section 109(b), which similarly call on the Administrator to set standards that in her “judgment” are “requisite to protect the public health”. The EPA is not permitted to consider potential costs of implementation in setting these standards. Whitman v. American Trucking Assn's, 531 U.S. 457, 466 (2001); see also Michigan v. EPA , U.S. (no. 14-46, June 29, 2015) slip op. pp. 10-11 (reiterating Whitman holding). The EPA notes further that section 111(b)(1) contains no terms such as “necessary and appropriate” which could suggest (or, in some contexts, require) that costs may be considered as part of the finding. Compare CAA section 112(n)(1)(A); see State of Michigan, slip op. pp. 7-8. The EPA, of course, must consider costs in determining whether a best system of emission reduction is adequately demonstrated and so can form the basis for a section 111(b) standard of performance, and the EPA has carefully considered costs here and found them to be reasonable. See sections V and VI below. The EPA also has found that the rule's quantifiable benefits exceed regulatory costs under a range of assumptions were new capacity to be built. See RIA. Accordingly, this endangerment finding would be justified if (against our view) it is both required, and (again, against our view) costs are to be considered as part of the finding.
The EPA also reviewed comments presenting other scientific information to determine whether that information has any meaningful impact on our analysis and conclusions. For both the rational basis analysis and for any endangerment finding, assuming for the sake of argument that one would be necessary for this final rule, the EPA focused on public health and welfare impacts within the United States, as it did in the 2009 Endangerment Finding. The impacts in other world regions strengthen the case because impacts in other world regions can in turn adversely affect the United States and its citizens. ^{74}
^{74} See 74 FR 66514 and 66535, December 15, 2009.
Lastly, EPA identified technically feasible and cost effective controls that can be applied nationally to reduce methane emissions and, thus, GHG emissions, from the oil and natural gas source category.
The EPA considered whether the costs ( e.g., capital costs, operating costs) are reasonable considering the emission reductions achieved through application of the controls required. For a detailed discussion on how we evaluated control costs and our cost analysis for individual emission sources, please see the proposal and the final TSD in the public docket.

V. Summary of Final Standards
This section presents a summary of the specific standards we are finalizing for various types of equipment and emission points. More details of the rationale for these standards and requirements, including alternative compliance options and exemptions to the standards, are provided in sections VI, VII, and VIII of this preamble, the TSD, and the RTC document in the public docket.

A. Control of GHG and VOC Emissions in the Oil and Natural Gas Source Category—Overview
In this action, the EPA is finalizing emission standards for GHG, in the form of limitations on methane, and VOC emissions, for certain new, modified and reconstructed emission sources across the oil and natural gas source category at subpart OOOOa. For some of these sources, there are VOC requirements currently in place that were established in the 2012 NSPS, and we are now establishing GHG limitations for those emission points. For others, for which there are no current requirements, we are finalizing both GHG and VOC standards. We are also finalizing improvements to enhance implementation of the current standards at subpart OOOO. For the reasons explained in the previous section, the EPA believes that GHG standards, in the form of limitations on methane, are warranted, even for those already subject to VOC standards under the 2012 NSPS. Further, as shown in the final TSD, there are cost effective controls that achieve simultaneous reductions of GHG and VOC emissions.
Pursuant to CAA section 111(b), we are both amending subpart OOOO and adding a new subpart, OOOOa. We are amending subpart OOOO, which applies to facilities constructed, modified or reconstructed after August 23, 2011, ( i.e., the original proposal date of subpart OOOO) and on or before September 18, 2015 ( i.e., the proposal date of the new subpart OOOOa), and is amended only to include the revisions reflecting implementation improvements in response to issues raised in petitions for reconsideration. We are adding subpart OOOOa, which will apply to facilities constructed, modified or reconstructed after September 18, 2015, to include current VOC requirements already provided in subpart OOOO (as updated) as well as new provisions for GHGs and VOCs across the oil and natural gas source category as highlighted below in this section.
As the purpose of this action is to control and limit emissions of GHG and VOC, EPA seeks to confirm that all regulatory standards are met. Any owner or operator claiming technical infeasibility, nonapplicability, or exemption from the regulation has the burden to demonstrate the claim is reasonable based on the relevant information. In any subsequent review of a technical infeasibility or nonapplicability determination, or a claimed exemption, EPA will independently assess the basis for the claim to ensure flaring is limited and emissions are minimized, in compliance with the rule. Well-designed rules ensure fairness among industry competitors and are essential to the success of future enforcement efforts.

B. Centrifugal Compressors
We are finalizing amendments to the 2012 NSPS, and adding new requirements to establish both VOC and GHG standards (in the form of limitations on methane emissions) for new, modified or reconstructed wet seal centrifugal compressors located across the oil and natural gas source category. Specifically, the final rule adds GHG standards to the current VOC standards for wet seal centrifugal compressors, as well as establishing GHG and VOC standards for those that are currently unregulated, with one exception. We are not establishing requirements for centrifugal compressors at well sites. As finalized, the standards require a 95 percent reduction of the emissions from each wet seal centrifugal compressor affected facility. The standard can be achieved by capturing and routing the emissions, using a cover and closed vent system, to a control device that achieves an emission reduction of 95 percent, or routing to a process.

C. Reciprocating Compressors
We are finalizing amendments to the 2012 NSPS and adding new requirements to establish both VOC and GHG standards (in the form of limitations on methane emissions) for new, modified, or reconstructed reciprocating compressors located across the oil and natural gas source category. Specifically, the final rule adds GHG standards to the current VOC standards for reciprocating compressors, as well as establishing GHG and VOC standards for those that are currently unregulated, with one exception. We are not establishing requirements for reciprocating compressors at well sites. The standards, which are operational standards, require either replacement of the rod packing based on usage or routing of rod packing emissions to a process via a closed vent system under negative pressure. The owner or operator of a reciprocating compressor affected facility is required to monitor the duration (in hours) that the compressor is operated, beginning on the date of initial startup of the reciprocating compressor affected facility. On or before 26,000 hours of operation, the owner or operator is required to change the rod packing. Owners or operators can elect to change the rod packing every 36 months in lieu of monitoring compressor operating hours. As an alternative to rod packing replacement, owners and operators may route the rod packing emissions to a process via a closed vent system operated at negative pressure.

D. Pneumatic Controllers
We are finalizing amendments to the 2012 NSPS and adding new requirements to establish both VOC and GHG standards (in the form of limitations on methane emissions) for new, modified, or reconstructed pneumatic controllers located across the oil and natural gas source category. Specifically, the final rule adds GHG standards to the current VOC standards for pneumatic controllers and establishes GHG and VOC standards for those that are currently unregulated. We are finalizing GHG (in the form of limitations on methane emissions) and VOC standards to control emissions by requiring use of low-bleed controllers in place of high-bleed controllers ( i.e. , natural gas bleed rate not to exceed 6 standard cubic feet per hour (scfh)) at all locations within the source category except for natural gas processing plants. For natural gas processing plants, we are finalizing standards to control GHG and VOC emissions by requiring that pneumatic controllers have a zero natural gas bleed rate ( i.e., they are operated by means other than natural gas, such as being driven by compressed instrument air). These standards apply to each newly installed, modified or reconstructed pneumatic controller (including replacement of an existing controller). The finalized standards provide exemptions for certain critical applications based on functional considerations.

E. Pneumatic Pumps
We are finalizing standards for natural gas-driven diaphragm pumps. ^{75} The standards require that GHGs (in the form of limitations on methane emissions) and VOC emissions from new, modified and reconstructed natural gas-driven diaphragm pumps located at well sites be reduced by 95 percent if either a control device or the ability to route to a process is already available onsite, unless it is technically infeasible at sites other than new developments ( i.e. , greenfield sites). In setting this requirement, the EPA recognizes that there may not be a control device or process available onsite. Our analysis shows that it is not cost-effective to require the owner or operator of a pneumatic pump affected facility to install a new control device or process onsite to capture emissions. If a control device or ability to route to a process is not available onsite, the pneumatic pump affected facility is not subject to the emission reduction provisions of the final rule. In other instances, there may be a control device available onsite, but it may not be capable of achieving a 95 percent reduction. In those cases, we are not requiring the owner or operator to install a new control device onsite or to retrofit the existing control device, however, we are requiring the owner or operator of a pneumatic pump affected facility at a well site to route the emissions to an existing control device even it if achieves a level of emissions reduction less than 95 percent. In those instances, the owner or operator must maintain records demonstrating the percentage reduction that the control device is designed to achieve. In this way, the final rule will achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device cannot achieve a 95 percent reduction. For pneumatic pumps located at natural gas processing plants, the standards require that GHG and VOC emissions from natural gas-driven diaphragm pumps be zero.
^{75} A lean glycol circulation pump that relies on energy exchange with the rich glycol from the contactor is not considered a diaphragm pump. For more details, please see section VI.

F. Well Completions
We are finalizing GHG standards (in the form of limiting methane emissions) for well completions of hydraulically fractured (or refractured) gas wells as well as GHG and VOC standards for well completions of hydraulically fractured (or refractured) oil wells. As explained in the proposal preamble, the BSER for these emission reductions are the same as the BSER for reducing VOC emissions from hydraulically fractured gas wells. Therefore, the operational standards finalized in this action are essentially the same as the VOC standards for hydraulically fractured gas wells promulgated in the 2012 NSPS. For the reason stated above, the well completion standards in this final rule apply to both gas and oil well completions.
As with gas wells, for well completions of hydraulically fractured (or refractured) oil wells, we identified two subcategories of hydraulically fractured wells for which well completions are conducted: (1) Non-wildcat and non-delineation wells (subcategory 1 wells); and (2) wildcat and delineation wells (subcategory 2 wells). A wildcat well, also referred to as an exploratory well, is a well drilled outside known fields or is the first well drilled in an oil or gas field where no other oil and gas production exists. A delineation well is a well drilled to determine the boundary of a field or producing reservoir.
We are finalizing operational standards for subcategory 1 wells that require a combination of reduced emissions completion (REC) and combustion. Compared to combustion alone, the combination of REC and combustion will maximize gas recovery and minimize venting to the atmosphere. The finalized standards for subcategory 2 wells require combustion.
For subcategory 1 wells, we define the flowback period of a well completion as consisting of two distinct stages, the “initial flowback stage” and the “separation flowback stage.” The initial flowback stage begins with the onset of flowback and ends when the flowback is routed to a separator. Routing of the flowback to a separator is required as soon as a separator is able to function ( i.e. , the operator must route the flowback to a separator unless it is technically infeasible for a separator to function). Any gas in the flowback prior to the point at which a separator begins functioning is not subject to control. The point at which the separator can function marks the beginning of the separation flowback stage. During this stage, the operator must do the following, unless technically infeasible to do so as discussed below: (1) Route all salable quality gas from the separator to a gas flow line or collection system; (2) re-inject the gas into the well or another well; (3) use the gas as an onsite fuel source; or (4) use the gas for another useful purpose that a purchased fuel or raw material would serve. If the operator assesses all four options for use of recovered gas, and still finds it technically infeasible to route the gas as described, the operator must route the gas to a completion combustion device with a continuous pilot flame and document the technical infeasibility assessment according to § 60.5420a(c) of this final rule, which describes the specific types of information required to document that the operator has exercised due diligence in making the assessment. No direct venting of gas is allowed during the separation flowback stage unless combustion creates a fire or safety hazard or can damage tundra, permafrost or waterways. The separation flowback stage ends when the well is shut in and the flowback equipment is permanently disconnected from the well or on startup of production. This also marks the end of the flowback period.
The operator has a general duty to safely maximize resource recovery and minimize releases to the atmosphere over the duration of the flowback period. For subcategory 1 wells (except for low gas to oil ratio (GOR) and low pressure wells discussed below), the operator is required to have a separator onsite during the entirety of the flowback period. The operator is also required to document the stages of the completion operation by maintaining records of (1) the date and time of the onset of flowback; (2) the date and time of each attempt to route flowback to the separator; (3) the date and time of each occurrence in which the operator reverted to the initial flowback stage; (4) the date and time of well shut in; and (5) the date and time that temporary flowback equipment is disconnected. In addition, the operator must document the total duration of venting, combustion and flaring over the flowback period. All flowback liquids during the initial flowback period and the separation flowback period must be routed to a well completion vessel, a storage vessel or a collection system. Because the BSER for oil wells and gas wells are the same, the final rule applies these requirements to both oil and gas wells.
For subcategory 2 wells, we are finalizing an operational standard that requires either (1) routing all flowback directly to a completion combustion device with a continuous pilot flame (which can include a pit flare) or, at the option of the operator, (2) routing the flowback to a well completion vessel and sending the flowback to a separator as soon as a separator will function and then directing the separated gas to a completion combustion device with a continuous pilot flame. For option 2, any gas in the flowback prior to the point when the separator will function is not subject to control. In either case, combustion is not required if combustion creates a fire or safety hazard or can damage tundra, permafrost or waterways. Operators are required to maintain the same records described above for category 1 wells.
As with gas wells, we similarly recognize the limitation of “low pressure” oil wells from conducting REC. Therefore, consistent with the 2012 NSPS, low pressure wells are affected facilities and have the same requirements as subcategory 2 wells (wildcat and delineation wells). We have revised the definition of a “low pressure” well in response to comment.
Further, wells with a GOR of less than 300 scf of gas per stock tank barrel of oil produced are affected facilities, but have no well completion requirements, providing the owner or operator maintains records of the low GOR certification and a claim signed by the certifying official.
We are also retaining the provision from the 2012 NSPS, now at § 60.5365a(a)(1), that a well that is refractured, and for which the well completion operation is conducted according to the requirements of § 60.5375a(a)(1) through (4), is not considered a modified well and, therefore, does not become an affected facility for purposes of the well completion standards. We point out that such an exclusion of a “well” from applicability under the NSPS has no effect on the affected facility status of the “well site” for purposes of the fugitive emissions standards at § 60.5397a.

G. Fugitive Emissions From Well Sites and Compressor Stations
We are finalizing standards to control GHGs (in the form of limitations on methane emissions) and VOC emissions from fugitive emission components at well sites and compressor stations. Specifically, we are finalizing semiannual monitoring and repair of fugitive emission components at well sites and quarterly monitoring and repair at compressor stations. Monitoring of the components must be conducted using optical gas imaging (OGI), and repairs must be made if any visible emissions are observed. Method 21 may be used as an alternative monitoring method at a repair threshold level at 500 parts per million (ppm). Repairs must be made within 30 days of finding fugitive emissions and a resurvey of the repaired component must be made within 30 days of the repair using OGI or Method 21 at a repair threshold of 500 ppm. A monitoring plan that covers the collection of fugitive emissions components at well sites or compressor stations within a company-defined area must be developed and implemented.

H. Equipment Leaks at Natural Gas Processing Plants
We are finalizing standards to control GHGs (in the form of limitations on methane emissions) from equipment leaks at new, modified or reconstructed natural gas processing plants. These requirements are the same as the VOCs equipment leak requirements in the 2012 NSPS and require the level of control established in NSPS part 60, subpart VVa, including a detection level of 500 ppm for certain pieces of equipment, as in the 2012 NSPS. As with VOC reduction, we believe that subpart VVa level of control reflects the best system of emission reductions for reducing methane emissions.

I. Liquids Unloading Operations
The EPA stated in the proposal that we did not have sufficient information to propose a national standard for liquids unloading. ^{76} However, the EPA requested comment on nationally applicable technologies and techniques that reduce GHG and VOC emissions from these events. Although the EPA received valuable information from the public comment process, the information was not sufficient to finalize a national standard representing BSER for liquids unloading.
^{76} See 80 FR 56614 and 80 FR 56644, September 18, 2015.
Specifically, we requested data and information on the level of GHG and VOC emissions per unloading event, the number of unloading events per year, and the number of wells that perform liquids unloading. In addition, we requested comment on (1) characteristics of the well that play a role in the frequency of liquids unloading events and the level of emissions; (2) demonstrated techniques to reduce the emissions from liquids unloading events, including the use of smart automation and the effectiveness and cost of these techniques; (3) whether there are demonstrated techniques that can be employed on new wells that will reduce the emissions from liquids unloading events in the future; and (4) whether emissions from liquids unloading can be captured and routed to a control device and whether this has been demonstrated in practice.
The EPA received some information pertaining to our request for information. Specifically, the EPA received information on the frequency of unloading and on techniques to reduce emissions through capture or flaring and learned of some operators that have been able to achieve capture in practice. While we have gained better understanding of the practice of liquids unloading, the EPA did not receive the necessary information to identify an emission reduction technology that can be applied across the category of sources. We also considered the possibility of subcategorization. However, according to the information received, the differences in liquids unloading events (with respect to both frequency and emission level) are not due to differences in well size or type of wells at which liquids unloading is performed, but rather the specific conditions of a given well at the time the operator determines that well production is impaired such that unloading must be done. Operators select the technique to perform liquids unloading operations based on the conditions of the well each time production is impaired. Because well conditions change over time, each iteration of unloading may require repeating a single technique or attempting a different technique that may not have been appropriate under prior conditions. Given the differences in conditions at different wells when liquids unloading must be performed, the EPA did not receive information about techniques, individually or as a group, that helped us to identify a BSER under our CAA section 111(b) authority. The EPA continues to search for better means to address emissions associated with liquids unloading and is including this emissions source in the upcoming information gathering effort. ^{77} Please refer to the RTC for additional discussion on liquids unloading. ^{78}
^{77} See section III.E of this preamble for a discussion of the upcoming information gathering effort.
^{78} See RTC document in EPA Docket ID No. EPA-HQ-OAR-2010-0505.

J. Recordkeeping and Reporting
We are finalizing recordkeeping and reporting requirements that are consistent with those in the current NSPS. The final rule requires owners or operators to submit initial notifications and annual reports, in addition to retaining records to assist in documenting that they are complying with the provisions of the NSPS.
For new, modified, or reconstructed pneumatic controllers, owners and operators are not required to submit an initial notification for each piece of equipment; rather, they must report the installation of these affected facilities in their first annual report following the compliance period during which they were installed. Owners or operators of well affected facilities (consistent with current requirements for gas well affected facilities) are required to submit an initial notification no later than two days prior to the commencement of each well completion operation. This notification must include contact information for the owner or operator, the United States Well Number (formerly the American Petroleum Institute (API) well number), the latitude and longitude coordinates for each well, and the planned date of the beginning of flowback.
In addition, initial annual reports are due no later than 90 days after the end of the initial compliance period, which is established in the rule. Subsequent annual reports are due no later than the same date each year as the initial annual report. The annual reports include information on all affected facilities that were constructed, modified or reconstructed during the previous year. A single report may be submitted covering multiple affected facilities, provided that the report contains all the information required by § 60.5420a(b). This information includes general information on the company ( e.g. , company name), as well as information specific to individual affected facilities, such as the well ID associated with the affected facility ( e.g. , storage vessels) and the facility site name ( e.g. , “Compressor Station XYZ” or “Tank Battery 123”) and the address of the affected facility.
For well affected facilities, the information required in the annual report includes the location of the well, the United States well number, the date and time of the onset of flowback following hydraulic fracturing or refracturing, the date and time of each attempt to direct flowback to a separator, the date and time of each occurrence of returning to the initial flowback stage, and the date and time that the well was shut in and the flowback equipment was permanently disconnected or the startup of production, the duration of flowback, the duration of recovery to the flow line, duration of the recovery of gas for another useful purpose, duration of combustion, duration of venting, and specific reasons for venting in lieu of capture or combustion. For each well for which a technical infeasibility exemption is claimed, to route the recovered gas to any of the four options specified in § 60.5375a(a)(1)(ii), the report includes the reasons for the claim of technical infeasibility with respect to all four options provided in that subparagraph.
For each well for which an exemption is claimed the owner or operator must maintain records of the low GOR certification and submit a claim signed by the certifying official in the annual report. For each well for which an exemption is claimed for conditions in which combustion may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways, the report should include the location of the well, the United States Well Number, the specific exception claimed, the starting date and ending date for the period the well operated under the exception, and an explanation of why the well meets the claimed exception. The annual report must also include records of deviations where well completions were not conducted according to the applicable standards.
For centrifugal compressor affected facilities, information in the annual report must include an identification of each centrifugal compressor using a wet seal system constructed, modified or reconstructed during the reporting period, as well as records of deviations in cases where the centrifugal compressor was not operated in compliance with the applicable standards.
For reciprocating compressors, information in the annual report must include the cumulative number of hours of operation or the number of months since initial startup or the previous reciprocating compressor rod packing replacement, whichever is later, or a statement that emissions from the rod packing are being routed to a process through a closed vent system under negative pressure.
Information in the annual report for pneumatic controller affected facilities includes location and documentation of manufacturer specifications of the natural gas bleed rate of each pneumatic controller installed during the reporting period. For pneumatic controllers for which the owner is claiming an exemption from the standards, the annual report includes documentation that the use of a pneumatic controller with a natural gas bleed rate greater than 6 scfh is required and the reasons why. The annual report also includes records of deviations from the applicable standards.
For pneumatic pump affected facilities, information in the annual report includes an identification of each pneumatic pump constructed, modified or reconstructed during the compliance period; if applicable, a certification that no control was available onsite and that there is no ability to route to a process; an identification of any sites that contain pneumatic pumps and installed a control device during the reporting period, where there was previously no control device or ability to route to a process at a site; and records of deviations in cases where the pneumatic pump was not operated in compliance with the applicable standards.
The final rule includes new requirements for monitoring and repairing sources of fugitive emissions at well sites and compressor stations. An owner or operator must submit an annual report, which covers the collection of fugitive emissions components at well sites and compressor stations within an area defined by the company. The report must include the date and time of the surveys completed during the reporting year, the name of the operator performing the survey; the ambient temperature, sky conditions, and maximum wind during the survey; the type of monitoring instrument used; the number and type of components that were found to have fugitive emissions; the number and type of components that were not repaired during the monitoring survey; the number and type of difficult-to-monitor and unsafe-to-monitor components that were monitored; the date of the successful repair of the fugitive emissions component if it was not repaired during the survey; the number and type of fugitive emission components that were placed on delay of repair and the explanation of why the component could not be repaired and was placed on delay of repair; and the type of monitoring instrument used to resurvey a repaired component that could not be repaired during the initial monitoring survey. If an owner or operator chooses to use Method 21 to conduct the monitoring survey, they are required to keep records that include the type of monitoring instrument used and the fugitive emissions component identification. The owner or operator is required to keep a log for each affected facility. The log must include the date the monitoring survey was performed, the technology used to perform the survey, the number and types of equipment found to have fugitive emissions, a digital photograph or video of the monitoring survey when an OGI instrument is used to perform the monitoring survey, the date or dates of first attempt to repair the source of fugitive emissions, the date of repair of each source of fugitive emissions that could not be repaired during the initial monitoring survey, any source of fugitive emissions found to be technically infeasible or unsafe to repair and an explanation of why the component was placed on delay of repair, a list of the fugitive emissions components that were tagged as a result of not being repaired during the initial monitoring survey, and a digital photograph or video of each untagged fugitive emissions component that could not be repaired during the monitoring survey when the fugitive emissions were initially found. These digital photographs and logs must be available at the affected facility or the field office.
Consistent with the current requirements of subpart OOOO, records must be retained for 5 years and generally consist of the same information required in the initial notification and annual reports. The records may be maintained either onsite or at the nearest field office.

K. Reconsideration Issues Being Addressed
The EPA is finalizing numerous items in subpart OOOO on which we granted reconsideration and proposed changes with some further adjustments as a result of public comment. To the extent that these items relate to subpart OOOOa, we are also finalizing the same provisions for purposes of consistency between the two rules. First, we are finalizing corrections to the storage vessel control device monitoring and testing provisions related to in-field performance testing of enclosed combustors, initial and ongoing performance testing for any enclosed combustors used to comply with the emissions standard for an affected facility, and consistent requirements for monitoring of visible emissions for all enclosed combustion units. We are also finalizing clarified applicability requirements for storage vessel affected facilities. Next, we are finalizing amendments to include initial compliance requirements for bypass devices and certain closed vent systems and provide an alternative in subpart OOOO. Specifically, the rule allows for either an alarm at the bypass device or a remote alarm. The EPA is not finalizing our proposal to require both forms of alarm under subpart OOOO to avoid retroactive requirements.
Additionally, the EPA is finalizing recordkeeping requirements for repair logs for control devices failing a visible emissions test. We are clarifying the due date for the initial annual report and finalizing that flares used to comply with subpart OOOO are subject to the design and operation requirements in the general provisions. Next, we clarify that the monitoring provisions of subpart VVa applicable to affected units of subpart OOOO do not extend to open-ended valves or lines. We are finalizing clarification to the initial compliance requirement specifically to identify that the 2012 rule already includes a provision similar to subpart KKK. The EPA is finalizing the exemption from the notification required for reconstruction to affected facility pneumatic controllers, centrifugal compressors, and storage vessels in subpart OOOOa. The EPA is finalizing provisions for management of waste from spent carbon canisters. The EPA is finalizing a definition of the term “capital expenditure” in subpart OOOO. The EPA is finalizing an exemption for certain water recycling vessels that EPA did not intend to be affected facility storage vessels under subparts OOOO or OOOOa. By exempting such vessels, EPA will address a disincentive for recycling of water for hydraulic fracturing. Lastly, the EPA is not finalizing continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities in subpart OOOO. For additional discussion of these issues, please refer to section VI of this preamble and the RTC.

L. Technical Corrections and Clarifications
We discovered 22 drafting errors in the proposal and have corrected these errors in the final rule. Please see section VI for a complete list of technical corrections and clarifications.

M. Prevention of Significant Deterioration and Title V Permitting
In the proposed rule, we stated that the pollutant we were proposing to regulate was GHGs, not methane as a separately regulated pollutant. 80 FR 56593, 56600-01 (Sept. 18, 2015). As explained in section VII of this preamble, we are adding provisions to the final rule, analogous to what was included in Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, 80 FR 64509 (Oct. 23 2015), to make clear in the regulatory text that the pollutant regulated by this rule is GHGs.

N. Final Standards Reflecting Next Generation Compliance and Rule Effectiveness
In making decisions on the final requirements for this rule, we have emphasized the value of requirements that reflect principles of Next Generation Compliance and Rule Effectiveness. EPA's Next Generation Compliance strategy includes designing rules that promote improved compliance and better environmental outcomes. Specifically, we are finalizing standards with the following Next Generation Compliance strategies: (1) Electronic reporting via the EPA's Central Data Exchange (CDX), (2) clear applicability criteria ( e.g. , modification criteria), (3) incentives for intrinsically lower emitting equipment ( e.g. , solar pumps at gas plants are not affected facilities), (4) OGI technology for monitoring fugitive emissions, (5) digital picture reporting as an alternative for well completions (“REC PIX”) and manufacturer installed control devices, (6) qualified professional engineer certification of technical infeasibility to connect a pneumatic pump to an existing control device, and (7) qualified professional engineer certification of closed vent system design. These requirements, or options for compliance, provide opportunities for owners and operators to reduce obligations by making particular choices, reduce the burden for both the regulated industry and the agencies providing oversight, and provide greater transparency for all parties, including the public.

VI. Significant Changes Since Proposal
This section identifies significant changes in this rule from the proposed rule. These changes reflect the EPA's consideration of over 900,000 comments submitted on the proposal and other information received since the proposal, while preserving the aims underlying the proposal. The final rule protects human health and the environment by improving the existing NSPS and adding emission reduction standards for additional significant sources of GHGs and VOCs, consistent with the CAA. The EPA sought to achieve this important goal by endeavoring, where possible, to consistently expand the 2012 NSPS requirements across the oil and natural gas sector while also accounting for the unique characteristics of each type of source in setting emission reduction requirements. In this section, we discuss the significant changes since proposal by source category and the broad background for those changes. More specific information regarding comments and our responses appears in section VIII and in materials available in the docket.

A. Centrifugal Compressors
For centrifugal compressors, comments and information available led us to finalize the standards as proposed. In the proposed rule, we proposed to require 95 percent reduction of emissions from each centrifugal compressor affected facility. The standard can be achieved by capturing and routing the emissions using a cover and closed vent system to a control device ( i.e. , combustion control device) that achieves an emission reduction of 95 percent, or by routing the captured emissions to a process. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.

B. Reciprocating Compressors
For the reciprocating compressors requirements, we are finalizing the standards as proposed, except with a slight modification to the definition of reciprocating compressor rod packing. In the proposed rule, we proposed to require replacement of rod packing on or before 26,000 hours or 3 years of operation, or alternatively to route emissions via a closed vent system under negative pressure. To account for segments of the industry in which reciprocating compressors operate in a pressurized mode for a fraction of the calendar year, the standard is based on the determination that 26,000 hours of operation are comparable to 3 years of continuous operation.
In the final rule, we revised the definition of reciprocating compressor rod packing. The EPA received comment that the definition of rod packing should be included in the rule to clarify the intent to replace any component of the rod packing that was contributing to emissions from the rod packing assembly. Because we agree that this clarification is useful, we have revised the definition of reciprocating compressor rod packing in the final rule to mean a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes from the compressor, or any other mechanism that provides the same function of limiting the amount of compressed natural gas that escapes from the compressor. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.

C. Pneumatic Controllers
For pneumatic controllers, comments and information available led us to finalize the standards as proposed. We proposed to require the use of low-bleed controllers in place of high-bleed controllers ( i.e., natural gas bleed rate not to exceed 6 scfh) ^{79} at all locations within the source category, except for natural gas processing plants. For natural gas processing plants, the standards require control of GHG and VOC emissions by requiring that pneumatic controllers have a zero natural gas bleed rate ( i.e., they are operated by means other than natural gas, such as being driven by compressed instrument air).
^{79} Low-bleed controllers are not affected facilities under this final rule.
The final rule provides that certain pneumatic controllers, reflecting the particular functions they perform, have only tagging and recordkeeping and reporting requirements. As discussed in the proposal, the EPA identified situations where high-bleed controllers ( i.e., controllers with a natural gas bleed rate greater than 6 scfh) are necessary because of functional requirements, such as positive actuation or rapid actuation. An example would be controllers used on large emergency shutdown valves on pipelines entering or exiting compressor stations. The 2012 NSPS accounts for this by providing an exemption to pneumatic controllers for which compliance would pose a functional limitation due to their actuation response time or other operating characteristics. The EPA is finalizing the same exemption for all pneumatic controllers across the source category. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.

D. Pneumatic Pumps
In the final rule, the EPA is finalizing requirements for pneumatic pumps that use control devices or processes that are already available onsite. At natural gas processing plants, the EPA proposed to require reductions of 100 percent of GHG (in the form of methane) and VOC emissions from all diaphragm pneumatic pumps. For locations other than natural gas processing plants, the EPA proposed to require reductions of 95 percent of GHG (in the form of methane) and VOC emissions from all natural gas-driven diaphragm pumps, if an existing control or process was available.
The public comment process helped us to identify aspects of the proposed requirements that may not be practical or feasible in all cases, and commenters submitted additional information for us to analyze. In this final rule, based on our consideration of the comments received and other relevant information, we have made certain changes to the proposed standards for pneumatic pumps. The final standards require the GHG (in the form of a limitation on methane) and VOC emissions from new, modified, or reconstructed natural gas-driven diaphragm pumps located at well sites to be routed to an available control device or process onsite, unless such routing is technically infeasible at non-greenfield sites. We are not finalizing a technical infeasibility exemption at greenfield sites, where circumstances that could otherwise make control of a pneumatic pump technically infeasible at an existing location can be addressed in the site's design and construction. For pneumatic pumps located at a natural gas processing plant, the final rule requires the GHG (in the form of a limitation on methane) and VOC emissions from natural gas-driven diaphragm pumps to be zero.
While we acknowledge that solar-powered, electrically-powered, and air-driven pumps cannot be employed in all applications, we encourage operators to use pumps other than natural gas-driven pneumatic pumps where their use is technically feasible. To incentivize the use of these alternatives, the final rule's definition of “pneumatic pump affected facility” described in § 60.5365a(h) only includes natural gas-driven pumps. Pumps that are driven by means other than natural gas are not affected facilities subject to the pneumatic pump provisions of the NSPS and are not subject to any requirements under the final rule.
Provided below are the significant changes since proposal that result from the information in the record and the comments that we received and our rationale for these changes. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.

1. Piston Pumps
The EPA received several comments concerning the level of GHG and VOC emissions from natural gas-driven pneumatic piston pumps. The comments focused on the small volume of gas discharged by these pumps and the intermittent nature of their use. Other commenters suggested that the EPA treat pneumatic pumps consistently with pneumatic controllers. The commenters state that the same bleed rate considerations should be applied to pneumatic pumps because they are similar devices. Other commenters discussed the technical infeasibility of controlling emissions from piston pumps due to the inability to move such a small and intermittent gas flow through a duct or pipe to a control device.
We agree with commenters that pneumatic controller bleed rate considerations can serve as a useful guide in considering emission reduction requirements for pneumatic pumps. In response to these comments, we further evaluated the natural gas flow rate of pneumatic pumps and agree that piston pumps are inherently low-emitting because of their small size, design, and usage patterns. As discussed in the TSD to the proposed rule, we used natural gas emission rates between 2.2 to 2.5 scf/hr during operation of piston pumps. We determined these emission rates based on a joint report from the EPA and the Gas Research Institute on methane emissions from the natural gas industry. Our analysis of the currently available data, the information in the record, and consideration of public comments lead us to the conclusion that we should exclude piston pumps from coverage under the NSPS based on their inherently low emission rates. This approach is consistent with the manner in which we addressed low-bleed pneumatic controllers. After considering the inherently low emission rates of low-bleed pneumatic controllers, we determined that they should not be subject to the final rule requirements. Similarly, based upon the information that we have on the low emission rates of piston pumps, we are not establishing requirements for them in this final rule.
We note that our best available emissions data for diaphragm pumps, as discussed in the TSD, indicates that the emission rate ranges from about 20 to 22 scf/hr during operation of a diaphragm pump. Based on our analysis of this data, we do not believe exclusion of diaphragm pumps from the definition of a pneumatic pump affected facility is warranted. As a result, we are retaining requirements for diaphragm pumps in the final rule.

2. Pneumatic Pumps Located in the Gathering and Boosting and Transmission and Storage Segments
We received comment that pneumatic pumps located in the transmission and storage segment generally have very low emissions. Similar to the arguments presented above for piston pumps, commenters contend that these low emission rate pumps should not be subjected to the final rule. In response to these comments, we reviewed our available information used in the proposed rule TSD to estimate the number of pneumatic pumps and the emission rates of these pumps in all segments of the oil and natural gas sector. In the TSD for the final rule, we noted that neither the GHGRP nor the GHG Inventory include data about pneumatic pumps or their emission rates in the natural gas transmission and storage segment. Because we currently have no reliable source of information indicating the prevalence of use of pneumatic pumps in this segment, nor what their emission rates would be if they are used, we are not finalizing pneumatic pump requirements for the transmission and storage segment at this time.
We also reviewed the available GHGRP and GHG Inventory data for pneumatic pumps, which was limited to the production segment. We consider the production segment to include both well sites and the gathering and boosting segment. Our available data indicate that pneumatic pumps are used at well sites as well as emission data for those pumps, but are silent on the prevalence of use of pneumatic pumps in the gathering and boosting segment, and what their emission rates would be if they are used. As with pneumatic pumps in the transmission and storage segment, we are not finalizing pneumatic pump requirements for the gathering and boosting segments at this time because of the lack of information in the record to support finalizing requirements for these pumps.
We note that the EPA is currently conducting a formal process to gather additional data on existing sources in the oil and natural gas sector. We believe that this data collection effort will provide additional information on the use and emissions of pneumatic pumps in the transmission and storage segment and gathering and boosting segment. Once we have obtained and analyzed these data, we will be better equipped to determine whether regulation of pneumatic pumps in the transmission and storage segment and gathering and boosting segment is warranted. See section III.E for more detail regarding the EPA's information collection request for existing sources.

3. Technical Infeasibility
We agree with comments that there may be circumstances, such as insufficient pressure or control device capacity, where it is technically infeasible to capture and route pneumatic pump emissions to a control device or process, and we have made changes in the final rule to include an exemption for these instances. The owner or operator must maintain records of an engineering evaluation and certification providing the basis for the determination that it is technically infeasible to meet the rule requirements. The rule does not allow the operator to claim the technical infeasibility exemption for a pneumatic pump affected facility at a greenfield site (defined as a site, other than a natural gas processing plant, which is entirely new construction), where circumstances that could otherwise make control of a pneumatic pump technically infeasible at an existing location can be addressed in the site's design and construction.

4. Efficiency of Existing Control Devices
As noted above, we are finalizing emission standards for new, modified, and reconstructed natural gas-driven diaphragm pumps located at well sites requiring emissions be reduced by 95 percent if either a control device or the ability to route to a process is already available onsite. In setting this requirement, the EPA recognizes that there may not be a control device or process available onsite. Our analysis shows that it is not cost-effective to require the owner or operator of a pneumatic pump affected facility to install a new control device or process onsite to capture emissions. In those instances, the pneumatic pump affected facility is not subject to the emission reduction provisions of the final rule.
Commenters have also raised concerns, and we agree, that the control device available onsite may not be able to achieve a 95 percent emission reduction. We evaluated whether this requirement should only be triggered when a NSPS subpart OOOO or OOOOa compliant control device was onsite, which would alleviate the control efficiency concern raised by commenters. However, the EPA is concerned that significant emissions reductions would be lost as a result of limiting the required type of equipment that must be used to control pneumatic pump emissions to only those that are designed to achieve 95 percent emission reductions. We are not requiring the owner or operator to install a new control device on site that is capable of meeting a 95 percent reduction nor are we requiring that the existing control device be retrofitted to enable it to meet the 95 percent reduction requirement. However, we are requiring that the owner or operator of a pneumatic pump affected facility at well sites to route the emissions to an existing control device even if it achieves a level of emissions reduction less than 95 percent. In those instances, the owner or operator must maintain records demonstrating the percentage reduction that the control device is designed to achieve. In this way, the final rule will achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device on site cannot achieve a 95 percent reduction.

5. Compliance Requirements
In response to concerns about applicability of subpart OOOO or OOOOa compliance requirements, the EPA has clarified our intent in the final rule that existing control devices that are not already subject to subparts OOOO or OOOOa compliance requirements ( i.e., control devices that are subject to other federal or state compliance requirements) are not subject to the performance specifications, performance testing, and monitoring requirements in this rule solely because they are controlling pneumatic pump emissions. We believe that control devices covered by other federal, state, or other regulations would be subject to compliance requirements under those provisions and, therefore, we have reasonable assurance that the devices will perform adequately, and we do not need to include existing controls that are not already covered by subparts OOOO and OOOOa under the compliance requirements for these subparts.

6. Cost Analysis
In response to commenters' concerns that the costs were underestimated for compliance with the pneumatic pump requirements, we revised the cost analysis using the average of our annualized costs and two additional annualized cost estimates provided by commenters. ^{80} Commenters' cost estimate methodologies and inputs varied from EPA's cost estimate which prevented us from conducting a side-by-side comparison with our cost estimate, nor could we directly compare the commenters' estimates with one another. However, in order to take into account the cost estimates provided by the commenters, we revised our cost analysis using the average of our annualized costs and the two additional annualized cost estimates provided by commenters. This is the same approach we would have taken had we obtained cost quotes from three separate vendors to install the closed vent system, and which we believe is the most equitable procedure when there is insufficient information to distinguish between the three cost estimates. One commenter gave an estimated capital cost of $5,800 which is annualized to be $826. A second commenter gave an estimated capital cost of $8,500 which annualized to be $1,210. The proposed capital cost to route emissions through a closed vent system was $2,000 which when annualized is $285. Based on our revised cost analysis, the capital cost for routing the emissions to an existing control device or process is $5,433, and the annualized cost is $774. We more fully discuss our cost estimate analysis in the TSD.
^{80} See EPA docket ID No. EPA-HQ-OAR-2010-0505.
We evaluated the cost of control for routing emissions to an existing combustion device or process where we assign the cost equally to methane and VOC. For diaphragm pumps at well sites, the cost of reducing methane emissions is $235 per ton and the cost of reducing VOC emissions is $847 per ton, using the single-pollutant approach. Based on this revised cost analysis using additional cost information, we find that the cost of control for reducing methane emissions remains reasonable.

7. Affected Facility Definition
The EPA received comment that there was contradictory language in the proposal preamble and regulatory text regarding recordkeeping requirements for pneumatic pumps where no control device was on site. This lack of clarity was the result of the affected facility definition for pneumatic pumps. In the final rule, we have revised the definition to clarify that coverage under this rule is independent of availability of a control device on site. Specifically, all natural gas-driven diaphragm pumps at natural gas processing plants or well sites are affected facilities, except for pumps at well sites that operate less than 90 days per calendar year. The EPA has revised the final regulatory text to make clear that all pneumatic pumps affected facilities must be reported on the annual report and records maintained as applicable to control status of the pump.

8. Timing of Initial Compliance
The EPA is also finalizing requirements for pneumatic pump affected facilities at natural gas processing plants. The EPA is finalizing GHG and VOC emissions control requirements for pneumatic pump affected facilities at well sites if there is a control device or ability to route to a process available on site or subsequently installed on site. We are also finalizing a technical infeasibility exception when it is infeasible to route the pneumatic pump to the control device (or route to a process) at non-greenfield sites. An owner or operator applying this exemption must obtain a professional engineering assessment demonstrating the reasons for the exemption.
As pointed out by commenters, the technical infeasibility exemption may be based on safety concerns that could arise when a control device is not designed to handle the additional stream from the pneumatic pump. Commenters also expressed concern about safety issues related to increased pressure on the rest of the closed vent system connected to the control device. In light of these comments, we believe that the proposed 60-day compliance period may be insufficient to identify a qualified professional engineer, obtain the necessary design documents for the existing control device and associated ductwork, evaluate the design documents in light of the increased flow from the pneumatic pump, make an assessment of the technical feasibility of routing the pneumatic pump to the control device, and issue the required certification. Therefore, we are finalizing the compliance period to begin on November 30, 2016 to allow sufficient time for these necessary tasks to be completed.

E. Well Completions
For the well completion requirements, we proposed to require RECs, when technically feasible and in combination with a completion combustion device, for subcategory 1 wells. For subcategory 2 wells, we proposed an operational standard that would require minimization of venting of gas and hydrocarbon vapors during the completion operation through the use of a completion combustion device, with provisions for venting in lieu of combustion for situations in which combustion would present safety hazards. The proposed rule identified challenging issues for which we solicited comment in order to obtain additional information.
The public comment process helped us to identify aspects of the proposed requirements that in practice may not be practical in all cases, and commenters submitted additional information for us to analyze. In this final rule, based on our consideration of the comments received and other relevant information, we have made certain changes to the proposed standards for well completions. The final rule refines the well completion requirements to reduce emissions and provide clarity for both operators and regulators. The EPA is finalizing well completion standards for hydraulically fractured or refractured wells. ^{81} The final standards require a combination of REC and combustion at subcategory 1 wells and combustion at subcategory 2 wells and low pressure wells. Provided below are the significant changes since proposal that result from the comments we received and our rationale for these changes. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
^{81} As noted earlier in section IV, in 2012 EPA promulgated VOC standards for completions of hydraulically fractured or refractured gas wells. Today's action establishes GHG standards for gas well completions, as well as GHG and VOC standards for hydraulically fractured and refractured oil well completions.

1. Separator Function
The EPA solicited comment on the use of a separator during flowback and whether a separator can be employed for every well completion. We received several comments identifying situations where a separator cannot function. Specifically, commenters noted instances where a separator cannot function due to very low gas flow from the well, contaminated gas flow, or low reservoir pressure requiring artificial lift techniques. Commenters indicate that because of these scenarios there can be a complete absence of a separation flowback stage during the well completion (which, according to the commenters, can be particularly common in some basins and fields). Commenters asserted that many of these circumstances can be anticipated prior to the onset of flowback. Furthermore, commenters stated that the requirement to have a separator onsite would likely cause the operator to incur a cost with no environmental benefit derived.
We believe that commenters have presented legitimate situations where it would be technically infeasible to use a separator, which is required for performing a REC. The challenge is, however, that the factors that lead to technical infeasibility of a separator to function may not be apparent until the time the well completion occurs, at which time it is too late to provide the equipment and, as a result, the well completion will go forward without controls. Further, the commenters did not provide data, and we do not have sufficient data to consistently and accurately identify the subcategory or types of wells for which these circumstances occur regularly or what criteria would be used as the basis for an exemption to the REC requirement such that a separator would not be required to be onsite for these specific well completions. In order to accommodate these concerns raised by commenters, the final rule requires a separator to be onsite during the entire flowback period for subcategory 1 wells ( i.e., non-exploratory or non-delineation wells, also known as development wells), but does not require performance of REC where a separator cannot function. We anticipate a subcategory 1 well to be producing or near other producing wells. We therefore anticipate REC equipment (including separators) to be onsite or nearby, or that any separator brought onsite or nearby can be put to use. For the reason stated above, we do not believe that requiring a separator onsite would incur cost with no environmental benefit.
However, unlike subcategory 1 wells, subcategory 2 wells are in areas where gas composition is likely unknown and, therefore, there is less certainty that a separator can work at these wells. If the separator does not work, there are unlikely subcategory 1 wells nearby that can put the separator to use. For the reasons stated above, we are not requiring that a separator be onsite for the well completion of subcategory 2 wells.
The EPA had proposed that, for subcategory 2 wells and low pressure wells, operators would be required to route flowback to a completion combustion device as soon as the separator was able to function. We had based the proposed requirement for these wells on our determination that BSER was combustion, and efficient combustion using traditional combustion devices could be achieved through separation of the gas from the liquid and solid flowback materials prior to routing to the completion combustion device.
As discussed in the 2015 proposal, traditional combustion devices ( e.g., flares or enclosed combustors) cannot work initially because the flowback following hydraulic fracturing consists for liquids, gases and sand in high-volume, multiphase slug flow. As a result, these devices can work only after a separator can function. While pit flares can be installed and used from the start, considering the makeup of the initial flowback, we believe there is little gas to be burned, and so we assume there is not an appreciable difference between the amount of emissions reductions between a traditional combustion device and a pit flare. In addition, we believe that pit flares have increased potential for secondary impacts compared to traditional flares, due to the potential for the incomplete combustion of natural gas across the pit flare plume.
Although not required, some owners and operators may choose to separate the gas from the other flowback materials for water management or other purposes. If a separator is used, any separated gas can be routed to combustion. In light of all of the above, we are providing in the final rule two options for completions of subcategory 2 wells: (1) Route all flowback directly to a completion combustion device (in that case a pit flare); or (2) should an owner or operator choose to use a separator, route the separated gas to a completion combustion device as soon as a separator is able to operate.
We are providing the same two options for low pressure wells. We believe that wells cannot perform a REC if there is not sufficient well pressure or gas content during the well completion to operate the surface equipment required for a REC, and low pressure gas could prevent proper operation of the separator. Alternatively, when feasible, some owners and operators may choose to separate the gas from the other flowback materials for water management or other purposes. If a separator is used, any separated gas must be routed to combustion.

2. REC Feasibility
The second instance for potential technical infeasibility occurs during the separation flowback stage, where operators cannot perform a REC and, therefore, must combust. The EPA received comment that additional requirements are necessary to ensure that flaring of the recovered gas during the separation flowback stage is limited to scenarios where all options included in our definition for REC—(1) route the recovered gas from the separator into a gas flow line or collection system, (2) re-inject the recovered gas into the well or another well, (3) use the recovered gas as an onsite fuel source, or (4) use the recovered gas for another useful purpose that a purchased fuel or raw material would serve—have been pursued and their technical infeasibility documented. ^{82} Commenters identified factors such as the availability and capacity of gathering lines, right of way issues, the quality of gas, and ownership issues that could impact the ability of operators to capture and use gas. Commenters stated that the provision for technical infeasibility for operators to use the recovered gas is vague and runs counter to the improvements the EPA seeks to establish within the oil and gas industry. Other commenters urged the EPA to allow flaring only as a last resort by requiring advanced notification and detailed documentation of the technical infeasibility of capturing and using salable quality gas. Commenters further stated that flaring should be very rarely necessary, as the EPA has identified four separate options for using recovered gas. The commenter recommends that EPA add additional notification and reporting requirements to ensure that all four options have been pursued and their technical infeasibility documented. The EPA agrees that the exemption from REC due to technical infeasibility should be limited. However, as illustrated by the comments received, the circumstances under which a REC is technically infeasible are varied. It is, therefore, difficult to provide one definition that can address all scenarios.
^{82} This definition is the same as the definition for REC in subpart OOOO which, in response to public comment, included options in addition to routing to a gas line.
The EPA considered, but declined to require, advanced notification for the following reasons. Technical infeasibility can be an after-the-fact occurrence ( i.e., gas was contaminated and not of salable quality or had characteristics prohibiting other beneficial use and, therefore, the gas was combusted); therefore, advanced notification may not always be possible. A case-by-case advance evaluation by a regulatory agency is also not feasible considering the large number of completions, the wide geographic dispersion of the completions and the remote location of many well sites. For these reasons, we are not requiring prior notification of the claim of the technical infeasibility exemption.
Rather we have expanded recordkeeping requirements in the final rule to include: (1) Detailed documentation of the reasons for the claim of technical infeasibility with respect to all four options provided in section 60.5375a(a)(1)(ii), including but not limited to, names and locations of the nearest gathering line; capture, re-injection, and reuse technologies considered; aspects of gas or equipment prohibiting use of recovered gas as a fuel onsite; and (2) technical considerations prohibiting any other beneficial use of recovered gas onsite. We emphasize that the exemption is limited to “technical” infeasibility ( e.g., lack of infrastructure, engineering issues, safety concerns).
In addition to the detailed documentation and recordkeeping requirement, the final rule requires that a separator be onsite during the entirety of the flowback period at subcategory 1 (developmental) wells, as described earlier. We believe these additional provisions will support a more diligent and transparent application of the intent of the technical infeasibility exemption from the REC requirement in the final rule. This information must be included in the annual report made available to the public 30 days after submission through the Compliance and Emissions Data Reporting Interface (CEDRI), allowing for public review of best practices and periodic auditing to ensure flaring is limited and emissions are minimized.

3. Gas to Oil Ratio (GOR) Exclusion
We are not finalizing the proposed exclusion of wells with low GOR from the definition of a well affected facility. However, in the final rule, low GOR wells are not subject to REC or combustion requirements. In order to ensure that low GOR claims are not being made without sufficient analysis and oversight, the final rule requires that records used to make the GOR determination must be retained and a certifying official must sign the low GOR determination.
The EPA proposed that wells with a GOR of less than 300 scf of gas per barrel of oil produced would not be affected facilities subject to the well completion provisions of the NSPS. ^{83} The reason for the proposed threshold GOR of 300 is that separators typically do not operate at a GOR less than 300, which is based on industry experience rather than a vetted technical specification for separator performance. Though in theory any amount of free gas could be separated from the liquid, in reality this is not practical given the design and operating parameters of separation units operating in the field.
^{83} On February 24, 2015, API submitted a comment to the EPA stating that oil wells with GOR values less than 300 do not have sufficient gas to operate a separator. http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2014-0831-0137.
The EPA also solicited comment on how operators could identify low GOR wells ( i.e., those with a GOR of less than 300 scf of gas per stock tank barrel of oil produced) prior to well completion, specifically the question of whether the GOR of nearby wells would be a reliable indicator in determining the GOR of a new or modified well. The EPA received comment stating that wells in the same area or reservoir could be used to indicate GOR prior to well completion. In light of the comments received and, upon further consideration, the EPA concludes that GOR of a well can be determined in advance. The EPA, therefore, does not believe that it is appropriate to prescribe in the final rule any specific way to determine the GOR for purposes of exempting low GOR wells from performing REC or combustion. However, to ensure that only those that, in fact, have GOR of less than 300 are exempt from the REC or combustion requirement; these wells remain affected facilities under the final rule. To ensure that their GORs are accurately determined, the final rule requires detailed documentation of their GOR determination as well as annual reporting and recordkeeping requirements. However, they are not subject to the REC or combustion requirement.

4. Low Pressure Wells
We have revised the low pressure well definition in the final rule. In the 2012 NSPS, the EPA recognized that certain wells, which the EPA called “low pressure gas wells,” cannot implement a REC because of a lack of necessary reservoir pressure to flow gas at rates appropriate for the transportation of solids and liquids from a hydraulically fractured gas well against additional back pressure that would be caused by the REC equipment, thereby making a REC infeasible. The 2012 NSPS exempts these wells from REC and instead requires combustion of the recovered gas.
In the EPA's proposed rule (80 FR 56611, September 18, 2015), in which we proposed to also regulate VOC and GHG emissions from oil wells, we proposed to amend the current requirements for low pressure gas wells to apply to all low pressure wells. We proposed to change the term “low pressure gas well” to “low pressure well” but keep the definition the same. The substance of the definition at proposal for “low pressure well” is the same as the currently codified definition for “low pressure gas well” in the 2012 NSPS. We solicited comment on whether this definition appropriately defined hydraulically fractured wells for which conducting a REC would be technologically infeasible or whether the definition should be revised to better characterize the criteria for all low pressure wells.
In our proposed definition, the pressure of the flowback fluid (oil, gas, and water) immediately before it enters the flow line is calculated by equation (1) below:
P L ( psia ) = 0.445 · P R ( psia ) − 0.038 · L ( ft ) + 67.578 Equation (1)
Where:
P L ( psia ) is the pressure of flowback fluid immediately before it enters the flow line;
P R ( psia ) is the pressure of the reservoir containing oil, gas, and water; and
L ( ft ) is the depth of the well.
The EPA proposed that if the pressure of flowback fluid immediately before it enters the flow line, P L, calculated using the above equation is less than the available line pressure, the well would be considered a low pressure well. Such a well would not be required to do a REC during flowback ( i.e., collect and send the associated gas to the flow line). Instead, such a well would only be required to combust the gas in a completion combustion device.
Commenters asked the EPA to provide a new definition of “low pressure oil well” to differentiate oil wells from gas wells. They stated that the definition of “low pressure well” set out in proposed section 60.5430a and taken from the definition of “low pressure gas well” in subpart OOOO (section 60.5430) is not appropriate for a low pressure oil well, because the surface and back pressure for oil wells is higher than that for gas wells. They further state that “. . . once the hydraulic fracture load stops coming back, a gas well will typically have much less liquids in the production tubing, making the surface pressure actually higher for the gas well vs. an oil well. This difference would be reflected in the 0.038 number which represents the gas gradient in the well, which would impart a back pressure. For oil wells this back pressure would be higher . . .” In response to these comments, the EPA modified the existing low pressure gas well equation (equation (1) above) to add pressure drop resulting from flow of oil and water in a well.
The EPA's evaluation of the steady flow of petroleum fluid (gas and oil) during flowback in wells resulted in the following modified equation, hereafter referred to as the low pressure well equation (equation 2 below):
Where:
P L is the pressure of flowback fluid immediately before it enters the flow line, expressed in psia;
P R is the pressure of the reservoir containing oil, gas, and water, expressed in psia;
L is the true vertical depth of the well, expressed in feet;
q o , q g , q w are the flow rates of oil, gas, and water, respectively, in the well, expressed in cubic feet/second; and
ρ o is the density of oil in the well, expressed in pounds per cubic feet.
EPA's low pressure well equation is used to predict the pressure of the flowback fluid (oil, gas, and water) immediately before it enters the flow line. The low pressure well equation uses inputs similar to those required for the gas well definition and for which information is understood to be available before well completion activity starts at a well site. These inputs include reservoir (or formation) pressure; true vertical depth of the well; flow rates of oil, gas, and water in the well; and the density of oil in the well.
As oil-gas-water mixture flows upwards in a well to a lower pressure location, oil and gas volumes change and some of the dissolved gas evolves out of solution in oil. These phenomena result in oil and gas densities and volumetric flows changing with well depth. Therefore, oil density, ρ o , and volumetric flow rate, q o , for use in equation (2) are calculated using the known value of oil API gravity at a well site and the widely used correlations provided in Vasquez and Beggs (1980). ^{84} The gas volumetric flow, q g , is calculated using widely used correlations provided in Guo and Ghalambor (2005). ^{85} Details on using equation (2) to calculate the pressure of flowback fluid immediately before it enters the flow line, P L , can be found in the TSD in the public docket.
^{84} Vasquez, M. and Beggs, H.D., “Correlations for fluid physical property prediction,” JPT, 1980.
^{85} Guo, B. and Ghalambor, A., “Natural Gas Engineering Handbook,” Gulf Publishing Company, 2005.
As noted above, equation (2) is the low pressure well equation for all wells in the final rule. This equation predicts the pressure, P L, of the flowback fluid (oil, gas, and water) immediately before it enters the flow line during the separation flowback period. In response to comments, the EPA's final regulations require that this pressure be compared to the actual flow line pressure available at the well site. Wells with insufficient predicted pressure to produce into the flow line are required to combust the gas in a control device. Wells with sufficient pressure to produce into the flow line are required to capture the gas and produce it into the flow line.
EPA further notes that equation (2) is a modification of equation (1) and adds pressure drop resulting from flows of oil and water. When characterizing a well with conditions of gas flow only ( i.e., q o = q w = 0), equation (2) reduces to equation (1), the equation for gas wells. Also note that equation (2) for line pressure is derived using a vertical well. It is known that inclined wells exist in the field, which will experience a somewhat higher frictional drop due to longer flow length. Nonetheless, it is expected that equation (2) would be able to account for minor increases in pressure drop due to increased frictional drop at inclined wells because the frictional pressure drop component contributes a small amount to the total pressure drop (about 1 percent on average) and conservative assumptions were used in deriving equation (2)—notably, bottom hole pressure equals one-half of formation pressure.
In addition to the revised low pressure well equation, we are providing, in the final definition of low pressure well, other characteristics of the well that would indicate that a well is a low pressure well. We believe that if the static pressure ( i.e., pressure with the well shut in and not flowing) at the wellhead following hydraulic fracturing, and prior to the onset of flowback, is less than the flow line pressure at the sales meter, the well is a low pressure well without having to demonstrate that it is such by using the low pressure well equation in the final rule.
Instead of using the equation, under the final rule, operators who suspect that a well may be a low pressure well have the option, for screening purposes, of performing a wellhead static pressure ( i.e., pressure with the well shut in and not flowing) check following fracturing and prior to the onset of flowback. If the static pressure at the wellhead was less than the flow line pressure at the sales meter, then the well would be a low pressure well. We believe that such a comparison would be conservative because, for a given well, the static pressure ( i.e., with no fluid movement through the well) would be higher than the dynamic pressure ( i.e., with the well flowing) because there would be no pressure losses brought about by friction caused by material movement in the tubing string. For some wells, use of this method could eliminate the need for the detailed calculations provided in the low pressure well equation discussed above. For other wells ( i.e., those wells where the static pressure was greater than the flow line pressure), it would be necessary for the operator to use the low pressure well equation.
Commenters asserted that many oil reservoirs have pressure that is insufficient for wells to naturally flow even after hydraulic fracturing. The commenters stated that this can be evidenced by the prevalence of artificial lift equipment such as rod pumps visible across the landscape of many oil producing areas. The commenters cited examples of reservoirs such as the Permian Basin, where horizontal drilling is used to extend the life of existing producing formations. The commenters explained that many oil wells that are hydraulically fractured do not have sufficient reservoir pressure to flowback fracture fluids. One company estimated that 30 percent of its hydraulically fractured horizontal wells and 80 percent of its hydraulically fractured vertical wells in the Permian Basin require artificial lift to flowback. In these cases, the commenter explained, rod pumps are installed on the wells to artificially lift the fracture fluids to the surface. In light of the comments received, the EPA believes that wells that require artificial lift equipment for flowback of fracture fluids should be classified as low pressure wells, as we believe that performing a REC is technically infeasible for these wells.
To meet the definition of low pressure well, the well must satisfy any of the criteria above. We have revised the definition in the regulatory text to reflect this change. Section VIII, the RTC document, the TSD, and other materials available in the docket provide more discussion of these topics.

5. Timing of Initial Compliance
The EPA proposed the well completion requirements that, if finalized, would apply to both oil and gas well completions using hydraulic fracturing. In the 2012 NSPS, we provided a phase-in approach in the gas well completion requirements due to the concern with insufficient REC and trained personnel if REC were required immediately for all gas well completions. However, we did not provide the same in this proposal on the assumption that the supplies of REC equipment and trained personnel have caught up with the demand and, therefore, are no longer an issue. While some commenters agreed, other commenters indicated that the proposed rule, which would dramatically increase the number of well completions subject to the NSPS, would lead to REC equipment shortages. One commenter estimated that it would take at least 6 months to obtain the necessary equipment, while another commenter estimated that it would take 24 months. One commenter noted that owners and operators have been drilling wells, but delaying completion, due to the current economic conditions affecting the industry, causing a suppressed equipment demand. Finally, one state regulatory agency recommended extending the compliance period to 120 days to allow sufficient time to contract for the necessary completion equipment.
After reviewing the comments, we agree that some owners and operators may have difficulty complying with the REC requirements in the final rule in the near term due to the unavailability of REC equipment. Although REC equipment suppliers have increased production to meet the demand for gas well completions under subpart OOOO, the affected facility under subpart OOOOa includes both gas and oil wells and will more than double the number of wells requiring REC equipment over subpart OOOO. We believe this demand will likely lead to a short-term shortage of REC equipment. However, based on the prior experience, we believe that suppliers have both the capability and incentive to catch up with the demand quickly, as opposed to the longer terms suggested by the commenters; they likely already stepped up production since this rule was proposed last year in anticipation of the impending increase in demand. In light of the above, the final rule provides a phase-in approach that would allow a quick build-up of the REC supplies in the near term. Specifically, for subcategory 1 oil wells, the final rule requires combustion for well completions conducted before November 30, 2016 and REC if technically feasible for well completions conducted thereafter. For subcategory 2 and low pressure oil wells, the final rule requires combustion during well completion, which is the same as that required for completion of subcategory 2 and low pressure gas well in the 2012 NSPS. For gas well completions, which are already subject to well completion requirements in the 2012 NSPS, the requirements remain the same.

F. Fugitive Emissions From Well Sites and Compressor Stations
For fugitive emissions requirements for the source category, three principles or aims directed our efforts. The first aim was to produce a consistent and accountable program for a source to use to identify and repair fugitive emissions at well sites and compressor stations. A second aim was to provide an opportunity for companies to design and implement their own fugitive emissions monitoring and repair programs. The third aim was to focus the fugitive emissions monitoring and repair program on components from which we expected the greatest emissions, with consideration of appropriate exemptions. The fourth aim was to establish a program that would complement other programs currently in place. With these principles in mind, we proposed a detailed monitoring plan; semiannual requirements using OGI technology for monitoring to find and repair sources of fugitive emissions, which we had identified as the BSER; a shifting monitoring schedule based on performance; a 15-day timeframe for repairing and resurveying leaks; and an exemption for low production wells.
The public comment process helped us to identify additional information to consider and provided an opportunity to refine the standards proposed. Commenters specifically identified concerns with the definition of modification for well sites and compressor stations, the monitoring plan, the fluctuating survey frequency, the overlap with state and federal requirements, use of emerging monitoring technologies, the initial compliance timeframe, and the relationship between production level and fugitive emissions.
In this final rule, based on our consideration of the comments received and other relevant information, we have made changes to the proposed standards for fugitive emissions from well sites and compressor stations. The final rule refines the monitoring program requirements while still achieving the main goals. Below we describe the significant changes since proposal for specific topics related to fugitive emissions and our rationale for these changes. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.

1. Fugitive Emissions From Well Sites

a. Monitoring Frequency
In conjunction with semiannual monitoring, the EPA co-proposed annual monitoring and solicited comment on the availability of trained OGI contractors and OGI instrumentation. 80 FR 56637, September 18, 2015. Commenters provided numerous comments and data regarding annual, semiannual and quarterly monitoring surveys. These comments largely focused on the cost, effectiveness, and feasibility of the different program frequencies. The EPA evaluated these comments and information, as well as certain production segment equipment counts from the 2016 public review draft GHG Inventory, which were developed from the data reported to the GHGRP. Based on the above information, the EPA updated its proposal assumptions on equipment counts per well site to use data from the 2016 public review draft update. This resulted in changes to the well site model plant. Specifically, the equipment count for meters/piping at a gas well site increased from 1 to 3, which tripled the component counts from meters/piping at these sites. In addition, the EPA developed a third model plant to represent associated gas well sites. This category includes wells with GOR between 300 and 100,000 standard cubic feet per barrel (scf/bbl), and the model plant is assumed to have the same component counts as the model oil well site, as well as components associated with meters/piping. The EPA used this information to re-evaluate the control options for annual, semiannual and quarterly monitoring. As shown in the TSD, the control cost, using OGI, based on quarterly monitoring is not cost-effective, while both semiannual and annual monitoring remain cost-effective for reducing GHG (in the form of methane) and VOC emissions. Because control costs for both semiannual and annual monitoring are cost-effective, we evaluated the difference in emissions reductions between the two monitoring frequencies and concluded that semiannual monitoring would achieve greater emissions reductions. Therefore, the EPA is finalizing the proposed semiannual monitoring frequency. Please see the RTC document in the public docket for further discussion. ^{86} Even though the EPA has determined that semi-annual surveys for well sites is the BSER under this NSPS, this does not preclude the EPA from taking a different approach in the future, including requiring more frequent monitoring ( e.g., quarterly).
^{86} See EPA docket ID No. EPA-HQ-OAR-2010-0505.

b. Low Production Well Sites
The EPA proposed to exclude low production well sites ( i.e., well sites where the average combined oil and natural gas production is less than 15 barrels of oil equivalent (boe) per day averaged over the first 30 days of production) from the fugitive emissions monitoring and repair requirements for well sites. As we explained in the preamble to the proposed rule, we believed that these wells are mostly owned by small businesses and that fugitive emissions associated with these wells are generally low. 80 FR 56639, September 18, 2015. We were concerned about the burden on small businesses, in particular, where there may be little emission reduction to be achieved. Id. We specifically requested comment on the proposed exclusion and the appropriateness of the 15 boe per day threshold. We also requested data that would confirm that low production sites have low GHG and VOC fugitive emissions.
Several commenters indicated that low production well sites should be exempt from fugitive emissions monitoring and that the 15 boe per day threshold averaged over the first 30 days of production is appropriate for the exemption, however, commenters did not provide data. Other commenters indicated that the low production well sites exemption would not benefit small businesses since these types of wells would not be economical to operate and few operators, if any, would operate new well sites that average 15 boe per day.
Several commenters stated that the EPA should not exempt low production well sites because they are still a part of the cumulative emissions that would impact the environment. One commenter indicated that low production well sites have the potential to emit high fugitive emissions. Another commenter stated that low production well sites should be required to perform fugitive emissions monitoring at a quarterly or monthly frequency. One commenter provided an estimate of low producing gas and oil wells that indicated that a significant number of wells would be excluded from fugitive emissions monitoring.
Based on the data from DrillingInfo, 30 percent of natural gas wells are low production wells, and 43 percent of all oil wells are low production wells. The EPA believes that low production well sites have the same type of equipment ( e.g., separators, storage vessels) and components ( e.g., valves, flanges) as production well sites with production greater than 15 boe per day. Because we did not receive additional data on equipment or component counts for low production wells, we believe that a low production well model plant would have the same equipment and component counts as a non-low production well site. This would indicate that the emissions from low production well sites could be similar to that of non-low production well sites. We also believe that this type of well may be developed for leasing purposes but is typically unmanned and not visited as often as other well sites that would allow fugitive emissions to go undetected. We did not receive data showing that low production well sites have lower GHG (principally as methane) or VOC emissions other than non-low production well sites. In fact, the data that were provided indicated that the potential emissions from these well sites could be as significant as the emissions from non-low production well sites because the type of equipment and the well pressures are more than likely the same. In discussions with us, stakeholders indicated that well site fugitive emissions are not correlated with levels of production, but rather based on the number of pieces of equipment and components. Therefore, we believe that the fugitive emissions from low production and non-low production well sites are comparable.
Based on these considerations and, in particular, the large number of low production wells and the similarities between well sites with production greater than 15 boe per day and low production well sites in terms of the components that could leak and the associated emissions, we are not exempting low production well sites from the fugitive emissions monitoring program. Therefore, the collection of fugitive emissions components at all new, modified or reconstructed well sites is an affected facility and must meet the requirements of the fugitive emissions monitoring program.

c. Monitoring Using Method 21
The EPA's analysis for the proposed rule found OGI to be more cost-effective at detecting fugitive emissions than the traditional protocol for that purpose, Method 21, and the EPA, therefore, identified OGI as the BSER for monitoring fugitive emissions at well sites. See 80 FR 56636, September 18, 2015. The EPA solicited comment on whether to allow Method 21 as an alternative fugitive emissions monitoring method to OGI. 80 FR 56638, September 18, 2015. We also solicited comment on the repair threshold for components that are found to have fugitive emissions using Method 21. Id.
Numerous industry, state, and environmental commenters indicated that Method 21 is preferred or should be allowed as an alternative to OGI, citing availability, costs, and training associated with OGI.
Several commenters indicated that the EPA should set the Method 21 fugitive emissions repair threshold at 10,000 ppm, the level at which our recent work indicates that fugitive emissions are generally detectable using OGI instrumentation provided that the right operating conditions ( e.g., wind speed and background temperature) are present. 80 FR 56635, September 18, 2015. Some commenters stated that the repair threshold should be 500 ppm to achieve a high level of fugitive emission reductions while other commenters state that a 500 ppm repair threshold would target fugitive emissions that would not provide meaningful reductions.
The issue of the repair threshold when Method 21 is used is a critical decision. As discussed in the preamble to the proposed rule, Method 21, at an appropriate repair threshold, is capable of achieving the same or better emission reductions as OGI. However, at proposal, we determined that Method 21 was not cost-effective at a semiannual monitoring frequency with a repair threshold of 500 ppm.
While we agree with the importance of allowing the use of Method 21 as an alternative, we need to ensure that its use does not result in fewer emissions reductions than what would otherwise be achieved using OGI, which is the BSER based on our analysis. Available data show that OGI can detect fugitive emissions at a concentration of at least 10,000 ppm when restricting its use during certain environmental conditions such as high wind speeds. Due to the dynamic nature for the OGI detection capabilities, OGI may also image emissions at a lower concentration when environmental conditions are ideal. Because an OGI instrument can only visualize emissions and not the corresponding concentration, any components with visible emissions, including those emissions that are less than 10,000 ppm, would be repaired. Method 21 is capable of detecting fugitive emissions at concentrations well below 10,000 ppm. However, if the repair threshold was set at 10,000 ppm, an owner or operator would not have to repair any leaks that are less than 10,000 ppm, thereby foregoing the reductions that would otherwise be achieved by using the OGI. For the reason outlined in this section, 10,000 ppm is not an appropriate repair threshold for Method 21.
Using information provided by commenters, we evaluated the methane and VOC emission reductions associated with the use of Method 21 at repair thresholds of 10,000 ppm and 500 ppm, the two levels recommended by the various commenters. We used AP-42 emission factors to determine the emissions from fugitive emissions components that were found to be leaking using a Method 21 instrument and concluded that emissions reductions are lower than when OGI is used to survey the same components. The lower emission reductions are due to fugitive emissions with a concentration lower than 10,000 ppm not being found using the Method 21 instrument when it is calibrated to detect emissions at a threshold of 10,000 ppm or greater.
We then calculated the emission reductions that result from using a Method 21 instrument to conduct a monitoring survey at a repair threshold of 500 ppm. At this threshold, the operator would have to repair every component found to have fugitive emissions over 500 ppm threshold. This results in emission reductions greater than the emissions reductions that would be achieved if OGI were used instead. For the reasons stated in this section, using Method 21 to conduct monitoring surveys at a repair threshold of 500 ppm is better than, or at least equivalent to, using OGI to conduct the same survey; we are allowing it in the final rule as an alternative to the use of OGI. We acknowledge that the cost of conducting a survey using Method 21 may be more expensive than using OGI; however, some owners or operators may still chose to use Method 21 for convenience or due to the lack of availability of OGI instruments or trained personnel. Therefore, to ensure that it achieves at least the level of emission reduction to be achieved using the OGI, the final rule allows the use of Method 21 with a repair threshold of 500 ppm.
Based on interest in having Method 21 as an approved alternative, we are finalizing it as an alternative to OGI. Allowing Method 21 as an alternative will address some of the uncertainty expressed by small entities that indicated a concern with needing to purchase an OGI instrument or hire trained OGI contractors to perform their monitoring surveys. We are finalizing Method 21 as an alternative to OGI for monitoring fugitive emissions components at a repair threshold of an instrument reading of 500 ppm or greater. We are also finalizing specific recordkeeping and reporting requirements when Method 21 is used to perform a monitoring survey.

d. Shifting of Monitoring Frequency Based on Performance
The EPA proposed shifting monitoring frequencies (ranging from annual to quarterly monitoring) based on the percentage of components that are found to have fugitive emissions during a monitoring survey. We solicited comment on the proposed monitoring approach, including the proposed metrics of one percent and three percent to determine monitoring frequency or whether the monitoring frequency thresholds should be based on a specific number of components that are found to have fugitive emissions. In addition, the EPA solicited comment on whether a performance-based frequency or a fixed-frequency program was more appropriate.
Most commenters opposed performance-based monitoring frequency. They raised specific concerns that performance-based monitoring and shifting monitoring frequencies would be costly, time-consuming, and impose a complex administrative burden for the industry and states. For example, commenters pointed out that an owner may have hundreds or even thousands of well sites and a potentially ever-changing survey schedule for each of those sites would present an untenable logistical hurdle. Most of the commenters stated that the EPA should finalize a fixed monitoring frequency to provide a level of certainty to owners and operators for planning future schedules of survey crews.
The EPA considered these comments and agrees that imposing a performance-based monitoring schedule would require operators to develop an extensive administrative program to ensure compliance. Under the performance-based monitoring, owners and operators would need to count all of the components at the well sites, affix identification tags on each component or develop detailed piping and instrument diagram. During each monitoring survey, owners and operators would need to calculate the percentage of leaking fugitive emissions components to determine the next monitoring frequency schedule.
We also agree that the shifting monitoring frequencies could cause regulated entities additional administrative burden to determine compliance since the monitoring frequencies could change each year, but the correct frequency may not be reflected in the operating permit. This could also result in fugitive emissions being undetected longer due to less frequent monitoring. We believe that the potential for a performance-based approach to encourage greater compliance is outweighed in this case by these additional burdens and the complexity it would add. Therefore, the EPA is finalizing a fixed-frequency monitoring instead of performance-based monitoring.

e. Fugitive Emissions Components Repair and Resurvey
The EPA proposed that components that are a source of fugitive emissions must be repaired or replaced as soon as practicable and, in any case, no later than 15 calendar days after detection of the fugitive emissions. For sources of fugitive emissions that cannot be repaired within 15 days of finding the emissions, due to technical infeasibility or unsafe conditions, the EPA proposed that the components could be placed on a delay of repair until the next scheduled shutdown or within six months, whichever is earlier. We also proposed that a repaired fugitive emissions component be resurveyed within 15 days of the repair. The EPA solicited comment on all three aspects.
Commenters voiced various opinions regarding the requirements. Many commenters shared concerns that the 15-day window for repairs is too short, due to factors such as remoteness of equipment locations, unsuccessful repair attempts, and multiple components needing repair. Other commenters preferred the 15-day window, in the interest of achieving immediate mitigation of health and safety risks and alignment with standards in several states.
Multiple commenters provided comments on the proposed delay of repair standards, including concerns about delays lasting longer than six months due to availability of supplies needed to complete repairs and information regarding the frequency of delayed repairs. Some commenters also indicated that in some cases, requiring prompt repairs could lead to more emissions than if repairs were able to be delayed, for example if a well shut-in or vent blow-down is required.
Regarding the 15-day window to resurvey repairs to fugitive emissions components, multiple commenters stated that the final rule should allow 30 days for the resurvey, due to the potential need for specialized personnel for the resurvey, while others considered 15 days to be adequate. Regarding performance of the resurvey, many commenters also suggested that soap bubbles, as specified in section 8.3.3 of Method 21, be allowed to determine if the components have been repaired.
After considering the comments above, the EPA agrees that repairs for some sources of fugitive emissions at a well site may take multiple attempts or require additional equipment that is not readily available and may take longer than 15 days to repair. Well sites, unlike chemical plants or refineries, may be located in remote areas and it is unlikely that they would have warehouses or maintenance shops nearby where spare equipment or tools are kept that would be needed to perform repairs within 15 days. We also recognize that fugitive emissions must be alleviated as soon as practicable. We believe that allowing an additional 15 days for repair would give owners and operators enough time to get the parts or the personnel needed to repair or replace the components that could not be repaired during the initial monitoring survey. Therefore, we are finalizing 30 days for the repair of fugitive emissions sources. However, we do recognize that some state LDAR programs require repairs to be made within 5 to 15 days of finding a leak. We encourage operators to continue to fix leaks within that timeframe, since the majority of leaks are fixed when they are found. We do expect that the majority of components will not need the additional 15 days for repair.
The EPA agrees, based on our review of the comments, that only a small percentage of components would not be able to be repaired during that 30 day period. We also agree that a complete well shutdown or a well shut-in may be necessary to repair certain components, such as components on the wellhead, and this could result in greater emissions than what would be emitted by the leaking component. The EPA does not agree that unavailability of supplies or custom parts is a justification for delaying repair ( i.e. , beyond the 30 days for repair provided in this final rule) since the operator can plan for repair of fugitive emission components by having stock readily accessible or obtaining the parts within 30 days after finding the fugitive emissions.
Based on available information, it may be two years before a well is shut-in or shutdown. Therefore, to avoid the excess emissions (and cost) of prematurely forcing a shutdown, we are amending the rule to allow 2 years to fix a leak where it is determined to be technically infeasible to repair within 30 days; however, if an unscheduled or emergency vent blowdown, compressor station shutdown, well shutdown, or well shut-in occurs during the delay of repair period, the fugitive emissions components would need to be fixed at that time. The owner or operator will have to record the number and types of components that are placed on delay of repair and record an explanation for each delay of repair.
Method 21 allows a user to spray a soap solution on components that are operating under certain conditions ( e.g. , no continuous moving parts or no surface temperatures above the boiling point or below the freezing point of the soap solution) to determine if any soap bubbles form. If no bubbles form, the components are deemed to be operating with no detected emissions. We note that spraying soap solution to confirm whether a component has been repaired may not work for all fugitive emissions components, such as a leak found under the hood of the thief hatch because it would be difficult to apply the soap solution or observe bubbles. However, we believe that this alternative will provide some owners and operators a simple, low cost way to confirm that a fugitive emissions component has been repaired. This would also allow the resurveys to be performed by the same personnel that completed the repairs instead of other certified monitoring personnel or hired contractors that would have to come back to verify the repairs. Therefore, we are finalizing the use of the alternative screening procedures specified in Section 8.3.3 of Method 21 for resurveying repaired fugitive emissions components, where appropriate.
For owners or operators that cannot use soap spray to verify repairs, we are allowing an additional 30 days for resurvey of the repaired fugitive emissions components, to allow time for contractors or designated OGI personnel to perform the resurvey because they are not typically the same personnel that would perform the repairs.

f. Definition of “Fugitive Emission Component”
As just discussed, we proposed monitoring, repair, and resurvey of “fugitive emission components.” The EPA solicited comment on the proposed definition of fugitive emissions components. Commenters indicated that, as proposed, the fugitive emissions component definition is too broad and vague, because it contains both equipment and component types, and suggested that the EPA modify the definition to be more targeted and easier for states and other regulatory authorities to determine compliance, and recommended other definitions, such as that used by the state of Colorado.
The EPA agrees with commenters that, as proposed, the fugitive emissions component definition may cause confusion due to inclusion of equipment types, such as uncontrolled storage vessels that are potential sources of vented emissions (as opposed to fugitive emissions), in the definition.
Therefore, we are finalizing changes to the definition to remove equipment types and identify specific components, such as valves and flanges, that have the potential to be sources of fugitive emissions and that, when surveyed and repaired, would significantly reduce GHG and VOC emissions. This targeted list will remove the ambiguity of the proposed definition and will allow owners and operators to consistently identify fugitive emissions at well sites. We are finalizing the definition for fugitive emissions components in § 60.4530a of this final rule.
As finalized, the definition also aligns closely with other states' and federal agencies' definitions of fugitive emissions components by targeting similar components to the components in those definitions. Owners and operators can therefore monitor one set of components while complying with the requirements of this final rule and other state or federal fugitive emissions monitoring programs.

g. Timing of the Initial Monitoring Survey
The EPA proposed that the initial monitoring be conducted within 30 days after the initial startup of the first well completion or modification of a well site. EPA solicited comment on whether the proposal provides an appropriate amount of time to begin conducting fugitive emissions monitoring. We received a wide variety of comments and suggestions for the appropriate time for fugitive emissions monitoring to begin.
Several commenters indicated that initial monitoring should begin after production starts, because time is needed to close out the drilling activities. The commenters further stated that completion activities and the transition from completion to production at well sites is unpredictable and temporary completion equipment may still be onsite 30 days after the “initial startup of the first well completion.” One commenter indicated that production may not begin immediately after a well completion, so initial monitoring should not begin until after production starts.
The EPA acknowledges that at the time of a well completion all of the associated permanent equipment may not be present and conducting the initial monitoring survey may not capture all of the fugitive emissions components that would be in operation during production. In addition, we believe it is important to conduct the initial survey soon after the permanent equipment is in place to catch any improperly installed or defective equipment that may have substantial fugitive emissions immediately after installation. We believe that the permanent equipment will be in place at the startup of production ( i.e. , the initial flow following the end of the flowback when there is continuous recovery of saleable quality gas). Therefore, the startup of production more accurately reflects the start of normal operations and would capture any fugitive emissions from the newly constructed or modified components at the well site. Therefore, we are finalizing that the startup of production marks the beginning of the initial monitoring survey period for the collection of fugitive emissions components.
Furthermore, based on the comments received, we are concerned that the tasks required prior to conducting an initial survey would take more than the 30 days we had proposed. Because each new or modified well site must be covered by a monitoring plan for a company-defined area, owners and operators must visit and assess each new or modified well site in order to incorporate it into a newly developed or modified monitoring plan for that area. They also need to secure certified monitoring survey contractors or monitoring instruments. In addition, they need to ensure that other compliance requirements will be met, such as recordkeeping and reporting. In light of the activities described above, the EPA is requiring in the final rule that the initial survey be conducted within 60 days from the startup of production.
While 60 days from startup of production is sufficient time to conduct the initial survey once the underlying program infrastructure is established, we recognize that the initial establishment of the required program's infrastructure and the initial round of monitoring surveys will require additional time. Most importantly, additional time is needed to secure the necessary equipment or trained personnel, according to one OGI instrument manufacturer, which commented that they would need to increase production of key components for the OGI instrument to meet demand. The OGI manufacturer also indicated that they would need to scale up the number of personnel needed to provide OGI training and service of the equipment. We are concerned that currently there is not sufficient equipment and trained personnel to meet the demand imposed by this final rule in the near term. Accordingly, it will be necessary to have a window of time for trained personnel to work through this backlog. Furthermore, as previously mentioned, an owner or operator will need to develop a monitoring plan that would apply to each well site located within the company-defined area, which requires an assessment of each well site. Therefore, before a plan can be developed or modified, the owner or operator would need time to visit each well site within the company-defined area. Based on the information that we used to develop the model well site plants, each company-defined area may consist of up to 22 well sites within a 70-mile radius of a central or district office. In light of the above, the initial site visits and development of the monitoring plan would require a significant amount of time. Time is also needed to secure certified monitoring survey contractors or monitoring instruments. In addition, owners and operators will need to plan the logistics of the initial activities in order to comply with the requirements. This includes time to set up recordkeeping systems and to train personnel to manage the fugitive emissions monitoring program. These corporate systems are critical for submitting the notification of initial and subsequent annual compliance status.
As noted above, once programs are established and equipment supplies have caught up, well owners will be able to add additional affected facilities to existing programs and, thus, this longer timeline will not be needed. Therefore, in order to provide time for owners and operators to establish the initial groundwork of their fugitives program, we are requiring that the initial monitoring survey must take place by June 3, 2017 or within 60 days of the startup of production, whichever is later. ^{87} We anticipate that sources will begin to phase in these requirements as additional devices and trained personnel become available. For additional discussion, please refer to the materials in the docket.
^{87} For well site activities, such as the installation of a new well, a hydraulically fractured or refractured well, which commenced on or after September 18, 2015 are subject to this rule once it is finalized.

h. Monitoring Plan
The EPA proposed that owners or operators develop a corporate-wide fugitive emissions monitoring plan that specifies the measures for locating sources and the detection technology to be used. We also proposed that, in addition to the corporate-wide monitoring plan, owners or operators develop a site-specific fugitive emissions monitoring plan that specifies information such as the number of fugitive emission components that pertains to that single site. ^{88} The EPA solicited comment on the required elements of the proposed corporate-wide monitoring plan; specifically, the EPA asked for comment on whether other techniques, such as visual inspections to help identify indicators of potential leaks, should be included within the monitoring plan.
^{88} See 80 FR 56612 (September 18, 2015).
Some commenters agreed with the EPA's proposal to require a corporate-wide fugitive monitoring plan but expressed concerns about the elements of the plan, while others objected that the proposed plan is overly prescriptive and costly, with particular concerns about including requirements for a walking path and for digital photographs. Other commenters suggested changing the scope of monitoring plans to accommodate variations in locations of contractors and equipment.
We considered these comments, and we have made the following changes to the proposal in the final rule.
First, the final rule requires owners or operators to develop a fugitive emission monitoring plan for well sites within a company-defined area instead of corporate-wide and site-specific monitoring plans. This will give companies the flexibility to group well sites that are located within close proximity, under common control within a field or district, or that are managed by a single group of personnel. This would also afford owners and operators of well sites within different basins the ability to tailor their plans for the specific elements within each basin ( i.e. , geography, well site characterization, emission profile). Information we received indicates that, in many cases, several sites within a specific geographic area may have similar equipment and would use the same contractors, company-owned monitoring instruments, or company personnel to perform the monitoring surveys. Based on a study conducted for the city of Fort Worth, Texas, we estimate that, on average, there are 22 well sites within a company's specific geographic region. ^{89} In this study, a total of 375 well pads were identified in the Fort Worth area, and these well pads were owned and operated by 17 different companies, or an average of 22 well pads per company. We believe these data provide a reasonable estimate of the number of well sites operated by a company in a specific geographic region. Therefore, we are removing the proposed corporate-wide and site-specific monitoring plan requirements and finalizing requirements that owners and operators develop a fugitive emissions monitoring plan for each of the company-defined areas that covers the collection of fugitive emissions components at well sites. As a result, the final rule requires owners and operators to develop a plan that describes the sites generally, including descriptions of equipment, plans for how they will monitor, etc., that apply to all similar sites. This will allow owners and operators to develop a monitoring plan for groups of similar well sites within an area for ease of implementation and compliance.
^{89} ERG and Sage Environmental Consulting, LP. City of Fort Worth Natural Gas Air Quality Study, Final Report. Prepared for the City of Fort Worth, Texas. July 13, 2011. Available at http://fortworthtexas.gov/gaswells/default.aspx?id=87074 .
Second, we have made changes in the final rule to the proposed digital photograph requirements. We believe concerns regarding the burden of printing or transmitting digital pictures within the annual report are the result of unclear language in the proposed rule. Our intent was to require the owner or operator to include one or more digital photographs of the survey being performed. However, we inadvertently included that text within the requirement for each fugitive emission. It was not our intent to require a digital photograph of each fugitive emission in the annual report; instead we wanted to ensure, through pictorial documentation, that the monitoring survey had been performed. After consideration of the comments received, we believe we can further streamline this requirement. Because a source with fugitive emissions during the reporting period is subject to other recordkeeping and reporting requirements, this provides sufficient documentation that the survey was performed. Therefore, we have removed the proposed requirement to provide a digital photograph in the annual report for each required monitoring survey. We are requiring owners and operators to retain a record of each monitoring survey performed with optical gas imaging by keeping one or more digital photographs or videos captured with the OGI instrument. The photograph or video must either include the latitude and longitude of the collection of fugitive emissions components imbedded within the photograph or video or must consist of an image of the monitoring survey being performed with a separately operating GPS device within the same digital picture or video, provided that the latitude and longitude output of the GPS unit can be clearly read in the image.
Third, with the allowance for Method 21 monitoring as an alternative to OGI instrument monitoring, we are finalizing a requirement that sources of fugitive emissions ( e.g. , a leaking fugitive emissions component) that cannot be repaired during the initial monitoring survey either be temporarily tagged for identification for repair or be digitally photographed or video recorded in a way that identifies the location of the fugitive emissions component needing repair. If an owner or operator chooses to digitally photograph the leaking component(s) instead of using identification tags, the photograph will meet the requirement to take a digital photograph during a monitoring survey, as long as the digital photograph is taken with the OGI instrument and includes the latitude and longitude either imbedded in the photograph or visible in the picture.
Fourth, we are finalizing the walking path requirement with minor changes. We are revising the walking path terminology to observation path in order to clarify that our intent is focused on the field of view of the OGI instrument, not the physical location of the OGI operator. We believe this terminology change will alleviate commenters' concerns regarding the potentially overly prescriptive nature of the defined walking path with transient interferences, environmental obstructions, weather conditions and safety issues. This revision also clarifies our intent to allow for the use of all types of OGI instruments ( e.g. , mounted, handheld or remote controlled).
The purpose of the observation path is to ensure that the OGI operator visualizes all of the components that must be monitored, just as a Method 21 operator in a traditional leak detection program surveys all of the components. In the traditional scenario, the owner or operator tags all of the equipment that must be monitored, and when the Method 21 operator subsequently inspects the affected facility, the operator scans each component's tag and notes the component's instrument reading. The EPA realizes that this is a time-consuming practice. Additionally, while the Method 21 operator must contact each component with the probe of the Method 21 instrument and monitor it individually, we recognize that with OGI, the operator can be away from the components and still monitor several components simultaneously.
Recognizing these aspects of traditional and OGI leak detection methods, we want to offer owners and operators an alternative to the traditional tagging approach. However, because we are no longer requiring a traditional log of instrument readings, the rule must provide another way to ensure that the compliance obligation to monitor all equipment is met. We believe that the observation path requirement effectively ensures that an operator looks at all of the required components but reduces the burden of tagging and logging associated with traditional Method 21 programs. Unlike the tagging and logging requirement associated with traditional Method 21 programs, the requirement to develop an observation path is a one-time requirement (as long as the path does not need to change due to the addition of components). We do not expect facilities to create overly detailed process and instrumentation diagrams to describe the observation path. The observation path description could be a simple schematic diagram of the facility site or an aerial photograph of the facility site, as long as such a photograph clearly shows locations of the components and the OGI operator's walking path. As a result, we do not believe that the requirement to document the observation path is burdensome.

i. Provision for Emerging Technology
As the EPA noted in the 2015 proposal, fugitive emissions monitoring is a field of emerging technology, and major advances are expected in the near future. 80 FR at 56639. We are seeing a rapidly growing push to develop and produce low-cost monitoring technologies to find fugitive and direct methane and VOC emissions sooner and at lower levels than current technology allows, thus enhancing the ability of operators to detect fugitive emissions. During the development of the proposed rule, the EPA solicited comments and information on emerging technologies that could potentially be used to detect fugitive emissions at well sites or compressor stations and how these technologies could be used ( e.g. , as standalone monitors or in conjunction with OGI). Several commenters indicated that methane and VOC leak detection technology is undergoing continuous and rapid development and innovation, potentially yielding, for example, continuous emissions monitoring technologies, and urged the EPA to allow emerging technology to be used for fugitive emissions monitoring. The EPA agrees that continued development of these cost effective technologies is important and that the final rule should encourage and accommodate it to the extent possible.
Fugitive emissions monitoring and repair is a work practice standard, as allowed under section 111(h)(1) of the CAA. A work practice standard is an emission limitation that is not necessarily in a numeric format, such as the visualization of fugitive emissions using OGI. As described in section 111(h)(3), the Administrator may approve an alternative means of emission limitation for a work practice standard if it can be proven that an equal reduction in emissions will be achieved. To that end, pursuant to CAA section 111(h)(3), we are establishing in the final rule a process for the agency to permit the use of innovative technology for reducing fugitive emissions at well sites and/or compressor stations. Specifically, under the final rule, owners or operators may submit a request to the EPA for “an alternative means of emission limitation” where a technology has been demonstrated to achieve a reduction in emissions at least equivalent to the reduction in emissions achieved under the work practice or operational requirements for reducing fugitive emissions at well sites and/or compressor stations in subpart OOOOa.
To facilitate the application and review process, the final rule includes information to be provided in the application that would be needed for us to expeditiously evaluate the emerging technology. Such information must include a description of the emerging technology and the associated monitoring instrument or measurement technology; a description of the method and data quality used to ensure the effectiveness of the technology; a description of the method detection limit of the technology and the action level at which fugitive emissions would be detected; a description of the quality assurance and control measures employed by the technology; field data that verify the feasibility and detection capabilities of the technology; and any restrictions for using the technology.
This process will allow for the use of any currently emerging technology or any technology that is developed in the future that is capable of achieving methane and VOC emission reductions at levels that are at least equivalent to reductions achieved when using OGI or Method 21 for fugitive emissions monitoring. This process will also allow for the use of alternative fugitive emissions monitoring approaches such as periodic, continuous, fixed, mobile, or a hybrid approach. Consistent with section 111(h)(3), any application will be publicly noticed in the Federal Register , which the EPA intends to provide within six months after receiving a complete application, including all required information for evaluation. The EPA will provide an opportunity for public hearing and comment on the application and on intended action the EPA might take. The EPA intends to make a final determination within six months after the close of the public comment period. The EPA will also publish its final determination in the Federal Register . If final determination is a denial, the EPA will provide reasoning for denial and recommendations for further development and evaluation of the emerging technology, if appropriate.

j. Definition of Well Site
In the proposed rule, we had defined “well site,” for purposes of the fugitive emissions standards at § 60.5397a, to include separately located, centralized tank batteries. We received comments that the definition was unclear and that there was concern that the affected facility status of centralized tank batteries could inadvertently pull into affected facility status those well sites that only contain one or more wellheads, which were proposed to be excluded from affected facility status. We agree that the proposed definition of well site was somewhat unclear, and we have revised the definition in the final rule. With regard to the affected facility status of centralized tank batteries and its effect on well sites that only contain one or more wellheads, our intent is not to have well sites that only contain one or more wellheads subject to fugitive emissions standards. To make this intent more explicit, we have added language to § 60.5365a(i)(2) to this effect.

2. Fugitive Emissions From Compressor Stations
Based on our consideration of the comments received and other relevant information, we have made several changes to the proposed fugitive emissions standards for the compressor stations in this final rule. The finalized fugitive emissions monitoring and repair requirements for compressor stations are similar to the requirements for well sites, so we streamlined this section by referencing our well site discussion, where appropriate. Below we provide the significant changes since proposal and our rationales for these changes.

a. Monitoring Frequency
In conjunction with semiannual monitoring, the EPA co-proposed annual monitoring, solicited comment on conducting monitoring surveys on a quarterly basis, and solicited comment on the availability of trained OGI contractors and OGI instrumentation. 80 FR at 56639.
Some commenters supported quarterly monitoring on the belief that it is more accurate and cost-effective than the monitoring frequencies proposed by the EPA. Other commenters opposed quarterly monitoring, alleging that it is not cost-effective and may be infeasible due to weather or shortages associated with OGI, necessary for the surveys. Also citing factors such as cost-effectiveness and questioning data underlying the EPA's analysis, some commenters supported annual monitoring or generally opposed semiannual monitoring.
Based on the comments received, the EPA reviewed the type of equipment and the associated components that were included in the model plant used to determine emission reductions and costs for compressor stations at proposal. The storage and transmission model plants developed for the proposed rule had inadvertently included site blowdown open-ended lines, which are not sources of fugitive emissions but are vents. Therefore, the transmission and storage model plants were revised for the final rule to remove these components from the total component count.
The EPA used information provided by commenters to re-evaluate the control options for annual, semiannual and quarterly monitoring. As shown in the TSD, the control costs for quarterly, semiannual, and annual monitoring remain cost-effective for reducing GHG (in the form of methane) and VOC emissions. Semiannual and quarterly monitoring would provide greater emissions reductions than would annual monitoring. However, as explained in the proposed rule, we were concerned with compliance burden, in particular for small businesses, associated with quarterly monitoring even though it was cost effective. 80 FR at 56641. Specifically, we were concerned that the limited supplies of trained personnel for performing surveys might lead to disadvantages for small businesses, which are more likely to hire trained personnel. Id. However, certain changes we have made in the final rule will help alleviate the concern. For example, the final rule requires that the initial monitoring survey must take place by June 3, 2017 or within 60 days of the startup of production, whichever is later. This allows additional time for owners and operators to establish the requirement program's infrastructure at the initial stage. Another example, in light of comments urging EPA to allow Method 21 as an alternative, and the fact that we know many companies already own Method 21 instruments, offering Method 21 at a repair threshold of 500 ppm, as an alternative to conduct the monitoring surveys, will alleviate some of the demand for OGI instruments and personnel. Therefore, the EPA is finalizing quarterly monitoring frequency for the collection of fugitive emissions components at compressor stations to ensure the maximum amount of emission reductions. Please see the RTC document in the public docket for further discussion. ^{90}
^{90} See EPA docket ID No. EPA-HQ-OAR-2010-0505.
Some commenters requested that fugitive emissions monitoring exemptions be given to well sites and compressor stations that are located in areas of the country that routinely experience extreme weather. The commenters noted that these areas experience several months of average temperatures below 0 °F and long periods of snow cover. The commenter also provided information from one of the OGI instrument manufacturers which indicates that the instrument cannot operate at temperatures below −4 °F. The commenter also expressed concerns about monitoring survey personnel's safety if they were to attempt to conduct surveys in these weather conditions.
We agree that there are areas within the United States that regularly have extreme weather conditions such as three or more consecutive months of average temperatures below 0 °F. We also obtained information from two OGI instrument manufacturers that confirm that the minimum operating temperature of the OGI instruments is −4 °F. As such, these prolonged subzero temperature conditions would make performing fugitive emissions monitoring surveys impossible during several months of the year. Additionally, while we believe that company personnel may be accessing these sites for maintenance activities, it may be difficult to transport OGI contractors to unmanned sites within these areas during these periods, as outside access for OGI contractors usually requires air travel to access these production sites.
Based on these considerations, we are waiving quarterly fugitive emissions monitoring surveys at compressor stations if, based on three years of historical climatic data, two of the three consecutive months within the quarter has an average temperature below 0 °F. The average temperatures must be determined by historical climatic data from the National Oceanic and Atmospheric Administration or a source approved by the EPA Administrator. This waiver may not be used for two consecutive quarters and is not extended to well sites because we do not believe that there will be any locations that have average monthly temperatures below 0 °F for six consecutive months. Owners and operators will have to keep records of the waiver period, including the three months within the quarterly monitoring period, the average monthly temperatures and the source of the temperature information. Owners and operators will also have to report this information in their annual report.

b. Monitoring Using Method 21
In performing analysis for the proposed rule, the EPA found OGI to be more cost-effective than Method 21 and, therefore, identified OGI as the BSER for monitoring fugitive emissions at compressor stations. See 80 FR 56641, September 18, 2015. As with well sites, discussed previously in section VI.F.1.c, the EPA solicited comment on whether to allow Method 21 as an alternative fugitive emissions monitoring method to OGI and solicited comment on the repair threshold for components that are found to have fugitive emissions using Method 21.
The EPA received the same types of comments regarding allowing Method 21 as an alternative to OGI for monitoring fugitive emissions at compressor stations as for well sites, as discussed in section VI.F.1.c. Likewise, for the same reasons as discussed earlier, we are finalizing Method 21 as an alternative to OGI for monitoring fugitive emissions components at compressor stations at a repair threshold of an instrument reading of 500 ppm or greater. We are also finalizing specific recordkeeping and reporting requirements when Method 21 is used to perform a monitoring survey. See section V.J for more details on the recordkeeping and reporting requirements.

c. Shifting of Monitoring Frequency Based on Performance
The EPA proposed shifting monitoring frequencies (ranging from annual to quarterly monitoring) based on the percentage of components that are found to have fugitive emissions during a monitoring survey. We solicited comment on the proposed monitoring scheme, including the proposed metrics of one percent and three percent to determine monitoring frequency or whether the monitoring frequency thresholds should be based on a specific number of components that are found to have fugitive emissions. In addition, the EPA solicited comment on whether a performance-based frequency or a fixed-frequency was more appropriate.
The EPA received the same comments regarding frequency of monitoring for compressor stations as for well sites, discussed in section VI.F.1.d. Likewise, for the same reasons as discussed earlier, the EPA is finalizing a fixed monitoring frequency instead of performance based monitoring.

d. Fugitive Emissions Components Repair and Resurvey
The EPA proposed that a source of fugitive emissions at compressor stations must be repaired or replaced as soon as practicable, and, in any case, no later than 15 calendar days after detection of the fugitive emissions. The EPA solicited comment on whether 15 days is the appropriate amount of time for repair of sources of fugitive emissions from compressor stations. We also solicited comment on whether 15 days is the appropriate amount of time needed to resurvey a component after it has been repaired.
The EPA received the same comments regarding the timeframe for repairs, delay of repair, and resurveys for compressor stations as for well sites, discussed in section VI.F.1.e. Likewise, for the same reasons as discussed earlier, we are finalizing 30 days for the repair of fugitive emissions sources and an additional 30 days for resurvey of the repaired fugitive emissions components. We also are finalizing revisions to the delay of repair requirements. If a repair cannot be made due to a technical infeasibility that would require a blowdown or shutdown of the compressor station, or would be unsafe to repair by exposing personnel to immediate danger, the repair can be delayed until the next scheduled or emergency blowdown or station shutdown or within 2 years of finding the fugitive source of emissions, whichever is earlier. We believe that the likelihood of an emergency blowdown or a compressor station shutdown occurring within six months of finding fugitive emissions from a component may be low; however, it would be feasible to repair the component within a two-year timeframe, since one of above described events is likely to occur within that two-year timeframe. The owner or operator will also have to record the number and types of components that are placed on delay of repair and record an explanation for each delay of repair.
Similarly with respect to well sites, and as discussed in section VI.F.1.e, we are finalizing the use of the alternative screening procedures specified in Section 8.3.3 of Method 21 for resurveying repaired fugitive emissions components. Please see the RTC document in the public docket for further discussion.

e. Definition of “Fugitive Emission Component”
As discussed earlier, we proposed monitoring, repair and resurvey of “fugitive emission components,” that apply to both well sites and compressor stations because the type of components are identical. We solicited comment on the proposed definition. The EPA received the same comments regarding the fugitive emissions component definition for compressor stations as for well sites, discussed in section VI.F.1.f. Likewise, for the same reasons as discussed earlier, we are finalizing changes to the definition to identify specific components, such as valves and flanges, that have the potential to be sources of fugitive emissions and that, when surveyed and repaired, would significantly reduce GHG and VOC emissions. This targeted list will remove the ambiguity of the proposed definition and will allow owners and operators to consistently identify fugitive emissions at compressor stations.

f. Timing of the Initial Monitoring Survey
The EPA proposed that the initial monitoring be conducted within 30 days after the initial startup of a new compressor station or modification of an existing compressor station. The EPA solicited comment on whether 30 days is an appropriate amount of time to begin conducting fugitive emissions monitoring.
Many commenters supported a longer timeframe for commencing monitoring, citing time needed to complete well ties into a compressor station that collects field gas, safety, and the relationship with other regulations, while some commenters supported the timeframe proposed. The EPA recognizes that at the time of startup of a compressor station, additional gathering lines or well tie-ins may be required. However, we also believe that, at the time of startup, the associated collection of fugitive emissions components is operational and initial monitoring can begin, even if the gathering lines or well tie-ins are incomplete, which could take several months or longer. Sources of fugitive emissions could go undetected for months if we were to allow monitoring to begin after all of the gathering lines and tie-ins were completed. Therefore, we are finalizing the proposed requirement that initial monitoring will begin after the initial startup of a compressor station instead of allowing all of the gathering lines or tie-ins to be completed before monitoring begins.
However, based on the comments received, we are concerned that the tasks required prior to conducting an initial survey would take more than the 30 days we had proposed. Because each new or modified compressor station must be covered by a monitoring plan for a company-defined area, owners and operators must visit and assess each new or modified compressor station in order to incorporate it into a newly developed or modified monitoring plan for that area. They also need to secure certified monitoring survey contractors or monitoring instruments. In addition, they need to ensure that other compliance requirements will be met, such as recordkeeping and reporting. In light of the activities described above, the EPA is requiring in the final rule that the initial survey be conducted within 60 days from startup or modification of a compressor station.
While 60 days from startup or modification of a compressor station is sufficient time to conduct the initial survey once the underlying program infrastructure is established, we recognize that the initial establishment of the required program's infrastructure and the initial round of monitoring surveys will require additional time. Most importantly, additional time is needed to secure the necessary equipment or trained personnel according to one OGI instrument manufacturer, which commented that they would need to increase production of key components for the OGI instrument to meet demand. The OGI manufacturer also indicated that they would need to scale up the number of personnel needed to provide OGI training and service of the equipment. We are concerned that currently there is not sufficient equipment and trained personnel to meet the demand imposed by this final rule in the near term. Accordingly, it will be necessary to have a window of time for trained personnel to work through this backlog. Furthermore, as previously mentioned, an owner or operator will need to develop a monitoring plan that would apply to each compressor station located within the company-defined area, which requires an assessment of each compressor station. Therefore, before a plan can be developed or modified, the owner or operator would need time to visit each compressor station within the company-defined area. In light of the above, the initial site visits and development of the monitoring plan would require a significant amount of time. Time is also needed to secure certified monitoring survey contractors or monitoring instruments. In addition, owners and operators will need to plan the logistics of the initial activities in order to comply with the requirements. This includes time to set up recordkeeping systems and to train personnel to manage the fugitive emissions monitoring program. These corporate systems are critical for submitting the notification of initial and subsequent annual compliance status.
As noted above, once programs are established and equipment supplies have caught up, well owners will be able to add additional affected facilities to existing programs and, thus, this longer timeline will not be needed. Therefore, in order to provide time for owners and operators to establish the initial groundwork of their fugitives program, we are requiring that the initial monitoring survey must take place by June 3, 2017 or within 60 days of the startup or modification of a compressor station, whichever is later. We anticipate that sources will begin to phase in these requirements as additional devices and trained personnel become available. For additional discussion, please refer to the materials in the docket.

g. Monitoring Plan
The EPA proposed that owners or operators develop a corporate-wide emissions monitoring plan that specifies the measures for locating sources and the detection technology to be used. The EPA also proposed that owners or operators develop a separate site-specific fugitive emissions monitoring plan that specifies information, such as the number of fugitive emission components for that site and for each affected facility. The EPA solicited comment on the required elements of the proposed corporate-wide monitoring plan and specifically asked for comment regarding whether the monitoring plan should include other techniques, such as visual inspections to help identify indicators of potential leaks.
As with this topic in the context of well sites, and as discussed in section VI.F.1.h, some commenters agreed with the EPA's proposal to require a corporate fugitive monitoring plan, but expressed concerns about the elements of the plan, while others objected that the proposed plan is overly prescriptive and costly, with particular concerns about including requirements for a walking path and for digital photographs. Other commenters suggested changing the scope of monitoring plans to accommodate variations in locations of contractors and equipment.
Based on the comments that we received, we are revising the fugitive emissions monitoring plan for compressor stations. We acknowledge that developing and implementing a corporate-wide monitoring plan that would be applicable to all compressor stations within a company could be problematic because compressor station configurations may differ across areas ( i.e., basins, fields, or districts) and what may be applicable in one area may not be relevant in another area. This would mean that a company could have to design and implement a site-specific plan for each compressor station.
We also agree that developing a site-specific plan may be overly burdensome because several gathering and boosting or transmission compressor stations may exist in a specific geographic area and have similar equipment. Using information from the Interstate Natural Gas Association of America (INGAA) and the Energy Information Administration (EIA), we estimated that, on average, compressor stations are located 70 miles apart. We also assumed that a company could monitor emissions from gathering and boosting or transmission compressor stations within a 210-mile radius of a central location. Using these assumptions, we estimated that a company could monitor seven gathering and boosting or transmission compressor stations within that company's specific geographic region. In such cases, companies would benefit from having a plan to cover all of the compressor stations within that area, as the monitoring will likely require use of the same contractors, the same company-owned monitoring instruments, or the same company personnel to perform the monitoring surveys. Allowing companies to develop one fugitive emissions monitoring plan for all of the compressors within a company-defined area would alleviate burden and provide efficiency for owners and operators.
Therefore, we are replacing the proposed corporate-wide and site-specific monitoring plan requirements with a requirement for owners or operators to develop a corporate monitoring plan for each of the company-defined areas that would cover the collection of fugitive emissions components at the compressor stations located within that company-defined area. This will allow owners and operators flexibility in developing monitoring plans for compressor stations by allowing owners and operators to determine which company-defined area can be covered under the specifications outlined in one monitoring plan, for ease of implementation and compliance. See section VI.F.1.h of this preamble for further discussion.

h. Modifications for Compressor Stations
The EPA proposed that, for the purposes of the collection of fugitive emissions monitoring and repair requirements, a compressor station is modified when a new compressor is constructed at an existing compressor station or when a physical change is made that causes an increase in the compression capacity of an existing compressor station. We received numerous comments on the compressor modification definition.
Several commenters stated that the compressor station modification definition is too vague and broad because anytime a physical modification occurred, a regulatory modification would be triggered regardless of whether there were additional emissions. Commenters also stated if a compressor station is not operating at full capacity, addition of a compressor may not necessarily increase the compressor station capacity, nor would addition of a compressor with greater horsepower (thus adding capacity) necessarily increase emissions.
At proposal, we attempted to identify distinct actions that we were confident would result in an emissions increase and would clearly mark for operators and regulators when a modification occurs. However, upon reviewing the comments, we agree that certain triggering events identified in the proposal may not result in an increase in emissions. Specifically, EPA agrees that an addition of a compressor does not result in an increase in emissions in all instances. For example, there is no emission increase when a new compressor is being installed as a replacement to an existing one. We have, therefore, made changes in the final rule to clarify when an addition of a new compressor would increase emission and therefore trigger the fugitive emission standards ( i.e., when it is installed as an additional compressor or if it is a replacement that is of greater horsepower than the compressor or compressors that it is replacing).
The EPA agrees that an increase in the compression capacity that is not due to the addition of a compressor that would result in an increase of the overall design capacity of the compressor station is not a modification. For example, a compressor station may have to increase the operating throughput by bringing existing compressors on-line to meet demand during peak seasons. In such a case, the compressors' capacities are already accounted for in the overall design capacity for the compressor station, and bringing them on-line would not increase the overall design capacity nor would it increase the potential emissions of the compressor station. Therefore, we are not finalizing that an increase in compression capacity is a modification.
Commenters also indicated that the addition of a new compressor at an existing compressor station should not trigger a fugitive emissions monitoring program for the entire compressor station but, should only apply to the new compressor and its associated components. We disagree that the addition of a compressor at an existing compressor station should not trigger a fugitive emissions monitoring program for the entire compressor station. We have clarified that the installation of a compressor will only trigger the fugitive monitoring requirements if it is installed as an additional compressor or if it is a replacement that is of greater horsepower than the compressor or compressors that it is replacing. In this case, the design capacity and potential emissions of the compressor station would increase. Unlike the affected facilities for purposes of standards for centrifugal and reciprocating compressors themselves, the affected facility for purposes of the fugitive emission requirements is the collection of fugitive emissions components at a compressor station, not the fugitive emissions components associated with a single compressor. Therefore, if a compressor is added to an existing compressor station, the entire compressor station is subject to the fugitive emissions monitoring program.
Therefore, we are finalizing a definition that we are confident identifies actions that increase emissions and achieves our original goal of having clearly identifiable criteria that can be easily recognized by operators and regulators. We are finalizing that a modification to a compressor station occurs when a compressor is added to a compressor station or if one or more compressors is replaced with one or more compressors with a greater total horsepower.

i. Provision for Emerging Technology
Pursuant to CAA section 111(h)(3), we are establishing in the final rule a process for the Agency to permit the use of innovative technology for reducing fugitive emissions at well sites and/or compressor stations. For a detailed discussion, please see section VI.F.1.i.

G. Equipment Leaks at Natural Gas Processing Plants
For equipment leaks at natural gas processing plants, the EPA received a total of seven comments addressing issues such as the definition of natural gas processing plant and whether OGI may be used in place of Method 21. We reviewed the comments received and determined to finalize the standard for equipment leaks at natural gas processing plants as proposed. Specifically, the final rule requires NSPS part 60, subpart VVa level of control, including a detection limitation of 500 ppm for certain pieces of equipment. Please see the TSD and RTC documents in the public docket for further discussion.

H. Reconsideration Issues Being Addressed
To address numerous items on which we granted reconsideration, we proposed amendments to subpart OOOO and solicited comment on certain topics that would also impact the new NSPS requirements. With some revisions based on our consideration of public comment, the EPA is finalizing certain reconsideration amendments. These amendments address: Storage vessel control device monitoring and testing provisions; initial compliance requirements for bypass devices; recordkeeping requirements for repair logs for control devices failing a visible emissions test; clarification of the due date for the initial annual report under the 2012 NSPS; flare design and operation standards; LDAR for open-ended valves or lines; compliance period for LDAR for newly affected units; exemption to notification requirement for reconstruction; disposal of carbon from control devices; the definition of capital expenditure; and continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities. This section identifies specifically what the EPA proposed, identifies the regulatory text changes from proposal, and states how the EPA is finalizing these provisions. ^{91} Please see the TSD and RTC documents in the public docket for further discussion. ^{92}
^{91} 80 FR 56645, September 18, 2015.
^{92} See EPA docket ID No. EPA-HQ-OAR-2010-0505.

1. Storage Vessel Control Device Monitoring and Testing Provisions
The EPA proposed regulatory text changes to address performance testing and monitoring of control devices used for new storage vessel installations and centrifugal compressor emissions, specifically relating to in-field performance testing of enclosed combustors. The EPA specifically proposed to revise the limit for total organic carbon (TOC) concentration in the exhaust gases at the outlet of the control device from 20 ppmv to 600 ppmv as propane on a dry basis corrected to 3 percent oxygen, a value that more appropriately reflects 95 percent control of VOC inflow to control devices. The EPA also proposed initial and ongoing performance testing for any enclosed combustors used to comply with the emissions standard for an affected facility and whose make and model are not listed on the EPA Oil and Natural Gas Web site ( http://www.epa.gov/airquality/oilandgas/implement.html ) as those having already met a manufacturer's performance test demonstration. The proposal stated that performance testing of combustors not listed at the above Web site would be conducted on an ongoing basis, every 60 months of service, and monthly monitoring of visible emissions from each unit would also be required.
Additionally, the EPA proposed amendments to make the requirements for monitoring visible emissions consistent for all enclosed combustion units. Specifically, the EPA proposed to amend 40 CFR 60.5413(e)(3) to require monthly 15-minute period observations using EPA Method 22.
Based on information submitted through the public comment process, the EPA has identified four necessary revisions for the final storage vessel provisions. First, commenters provided information to the EPA concerning the use of 600 ppmv as propane as appropriately reflecting 95 percent control of VOC inflow to control devices. After an evaluation of the comments, we agreed that the EPA's assumption about the ratio of fuel to combustion air was incorrect, making the proposed 600 ppmv as propane value incorrect. The 600 ppmv as propane value was derived in the memorandum dated June 2, 2015, ^{93} which discusses the background for the § 60.5412(a)(1)(ii) TOC exhaust gas standard for combustion control devices to control VOC emissions from oil and gas affected facilities. While this analysis reflects the destruction of hydrocarbons compared to the concentration of hydrocarbon in the inlet fuel, our analysis did not take into account any in-stack dilution represented by the introduction of combustion air or the correction of that air to 3 percent oxygen. Since hydrocarbon combustion requires approximately a ratio of 12:1 input of combustion air to hydrocarbon, the outlet concentration of TOC would be adjusted downward to 275 parts per million by volume on a wet basis (ppmvw), as propane, at 3 percent O 2 . The final rule corrects this concentration at § 60.5412(a)(1)(ii), and the EPA has appended the memo in the public docket with this adjustment.
^{93} See Docket ID No. EPA-HQ-OAR-2010-0505-4907.
Second, the EPA is finalizing amendments to make the requirements for monitoring of visible emissions consistent for all enclosed combustion units. Prior to the proposal, enclosed combustors that met the manufacturer's performance test requirement were to conduct quarterly observations for visible smoke emissions employing section 11 of EPA Method 22 for a 60-minute period. Petitioners suggested it would ease implementation to adjust the frequency and duration to monthly 15-minute EPA Method 22 tests, which is currently required for continuous monitoring of enclosed combustors that are not manufacturer tested. The EPA agrees with the petitioners. This revision will result in consistent requirements to all enclosed combustors, which will make compliance easier for owners and operators. Because both monitoring requirements ensure compliance of the enclosed combustors, and having the same requirement would ease implementation burden, we are finalizing amendments to §§ 60.5413(e)(3) and 60.5415(b)(2)(vii)(B) to require monthly 15-minute period observations using EPA Method 22 Test, as suggested by the petitioner.
The EPA proposed requirements for determining applicability for new storage tanks that replace existing tanks. Commenters provided alternative text indicating how the meaning of the regulation was difficult to discern. The EPA considered the suggested text and agrees that amending this section will make the requirements for compliance easier to understand. The amended language has been finalized in § 60.5365(e)(4).
Fourth, the EPA received comments requesting removal of the requirement that certain devices that route emissions to processes must reduce emissions by 95 percent and instead be written to be consistent with § 60.5411a(c), which requires that process devices must operate 95 percent of the year or greater. Upon further reflection, the EPA determined that, because § 60.5395a(a) clearly requires that affected sources (except those with uncontrolled emissions below 4 tons per year (tpy)) must reduce VOC emission by 95 percent, it is not necessary to further prescribe the level of reduction to be achieved when emissions are routed to a process. The EPA has therefore removed such specification in § 60.5395a(b)(1) in the final rule. As finalized, this specific provision relative to control requirements is the same for centrifugal compressors, pneumatic pumps, and storage vessel affected facilities routing to a process.

2. Initial Compliance Requirements for Bypass Devices
The EPA proposed to amend § 60.5416(c)(3)(i) to include notification via remote alarm to the nearest field office in order to maintain consistency with previous amendments. The EPA proposed to require both an alarm at the bypass device and a remote alarm. The EPA proposed similar amendments to parallel requirements at § 60.5411(a)(3)(i)(A) for closed vent systems used with reciprocating compressors and centrifugal compressor wet seal degassing systems. At proposal to amend subpart OOOO, EPA changed “or” to “and” under subpart OOOO at §§ 60.5411(a)(3)(i)(A) and 60.5411(c)(3)(i)(A), which would have required that both an audible and remote alarm be installed on a bypass device with the potential to vent to the atmosphere. One commenter pointed out that the requirements would be applied retroactively, as the EPA changed the requirements in subpart OOOO as well as subpart OOOOa. The EPA agrees with the commenter that our intent was not to create a retroactive requirement by revising subpart OOOO. The EPA is therefore not finalizing the changes to subpart OOOO, § 60.5411(a)(3)(i)(A), or § 60.5411(c)(3)(i)(A).
Although we are not finalizing both audible and remote alarm requirements in subpart OOOO, the EPA disagrees that the requirement for remote notification is unreasonable and is therefore preserving the option as an alternative to an audible alarm. The EPA notes that either requirement is restricted to those bypass devices that vent to the atmosphere, not bypass devices (such as some pressure relief devices) that are required to be routed through closed vent systems to control devices. The EPA proposed to require both types of notification in subpart OOOOa because of the diverse nature of facilities that will use them. While an audible alarm may be sufficient at facilities that have personnel present on a continuous basis, not all affected facilities are at continuously-manned locations. An audible alarm on a bypass at a remote location that is visited only on a schedule by maintenance personnel would likely alert no one authorized to take action on the audible alarm until such time as the maintenance personnel arrive, which according to industry, may be a considerable time. The EPA agrees that the logistical requirements may need to be resolved in some instances, and is therefore finalizing the requirements in subpart OOOOa to be the same in substance as the requirements in subpart OOOO, which allow for the operator to choose one form of alarm or the other. Section 60.5416a(c)(3)(i) was revised to match the promulgated regulatory language in § 60.5416(c)(3)(i) of OOOO for consistency.

3. Recordkeeping Requirements for Repair Logs for Control Devices Failing a Visible Emissions Test
The EPA proposed that the recordkeeping requirements include the repair logs for control devices failing a visible emissions test as required by the rule. Petitioners noted that the recordkeeping requirements of § 60.5420(c) do not include the repair logs for control devices failing a visible emissions test required by § 60.5413(c). We agree that these recordkeeping requirements should be listed and are finalizing them at § 60.5420(c)(14).

4. Due Date for Initial Annual Report
The EPA did not propose regulatory text to amend the rule; rather, the EPA stated in the preamble to the proposed rule that we will consider any initial annual report submitted no later than January 15, 2014 to be a timely submission. All subsequent annual reports must be submitted by the correct date of January 13 of the year.

5. Flare Design and Operation Standards
The EPA proposed to remove the provision of Table 3 in subpart OOOO that exempts flares from complying with the requirements for the design and operation of flares under 40 CFR 60.18 of the General Provisions. By removing the exemption from the General Provisions of subpart OOOO, this clarifies that flares used to comply with subpart OOOO are subject to the design and operation requirements in the general provisions.
Comments on our proposal focused on support for the use of pressure-assisted flares. Pressure-assisted flares are designed to operate with high velocities up to sonic velocity conditions ( e.g., 700 to 1,400 feet per second for common hydrocarbon gases). In order to evaluate the use of pressure-assisted flares by the oil and natural gas industry and determine whether to develop operating parameters for pressure-assisted flares for purposes of subparts OOOO and subpart OOOOa, the EPA solicited comment on where in the source category, under what conditions ( e.g., maintenance), and how frequently pressure-assisted flares are used to control emissions from an affected facility, as defined within this subpart. From comments to our proposal, the EPA understands that there may be affected facilities that use pressure-assisted flares ( e.g., sonic flares) to control emissions from certain activities; however, the EPA now understands that an affected facility storage vessel, pneumatic pump, or centrifugal or reciprocating compressor would not use a pressure-assisted flare for control. The affected facility could be routed by closed vent system to a low pressure flare, which can comply with the velocity requirements of 40 CFR 60.18. The EPA received information showing that certain configurations have separate flare tips that accommodate high pressure and low pressure. The EPA understands that a flare configured this way would be able to meet § 60.18 on the low pressure side, which would be appropriate for compliance with these standards. Given these facts, the EPA is finalizing the rule as proposed, because no regulatory amendment appears necessary for such flares to comply with the proposed requirements.

6. Leak Detection and Repair (LDAR) for Open-Ended Valves or Lines
In the preamble to the final 2012 rule, the EPA stated that subpart VVa lowered the concentration limit defining a leak from 10,000 ppm to 500 ppm. The EPA's action did not revise subpart VVa, but rather changed the application of leak detection and repair provisions by making the LDAR standards of subpart VVa applicable to affected units subject to LDAR under subpart OOOO if the concentration emanating from a leak is 500 ppm or greater. The EPA further stated that monitoring requirements from subpart VVa applied to pumps, pressure relief devices, and open-ended valves or lines at units affected by LDAR under subpart OOOO. Although the preamble may have obscured the issue, we clarify here that the monitoring provisions of subpart VVa applicable to affected units of subpart OOOO do not extend to open-ended valves or lines. Given this clarification of preamble language, the EPA can identify no need to modify the regulatory language in response to this petition.

7. Compliance Period for LDAR for Newly Affected Units
An issue was raised in an administrative petition that the EPA did not adequately respond to a comment on the 2011 proposed NSPS regarding the compliance period for the LDAR requirements for on-shore natural gas processing plants. The commenter requested that the EPA include in subpart OOOO a provision similar to subpart KKK, 40 CFR 60.632(a), which allows a compliance period of up to 180 days after initial start-up. The commenter was concerned that a modification at an existing facility or a subpart KKK regulated facility could subject the facility to subpart OOOO LDAR requirements without adequate time to bring the whole process unit into compliance with the new regulation. We clarify that subpart OOOO, as promulgated in 2012, already includes a provision similar to subpart KKK, § 60.632(a), as requested in the comment. Therefore, the EPA has determined there is no need to modify the current regulations.

8. Exemption to Notification Requirement for Reconstruction
The EPA received an administrative petition that raised the issue that notification of reconstruction requirements under § 60.15(d) is unnecessary for some affected facilities. After consideration, the EPA agrees that some notifications are unnecessary because the EPA specifies notification of reconstruction for affected unit pneumatic controllers, centrifugal compressors, reciprocating compressors, and storage vessels under § 60.5410a and § 60.5420a, in lieu of the general notification requirement in § 60.15(d). To make this change effective, the EPA has noted this change in the explanatory comments in Table 3 reflecting that § 60.15(d) does not apply to affected facility pneumatic controllers, centrifugal compressors, reciprocating compressors and storage vessels in subpart OOOO. The EPA has determined to finalize these amendments as proposed.

9. Disposal of Carbon From Control Devices
The EPA re-proposed provisions for management of waste from spent carbon canisters that were finalized in § 60.5412(c)(2) of the 2012 NSPS to allow for comment. The EPA received no comment to the re-proposal. The EPA has determined to finalize these amendments as proposed.

10. The Definition of Capital Expenditure
The EPA proposed to specifically define the term “capital expenditure” in subpart OOOO. In this proposed definition, the EPA updated the formula to reflect the calendar year that subpart OOOO was proposed, as well as specified that the B value for subpart OOOO is 4.5. These updates are necessary for proper calculation of capital expenditure under subpart OOOO. The EPA has determined to finalize these amendments as proposed. Please refer to the RTC document in the public docket for this rulemaking for further discussion.

11. Tanks Associated With Water Recycling Operations
The EPA solicited comment in the proposed rule to remove tanks that are used for water recycling from potential NSPS applicability and on approaches that could be taken to amend the definition of “storage vessel.” Commenters requested that the EPA remove water tanks that are primarily used for water recycling from subpart OOOOa applicability. Commenters discussed that large storage tanks encourage large scale water recycling and are expected to reduce fresh water usage primarily in the Permian Basin. After reviewing the public comments, the EPA agrees that certain large water recycling vessels should be exempt from affected facility status for storage vessels because EPA did not intend such vessels to be affected facility storage vessels under subpart OOOO or OOOOa. By exempting such vessels, EPA will not create a disincentive for recycling of water for hydraulic fracturing. Therefore, the final rule exempts water recycling vessels that receive water that has been through separation, and are much larger than the storage vessels generally intended to be regulated by subparts OOOO and OOOOa for VOC emissions. The EPA has included the exemption language at § 60.5365(e)(5) and § 60.5365a(e)(5) in the final rule.

12. Continuous Control Device Monitoring
The EPA proposed under § 60.5417 to add continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities. The EPA received comments indicating that to impose this requirement on affected facilities under subpart OOOO may make such requirements retroactive, given the time between the original proposal for subpart OOOO and the proposal of the additional requirements. To avoid this possibility, the EPA will not finalize the change proposed to subpart OOOO, § 60.5417(h)(4).

I. Technical Corrections and Clarifications
The EPA is finalizing technical corrections and clarifications intended to provide clarity, improve implementation, and update procedures. This section identifies each correction and the rationale for these changes. Please see the TSD and RTC documents in the public docket for further discussion. ^{94}
^{94} See EPA docket I.D. No. EPA-HQ-OAR-2010-0505.
1. The EPA discovered drafting errors in § 60.5412a(d)(1)(iv)(A), § 60.5412a(d)(2) and § 60.5415a(e)(3) that required control of methane from storage vessels. As discussed in the preamble and the TSD for the proposed rule, the EPA did not consider reduction of methane emissions from storage vessels. Therefore, the reference to controlling storage vessel methane emissions in the proposed regulatory text in the above provisions was a drafting error. In correction, the EPA is removing “methane and” from these three provisions because methane control is not required for storage vessels under subpart OOOOa.
2. A commenter noted that EPA had omitted a clear deadline by which newly constructed, reconstructed, or modified storage vessels that receive liquids from sources other than hydraulically fractured wells must make their potential to emit determination, in § 60.5365a(e)(1). The commenter presumed, correctly, that the omission was inadvertent, stating that “Presumably, EPA intends that such tanks with potential VOC emissions greater than 6 tons per year would be subject to the rule.” We have more clearly specified the deadline.
3. We removed the requirement in § 60.5375a(a)(2) that all salable gas recovered from a well completion be routed as soon as practicable to a gathering line. This requirement was duplicative of the provisions of paragraph (a)(1) of the same section.
4. We revised § 60.5420a(b)(4)(i) to include the provision that gas recovered from reciprocating compressors could also be routed to a process as an alternative to replacing rod packing no later than on or before 26,000 hours of operation or 36 months. We additionally corrected an error that identified a wrong initial startup period. This correction consists of removing “since [insert date 60 days after publication of final rule in the Federal Register ].” This correction was also made in § 60.5420a(c)(3)(i) and § 60.5415a(c)(1).
5. We revised the requirements in § 60.5417a for heat sensing monitoring devices on pilot flames to clarify that these devices are not subject to calibration, quality assurance and quality control requirements. While we intended for these devices to monitor continuously, we did not intend to place all of the requirements for continuous parameter monitoring systems on these devices. We also revised the language in § 60.5417a(e) and § 60.5417a(g) to indicate that heat sensing is not a daily average and that a deviation occurs when the device fails to indicate the presence of a pilot flame.
6. We revised the language in § 60.5417a(f)(1)(iii) for monitoring inlet gas flow rate on control devices tested by the manufacturer. We did not intend for owners or operators to have to continuously achieve a minimum inlet gas flow rate. We have revised the requirement to indicate that there is only a limit on the maximum gas inlet flow rate to the device. We also revised the language in § 60.5417a(d)(1)(viii)(A) to indicate that the accuracy requirement is at the maximum flow rate.
7. We revised the language in § 60.5413a(d)(11)(iii) to indicate that manufacturers must demonstrate a destruction efficiency of 95 percent for total hydrocarbons (THC), as propane. This requirement previously stated that the manufacturer must demonstrate a destruction efficiency of 95 percent for VOC and methane. The revised language aligns more accurately with the testing requirements in the rule. Additionally, as these units are burning propene during the test, it would be impossible to demonstrate a destruction efficiency of methane. As methane is a one-carbon, single-bonded compound, it is more easily destructed than propene, a double-bonded compound, and thus, the destruction efficiency should be just as high or higher for methane than for the THC measured during the performance test.
8. We revised the testing language in § 60.5413a(b) in order to make it clearer for compliance purposes. The proposed language failed to clearly identify the number of runs or the length of runs expected for each performance test. Additionally, the calculations did not properly align with the specified methods. Section 60.5412a(d)(1)(i) has no subsections. The reference to “percent reduction performance requirement” in the referring section 60.5413a(b)(3) indicates that the cross reference should refer to section 60.5412a(d)(1)(iv)(A), which contains the percent reduction required.
9. We revised the language in § 60.5395a(a) to clarify that owners and operators must comply with the requirements of § 60.5395a(a)(1). The proposed language could have been interpreted to mean that compliance with § 60.5395a(a)(1) was not required if owners or operators complied with § 60.5395a(a)(3); however, it would be impossible to comply with § 60.5395a(a)(3) without first determining the potential for VOC emissions, as required by § 60.5395a(a)(1). We also further clarified when owners and operators must comply with the requirements of § 60.5395a(a)(2) and when they may comply with the requirements of § 60.5395a(a)(3).
10. We revised the language in § 60.5420a(b)(9)(i), § 60.5420a(b)(11), § 60.5422a(a), and 60.5423a(b) to update the Web site address for the Electronic Reporting Tool (ERT). We have also clarified that if the CEDRI form is not available at the time that a report is due, we do not intend for owners or operators to submit forms electronically through CEDRI until the form has been available for 90 days. We are also clarifying that this only applies to subsequent reports; owners or operators would not be required to enter previous reports into CEDRI once the form is available. While similar language was proposed, we realize that the previous language did not fully capture our intent.
11. We revised the language in § 60.5412a(c)(2)(iii) to correct a drafting error. The proposed language lists the types of units in which owners or operators must regenerate or reactivate spent carbon. The proposed language stated the unit must be operating emission controls in accordance with an emissions standard for VOC under another subpart in 40 CFR part 60 or this part, which is redundant. The language has been revised to state part 63 or this part. We also removed § 60.5412a(c)(2)(ii), as we do not believe that owners or operators would be able to regenerate or reactivate spent carbon in accordance with this section, as there are no requirements in this section for that activity. Finally, we removed the phrase “thermal treatment” in front of unit in § 60.5412a(c)(2)(i) and (iii) as the phrase “thermal treatment unit” is not defined.
12. We revised the language in § 60.5412a(c)(2)(iv) through (vii) and § 60.5413a(a)(4) and (5) to reconcile the fact that most hazardous waste combustion units are subject to the requirements of 40 CFR part 63 subpart EEE. While our intent was to encompass all hazardous waste incinerators, boilers and industrial furnaces in these requirements, referencing only 40 CFR parts 264, 265, 266 and 270 may have inadvertently excluded units.
13. We revised the language in § 60.5413a(b)(5)(ii)(B) to more clearly identify the continuing compliance obligations for units exempt from periodic testing.
14. We revised the TOC emission rate limit in § 60.5412a(a)(1)(ii) and § 60.5412a(d)(1)(iv)(B) to be consistent with the changes to the limit in 40 CFR part 60 subpart OOOO. For more explanation on this topic, see the discussion on reconsideration issues in section VI.H of this preamble. We also revised the TOC limit to be on a wet basis, as these units will be tested with Method 25A, which provides measurement data on a wet basis. While we note that compressors must control both VOCs and methane to at least 95 percent, the calculated limit reflects 95 percent control of VOC inflow to control devices. Because methane is the simplest carbon compound, it is very easy to destroy through combustion. Ensuring 95 percent destruction of VOCs will guarantee greater than 95 percent destruction of methane.
15. We revised the wording of § 60.5365(e)(4) and 60.5365a(e)(4) at the request of commenters seeking clearer direction on the applicability of standards to storage vessels returning to service. Since the re-wording does not change the meaning or requirements of the section, the revisions have been made to both subparts OOOO and OOOOa for consistency.
16. We corrected the cross reference in section 60.5415(c)(4) from § 60.5411(a) to section 60.5416(a) and (b), and in § 60.5415a paragraph (c)(4) from section 60.5411a(a) to § 60.5416a(a) and (b).
17. We corrected language in in § 60.5420(c)(6) to include reciprocating compressors.
18. We adjusted the language in § 60.5412(d)(1)(iv)(C), § 60.5412a(a)(1)(iii) and § 60.5412a(d)(1)(iv)(C). This language allowed operation of the control device at a minimum temperature of 760°Celsius, if the control device was able to demonstrate a uniform combustion temperature during the performance test. In our response to comments on the August 23, 2011 proposed rule, we agreed with commenters that uniform combustion profiles are difficult to obtain due to flame zone mixing and heat transfer. In response to that comment, we revised the language in 40 CFR part 63 subpart HH. We have now revised the language in 40 CFR part 60 subparts OOOO and OOOOa to mimic the language in 40 CFR part 63 subpart HH. We believe that this change is necessary as we do not believe that owners or operators will be able to demonstrate a uniform combustion zone temperature, nor have we defined what it means to have a uniform combustion zone temperature ( e.g. , the number of measurement points necessary, the agreement between points, etc.). Additionally, § 60.5412(d)(1)(iv)(C), § 60.5412a(a)(1)(iii) and § 60.5412a(d)(1)(iv)(C) previously referenced performance testing in accordance with § 60.5413 and § 60.5413a, but it was unclear what the performance testing obligations were. We believe the revised language will allow owners and operators to more easily comply with this requirement.
19. We added language to § 60.5412(d) and § 60.5412a(d) to make our intent clear that flares are acceptable control devices for storage vessels and to identify the design requirements for flares. We also revised language in § 60.5415a(b)(2)(vii) to clearly identify the continuing compliance requirements for flares.
20. We adjusted the language in § 60.5413a(b)(5)(ii)(A) and § 60.5417a(d)(1)(viii) to add a second compliance option for control device models tested under § 60.5413a(d). We are allowing owners and operators an option to retest these units every five years in lieu of continuously monitoring the gas flow rate. Owners and operators must still ensure they are not overwhelming the control device by using a control device that can handle the maximum flow rate at the site.
21. We added language to § 60.5417a(a) to identify the continuing compliance requirements for enclosed combustion devices that are not specifically identified in § 60.5417a(d).
22. In preparation of the final rule, EPA discovered an error in both subpart OOOO and the proposed subpart OOOOa. Specifically, they fail to include a general duty to minimize emissions. As the EPA clarified during the 2012 NSPS rulemaking, “[t]he general duty is applicable to a source at all times.” ^{95} Therefore, the absence of this provision in subpart OOOO and the proposed subpart OOOOa was an error, which is being corrected in these final rules at § 60.5370 and § 60.5370a.
^{95} See RTC document in EPA Docket I.D. No. EPA-HQ-OAR-2010-0505-4546.

J. Final Standards Reflecting Next Generation Compliance and Rule Effectiveness
We are finalizing certain standards that are reflecting EPA's Next Generation Compliance and rule effectiveness strategies. Based on our consideration of the comments received, we are finalizing some aspects as proposed while, for others, we have made a number of changes to the proposed standards. We have the opportunity to expand transparency by making the information we have more accessible and by making new information, obtained from advanced emissions monitoring and electronic reporting, publicly available. We are finalizing an electronic reporting requirement, via the EPA's CDX.
Other aspects of the final rule will maximize regulatory compliance, such as clear applicability of the final rule ( e.g. , in revisions to modification criteria) and provide incentives for inherently low-emitting equipment ( e.g. , solar pumps at gas plants are not affected facilities). Advances in technology additionally promote compliance by enhancing a “visibility” factor; this rule builds on such Next Generation strategies, by including measures involving the use of digital picture reporting and OGI technology. In lieu of independent third party verification for closed vent system design, we are finalizing a qualified professional engineer certification for certain issues. For example, as discussed in section VIII of this preamble, in response to comment, we are providing that a pneumatic pump that cannot be connected to an existing control device due to technical infeasibility does not have to meet this requirement. However, we will require that the source make this determination through use of a professional engineer certification. We are finalizing the use of OGI technology as a method for detecting fugitive emissions at well sites and compressor station sites. With the exception of “clear applicability”, “incentives for inherently low-emitting equipment” and “OGI technology for monitoring fugitive emissions”, which are discussed elsewhere in this preamble, this section identifies the rationale to the regulatory text changes from proposal and states how the EPA is finalizing these provisions. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.

1. Electronic Reporting
Through electronic reporting, or e-reporting, paper reporting is replaced by standardized, Internet-based, electronic reporting to a central repository using specifically developed forms, templates, and tools. E-reporting is not simply a regulated entity emailing an electronic copy of a document to the government but, also a means to make collected information easily accessible to the public and other stakeholders.
On March 20, 2015, the EPA proposed the “Electronic Reporting and Recordkeeping Requirements for New Source Performance Standards” (80 FR 15099, March 20, 2015). If adopted, the rule would revise the part 60 General Provisions and various NSPS subparts in part 60 of title 40 of the Code of Federal Regulations (CFR) to require affected facilities to submit specified air emissions data reports to the EPA electronically and to allow affected facilities to maintain electronic records of these reports. This proposed rule focuses on the submission of electronic reports to the EPA that provide direct measures of air emissions data such as performance test reports, performance evaluation reports, summary and excess emission reports and subpart specific reports that are similar in nature to these reports.
Subpart OOOO is one of the rules potentially affected by this rulemaking. When promulgated, in addition to electronically reporting the results of performance tests, which is already a requirement, a requirement to report the annual reports required in § 60.5420(b), the semiannual reports required in § 60.5422 and the excess emissions reports required in § 60.5423(b) would be added to subpart OOOO. The owner or operator would be required to use the appropriate electronic form in CEDRI for the subpart or an alternate electronic file format consistent with the form's extensible markup language (XML) schema. If the reporting form specific to the subpart is not available at the time that the report is due, the owner or operator would submit the report to the Administrator at the appropriate address listed in § 60.4 of the General Provisions. The owner or operator would begin submitting reports electronically with the next report that is due once the electronic form has been available for at least 90 days. The EPA is currently working to develop the form for subpart OOOO.
In the proposal for subpart OOOOa, the EPA included the same electronic reporting requirements for subpart OOOOa that were included for subpart OOOO in the March 2015 proposal. The EPA is finalizing the requirement to report certain performance test reports, excess emission reports, annual reports and semiannual reports electronically through the EPA's CDX using the CEDRI. The EPA believes that the electronic submittal of the reports addressed in this rulemaking will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment, and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors, and providing data quickly and accurately to the affected facilities, air agencies, the EPA and the public.
The EPA Web site that stores the submitted electronic data, WebFIRE, will be easily accessible to everyone and will provide a user-friendly interface that any stakeholder can access. By making the records, data and reports addressed in this rulemaking readily available, the EPA, the regulated community and the public will benefit when the EPA conducts its CAA-required reviews. As a result of having reports readily accessible, our ability to carry out comprehensive reviews will be increased and achieved within a shorter period of time.
The EPA anticipates fewer or less substantial information collection requests (ICRs) in conjunction with prospective CAA-required reviews may be needed, resulting in a decrease in time spent by industry to respond to data collection requests. The EPA also expects the ICRs to contain less extensive stack testing provisions, as we will already have stack test data electronically. Reduced testing requirements would be a cost savings to industry. The EPA should also be able to conduct these required reviews more quickly. While the regulated community may benefit from a reduced burden of ICRs, the general public benefits from the Agency's ability to provide these required reviews more quickly, resulting in increased public health and environmental protection.
Air agencies will benefit from more streamlined and automated review of the electronically submitted data. Having reports and associated data in electronic format will facilitate review through the use of software “search” options, as well as the downloading and analyzing of data in spreadsheet format. The ability to access and review air emission report information electronically will assist air agencies to more quickly and accurately determine compliance with the applicable regulations, potentially allowing a faster response to violations that could minimize harmful air emissions. This benefits both air agencies and the general public.
For a more thorough discussion of electronic reporting, see the discussion in the preamble of the March 2015 proposal. In summary, in addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with performance test data will save industry, air agencies, and the EPA significant time, money, and effort while improving the quality of emission inventories, air quality regulations, and enhancing the public's access to this important information.

2. Digital Picture Reporting as an Alternative for Well Completions (“REC PIX”) and Manufacturer Installed Control Devices
The EPA is finalizing digital picture reporting as an alternative for well completions and manufacturer installed control devices as proposed. Specifically, the final rule allows digital picture reporting as an alternative for well completions (“REC PIX”) and manufacturer installed control devices. These alternative reporting options provide flexibility for owners and operators, provide enhanced “visibility” for regulators, and take advantage of the advances of the digital age with the ability to capture geospatial accuracy at any location.
Digital picture reporting as an alternative for well completions (“REC PIX”) reflects the 2012 NSPS. As with the 2012 NSPS, we continue to promote an optional mechanism by which owners and operators could streamline annual reporting of well completions by using a digital camera to document that a well completion was performed in compliance with subpart OOOOa. Although we understand that commenters have concerns about the amount of electronic storage capability necessary to store digital pictures, we believe that by allowing either the REC PIX or the elements required under the recordkeeping requirements for well completions, the owner or operator may determine what is most advantageous for their company. Should an owner or operator choose to submit the REC PIX, the REC PIX must consist of a digital photograph of the REC equipment in use, with the date and geospatial coordinates shown on the photographs. These photographs must be submitted with the next annual report, along with a list of well completions performed with identifying information for each well completed.
Digital picture reporting as an alternative for manufacturer installed control devices provides further opportunity and flexibility to owners and operators to advance data capture to ensure that compliance practices are in effect. This alternative recordkeeping and reporting option is allowed specifically for centrifugal compressors and storage vessels routed to control devices, where the control device used is one tested in accordance with the manufacturer testing procedures in the rule and is posted to the EPA Oil and Gas page. In lieu of a written record with the location of the centrifugal compressor or storage vessel and its associated control device in latitude and longitude, the digital picture alternative must have the date the photograph was taken and the latitude and longitude of the centrifugal compressor and control device or storage vessel and control device imbedded within or stored with the digital file. As an alternative to imbedded latitude and longitude within the digital picture, the digital picture may consist of a photograph of the centrifugal compressor and control device with a photograph of a separately operating GPS device within the same digital picture, provided the latitude and longitude output of the GPS unit can be clearly read in the digital photograph. Furthermore, as discussed in section VI.F of this preamble, digital pictures and frame captures will help ensure that OGI for fugitive emissions is being performed properly.

3. Certification of Technical Infeasibility of Connecting a Pneumatic Pump to an Existing Control Device
In response to comment, the final rule requires that a new, modified, or reconstructed pneumatic pump be routed to an existing control device or process onsite, unless the owner or operator obtains a certification that it is technically infeasible to do so. The EPA understands that some factors such as capacity of the existing control device and back pressure on the exhaust of the pneumatic pump imposed by the closed vent system and control device can contribute to infeasibility of routing a pneumatic pump to an existing control device onsite. Due to the various scenarios that could make routing a pneumatic pump to an onsite control device or process technically infeasible, we do not think we could prescribe a specific set of criteria or factors that must be considered for making such determination that could capture all such circumstances. However, we want to ensure that the owner or operator has effectively assessed these factors before making a claim of infeasibility. To that end, we have included provisions in the final rule to require certification by a qualified professional engineer of such technical infeasibility. In addition, we are requiring that the owner or operator maintain records of that certification for a period of five years.

4. Professional Engineer Design of Closed Vent Systems
It is the EPA's experience, through site inspections and interaction with the states, that closed vent systems and control devices for storage vessels and other emission sources often suffer from improper design or inadequate capacity that results in emissions not reaching the control device and/or the control device being overwhelmed by the volume of emissions. Either of these conditions can seriously compromise emissions control and can render the system ineffective. We also discussed the issue in the September 2015 Compliance Alert “EPA Observes Air Emissions from Controlled Storage Vessels at Onshore Oil and Natural Gas Production Facilities” (See https://www.epa.gov/sites/production/files/2015-09/documents/oilgascompliancealert.pdf ).
We believe it is important that owners and operators make real efforts to provide for proper design of these systems to ensure that all the emissions routed to the control device reach the control device and that the control device is sized and operated to result in proper control. As a result, we have included in the final rule provisions for certification by a qualified professional engineer that the closed vent system is properly designed to ensure that all emissions from the unit being controlled in fact reach the control device and allow for proper control.
Although the final rule does not include requirements for specific criteria for proper design, the EPA believes there are certain minimum design criteria that should be considered to ensure that the closed vent and control device system are designed to meet the requirements of the rule; i.e., the closed vent system must be capable of routing all gases, vapors, and fumes emitted from the affected facility to a control device or to a process that meets the requirements of the rule.
Furthermore, because other emissions may be collected into the closed vent system and routed to the control device, these design criteria include consideration of the contribution of these additional emissions to ensure proper sizing and operation. The minimum design elements include, but are not limited to, based on site-specific considerations:
1. Review of the Control Technologies to be Used to Comply with §§ 60.5380a and 60.5395a.
2. Closed Vent System Considerations:
a. Piping—
i. Size (include all emissions, not just affected facility);
ii. Back pressure, including low points which collect liquids;
iii. Pressure losses; and
iv. Bypasses and pressure release points.
3. Affected Facility Considerations:
a. Peak Flow from affected facility, including flash emissions, if applicable; and
b. Bypasses, pressure release points.
4. Control Device Considerations:
a. Maximum volumetric flow rate based on peak flow, and
b. Ability to handle future gas flow.

K. Provision for Equivalency Determinations
In recent years, certain states have developed programs to control various oil and gas emission sources in their own states. Due to the differences in the sources covered and the requirements, determining equivalency through direct comparison of the various state programs with the NSPS has proven to be difficult. We also did not find that any state program as a whole would reflect what we have identified as the BSERs for all emissions sources covered by the NSPS. In any event, federal standards are necessary to ensure that emissions from the oil and natural gas industry are controlled nationwide.
However, depending on the applicable state requirements, certain owners and operators may achieve equivalent or more emission reduction from their affected source(s) than the required reduction under the NSPS by complying with their state requirements. States may adopt and enforce standards or limitations that are more stringent than the NSPS. See CAA section 116 and the EPA's regulations at 40 CFR 60.10(a). For states that are being proactive in addressing emissions from the oil and natural gas industry, it is important that the NSPS complement such effort. Therefore, in the final rule, through the process described in section VI.F.1.i for emerging technology, owners and operators may also submit an application requesting that the EPA approve certain state requirement as “alternative means of emission limitations” under the NSPS for their affected facilities. The application would include a demonstration that emission reduction achieved under the state requirement(s) is at least equivalent to the emission reduction achieved under the NSPS standards for a given affected facility. Consistent with section 111(h)(3), any application will be publicly noticed, which the EPA intends to provide within six months after receiving a complete application, including all required information for evaluation. The EPA will provide an opportunity for public hearing on the application and on intended action the EPA might take. The EPA intends to make a final determination within six months after the close of the public comment period. The EPA will also publish its determination in the Federal Register .

VII. Prevention of Significant Deterioration and Title V Permitting

A. Overview
This final rule will regulate GHGs under CAA section 111. In this section, the EPA is addressing how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA Title V operating permit program. The EPA is adopting provisions in the regulations that explicitly address some of these potential implications based on our review of the proposed regulatory text and comments received on the proposal.
For purposes of the PSD program, the EPA is finalizing provisions in part 60 of its regulations and explaining in this preamble that the current threshold for determining whether a PSD source must satisfy the best available control technology (BACT) requirement for GHGs continues to apply after promulgation of this rule. This rule does not require any additional revisions to state implementation plans (SIPs). With respect to the Title V operating permits program, we are finalizing provisions in part 60 and explaining in this preamble that this rule does not affect whether sources are subject to the requirement to obtain a Title V operating permit based solely on emitting or having the potential to emit GHGs above major source thresholds.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program
EPA received several comments asking for clarification or changes to make clear that this rule did not directly regulate methane as a separate pollutant from GHG and that it would not cause sources to trigger PSD or Title V permitting requirements based solely on methane emissions. ^{96} This section discusses changes made in response to these comments as well as clarification as to what, if any, impact this rule has on PSD permitting. Section VII.C below addresses Title V-specific issues.
^{96} As is discussed elsewhere, the EPA has made clear that the pollutant subject to regulation is GHG, in the form of methane. Additional regulatory language in 40 CFR 60.5360a has been added to provide additional clarity.
Under the PSD program in part C of title I of the CAA, in areas that are classified as attainment or unclassifiable for NAAQS pollutants, a new or modified source that emits any air pollutant subject to regulation at or above specified thresholds is required to obtain a preconstruction permit. This permit ensures that the source meets specific requirements, including application of BACT to each pollutant subject to regulation under the CAA. Many states (and local districts) are authorized by the EPA to administer the PSD program and to issue PSD permits. If a state is not authorized, then the EPA issues the PSD permits for facilities in that state.
To identify the pollutants subject to the PSD permitting program, EPA regulations contain a definition of the term “regulated NSR pollutant.” 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition contains four subparts, which cover pollutants regulated under various parts of the CAA. The second subpart covers pollutants regulated under section 111 of the CAA. The fourth subpart is a catch-all provision that applies to “[a]ny pollutant that is otherwise subject to regulation under the Act.”
This definition and the associated PSD permitting requirements applied to GHGs for the first time on January 2, 2011, by virtue of the EPA's regulation of GHG emissions from motor vehicles, which first took effect on that same date. 75 FR 17004 (Apr. 2, 2010). GHGs became subject to regulation under the CAA and the fourth subpart of the “regulated NSR pollutant” definition became applicable to GHGs.
On June 3, 2010, the EPA issued a final rule, known as the Tailoring Rule, which phased in permitting requirements for GHG emissions from stationary sources under the CAA PSD and Title V permitting programs (75 FR 31514). Under its understanding of the CAA at the time, the EPA believed the Tailoring Rule was necessary to avoid a sudden and unmanageable increase in the number of sources that would be required to obtain PSD and Title V permits under the CAA because the sources emitted GHGs in amounts over applicable major source and major modification thresholds. In Step 1 of the Tailoring Rule, which began on January 2, 2011, the EPA limited application of PSD or Title V requirements to sources of GHG emissions only if the sources were subject to PSD or Title V “anyway” due to their emissions of non-GHG pollutants. These sources are referred to as “anyway sources.” In Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA applied the PSD and Title V permitting requirements under the CAA to sources that were classified as major and, thus, required to obtain a permit based solely on their potential GHG emissions and to modifications of otherwise major sources that required a PSD permit because they increased only GHG emissions above applicable levels in the EPA regulations.
In the PSD program, the EPA implemented the steps of the Tailoring Rule by adopting a definition of the term “subject to regulation.” The limitations in Step 1 of the Tailoring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR 51.166(b)(48)(iv). With respect to “anyway sources” covered by PSD during Step 1, this provision established that GHGs would not be subject to PSD requirements unless the source emitted GHGs in the amount of 75,000 tons per year (tpy) of CO2 Eq. or more. The primary practical effect of this paragraph is that the PSD BACT requirement does not apply to GHG emissions from an “anyway source” unless the source emits GHGs at or above this threshold. The Tailoring Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These provisions contain thresholds that, when applied through the definition of “regulated NSR pollutant,” function to limit the scope of the terms “major stationary source” and “major modification” that determine whether a source is required to obtain a PSD permit. See e.g., 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR 51.166(b)(2).
On June 23, 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Agency, issued a decision addressing the application of PSD permitting requirements to GHG emissions. The Supreme Court held that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or modification thereof) for the purpose of PSD applicability. The Court also said that the EPA could continue to require that PSD permits, otherwise required based on emissions of pollutants other than GHGs, contain limitations on GHG emissions based on the application of BACT. The Supreme Court decision effectively upheld PSD permitting requirements for GHG emissions under Step 1 of the Tailoring Rule for “anyway sources” and invalidated application of PSD permitting requirements to Step 2 sources based on GHG emissions. The Court also recognized that, although the EPA had not yet done so, it could “establish an appropriate de minimis threshold below which BACT is not required for a source's greenhouse gas emissions.” 134 S. Ct. at 2449.
In accordance with the Supreme Court decision, on April 10, 2015, the United States Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment vacating the regulations that implemented Step 2 of the Tailoring Rule but not the regulations that implement Step 1 of the Tailoring Rule. The court specifically vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 52.21(b)(48)(iv). The court also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA and, if so, to undertake such revisions.
The practical effect of the Supreme Court's clarification of the reach of the CAA is that it eliminates the need for Step 2 of the Tailoring Rule and subsequent steps of the GHG permitting phase-in that the EPA had planned to consider under the Tailoring Rule. This also eliminates the possibility that the promulgation of GHG standards under section 111 could result in additional sources becoming subject to PSD based solely on GHGs, notwithstanding the limitations the EPA adopted in the Tailoring Rule. ^{97} However, for an interim period, the EPA and the states will need to continue applying parts of the PSD definition of “subject to regulation” to ensure that sources obtain PSD permits meeting the requirements of the CAA.
^{97} As discussed in other portions of this rulemaking, GHG are the pollutant subject to regulation by this rule. The standards are specific to GHGs expressed in the form of limitations on emissions of methane. Changes, consistent with 40 CFR part 60, subpart TTTT as suggested by several of the commenters, have been made in 40 CFR 60.5360a to make this clear.
The CAA continues to require that PSD permits issued to “anyway sources” satisfy the BACT requirement for GHGs. Based on the language that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv), the EPA and states may continue to limit the application of BACT to GHG emissions in those circumstances where a source emits GHGs in the amount of at least 75,000 tpy on a CO2 Eq. basis. The EPA's intention is for this to serve as an interim approach while the EPA moves forward to propose a GHG significant emission rate (SER) that would establish a de minimis threshold level for permitting GHG emissions under PSD. Under this forthcoming rule, the EPA intends to propose restructuring the GHG provisions in its PSD regulations so that the de minimis threshold for GHGs will not reside within the definition of “subject to regulation.” This restructuring will be designed to make the PSD regulatory provisions on GHGs universally applicable, without regard to the particular subparts of the definition of “regulated NSR pollutant” that may cover GHGs. Upon promulgation of this PSD rule, it will then provide a framework that states may use when updating their SIPs consistent with the Supreme Court decision.
While the PSD rulemaking described above is pending, the EPA and approved state, local, and tribal permitting authorities will still need to implement the BACT requirement for GHGs. In order to enable permitting authorities to continue applying the 75,000 tpy CO2 Eq. threshold to determine whether BACT applies to GHG emissions from an “anyway source” after GHGs are subject to regulation under CAA section 111, the EPA has concluded that it is appropriate to adopt language in 40 CFR 60.5360a, language that is substantially similar to language found in 40 CFR 60.5515 (subpart TTTT).
While most of the Tailoring Rule limitations are no longer needed to avoid triggering the requirement to obtain a PSD permit based on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim applicability level for the GHG BACT requirement in “anyway source” PSD permits. Thus, there continues to be a need to ensure that the regulation of GHGs under CAA section 111 does not make this BACT applicability level for “anyway sources” effectively inoperable. The language in 40 CFR 60.5360a is necessary to avoid this result in light of the judicial actions described above.

C. Implications for Title V Program
Under the Title V program, certain stationary sources, including “major sources” are required to obtain an operating permit. This permit includes all of the CAA requirements applicable to the source, including adequate monitoring, recordkeeping, and reporting requirements to ensure sources' compliance. These permits are generally issued through EPA-approved state Title V programs.
In the proposal for this rulemaking, the EPA indicated that “the air pollutant that it propose[d] to regulate [was] the pollutant GHGs (which consist of the six well-mixed gases), consistent with other actions the EPA has taken under the CAA, although only methane will be reduced directly by the proposed standards.” 80 FR 56600-56601 (Sept. 18, 2015).
Similar to the comments received on PSD permitting, the EPA received several comments asking for clarification to make clear that this rule did not directly regulate methane as a separate pollutant from GHG and that it would not cause sources to be considered a major source under the Title V permitting program based solely on having methane emissions above the major source threshold. Several of these comments suggested that this issue could be addressed by adding provisions similar to those that appear in 40 CFR 60.5515 (subpart TTTT).
The immediately preceding section provides some general background about the application of the PSD and Title V permitting programs to GHG emissions. With respect to Title V, the definition of major source includes, in relevant part, a stationary source that “directly emits or has the potential to emit, 100 tpy or more of any air pollutant subject to regulation.” 40 CFR 70.2, 71.2 (definition of “major source”). In the Tailoring Rule, a GHG threshold was incorporated into the definition of “subject to regulation” under 40 CFR 70.2 and 71.2, such that those definitions specify that GHGs are not subject to regulation, unless, as of July 1, 2011, the emissions of GHGs are from a source emitting or having the potential to emit 100,000 tpy of GHGs on a CO2 Eq. basis. 40 CFR 70.2, 71.2 (definition of “subject to regulation”); see also 75 FR 31583, June 3, 2010. However, there is not a similar threshold for methane as a separately regulated air pollutant. Some comments reflected a concern that if methane were to be subject to regulation as a separate air pollutant, sources that emitted or had the potential to emit 100 tpy or more of methane would trigger major source status under Title V and any related requirements under the Title V permitting program.
In consideration of these comments and for purposes of clarity, the EPA has concluded that it is appropriate to adopt language in 40 CFR 60.5360a that is substantially similar to language found in 40 CFR 60.5515 (subpart TTTT). Consistent with the statement quoted above from the proposal, that provision along with the explanation in this preamble clarifies that the GHG standard established in this rulemaking regulates the air pollutant GHGs, although the standard is expressed in the form of a limitation on emission of methane. Accordingly, the air pollutant that is subject to regulation under this standard for Title V purposes is GHGs.
As noted above, on June 23, 2014, the United States Supreme Court issued its opinion in UARG v. EPA, 134 S.Ct. 2427 (June 23, 2014) and, in accordance with that decision, the D.C. Circuit subsequently issued an amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 2015). With respect to Title V, the Supreme Court said in UARG v. EPA that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source required to obtain a Title V operating permit. In accordance with that decision, the D.C. Circuit's amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency, vacated the Title V regulations under review in that case to the extent that they require a stationary source to obtain a Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. The D.C. Circuit also directed the EPA to consider whether any further revisions to its regulations are appropriate in light of UARG v. EPA, and, if so, to undertake to make such revisions. These court decisions make clear that promulgation of CAA section 111 requirements for GHGs will not result in the EPA imposing a requirement that stationary sources obtain a Title V permit solely because such sources emit or have the potential to emit GHGs above the applicable major source thresholds. ^{98}
^{98} The EPA intends to propose revisions to the Title V regulations in a future rulemaking action to respond to the Supreme Court decision and the D.C. Circuit's amended judgment. To the extent there are any issues related to the potential interaction between the promulgation of CAA section 111 requirements for GHGs and Title V applicability based on emissions above major source thresholds, the EPA anticipates there would be an opportunity to consider those during that rulemaking.
To be clear, however, unless exempted by the Administrator through regulation under CAA section 502(a), any source, including an area source (a “non-major source”), subject to an NSPS is required to apply for, and operate pursuant to, a Title V permit that ensures compliance with all applicable CAA requirements for the source, including any GHG-related applicable requirements. This aspect of the Title V program is not affected by UARG v. EPA, as the EPA does not read that decision to affect either the grounds other than those described above on which a Title V permit may be required or the applicable requirements that must be addressed in Title V permits. ^{99} For the source category in this rule, there is an exemption in 40 CFR 60.5370a from the obligation to obtain a Title V permit for sources that are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). However, sources that are subject to the CAA section 111 standards promulgated in this rule and that are otherwise required to obtain a Title V permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) will be required to apply for, and operate pursuant to, a Title V permit that ensures compliance with all applicable CAA requirements, including any GHG-related applicable requirements.
^{99} See Memorandum from Janet G. McCabe, Acting Assistant Administrator, Office of Air and Radiation, and Cynthia Giles, Assistant Administrator, Office of Enforcement and Compliance Assurance, to Regional Administrators, Regions 1-10, Next Steps and Preliminary Views on the Application of Clean Air Act Permitting Programs to Greenhouse Gases Following the Supreme Court's Decision in Utility Regulatory Group v. Environmental Protection Agency (July 24, 2014) at 5.

VIII. Summary of Significant Comments and Responses
This section summarizes the significant comments on our proposed amendments and our response to those comments.

A. Major Comments Concerning Listing of the Oil and Natural Gas Source Category
As previously explained, the EPA interprets the 1979 listing of this source category to cover the oil and natural gas industry broadly. To the extent there is any uncertainty, EPA proposed, as an alternative in the 2015 proposal, to revise the listing of this source category to include oil production and natural gas production, processing, and transmission and storage. We received several comments regarding the EPA's interpretation of the 1979 category listing and its alternative proposal to revise that listing. Provided below is one such comment and the EPA's response. Other comments on this subject and the EPA's responses thereto can be found in the RTC.
Comment: One commenter argues that, in the proposed rule, the EPA seeks to unlawfully expand the scope of the oil and natural gas sector source category, even beyond the expansion that the EPA undertook in 2012 with subpart OOOO, which the commenter had also opposed as unlawful. The commenter asserts that the EPA's attempt here to expand even further the types of emissions sources that would be subject to the NSPS is likewise unlawful. The commenter notes that, in this proposal, several types of never before regulated emissions sources would be regulated under NSPS, specifically, hydraulically fractured oil well completions, pneumatic pumps and fugitive emissions from well sites and compressor stations, and that some source types would also be regulated more generally for methane and VOC emissions, as only a small subset are currently regulated for VOC: Pneumatic controllers, centrifugal compressors and reciprocating compressors (except for compressors at well sites).
The commenter notes that the EPA's proposed NSPS would cover an even greater number of very small source types in the EPA's broadly defined “oil and natural gas source category,” which, according to the EPA, includes production, processing, transmission and storage. The commenter notes that the EPA again maintains, as it did in the original subpart OOOO rulemaking, that all emissions sources proposed for regulation are covered by its 1979 listing of the oil and natural gas category.
The commenter claims that the EPA is incorrect that the 1979 original source category determination can be read to include the numerous smaller emissions points covered by this proposal. According to the commenter, the 1979 listing was focused on major emitting operations and cannot be reasonably construed as encompassing small, discrete sources that exist separate and apart from a large facility, like a processing plant.
The commenter claims that the EPA made clear in the 1979 listing notice that the category was listed to satisfy section 111(f) of the Clean Air Act. According to the commenter, that section required the EPA to create a list of “categories of major stationary sources” that had not been listed as of August 7, 1977, under section 111(b)(1)(A) of the Act, and to promulgate NSPS for the listed categories according to a set schedule. The commenter asserts that the EPA explained in the listing rule that its list included “major source categories,” which the EPA defined to include “those categories for which an average size plant has the potential to emit 100 tons or more per year of any one pollutant.”
Although the commenter notes that the EPA provided no further explanation in its original 1979 listing decision as to what facilities it intended to regulate under the “crude oil and natural gas production” source category, the commenter claims that “there can be no doubt that the category originally included `stationary sources' ( i.e., `plants') that typically have a potential to emit at least 100 tons per year of a regulated pollutant.” ^{100} The commenter argues that this communicates two important limitations on the original listing decision: First, the EPA was focused on discrete “plants” or “stationary sources”; and second, the EPA was focused on large emitting plants or stationary sources. The commenter argues that, as a result, the original listing decision cannot reasonably be interpreted to extend to the types of sources the EPA seeks to regulate in the proposal and that the additional source types that the EPA seeks to regulate in this proposal could not plausibly be considered part and parcel of major emitting plants.
^{100} API Comments on the Proposed Rulemaking—Standards of Performance for New Stationary Sources: Oil and Natural Gas Production and Natural Gas Transmission and Distribution, at 2 (December 4, 2015).
The commenter notes that the EPA interpreted the 1979 listing to be broader than the “production source segment” because the EPA evaluated equipment that is used in various segments of the natural gas industry, such as stationary pipeline compressor engines. 80 FR 56600, September 18, 2015. The commenter argues that this does not evince an intent to regulate non-major source types, but only that the Agency evaluated equipment located at what it perceived to be major facilities.
The commenter further notes that, in the preamble to the proposed NSPS for natural gas processing plants, the EPA described the major emission points of this source category to include process, storage and equipment leaks. However, the commenter argues that this does not support what the commenter claims as “broad regulation of even the smallest sources in the oil and natural gas industry.” ^{101} The commenter notes that the emissions points regulated in that rulemaking—process units and compressors—were located at gas processing plants. The commenter argues that it is telling that the Agency decided to regulate only natural gas processing plants—the closest thing to a major emitting plant that can be found in this sector—in that NSPS.
^{101} Id.
Response: In 1979, the EPA published a list of source categories, including “oil and natural gas production,” pursuant to a new section 111(f) in the Clean Air Act amendment of 1977, which directed the EPA to list under 111(b)(1)(A) “categories of major stationary sources” and establish standards of performance for the listed source categories. As explained in the September 2015 proposal preamble and earlier in section IV.A of this preamble, the EPA interprets the 1979 listing to broadly cover the oil and natural gas industry. The commenter claims that the EPA's interpretation is incorrect because the 1979 listing included only large emitting plants or stationary sources. However, the commenter's interpretation fails for the following reasons.
The commenter's claim relies in large part on the EPA's definition of a “major source category” in the 1979 listing action, which was defined as “an average size plant that has the potential to emit 100 tons or more per year of any one pollutant,” 44 FR 49222 (August 21, 1979). However, despite the definition above, the EPA provided notice in the listing action that “certain new sources of smaller than average size within these categories may have less than a 100 ton per year emission potential.” 43 FR 38872, 38873 (August 31, 1978). The EPA thus made clear that the 1979 listing did not include only those meeting the major source threshold. The EPA's contemporaneous explanation indicates that, while the 1979 action focused on large emitting sources, the EPA recognized at the time that there are smaller sources that may warrant regulation.
The commenter next argues that the 1979 listing included only large plants because it included only “stationary sources.” However, “stationary sources,” as defined in section 111(a)(2), include not only buildings, structures and facilities (e.g., plants) but also installations, such as equipment, that emit or may emit any pollutant. Moreover, this definition contains no size limitation.
The commenter cites to the EPA's initial NSPS promulgation in 1985, which regulated only natural gas processing plants, as evidence that the 1979 listing included only large emitting stationary sources and, in the case of the oil and natural gas source category, only natural gas processing plants. However, the fact that the EPA regulated only natural gas processing plants in the 1985 NSPS does not establish that the listed oil and natural gas source category consists of only large natural gas processing plants. On the contrary, this argument ignores that the category, as listed, also includes crude oil production. Further, such narrow view is inconsistent with the EPA's clarification of the 1979 listing and the statutory definition of “stationary sources,” neither of which limits a listed category of stationary sources under section 111 only to large plants such as natural gas processing plants, as explained above.
The commenter's assertion is also refuted by the EPA's statements during the development of the 1985 NSPS. Specifically, in the preamble to the proposed rule for equipment leaks at natural gas processing plants, the EPA described the major emission points of this source category to include process, storage and equipment leaks, which can be found in various segments of the oil and natural gas industry. Further, as mentioned earlier, the EPA described the listed oil and natural gas source category to include emission points that the EPA did not regulate at that time, such as “well systems field oil and gas separators, wash tanks, settling tanks and other sources.” 49 FR at 2637. The EPA explained in that action that it could not address these emission at that time because “best demonstrated control technology has not been identified.”
In light of the above, EPA reasonably interprets the 1979 listing to include the sources regulated under the 2012 oil and gas NSPS as well as those subject to today's action. The EPA established well completion performances standards for hydraulically fractured gas wells in the 2012 NSPS and for oil wells in today's action. These standards address some of the above mentioned well system emissions that the EPA could not regulate previously due to the lack of data. In addition, as mentioned above, the EPA had previously identified equipment leaks as a major emission point from this listed source category and established leaks standards for natural gas processing plants. Today's action further reduces emissions from equipment leaks by establishing work practice standards to detect and repair fugitive emissions at well sites and compressor stations. Emissions from equipment do not result only from leaks but also from normal operations that, if uncontrolled, are vented into the atmosphere. Therefore, both the 2012 NSPS and today's rule include performance standards for certain equipment used throughout the oil and natural gas industry, such as storage vessels, pneumatic controllers, pneumatic pumps, and compressors. Because these equipment are widely used across this industry, they contribute significant amount of emissions even if emissions from an individual piece of equipment may not be big. ^{102}
^{102} For example, based on industry wide estimate, high-bleed pneumatic controllers (from production through transmission and storage) emit in total of 87,285 tons of VOC and 350,000 tons of methane (8.7 million metric tons of CO 2 e).
The commenter's main concern appears to be with the EPA regulating what the commenter claims to be “very small emission sources” and, therefore, unreasonable. However, section 111(b)(1)(A) requires that the EPA list source categories, not emission sources. In listing a source category, the EPA is not required to identify specific emission points within that source category. However, having listed a source category, the EPA is then required under section 111(b)(1)(B) to establish through rulemaking performance standards that reflect the best system of emission reductions, which would entail evaluation of emissions, control options, and other considerations (including their costs) for the sources to be regulated. Therefore, specific concerns with regulation of certain emission sources can be addressed during the rulemaking to establish such performance standards, where a commenter can argue that controlling a specific type of source is unreasonable under 111(b)(1)(B).
For the reasons stated above, the commenter fails to support its claim that the EPA's interpretation of the 1979 listing is unlawful. The commenter also fails to support its interpretation of the 1979 listing. The EPA's interpretation of the 1979 listing therefore remains unchanged.
Comment: The commenter claims that the EPA fails to make the required statutory findings under section 111(b)(1)(A) to support its proposed revision to the 1979 listing. The commenter asserts that, under section 111(b)(1)(A), the EPA is authorized to regulate additional source types if and only if it: (1) Defines a discrete “category” of stationary sources; and (2) determines that emissions from the source category cause or significantly contribute to endangerment to health or the environment.
The commenter claims that the EPA makes no effort whatsoever to demonstrate that emissions from the particular additionally-regulated sources in subpart OOOOa cause or contribute to endangerment to health or the environment. Instead, the Agency simply asserts general public health effects associated with GHGs, VOC, and SO 2 and then evaluates emissions from oil and natural gas sources generally. See 80 FR 56601-08, September 18, 2015. For methane, the EPA merely breaks down emissions into four general “segments” (natural gas production, natural gas processing, natural gas transmission and storage, and petroleum production), but does not evaluate particular source type emissions within those segments. The EPA does nothing to break down its evaluation of emissions even by sector segment for SO 2 and VOC. This failure to investigate the key statutory listing criteria is patently arbitrary and plainly violates the requirement in section 307(d)(3) of the Clean Air Act to clearly set forth the basis and purpose of the proposal.
The commenter claims that under the EPA's logic, as long as certain types of stationary sources in a category, or segment of a category, cause or significantly contribute to endangerment to health or the environment, the Agency can lump together in the defined source category (or segment of a source category) all manner of ancillary equipment and operations, even if those ancillary equipment and operations do not in and of themselves significantly contribute to the previously identified endangerment. See 80 FR 56601, September 18, 2015. This is not a reasonable interpretation of section 111(b)(1)(A) because such an interpretation would bestow virtually unlimited regulatory authority upon the EPA, allowing the EPA to evade the express listing criteria by creating loose associations of nominally related sources in a sector.
Response: The commenter claims that the EPA must separately list and make the required findings under CAA section 111(b)(1)(A) for the “additional source types” from the oil and natural gas industry that were not covered by the 1979 listing. First of all, the EPA disagrees that there are such “additional source types” because, for the reasons stated in section IV.A of this preamble and the response to comment immediately above, the EPA interprets the 1979 listing to broadly cover the oil and natural gas industry. To the extent there is any uncertainty, the EPA rejects the commenter's claim that the 1979 listing covers only natural gas processing plants. But, more importantly, the EPA rejects this comment because it is contrary to the law.
CAA section 111(b)(1)(A) requires that the EPA list a category of sources “if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” ^{103} The provision is clear that the listing and endangerment findings requirements are to be made for source categories, not specific emission sources within the source category. The provision also does not require that the EPA identify all emission points within a source category when listing that category.
^{103} As previously mentioned, the required findings under section 111(b)(1)(A) is commonly referred to as the “endangerment findings.”
The commenter's claim that the EPA must separately list and make findings for particular emission source types within individual segments of the natural gas industry clearly contradicts with the plain language of section 111(b)(1)(A) which, as discussed above, is stated in terms of source category, not emission source types. Regardless, the EPA has satisfied the two criteria the commenter has identified as required by section 111(b)(1)(A): (1) Define a discrete category of stationary sources; and (2) determine that emissions from the source category cause or significantly contribute to endangerment to health or the environment. Although the EPA does not believe that revision to the 1979 category listing to be necessary for today's action, the EPA is finalizing as an alternative its proposed revision of the category listing to broadly include the oil and natural gas industry. In support of the revision, the final rule includes the Administrator's determination under section 111(b)(1)(A) that, in her judgment, this source category, as defined in this revision, contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare.
The commenter also appears to claim that the EPA cannot revise the scope of a listed source category, but must instead separately list and make findings for what the commenter considers as “additional source types” within an already listed source category. The commenter offers no legal basis to support its claim because there is none. On the contrary, as explained below, the commenter claim impermissibly restricts the EPA's authority under section 111(b)(1)(A).
Section 111(b)(1)(A) requires that the EPA revise the category listing from time to time; it does not limit such revision to simply adding new source categories. The only criteria that section 111(b)(1)(A) states for the EPA to apply to category listing revision are the same as those for the initial category listing: That the category “causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” Thus, the statute leaves the EPA with the discretion to determine how to carry out such task, and that gives the EPA the flexibility to list and revise the list, including redefining the scope of a previously listed category, as long as long as the EPA meets the above criteria with the requisite endangerment findings for the source category as a whole. It allows the EPA to revise a category listing to include sources that, though not included in the initial listing ( e.g., the EPA might now have known about it at the time), reasonably belong in a listed source category. The commenter provides no compelling reason that such emission sources need a separate category listing and endangerment finding. In light of the above, the commenter's claim for a separate category listing and endangerment finding is not only unsupported by the statute, it unreasonably curtails the discretion section 111(b)(1)(A) provides the EPA in executing its category listing and revision authority under that provision. For the reasons stated above, the EPA disagrees with this comment.

B. Major Comments Concerning EPA's Authority To Establish GHG Standards in the Form of Limitations on Methane Emissions
As previously explained in section IV.D, the EPA's authority for regulating GHGs in this rule is CAA section 111. The standards in this rule that are specific to GHGs are expressed in the form of limitations on emissions of methane, and not the other constituent gases of the air pollutant GHGs. We received several comments regarding the EPA's interpretation of CAA section 111. Provided below is a summary of such comments and the EPA's response. Other comments on this subject and the EPA's responses thereto can be found in the RTC document.
Comment: Several commenters argued that the EPA cannot rely on the 2009 Endangerment Finding for GHG to justify the limitations of methane in this rule. The commenters made several arguments.
First, some commenters asserted that the EPA cannot regulate methane alone or specifically without a new Endangerment and Cause or Contribute Finding for the individual gas, because the original 2009 Finding defined the pollutant as the six well-mixed greenhouse gases. One commenter further stated that it is unlawful for the EPA to regulate only methane based on an endangerment finding that is largely attributable to other pollutants and that, of the six greenhouse gases, carbon dioxide is emitted in vastly greater quantities (even on a carbon dioxide equivalent basis) than methane.
Second, some commenters argue that a new endangerment finding is necessary for each pollutant regulated in a given source category. One commenter claims that section 111(b)(1)(A) of the CAA requires the EPA to list a category of stationary sources if, in the Administrator's judgment, the category causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare. The commenter further argues that this CAA section unambiguously requires the EPA to list and regulate according to endangerment and significant contribution findings for particular pollutants. The commenter goes to state that it is unreasonable for the EPA to use a cause-or-contribute finding made for one pollutant thirty years ago in order to justify controlling a different pollutant today. The commenter asserts that a “rational basis test” is insufficient justification, and that the term “rational basis” is not found in section 111.
Third, some commenters argue that methane does not endanger human health or welfare. One commenter states that methane is naturally occurring and is non-toxic, that it does not accumulate in the body, that the only real risks that it poses are that it is flammable when present in high concentrations, and that inhaling high levels can cause oxygen deprivation. Another commenter claims that recent science supports a weakening of the case for human-caused global warming.
Finally, some commenters state that the impacts of the rule will be very small. One commenter argues that “the oil and gas sector do [sic] not significantly cause or contribute to climate change” because methane emissions from that sector “account for only 3 percent of total United States domestic GHG emissions, just over 2 percent of the total United States GHG Inventory, and 0.3 percent of Global GHG emissions” and transmission and storage is only a third of that total.
Response: As a general matter, commenters on this issue consistently mischaracterize the EPA's actions. The standards in this rule that are specific to GHGs are expressed in the form of limitations on emissions of methane. For these standards, GHG is the regulated pollutant. An endangerment finding is only required when the EPA lists a source category under section 111(b)(1)(A). Nothing in section 111 requires that the EPA make further endangerment findings with respect to each pollutant that it regulates under section 111(b)(1)(B). By considering whether there is a rational basis to regulate a given pollutant from a listed source category, the EPA ensures that it regulates pollutants that warrant regulation.
For purposes of this final rule, the EPA's rational basis is supported, in part, by the analysis that supported the 2009 Endangerment Finding. If, as commenters argue, the EPA is required to make additional findings of endangerment and cause-or-contribute for this final rule, then the analysis that supported the 2009 Endangerment Finding, along with other facts presented herein, including the information in sections IV.B and C, would be sufficient to make these findings.
While the 2009 Endangerment Finding defined the pollutant as the “aggregate group of the well-mixed greenhouse gases” the finding was also clear that a given source category does not have to emit every single one of these gases in order to contribute to the pollution in question. See 74 FR 66496-99 and 66541 (December 15, 2009). Specifically, as we explained in the 2009 Endangerment Finding, two of the six pollutants (PFCs and SF 6 ) are not emitted by motor vehicles, the source category in question in the 2009 Endangerment Finding. Moreover, while motor vehicles contribute to emissions of HFC-134a, there are many other HFCs which are not emitted by that source. Just as the GHG emissions from motor vehicles do not need to contain all six gases in order to be regulated, the GHG emissions from the oil and gas sector do not need to contain all six gases. Therefore, the EPA does not need to make an endangerment finding for methane alone: The 2009 Endangerment Finding that defines the aggregate group of six well-mixed gases as the air pollution addresses emissions of any individual component of that aggregate group and, therefore, supports the rational basis for this final rule.
Next, the assertion that methane has no risks beyond flammability is false. While methane is indeed produced from natural sources, the health and welfare risks of elevated concentrations of greenhouse gases (including methane) was detailed in the 2009 Endangerment Finding. Moreover, methane is a precursor to tropospheric ozone formation, which also impacts human health. As further context, according to the IPCC, historical methane emissions contribute the second most warming today of all the greenhouse gases, after carbon dioxide. This makes methane emission reductions an important contribution to reducing the atmospheric concentrations of the six well-mixed greenhouse gases.
Lastly, the climate benefits anticipated from the implementation of this rule are consequential in terms of the quantity of methane reduced, particularly in light of the potency of methane as a GHG. The reductions are additionally important as the United States oil and natural gas sector emits about 32 percent of United States methane emissions and about 3.4 percent of all United States GHGs. The final standards are expected to reduce methane emissions annually by about 6.9 million metric tons CO 2 Eq. in 2020 and by about 11 million metric tons CO 2 Eq. in 2025. To gives a sense of the magnitude of these reductions, the methane reductions expected in 2020 are equivalent to about 2.8 percent of the methane emissions for this sector reported in the United States GHG Inventory for 2014. Expected reductions in 2025 are equivalent to around 4.7 percent of 2014 emissions. As discussed in section IX.E, the estimated monetized benefits of methane emission reductions resulting from this rule are $160 million to approximately $950 million for reduced emissions in 2020, and $320 million to $1.8 billion for reduced emissions in 2025, depending on the discount rate used. The magnitude of these benefits estimates demonstrates that the methane reductions are consequential from an economic perspective, as well as physical perspective.

C. Major Comments Concerning Compressors

1. Wet Seal Centrifugal Compressors With Emission Rates Equal to or Lower Than Dry Seal Centrifugal Compressors
Comment: The EPA received several comments asserting that there are many wet seal centrifugal compressors that have emissions that are equal to, or lower than, dry seal compressors. One commenter notes that the EPA cites 6 standard cubic feet per minute (scfm) as the emission rate for dry seals and that a wide variety of wet seal systems are in use with varying rates of de-gas emissions and that if wet seal system can meet an emissions performance specification on par with dry seals ( i.e., 6 scfm), they should be exempt from the 95 percent reduction requirement. One commenter states that data indicate that a well-maintained wet seal will have a methane emission rate comparable to or lesser than dry seals and that the emission rate for commenter's compressors is significantly lower than the average rate identified in the EPA's National Emissions Inventory for this kind of source.
Response: The emissions factor used in our BSER analysis is an average factor calculated from available emissions information. As such, there are some wet seal centrifugal compressors that have a lower emission rate than the average emission rate. However, we have not been provided, nor do we have, any data indicating that there is a specific type or significant population of wet seal centrifugal compressors that have emission rates that are equal to or lower than dry seal compressors. We acknowledge that a well-maintained wet seal compressor may have lower emissions; however, as noted, the rule is based on an average emission factor derived from the best available information on a population of wet seal compressors. We have no data on which to base an exemption or different requirement for a subcategory of merely presumed low-emitting wet seal centrifugal compressors.

2. Regulation of Centrifugal and Reciprocating Compressors at Well Sites
Comment: The EPA received several comments opposing the exemption of centrifugal and reciprocating compressors located at well heads from the requirements of the rule. The commenters state that there are thousands of well head reciprocating compressors across the nation as well as some centrifugal compressors at well heads, and they pose a significant source of emissions unless properly controlled. The commenters contend that the reason the EPA claims to exclude these compressors is based on EPA data that show no centrifugal compressors located at well heads and on the determination that it is not cost effective to regulate these reciprocating compressors. Commenters state that the GHGRP data shows that there are centrifugal compressors located at well heads and that they should be regulated under the rule. Further, commenters assert that the EPA's cost effectiveness determination for reciprocating compressors is arbitrary because it was based on outdated emission factors and that if updated, the revised emissions would render the control for the well head compressors as cost-effective. Commenters suggest that the EPA should have relied on updated emission factors to estimate emissions from well-site compressors as it did to estimate emissions from gathering sector compressors, or at least explained why it failed to rely on updated emissions data to estimate emissions from well-site compressors.
Response: The emissions estimates presented in the proposal were based on the most robust data available at the time of their development. The EPA began collecting data through GHGRP on centrifugal compressors in the onshore petroleum and natural gas production segment in 2011. However, reporting of input data for compressors, including the count of centrifugal compressors at a facility, in onshore production was deferred until 2015 and published for the first time in October 2015. As a result, data on the number of centrifugal compressors were not available through GHGRP at the time of the development of the NSPS OOOOa proposal.
The EPA agrees with the commenter that the newly available data from GHGRP show the presence of centrifugal compressors in the onshore production segment, but the EPA disagrees with the commenter that it should cover these sources under the final rule. Although GHGRP data shows that 15 reporters indicated 69 centrifugal compressors at production facilities, the data do not provide a method to determine the number of centrifugal compressors with wet seals in onshore production. The GHGRP does not collect data on seal type (wet seal and dry seal) for onshore production. The EPA is not aware of other data sets on wet seals in the onshore production segment. Based on available data on the number of centrifugal compressors in onshore production, it is unlikely that there is a large population of centrifugal compressors with wet seals in onshore production.
With respect to emission factors for reciprocating compressors at well sites, the EPA proposed to exempt these compressors from the standards because we found that the cost of control for reciprocating compressors at well sites is not reasonable. Commenters on the 2014 Oil and Gas White Papers and on the subpart OOOOa proposal did not provide new data available for development of emission factors for reciprocating compressors at well sites. The EPA has not identified additional data sources for development of emission factors for reciprocating compressors at well sites and, therefore, has not updated its emissions estimate for this source. We continue to believe the cost of control for reciprocating compressors at well sites remains unreasonable. The final rule exempts centrifugal and reciprocating compressors at well sites.

3. Condition-Based Maintenance
Comment: The EPA solicited comment on an alternative to the proposed requirements which consists of monitoring of rod packing leakage to identify when the rate of rod packing leakage indicates that packing replacement is needed. Under such a condition-based maintenance provision, rod packing would be inspected or monitored based on a prescribed method and frequency and rod packing replacement, or repair would be required once a prescribed leak rate was observed. We requested additional information on the technical details of this condition-based concept.
Several commenters state that the rule should include an alternative maintenance program and allow operators flexibility to use a condition-based maintenance approach to reduce emissions rather than a prescribed maintenance schedule as currently included in the rule. In addition to controlling emissions, commenters assert that a condition-based maintenance may extend the operation of functional rod packing, eliminate premature and wasteful rod packing maintenance/replacement and, possibly, where rod packing leakage increases quicker than is typical, condition-based maintenance can result in earlier maintenance than EPA's proposed prescribed maintenance schedule. Commenters note that condition-based maintenance has been a proven successful technique for reducing methane emissions through the Natural Gas STAR program, where rod packing leaks were periodically monitored and the value of the incremental leaked gas (relative to leak rates for “new” packing) was compared to the rod packing maintenance cost. When the incremental lost gas value exceeded the maintenance/replacement cost, the rod packing maintenance was determined to be cost-effective.
Other commenters noted that because operators in transmission and storage segment do not own the gas, a different performance metric could be used and recommended a metric based on a defined leak rate or change in leak rate over time. Commenters recommended possibly setting a threshold at a leak rate above 2 scfm, combined with annual monitoring, which would require rod packing maintenance/replacement within nine months or during the next unit shutdown, whichever is sooner and which is consistent with a draft California Air Resources Board (CARB) regulation for oil and gas operations.
Response: The EPA disagrees with the commenters that the rule should include an alternative maintenance program and allow operators flexibility to use condition-based maintenance approach to reduce emissions rather than a prescribed maintenance schedule. While we received comment supporting the addition of a threshold-based or condition-based maintenance provision, we did not receive sufficient technical details to properly evaluate this alternative for inclusion in the rule. Although condition-based maintenance has been shown to be effective under the Natural Gas STAR program, the criteria on which rule requirements could be based would require significantly more data and analysis. Specifically, in order to evaluate such a provision for the rule, we would need to determine an appropriate leak-rate threshold which would trigger rod packing replacement. Commenters suggested 2 scfm demonstrated acceptable rod packing leakage; however, the commenters provided no substantive data as to the reason for this threshold. Commenters also recommended that we model the provision after the California Air Resources Board proposed regulation which was based on input from rod packing vendors. Although some valuable information was provided, the level of technical data and information necessary to analyze all aspects of such a provision were not provided. Therefore, we are unable to evaluate the condition-based maintenance provision for inclusion in the rule at this time.

D. Major Comments Concerning Pneumatic Controllers

1. Studies That Indicate Emission Rates for Low-Bleed Pneumatic Controllers That Are Higher Than the EPA Estimates
Comment: The EPA received comment that several recent studies report that pneumatic controllers emit more than they are designed to emit and that their emission rate is higher than the currently estimated EPA emission rate for pneumatic controllers. Specifically, the commenters noted that studies indicated that controllers were observed to have emissions inconsistent with the manufacturer's design and were likely operating incorrectly due to maintenance or equipment issues. Low-bleed pneumatic controllers were observed to have emission rates that were 270 percent higher than the EPA's emission factor for these devices, in some cases approaching the emission rate of high-bleed controllers.
Response: The emissions estimates presented in the proposal were based on the most robust data available at the time of their development. The EPA is familiar with the studies discussed in the comments summarized here and several of those studies were discussed in the EPA's Oil and Gas White Paper. The EPA has reviewed available data; because of the lack of emissions data that are straightforward to use in assessment of emissions from specific bleed rate categories ( i.e., high-bleed and low-bleed), the EPA has retained the emission factors for pneumatic controllers used in the proposal analysis and has retained the requirements for pneumatic controllers.

2. Capture and Control of Emissions From Pneumatic Controllers
Comment: The EPA received comment that pneumatic controllers should be required to capture emissions through a closed vent system and route the captured emissions to a process or a control device, similar to the approach the EPA has taken in its proposed standards for pneumatic pumps and compressors. The commenters cite recent Wyoming proposed rules for existing pneumatic controllers that allow operators of existing high-bleed controllers to route emissions to a process and the California Air Resources Board (CARB) proposed rules which requires that operators capture emissions and route to a process or control device. Commenters state that this approach would work for all types of pneumatic controllers and that this approach would be cost effective based on the costs identified for pneumatic pumps in the TSD.
Response: The EPA disagrees with the commenters that capturing and routing emissions from pneumatic controllers to a process or control device is a viable control option under our BSER analysis. While the commenter stated that a few permits in Wyoming indicate that a facility is capturing emissions from controllers and routing to a control device, we believe that there is insufficient information and data available for the EPA to establish the control option as the BSER. For more information, please see the RTC.

E. Major Comments Concerning Pneumatic Pumps

1. Compliance Date
Comment: Commenters stated that the EPA requires that new or modified pneumatic pumps at a site that currently lack an emission control device will become an affected facility if a control device is later installed; and, the facility must be in compliance within 30 days of installation of the new control device. One commenter states that 30 days does not provide such sources sufficient time to come into compliance. The commenter suggests that the rule be revised to require compliance within 30 days of startup of the control device so that the operator can ensure that the control device is properly tested after installation without concern over triggering non-compliance for pneumatic pump controls.
Response: We agree that additional time is appropriate for designing connections and testing after control device installation. Therefore, we have revised the compliance date in the final rule with respect to control devices that are installed on site after installation of the pneumatic pump affected facility. In the final rule, the compliance date for pneumatic pump affected facilities to be routed to a newly installed onsite control device 30 days after startup of the control device.

2. Subsequent Removal of Control Device
Comment: Several commenters expressed concern that the rule did not provide a way to remove control equipment from a site when it is no longer needed for the purpose for which it was installed. Further, they requested that the EPA clarify that a source ceases to be an affected facility if the control device is no longer needed for other equipment. The commenters cite an example where the exiting control device onsite is installed for a subpart OOOO storage vessel and subsequently the storage vessel's potential to emit falls below 6 tpy. If this were to occur, the storage vessel would no longer be subject to regulation and the control device would no longer be necessary.
Response: The EPA agrees that the intent of the proposal was not to require existing control devices that are no longer required for their original purposes to remain at a site only to control pneumatic pump affected facility emissions. Therefore, the final rule clarifies that subsequent to the removal of a control device and provided that there is no ability to route to a process, a pneumatic pump affected facility is no longer required to comply with § 60.5393a(b)(1) or (2). However, these units will continue to be affected facilities and we are requiring pneumatic pump affected facilities to continue following the relevant recordkeeping requirements of § 60.5420a even after an existing control device is removed.

3. Limited-Use Pneumatic Pumps
Comment: Commenters state that there are natural gas-driven pneumatic pumps which are used intermittently to transfer bulk liquids. These limited use pumps may be manually operated as needed or may be triggered by a level controller or other sensor. Specific examples provided by the commenters include engine skid sump pumps, pipeline sump pumps, tank bottom pumps, flare knockout drum pumps, and separator knockout drum pumps that are used to pump liquids from one place to another. The commenters contend that these pumps do not run continuously or even seasonally for long periods but only run periodically as needed. Thus, these pumps do not exhaust large volumes of gas in the aggregate. For this reason, the commenters requested that the final rule include an exemption for limited-use pneumatic pumps.
Response: In the TSDs to the proposed and final rule, the emission factors we used for pneumatic pumps assumed that the pumps operated 40 percent of the time. While we understood that pneumatic pumps typically do not run continuously, we did assume that the 40 percent usage was distributed evenly throughout the year. However, based upon the comments we received, the usage of some pneumatic pumps is much more limited than we previously determined and not spread evenly throughout the year. We did not intend to regulate these limited-use pneumatic pumps and are not including limited-use pneumatic pumps in the definition of pneumatic pump affected facilities that are located at well sites. Specifically, if a pump located at a well site operates for any period of time each day for less than a total of 90 days per year, this limited-use pneumatic pump is not an affected facility under this rule. We believe this requirement is sufficient to address the commenters' concerns for both intermittent use and temporary use pneumatic pumps.
Because we believe there are multiple viable alternatives available at natural gas processing plants that are not available at well sites, we do not believe it is necessary to exclude limited-use pneumatic pumps located at natural gas processing plants from the definition of pneumatic pump affected facility. Based on our best available information, both instrument air and electricity are readily available at natural gas processing plants. We believe owners and operators will choose instrument air over natural gas-driven pumps since their other pumps will be air powered. We also believe owners and operators can utilize electric pumps for intermittent activities cited by the commenters such as sump pumps and transfer pumps where it is safe to use an electric pump. Given these options, we conclude that it is not necessary to exclude limited-use pneumatic pumps located at natural gas processing plants from the definition of pneumatic pump affected facility in the final rule.

4. Removal of Tagging Requirements
Comment: Several commenters requested that the EPA remove the tagging requirement for pneumatic pump affected facilities. As written, the proposed rule required that operators tag pumps that are affected facilities and those that are not affected facilities. The commenters contend that the tagging requirement appears to add little value and is confusing. Commenters suggest operators should only be required to maintain a list of make, model, and serial number, rather than individual tags and that a list of make, model, and serial number will achieve the same results desired by the EPA, without presenting the unnecessary operational hurdles associated with individual tagging and recordkeeping.
Response: The EPA has reviewed the proposed tagging requirements and agrees with the commenters that the recordkeeping in lieu of tagging for pneumatic pumps affected facilities is sufficient. Therefore, the EPA has removed the tagging requirements for pneumatic pump affected facilities in the final rule.

5. Lean Glycol Circulation Pumps
Comment: The EPA solicited comments on the level of uncontrolled emissions from lean glycol circulation pumps and how they are vented through the dehydrator system. We received comments corroborating our understanding at proposal and in the white papers that emissions from these pumps are vented through the rich glycol separator vent or the reboiler still vent and are already regulated under 40 CFR part 63 subparts HH and HHH.
Response: The EPA's understanding during the proposal was that the lean glycol pumps are integral to the operation of the dehydrator, and as such, emissions from glycol dehydrator pumps are not separately quantified because these emissions are released from the same stack as the rest of the emissions from the dehydrator system, including HAP emission that are being controlled to meet the standards under the National Emission Standards for Hazardous Air Pollutants (NESHAP) at 40 CFR part 63 subparts HH and HHH. It is also our understanding from white paper commenters that replacing the natural gas in gas-assisted lean glycol pumps with instrument air is not feasible and would create significant safety concerns. Commenters on the white paper stated that the only option for these types of pumps are to replace them with electric motor driven pumps; however, solar and battery systems large enough to power these types of pumps are not currently feasible. Therefore, we have clarified that lean glycol circulation pumps are not affected facilities under the final pneumatic pumps standards.

F. Major Comments Concerning Well Completions

1. Request for a Limited Use of Combustion
Comment: Several commenters support the requirements for reducing completion emissions at oil wells; however, they express concern that the proposed rule does not go far enough in establishing a hierarchy of preference for the beneficial use options provided in the rule (i.e., routing the recovered gas from the separator into a gas flow line or collection system, re-injecting the recovered gas into the well or another well, use of the recovered gas as an onsite fuel source or use of the recovered gas for another useful purpose that a purchased fuel or raw material would serve) over what the commenters perceive to be the least-preferable option to route the emission to a combustion control device. Further, one commenter states that the technical infeasibility exemption in the rule is vague and could detract significantly from the overall value of this standard if not narrowly limited in application. The commenter notes that because of the swiftly increasing production of oil (along with associated natural gas) in the United States which produces very high initial rates of oil and associated gas, it is vital that the rule's requirements apply rigorously.
Response: The EPA agrees that REC should be preferred over combustion due to the secondary environmental impact from combustion. The final rule reflects such preference by requiring REC unless it is technically infeasible, in which event the recovered gas is to be routed to a completion combustion device. Further, to ensure that the exemption from REC due to technical infeasibility is limited to those situations where the operator can demonstrate that each of the options to capture and use gas beneficially is not feasible and why, we have expanded recordkeeping requirements in the final rule to include: (1) Detailed documentation of the reasons for the claim of technical infeasibility with respect to all four options provided in § 60.5375a(a)(1)(ii), including but not limited to, names and locations of the nearest gathering line; capture, re-injection, and reuse technologies considered; aspects of gas or equipment prohibiting use of recovered gas as a fuel onsite; and (2) technical considerations prohibiting any other beneficial use of recovered gas on site.
We believe these additional provisions will support a more diligent and transparent application of the intent of the technical infeasibility exemption from the REC requirement in the final rule. This information must be included in the annual report made available to the public 30 days after submission through CEDRI and WebFIRE, allowing for public review of best practices and periodic auditing to ensure flaring is limited and emissions are minimized.

G. Major Comments Concerning Fugitive Emissions From Well Sites and Compressor Stations

1. Modification Definitions for Well Sites
Comment: Several commenters assert that the definition of “modification” of a well site under the proposed rule in § 60.5365a(i) is overly broad because it would bring many existing well sites under the Rule's requirements. The commenters believe that drilling a new well or hydraulically fracturing an existing well does not increase the probability of a leak from an individual component and no new components result from these activities, thus the potential emissions rate does not change and should not be consider a modification.
Response: The EPA believes the addition of a new well or the hydraulically fracturing or refracturing of an existing well will increase emissions from the well site for the following reasons. These events are followed by production from these wells which generate additional emissions at the well sites. Some of these additional emissions will pass through leaking fugitive emission components at the well sites (in addition to the emissions already leaking from those components). Further, it is not uncommon that an increase in production would require additional equipment and, therefore, additional fugitive emission components at the well sites. We also believe that defining “modification” to include these two events, rather than requiring complex case-by-case analysis to determine whether there is emission increase in each event, will ease implementation burden for owners and operators. For the reasons stated above, EPA is finalizing the definition of “modification” of a well site, as proposed.

2. Monitoring Plan
Comment: Commenters expressed concerns about the elements of the proposed monitoring plans and encouraged the EPA to consult with the oil and gas industry and states to adopt requirements that would meet their specific needs. Commenters suggested that an area-wide monitoring plan should be allowed instead of a corporate-wide or site specific plan. The area plan would allow owners to write a plan that covers various areas for each specific region since operators may rely on contractors in one area due to location while company-owned monitoring equipment may be used within another area.
Response: The EPA participated in numerous meetings with industry, environmental and state stakeholders to discuss the proposed rule. During these meetings industry stakeholders further explained why a corporate-wide monitoring plan would be difficult to develop due to their corporate structures, well site locations, basin characteristics and many other factors. They also indicated that a site-specific plan would be redundant since many well sites within a district or field office are similar and would utilize the same personnel, contractors or monitoring equipment. The industry stakeholders provided input on specific elements of the monitoring plan, such as the walking path requirement. Based on the comments that we received and subsequent stakeholder meetings, we have made changes to the monitoring plan and have further explained our intent for the walking path. We have also modified the digital photograph recordkeeping requirements for sources of fugitive emissions. See section VI.f.1.h of this preamble for further discussion.

H. Major Comments Concerning Final Standards Reflecting Next Generation Compliance and Rule Effectiveness Strategies

1. Electronic Reporting
Comment: While some commenters express support, several commenters oppose electronic reporting of compliance-related records. Some of the commenters state that they have an obligation under the rule to maintain these records and make them available to the regulatory agency upon request, and this should be sufficient. Providing all the records requested under the proposed rule would likely cause a backlog of correspondence between the regulatory agency and the industry. Other commenters expressed concern that sensitive company information could be present in the records, and other parties could use a FOIA request to obtain the records.
Additional commenters pointed out that the EPA should not require electronic reporting until CEDRI is modified to accommodate the unique nature of the oil and natural gas production industry. As the commenters understand the operational characteristics of CEDRI, the system links reports for each affected facility to the site at which they are located. Under subparts OOOO and OOOOa, there is no unique site identifier. This would result in owners and operators having to deconstruct the annual report in order to obtain the affected facility level data needed for CEDRI. The EPA did not account for this burden and cost. The commenters request that should electronic reporting be required, that CEDRI be revised to accept the annual reports as currently specified in the proposed rule as a pdf file or hardcopy until these issues can be resolved. Commenters also request that CEDRI be modified to accept area-wide reports rather than site-level reports. Additionally, commenters noted that the definition of “certifying official” under CEDRI is different than in the proposed rule.
Finally, since the EPA did not propose regulatory language for these requirements, some commenters believe that the EPA cannot finalize these requirements without first proposing the regulatory language.
Response: The EPA notes that regulatory language for the electronic reporting requirements was available in § 60.5420a, § 60.5422a and § 60.5423a of the proposed rule.
The EPA thanks the commenters for the support for electronic reporting. Electronic reporting is in ever-increasing use and is universally considered to be faster, more efficient and more accurate for all parties once the initial systems have been established and start-up costs completed. Electronic reporting of environmental data is already common practice in many media offices at the EPA; programs such as the Toxics Release Inventory (TRI), the Greenhouse Gas Reporting Program, Acid Rain and NO X Budget Trading Programs and the Toxic Substances Control Act (TSCA) New Chemicals Program all require electronic submissions to the EPA. The EPA has previously implemented similar electronic reporting requirements in over 50 different subparts within parts 60 and 63. WebFIRE, the public access site for these data, currently houses over 5000 reports that have been submitted to the EPA via CEDRI.
The EPA notes that reporting is an essential element in compliance assurance, and this is especially true in this sector. Because of the large number of sites and the remoteness of sites, it is unlikely that the delegated agencies will be able to visit all sites. By providing reports electronically in a standardized format, the system benefits air agencies by streamlining review of data, facilitating large scale data analysis, providing access to reports and providing cost savings through a reduction in storage costs. The narrative and upload fields within the CEDRI forms can even be used to provide information to satisfy extra reporting requirements that state and local air agencies may impose.
The EPA is sensitive to the complexity of the oil and gas regulations and the unique challenges presented by this sector. CEDRI forms are designed to be consistent with the requirements of the underlying subparts and are unique to each regulation. The forms are reviewed multiple times before being finalized, and they are subjected to a beta testing period that allows end-users to provide feedback on issues with the forms prior to requiring their use. Also, if a form has not yet been completed by the time the rule is effective, affected facilities will not be required to use CEDRI until the form has been available for at least 90 days. The EPA notes that we have recently developed a bulk upload feature for several subparts within CEDRI. The bulk upload feature allows users to enter data for sites across the country in a single file instead of having to submit individual reports for each site. This feature should alleviate some of the commenters' concerns.
The EPA is aware that facility personnel must learn the new reporting system, but the savings realized by simplified data entry outweighs the initial period of learning the system. Electronic reporting can eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors and providing data quickly and accurately. Reporting form standardization can also lead to cost savings by laying out the data elements specified by the regulations in a step-by-step process, thereby helping to ensure completeness of the data and allowing for accurate assessment of data quality. Additionally, the EPA's electronic reporting system will be able to access existing information in previously submitted reports and data stored in other EPA databases. These data can be incorporated into new reports, which will lead to reporting burden reduction through labor savings.
In 2011, in response to Executive Order 13563, the EPA developed a plan to periodically review its regulations to determine if they should be modified, streamlined, expanded, or repealed in an effort to make regulations more effective and less burdensome. ^{104} The plan includes replacing outdated paper reporting with electronic reporting. In keeping with this plan and the White House's Digital Government Strategy, ^{105} in 2013 the EPA issued an agency-wide policy specifying that EPA will start with the assumption that reporting will be electronic and not paper. The EPA believes that the electronic submittal of the reports addressed in this rulemaking increases the usefulness of the data contained in those reports, is in keeping with current trends in data availability, further assists in the protection of public health and the environment and will ultimately result in less burden on the regulated community. Therefore, the EPA is retaining the requirement to report these data electronically.
^{104} EPA's Final Plan for Periodic Retrospective Reviews, August 2011. Available at: http://www.epa.gov/regdarrt/retrospective/documents/eparetroreviewplan-aug2011.pdf .
^{105} Digital Government: Building a 21st Century Platform to Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/sites/default/files/omb/egov/digital-government/digital-government-strategy.pdf .

2. Third-Party Verification for Closed Vent Systems
Comment: Several commenters express opposition to a third-party verification system for the design of closed vent systems. Some of the commenters explain that they design their closed vent system using in-house staff. Many of the details regarding actual flow volumes and gas composition are unknown at the initial design stage, so it would not be possible to certify the design's effectiveness prior to construction. Also, storage vessels are designed to have some level of losses, so it would also not be possible to certify that the closed vent system routes all emissions to the control device.
Several of the commenters also express concern that the verification process discussed in the preamble to the proposed rule would create a complex bureaucratic scheme with no measurable benefits. Many of the commenters believe such a verification process would add a significant labor and cost burden that the EPA has not quantified. The EPA's contention that third-party verification “may” improve compliance is presented without any analysis or support and does not justify the costs of such a program.
Concerning the impartiality requirements outlined by the EPA, some of the commenters believe that it would be impossible to find someone who is qualified to do verification that could pass those requirements due to the interrelationship between the production and support companies over decades of working with one another. Some commenters contend that the EPA overestimates the availability of qualified third-party consultants, assuming that an impartial one could be found, that understands the industry well enough to competently review designs for closed vent systems.
Some of the commenters remind the EPA of the conclusions the Agency reached after proposing a similar third-party verification system for the Greenhouse Gas Reporting Program, in which the EPA expressed concerns about establishing third-party verification protocols, developing a system to accredit third-party verifiers, and developing a system to ensure impartiality.
Response: The EPA continues to believe that independent third party verification can furnish more, and sometimes better, data about regulatory compliance. With better data about compliance, regulatory agencies, including the EPA, would have more information to determine what types of regulations are effective and how to spend their resources. A critical element to independent third party verification is to ensure third-party verifiers are truly independent from their clients and perform competently. We continue to believe that this model best limits the risk of bias or “capture” due to the third-party verifier identifying or aligning his interests too closely with those of the client. However, in other rulemakings, we have explored and implemented an alternative to the independent third party verification, where engineering design is the element we wish to ensure is examined and implemented without bias. This is the “qualified professional engineer” model. In the “Resource Conservation and Recovery Act (RCRA) Burden Reduction Initiative” (Burden Reduction Rule) (71 FR 16826, April 4, 2006) and the “Oil Pollution Prevention and Response; Non-Transportation-Related Onshore and Offshore Facilities rule (67 FR 47042, July 17, 2002), the Agency came to similar conclusions. First, that professional engineers, whether independent or employees of a facility, being professionals, will uphold the integrity of their profession and only certify documents that meet the prescribed regulatory requirements and that the integrity of both the professional engineer and the professional oversight of boards licensing professional engineers are sufficient to prevent any abuses. And second, that in-house professional engineers may be the persons most familiar with the design and operation of the facility and that a restriction on in-house professional certifications might place an undue and unnecessary financial burden on owners or operators of facilities by forcing them to hire an outside engineer. Also in the “Burden Reduction Rule” the Agency concluded that a professional engineer is able to give fair and technical review because of the oversight programs established by the state licensing boards that will subject the professional engineer to penalties, including the loss of license and potential fines if certifications are provided when the facts do not warrant it. A qualified professional engineer maintains the most important components of any certification requirement: (1) That the engineer be qualified to perform the task based on training and experience; and (2) that she or he be a professional engineer licensed to practice engineering under the title Professional Engineer which requires following a code of ethics with the potential of losing his/her license for negligence (see 71 FR 16868, April 4, 2006). The personal liability of the professional engineer provides strong support for both the requirement that certifications must be performed by licensed professional engineers. The Agency is convinced that an employee of a facility, who is a qualified professional engineer and who has been licensed by a state licensing board, would be no more likely to be biased than a qualified professional engineer who is not an employee of the owner or operator. The EPA has concluded that the programs established by state licensing boards provide sufficient guarantees that a professional engineer, regardless of whether he/she is “independent” of the facility, will give a fair technical review. As an additional protection, the Agency has re-evaluated the design criteria for closed vent systems to ensure that the requirements are sufficiently objective and technically precise, while providing site specific flexibility, that a qualified professional engineer will be able to certify that they have been met.
It is important to reiterate that state licensing boards can investigate complaints of negligence or incompetence on the part of professional engineers and may impose fines and other disciplinary actions, such as cease-and-desist orders or license revocation. (See 71 FR 16868.) In light of the third party oversight provided by the state licensing boards in combination with the numerous recordkeeping and recording requirements established in this rule, the Agency is confident that abuses of the certification requirements will be minimal and that human health and the environment will be protected.
In other rulemakings, which have allowed for a qualified professional engineer in lieu of an independent reviewer, the Agency has required that the professional engineer be licensed in the state in which the facility is located. (See “Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities; Final Rule” (Coal Ash Rule) (80 FR 21302, April 17, 2015)). The Agency has made this decision, in that rule, for a number of reasons, but primarily because state licensing boards can provide the necessary oversight on the actions of the professional engineer and investigate complaints of negligence or incompetence as well as impose fines and other disciplinary actions such as cease-and-desist orders or license revocation. The Agency concluded that oversight may not be as rigorous if the professional engineer is operating under a license issued from another state. While we believe this is the appropriate outcome for the Coal Ash Rule, in part due to the regional and geological conditions specific to the landfill design, we do not believe that we need to provide this restriction for the closed vent system design under this rulemaking. Closed vent system design elements are not predicated on regional characteristics but instead follow generally and widely understood engineering analysis such as volumetric flow, back pressure and pressure drops. We do believe that the professional engineer should be licensed in a minimum of one of the states in which the certifying official does business.
Whether to specify independent third-party reporting, some other type of third-party or self-reporting, or a Professional Engineer is a case-specific decision that will vary depending on the nature of the rule, the characteristics of the sector(s) and regulated entities, and the applicable regulatory requirements. Based on all relevant factors for this rule, the EPA has determined that a qualified Professional Engineer approach is appropriate and that it is unnecessary to require the individual making certifications under this rule to be “independent third parties.” Thus the final rule does not prohibit an employee of the facility from making the certification, provided they are a professional engineer that is licensed by a state licensing board.

3. The EPA's Authority and Costs for Standards Reflecting Next Generation Compliance and Rule Effectiveness
Comment: Several commenters believe that standards reflecting Next Generation Compliance and rule effectiveness strategies discussed in the preamble to the proposed rule are not legal and represent an overreach of its authority. While the EPA has authority to require reasonable recordkeeping, reporting and monitoring under the CAA, there is nothing in the CAA that can be construed to authorize the EPA to force the regulated community to hire a third-party contractor to do the EPA's work. The commenters point out that the EPA admitted in the preamble to the 2011 proposal of subpart OOOO that ensuring compliance with the well completion requirements would be very difficult and burdensome for regulatory agencies. The commenters believe that the EPA is using the requirements to relieve the regulatory agencies of some of this burden. One commenter stated that the requirements amount to an unfunded enforcement mandate on the facilities it is supposed to be regulating.
The commenters also state that the compliance requirements would violate the Anti-Deficiency Act because the third-party verification requirements would circumvent budget appropriations for EPA enforcement activities (see 31 U.S.C. 1341(a)(1)(A)).
Some of the commenters also object to the EPA justifying increased monitoring, recordkeeping and reporting requirements on consent decrees in enforcement actions. The commenters point out that consent decrees impose more stringent requirements on facilities that have been found to be in violation of a regulatory requirement; therefore, consent decree requirements would be inappropriate for generally applicable regulations. The commenters state that the EPA has provided no justification for imposing heightened requirements on all facilities regardless of their compliance history.
Several commenters also state that the EPA must propose the regulatory language for all of the compliance provisions reflecting Next Generation Compliance and rule effectiveness strategies before they can be finalized and doing otherwise would raise a notice and comment issue. One commenter added that the EPA's intent is to apply such compliance requirements to more industries than just oil and natural gas production. Therefore, the EPA must separately propose the compliance requirements in their entirety, including estimated costs and benefits, before using them in any specific rulemakings.
Many commenters believe the standards reflecting Next Generation and rule effectiveness strategies will add significant labor and cost burdens over and above the compliance costs that the EPA already estimated for complying with the proposed rule. For example, one commenter calculates that their company will have to generate 270,000 closed vent system monthly inspection reports in the first five years of the rule if current requirements are finalized. Another commenter estimates the cost of installing continuous pressure monitoring equipment at a single site to be $20,000, resulting in potential company-wide costs of about $15 million. One commenter adds, based on their own experience with third-party auditors, the cost of an audit can range from $8,000 to $15,000 per audit, per facility. In general, the commenters state that the compliance requirements raise technical and operational complexities which can only result in increased costs. Some of the commenters note that these costs would be untenable for small businesses.
Some of the commenters also expressed concern about a lack of necessary IT infrastructure, such as data acquisition hardware, data management software, and appropriate software, at remote oil and natural gas production and transmission facilities. The commenters also point out the lack of electricity at these sites. The commenters point out that dealing with these issues further increase the costs associated with these compliance measures.
Response: The EPA believes that the comment regarding our legal authority may be based upon a misunderstanding of EPA's Next Generation Compliance and rule effectiveness strategies. The EPA describes these strategies as follows:
“Today's pollution challenges require a modern approach to compliance, taking advantage of new tools and approaches while strengthening vigorous enforcement of environmental laws. Next Generation Compliance is EPA's integrated strategy to do that, designed to bring together the best thinking from inside and outside EPA.” ^{106} Among the referenced modern approaches to compliance is to “[d]esign regulations and permits that are easier to implement, with a goal of improved compliance and environmental outcomes.”
^{106} USEPA; Next Generation Compliance Web page at https://www.epa.gov/compliance/next-generation-compliance .
Thus EPA's Next Generation Compliance and rule effectiveness strategies, in and of themselves, impose no requirements or obligations on the regulated community. The strategies establish no regulatory terms for any sector or facility nor create rights or responsibilities in any party. Rather, the strategies describe general compliance assurance and regulatory design principles, approaches, and tools that EPA may consider in conducting rulemaking, permitting, and compliance assurance, and enforcement activities.
Regarding comments that in order to avoid notice and comment issues the EPA must propose regulatory language before finalizing any regulatory language, the EPA disagrees. Section 307(d)(3) of the CAA states that “notice of proposed rulemaking shall be published in the Federal Register , as provided under section 553(b) of title 5, United States Code . . . .” There is nothing in the remainder of section 307(d) that requires the EPA to publish the regulatory text. Similarly, section 553(b) of the Administrative Procedure Act (APA) does not require agencies to publish the actual regulatory text. See EMILY's List v. FEC, 362 F. Supp. 2d 43, 53 (D.D.C. 2005), where “[t]he Court notes that section 553 itself does not require the Agency to publish the text of a proposed rule, since the Agency is permitted to publish 'either the terms or substance of the proposed rule or a description of the subjects and issues involved.' ”. For this rulemaking, the EPA has provided notice and opportunity to comment for all of the specific regulatory requirements applicable to the sector and facilities covered by the rulemaking, either through proposed regulatory language or a description in the preamble.
The EPA notes that the proposal for independent third party verification—replaced in the final rule with qualified Professional Engineer requirements—reflects the responsibility of regulated entities to comply with the new NSPS. CAA Section 111(a)(1) defines “a standard of performance” as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated.” Further, in directing the Administrator to propose and promulgate regulations under section 111(b)(1)(B), Congress provided that the Administrator should take comment and then finalize the standards with such modifications “as he deems appropriate.” The D.C. Circuit has considered similar statutory phrasing from CAA section 231(a)(3) and concluded that “[t]his delegation of authority is both explicit and extraordinarily broad.” National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 1221, 1229 (D.C. Cir. 2007).
In addition, the information to be collected for the proposed NSPS is based on notification, performance tests, recordkeeping and reporting requirements which will be mandatory for all operators subject to the final standards. Recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414) which provides that for “any standard of performance under section 7411,” the Administrator may require the sources to, among other things, “install, use, and maintain such monitoring equipment, and use such audit procedures, or methods” and submit compliance certifications in accordance with subsection (a)(3) of this section,” as the Administrator may require. CAA section 114(a)(1)(A)-(G).
As discussed in section VI and in this section, the EPA has determined that to comply with the new NSPS and meet its emissions standard, regulated entities must obtain certifications from qualified Professional Engineers to demonstrate technical infeasibility to connect a pneumatic pump to an existing control device and to ensure the proper closed vent system design. The EPA believes for the sources covered by this rule, a professional engineer can furnish more, and sometimes better, data about regulatory compliance, especially where engineering design ( e.g. , closed vent system design) is the element we want to ensure is examined and implemented without bias.
The EPA notes that nothing in this rule relieves the EPA of any of its responsibilities under the CAA or implies that the EPA will not continue to use its enforcement authorities under the CAA or devote resources to monitoring and enforcing this rule. This rule simply ensures that regulated parties will have the tools available to assess and ensure their own compliance.
The EPA wishes to explain that unfunded mandates are typically rules that impose significant obligations, without funding, on state, local, or tribal governments. ^{107} Interpreting this comment as applying to the obligations this NSPS imposes on entities to which it will apply, all rules, by definition, impose some obligations and responsibilities on subject facilities. In this preamble, the EPA explains the benefits, costs, and justification for each regulatory requirement.
^{107} See USEPA, Rulemakings by Effect: Unfunded Mandates Web site at https://yosemite.epa.gov/opei/rulegate.nsf/content/effectsunfunded.html?OpenDocument&Count=1000&ExpandView .
As discussed above, the EPA explains the emission standards in this NSPS apply to the subject regulated entities. The EPA remains responsible for ensuring and enforcing compliance with the rule. The EPA notes that nothing in this rule relieves the EPA of any of its responsibilities under the CAA to ensure and enforce regulatory compliance.
The EPA agrees, that if the EPA were to seek to apply the standards in this rule—or any other regulatory standards, reflecting the Agency's Next Generation Compliance and rule effectiveness strategies or otherwise—to additional sectors beyond oil and natural gas production, the EPA would need to separately propose and justify the standards. As discussed above, however, the EPA's Next Generation Compliance and rule effectiveness strategies, in and of themselves, impose no requirements on the regulated community. The strategies prescribe no specific regulatory terms for any sector or facility nor do they create rights or responsibilities in any party. Rather, they describe compliance assurance and regulatory design strategies and approaches that the EPA will consider in conducting rulemaking, permitting, and compliance assurance, and enforcement activities that are inappropriate for notice and comment rulemaking. If the EPA believes that these strategies and approaches should be applied in other circumstances and to other industry sectors, the Agency will do this through other regulatory actions.
The EPA agrees with the commenters that certain of the Next Generation and rule effectiveness strategies are the result of information that the Agency has gained from implementation of past consent decrees ( e.g. , closed vent system design and fugitives monitoring program audit). It is not unusual for the Agency to require additional monitoring practices, and recordkeeping and reporting requirements through consent, as this provides us an opportunity to identify the effectiveness of these standards from those companies that have engaged in violative conduct. Furthermore, through our enforcement efforts, when we see common and widespread compliance problems that can be addressed through improved monitoring, reporting and recordkeeping practices, it is our duty to include these tools in rulemaking, resulting in greater environmental benefit. As discussed elsewhere in this preamble, we are not requiring an “independent third party” verification of closed vent system design, nor are we requiring that the fugitive emissions monitoring program be audited. However, because of the widespread issues we have found with closed vent system design, the Agency will require a certification by a qualified professional engineer.
Regarding the comment about necessary IT infrastructure, such as data acquisition hardware, data management software, and appropriate software, at remote oil and natural gas production and transmission facilities and the lack of electricity at these sites, the Agency does not believe that the next generation and rule effectiveness initiatives we are proposing directly require IT infrastructure beyond that already required by other aspects of the rule. Likewise, onsite electrical availability for remote well sites is not an issue for the Next Generation and Rule Effectiveness strategies that we are finalizing.

IX. Impacts of the Final Amendments

A. What are the air impacts?
For this action, the EPA estimated the emission reductions that will occur due to the implementation of the final emission limits. The EPA estimated emission reductions based on the control technologies proposed as the BSER. This analysis estimates regulatory impacts for the analysis years of 2020 and 2025. The analysis of 2020 represents the accumulation of new and modified sources from the first full year of compliance, 2016, through 2020 to illustrate the near-term impacts of the rule. The regulatory impact estimates for 2020 include sources newly affected in 2020 as well as the accumulation of affected sources from 2016 to 2019 that are also assumed to be in continued operation in 2020, thus incurring compliance costs and emissions reductions in 2020. We also estimate impacts in 2025 to illustrate the continued compound effect of this rule over a longer period. The regulatory impact estimates for 2025 include sources newly affected in 2025 as well as the accumulation of affected sources from 2016 to 2024 that are also assumed to be in continued operation in 2025, thus incurring compliance costs and emissions reductions in 2025.
In 2020, we have estimated that the final NSPS would reduce about 300,000 tons of methane emissions and 150,000 tons of VOC emissions from affected facilities. In 2025, we have estimated that the proposed NSPS would reduce about 510,000 tons of methane emissions and 210,000 tons of VOC emissions from affected facilities. The NSPS is also expected to concurrently reduce about 1,900 tons HAP in 2020 and 3,900 tons HAP in 2025.
As described in the TSD and RIA for this rule, the EPA projected affected facilities using a combination of historical data from the United States GHG Inventory, and projected activity levels, taken from the Energy Information Administration (EIA's) Annual Energy Outlook (AEO). The EPA also considered state regulations with similar requirements to the final NSPS in projecting affected sources for impacts analyses supporting this rule.

B. What are the energy impacts?
Energy impacts in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section. There would be little national energy demand increase from the operation of any of the environmental controls expected to be used for compliance with the final NSPS.
The final NSPS encourages the use of emission controls that recover hydrocarbon products, such as methane, that can be used onsite as fuel or reprocessed within the production process for sale. We estimate that the standards will result in a total cost of about $320 million in 2020 and $530 million in 2025 (in 2012 dollars).

C. What are the compliance costs?
The EPA estimates the total capital cost of the final NSPS will be $250 million in 2020 and $360 million in 2025. The estimate of total annualized engineering costs of the final NSPS is $390 million in 2020 and $640 million in 2025. This annual cost estimate includes capital, operating, maintenance, monitoring, reporting, and recordkeeping costs. This estimated annual cost does not take into account any producer revenues associated with the recovery of salable natural gas. The EPA estimates that about 16 billion cubic feet in 2020 and 27 billion cubic feet of natural gas in 2025 will be recovered by implementing the NSPS. In the engineering cost analysis, we assume that producers are paid $4 per thousand cubic feet (Mcf) for the recovered gas at the wellhead. After accounting for these revenues, the estimate of total annualized engineering costs of the final NSPS are estimated to be $320 million in 2020 and $530 million in 2025. ^{108} The price assumption is influential on estimated annualized engineering costs. A simple sensitivity analysis indicates $1/Mcf change in the wellhead price causes a change in estimated engineering compliance costs of about $16 million in 2020 and $27 million in 2025.
^{108} To the extent that NSPS affected facilities would have controlled emissions voluntarily through the Methane Challenge or other initiatives, the estimated costs and benefits of the NSPS would be lower than those included in the RIA analysis.

D. What are the economic and employment impacts?
The EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the final rule on the United States energy system. The NEMS is a publically-available model of the United States energy economy developed and maintained by the EIA and is used to produce the AEO, a reference publication that provides detailed forecasts of the United States energy economy.
The EPA estimate that natural gas and crude oil drilling levels decline slightly over the 2020 to 2025 period relative to the baseline (by about 0.17 percent for natural gas wells and about 0.02 percent for crude oil wells). Natural gas production decreases slightly over the 2020 to 2025 period relative to the baseline (by about 0.03 percent), while crude oil production does not vary appreciably. Crude oil wellhead prices for onshore lower 48 production are not estimated to change appreciably over the 2020 to 2025 period relative to the baseline. However, wellhead natural gas prices for onshore lower 48 production are estimated to increase slightly over the 2020 to 2025 period relative to the baseline (about 0.20 percent). Net imports of natural gas are estimated to increase slightly over the 2020 to 2025 period relative to the baseline (by about 0.11 percent). Crude oil net imports are not estimated to change appreciably over the 2020 to 2025 period relative to the baseline.
Executive Order 13563 directs federal agencies to consider the effect of regulations on job creation and employment. According to the Executive Order, “our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation. It must be based on the best available science.” (Executive Order 13563, 2011) While a standalone analysis of employment impacts is not included in a standard benefit-cost analysis, such an analysis is of particular concern in the current economic climate given continued interest in the employment impact of regulations such as this final rule.
The EPA estimated the labor impacts due to the installation, operation, and maintenance of control equipment, control activities, and labor associated with new reporting and recordkeeping requirements. We estimated up-front and continual, annual labor requirements by estimating hours of labor required for compliance and converting this number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours per week multiplied by 52 weeks). The up-front labor requirement to comply with the proposed NSPS is estimated at about 270 FTEs in both 2020 and 2025. The annual labor requirement to comply with final NSPS is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025.
We note that this type of FTE estimate cannot be used to identify the specific number of employees involved or whether new jobs are created for new employees versus displacing jobs from other sectors of the economy.

E. What are the benefits of the final standards?
The final rule is expected to result in significant reductions in emissions. In 2020, the final rule is anticipated to reduce 300,000 short tons, or 280,000 metric tons, of methane (a GHG and a precursor to tropospheric ozone formation), 150,000 tons of VOC (a precursor to both PM (2.5 microns and less) (PM 2.5 ) and ozone formation), and 1,900 tons of HAP. In 2025, the final rule is anticipated to reduce 510,000 short tons (460,000 metric tons) of methane, 210,000 tons of VOC, and 3,900 tons of HAP. These pollutants are associated with substantial health effects, climate effects, and other welfare effects.
The final standards are expected to reduce methane emissions annually by about 6.9 million metric tons CO 2 Eq. in 2020 and by about 11 million metric tons CO 2 Eq. in 2025. It is important to note that the emission reductions are based upon predicted activities in 2020 and 2025; however, the EPA did not forecast sector-level emissions in 2020 and 2025 for this rulemaking. To give a sense of the magnitude of the reductions, the methane reductions expected in 2020 are equivalent to about 2.8 percent of the methane emissions for this sector reported in the United States GHG Inventory for 2014 (about 232 million metric tons CO Eq. from petroleum and natural gas production and gas processing, transmission, and storage). Expected reductions in 2025 are equivalent to around 4.7 percent of 2014 emissions. As it is expected that emissions from this sector would increase over time, the estimates compared against the 2014 emissions would likely overestimate the percent of reductions from total emissions in 2020 and 2025.
Methane is a potent GHG that, once emitted into the atmosphere, absorbs terrestrial infrared radiation that contributes to increased global warming and continuing climate change. Methane reacts in the atmosphere to form tropospheric ozone and stratospheric water vapor, both of which also contribute to global warming. When accounting for the impacts of changing methane, tropospheric ozone, and stratospheric water vapor concentrations, the Intergovernmental Panel on Climate Change (IPCC) 5th Assessment Report (2013) found that historical emissions of methane accounted for about 30 percent of the total current warming influence (radiative forcing) due to historical emissions of GHGs. Methane is therefore a major contributor to the climate change impacts described previously. In 2013, total methane emissions from the oil and natural gas industry represented nearly 29 percent of the total methane emissions from all sources and account for about 3 percent of all CO 2 -equivalent emissions in the United States, with the combined petroleum and natural gas systems being the largest contributor to United States anthropogenic methane emissions.
We calculated the global social benefits of methane emission reductions expected from the final NSPS standards for oil and natural gas sites using estimates of the social cost of methane (SC-CH 4 ), a metric that estimates the monetary value of impacts associated with marginal changes in methane emissions in a given year. The SC-CH 4 estimates applied in this analysis were developed by Marten et al. (2014) and are discussed in greater detail below.
A similar metric, the social cost of CO 2 (SC-CO 2 ), provides important context for understanding the Marten et al. SC-CH 4 estimates. ^{109} The SC-CO 2 is a metric that estimates the monetary value of impacts associated with marginal changes in CO 2 emissions in a given year. Similar to the SC-CH 4 , it includes a wide range of anticipated climate impacts, such as net changes in agricultural productivity, property damage from increased flood risk, and changes in energy system costs, such as reduced costs for heating and increased costs for air conditioning. Estimates of the SC-CO 2 have been used by the EPA and other federal agencies to value the impacts of CO 2 emissions changes in benefit cost analysis for GHG-related rulemakings since 2008.
^{109} Previous analyses have commonly referred to the social cost of carbon dioxide emissions as the social cost of carbon or SCC. To more easily facilitate the inclusion of non-CO 2 GHGs in the discussion and analysis the more specific SC-CO 2 nomenclature is used to refer to the social cost of CO 2 emissions.
The SC-CO 2 estimates were developed over many years, using the best science available, and with input from the public. Specifically, an interagency working group (IWG) that included the EPA and other executive branch agencies and offices used three integrated assessment models (IAMs) to develop the SC-CO 2 estimates and recommended four global values for use in regulatory analyses. The SC-CO 2 estimates were first released in February 2010 and updated in 2013 using new versions of each IAM. The 2010 SC-CO 2 Technical Support Document (2010 TSD) provides a complete discussion of the methods used to develop these estimates and the current SC-CO 2 TSD presents and discusses the 2013 update (including recent minor technical corrections to the estimates). ^{110}
^{110} Both the 2010 SC-CO 2 TSD and the current TSD are available at: https://www.whitehouse.gov/omb/oira/social-cost-of-carbon .
The SC-CO 2 TSDs discuss a number of limitations to the SC-CO 2 analysis, including the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. Currently, IAMs do not assign value to all of the important physical, ecological, and economic impacts of climate change recognized in the climate change literature due to a lack of precise information on the nature of damages and because the science incorporated into these models understandably lags behind the most recent research. Nonetheless, these estimates and the discussion of their limitations represent the best available information about the social benefits of CO 2 reductions to inform benefit-cost analysis. The EPA and other agencies continue to engage in research on modeling and valuation of climate impacts with the goal to improve these estimates and continue to consider feedback on the SC-CO 2 estimates from stakeholders through a range of channels, including public comments on Agency rulemakings, a separate Office of Management and Budget (OMB) public comment solicitation, and through regular interactions with stakeholders and research analysts implementing the SC-CO 2 methodology. See the RIA of this rule for additional details.
A challenge particularly relevant to this rule is that the IWG did not estimate the social costs of non-CO 2 GHG emissions at the time the SC-CO 2 estimates were developed. In addition, the directly modeled estimates of the social costs of non-CO 2 GHG emissions previously found in the published literature were few in number and varied considerably in terms of the models and input assumptions they employed ^{111} (EPA 2012). In the past, EPA has sought to understand the potential importance of monetizing non-CO 2 GHG emissions changes through sensitivity analysis using an estimate of the GWP of methane to convert emission impacts to CO 2 equivalents, which can then be valued using the SC-CO 2 estimates. This approach approximates the social cost of methane (SC-CH 4 ) using estimates of the SC-CO 2 and the GWP of methane. ^{112}
^{111} U.S. EPA. 2012. Regulatory Impact Analysis Final New Source Performance Standards and Amendments to the National Emissions Standards for Hazardous Air Pollutants for the Oil and Natural Gas Industry. Office of Air Quality Planning and Standards, Health and Environmental Impacts Division. April. http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf. Accessed March 30, 2015.
^{112} For example, see (1) U.S. EPA. (2012). “Regulatory impact analysis supporting the 2012 U.S. Environmental Protection Agency final new source performance standards and amendments to the national emission standards for hazardous air pollutants for the oil and natural gas industry.” Retrieved from http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf and (2) U.S. EPA. (2012). “Regulatory impact analysis: Final rulemaking for 2017-2025 light-duty vehicle greenhouse gas emission standards and corporate average fuel economy standards.” Retrieved from http://www.epa.gov/otaq/climate/documents/420r12016.pdf .
The published literature documents a variety of reasons that directly modeled estimates of SC-CH 4 are an analytical improvement over the estimates from the GWP approximation approach. Specifically, several recent studies found that GWP-weighted benefit estimates for methane are likely to be lower than the estimates derived using directly modeled social cost estimates for these gases. ^{113} The GWP reflects only the relative integrated radiative forcing of a gas over 100 years in comparison to CO 2 . The directly modeled social cost estimates differ from the GWP-scaled SC-CO 2 because the relative differences in timing and magnitude of the warming between gases are explicitly modeled, the non-linear effects of temperature change on economic damages are included, and rather than treating all impacts over a hundred years equally, the modeled damages over the time horizon considered (300 years in this case) are discounted to present value terms. A detailed discussion of the limitations of the GWP approach can be found in the RIA.
^{113} See Waldhoff et al. (2011); Marten and Newbold (2012); and Marten et al. (2014).
In general, the commenters on previous rulemakings strongly encouraged the EPA to incorporate the monetized value of non-CO 2 GHG impacts into the benefit cost analysis. However, they noted the challenges associated with the GWP approach, as discussed above, and encouraged the use of directly modeled estimates of the SC-CH 4 to overcome those challenges.
Since then, a paper by Marten et al. (2014) has provided the first set of published SC-CH 4 estimates in the peer-reviewed literature that are consistent with the modeling assumptions underlying the SC-CO 2 estimates. 114 115
Specifically, the estimation approach of Marten et al. used the same set of three IAMs, five socioeconomic and emissions scenarios, equilibrium climate sensitivity distribution, three constant discount rates, and aggregation approach used by the IWG to develop the SC-CO 2 estimates.
^{114} Marten et al. (2014) also provided the first set of SC-N 2 O estimates that are consistent with the assumptions underlying the IWG SC-CO 2 estimates.
^{115} Marten, A.L., E.A. Kopits, C.W. Griffiths, S.C. Newbold & A. Wolverton (2014, online publication; 2015, print publication). Incremental CH 4 and N 2 O mitigation benefits consistent with the United States Government's SC-CO 2 estimates, Climate Policy, DOI: 10.1080/14693062.2014.912981.
The SC-CH 4 estimates from Marten et al. (2014) are presented below in Table 8. More detailed discussion of the SC-CH 4 estimation methodology, results and a comparison to other published estimates can be found in the RIA and in Marten et al.
Table 8—Social Cost of CH 4 , 2012-2050 a
[In 2012$ per metric ton] (Source: Marten et al., 2014 b )
Year | SC-CH 4 | 5% Average | 3% Average | 2.5% Average | 3% 95th percentile
2012 | $430 | $1000 | $1400 | $2800
2015 | 490 | 1100 | 1500 | 3000
2020 | 580 | 1300 | 1700 | 3500
2025 | 700 | 1500 | 1900 | 4000
2030 | 820 | 1700 | 2200 | 4500
2035 | 970 | 1900 | 2500 | 5300
2040 | 1100 | 2200 | 2800 | 5900
2045 | 1300 | 2500 | 3000 | 6600
2050 | 1400 | 2700 | 3300 | 7200
Notes:
a There are four different estimates of the SC-CH 4 , each one emissions-year specific. The first three shown in the table are based on the average SC-CH 4 from three integrated assessment models at discount rates of 5, 3, and 2.5 percent. The fourth estimate is the 95th percentile of the SC-CH 4 across all three models at a 3 percent discount rate. See RIA for details.
b The estimates in this table have been adjusted to reflect the minor technical corrections to the SC-CO 2 estimates described above. See the Corrigendum to Marten et al. (2014), http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550.
The application of these directly modeled SC-CH 4 estimates from Marten et al. (2014) in a benefit-cost analysis of a regulatory action is analogous to the use of the SC-CO 2 estimates. In addition, the limitations for the SC-CO 2 estimates discussed above likewise apply to the SC-CH 4 estimates, given the consistency in the methodology.
In early 2015, the EPA conducted a peer review of the application of the Marten et al. (2014) non-CO 2 social cost estimates in regulatory analysis and received responses that supported this application. See the RIA for a detailed discussion.
The EPA also carefully considered the full range of public comments and associated technical issues on the Marten et al. SC-CH 4 estimates received through this rulemaking. The comments addressed the technical details of the SC-CO 2 estimates and the Marten et al. SC-CH 4 estimates as well as their application to this rulemaking analysis. The commenters also provided constructive recommendations to improve the SC-CO 2 and SC-CH 4 estimates in the future. Based on the evaluation of the public comments on this rulemaking, the favorable peer review of the Marten et al. application, and past comments urging the EPA to value non-CO 2 GHG impacts in its rulemakings, the EPA concluded that the estimates represent the best scientific information on the impacts of climate change available in a form appropriate for incorporating the damages from incremental methane emissions changes into regulatory analysis. The EPA has included those benefits in the main benefits analysis. See the RTC document for the complete response to comments received on the SC-CH 4 as part of this rulemaking.
The methane benefits calculated using Marten et al. (2014) are presented in Table 9 for years 2020 and 2025. Applying this approach to the methane reductions estimated for the NSPS, the 2020 methane benefits vary by discount rate and range from about $160 million to approximately $960 million; the mean SC-CH 4 at the 3-percent discount rate results in an estimate of about $360 million in 2020. The methane benefits increase in the 2025, ranging from $320 million to $1.8 billion, depending on discount rate used; the mean SC-CH 4 at the 3-percent discount rate results in an estimate of about $690 million in 2025.
Table 9—Estimated Global Benefits of Methane Reductions
[In millions, 2012$]
Discount rate and statistic | Year | 2020 | 2025
Million metric tonnes of methane reduced | 0.28 | 0.46
Million metric tonnes of CO 2 Eq. | 6.9 | 11
5% (average) | $160 | $320
3% (average) | $360 | $690
2.5% (average) | $480 | $890
3% (95th percentile) | $960 | $1,800
In addition to the limitation discussed above, and the referenced documents, there are additional impacts of individual GHGs that are not currently captured in the IAMs used in the directly modeled approach of Marten et al. (2014) and, therefore, not quantified for the rule. For example, in addition to being a GHG, methane is a precursor to ozone. The ozone generated by methane has important non-climate impacts on agriculture, ecosystems, and human health. The RIA describes the specific impacts of methane as an ozone precursor in more detail and discusses studies that have estimated monetized benefits of these methane generated ozone effects. The EPA continues to monitor developments in this area of research.
With the data available, we are not able to provide credible health benefit estimates for the reduction in exposure to HAP, ozone and PM 2.5 for these rules, due to the differences in the locations of oil and natural gas emission points relative to existing information and the highly localized nature of air quality responses associated with HAP and VOC reductions. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. ^{116} In addition to health improvements, there will be improvements in visibility effects, ecosystem effects and climate effects, as well as additional product recovery.
^{116} Previous studies have estimated the monetized benefits-per-ton of reducing VOC emissions associated with the effect that those emissions have on ambient PM 2.5 levels and the health effects associated with PM 2.5 exposure (Fann, Fulcher, and Hubbell, 2009). While these ranges of benefit-per-ton estimates can provide useful context, the geographic distribution of VOC emissions from the oil and gas sector are not consistent with emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition, the benefit-per-ton estimates for VOC emission reductions in that study are derived from total VOC emissions across all sectors. Coupled with the larger uncertainties about the relationship between VOC emissions and PM 2.5 and the highly localized nature of air quality responses associated with HAP and VOC reductions, these factors lead us to conclude that the available VOC benefit-per-ton estimates are not appropriate to calculate monetized benefits of these rules, even as a bounding exercise.
Although we do not have sufficient information or modeling available to provide quantitative estimates for this rulemaking, we include a qualitative assessment of the health effects associated with exposure to HAP, ozone and PM 2.5 in the RIA for this rule. These qualitative effects are briefly summarized below, but for more detailed information, please refer to the RIA, which is available in the docket. One of the HAP of concern from the oil and natural gas sector is benzene, which is a known human carcinogen. VOC emissions are precursors to both PM 2.5 and ozone formation. As documented in previous analyses (U.S. EPA, 2006 ^{117,} U.S. EPA, 2010 ^{118} , and U.S. EPA, 2014 ^{119} ), exposure to PM 2.5 and ozone is associated with significant public health effects. PM 2.5 is associated with health effects, including premature mortality for adults and infants, cardiovascular morbidity such as heart attacks, and respiratory morbidity such as asthma attacks, acute bronchitis, hospital admissions and emergency room visits, work loss days, restricted activity days and respiratory symptoms, as well as visibility impairment. ^{120} Ozone is associated with health effects, including hospital and emergency department visits, school loss days and premature mortality, as well as injury to vegetation and climate effects. ^{121}
^{117} U.S. EPA. RIA. National Ambient Air Quality Standards for Particulate Matter, Chapter 5. Office of Air Quality Planning and Standards, Research Triangle Park, NC. October 2006. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205—Benefits.pdf .
^{118} U.S. EPA. RIA. National Ambient Air Quality Standards for Ozone. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January 2010. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-supplemental_analysis_full.pdf .
^{119} U.S. EPA. RIA. National Ambient Air Quality Standards for Ozone. Office of Air Quality Planning and Standards, Research Triangle Park, NC. December 2014. Available on the Internet at http://www.epa.gov/ttnecas1/regdata/RIAs/20141125ria.pdf .
^{120} U.S. EPA. Integrated Science Assessment for Particulate Matter (Final Report) . EPA-600-R-08-139F. National Center for Environmental Assessment—RTP Division. December 2009. Available at http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546 .
^{121} U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final) . EPA/600/R-05/004aF-cF. Washington, DC: U.S. EPA. February 2006. Available on the Internet at http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923 .
Finally, the control techniques to meet the standards are anticipated to have minor secondary emissions impacts, which may partially offset the direct benefits of this rule. The magnitude of these secondary air pollutant impacts is small relative to the direct emission reductions anticipated from this rule.
In particular, the EPA has estimated that an increase in flaring of natural gas in response to this rule will produce a variety of emissions, including about 1.0 million short tons of CO 2 in 2020 and about 1.2 million short tons of CO 2 in 2025. The EPA has not estimated the monetized value of the secondary emissions of CO 2 because much of the VOCs and methane that would have been released in the absence of the flare would have eventually oxidized into CO 2 in the atmosphere. Note that the CO 2 produced from the methane oxidizing in the atmosphere is not included in the calculation of the SC-CH 4 .
For VOC emissions, the oxidization period is relatively short, on the order of a couple of weeks. However, for methane, the oxidization period is longer, on the order of a decade, and the EPA recognizes that because the growth rate of the SC-CO 2 estimates are lower than their associated discount rates, the estimated impact of CO 2 produced in the future via oxidized methane from fossil-based emissions may be less than the estimated impact of CO 2 released immediately from combustion. This would imply a small disbenefit associated with the earlier release of CO 2 during combustion of the methane emissions.
In the proposal, the EPA solicited comment on the appropriateness of monetizing the impact of the earlier release of CO 2 due to combusting methane emissions from oil and gas sites and an illustrative analysis that described a potential approach to approximate this value using the SC-CO 2 . The EPA did not receive any comments regarding the appropriate methodology for conducting such an analysis, but did receive one comment letter that voiced general support for monetizing the secondary impacts. In consideration of this comment and recognizing the challenges and uncertainties related to estimation of these secondary emissions impacts for this rulemaking, EPA has continued to examine this issue in the context of this regulatory analysis ( i.e., the combusting of fossil-based methane at oil and gas sites) and explored ways to improve the illustrative analysis. See RIA for details.

X. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders .

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
This action is an economically significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action.
In addition, the EPA prepared a Regulatory Impact Analysis (RIA) of the potential costs and benefits associated with this action. The RIA available in the docket describes in detail the empirical basis for the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. Table 10 shows the results of the cost and benefits analysis for the final rule.
Table 10—Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Oil and Natural Gas NSPS in 2020 and 2025
[Millions of 2012$]
| 2020 | 2025
Total Monetized Benefits ^1 | $360 million | $690 million.
Total Costs ^2 | $320 million | $530 million.
Net Benefits ^3 | $35 million | $170 million.
Non-monetized Benefits | Non-monetized climate benefits.
| Health effects of PM 2.5 and ozone exposure from 150,000 tons of VOC in 2020 and 210,000 tons of VOC in 2025.
| Health effects of HAP exposure from 1,900 tons of HAP in 2020 and 3,900 tons of HAP in 2025.
| Health effects of ozone exposure from 300,000 tons of methane in 2020 and 510,000 tons methane in 2025.
| Visibility impairment.
| Vegetation effects.
1 We estimate methane benefits associated with four different values of a one ton methane reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). For the purposes of this table, we show the benefits associated with the model average at 3 percent discount rate, however we emphasize the importance and value of considering the full range of social cost of methane values. We provide estimates based on additional discount rates in preamble section IX.E and in the RIA. The CO 2 -equivalent (CO 2 Eq.) methane emission reductions are 6.9 million metric tons in 2020 and 11 million metric tons in 2025. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits.
2 The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue from additional natural gas recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 percent discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate.
3 Figures may not sum due to rounding.

B. Paperwork Reduction Act (PRA)
The Office of Management and Budget (OMB) has previously approved the information collection activities contained in 40 CFR part 60, subpart OOOO under the PRA and has assigned OMB control number 2060-0673 and ICR number 2437.01; a summary can be found at 77 FR 49537. The information collection requirements in the final action titled, Standards of Performance for Crude Oil and Natural Gas Facilities for Construction, Modification, or Reconstruction (40 CFR part 60 subpart OOOOa) have been submitted for approval to the OMB under the PRA. The ICR document prepared by the EPA has been assigned EPA ICR Number 2523.01. You can find a copy of the ICR in the docket for this rule, and is briefly summarized below.
The information to be collected for the final NSPS is based on notification, performance tests, recordkeeping and reporting requirements which will be mandatory for all operators subject to the final standards. Recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). The information will be used by the delegated authority (state agency, or Regional Administrator if there is no delegated state agency) to ensure that the standards and other requirements are being achieved. Based on review of the recorded information at the site and the reported information, the delegated permitting authority can identify facilities that may not be in compliance and decide which facilities, records, or processes may need inspection. All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B.
Potential respondents under subpart OOOOa are owners or operators of new, modified or reconstructed oil and natural gas affected facilities as defined under the rule. None of the facilities in the United States are owned or operated by state, local, tribal or the Federal government. All facilities are privately owned for-profit businesses. The requirements in this action result in industry recording keeping and reporting burden associated with review of the requirements for all affected entities, gathering relevant information, performing initial performance tests and repeat performance tests if necessary, writing and submitting the notifications and reports, developing systems for the purpose of processing and maintaining information, and train personnel to be able to respond to the collection of information.
The estimated average annual burden (averaged over the first 3 years after the effective date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for the 2,554 owners and operators that are subject to the rule is 98,438 labor hours, with an annual average cost of $3,361,074. The annual public reporting and recordkeeping burden for this collection of information is estimated to average 20 hours per response. Respondents must monitor all specified criteria at each affected facility and maintain these records for 5 years. Burden is defined at 5 CFR 1320.3(b).
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 the EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act (RFA)
Pursuant to sections 603 and 609(b) of the RFA, the EPA prepared an initial regulatory flexibility analysis (IRFA) for the proposed rule and convened a Small Business Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity representatives that potentially would be subject to the rule's requirements. Summaries of the IRFA and Panel recommendations are presented in the proposed rule at 80 FR 56593.
As required by section 604 of the RFA, the EPA prepared a final regulatory flexibility analysis (FRFA) for this action. The FRFA addresses the issues raised by public comments on the IRFA for the proposed rule. The complete FRFA is available for review in the RIA in the public docket and is summarized here.

1. Statutory Authority
The legal authority for this rule stems from section 111 of the CAA, which requires the EPA to issue “standards of performance” for new sources in the list of categories of stationary sources that cause or contribute significantly to air pollution and which may reasonably be anticipated to endanger public health or welfare. See section III.A of this preamble for more information.

2. Significant Issues Raised and Agency Responses
The EPA received comments on the proposed standards related to the potential impacts on small entities and requests for comments that were included based on the SBAR Panel Recommendations. See sections VI and VIII of this preamble and the RTC Document in Docket ID EPA-HQ-OAR-2010-0505 for more detailed responses.
Low production wells: Several commenters supported the proposed exemption of low production well sites from the fugitive monitoring requirements. Commenters noted that marginal wells generate relatively low revenue and these wells are often drilled and operated by small companies.
Response: While these commenters did provide support for the proposed low production well exemption, other commenters indicated that low production well sites have the potential to emit substantial amounts of fugitive emissions, and that a significant number of wells would be excluded from fugitive emissions monitoring based on this exemption. We did not receive data showing that low production well sites have lower emissions than non-low production well sites. In fact, the data that were provided indicated that the potential emissions from these well sites could be as significant as the emissions from non-low production well sites since the type of equipment and the well pressures are more than likely the same. In discussions with stakeholders, they indicated that well site fugitive emissions are not based on production, but rather on the number of pieces of equipment and components. Therefore, we believe that the emissions from low production and non-low production well sites are comparable and we did not finalize the proposed exclusion of low production well sites from fugitive emissions monitoring.
REC costs: Commenters stated that small operators have higher well completion costs, and typically conduct completions less frequently. Generally, small operators lack the purchasing power to get the discounted prices service companies offer to larger operators. However, small entity commenters did not provide specific cost information.
Response: The BSER analysis is based on the averages of nationwide data. It is possible for a small operator to have higher than the nationwide average completion costs, however, the daily completion cost provided by the commenters is not significantly different than the EPA's estimate. Therefore, we do not believe that the cost of RECs disfavor small businesses.
Phase-in period for RECs: Commenters stated that the EPA should create a compliance phase-in period of at least 6 months for the REC requirements, to accommodate small operators. Commenters stated that REC equipment is in short supply, and this will drive up REC costs. Commenters stated that small entities lack the purchasing power of larger operators, which makes it difficult to obtain the needed equipment before the compliance period begins.
Response: We agree that compliance with the REC requirements in the final rule could be burdensome for some in the near term due to the unavailability of REC equipment. As discussed in section VI of the preamble, the final rule provides a phase-in approach that would allow a quick build-up of the REC supplies in the near term.
Alternatives to OGI technology: Several commenters indicated that the EPA should allow alternatives to OGI technology as the cost is excessive for small operators.
Response: In the final rule, the EPA is allowing Method 21 with a repair threshold of 500 ppm as an alternative to OGI. We believe this alternative will alleviate some of the burden on small entities.
Basing monitoring frequency on the percentage of leaking components: Commenters indicated that using a percentage of components, rather than a set number of components, to determine the frequency of surveys is also unfair to small entities since a small site will have fewer fugitive emission components than a larger site. Commenters stated that smaller entities are much more likely to operate these smaller sites, and thus are more likely to have higher frequency survey requirements under the percentage-based system.
Response: The EPA agrees that imposing a performance based monitoring schedule would require operators to develop a program that would require extensive administration to ensure compliance. We believe that the potential for a performance-based approach to encourage greater compliance is outweighed in this case by these additional burdens and the complexity it would add. Therefore, the EPA is finalizing a fixed monitoring frequency instead of performance based monitoring.
Timing of initial fugitive monitoring periods: Commenters stated that the requirement to conduct surveys for affected facilities using OGI technology within 30 days of the well completion or within 30 days of modification is overly restrictive. Additionally, commenters stated that small operators may not be able to find vendors available to survey a small number of wells within the required timeframe. One commenter stated that contractors will be in high demand and may give scheduling preference to larger clients versus small business entities.
Response: The EPA considered these and other comments and concluded that the proposed time of 30 days within a well completion or modification is not enough time to complete the necessary preparations for the initial monitoring survey. In addition, other commenters pointed out that first date of production should be the trigger, rather than the date of well completion. Therefore, for the collection of fugitive emissions components at a new or modified well site, we are finalizing that the initial monitoring survey must take place by June 3, 2017 or within 60 days of the startup of production, whichever is later. We believe this extended timeframe for compliance will alleviate some of the burden on smaller operators.
Third party compliance: Commenters believe that requiring third party compliance audits will be a significant burden on small entities. One commenter said that a third-party audit requirement will dramatically increase the costs of the program and have a negative competitive impact on smaller, less funded operators.
Response: While the EPA continues to believe that independent third party verification can furnish more, and sometimes better, data about regulatory compliance, we have explored alternatives to the independent third party verification. Specifically, the “qualified professional engineer” model was assessed to focus on the element of engineering design. The final rule requires a professional engineer certification of technical infeasibility of connecting a pneumatic pump to an existing control device, and a professional engineer design of closed vent systems. These certifications will ensure that the owner or operator has effectively assessed appropriate factors before making a claim of infeasibility and that the closed vent system is properly designed to verify that all emissions from the unit being controlled in fact reach the control device and allow for proper control. We believe this simplified approach will reduce the burden imposed on all affected facilities, including those owned by small businesses.

3. Affected Small Entities
To identify potentially affected entities under the proposed NSPS, the EPA combined information from industry databases to identify firms drilling and completing wells in 2012, as well as identified their oil and natural gas production levels for that year.
The analysis indicates about 2,031 small entities may be subject to the requirements for hydraulically fractured and re-fractured oil well completions and fugitive emissions requirements at well sites.

4. Reporting, Recordkeeping and Other Compliance Requirements
The information to be collected for the NSPS is based on notification, performance tests, recordkeeping and reporting requirements which will be mandatory for all operators subject to the final standards. The estimated average annual burden (averaged over the first 3 years after the effective date of the standards) for the recordkeeping and reporting requirements in subpart OOOOa for the 2,554 owners and operators that are subject to the rule is 98,438 labor hours, with an annual average cost of $3,361,074. The annual public reporting and recordkeeping burden for this collection of information is estimated to average 20 hours per response. Respondents must monitor all specified criteria at each affected facility and maintain these records for 5 years. Burden is defined at 5 CFR 1320.3(b).
The EPA summarized the potential regulatory cost impacts of the proposed rule and alternatives in Section 3 of the RIA. The analysis in the FRFA drew upon the same analysis and assumptions as the analyses presented in the RIA. The FRFA analysis is presented in its entirely in Section 6.3 of the RIA.
The EPA based the analysis in the FRFA on impacts estimates for the proposed requirements for hydraulically fractured and re-fractured oil well completions and well site fugitive emissions, which represent about 98 percent of the estimated compliance costs of the NSPS in 2020 and 2025. Not incorporating impacts from other provisions in this analysis underestimates impacts, but the EPA believes that detailed analysis of the two provisions impacts on small entities is illustrative of impacts on small entities from the rule in its entirety. The cost of compliance for small firms is estimated to be about $110 million in 2020 and $190 million in 2025.
We also estimate cost-to-sales ratios for small firms. For some firms, we estimate their 2012 sales levels by multiplying their 2012 oil and natural gas production levels reported in an industry database by the assumed oil and natural gas prices at the wellhead. For natural gas, we assumed the $4/Mcf for natural gas. For oil prices, we estimated revenues using two alternative prices, $70/bbl and $50/bbl. In the results, we call the case using $70/bbl the “primary scenario” and the case using the $50/bbl the “low oil price scenario”. For projected 2020 and 2025 potentially affected activities, we allocated compliance costs across entities based upon the costs estimated in the TSD and used in the RIA.
The percent of small firms with cost-to-sales ratios greater than 1 percent and greater than 3-percent increase from 2020 to 2025 as affected sources accumulate under the NSPS. Cost-to-sales ratios exceeding 1 percent and 3 percent. Also, cost-to-sales ratios fall as the oil price falls from the main scenario to the low oil price scenario.
The analysis above is subject to a number of caveats and limitations. These are discussed in detail in the IRFA, as well as in Section 3 of the RIA.

5. Steps Taken To Minimize Impact on Small Entities
The EPA considered three major options for this rule. The finalized option includes reduced emission completion (REC) and completion combustion requirements for a subset of newly completed oil wells that are hydraulically fractured or refractured and requirements that fugitive emissions survey and repair programs be performed semiannually at affected well sites and quarterly at affected transmission and storage or compressor stations. One option examined includes an exemption from low production well site fugitive requirements, but was rejected because we believe that low production well sites have similar equipment and components as sites that are not categorized as low production. Without data supporting a difference in emissions between low production well sites and not low production well sites, the EPA believes exempting low production well sites would reduce the effectiveness of the rule, especially considering the high proportion of small firms in the industry. The more stringent option required quarterly monitoring for all sites under the fugitive emissions programs, which leads to greater emissions reductions, however it also increases net costs and results in lower net benefits compared to the finalized option.
Significant comments with regard to the small business analysis received by the EPA include the topics of low production well exemptions, well completion costs, compliance phase-in periods, alternatives to OGI technology, monitoring frequency and timing, and third party compliance.
Though all comments were seriously considered, the EPA is unable to incorporate all suggestions without compromising the effectiveness of the final regulation. Changes to the rule from proposal that may benefit small entities due to comments received include allowing both OGI and Method 21 as acceptable monitoring technology, replacing a performance based monitoring schedule with a fixed frequency, lengthening the time of initial fugitive monitoring from within 30 days to the later of either June 3, 2017 or within 60 days of the startup of production, whichever is later, and simplifying the third party verification of technical infeasibility requirements. Though these are not monetized, we believe the flexibility and simplifications these changes have added to the rule result in a reduced burden on small entities.
In addition, the EPA is preparing a Small Entity Compliance Guide to help small entities comply with this rule. The guide will be available on the World Wide Web 60 days after publication of the final rule at https://www3.epa.gov/airquality/oilandgas/implement.html.

D. Unfunded Mandates Reform Act of 1995 (UMRA)
This action contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, that may result in expenditures of $100 million or more for state, local and tribal governments, in the aggregate, or the private sector in any one year. More specifically, this action contains a federal private sector mandate that may result in the expenditures of $100 million or more for the private section in any one year. Accordingly, the EPA has prepared the following written statement in compliance with sections 202 and 205 of UMRA. This rule is not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.

1. Statutory Authority
The legal authority for this rule stems from section 111 of the CAA, which requires the EPA to issue “standards of performance” for new sources in the list of categories of stationary sources that cause or contribute significantly to air pollution and which may reasonably be anticipated to endanger public health or welfare. See section III.A of this preamble for more information.

2. Costs and Benefits
As discussed in sections II.A.3, IX.C and IX.E of this preamble, this rule results in a net benefit. Including the resources from recovered natural gas that would otherwise be vented, the quantified net benefits of the regulation are estimated to be $35 million in 2020 and $170 million in 2025 in 2012 dollars using a 3 percent discount rate for climate benefits. The estimated total annualized engineering costs of the final rule, accounting for the recovered natural gas are $320 million in 2020 and $530 million in 2025. The EPA estimates the final rule will lead to monetized benefits of about $360 million in 2020 and $690 million in 2025, at the model average at a 3 percent discount rate. More in depth information on costs and benefits, including non-monetized or quantified benefits, of the final regulation can be found in the RIA.

3. Effects on National Economy
As seen in section IX.D of this preamble, the EPA used the National Energy Modeling System (NEMS) to estimate the impacts of the final rule on the United States energy system. Estimates show slight declines in natural gas and crude oil drilling, and natural gas production over the 2020 to 2025 period under the rule, while wellhead natural gas prices are estimated to increase slightly over the 2020 to 2025 period under the rule. Crude oil production and crude oil wellhead prices are not estimated to change appreciably over the 2020 to 2025 period under the rule. Net imports of natural gas are estimated to increase slightly over the 2020 to 2025 period, while net imports of crude oil are not estimated to change appreciably.
Also discussed in section IX.D, the up-front labor requirement to comply with the proposed NSPS is estimated at about 270 FTEs in 2020 and 2025. The annual labor requirement to comply with final NSPS is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025. For more in depth information on both the estimated energy markets impacts and estimated job creation and employment impacts of this rule, see the RIA.

4. Regulatory Alternatives
Alternate regulatory options examined in the RIA include decreasing fugitive survey requirements to annual at well sites and semiannual at all other affected locations (termed Option 1 in the RIA), and increasing fugitive survey frequency at all wells to quarterly (termed Option 3 in the RIA). The finalized regulation results in estimated net benefits of $35 million in 2020 and $170 million in 2025. Reducing fugitive survey requirements, Option 1, leads to lower costs as well as lower benefits and results in estimated net benefits of $54 million in 2020 and $180 million in 2025. Increasing the survey frequency leads to an increase in capital costs with a non-commensurate increase in monetized benefits, resulting in estimated net benefits of −$75 million in 2020, and −$38 million in 2025. Both of these regulatory options result in lower net benefits in 2025 compared to the finalized regulation. For a more in depth analysis of these options, see the RIA.

E. Executive Order 13132: Federalism
This action does not have federalism implications. It 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. These final rules primarily affect private industry and would not impose significant economic costs on state or local governments.

F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments
Subject to Executive Order 13175 (65 FR 67249; November 9, 2000), the EPA may not issue a regulation that has tribal implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by tribal governments, or the EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement.
The EPA has concluded that this action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law, thus Executive Order 13175 does not apply to this rule. The EPA believes that the affected facilities impacted by this rulemaking on tribal lands are owned by private entities, and tribes will not be directly impacted by the compliance costs associated with this rulemaking. There would only be tribal implications associated with this rulemaking in the case where a unit is owned by a tribal government or a tribal government is given delegated authority to enforce the rulemaking.
The EPA offered consultation with tribal officials early in the regulation development process to permit them an opportunity to have meaningful and timely input. Consultation letters were sent to the tribal leaders of 567 federally recognized tribes, provided information regarding this rule, and offered consultation. The EPA did not receive any requests for tribal consultation on this rulemaking. In addition, the EPA has conducted meaningful involvement with tribal stakeholders throughout the rulemaking process and provided an update on the Methane Strategy on the January 29, 2015 and September 10, 2015 National Tribal Air Association and EPA Air Policy monthly calls. Consistent with previous actions affecting the oil and natural gas sector, there is significant tribal interest because of the growth of the oil and natural gas production in Indian country. The EPA specifically solicited comment on the proposed action from tribal officials and considered comments received from tribal officials in the development of this final action. Please see the RTC document in the public docket.

G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks
This action is subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is an economically significant regulatory action as defined by Executive Order 12866, and the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the Agency has evaluated the environmental health and welfare effects of climate change on children.
Greenhouse gases including methane contribute to climate change and are emitted in significant quantities by the oil and gas sector. The EPA believes that the GHG emission reductions resulting from implementation of these final rules will further improve children's health.
The assessment literature cited in the EPA's 2009 Endangerment Finding 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 2009 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 IV.B of this preamble.

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use
Executive Order 13211 (66 FR 28355, May 22, 2001) provides that agencies will prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, Office of Management and Budget, a Statement of Energy Effects for certain actions identified as “significant energy actions.” Section 4(b) of Executive Order 13211 defines “significant energy actions” as any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is a significant regulatory action under Executive Order 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action.
This action is not a “significant energy action” as defined in Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The basis for these determinations follows.
The EPA used the NEMS to estimate the impacts of the final rule on the United States energy system. The NEMS is a publically-available model of the United States energy economy developed and maintained by the Energy Information Administration of the DOE and is used to produce the Annual Energy Outlook, a reference publication that provides detailed forecasts of the United States energy economy.
The EPA estimates that natural gas and crude oil drilling levels decline slightly over the 2020 to 2025 period under the final NSPS (by about 0.17 percent for natural gas wells and 0.02 percent for crude oil wells). Crude oil production does not vary appreciably under the rule, while natural gas production declines slightly over the 2020 to 2025 period (about 0.03 percent). Crude oil wellhead prices for onshore lower 48 production are not estimated to change appreciably over the 2020 to 2025 period. However, wellhead natural gas prices for onshore lower 48 production are estimated to increase slightly over the 2020 to 2025 period (about 0.20 percent). Net imports of natural gas are estimated to increase slightly in 2020 (by about 0.12 percent) and in 2025 (by about 0.11 percent). Crude oil net imports are not estimated to change in 2020, but decrease slightly in 2025 (by about 0.02 percent). Net imports of crude oil do not change appreciably over the 2020 to 2025 period.
Additionally, the NSPS establishes several performance standards that give regulated entities flexibility in determining how to best comply with the regulation. In an industry that is geographically and economically heterogeneous, this flexibility is an important factor in reducing regulatory burden. For more information on the estimated energy effects of this final rule, please see the Regulatory Impact Analysis, which is in the docket for this rule.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51
This action involves technical standards. Therefore, the EPA conducted searches for the Oil and Natural Gas Sector: Emission Standards for New and Modified Sources through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 60 Appendix A. No applicable voluntary consensus standards were identified for EPA Methods 1A, 2A, 2D, 21, and 22 and none were brought to its attention in comments. All potential standards were reviewed to determine the practicality of the voluntary consensus standards (VCS) for this rule.
Two VCS were identified as an acceptable alternative to EPA test methods for the purpose of this rule. First, ANSI/ASME PTC 19-10-1981, Flue and Exhaust Gas Analyses (Part 10) was identified to be used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A manual portions only and not the instrumental portion. This standard includes manual and instructional methods of analysis for carbon dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen, and sulfur dioxide. Second, ASTM D6420-99 (2010), “Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectrometry” is an acceptable alternative to EPA Method 18 with the following caveats, only use when the target compounds are all known and the target compounds are all listed in ASTM D6420 as measurable. ASTM D6420 should never be specified as a total VOC Method. (ASTM D6420-99 (2010) is not incorporated by reference in 40 CFR part 60.) The search identified 19 VCS that were potentially applicable for this rule in lieu of EPA reference methods. However, these have been determined to not be practical due to lack of equivalency, documentation, validation of data and other important technical and policy considerations. For additional information, please see the April 6, 2016, memo titled, “Voluntary Consensus Standard Results for Oil and Natural Gas Sector: Emission Standards for New and Modified Sources” in the public docket.
In this rule, the EPA is finalizing regulatory text for 40 CFR part 60, subpart OOOOa that includes incorporation by reference in accordance with requirements of 1 CFR 51.5 as discussed below. Ten standards are incorporated by reference.
• ASTM D86-96, Distillation of Petroleum Products (Approved April 10, 1996) covers the distillation of natural gasolines, motor gasolines, aviation gasolines, aviation turbine fuels, special boiling point spirits, naphthas, white spirit, kerosines, gas oils, distillate fuel oils, and similar petroleum products, utilizing either manual or automated equipment.
• ASTM D1945-03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography covers the determination of the chemical composition of natural gases and similar gaseous mixtures within a certain range of composition. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components.
• ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuel covers procedures for calculating heating value, relative density, and compressibility factor at base conditions for natural gas mixtures from compositional analysis. It applies to all common types of utility gaseous fuels.
• ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion covers the determination of the heating value of natural gases and similar gaseous mixtures within a certain range of composition.
• ASTM D6522-00 (Reapproved December 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers covers the determination of nitrogen oxides, carbon monoxide, and oxygen concentrations in controlled and uncontrolled emissions from natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters.
• ASTM E168-92, General Techniques of Infrared Quantitative Analysis covers the techniques most often used in infrared quantitative analysis. Practices associated with the collection and analysis of data on a computer are included as well as practices that do not use a computer.
• ASTM E169-93, General Techniques of Ultraviolet Quantitative Analysis (Approved May 15, 1993) provide general information on the techniques most often used in ultraviolet and visible quantitative analysis. The purpose is to render unnecessary the repetition of these descriptions of techniques in individual methods for quantitative analysis.
• ASTM E260-96, General Gas Chromatography Procedures (Approved April 10, 1996) is a general guide to the application of gas chromatography with packed columns for the separation and analysis of vaporizable or gaseous organic and inorganic mixtures and as a reference for the writing and reporting of gas chromatography methods.
• ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers measuring the oxygen or carbon dioxide content of the exhaust gas.
• EPA-600/R-12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards (Issued May 2012) is mandatory for certifying the calibration gases being used for the calibration and audit of ambient air quality analyzers and continuous emission monitors that are required by numerous parts of the CFR.
The EPA determined that the ASTM and ASME/ANSI standards, notwithstanding the age of the standards, are reasonably available because it they are available for purchase from the following addresses: American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959; or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016-5990. The EPA determined that the EPA standard is reasonably available because it is publically available through the EPA's Web site: http://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf .

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income, or indigenous populations. The EPA has determined this because the rulemaking increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income, or indigenous populations. The EPA has provided meaningful participation opportunities for minority, low-income, indigenous populations and tribes during the rulemaking process by conducting community calls and webinars. Documentation of these activities can be found in the public docket for this rulemaking.

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 is a “major rule” as defined by 5 U.S.C. 804(2).

List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping.
Dated: May 12, 2016.
Gina McCarthy,

Administrator.
For the reasons set out in the preamble, title 40, chapter I of the Code of Federal Regulations is amended as follows:

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
1. The authority citation for part 60 continues to read as follows:

Authority:
42 U.S.C. 4701, et seq.
2. Section 60.17 is amended by:
a. Revising paragraph (g)(14).
b. Revising paragraphs (h)(19), (75), (137), (167), (184), (193), (196), and (199).
c. Adding paragraph (j)(2).
The revisions and addition read as follows:
§ 60.17
Incorporations by reference.
* * * * *
(g) * * *
(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved for §§ 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), and (j), 60.105a(d), (f), and (g), § 60.106a(a), § 60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart FFFF, table 2 to subpart JJJJ, § 60.285a(f), §§ 60.4415(a), 60.2145(s) and (t), 60.2710(s), (t), and (w), 60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart MMMM, 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b) and 60.5413a(d).
* * * * *
(h) * * *
(19) ASTM D86-96, Distillation of Petroleum Products, (Approved April 10, 1996), IBR approved for §§ 60.562-2(d), 60.593(d), 60.593a(d), 60.633(h), 60.5401(f), 60.5401a(f).
* * * * *
(75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR approved for §§ 60.107a(d), 60.5413(d), 60.5413a(d).
* * * * *
(137) ASTM D3588-98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, (Approved May 10, 2003), IBR approved for §§ 60.107a(d), 60.5413(d), and 60.5413a(d).
* * * * *
(167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, (Approved June 1, 2006), IBR approved for §§ 60.107a(d), 60.5413(d), and 60.5413a(d).
* * * * *
(184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, (Approved October 1, 2005), IBR approved for table 2 to subpart JJJJ, §§ 60.5413(b) and (d), and 60.5413a(b).
* * * * *
(193) ASTM E168-92, General Techniques of Infrared Quantitative Analysis, IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400, 60.5400a(f).
* * * * *
(196) ASTM E169-93, General Techniques of Ultraviolet Quantitative Analysis, (Approved May 15, 1993), IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), and 60.5400a(f).
* * * * *
(199) ASTM E260-96, General Gas Chromatography Procedures, (Approved April 10, 1996), IBR approved for §§ 60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f) 60.5406(b), and 60.5406a(b)(3).
* * * * *
(j) * * *
(2) EPA-600/R-12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, May 2012, IBR approved for §§ 60.5413(d) and 60.5413a(d).
* * * * *
3. Part 60 is amended by revising the heading for Subpart OOOO to read as follows:

Subpart OOOO—Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution for which Construction, Modification or Reconstruction Commenced after August 23, 2011, and on or before September 18, 2015
4. Section 60.5360 is revised to read as follows:
§ 60.5360
What is the purpose of this subpart?
This subpart establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC) and sulfur dioxide (SO 2 ) emissions from affected facilities that commence construction, modification or reconstruction after August 23, 2011, and on or before September 18, 2015.
5. Section 60.5365 is amended by:
a. Revising the introductory text.
b. Revising paragraph (e)(4).
c. Adding paragraph (e)(5).
d. Revising paragraph (h)(4).
The revisions and addition read as follows:
§ 60.5365
Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the onshore affected facilities listed in paragraphs (a) through (g) of this section for which you commence construction, modification or reconstruction after August 23, 2011, and on or before September 18, 2015.
* * * * *
(e) * * *
(4) The following requirements apply immediately upon startup, startup of production, or return to service. A storage vessel affected facility that is reconnected to the original source of liquids is a storage vessel affected facility subject to the same requirements that applied before being removed from service. Any storage vessel that is used to replace any storage vessel affected facility is subject to the same requirements that apply to the storage vessel affected facility being replaced.
(5) A storage vessel with a capacity greater than 100,000 gallons used to recycle water that has been passed through two stage separation is not a storage vessel affected facility.
(h) * * *
(4) A gas well facility initially constructed after August 23, 2011, and on or before September 18, 2015 is considered an affected facility regardless of this provision.
6. Section 60.5370 is amended by revising paragraph (b) and adding paragraph (d) to read as follows:
§ 60.5370
When must I comply with this subpart?
* * * * *
(b) At all times, including periods of startup, shutdown, and malfunction, owners and operators shall maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.
* * * * *
(d) You are deemed to be in compliance with this subpart if you are in compliance with all applicable provisions of subpart OOOOa of this part.
§ 60.5410
[Amended]
7. Section 60.5410 is amended by removing and reserving paragraph (b)(6).
8. Section 60.5411 is amended by revising paragraphs (a)(3)(i)(A) and (c)(3)(i)(A) to read as follows:
§ 60.5411
What additional requirements must I meet to determine initial compliance for my covers and closed vent systems routing materials from storage vessels and centrifugal compressor wet seal degassing systems?
* * * * *
(a) * * *
(3) * * *
(i) * * *
(A) You must properly install, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere that is capable of taking periodic readings as specified in § 60.5416(a)(4) and either sounds an alarm, or initiates notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to § 60.5420(c)(8).
* * * * *
(c) * * *
(3) * * *
(i) * * *
(A) You must properly install, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere and that either sounds an alarm, or initiates notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to § 60.5420(c)(8).
* * * * *
9. Section 60.5412 is amended by:
a. Revising paragraphs (a)(1)(ii) and (d)(1) introductory text; and
b. Adding paragraph (d)(1)(iv).
The revisions and addition read as follows:
§ 60.5412
What additional requirements must I meet for determining initial compliance with control devices used to comply with the emission standards for my storage vessel or centrifugal compressor affected facility?
* * * * *
(a) * * *
(1) * * *
(ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 275 parts per million by volume as propane on a wet basis corrected to 3 percent oxygen as determined in accordance with the requirements of § 60.5413.
* * * * *
(d) * * *
(1) Each enclosed combustion device ( e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) must be designed to reduce the mass content of VOC emissions by 95.0 percent or greater. Each flare must be designed and operated in accordance with the requirements of § 60.5413(a)(1). You must follow the requirements in paragraphs (d)(1)(i) through (iv) of this section.
* * * * *
(iv) Each enclosed combustion control device ( e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) must be designed and operated in accordance with one of the performance requirements specified in paragraphs (d)(1)(iv)(A) through (D) of this section.
(A) You must reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of § 60.5413.
(B) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 275 parts per million by volume as propane on a wet basis corrected to 3 percent oxygen as determined in accordance with the requirements of § 60.5413.
(C) You must operate at a minimum temperature of 760 °Celsius, provided the control device has demonstrated, during the performance test conducted under § 60.5413, that combustion zone temperature is an indicator of destruction efficiency.
(D) If a boiler or process heater is used as the control device, then you must introduce the vent stream into the flame zone of the boiler or process heater.
* * * * *
10. Section 60.5413 is amended by revising paragraphs (d)(9)(iv) and (e)(3) to read as follows:
§ 60.5413
What are the performance testing procedures for control devices used to demonstrate compliance at my storage vessel or centrifugal compressor affected facility?
* * * * *
(d) * * *
(9) * * *
(iv) Calibration gases must be propane in air and be certified through EPA Protocol 1—“EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” (incorporated by reference as specified in § 60.17).
* * * * *
(e) * * *
(3) Devices must be operated with no visible emissions, except for periods not to exceed a total of 1 minute during any 15-minute period. A visible emissions test conducted according to section 11 of EPA Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, separated by at least 15 days between each test. The observation period shall be 15 minutes.
* * * * *
11. Section 60.5415 is amended by revising paragraphs (b)(2)(vii)(B) and (c)(4) to read as follows:
§ 60.5415
How do I demonstrate continuous compliance with the standards for my gas well affected facility, my centrifugal compressor affected facility, my stationary reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at onshore natural gas processing plants?
* * * * *
(b) * * *
(2) * * *
(vii) * * *
(B) Devices must be operated with no visible emissions, except for periods not to exceed a total of 1 minute during any 15-minute period. A visible emissions test conducted according to section 11 of Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, separated by at least 15 days between each test. The observation period shall be 15 minutes.
* * * * *
(c) * * *
(4) You must operate the rod packing emissions collection system under negative pressure and continuously comply with the closed vent requirements in § 60.5416(a) and (b).
* * * * *
12. Section 60.5416 is amended by revising paragraph (c)(3)(i) to read as follows:
§ 60.5416
What are the initial and continuous cover and closed vent system inspection and monitoring requirements for my storage vessel and centrifugal compressor affected facilities?
* * * * *
(c) * * *
(3) * * *
(i) You must properly install, calibrate and maintain a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere. Set the flow indicator to trigger an audible alarm, or initiate notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to § 60.5420(c)(8).
* * * * *
13. Section 60.5420 is amended by:
a. Revising paragraph (c) introductory text; and
b. Revising paragraph (c)(6); and
c. Adding paragraph (c)(14).
The revision and addition reads as follows:
§ 60.5420
What are my notification, reporting, and recordkeeping requirements?
* * * * *
(c) Recordkeeping requirements . You must maintain the records identified as specified in § 60.7(f) and in paragraphs (c)(1) through (14) of this section. All records required by this subpart must be maintained either onsite or at the nearest local field office for at least 5 years.
* * * * *
(6) Records of each closed vent system inspection required under § 60.5416(a)(1) and (2) for centrifugal or reciprocating compressors or § 60.5416(c)(1) for storage vessels.
* * * * *
(14) A log of records as specified in §§ 60.5412(d)(1)(iii) and 60.5413(e)(4) for all inspection, repair and maintenance activities for each control device failing the visible emissions test.
14. Section 60.5430 is amended by:
a. Adding, in alphabetical order, a definition for the term “capital expenditure;” and
b. Revising the definition for “group 2 storage vessel.”
The addition and revision read as follows:
§ 60.5430
What definitions apply to this subpart?
* * * * *
Capital expenditure means, in addition to the definition in 40 CFR 60.2, an expenditure for a physical or operational change to an existing facility that:
(1) Exceeds P, the product of the facility's replacement cost, R, and an adjusted annual asset guideline repair allowance, A, as reflected by the following equation: P = R × A, where
(i) The adjusted annual asset guideline repair allowance, A, is the product of the percent of the replacement cost, Y, and the applicable basic annual asset guideline repair allowance, B, divided by 100 as reflected by the following equation:
A = Y × (B ÷ 100);
(ii) The percent Y is determined from the following equation: Y = 1.0 − 0.575 log X, where X is 2011 minus the year of construction; and
(iii) The applicable basic annual asset guideline repair allowance, B, is 4.5.
(2) [Reserved]
* * * * *
Group 2 storage vessel means a storage vessel, as defined in this section, for which construction, modification or reconstruction has commenced after April 12, 2013, and on or before September 18, 2015.
* * * * *
15. Amend Table 3 to Subpart OOOO by revising entries “§ 60.15” and “§ 60.18” to read as follows:
Table 3 to Subpart OOOO of Part 60—Applicability of General Provisions to Subpart OOOO
General provisions citation | Subject of citation | Applies to subpart? | Explanation
* * * * * * *
§ 60.15 | Reconstruction | Yes | Except that § 60.15(d) does not apply to gas wells, pneumatic controllers, centrifugal compressors, reciprocating compressors or storage vessels.
* * * * * * *
§ 60.18 | General control device requirements | Yes | Except that the period of visible emissions shall not exceed a total of 1 minute during any 15-minute period instead of 5 minutes during any 2 consecutive hours as required in § 60.18(c).
* * * * * * *
16. Add subpart OOOOa, consisting of sections 60.5360a through 60.5499a, to part 60 to read as follows:

Subpart OOOOa—Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced after September 18, 2015
Sec.
60.5360a
What is the purpose of this subpart?
60.5365a
Am I subject to this subpart?
60.5370a
When must I comply with this subpart?
60.5375a
What GHG and VOC standards apply to well affected facilities?
60.5380a
What GHG and VOC standards apply to centrifugal compressor affected facilities?
60.5385a
What GHG and VOC standards apply to reciprocating compressor affected facilities?
60.5390a
What GHG and VOC standards apply to pneumatic controller affected facilities?
60.5393a
What GHG and VOC standards apply to pneumatic pump affected facilities?
60.5395a
What VOC standards apply to storage vessel affected facilities?
60.5397a
What fugitive emissions GHG and VOC standards apply to the affected facility which is the collection of fugitive emissions components at a well site and the affected facility which is the collection of fugitive emissions components at a compressor station?
60.5398a
What are the alternative means of emission limitations for GHG and VOC from well completions, reciprocating compressors, the collection of fugitive emissions components at a well site and the collection of fugitive emissions components at a compressor station?
60.5400a
What equipment leak GHG and VOC standards apply to affected facilities at an onshore natural gas processing plant?
60.5401a
What are the exceptions to the equipment leak GHG and VOC standards for affected facilities at onshore natural gas processing plants?
60.5402a
What are the alternative means of emission limitations for GHG and VOC equipment leaks from onshore natural gas processing plants?
60.5405a
What standards apply to sweetening unit affected facilities at onshore natural gas processing plants?
60.5406a
What test methods and procedures must I use for my sweetening unit affected facilities at onshore natural gas processing plants?
60.5407a
What are the requirements for monitoring of emissions and operations from my sweetening unit affected facilities at onshore natural gas processing plants?
60.5408a
What is an optional procedure for measuring hydrogen sulfide in acid gas—Tutwiler Procedure?
60.5410a
How do I demonstrate initial compliance with the standards for my well, centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump, storage vessel, collection of fugitive emissions components at a well site, and collection of fugitive emissions components at a compressor station, and equipment leaks and sweetening unit affected facilities at onshore natural gas processing plants?
60.5411a
What additional requirements must I meet to determine initial compliance for my covers and closed vent systems routing emissions from centrifugal compressor wet seal fluid degassing systems, reciprocating compressors, pneumatic pump and storage vessels?
60.5412a
What additional requirements must I meet for determining initial compliance with control devices used to comply with the emission standards for my centrifugal compressor, and storage vessel affected facilities?
60.5413a
What are the performance testing procedures for control devices used to demonstrate compliance at my centrifugal compressor, pneumatic pump and storage vessel affected facilities?
60.5415a
How do I demonstrate continuous compliance with the standards for my well, centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump, storage vessel, collection of fugitive emissions components at a well site, and collection of fugitive emissions components at a compressor station affected facilities, and affected facilities at onshore natural gas processing plants?
60.5416a
What are the initial and continuous cover and closed vent system inspection and monitoring requirements for my centrifugal compressor, reciprocating compressor, pneumatic pump, and storage vessel affected facilities?
60.5417a
What are the continuous control device monitoring requirements for my centrifugal compressor, pneumatic pump, and storage vessel affected facilities?
60.5420a
What are my notification, reporting, and recordkeeping requirements?
60.5421a
What are my additional recordkeeping requirements for my affected facility subject to GHG and VOC requirements for onshore natural gas processing plants?
60.5422a
What are my additional reporting requirements for my affected facility subject to GHG and VOC requirements for onshore natural gas processing plants?
60.5423a
What additional recordkeeping and reporting requirements apply to my sweetening unit affected facilities at onshore natural gas processing plants?
60.5425a
What parts of the General Provisions apply to me?
60.5430a
What definitions apply to this subpart?
60.5432a
How do I determine whether a well is a low pressure well using the low pressure well equation?
60.5433a—60.5499a
[Reserved]
Table 1 to Subpart OOOOa of Part 60
Required Minimum Initial SO 2 Emission Reduction Efficiency (Zi)
Table 2 to Subpart OOOOa of Part 60
Required Minimum SO 2 Emission Reduction Efficiency (Zc)
Table 3 to Subpart OOOOa of Part 60
Applicability of General Provisions to Subpart OOOOa

Subpart OOOOa—Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015
§ 60.5360a
What is the purpose of this subpart?
(a) This subpart establishes emission standards and compliance schedules for the control of the pollutant greenhouse gases (GHG). The greenhouse gas standard in this subpart is in the form of a limitation on emissions of methane from affected facilities in the crude oil and natural gas source category that commence construction, modification, or reconstruction after September 18, 2015. This subpart also establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC) and sulfur dioxide (SO 2 ) emissions from affected facilities in the crude oil and natural gas source category that commence construction, modification or reconstruction after September 18, 2015. The effective date of the rule is August 2, 2016.
(b) Prevention of Significant Deterioration (PSD) and title V thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
§ 60.5365a
Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the onshore affected facilities listed in paragraphs (a) through (j) of this section for which you commence construction, modification, or reconstruction after September 18, 2015.
(a) Each well affected facility, which is a single well that conducts a well completion operation following hydraulic fracturing or refracturing. The provisions of this paragraph do not affect the affected facility status of well sites for the purposes of § 60.5397a. The provisions of paragraphs (a)(1) through (4) of this section apply to wells that are hydraulically refractured: (1) A well that conducts a well completion operation following hydraulic refracturing is not an affected facility, provided that the requirements of § 60.5375a(a)(1) through (4) are met. However, hydraulic refracturing of a well constitutes a modification of the well site for purposes of paragraph (i)(3)(iii) of this section, regardless of affected facility status of the well itself.
(2) A well completion operation following hydraulic refracturing not conducted pursuant to § 60.5375a(a)(1) through (4) is a modification to the well.
(3) Except as provided in § 60.5365a(i)(3)(iii), refracturing of a well, by itself, does not affect the modification status of other equipment, process units, storage vessels, compressors, pneumatic pumps, or pneumatic controllers.
(4) A well initially constructed after September 18, 2015, that conducts a well completion operation following hydraulic refracturing is considered an affected facility regardless of this provision.
(b) Each centrifugal compressor affected facility, which is a single centrifugal compressor using wet seals. A centrifugal compressor located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility under this subpart.
(c) Each reciprocating compressor affected facility, which is a single reciprocating compressor. A reciprocating compressor located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility under this subpart.
(d) Each pneumatic controller affected facility:
(1) Each pneumatic controller affected facility not located at a natural gas processing plant, which is a single continuous bleed natural gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 scfh.
(2) Each pneumatic controller affected facility located at a natural gas processing plant, which is a single continuous bleed natural gas-driven pneumatic controller.
(e) Each storage vessel affected facility, which is a single storage vessel with the potential for VOC emissions equal to or greater than 6 tpy as determined according to this section. The potential for VOC emissions must be calculated using a generally accepted model or calculation methodology, based on the maximum average daily throughput determined for a 30-day period of production prior to the applicable emission determination deadline specified in this subsection. The determination may take into account requirements under a legally and practically enforceable limit in an operating permit or other requirement established under a federal, state, local or tribal authority.
(1) For each new, modified or reconstructed storage vessel you must determine the potential for VOC emissions within 30 days after liquids first enter the storage vessel, except as provided in paragraph (e)(3)(iv) of this section. For each new, modified or reconstructed storage vessel receiving liquids pursuant to the standards for well affected facilities in § 60.5375a, including wells subject to § 60.5375a(f), you must determine the potential for VOC emissions within 30 days after startup of production of the well.
(2) A storage vessel affected facility that subsequently has its potential for VOC emissions decrease to less than 6 tpy shall remain an affected facility under this subpart.
(3) For storage vessels not subject to a legally and practically enforceable limit in an operating permit or other requirement established under federal, state, local or tribal authority, any vapor from the storage vessel that is recovered and routed to a process through a VRU designed and operated as specified in this section is not required to be included in the determination of VOC potential to emit for purposes of determining affected facility status, provided you comply with the requirements in paragraphs (e)(3)(i) through (iv) of this section.
(i) You meet the cover requirements specified in § 60.5411a(b).
(ii) You meet the closed vent system requirements specified in § 60.5411a(c) and (d).
(iii) You must maintain records that document compliance with paragraphs (e)(3)(i) and (ii) of this section.
(iv) In the event of removal of apparatus that recovers and routes vapor to a process, or operation that is inconsistent with the conditions specified in paragraphs (e)(3)(i) and (ii) of this section, you must determine the storage vessel's potential for VOC emissions according to this section within 30 days of such removal or operation.
(4) The following requirements apply immediately upon startup, startup of production, or return to service. A storage vessel affected facility that is reconnected to the original source of liquids is a storage vessel affected facility subject to the same requirements that applied before being removed from service. Any storage vessel that is used to replace any storage vessel affected facility is subject to the same requirements that apply to the storage vessel affected facility being replaced.
(5) A storage vessel with a capacity greater than 100,000 gallons used to recycle water that has been passed through two stage separation is not a storage vessel affected facility.
(f) The group of all equipment within a process unit is an affected facility.
(1) Addition or replacement of equipment for the purpose of process improvement that is accomplished without a capital expenditure shall not by itself be considered a modification under this subpart.
(2) Equipment associated with a compressor station, dehydration unit, sweetening unit, underground storage vessel, field gas gathering system, or liquefied natural gas unit is covered by §§ 60.5400a, 60.5401a, 60.5402a, 60.5421a, and 60.5422a if it is located at an onshore natural gas processing plant. Equipment not located at the onshore natural gas processing plant site is exempt from the provisions of §§ 60.5400a, 60.5401a, 60.5402a, 60.5421a, and 60.5422a.
(3) The equipment within a process unit of an affected facility located at onshore natural gas processing plants and described in paragraph (f) of this section are exempt from this subpart if they are subject to and controlled according to subparts VVa, GGG, or GGGa of this part.
(g) Sweetening units located at onshore natural gas processing plants that process natural gas produced from either onshore or offshore wells.
(1) Each sweetening unit that processes natural gas is an affected facility; and
(2) Each sweetening unit that processes natural gas followed by a sulfur recovery unit is an affected facility.
(3) Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H 2 S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in § 60.5423a(c) but are not required to comply with §§ 60.5405a through 60.5407a and §§ 60.5410a(g) and 60.5415a(g).
(4) Sweetening facilities producing acid gas that is completely re-injected into oil-or-gas-bearing geologic strata or that is otherwise not released to the atmosphere are not subject to §§ 60.5405a through 60.5407a, 60.5410a(g), 60.5415a(g), and 60.5423a.
(h) Each pneumatic pump affected facility:
(1) For natural gas processing plants, each pneumatic pump affected facility, which is a single natural gas-driven diaphragm pump.
(2) For well sites, each pneumatic pump affected facility, which is a single natural gas-driven diaphragm pump. A single natural gas-driven diaphragm pump that is in operation less than 90 days per calendar year is not an affected facility under this subpart provided the owner/operator keeps records of the days of operation each calendar year and submits such records to the EPA Administrator (or delegated enforcement authority) upon request. For the purposes of this section, any period of operation during a calendar day counts toward the 90 calendar day threshold.
(i) Except as provided in § 60.5365a(i)(2), the collection of fugitive emissions components at a well site, as defined in § 60.5430a, is an affected facility.
(1) [Reserved]
(2) A well site that only contains one or more wellheads is not an affected facility under this subpart. The affected facility status of a separate tank battery surface site has no effect on the affected facility status of a well site that only contains one or more wellheads.
(3) For purposes of § 60.5397a, a “modification” to a well site occurs when:
(i) A new well is drilled at an existing well site;
(ii) A well at an existing well site is hydraulically fractured; or
(iii) A well at an existing well site is hydraulically refractured.
(j) The collection of fugitive emissions components at a compressor station, as defined in § 60.5430a, is an affected facility. For purposes of § 60.5397a, a “modification” to a compressor station occurs when:
(1) An additional compressor is installed at a compressor station; or
(2) One or more compressors at a compressor station is replaced by one or more compressors of greater total horsepower than the compressor(s) being replaced. When one or more compressors is replaced by one or more compressors of an equal or smaller total horsepower than the compressor(s) being replaced, installation of the replacement compressor(s) does not trigger a modification of the compressor station for purposes of § 60.5397a.
§ 60.5370a
When must I comply with this subpart?
(a) You must be in compliance with the standards of this subpart no later than August 2, 2016 or upon startup, whichever is later.
(b) At all times, including periods of startup, shutdown, and malfunction, owners and operators shall maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. The provisions for exemption from compliance during periods of startup, shutdown and malfunctions provided for in 40 CFR 60.8(c) do not apply to this subpart.
(c) You are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart.
§ 60.5375a
What GHG and VOC standards apply to well affected facilities?
If you are the owner or operator of a well affected facility as described in § 60.5365a(a) that also meets the criteria for a well affected facility in § 60.5365(a) of subpart OOOO of this part, you must reduce GHG (in the form of a limitation on emissions of methane) and VOC emissions by complying with paragraphs (a) through (g) of this section. If you own or operate a well affected facility as described in § 60.5365a(a) that does not meet the criteria for a well affected facility in § 60.5365(a) of subpart OOOO of this part, you must reduce GHG and VOC emissions by complying with paragraphs (f)(3), (f)(4) or (g) for each well completion operation with hydraulic fracturing prior to November 30, 2016, and you must comply with paragraphs (a) through (g) of this section for each well completion operation with hydraulic fracturing on or after November 30, 2016.
(a) Except as provided in paragraph (f) and (g) of this section, for each well completion operation with hydraulic fracturing you must comply with the requirements in paragraphs (a)(1) through (4) of this section. You must maintain a log as specified in paragraph (b) of this section.
(1) For each stage of the well completion operation, as defined in § 60.5430a, follow the requirements specified in paragraphs (a)(1)(i) through (iii) of this section.
(i) During the initial flowback stage, route the flowback into one or more well completion vessels or storage vessels and commence operation of a separator unless it is technically infeasible for a separator to function. Any gas present in the initial flowback stage is not subject to control under this section.
(ii) During the separation flowback stage, route all recovered liquids from the separator to one or more well completion vessels or storage vessels, re-inject the recovered liquids into the well or another well, or route the recovered liquids to a collection system. Route the recovered gas from the separator into a gas flow line or collection system, re-inject the recovered gas into the well or another well, use the recovered gas as an onsite fuel source, or use the recovered gas for another useful purpose that a purchased fuel or raw material would serve. If it is technically infeasible to route the recovered gas as required above, follow the requirements in paragraph (a)(3) of this section. If, at any time during the separation flowback stage, it is technically infeasible for a separator to function, you must comply with paragraph (a)(1)(i) of this section.
(iii) You must have a separator onsite during the entirety of the flowback period, except as provided in paragraphs (a)(1)(iii)(A) through (C) of this section.
(A) A well that is not hydraulically fractured or refractured with liquids, or that does not generate condensate, intermediate hydrocarbon liquids, or produced water such that there is no liquid collection system at the well site is not required to have a separator onsite.
(B) If conditions allow for liquid collection, then the operator must immediately stop the well completion operation, install a separator, and restart the well completion operation in accordance with § 60.5375a(a)(1).
(C) The owner or operator of a well that meets the criteria of paragraph (a)(1)(iii)(A) or (B) of this section must submit the report in § 60.5420a(b)(2) and maintain the records in § 60.5420a(c)(1)(iii).
(2) [Reserved]
(3) If it is technically infeasible to route the recovered gas as required in § 60.5375a(a)(1)(ii), then you must capture and direct recovered gas to a completion combustion device, except in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways. Completion combustion devices must be equipped with a reliable continuous pilot flame.
(4) You have a general duty to safely maximize resource recovery and minimize releases to the atmosphere during flowback and subsequent recovery.
(b) You must maintain a log for each well completion operation at each well affected facility. The log must be completed on a daily basis for the duration of the well completion operation and must contain the records specified in § 60.5420a(c)(1)(iii).
(c) You must demonstrate initial compliance with the standards that apply to well affected facilities as required by § 60.5410a(a).
(d) You must demonstrate continuous compliance with the standards that apply to well affected facilities as required by § 60.5415a(a).
(e) You must perform the required notification, recordkeeping and reporting as required by § 60.5420a(a)(2), (b)(1) and (2), and (c)(1).
(f) For each well affected facility specified in paragraphs (f)(1) and (2) of this section, you must comply with the requirements of paragraphs (f)(3) and (4) of this section.
(1) Each well completion operation with hydraulic fracturing at a wildcat or delineation well.
(2) Each well completion operation with hydraulic fracturing at a non-wildcat low pressure well or non-delineation low pressure well.
(3) You must comply with either paragraph (f)(3)(i) or (f)(3)(ii) of this section, unless you meet the requirements in paragraph (g) of this section. You must also comply with paragraph (b) of this section.
(i) Route all flowback to a completion combustion device, except in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways. Completion combustion devices must be equipped with a reliable continuous pilot flame.
(ii) Route all flowback into one or more well completion vessels and commence operation of a separator unless it is technically infeasible for a separator to function. Any gas present in the flowback before the separator can function is not subject to control under this section. Capture and direct recovered gas to a completion combustion device, except in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways. Completion combustion devices must be equipped with a reliable continuous pilot flame. (4) You must submit the notification as specified in § 60.5420a(a)(2), submit annual reports as specified in § 60.5420a(b)(1) and (2) and maintain records specified in § 60.5420a(c)(1)(iii) for each wildcat and delineation well. You must submit the notification as specified in § 60.5420a(a)(2), submit annual reports as specified in § 60.5420a(b)(1) and (2), and maintain records as specified in § 60.5420a(c)(1)(iii) and (vii) for each low pressure well.
(g) For each well affected facility with less than 300 scf of gas per stock tank barrel of oil produced, you must comply with paragraphs (g)(1) and (2) of this section.
(1) You must maintain records specified in § 60.5420a(c)(1)(vi).
(2) You must submit reports specified in § 60.5420a(b)(1) and (2).
§ 60.5380a
What GHG and VOC standards apply to centrifugal compressor affected facilities?
You must comply with the GHG and VOC standards in paragraphs (a) through (d) of this section for each centrifugal compressor affected facility.
(a)(1) You must reduce methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95.0 percent.
(2) If you use a control device to reduce emissions, you must equip the wet seal fluid degassing system with a cover that meets the requirements of § 60.5411a(b). The cover must be connected through a closed vent system that meets the requirements of § 60.5411a(a) and (d) and the closed vent system must be routed to a control device that meets the conditions specified in § 60.5412a(a), (b) and (c). As an alternative to routing the closed vent system to a control device, you may route the closed vent system to a process.
(b) You must demonstrate initial compliance with the standards that apply to centrifugal compressor affected facilities as required by § 60.5410a(b).
(c) You must demonstrate continuous compliance with the standards that apply to centrifugal compressor affected facilities as required by § 60.5415a(b).
(d) You must perform the reporting as required by § 60.5420a(b)(1) and (3), and the recordkeeping as required by § 60.5420a(c)(2), (6) through (11), and (17), as applicable.
§ 60.5385a
What GHG and VOC standards apply to reciprocating compressor affected facilities?
You must reduce GHG (in the form of a limitation on emissions of methane) and VOC emissions by complying with the standards in paragraphs (a) through (d) of this section for each reciprocating compressor affected facility.
(a) You must replace the reciprocating compressor rod packing according to either paragraph (a)(1) or (2) of this section, or you must comply with paragraph (a)(3) of this section.
(1) On or before the compressor has operated for 26,000 hours. The number of hours of operation must be continuously monitored beginning upon initial startup of your reciprocating compressor affected facility, or the date of the most recent reciprocating compressor rod packing replacement, whichever is later.
(2) Prior to 36 months from the date of the most recent rod packing replacement, or 36 months from the date of startup for a new reciprocating compressor for which the rod packing has not yet been replaced.
(3) Collect the methane and VOC emissions from the rod packing using a rod packing emissions collection system that operates under negative pressure and route the rod packing emissions to a process through a closed vent system that meets the requirements of § 60.5411a(a) and (d).
(b) You must demonstrate initial compliance with standards that apply to reciprocating compressor affected facilities as required by § 60.5410a(c).
(c) You must demonstrate continuous compliance with standards that apply to reciprocating compressor affected facilities as required by § 60.5415a(c).
(d) You must perform the reporting as required by § 60.5420a(b)(1) and (4) and the recordkeeping as required by § 60.5420a(c)(3), (6) through (9), and (17), as applicable.
§ 60.5390a
What GHG and VOC standards apply to pneumatic controller affected facilities?
For each pneumatic controller affected facility you must comply with the GHG and VOC standards, based on natural gas as a surrogate for GHG and VOC, in either paragraph (b)(1) or (c)(1) of this section, as applicable. Pneumatic controllers meeting the conditions in paragraph (a) of this section are exempt from this requirement.
(a) The requirements of paragraph (b)(1) or (c)(1) of this section are not required if you determine that the use of a pneumatic controller affected facility with a bleed rate greater than the applicable standard is required based on functional needs, including but not limited to response time, safety and positive actuation. However, you must tag such pneumatic controller with the month and year of installation, reconstruction or modification, and identification information that allows traceability to the records for that pneumatic controller, as required in § 60.5420a(c)(4)(ii).
(b)(1) Each pneumatic controller affected facility at a natural gas processing plant must have a bleed rate of zero.
(2) Each pneumatic controller affected facility at a natural gas processing plant must be tagged with the month and year of installation, reconstruction or modification, and identification information that allows traceability to the records for that pneumatic controller as required in § 60.5420a(c)(4)(iv).
(c)(1) Each pneumatic controller affected facility at a location other than at a natural gas processing plant must have a bleed rate less than or equal to 6 standard cubic feet per hour.
(2) Each pneumatic controller affected facility at a location other than at a natural gas processing plant must be tagged with the month and year of installation, reconstruction or modification, and identification information that allows traceability to the records for that controller as required in § 60.5420a(c)(4)(iii).
(d) You must demonstrate initial compliance with standards that apply to pneumatic controller affected facilities as required by § 60.5410a(d).
(e) You must demonstrate continuous compliance with standards that apply to pneumatic controller affected facilities as required by § 60.5415a(d).
(f) You must perform the reporting as required by § 60.5420a(b)(1) and (5) and the recordkeeping as required by § 60.5420a(c)(4).
§ 60.5393a
What GHG and VOC standards apply to pneumatic pump affected facilities?
For each pneumatic pump affected facility you must comply with the GHG and VOC standards, based on natural gas as a surrogate for GHG and VOC, in either paragraph (a) or (b) of this section, as applicable, on or after November 30, 2016.
(a) Each pneumatic pump affected facility at a natural gas processing plant must have a natural gas emission rate of zero.
(b) For each pneumatic pump affected facility at a well site you must comply with paragraph (b)(1) or (2) of this section.
(1) If the pneumatic pump affected facility is located at a greenfield site as defined in § 60.5430a, you must reduce natural gas emissions by 95.0 percent, except as provided in paragraphs (b)(3) and (4) of this section.
(2) If the pneumatic pump affected facility is not located at a greenfield site as defined in § 60.5430a, you must reduce natural gas emissions by 95.0 percent, except as provided in paragraphs (b)(3), (4) and (5) of this section.
(3) You are not required to install a control device solely for the purpose of complying with the 95.0 percent reduction requirement of paragraph (b)(1) or (b)(2) of this section. If you do not have a control device installed on site by the compliance date and you do not have the ability to route to a process, then you must comply instead with the provisions of paragraphs (b)(3)(i) and (ii) of this section.
(i) Submit a certification in accordance with § 60.5420a(b)(8)(i)(A) in your next annual report, certifying that there is no available control device or process on site and maintain the records in § 60.5420a(c)(16)(i) and (ii).
(ii) If you subsequently install a control device or have the ability to route to a process, you are no longer required to comply with paragraph (b)(2)(i) of this section and must submit the information in § 60.5420a(b)(8)(ii) in your next annual report and maintain the records in § 60.5420a(c)(16)(i), (ii), and (iii). You must be in compliance with the requirements of paragraph (b)(2) of this section within 30 days of startup of the control device or within 30 days of the ability to route to a process.
(4) If the control device available on site is unable to achieve a 95 percent reduction and there is no ability to route the emissions to a process, you must still route the pneumatic pump affected facility's emissions to that existing control device. If you route the pneumatic pump affected facility to a control device installed on site that is designed to achieve less than a 95 percent reduction, you must submit the information specified in § 60.5420a(b)(8)(i)(C) in your next annual report and maintain the records in § 60.5420a(c)(16)(iii).
(5) If an owner or operator at a non-greenfield site determines, through an engineering assessment, that routing a pneumatic pump to a control device or a process is technically infeasible, the requirements specified in paragraph (b)(5)(i) through (iv) of this section must be met.
(i) The owner or operator shall conduct the assessment of technical infeasibility in accordance with the criteria in paragraph (b)(5)(iii) of this section and have it certified by a qualified professional engineer in accordance with paragraph (b)(5)(ii) of this section.
(ii) The following certification, signed and dated by the qualified professional engineer shall state: “I certify that the assessment of technical infeasibility was prepared under my direction or supervision. I further certify that the assessment was conducted and this report was prepared pursuant to the requirements of § 60.5393a(b)(5)(iii). Based on my professional knowledge and experience, and inquiry of personnel involved in the assessment, the certification submitted herein is true, accurate, and complete. I am aware that there are penalties for knowingly submitting false information.”
(iii) The assessment of technical feasibility to route emissions from the pneumatic pump to an existing control device onsite or to a process shall include, but is not limited to, safety considerations, distance from the control device, pressure losses and differentials in the closed vent system and the ability of the control device to handle the pneumatic pump emissions which are routed to them. The assessment of technical infeasibility shall be prepared under the direction or supervision of the qualified professional engineer who signs the certification in accordance with paragraph (b)(2)(ii) of this section.
(iv) The owner or operator shall maintain the records § 60.5420a(c)(16)(iv).
(6) If the pneumatic pump is routed to a control device or a process and the control device or process is subsequently removed from the location or is no longer available, you are no longer required to be in compliance with the requirements of paragraph (b)(1) or (b)(2) of this section, and instead must comply with paragraph (b)(3) of this section and report the change in next annual report in accordance with § 60.5420a(b)(8)(ii).
(c) If you use a control device or route to a process to reduce emissions, you must connect the pneumatic pump affected facility through a closed vent system that meets the requirements of § 60.5411a(a) and (d).
(d) You must demonstrate initial compliance with standards that apply to pneumatic pump affected facilities as required by § 60.5410a(e).
(e) You must perform the reporting as required by § 60.5420a(b)(1) and (8) and the recordkeeping as required by § 60.5420a(c)(6) through (10), (16), and (17), as applicable.
§ 60.5395a
What VOC standards apply to storage vessel affected facilities?
Except as provided in paragraph (e) of this section, you must comply with the VOC standards in this section for each storage vessel affected facility.
(a) You must comply with the requirements of paragraphs (a)(1) and (2) of this section. After 12 consecutive months of compliance with paragraph (a)(2) of this section, you may continue to comply with paragraph (a)(2) of this section, or you may comply with paragraph (a)(3) of this section, if applicable. If you choose to meet the requirements in paragraph (a)(3) of this section, you are not required to comply with the requirements of paragraph (a)(2) of this section except as provided in paragraphs (a)(3)(i) and (ii) of this section.
(1) Determine the potential for VOC emissions in accordance with § 60.5365a(e).
(2) Reduce VOC emissions by 95.0 percent within 60 days after startup. For storage vessel affected facilities receiving liquids pursuant to the standards for well affected facilities in § 60.5375a(a)(1)(i) or (ii), you must achieve the required emissions reductions within 60 days after startup of production as defined in § 60.5430a.
(3) Maintain the uncontrolled actual VOC emissions from the storage vessel affected facility at less than 4 tpy without considering control. Prior to using the uncontrolled actual VOC emission rate for compliance purposes, you must demonstrate that the uncontrolled actual VOC emissions have remained less than 4 tpy as determined monthly for 12 consecutive months. After such demonstration, you must determine the uncontrolled actual VOC emission rate each month. The uncontrolled actual VOC emissions must be calculated using a generally accepted model or calculation methodology, and the calculations must be based on the average throughput for the month. You may no longer comply with this paragraph and must instead comply with paragraph (a)(2) of this section if your storage vessel affected facility meets the conditions specified in paragraphs (a)(3)(i) or (ii) of this section.
(i) If a well feeding the storage vessel affected facility undergoes fracturing or refracturing, you must comply with paragraph (a)(2) of this section as soon as liquids from the well following fracturing or refracturing are routed to the storage vessel affected facility.
(ii) If the monthly emissions determination required in this section indicates that VOC emissions from your storage vessel affected facility increase to 4 tpy or greater and the increase is not associated with fracturing or refracturing of a well feeding the storage vessel affected facility, you must comply with paragraph (a)(2) of this section within 30 days of the monthly determination.
(b) Control requirements. (1) Except as required in paragraph (b)(2) of this section, if you use a control device to reduce VOC emissions from your storage vessel affected facility, you must equip the storage vessel with a cover that meets the requirements of § 60.5411a(b) and is connected through a closed vent system that meets the requirements of § 60.5411a(c) and (d), and you must route emissions to a control device that meets the conditions specified in § 60.5412a(c) or (d). As an alternative to routing the closed vent system to a control device, you may route the closed vent system to a process.
(2) If you use a floating roof to reduce emissions, you must meet the requirements of § 60.112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting requirements in 40 CFR part 60, subpart Kb.
(c) Requirements for storage vessel affected facilities that are removed from service or returned to service. If you remove a storage vessel affected facility from service, you must comply with paragraphs (c)(1) through (3) of this section. A storage vessel is not an affected facility under this subpart for the period that it is removed from service.
(1) For a storage vessel affected facility to be removed from service, you must comply with the requirements of paragraphs (c)(1)(i) and (ii) of this section.
(i) You must completely empty and degas the storage vessel, such that the storage vessel no longer contains crude oil, condensate, produced water or intermediate hydrocarbon liquids. A storage vessel where liquid is left on walls, as bottom clingage or in pools due to floor irregularity is considered to be completely empty.
(ii) You must submit a notification as required in § 60.5420a(b)(6)(v) in your next annual report, identifying each storage vessel affected facility removed from service during the reporting period and the date of its removal from service.
(2) If a storage vessel identified in paragraph (c)(1)(ii) of this section is returned to service, you must determine its affected facility status as provided in § 60.5365a(e).
(3) For each storage vessel affected facility returned to service during the reporting period, you must submit a notification in your next annual report as required in § 60.5420a(b)(6)(vi), identifying each storage vessel affected facility and the date of its return to service.
(d) Compliance, notification, recordkeeping, and reporting. You must comply with paragraphs (d)(1) through (3) of this section.
(1) You must demonstrate initial compliance with standards as required by § 60.5410a(h) and (i).
(2) You must demonstrate continuous compliance with standards as required by § 60.5415a(e)(3).
(3) You must perform the required reporting as required by § 60.5420a(b)(1) and (6) and the recordkeeping as required by § 60.5420a(c)(5) through (8), (12) through (14), and (17), as applicable.
(e) Exemptions. This subpart does not apply to storage vessels subject to and controlled in accordance with the requirements for storage vessels in 40 CFR part 60, subpart Kb, and 40 CFR part 63, subparts G, CC, HH, or WW.
§ 60.5397a
What fugitive emissions GHG and VOC standards apply to the affected facility which is the collection of fugitive emissions components at a well site and the affected facility which is the collection of fugitive emissions components at a compressor station?
For each affected facility under § 60.5365a(i) and (j), you must reduce GHG (in the form of a limitation on emissions of methane) and VOC emissions by complying with the requirements of paragraphs (a) through (j) of this section. These requirements are independent of the closed vent system and cover requirements in § 60.5411a.
(a) You must monitor all fugitive emission components, as defined in § 60.5430a, in accordance with paragraphs (b) through (g) of this section. You must repair all sources of fugitive emissions in accordance with paragraph (h) of this section. You must keep records in accordance with paragraph (i) of this section and report in accordance with paragraph (j) of this section. For purposes of this section, fugitive emissions are defined as: Any visible emission from a fugitive emissions component observed using optical gas imaging or an instrument reading of 500 ppm or greater using Method 21.
(b) You must develop an emissions monitoring plan that covers the collection of fugitive emissions components at well sites and compressor stations within each company-defined area in accordance with paragraphs (c) and (d) of this section.
(c) Fugitive emissions monitoring plans must include the elements specified in paragraphs (c)(1) through (8) of this section, at a minimum.
(1) Frequency for conducting surveys. Surveys must be conducted at least as frequently as required by paragraphs (f) and (g) of this section.
(2) Technique for determining fugitive emissions ( i.e., Method 21 at 40 CFR part 60, appendix A-7, or optical gas imaging).
(3) Manufacturer and model number of fugitive emissions detection equipment to be used.
(4) Procedures and timeframes for identifying and repairing fugitive emissions components from which fugitive emissions are detected, including timeframes for fugitive emission components that are unsafe to repair. Your repair schedule must meet the requirements of paragraph (h) of this section at a minimum.
(5) Procedures and timeframes for verifying fugitive emission component repairs.
(6) Records that will be kept and the length of time records will be kept.
(7) If you are using optical gas imaging, your plan must also include the elements specified in paragraphs (c)(7)(i) through (vii) of this section.
(i) Verification that your optical gas imaging equipment meets the specifications of paragraphs (c)(7)(i)(A) and (B) of this section. This verification is an initial verification and may either be performed by the facility, by the manufacturer, or by a third party. For the purposes of complying with the fugitives emissions monitoring program with optical gas imaging, a fugitive emission is defined as any visible emissions observed using optical gas imaging.
(A) Your optical gas imaging equipment must be capable of imaging gases in the spectral range for the compound of highest concentration in the potential fugitive emissions.
(B) Your optical gas imaging equipment must be capable of imaging a gas that is half methane, half propane at a concentration of 10,000 ppm at a flow rate of ≤60g/hr from a quarter inch diameter orifice.
(ii) Procedure for a daily verification check.
(iii) Procedure for determining the operator's maximum viewing distance from the equipment and how the operator will ensure that this distance is maintained.
(iv) Procedure for determining maximum wind speed during which monitoring can be performed and how the operator will ensure monitoring occurs only at wind speeds below this threshold.
(v) Procedures for conducting surveys, including the items specified in paragraphs (c)(7)(v)(A) through (C) of this section.
(A) How the operator will ensure an adequate thermal background is present in order to view potential fugitive emissions.
(B) How the operator will deal with adverse monitoring conditions, such as wind.
(C) How the operator will deal with interferences (e.g., steam).
(vi) Training and experience needed prior to performing surveys.
(vii) Procedures for calibration and maintenance. At a minimum, procedures must comply with those recommended by the manufacturer.
(8) If you are using Method 21 of appendix A-7 of this part, your plan must also include the elements specified in paragraphs (c)(8)(i) and (ii) of this section. For the purposes of complying with the fugitive emissions monitoring program using Method 21 a fugitive emission is defined as an instrument reading of 500 ppm or greater.
(i) Verification that your monitoring equipment meets the requirements specified in Section 6.0 of Method 21 at 40 CFR part 60, appendix A-7. For purposes of instrument capability, the fugitive emissions definition shall be 500 ppm or greater methane using a FID-based instrument. If you wish to use an analyzer other than a FID-based instrument, you must develop a site-specific fugitive emission definition that would be equivalent to 500 ppm methane using a FID-based instrument ( e.g., 10.6 eV PID with a specified isobutylene concentration as the fugitive emission definition would provide equivalent response to your compound of interest).
(ii) Procedures for conducting surveys. At a minimum, the procedures shall ensure that the surveys comply with the relevant sections of Method 21 at 40 CFR part 60, appendix A-7, including Section 8.3.1.
(d) Each fugitive emissions monitoring plan must include the elements specified in paragraphs (d)(1) through (4) of this section, at a minimum, as applicable.
(1) Sitemap.
(2) A defined observation path that ensures that all fugitive emissions components are within sight of the path. The observation path must account for interferences.
(3) If you are using Method 21, your plan must also include a list of fugitive emissions components to be monitored and method for determining location of fugitive emissions components to be monitored in the field ( e.g. tagging, identification on a process and instrumentation diagram, etc.).
(4) Your plan must also include the written plan developed for all of the fugitive emission components designated as difficult-to-monitor in accordance with paragraph (g)(3)(i) of this section, and the written plan for fugitive emission components designated as unsafe-to-monitor in accordance with paragraph (g)(3)(ii) of this section.
(e) Each monitoring survey shall observe each fugitive emissions component, as defined in § 60.5430a, for fugitive emissions.
(f)(1) You must conduct an initial monitoring survey within 60 days of the startup of production, as defined in § 60.5430a, for each collection of fugitive emissions components at a new well site or by June 3, 2017, whichever is later. For a modified collection of fugitive emissions components at a well site, the initial monitoring survey must be conducted within 60 days of the first day of production for each collection of fugitive emission components after the modification or by June 3, 2017, whichever is later.
(2) You must conduct an initial monitoring survey within 60 days of the startup of a new compressor station for each new collection of fugitive emissions components at the new compressor station or by June 3, 2017, whichever is later. For a modified collection of fugitive components at a compressor station, the initial monitoring survey must be conducted within 60 days of the modification or by June 3, 2017, whichever is later.
(g) A monitoring survey of each collection of fugitive emissions components at a well site or at a compressor station must be performed at the frequencies specified in paragraphs (g)(1) and (2) of this section, with the exceptions noted in paragraphs (g)(3) and (4) of this section.
(1) A monitoring survey of each collection of fugitive emissions components at a well site within a company-defined area must be conducted at least semiannually after the initial survey. Consecutive semiannual monitoring surveys must be conducted at least 4 months apart.
(2) A monitoring survey of the collection of fugitive emissions components at a compressor station within a company-defined area must be conducted at least quarterly after the initial survey. Consecutive quarterly monitoring surveys must be conducted at least 60 days apart.
(3) Fugitive emissions components that cannot be monitored without elevating the monitoring personnel more than 2 meters above the surface may be designated as difficult-to-monitor. Fugitive emissions components that are designated difficult-to-monitor must meet the specifications of paragraphs (g)(3)(i) through (iv) of this section.
(i) A written plan must be developed for all of the fugitive emissions components designated difficult-to-monitor. This written plan must be incorporated into the fugitive emissions monitoring plan required by paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each fugitive emissions component designated as difficult-to-monitor.
(iii) The plan must include an explanation of why each fugitive emissions component designated as difficult-to-monitor is difficult-to-monitor.
(iv) The plan must include a schedule for monitoring the difficult-to-monitor fugitive emissions components at least once per calendar year.
(4) Fugitive emissions components that cannot be monitored because monitoring personnel would be exposed to immediate danger while conducting a monitoring survey may be designated as unsafe-to-monitor. Fugitive emissions components that are designated unsafe-to-monitor must meet the specifications of paragraphs (g)(4)(i) through (iv) of this section.
(i) A written plan must be developed for all of the fugitive emissions components designated unsafe-to-monitor. This written plan must be incorporated into the fugitive emissions monitoring plan required by paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each fugitive emissions component designated as unsafe-to-monitor.
(iii) The plan must include an explanation of why each fugitive emissions component designated as unsafe-to-monitor is unsafe-to-monitor.
(iv) The plan must include a schedule for monitoring the fugitive emissions components designated as unsafe-to-monitor.
(5) The requirements of paragraph (g)(2) of this section are waived for any collection of fugitive emissions components at a compressor station located within an area that has an average calendar month temperature below 0 °Fahrenheit for two of three consecutive calendar months of a quarterly monitoring period. The calendar month temperature average for each month within the quarterly monitoring period must be determined using historical monthly average temperatures over the previous three years as reported by a National Oceanic and Atmospheric Administration source or other source approved by the Administrator. The requirements of paragraph (g)(2) of this section shall not be waived for two consecutive quarterly monitoring periods.
(h) Each identified source of fugitive emissions shall be repaired or replaced in accordance with paragraphs (h)(1) and (2) of this section. For fugitive emissions components also subject to the repair provisions of §§ 60.5416a(b)(9) through (12) and (c)(4) through (7), those provisions apply instead to those closed vent system and covers, and the repair provisions of paragraphs (h)(1) and (2) of this section do not apply to those closed vent systems and covers.
(1) Each identified source of fugitive emissions shall be repaired or replaced as soon as practicable, but no later than 30 calendar days after detection of the fugitive emissions.
(2) If the repair or replacement is technically infeasible, would require a vent blowdown, a compressor station shutdown, a well shutdown or well shut-in, or would be unsafe to repair during operation of the unit, the repair or replacement must be completed during the next compressor station shutdown, well shutdown, well shut-in, after an unscheduled, planned or emergency vent blowdown or within 2 years, whichever is earlier.
(3) Each repaired or replaced fugitive emissions component must be resurveyed as soon as practicable, but no later than 30 days after being repaired, to ensure that there are no fugitive emissions.
(i) For repairs that cannot be made during the monitoring survey when the fugitive emissions are initially found, the operator may resurvey the repaired fugitive emissions components using either Method 21 or optical gas imaging within 30 days of finding such fugitive emissions.
(ii) For each repair that cannot be made during the monitoring survey when the fugitive emissions are initially found, a digital photograph must be taken of that component or the component must be tagged for identification purposes. The digital photograph must include the date that the photograph was taken, must clearly identify the component by location within the site ( e.g., the latitude and longitude of the component or by other descriptive landmarks visible in the picture).
(iii) Operators that use Method 21 to resurvey the repaired fugitive emissions components are subject to the resurvey provisions specified in paragraphs (h)(3)(iii)(A) and (B) of this section.
(A) A fugitive emissions component is repaired when the Method 21 instrument indicates a concentration of less than 500 ppm above background or when no soap bubbles are observed when the alternative screening procedures specified in section 8.3.3 of Method 21 are used.
(B) Operators must use the Method 21 monitoring requirements specified in paragraph (c)(8)(ii) of this section or the alternative screening procedures specified in section 8.3.3 of Method 21.
(iv) Operators that use optical gas imaging to resurvey the repaired fugitive emissions components, are subject to the resurvey provisions specified in paragraphs (h)(3)(iv)(A) and (B) of this section.
(A) A fugitive emissions component is repaired when the optical gas imaging instrument shows no indication of visible emissions.
(B) Operators must use the optical gas imaging monitoring requirements specified in paragraph (c)(7) of this section.
(i) Records for each monitoring survey shall be maintained as specified § 60.5420a(c)(15).
(j) Annual reports shall be submitted for each collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a compressor station that include the information specified in § 60.5420a(b)(7). Multiple collection of fugitive emissions components at a well site or at a compressor station may be included in a single annual report.
§ 60.5398a
What are the alternative means of emission limitations for GHG and VOC from well completions, reciprocating compressors, the collection of fugitive emissions components at a well site and the collection of fugitive emissions components at a compressor station?
(a) If, in the Administrator's judgment, an alternative means of emission limitation will achieve a reduction in GHG (in the form of a limitation on emission of methane) and VOC emissions at least equivalent to the reduction in GHG and VOC emissions achieved under § 60.5375a, § 60.5385a, and § 60.5397a, the Administrator will publish, in the Federal Register , a notice permitting the use of that alternative means for the purpose of compliance with § 60.5375a, § 60.5385a, and § 60.5397a. The notice may condition permission on requirements related to the operation and maintenance of the alternative means.
(b) Any notice under paragraph (a) of this section must be published only after notice and an opportunity for a public hearing.
(c) The Administrator will consider applications under this section from either owners or operators of affected facilities.
(d) Determination of equivalence to the design, equipment, work practice or operational requirements of this section will be evaluated by the following guidelines:
(1) The applicant must collect, verify and submit test data, covering a period of at least 12 months to demonstrate the equivalence of the alternative means of emission limitation. The application must include the following information:
(i) A description of the technology or process.
(ii) The monitoring instrument and measurement technology or process.
(iii) A description of performance based procedures ( i.e., method) and data quality indicators for precision and bias; the method detection limit of the technology or process.
(iv) For affected facilities under § 60.5397a, the action criteria and level at which a fugitive emission exists.
(v) Any initial and ongoing quality assurance/quality control measures.
(vi) Timeframes for conducting ongoing quality assurance/quality control.
(vii) Field data verifying viability and detection capabilities of the technology or process.
(viii) Frequency of measurements.
(ix) Minimum data availability.
(x) Any restrictions for using the technology or process.
(xi) Operation and maintenance procedures and other provisions necessary to ensure reduction in methane and VOC emissions at least equivalent to the reduction in methane and VOC emissions achieved under § 60.5397a.
(xii) Initial and continuous compliance procedures, including recordkeeping and reporting.
(2) For each determination of equivalency requested, the emission reduction achieved by the design, equipment, work practice or operational requirements shall be demonstrated.
(3) For each affected facility for which a determination of equivalency is requested, the emission reduction achieved by the alternative means of emission limitation shall be demonstrated.
(4) Each owner or operator applying for a determination of equivalence to a work practice standard shall commit in writing to work practice(s) that provide for emission reductions equal to or greater than the emission reductions achieved by the required work practice.
(e) After notice and opportunity for public hearing, the Administrator will determine the equivalence of a means of emission limitation and will publish the determination in the Federal Register .
(f) An application submitted under this section will be evaluated as set forth in paragraphs (f)(1) and (2) of this section.
(1) The Administrator will compare the demonstrated emission reduction for the alternative means of emission limitation to the demonstrated emission reduction for the design, equipment, work practice or operational requirements and, if applicable, will consider the commitment in paragraph (d) of this section.
(2) The Administrator may condition the approval of the alternative means of emission limitation on requirements that may be necessary to ensure operation and maintenance to achieve the same emissions reduction as the design, equipment, work practice or operational requirements. (g) Any equivalent means of emission limitations approved under this section shall constitute a required work practice, equipment, design or operational standard within the meaning of section 111(h)(1) of the CAA.
§ 60.5400a
What equipment leak GHG and VOC standards apply to affected facilities at an onshore natural gas processing plant?
This section applies to the group of all equipment, except compressors, within a process unit.
(a) You must comply with the requirements of §§ 60.482-1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-11a, except as provided in § 60.5401a.
(b) You may elect to comply with the requirements of §§ 60.483-1a and 60.483-2a, as an alternative.
(c) You may apply to the Administrator for permission to use an alternative means of emission limitation that achieves a reduction in emissions of methane and VOC at least equivalent to that achieved by the controls required in this subpart according to the requirements of § 60.5402a.
(d) You must comply with the provisions of § 60.485a except as provided in paragraph (f) of this section.
(e) You must comply with the provisions of §§ 60.486a and 60.487a except as provided in §§ 60.5401a, 60.5421a, and 60.5422a.
(f) You must use the following provision instead of § 60.485a(d)(1): Each piece of equipment is presumed to be in VOC service or in wet gas service unless an owner or operator demonstrates that the piece of equipment is not in VOC service or in wet gas service. For a piece of equipment to be considered not in VOC service, it must be determined that the VOC content can be reasonably expected never to exceed 10.0 percent by weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contains or contacts the field gas before the extraction step in the process. For purposes of determining the percent VOC content of the process fluid that is contained in or contacts a piece of equipment, procedures that conform to the methods described in ASTM E169-93, E168-92, or E260-96 (incorporated by reference as specified in § 60.17) must be used.
§ 60.5401a
What are the exceptions to the equipment leak GHG and VOC standards for affected facilities at onshore natural gas processing plants?
(a) You may comply with the following exceptions to the provisions of § 60.5400a(a) and (b).
(b)(1) Each pressure relief device in gas/vapor service may be monitored quarterly and within 5 days after each pressure release to detect leaks by the methods specified in § 60.485a(b) except as provided in § 60.5400a(c) and in paragraph (b)(4) of this section, and § 60.482-4a(a) through (c) of subpart VVa of this part.
(2) If an instrument reading of 500 ppm or greater is measured, a leak is detected.
(3)(i) When a leak is detected, it must be repaired as soon as practicable, but no later than 15 calendar days after it is detected, except as provided in § 60.482-9a.
(ii) A first attempt at repair must be made no later than 5 calendar days after each leak is detected.
(4)(i) Any pressure relief device that is located in a nonfractionating plant that is monitored only by non-plant personnel may be monitored after a pressure release the next time the monitoring personnel are onsite, instead of within 5 days as specified in paragraph (b)(1) of this section and § 60.482-4a(b)(1).
(ii) No pressure relief device described in paragraph (b)(4)(i) of this section may be allowed to operate for more than 30 days after a pressure release without monitoring.
(c) Sampling connection systems are exempt from the requirements of § 60.482-5a.
(d) Pumps in light liquid service, valves in gas/vapor and light liquid service, pressure relief devices in gas/vapor service, and connectors in gas/vapor service and in light liquid service that are located at a nonfractionating plant that does not have the design capacity to process 283,200 standard cubic meters per day (scmd) (10 million standard cubic feet per day) or more of field gas are exempt from the routine monitoring requirements of §§ 60.482-2a(a)(1), 60.482-7a(a), 60.482-11a(a), and paragraph (b)(1) of this section.
(e) Pumps in light liquid service, valves in gas/vapor and light liquid service, pressure relief devices in gas/vapor service, and connectors in gas/vapor service and in light liquid service within a process unit that is located in the Alaskan North Slope are exempt from the routine monitoring requirements of §§ 60.482-2a(a)(1), 60.482-7a(a), 60.482-11a(a), and paragraph (b)(1) of this section.
(f) An owner or operator may use the following provisions instead of § 60.485a(e):
(1) Equipment is in heavy liquid service if the weight percent evaporated is 10 percent or less at 150 °Celsius (302 °Fahrenheit) as determined by ASTM Method D86-96 (incorporated by reference as specified in § 60.17).
(2) Equipment is in light liquid service if the weight percent evaporated is greater than 10 percent at 150 °Celsius (302 °Fahrenheit) as determined by ASTM Method D86-96 (incorporated by reference as specified in § 60.17).
(g) An owner or operator may use the following provisions instead of § 60.485a(b)(2): A calibration drift assessment shall be performed, at a minimum, at the end of each monitoring day. Check the instrument using the same calibration gas(es) that were used to calibrate the instrument before use. Follow the procedures specified in Method 21 of appendix A-7 of this part, Section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. Record the instrument reading for each scale used as specified in § 60.486a(e)(8). Divide these readings by the initial calibration values for each scale and multiply by 100 to express the calibration drift as a percentage. If any calibration drift assessment shows a negative drift of more than 10 percent from the initial calibration value, then all equipment monitored since the last calibration with instrument readings below the appropriate leak definition and above the leak definition multiplied by (100 minus the percent of negative drift/divided by 100) must be re-monitored. If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment since the last calibration with instrument readings above the appropriate leak definition and below the leak definition multiplied by (100 plus the percent of positive drift/divided by 100) may be re-monitored.
§ 60.5402a
What are the alternative means of emission limitations for GHG and VOC equipment leaks from onshore natural gas processing plants?
(a) If, in the Administrator's judgment, an alternative means of emission limitation will achieve a reduction in GHG and VOC emissions at least equivalent to the reduction in GHG and VOC emissions achieved under any design, equipment, work practice or operational standard, the Administrator will publish, in the Federal Register , a notice permitting the use of that alternative means for the purpose of compliance with that standard. The notice may condition permission on requirements related to the operation and maintenance of the alternative means.
(b) Any notice under paragraph (a) of this section must be published only after notice and an opportunity for a public hearing.
(c) The Administrator will consider applications under this section from either owners or operators of affected facilities, or manufacturers of control equipment.
(d) An application submitted under paragraph (c) of this section must meet the following criteria:
(1) The applicant must collect, verify and submit test data, covering a period of at least 12 months, necessary to support the finding in paragraph (a) of this section.
(2) The application must include operation, maintenance and other provisions necessary to assure reduction in methane and VOC emissions at least equivalent to the reduction in methane and VOC emissions achieved under the design, equipment, work practice or operational standard in paragraph (a) of this section by including the information specified in paragraphs (d)(1)(i) through (x) of this section.
(i) A description of the technology or process.
(ii) The monitoring instrument and measurement technology or process.
(iii) A description of performance based procedures (i.e. method) and data quality indicators for precision and bias; the method detection limit of the technology or process.
(iv) The action criteria and level at which a fugitive emission exists.
(v) Any initial and ongoing quality assurance/quality control measures.
(vi) Timeframes for conducting ongoing quality assurance/quality control.
(vii) Field data verifying viability and detection capabilities of the technology or process.
(viii) Frequency of measurements.
(ix) Minimum data availability.
(x) Any restrictions for using the technology or process.
(3) The application must include initial and continuous compliance procedures including recordkeeping and reporting.
§ 60.5405a
What standards apply to sweetening unit affected facilities at onshore natural gas processing plants?
(a) During the initial performance test required by § 60.8(b), you must achieve at a minimum, an SO 2 emission reduction efficiency (Z i ) to be determined from Table 1 of this subpart based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility.
(b) After demonstrating compliance with the provisions of paragraph (a) of this section, you must achieve at a minimum, an SO 2 emission reduction efficiency (Z c ) to be determined from Table 2 of this subpart based on the sulfur feed rate (X) and the sulfur content of the acid gas (Y) of the affected facility.
§ 60.5406a
What test methods and procedures must I use for my sweetening unit affected facilities at onshore natural gas processing plants?
(a) In conducting the performance tests required in § 60.8, you must use the test methods in appendix A of this part or other methods and procedures as specified in this section, except as provided in § 60.8(b).
(b) During a performance test required by § 60.8, you must determine the minimum required reduction efficiencies (Z) of SO 2 emissions as required in § 60.5405a(a) and (b) as follows:
(1) The average sulfur feed rate (X) must be computed as follows:
X
=
KQ
a
Y
Where:
X = average sulfur feed rate, Mg/D (LT/D).
Q a = average volumetric flow rate of acid gas from sweetening unit, dscm/day (dscf/day).
Y = average H 2 S concentration in acid gas feed from sweetening unit, percent by volume, expressed as a decimal.
K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg)).
= 1.331 × 10 − ^3 Mg/dscm, for metric units.
= (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long ton)).
= 3.707 × 10 − ^5 long ton/dscf, for English units.
(2) You must use the continuous readings from the process flowmeter to determine the average volumetric flow rate (Q a ) in dscm/day (dscf/day) of the acid gas from the sweetening unit for each run.
(3) You must use the Tutwiler procedure in § 60.5408a or a chromatographic procedure following ASTM E260-96 (incorporated by reference as specified in § 60.17) to determine the H 2 S concentration in the acid gas feed from the sweetening unit (Y). At least one sample per hour (at equally spaced intervals) must be taken during each 4-hour run. The arithmetic mean of all samples must be the average H 2 S concentration (Y) on a dry basis for the run. By multiplying the result from the Tutwiler procedure by 1.62 × 10 − ^3 , the units gr/100 scf are converted to volume percent.
(4) Using the information from paragraphs (b)(1) and (3) of this section, Tables 1 and 2 of this subpart must be used to determine the required initial (Z i ) and continuous (Z c ) reduction efficiencies of SO 2 emissions.
(c) You must determine compliance with the SO 2 standards in § 60.5405a(a) or (b) as follows:
(1) You must compute the emission reduction efficiency (R) achieved by the sulfur recovery technology for each run using the following equation:
R = (100 S )/( S + E )
(2) You must use the level indicators or manual soundings to measure the liquid sulfur accumulation rate in the product storage vessels. You must use readings taken at the beginning and end of each run, the tank geometry, sulfur density at the storage temperature, and sample duration to determine the sulfur production rate (S) in kg/hr (lb/hr) for each run.
(3) You must compute the emission rate of sulfur for each run as follows:
E
=
C
e
Q
sd
/
K
1
Where:
E = emission rate of sulfur per run, kg/hr.
C e = concentration of sulfur equivalent (SO ^{2+} reduced sulfur), g/dscm (lb/dscf).
Q sd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr).
K 1 = conversion factor, 1000 g/kg (7000 gr/lb).
(4) The concentration (C e ) of sulfur equivalent must be the sum of the SO 2 and TRS concentrations, after being converted to sulfur equivalents. For each run and each of the test methods specified in this paragraph (c) of this section, you must use a sampling time of at least 4 hours. You must use Method 1 of appendix A-1 of this part to select the sampling site. The sampling point in the duct must be at the centroid of the cross-section if the area is less than 5 m ^2 (54 ft ^2 ) or at a point no closer to the walls than 1 m (39 in) if the cross-sectional area is 5 m ^2 or more, and the centroid is more than 1 m (39 in) from the wall.
(i) You must use Method 6 of appendix A-4 of this part to determine the SO 2 concentration. You must take eight samples of 20 minutes each at 30-minute intervals. The arithmetic average must be the concentration for the run. The concentration must be multiplied by 0.5 × 10 − ^3 to convert the results to sulfur equivalent. In place of Method 6 of Appendix A of this part, you may use ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by reference as specified in § 60.17).
(ii) You must use Method 15 of appendix A-5 of this part to determine the TRS concentration from reduction-type devices or where the oxygen content of the effluent gas is less than 1.0 percent by volume. The sampling rate must be at least 3 liters/min (0.1 ft ^3 /min) to insure minimum residence time in the sample line. You must take sixteen samples at 15-minute intervals. The arithmetic average of all the samples must be the concentration for the run. The concentration in ppm reduced sulfur as sulfur must be multiplied by 1.333 × 10 − ^3 to convert the results to sulfur equivalent.
(iii) You must use Method 16A of appendix A-6 of this part or Method 15 of appendix A-5 of this part or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by reference as specified in § 60.17) to determine the reduced sulfur concentration from oxidation-type devices or where the oxygen content of the effluent gas is greater than 1.0 percent by volume. You must take eight samples of 20 minutes each at 30-minute intervals. The arithmetic average must be the concentration for the run. The concentration in ppm reduced sulfur as sulfur must be multiplied by 1.333 × 10 − ^3 to convert the results to sulfur equivalent.
(iv) You must use Method 2 of appendix A-1 of this part to determine the volumetric flow rate of the effluent gas. A velocity traverse must be conducted at the beginning and end of each run. The arithmetic average of the two measurements must be used to calculate the volumetric flow rate (Q sd ) for the run. For the determination of the effluent gas molecular weight, a single integrated sample over the 4-hour period may be taken and analyzed or grab samples at 1-hour intervals may be taken, analyzed, and averaged. For the moisture content, you must take two samples of at least 0.10 dscm (3.5 dscf) and 10 minutes at the beginning of the 4-hour run and near the end of the time period. The arithmetic average of the two runs must be the moisture content for the run.
§ 60.5407a
What are the requirements for monitoring of emissions and operations from my sweetening unit affected facilities at onshore natural gas processing plants?
(a) If your sweetening unit affected facility is located at an onshore natural gas processing plant and is subject to the provisions of § 60.5405a(a) or (b) you must install, calibrate, maintain, and operate monitoring devices or perform measurements to determine the following operations information on a daily basis:
(1) The accumulation of sulfur product over each 24-hour period. The monitoring method may incorporate the use of an instrument to measure and record the liquid sulfur production rate, or may be a procedure for measuring and recording the sulfur liquid levels in the storage vessels with a level indicator or by manual soundings, with subsequent calculation of the sulfur production rate based on the tank geometry, stored sulfur density, and elapsed time between readings. The method must be designed to be accurate within ±2 percent of the 24-hour sulfur accumulation.
(2) The H 2 S concentration in the acid gas from the sweetening unit for each 24-hour period. At least one sample per 24-hour period must be collected and analyzed using the equation specified in § 60.5406a(b)(1). The Administrator may require you to demonstrate that the H 2 S concentration obtained from one or more samples over a 24-hour period is within ±20 percent of the average of 12 samples collected at equally spaced intervals during the 24-hour period. In instances where the H 2 S concentration of a single sample is not within ±20 percent of the average of the 12 equally spaced samples, the Administrator may require a more frequent sampling schedule.
(3) The average acid gas flow rate from the sweetening unit. You must install and operate a monitoring device to continuously measure the flow rate of acid gas. The monitoring device reading must be recorded at least once per hour during each 24-hour period. The average acid gas flow rate must be computed from the individual readings.
(4) The sulfur feed rate (X). For each 24-hour period, you must compute X using the equation specified in § 60.5406a(b)(1).
(5) The required sulfur dioxide emission reduction efficiency for the 24-hour period. You must use the sulfur feed rate and the H 2 S concentration in the acid gas for the 24-hour period, as applicable, to determine the required reduction efficiency in accordance with the provisions of § 60.5405a(b).
(b) Where compliance is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device, you must install, calibrate, maintain, and operate monitoring devices and continuous emission monitors as follows:
(1) A continuous monitoring system to measure the total sulfur emission rate (E) of SO 2 in the gases discharged to the atmosphere. The SO 2 emission rate must be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring system must be set so that the equivalent emission limit of § 60.5405a(b) will be between 30 percent and 70 percent of the measurement range of the instrument system.
(2) Except as provided in paragraph (b)(3) of this section: A monitoring device to measure the temperature of the gas leaving the combustion zone of the incinerator, if compliance with § 60.5405a(a) is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device. The monitoring device must be certified by the manufacturer to be accurate to within ±1 percent of the temperature being measured.
(3) When performance tests are conducted under the provision of § 60.8 to demonstrate compliance with the standards under § 60.5405a, the temperature of the gas leaving the incinerator combustion zone must be determined using the monitoring device. If the volumetric ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur (expressed as SO 2 ) in the gas leaving the incinerator is equal to or less than 0.98, then temperature monitoring may be used to demonstrate that sulfur dioxide emission monitoring is sufficient to determine total sulfur emissions. At all times during the operation of the facility, you must maintain the average temperature of the gas leaving the combustion zone of the incinerator at or above the appropriate level determined during the most recent performance test to ensure the sulfur compound oxidation criteria are met. Operation at lower average temperatures may be considered by the Administrator to be unacceptable operation and maintenance of the affected facility. You may request that the minimum incinerator temperature be reestablished by conducting new performance tests under § 60.8.
(4) Upon promulgation of a performance specification of continuous monitoring systems for total reduced sulfur compounds at sulfur recovery plants, you may, as an alternative to paragraph (b)(2) of this section, install, calibrate, maintain, and operate a continuous emission monitoring system for total reduced sulfur compounds as required in paragraph (d) of this section in addition to a sulfur dioxide emission monitoring system. The sum of the equivalent sulfur mass emission rates from the two monitoring systems must be used to compute the total sulfur emission rate (E).
(c) Where compliance is achieved through the use of a reduction control system not followed by a continually operated incineration device, you must install, calibrate, maintain, and operate a continuous monitoring system to measure the emission rate of reduced sulfur compounds as SO 2 equivalent in the gases discharged to the atmosphere. The SO 2 equivalent compound emission rate must be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring system must be set so that the equivalent emission limit of § 60.5405a(b) will be between 30 and 70 percent of the measurement range of the system. This requirement becomes effective upon promulgation of a performance specification for continuous monitoring systems for total reduced sulfur compounds at sulfur recovery plants.
(d) For those sources required to comply with paragraph (b) or (c) of this section, you must calculate the average sulfur emission reduction efficiency achieved (R) for each 24-hour clock interval. The 24-hour interval may begin and end at any selected clock time, but must be consistent. You must compute the 24-hour average reduction efficiency (R) based on the 24-hour average sulfur production rate (S) and sulfur emission rate (E), using the equation in § 60.5406a(c)(1).
(1) You must use data obtained from the sulfur production rate monitoring device specified in paragraph (a) of this section to determine S.
(2) You must use data obtained from the sulfur emission rate monitoring systems specified in paragraphs (b) or (c) of this section to calculate a 24-hour average for the sulfur emission rate (E). The monitoring system must provide at least one data point in each successive 15-minute interval. You must use at least two data points to calculate each 1-hour average. You must use a minimum of 18 1-hour averages to compute each 24-hour average.
(e) In lieu of complying with paragraphs (b) or (c) of this section, those sources with a design capacity of less than 152 Mg/D (150 LT/D) of H 2 S expressed as sulfur may calculate the sulfur emission reduction efficiency achieved for each 24-hour period by:
Where:
R = The sulfur dioxide removal efficiency achieved during the 24-hour period, percent.
K 2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 LT/D per lb/hr).
S = The sulfur production rate during the 24-hour period, kg/hr (lb/hr).
X = The sulfur feed rate in the acid gas, Mg/D (LT/D).
(f) The monitoring devices required in paragraphs (b)(1), (b)(3) and (c) of this section must be calibrated at least annually according to the manufacturer's specifications, as required by § 60.13(b).
(g) The continuous emission monitoring systems required in paragraphs (b)(1), (b)(3), and (c) of this section must be subject to the emission monitoring requirements of § 60.13 of the General Provisions. For conducting the continuous emission monitoring system performance evaluation required by § 60.13(c), Performance Specification 2 of appendix B of this part must apply, and Method 6 of appendix A-4 of this part must be used for systems required by paragraph (b) of this section. In place of Method 6 of appendix A-4 of this part, ASME PTC 19.10-1981 (incorporated by reference—see § 60.17) may be used.
§ 60.5408a
What is an optional procedure for measuring hydrogen sulfide in acid gas—Tutwiler Procedure?
The Tutwiler procedure may be found in the Gas Engineers Handbook, Fuel Gas Engineering practices, The Industrial Press, 93 Worth Street, New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket A-80-20-A, Entry II-I-67).
(a) When an instantaneous sample is desired and H 2 S concentration is 10 grains per 1000 cubic foot or more, a 100 ml Tutwiler burette is used. For concentrations less than 10 grains, a 500 ml Tutwiler burette and more dilute solutions are used. In principle, this method consists of titrating hydrogen sulfide in a gas sample directly with a standard solution of iodine.
(b) Apparatus. (See Figure 1 of this subpart.) A 100 or 500 ml capacity Tutwiler burette, with two-way glass stopcock at bottom and three-way stopcock at top that connect either with inlet tubulature or glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml subdivision; rubber tubing connecting burette with leveling bottle.
(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g iodine, and 20 to 25 g cp potassium iodide (KI) for each liter of solution. Dissolve KI in as little water as necessary; dissolve iodine in concentrated KI solution, make up to proper volume, and store in glass-stoppered brown glass bottle.
(2) Standard iodine solution, 1 ml=0.001771 g I. Transfer 33.7 ml of above 0.1N stock solution into a 250 ml volumetric flask; add water to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard iodine solution is equivalent to 100 grains H 2 S per cubic feet of gas.
(3) Starch solution. Rub into a thin paste about one teaspoonful of wheat starch with a little water; pour into about a pint of boiling water; stir; let cool and decant off clear solution. Make fresh solution every few days.
(d) Procedure . Fill leveling bulb with starch solution. Raise (L), open cock (G), open (F) to (A), and close (F) when solutions starts to run out of gas inlet. Close (G). Purge gas sampling line and connect with (A). Lower (L) and open (F) and (G). When liquid level is several ml past the 100 ml mark, close (G) and (F), and disconnect sampling tube. Open (G) and bring starch solution to 100 ml mark by raising (L); then close (G). Open (F) momentarily, to bring gas in burette to atmospheric pressure, and close (F). Open (G), bring liquid level down to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E) and disconnect it from burette. Rinse graduated cylinder with a standard iodine solution (0.00171 g I per ml); fill cylinder and record reading. Introduce successive small amounts of iodine through (F); shake well after each addition; continue until a faint permanent blue color is obtained. Record reading; subtract from previous reading, and call difference D.
(e) With every fresh stock of starch solution perform a blank test as follows: Introduce fresh starch solution into burette up to 100 ml mark. Close (F) and (G). Lower (L) and open (G). When liquid level reaches the 10 ml mark, close (G). With air in burette, titrate as during a test and up to same end point. Call ml of iodine used C. Then,
Grains H 2 S per 100 cubic foot of gas = 100 (D-C)
(f) Greater sensitivity can be attained if a 500 ml capacity Tutwiler burette is used with a more dilute (0.001N) iodine solution. Concentrations less than 1.0 grains per 100 cubic foot can be determined in this way. Usually, the starch-iodine end point is much less distinct, and a blank determination of end point, with H 2 S-free gas or air, is required.
§ 60.5410a
How do I demonstrate initial compliance with the standards for my well, centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump, storage vessel, collection of fugitive emissions components at a well site, collection of fugitive emissions components at a compressor station, and equipment leaks and sweetening unit affected facilities at onshore natural gas processing plants?
You must determine initial compliance with the standards for each affected facility using the requirements in paragraphs (a) through (j) of this section. The initial compliance period begins on August 2, 2016, or upon initial startup, whichever is later, and ends no later than 1 year after the initial startup date for your affected facility or no later than 1 year after August 2, 2016. The initial compliance period may be less than one full year.
(a) To achieve initial compliance with the methane and VOC standards for each well completion operation conducted at your well affected facility you must comply with paragraphs (a)(1) through (4) of this section.
(1) You must submit the notification required in § 60.5420a(a)(2).
(2) You must submit the initial annual report for your well affected facility as required in § 60.5420a(b)(1) and (2).
(3) You must maintain a log of records as specified in § 60.5420a(c)(1)(i) through (iv), as applicable, for each well completion operation conducted during the initial compliance period. If you meet the exemption for wells with a GOR less than 300 scf per stock barrel of oil produced, you do not have to maintain the records in § 60.5420a(c)(1)(i) through (iv) and must maintain the record in § 60.5420a(c)(1)(vi).
(4) For each well affected facility subject to both § 60.5375a(a)(1) and (3), as an alternative to retaining the records specified in § 60.5420a(c)(1)(i) through (iv), you may maintain records in accordance with § 60.5420a(c)(1)(v) of one or more digital photographs with the date the photograph was taken and the latitude and longitude of the well site imbedded within or stored with the digital file showing the equipment for storing or re-injecting recovered liquid, equipment for routing recovered gas to the gas flow line and the completion combustion device (if applicable) connected to and operating at each well completion operation that occurred during the initial compliance period. As an alternative to imbedded latitude and longitude within the digital photograph, the digital photograph may consist of a photograph of the equipment connected and operating at each well completion operation with a photograph of a separately operating GPS device within the same digital picture, provided the latitude and longitude output of the GPS unit can be clearly read in the digital photograph.
(b)(1) To achieve initial compliance with standards for your centrifugal compressor affected facility you must reduce methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95.0 percent or greater as required by § 60.5380a(a) and as demonstrated by the requirements of § 60.5413a.
(2) If you use a control device to reduce emissions, you must equip the wet seal fluid degassing system with a cover that meets the requirements of § 60.5411a(b) that is connected through a closed vent system that meets the requirements of § 60.5411a(a) and (d) and is routed to a control device that meets the conditions specified in § 60.5412a(a), (b) and (c). As an alternative to routing the closed vent system to a control device, you may route the closed vent system to a process.
(3) You must conduct an initial performance test as required in § 60.5413a within 180 days after initial startup or by August 2, 2016, whichever is later, and you must comply with the continuous compliance requirements in § 60.5415a(b).
(4) You must conduct the initial inspections required in § 60.5416a(a) and (b).
(5) You must install and operate the continuous parameter monitoring systems in accordance with § 60.5417a(a) through (g), as applicable.
(6) ]Reserved]
(7) You must submit the initial annual report for your centrifugal compressor affected facility as required in § 60.5420a(b)(1) and (3).
(8) You must maintain the records as specified in § 60.5420a(c)(2), (6) through (11), and (17), as applicable.
(c) To achieve initial compliance with the standards for each reciprocating compressor affected facility you must comply with paragraphs (c)(1) through (4) of this section.
(1) If complying with § 60.5385a(a)(1) or (2), during the initial compliance period, you must continuously monitor the number of hours of operation or track the number of months since the last rod packing replacement.
(2) If complying with § 60.5385a(a)(3), you must operate the rod packing emissions collection system under negative pressure and route emissions to a process through a closed vent system that meets the requirements of § 60.5411a(a) and (d).
(3) You must submit the initial annual report for your reciprocating compressor as required in § 60.5420a(b)(1) and (4).
(4) You must maintain the records as specified in § 60.5420a(c)(3) for each reciprocating compressor affected facility.
(d) To achieve initial compliance with methane and VOC emission standards for your pneumatic controller affected facility you must comply with the requirements specified in paragraphs (d)(1) through (6) of this section, as applicable.
(1) You must demonstrate initial compliance by maintaining records as specified in § 60.5420a(c)(4)(ii) of your determination that the use of a pneumatic controller affected facility with a bleed rate greater than the applicable standard is required as specified in § 60.5390a(b)(1) or (c)(1).
(2) If you own or operate a pneumatic controller affected facility located at a natural gas processing plant, your pneumatic controller must be driven by a gas other than natural gas, resulting in zero natural gas emissions.
(3) If you own or operate a pneumatic controller affected facility located other than at a natural gas processing plant, the controller manufacturer's design specifications for the controller must indicate that the controller emits less than or equal to 6 standard cubic feet of gas per hour.
(4) You must tag each new pneumatic controller affected facility according to the requirements of § 60.5390a(b)(2) or (c)(2).
(5) You must include the information in paragraph (d)(1) of this section and a listing of the pneumatic controller affected facilities specified in paragraphs (d)(2) and (3) of this section in the initial annual report submitted for your pneumatic controller affected facilities constructed, modified or reconstructed during the period covered by the annual report according to the requirements of § 60.5420a(b)(1) and (5).
(6) You must maintain the records as specified in § 60.5420a(c)(4) for each pneumatic controller affected facility.
(e) To achieve initial compliance with emission standards for your pneumatic pump affected facility you must comply with the requirements specified in paragraphs (e)(1) through (7) of this section, as applicable.
(1) If you own or operate a pneumatic pump affected facility located at a natural gas processing plant, your pneumatic pump must be driven by a gas other than natural gas, resulting in zero natural gas emissions.
(2) If you own or operate a pneumatic pump affected facility not located at a natural gas processing plant, you must reduce emissions in accordance § 60.5393a(b)(1) or (b)(2), and you must collect the pneumatic pump emissions through a closed vent system that meets the requirements of § 60.5411a(a) and (d).
(3) If you own or operate a pneumatic pump affected facility not located at a natural gas processing plant and there is no control device or process available on site, you must submit the certification in 60.5420a(b)(8)(i)(A).
(4) If you own or operate a pneumatic pump affected facility not located at a natural gas processing plant or a greenfield site, and you are unable to route to an existing control device due to technical infeasibility, and you are unable to route to a process, you must submit the certification in § 60.5420a(b)(8)(i)(B).
(5) If you own or operate a pneumatic pump affected facility not located other than at a natural gas processing plant and you reduce emissions in accordance with § 60.5393a(b)(4), you must collect the pneumatic pump emissions through a closed vent system that meets the requirements of § 60.5411a(c) and (d).
(6) You must submit the initial annual report for your pneumatic pump affected facility required in § 60.5420a(b)(1) and (8).
(7) You must maintain the records as specified in § 60.5420a(c)(6), (8) through (10), (16), and (17), as applicable, for each pneumatic pump affected facility.
(f) For affected facilities at onshore natural gas processing plants, initial compliance with the methane and VOC standards is demonstrated if you are in compliance with the requirements of § 60.5400a.
(g) For sweetening unit affected facilities at onshore natural gas processing plants, initial compliance is demonstrated according to paragraphs (g)(1) through (3) of this section.
(1) To determine compliance with the standards for SO 2 specified in § 60.5405a(a), during the initial performance test as required by § 60.8, the minimum required sulfur dioxide emission reduction efficiency (Z i ) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology as specified in paragraphs (g)(1)(i) and (ii) of this section.
(i) If R ≥ Z i , your affected facility is in compliance.
(ii) If R < Z i , your affected facility is not in compliance.
(2) The emission reduction efficiency (R) achieved by the sulfur reduction technology must be determined using the procedures in § 60.5406a(c)(1).
(3) You must submit the results of paragraphs (g)(1) and (2) of this section in the initial annual report submitted for your sweetening unit affected facilities at onshore natural gas processing plants.
(h) For each storage vessel affected facility, you must comply with paragraphs (h)(1) through (6) of this section. You must demonstrate initial compliance by August 2, 2016, or within 60 days after startup, whichever is later.
(1) You must determine the potential VOC emission rate as specified in § 60.5365a(e).
(2) You must reduce VOC emissions in accordance with § 60.5395a(a).
(3) If you use a control device to reduce emissions, you must equip the storage vessel with a cover that meets the requirements of § 60.5411a(b) and is connected through a closed vent system that meets the requirements of § 60.5411a(c) and (d) to a control device that meets the conditions specified in § 60.5412a(d) within 60 days after startup for storage vessels constructed, modified or reconstructed at well sites with no other wells in production, or upon startup for storage vessels constructed, modified or reconstructed at well sites with one or more wells already in production.
(4) You must conduct an initial performance test as required in § 60.5413a within 180 days after initial startup or within 180 days of August 2, 2016, whichever is later, and you must comply with the continuous compliance requirements in § 60.5415a(e).
(5) You must submit the information required for your storage vessel affected facility in your initial annual report as specified in § 60.5420a(b)(1) and (6).
(6) You must maintain the records required for your storage vessel affected facility, as specified in § 60.5420a(c)(5) through (8), (12) through (14), and (17), as applicable, for each storage vessel affected facility.
(i) For each storage vessel affected facility that complies by using a floating roof, you must submit a statement that you are complying with § 60.112(b)(a)(1) or (2) in accordance with § 60.5395a(b)(2) with the initial annual report specified in § 60.5420a(b).
(j) To achieve initial compliance with the fugitive emission standards for each collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a compressor station, you must comply with paragraphs (j)(1) through (5) of this section.
(1) You must develop a fugitive emissions monitoring plan as required in § 60.5397a(b)(c), and (d).
(2) You must conduct an initial monitoring survey as required in § 60.5397a(f).
(3) You must maintain the records specified in § 60.5420a(c)(15).
(4) You must repair each identified source of fugitive emissions for each affected facility as required in § 60.5397a(h).
(5) You must submit the initial annual report for each collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a compressor station compressor station as required in § 60.5420a(b)(1) and (7).
§ 60.5411a
What additional requirements must I meet to determine initial compliance for my covers and closed vent systems routing emissions from centrifugal compressor wet seal fluid degassing systems, reciprocating compressors, pneumatic pumps and storage vessels?
You must meet the applicable requirements of this section for each cover and closed vent system used to comply with the emission standards for your centrifugal compressor wet seal degassing systems, reciprocating compressors, pneumatic pumps and storage vessels.
(a) Closed vent system requirements for reciprocating compressors, centrifugal compressor wet seal degassing systems and pneumatic pumps.
(1) You must design the closed vent system to route all gases, vapors, and fumes emitted from the reciprocating compressor rod packing emissions collection system, the wet seal fluid degassing system or pneumatic pump to a control device or to a process. For reciprocating and centrifugal compressors, the closed vent system must route all gases, vapors, and fumes to a control device that meets the requirements specified in § 60.5412a(a) through (c).
(2) You must design and operate the closed vent system with no detectable emissions as demonstrated by § 60.5416a(b).
(3) You must meet the requirements specified in paragraphs (a)(3)(i) and (ii) of this section if the closed vent system contains one or more bypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device.
(i) Except as provided in paragraph (a)(3)(ii) of this section, you must comply with either paragraph (a)(3)(i)(A) or (B) of this section for each bypass device.
(A) You must properly install, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere that is capable of taking periodic readings as specified in § 60.5416a(a)(4)(i) and sounds an alarm, or initiates notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to § 60.5420a(c)(8).
(B) You must secure the bypass device valve installed at the inlet to the bypass device in the non-diverting position using a car-seal or a lock-and-key type configuration.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devices are not subject to the requirements of paragraph (a)(3)(i) of this section.
(b) Cover requirements for storage vessels and centrifugal compressor wet seal fluid degassing systems.
(1) The cover and all openings on the cover ( e.g. , access hatches, sampling ports, pressure relief devices and gauge wells) shall form a continuous impermeable barrier over the entire surface area of the liquid in the storage vessel or wet seal fluid degassing system.
(2) Each cover opening shall be secured in a closed, sealed position ( e.g. , covered by a gasketed lid or cap) whenever material is in the unit on which the cover is installed except during those times when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this includes openings necessary to equalize or balance the internal pressure of the unit following changes in the level of the material in the unit);
(ii) To inspect or sample the material in the unit;
(iii) To inspect, maintain, repair, or replace equipment located inside the unit; or
(iv) To vent liquids, gases, or fumes from the unit through a closed vent system designed and operated in accordance with the requirements of paragraph (a) or (c), and (d), of this section to a control device or to a process.
(3) Each storage vessel thief hatch shall be equipped, maintained and operated with a weighted mechanism or equivalent, to ensure that the lid remains properly seated and sealed under normal operating conditions, including such times when working, standing/breathing, and flash emissions may be generated. You must select gasket material for the hatch based on composition of the fluid in the storage vessel and weather conditions.
(c) Closed vent system requirements for storage vessel affected facilities using a control device or routing emissions to a process.
(1) You must design the closed vent system to route all gases, vapors, and fumes emitted from the material in the storage vessel to a control device that meets the requirements specified in § 60.5412a(c) and (d), or to a process.
(2) You must design and operate a closed vent system with no detectable emissions, as determined using olfactory, visual and auditory inspections.
(3) You must meet the requirements specified in paragraphs (c)(3)(i) and (ii) of this section if the closed vent system contains one or more bypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device or to a process.
(i) Except as provided in paragraph (c)(3)(ii) of this section, you must comply with either paragraph (c)(3)(i)(A) or (B) of this section for each bypass device.
(A) You must properly install, calibrate, maintain, and operate a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere that sounds an alarm, or initiates notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is activated according to § 60.5420a(c)(8).
(B) You must secure the bypass device valve installed at the inlet to the bypass device in the non-diverting position using a car-seal or a lock-and-key type configuration.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devices are not subject to the requirements of paragraph (c)(3)(i) of this section.
(d) Closed vent systems requirements for centrifugal compressor wet seal fluid degassing systems, reciprocating compressors, pneumatic pumps and storage vessels using a control device or routing emissions to a process.
(1) You must conduct an assessment that the closed vent system is of sufficient design and capacity to ensure that all emissions from the storage vessel are routed to the control device and that the control device is of sufficient design and capacity to accommodate all emissions from the affected facility and have it certified by a qualified professional engineer in accordance with paragraphs (d)(1)(i) and (ii) of this section.
(i) You must provide the following certification, signed and dated by the qualified professional engineer: “I certify that the closed vent system design and capacity assessment was prepared under my direction or supervision. I further certify that the closed vent system design and capacity assessment was conducted and this report was prepared pursuant to the requirements of subpart OOOOa of 40 CFR part 60. Based on my professional knowledge and experience, and inquiry of personnel involved in the assessment, the certification submitted herein is true, accurate, and complete. I am aware that there are penalties for knowingly submitting false information.”
(ii) The assessment shall be prepared under the direction or supervision of the qualified professional engineer who signs the certification in paragraph (d)(1)(i) of this section.
§ 60.5412a
What additional requirements must I meet for determining initial compliance with control devices used to comply with the emission standards for my centrifugal compressor, and storage vessel affected facilities?
You must meet the applicable requirements of this section for each control device used to comply with the emission standards for your centrifugal compressor affected facility, or storage vessel affected facility.
(a) Each control device used to meet the emission reduction standard in § 60.5380a(a)(1) for your centrifugal compressor affected facility must be installed according to paragraphs (a)(1) through (3) of this section. As an alternative, you may install a control device model tested under § 60.5413a(d), which meets the criteria in § 60.5413a(d)(11) and meet the continuous compliance requirements in § 60.5413a(e).
(1) Each combustion device ( e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) must be designed and operated in accordance with one of the performance requirements specified in paragraphs (a)(1)(i) through (iv) of this section.
(i) You must reduce the mass content of methane and VOC in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of § 60.5413a(b), with the exceptions noted in § 60.5413a(a).
(ii) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 275 parts per million by volume as propane on a wet basis corrected to 3 percent oxygen as determined in accordance with the applicable requirements of § 60.5413a(b), with the exceptions noted in § 60.5413a(a).
(iii) You must operate at a minimum temperature of 760 °Celsius, provided the control device has demonstrated, during the performance test conducted under § 60.5413a(b), that combustion zone temperature is an indicator of destruction efficiency.
(iv) If a boiler or process heater is used as the control device, then you must introduce the vent stream into the flame zone of the boiler or process heater.
(2) Each vapor recovery device ( e.g. , carbon adsorption system or condenser) or other non-destructive control device must be designed and operated to reduce the mass content of methane and VOC in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of § 60.5413a(b). As an alternative to the performance testing requirements, you may demonstrate initial compliance by conducting a design analysis for vapor recovery devices according to the requirements of § 60.5413a(c).
(3) You must design and operate a flare in accordance with the requirements of § 60.18(b), and you must conduct the compliance determination using Method 22 of appendix A-7 of this part to determine visible emissions.
(b) You must operate each control device installed on your centrifugal compressor affected facility in accordance with the requirements specified in paragraphs (b)(1) and (2) of this section.
(1) You must operate each control device used to comply with this subpart at all times when gases, vapors, and fumes are vented from the wet seal fluid degassing system affected facility as required under § 60.5380a(a)(1) through the closed vent system to the control device. You may vent more than one affected facility to a control device used to comply with this subpart.
(2) For each control device monitored in accordance with the requirements of § 60.5417a(a) through (g), you must demonstrate compliance according to the requirements of § 60.5415a(b)(2), as applicable.
(c) For each carbon adsorption system used as a control device to meet the requirements of paragraph (a)(2) or (d)(2) of this section, you must manage the carbon in accordance with the requirements specified in paragraphs (c)(1) or (2) of this section.
(1) Following the initial startup of the control device, you must replace all carbon in the control device with fresh carbon on a regular, predetermined time interval that is no longer than the carbon service life established according to § 60.5413a(c)(2) or (3) or according to the design required in paragraph (d)(2) of this section, for the carbon adsorption system. You must maintain records identifying the schedule for replacement and records of each carbon replacement as required in § 60.5420a(c)(10) and (12).
(2) You must either regenerate, reactivate, or burn the spent carbon removed from the carbon adsorption system in one of the units specified in paragraphs (c)(2)(i) through (vi) of this section.
(i) Regenerate or reactivate the spent carbon in a unit for which you have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 264, subpart X.
(ii) Regenerate or reactivate the spent carbon in a unit equipped with an operating organic air emission controls in accordance with an emissions standard for VOC under another subpart in 40 CFR part 63 or this part.
(iii) Burn the spent carbon in a hazardous waste incinerator for which the owner or operator complies with the requirements of 40 CFR part 63, subpart EEE and has submitted a Notification of Compliance under 40 CFR 63.1207(j).
(iv) Burn the spent carbon in a hazardous waste boiler or industrial furnace for which the owner or operator complies with the requirements of 40 CFR part 63, subpart EEE and has submitted a Notification of Compliance under 40 CFR 63.1207(j).
(v) Burn the spent carbon in an industrial furnace for which you have been issued a final permit under 40 CFR part 270 that implements the requirements of 40 CFR part 266, subpart H.
(vi) Burn the spent carbon in an industrial furnace that you have designed and operated in accordance with the interim status requirements of 40 CFR part 266, subpart H.
(d) Each control device used to meet the emission reduction standard in § 60.5395a(a)(2) for your storage vessel affected facility must be installed according to paragraphs (d)(1) through (4) of this section, as applicable. As an alternative to paragraph (d)(1) of this section, you may install a control device model tested under § 60.5413a(d), which meets the criteria in § 60.5413a(d)(11) and meet the continuous compliance requirements in § 60.5413a(e).
(1) For each combustion control device ( e.g. , thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) you must meet the requirements in paragraphs (d)(1)(i) through (iv) of this section.
(i) Ensure that each enclosed combustion control device is maintained in a leak free condition.
(ii) Install and operate a continuous burning pilot flame.
(iii) Operate the combustion control device with no visible emissions, except for periods not to exceed a total of 1 minute during any 15 minute period. A visible emissions test using section 11 of EPA Method 22 of appendix A-7 of this part must be performed at least once every calendar month, separated by at least 15 days between each test. The observation period shall be 15 minutes. Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. Following return to operation from maintenance or repair activity, each device must pass a Method 22 of appendix A-7 of this part visual observation as described in this paragraph.
(iv) Each enclosed combustion control device ( e.g. , thermal vapor incinerator, catalytic vapor incinerator, boiler, or process heater) must be designed and operated in accordance with one of the performance requirements specified in paragraphs (A) through (D) of this section.
(A) You must reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight or greater as determined in accordance with the requirements of § 60.5413a(b).
(B) You must reduce the concentration of TOC in the exhaust gases at the outlet to the device to a level equal to or less than 275 parts per million by volume as propane on a wet basis corrected to 3 percent oxygen as determined in accordance with the applicable requirements of § 60.5413a(b).
(C) You must operate at a minimum temperature of 760 °Celsius, provided the control device has demonstrated, during the performance test conducted under § 60.5413a(b), that combustion zone temperature is an indicator of destruction efficiency.
(D) If a boiler or process heater is used as the control device, then you must introduce the vent stream into the flame zone of the boiler or process heater.
(2) Each vapor recovery device ( e.g. , carbon adsorption system or condenser) or other non-destructive control device must be designed and operated to reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight or greater. A carbon replacement schedule must be included in the design of the carbon adsorption system.
(3) You must design and operate a flare in accordance with the requirements of § 60.18(b), and you must conduct the compliance determination using Method 22 of appendix A-7 of this part to determine visible emissions.
(4) You must operate each control device used to comply with this subpart at all times when gases, vapors, and fumes are vented from the storage vessel affected facility through the closed vent system to the control device. You may vent more than one affected facility to a control device used to comply with this subpart.
§ 60.5413a
What are the performance testing procedures for control devices used to demonstrate compliance at my centrifugal compressor and storage vessel affected facilities?
This section applies to the performance testing of control devices used to demonstrate compliance with the emissions standards for your centrifugal compressor affected facility or storage vessel affected facility. You must demonstrate that a control device achieves the performance requirements of § 60.5412a(a)(1) or (2) or (d)(1) or (2) using the performance test methods and procedures specified in this section. For condensers and carbon adsorbers, you may use a design analysis as specified in paragraph (c) of this section in lieu of complying with paragraph (b) of this section. In addition, this section contains the requirements for enclosed combustion control device performance tests conducted by the manufacturer applicable to storage vessel and centrifugal compressor affected facilities.
(a) Performance test exemptions. You are exempt from the requirements to conduct performance tests and design analyses if you use any of the control devices described in paragraphs (a)(1) through (7) of this section.
(1) A flare that is designed and operated in accordance with § 60.18(b). You must conduct the compliance determination using Method 22 of appendix A-7 of this part to determine visible emissions.
(2) A boiler or process heater with a design heat input capacity of 44 megawatts or greater.
(3) A boiler or process heater into which the vent stream is introduced with the primary fuel or is used as the primary fuel.
(4) A boiler or process heater burning hazardous waste for which you have been issued a final permit under 40 CFR part 270 and comply with the requirements of 40 CFR part 266, subpart H; you have certified compliance with the interim status requirements of 40 CFR part 266, subpart H; you have submitted a Notification of Compliance under 40 CFR 63.1207(j) and comply with the requirements of 40 CFR part 63, subpart EEE; or you comply with 40 CFR part 63, subpart EEE and will submit a Notification of Compliance under 40 CFR 63.1207(j) by the date specified in § 60.5420(b)(9) for submitting the initial performance test report.
(5) A hazardous waste incinerator for which you have submitted a Notification of Compliance under 40 CFR 63.1207(j), or for which you will submit a Notification of Compliance under 40 CFR 63.1207(j) by the date specified in § 60.5420a(b)(9) for submitting the initial performance test report, and you comply with the requirements of 40 CFR part 63, subpart EEE.
(6) A performance test is waived in accordance with § 60.8(b).
(7) A control device whose model can be demonstrated to meet the performance requirements of § 60.5412a(a)(1) or (d)(1) through a performance test conducted by the manufacturer, as specified in paragraph (d) of this section.
(b) Test methods and procedures. You must use the test methods and procedures specified in paragraphs (b)(1) through (5) of this section, as applicable, for each performance test conducted to demonstrate that a control device meets the requirements of § 60.5412a(a)(1) or (2) or (d)(1) or (2). You must conduct the initial and periodic performance tests according to the schedule specified in paragraph (b)(5) of this section. Each performance test must consist of a minimum of 3 test runs. Each run must be at least 1 hour long.
(1) You must use Method 1 or 1A of appendix A-1 of this part, as appropriate, to select the sampling sites specified in paragraphs (b)(1)(i) and (ii) of this section. Any references to particulate mentioned in Methods 1 and 1A do not apply to this section.
(i) Sampling sites must be located at the inlet of the first control device and at the outlet of the final control device to determine compliance with a control device percent reduction requirement.
(ii) The sampling site must be located at the outlet of the combustion device to determine compliance with a TOC exhaust gas concentration limit.
(2) You must determine the gas volumetric flowrate using Method 2, 2A, 2C, or 2D of appendix A-2 of this part, as appropriate.
(3) To determine compliance with the control device percent reduction performance requirement in § 60.5412a(a)(1)(i), (a)(2) or (d)(1)(iv)(A), you must use Method 25A of appendix A-7 of this part. You must use Method 4 of appendix A-3 of this part to convert the Method 25A results to a dry basis. You must use the procedures in paragraphs (b)(3)(i) through (iii) of this section to calculate percent reduction efficiency.
(i) You must compute the mass rate of TOC using the following equations:
E
i
=
K
2
C
i
M
p
Q
i
E
o
=
K
2
C
o
M
p
Q
o
Where:
E i , E o = Mass rate of TOC at the inlet and outlet of the control device, respectively, dry basis, kilograms per hour.
K 2 = Constant, 2.494 × 10 −6 (parts per million) (gram-mole per standard cubic meter) (kilogram/gram) (minute/hour), where standard temperature (gram-mole per standard cubic meter) is 20 °Celsius.
C i , C o = Concentration of TOC, as propane, of the gas stream as measured by Method 25A at the inlet and outlet of the control device, respectively, dry basis, parts per million by volume.
M p = Molecular weight of propane, 44.1 gram/gram-mole.
Q i , Q o = Flowrate of gas stream at the inlet and outlet of the control device, respectively, dry standard cubic meter per minute.
(ii) You must calculate the percent reduction in TOC as follows:
Where:
R cd = Control efficiency of control device, percent.
E i , = Mass rate of TOC at the inlet to the control device as calculated under paragraph (b)(3)(i) of this section, kilograms per hour.
E o = Mass rate of TOC at the outlet of the control device, as calculated under paragraph (b)(3)(i) of this section, kilograms per hour.
(iii) If the vent stream entering a boiler or process heater with a design capacity less than 44 megawatts is introduced with the combustion air or as a secondary fuel, you must determine the weight-percent reduction of total TOC across the device by comparing the TOC in all combusted vent streams and primary and secondary fuels with the TOC exiting the device, respectively.
(4) You must use Method 25A of appendix A-7 of this part to measure TOC, as propane, to determine compliance with the TOC exhaust gas concentration limit specified in § 60.5412a(a)(1)(ii) or (d)(1)(iv)(B). You may also use Method 18 of appendix A-6 of this part to measure methane and ethane. You may subtract the measured concentration of methane and ethane from the Method 25A measurement to demonstrate compliance with the concentration limit. You must determine the concentration in parts per million by volume on a wet basis and correct it to 3 percent oxygen, using the procedures in paragraphs (b)(4)(i) through (iii) of this section.
(i) If you use Method 18 to determine methane and ethane, you must take either an integrated sample or a minimum of four grab samples per hour. If grab sampling is used, then the samples must be taken at approximately equal intervals in time, such as 15-minute intervals during the run. You must determine the average methane and ethane concentration per run. The samples must be taken during the same time as the Method 25A sample.
(ii) You may subtract the concentration of methane and ethane from the Method 25A TOC, as propane, concentration for each run.
(iii) You must correct the TOC concentration (minus methane and ethane, if applicable) to 3 percent oxygen as specified in paragraphs (b)(4)(iii)(A) and (B) of this section.
(A) You must use the emission rate correction factor for excess air, integrated sampling and analysis procedures of Method 3A or 3B of appendix A-2 of this part, ASTM D6522-00 (Reapproved 2005), or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by reference as specified in § 60.17) to determine the oxygen concentration. The samples must be taken during the same time that the samples are taken for determining TOC concentration.
(B) You must correct the TOC concentration for percent oxygen as follows:
Where:
C c = TOC concentration, as propane, corrected to 3 percent oxygen, parts per million by volume on a wet basis.
C m = TOC concentration, as propane, (minus methane and ethane, if applicable), parts per million by volume on a wet basis.
%O 2m = Concentration of oxygen, percent by volume as measured, wet.
(5) You must conduct performance tests according to the schedule specified in paragraphs (b)(5)(i) and (ii) of this section.
(i) You must conduct an initial performance test within 180 days after initial startup for your affected facility. You must submit the performance test results as required in § 60.5420a(b)(9).
(ii) You must conduct periodic performance tests for all control devices required to conduct initial performance tests except as specified in paragraphs (b)(5)(ii)(A) and (B) of this section. You must conduct the first periodic performance test no later than 60 months after the initial performance test required in paragraph (b)(5)(i) of this section. You must conduct subsequent periodic performance tests at intervals no longer than 60 months following the previous periodic performance test or whenever you desire to establish a new operating limit. You must submit the periodic performance test results as specified in § 60.5420a(b)(9).
(A) A control device whose model is tested under, and meets the criteria of paragraph (d) of this section. For centrifugal compressor affected facilities, if you do not continuously monitor the gas flow rate in accordance with § 60.5417a(d)(1)(viii), then you must comply with the periodic performance testing requirements of paragraph (b)(5)(ii).
(B) A combustion control device tested under paragraph (b) of this section that meets the outlet TOC performance level specified in § 60.5412a(a)(1)(ii) or (d)(1)(iv)(B) and that establishes a correlation between firebox or combustion chamber temperature and the TOC performance level. For centrifugal compressor affected facilities, you must establish a limit on temperature in accordance with § 60.5417a(f) and continuously monitor the temperature as required by § 60.5417a(d).
(c) Control device design analysis to meet the requirements of § 60.5412a(a)(2) or (d)(2). (1) For a condenser, the design analysis must include an analysis of the vent stream composition, constituent concentrations, flowrate, relative humidity and temperature and must establish the design outlet organic compound concentration level, design average temperature of the condenser exhaust vent stream and the design average temperatures of the coolant fluid at the condenser inlet and outlet.
(2) For a regenerable carbon adsorption system, the design analysis shall include the vent stream composition, constituent concentrations, flowrate, relative humidity and temperature and shall establish the design exhaust vent stream organic compound concentration level, adsorption cycle time, number and capacity of carbon beds, type and working capacity of activated carbon used for the carbon beds, design total regeneration stream flow over the period of each complete carbon bed regeneration cycle, design carbon bed temperature after regeneration, design carbon bed regeneration time and design service life of the carbon.
(3) For a nonregenerable carbon adsorption system, such as a carbon canister, the design analysis shall include the vent stream composition, constituent concentrations, flowrate, relative humidity and temperature and shall establish the design exhaust vent stream organic compound concentration level, capacity of the carbon bed, type and working capacity of activated carbon used for the carbon bed and design carbon replacement interval based on the total carbon working capacity of the control device and source operating schedule. In addition, these systems shall incorporate dual carbon canisters in case of emission breakthrough occurring in one canister.
(4) If you and the Administrator do not agree on a demonstration of control device performance using a design analysis, then you must perform a performance test in accordance with the requirements of paragraph (b) of this section to resolve the disagreement. The Administrator may choose to have an authorized representative observe the performance test.
(d) Performance testing for combustion control devices—manufacturers' performance test. (1) This paragraph (d) applies to the performance testing of a combustion control device conducted by the device manufacturer. The manufacturer must demonstrate that a specific model of control device achieves the performance requirements in paragraph (d)(11) of this section by conducting a performance test as specified in paragraphs (d)(2) through (10) of this section. You must submit a test report for each combustion control device in accordance with the requirements in paragraph (d)(12) of this section.
(2) Performance testing must consist of three 1-hour (or longer) test runs for each of the four firing rate settings specified in paragraphs (d)(2)(i) through (iv) of this section, making a total of 12 test runs per test. Propene (propylene) gas must be used for the testing fuel. All fuel analyses must be performed by an independent third-party laboratory (not affiliated with the control device manufacturer or fuel supplier).
(i) 90-100 percent of maximum design rate (fixed rate).
(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 percent of the maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 100 percent of the maximum design rate. Hold at 100 percent for 5 minutes. In the 10-15 minute time range, incrementally ramp back down to 70 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling.
(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 percent of the maximum design rate. During the first 5 minutes, incrementally ramp the firing rate to 70 percent of the maximum design rate. Hold at 70 percent for 5 minutes. In the 10-15 minute time range, incrementally ramp back down to 30 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling.
(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the minimum firing rate. During the first 5 minutes, incrementally ramp the firing rate to 30 percent of the maximum design rate. Hold at 30 percent for 5 minutes. In the 10-15 minute time range, incrementally ramp back down to the minimum firing rate. Repeat three more times for a total of 60 minutes of sampling.
(3) All models employing multiple enclosures must be tested simultaneously and with all burners operational. Results must be reported for each enclosure individually and for the average of the emissions from all interconnected combustion enclosures/chambers. Control device operating data must be collected continuously throughout the performance test using an electronic Data Acquisition System. A graphic presentation or strip chart of the control device operating data and emissions test data must be included in the test report in accordance with paragraph (d)(12) of this section. Inlet fuel meter data may be manually recorded provided that all inlet fuel data readings are included in the final report.
(4) Inlet testing must be conducted as specified in paragraphs (d)(4)(i) and (ii) of this section.
(i) The inlet gas flow metering system must be located in accordance with Method 2A of appendix A-1 of this part (or other approved procedure) to measure inlet gas flow rate at the control device inlet location. You must position the fitting for filling fuel sample containers a minimum of eight pipe diameters upstream of any inlet gas flow monitoring meter.
(ii) Inlet flow rate must be determined using Method 2A of appendix A-1 of this part. Record the start and stop reading for each 60-minute THC test. Record the gas pressure and temperature at 5-minute intervals throughout each 60-minute test.
(5) Inlet gas sampling must be conducted as specified in paragraphs (d)(5)(i) and (ii) of this section.
(i) At the inlet gas sampling location, securely connect a Silonite-coated stainless steel evacuated canister fitted with a flow controller sufficient to fill the canister over a 3-hour period. Filling must be conducted as specified in paragraphs (d)(5)(i)(A) through (C) of this section.
(A) Open the canister sampling valve at the beginning of each test run, and close the canister at the end of each test run.
(B) Fill one canister across the three test runs such that one composite fuel sample exists for each test condition.
(C) Label the canisters individually and record sample information on a chain of custody form.
(ii) Analyze each inlet gas sample using the methods in paragraphs (d)(5)(ii)(A) through (C) of this section. You must include the results in the test report required by paragraph (d)(12) of this section.
(A) Hydrocarbon compounds containing between one and five atoms of carbon plus benzene using ASTM D1945-03 (incorporated by reference as specified in § 60.17).
(B) Hydrogen (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) using ASTM D1945-03 (incorporated by reference as specified in § 60.17).
(C) Higher heating value using ASTM D3588-98 or ASTM D4891-89 (incorporated by reference as specified in § 60.17).
(6) Outlet testing must be conducted in accordance with the criteria in paragraphs (d)(6)(i) through (v) of this section.
(i) Sample and flow rate must be measured in accordance with paragraphs (d)(6)(i)(A) and (B) of this section.
(A) The outlet sampling location must be a minimum of four equivalent stack diameters downstream from the highest peak flame or any other flow disturbance, and a minimum of one equivalent stack diameter upstream of the exit or any other flow disturbance. A minimum of two sample ports must be used.
(B) Flow rate must be measured using Method 1 of appendix A-1 of this part for determining flow measurement traverse point location, and Method 2 of appendix A-1 of this part for measuring duct velocity. If low flow conditions are encountered ( i.e., velocity pressure differentials less than 0.05 inches of water) during the performance test, a more sensitive manometer must be used to obtain an accurate flow profile.
(ii) Molecular weight and excess air must be determined as specified in paragraph (d)(7) of this section.
(iii) Carbon monoxide must be determined as specified in paragraph (d)(8) of this section.
(iv) THC must be determined as specified in paragraph (d)(9) of this section.
(v) Visible emissions must be determined as specified in paragraph (d)(10) of this section.
(7) Molecular weight and excess air determination must be performed as specified in paragraphs (d)(7)(i) through (iii) of this section.
(i) An integrated bag sample must be collected during the moisture test required by Method 4 of appendix A-3 of this part following the procedure specified in (d)(7)(i)(A) and (B) of this section. Analyze the bag sample using a gas chromatograph-thermal conductivity detector (GC-TCD) analysis meeting the criteria in paragraphs (d)(7)(i)(C) and (D) of this section.
(A) Collect the integrated sample throughout the entire test, and collect representative volumes from each traverse location.
(B) Purge the sampling line with stack gas before opening the valve and beginning to fill the bag. Clearly label each bag and record sample information on a chain of custody form.
(C) The bag contents must be vigorously mixed prior to the gas chromatograph analysis.
(D) The GC-TCD calibration procedure in Method 3C of appendix A-2 of this part must be modified by using EPA Alt-045 as follows: For the initial calibration, triplicate injections of any single concentration must agree within 5 percent of their mean to be valid. The calibration response factor for a single concentration re-check must be within 10 percent of the original calibration response factor for that concentration. If this criterion is not met, repeat the initial calibration using at least three concentration levels.
(ii) Calculate and report the molecular weight of oxygen, carbon dioxide, methane and nitrogen in the integrated bag sample and include in the test report specified in paragraph (d)(12) of this section. Moisture must be determined using Method 4 of appendix A-3 of this part. Traverse both ports with the sampling train required by Method 4 of appendix A-3 of this part during each test run. Ambient air must not be introduced into the integrated bag sample required by Method 3C of appendix A-2 of this part during the port change.
(iii) Excess air must be determined using resultant data from the EPA Method 3C tests and EPA Method 3B of appendix A-2 of this part, equation 3B-1, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by reference as specified in § 60.17).
(8) Carbon monoxide must be determined using Method 10 of appendix A-4 of this part. Run the test simultaneously with Method 25A of appendix A-7 of this part using the same sampling points. An instrument range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
(9) Total hydrocarbon determination must be performed as specified by in paragraphs (d)(9)(i) through (vii) of this section.
(i) Conduct THC sampling using Method 25A of appendix A-7 of this part, except that the option for locating the probe in the center 10 percent of the stack is not allowed. The THC probe must be traversed to 16.7 percent, 50 percent, and 83.3 percent of the stack diameter during each test run.
(ii) A valid test must consist of three Method 25A tests, each no less than 60 minutes in duration.
(iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) measurement range is preferred; as an alternative a 0-30 ppmvw (as carbon) measurement range may be used.
(iv) Calibration gases must be propane in air and be certified through EPA Protocol 1—“EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” (incorporated by reference as specified in § 60.17).
(v) THC measurements must be reported in terms of ppmvw as propane.
(vi) THC results must be corrected to 3 percent CO 2 , as measured by Method 3C of appendix A-2 of this part. You must use the following equation for this diluent concentration correction:
Where:
C meas = The measured concentration of the pollutant.
CO 2meas = The measured concentration of the CO 2 diluent.
3 = The corrected reference concentration of CO 2 diluent.
C corr = The corrected concentration of the pollutant.
(vii) Subtraction of methane or ethane from the THC data is not allowed in determining results.
(10) Visible emissions must be determined using Method 22 of appendix A-7 of this part. The test must be performed continuously during each test run. A digital color photograph of the exhaust point, taken from the position of the observer and annotated with date and time, must be taken once per test run and the 12 photos included in the test report specified in paragraph (d)(12) of this section.
(11) Performance test criteria. (i) The control device model tested must meet the criteria in paragraphs (d)(11)(i)(A) through (D) of this section. These criteria must be reported in the test report required by paragraph (d)(12) of this section.
(A) Results from Method 22 of appendix A-7 of this part determined under paragraph (d)(10) of this section with no indication of visible emissions.
(B) Average results from Method 25A of appendix A-7 of this part determined under paragraph (d)(9) of this section equal to or less than 10.0 ppmvw THC as propane corrected to 3.0 percent CO 2 .
(C) Average CO emissions determined under paragraph (d)(8) of this section equal to or less than 10 parts ppmvd, corrected to 3.0 percent CO 2 .
(D) Excess air determined under paragraph (d)(7) of this section equal to or greater than 150 percent.
(ii) The manufacturer must determine a maximum inlet gas flow rate which must not be exceeded for each control device model to achieve the criteria in paragraph (d)(11)(iii) of this section. The maximum inlet gas flow rate must be included in the test report required by paragraph (d)(12) of this section.
(iii) A manufacturer must demonstrate a destruction efficiency of at least 95 percent for THC, as propane. A control device model that demonstrates a destruction efficiency of 95 percent for THC, as propane, will meet the control requirement for 95 percent destruction of VOC and methane (if applicable) required under this subpart.
(12) The owner or operator of a combustion control device model tested under this paragraph must submit the information listed in paragraphs (d)(12)(i) through (vi) of this section in the test report required by this section in accordance with § 60.5420a(b)(10). Owners or operators who claim that any of the performance test information being submitted is confidential business information (CBI) must submit a complete file including information claimed to be CBI, on a compact disc, flash drive, or other commonly used electronic storage media to the EPA. The electronic media must be clearly marked as CBI and mailed to Attn: CBI Document Control Officer; Office of Air Quality Planning and Standards (OAQPS) CBIO Room 521; 109 T.W. Alexander Drive; RTP, NC 27711. The same file with the CBI omitted must be submitted to Oil_and_Gas_PT@EPA.GOV .
(i) A full schematic of the control device and dimensions of the device components.
(ii) The maximum net heating value of the device.
(iii) The test fuel gas flow range (in both mass and volume). Include the maximum allowable inlet gas flow rate.
(iv) The air/stream injection/assist ranges, if used.
(v) The test conditions listed in paragraphs (d)(12)(v)(A) through (O) of this section, as applicable for the tested model.
(A) Fuel gas delivery pressure and temperature.
(B) Fuel gas moisture range.
(C) Purge gas usage range.
(D) Condensate (liquid fuel) separation range.
(E) Combustion zone temperature range. This is required for all devices that measure this parameter.
(F) Excess air range.
(G) Flame arrestor(s).
(H) Burner manifold.
(I) Pilot flame indicator.
(J) Pilot flame design fuel and calculated or measured fuel usage.
(K) Tip velocity range.
(L) Momentum flux ratio.
(M) Exit temperature range.
(N) Exit flow rate.
(O) Wind velocity and direction.
(vi) The test report must include all calibration quality assurance/quality control data, calibration gas values, gas cylinder certification, strip charts, or other graphic presentations of the data annotated with test times and calibration values.
(e) Continuous compliance for combustion control devices tested by the manufacturer in accordance with paragraph (d) of this section. This paragraph (e) applies to the demonstration of compliance for a combustion control device tested under the provisions in paragraph (d) of this section. Owners or operators must demonstrate that a control device achieves the performance criteria in paragraph (d)(11) of this section by installing a device tested under paragraph (d) of this section, complying with the criteria specified in paragraphs (e)(1) through (8) of this section, maintaining the records specified in § 60.5420a(c)(2) or (c)(5)(vi) and submitting the report specified in § 60.5420a(b)(10).
(1) The inlet gas flow rate must be equal to or less than the maximum specified by the manufacturer.
(2) A pilot flame must be present at all times of operation.
(3) Devices must be operated with no visible emissions, except for periods not to exceed a total of 1 minute during any 15-minute period. A visible emissions test conducted according to section 11 of EPA Method 22 of appendix A-7 of this part must be performed at least once every calendar month, separated by at least 15 days between each test. The observation period shall be 15 minutes.
(4) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All repairs and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection.
(5) Following return to operation from maintenance or repair activity, each device must pass a visual observation according to EPA Method 22 of appendix A-7 of this part as described in paragraph (e)(3) of this section.
(6) If the owner or operator operates a combustion control device model tested under this section, an electronic copy of the performance test results required by this section shall be submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test results for that model of combustion control device are posted at the following Web site: epa.gov/airquality/oilandgas/ .
(7) Ensure that each enclosed combustion control device is maintained in a leak free condition.
(8) Operate each control device following the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions.
§ 60.5415a
How do I demonstrate continuous compliance with the standards for my well, centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump, storage vessel, collection of fugitive emissions components at a well site, and collection of fugitive emissions components at a compressor station affected facilities, and affected facilities at onshore natural gas processing plants?
(a) For each well affected facility, you must demonstrate continuous compliance by submitting the reports required by § 60.5420a(b)(1) and (2) and maintaining the records for each completion operation specified in § 60.5420a(c)(1).
(b) For each centrifugal compressor affected facility and each pneumatic pump affected facility, you must demonstrate continuous compliance according to paragraph (b)(3) of this section. For each centrifugal compressor affected facility, you also must demonstrate continuous compliance according to paragraphs (b)(1) and (2) of this section.
(1) You must reduce methane and VOC emissions from the wet seal fluid degassing system by 95.0 percent or greater.
(2) For each control device used to reduce emissions, you must demonstrate continuous compliance with the performance requirements of § 60.5412a(a) using the procedures specified in paragraphs (b)(2)(i) through (vii) of this section. If you use a condenser as the control device to achieve the requirements specified in § 60.5412a(a)(2), you may demonstrate compliance according to paragraph (b)(2)(viii) of this section. You may switch between compliance with paragraphs (b)(2)(i) through (vii) of this section and compliance with paragraph (b)(2)(viii) of this section only after at least 1 year of operation in compliance with the selected approach. You must provide notification of such a change in the compliance method in the next annual report, following the change.
(i) You must operate below (or above) the site specific maximum (or minimum) parameter value established according to the requirements of § 60.5417a(f)(1).
(ii) You must calculate the daily average of the applicable monitored parameter in accordance with § 60.5417a(e) except that the inlet gas flow rate to the control device must not be averaged.
(iii) Compliance with the operating parameter limit is achieved when the daily average of the monitoring parameter value calculated under paragraph (b)(2)(ii) of this section is either equal to or greater than the minimum monitoring value or equal to or less than the maximum monitoring value established under paragraph (b)(2)(i) of this section. When performance testing of a combustion control device is conducted by the device manufacturer as specified in § 60.5413a(d), compliance with the operating parameter limit is achieved when the criteria in § 60.5413a(e) are met.
(iv) You must operate the continuous monitoring system required in § 60.5417a(a) at all times the affected source is operating, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions and required monitoring system quality assurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments). A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to complete monitoring system repairs in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable.
(v) You may not use data recorded during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities in calculations used to report emissions or operating levels. You must use all the data collected during all other required data collection periods to assess the operation of the control device and associated control system.
(vi) Failure to collect required data is a deviation of the monitoring requirements, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions and required quality monitoring system quality assurance or quality control activities (including, as applicable, system accuracy audits and required zero and span adjustments).
(vii) If you use a combustion control device to meet the requirements of § 60.5412a(a)(1) and you demonstrate compliance using the test procedures specified in § 60.5413a(b), or you use a flare designed and operated in accordance with § 60.18(b), you must comply with paragraphs (b)(2)(vii)(A) through (D) of this section.
(A) A pilot flame must be present at all times of operation.
(B) Devices must be operated with no visible emissions, except for periods not to exceed a total of 1 minute during any 15-minute period. A visible emissions test conducted according to section 11 of EPA Method 22, 40 CFR part 60, appendix A, must be performed at least once every calendar month, separated by at least 15 days between each test. The observation period shall be 15 minutes.
(C) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All repairs and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection.
(D) Following return to operation from maintenance or repair activity, each device must pass a Method 22 of appendix A-7 of this part visual observation as described in paragraph (b)(2)(vii)(B) of this section.
(viii) If you use a condenser as the control device to achieve the percent reduction performance requirements specified in § 60.5412a(a)(2), you must demonstrate compliance using the procedures in paragraphs (b)(2)(viii)(A) through (E) of this section.
(A) You must establish a site-specific condenser performance curve according to § 60.5417a(f)(2).
(B) You must calculate the daily average condenser outlet temperature in accordance with § 60.5417a(e).
(C) You must determine the condenser efficiency for the current operating day using the daily average condenser outlet temperature calculated under paragraph (b)(2)(viii)(B) of this section and the condenser performance curve established under paragraph (b)(2)(viii)(A) of this section.
(D) Except as provided in paragraphs (b)(2)(viii)(D)( 1 ) and ( 2 ) of this section, at the end of each operating day, you must calculate the 365-day rolling average TOC emission reduction, as appropriate, from the condenser efficiencies as determined in paragraph (b)(2)(viii)(C) of this section.
( 1 ) After the compliance dates specified in § 60.5370a(a), if you have less than 120 days of data for determining average TOC emission reduction, you must calculate the average TOC emission reduction for the first 120 days of operation after the compliance date. You have demonstrated compliance with the overall 95.0 percent reduction requirement if the 120-day average TOC emission reduction is equal to or greater than 95.0 percent.
( 2 ) After 120 days and no more than 364 days of operation after the compliance date specified in § 60.5370a(a), you must calculate the average TOC emission reduction as the TOC emission reduction averaged over the number of days between the current day and the applicable compliance date. You have demonstrated compliance with the overall 95.0 percent reduction requirement if the average TOC emission reduction is equal to or greater than 95.0 percent.
(E) If you have data for 365 days or more of operation, you have demonstrated compliance with the TOC emission reduction if the rolling 365-day average TOC emission reduction calculated in paragraph (b)(2)(viii)(D) of this section is equal to or greater than 95.0 percent.
(3) You must submit the annual reports required by 60.5420a(b)(1) and (3) and maintain the records as specified in § 60.5420a(c)(2), (6) through (11), and (17), as applicable.
(c) For each reciprocating compressor affected facility complying with § 60.5385a(a)(1) or (2), you must demonstrate continuous compliance according to paragraphs (c)(1) through (3) of this section. For each reciprocating compressor affected facility complying with § 60.5385a(a)(3), you must demonstrate continuous compliance according to paragraph (c)(4) of this section.
(1) You must continuously monitor the number of hours of operation for each reciprocating compressor affected facility or track the number of months since initial startup or the date of the most recent reciprocating compressor rod packing replacement, whichever is later.
(2) You must submit the annual reports as required in § 60.5420a(b)(1) and (4) and maintain records as required in § 60.5420a(c)(3).
(3) You must replace the reciprocating compressor rod packing on or before the total number of hours of operation reaches 26,000 hours or the number of months since the most recent rod packing replacement reaches 36 months.
(4) You must operate the rod packing emissions collection system under negative pressure and continuously comply with the cover and closed vent requirements in § 60.5416a(a) and (b).
(d) For each pneumatic controller affected facility, you must demonstrate continuous compliance according to paragraphs (d)(1) through (3) of this section.
(1) You must continuously operate the pneumatic controllers as required in § 60.5390a(a), (b), or (c).
(2) You must submit the annual reports as required in § 60.5420a(b)(1) and (5).
(3) You must maintain records as required in § 60.5420a(c)(4).
(e) You must demonstrate continuous compliance according to paragraph (e)(3) of this section for each storage vessel affected facility, for which you are using a control device or routing emissions to a process to meet the requirement of § 60.5395a(a)(2).
(1)-(2) [Reserved]
(3) For each storage vessel affected facility, you must comply with paragraphs (e)(3)(i) and (ii) of this section.
(i) You must reduce VOC emissions as specified in § 60.5395a(a)(2).
(ii) For each control device installed to meet the requirements of § 60.5395a(a)(2), you must demonstrate continuous compliance with the performance requirements of § 60.5412a(d) for each storage vessel affected facility using the procedure specified in paragraph (e)(3)(ii)(A) and either (e)(3)(ii)(B) or (e)(3)(ii)(C) of this section.
(A) You must comply with § 60.5416a(c) for each cover and closed vent system.
(B) You must comply with § 60.5417a(h) for each control device.
(C) Each closed vent system that routes emissions to a process must be operated as specified in § 60.5411a(c)(2) and (3).
(f) For affected facilities at onshore natural gas processing plants, continuous compliance with methane and VOC requirements is demonstrated if you are in compliance with the requirements of § 60.5400a.
(g) For each sweetening unit affected facility at onshore natural gas processing plants, you must demonstrate continuous compliance with the standards for SO 2 specified in § 60.5405a(b) according to paragraphs (g)(1) and (2) of this section.
(1) The minimum required SO 2 emission reduction efficiency (Z c ) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology.
(i) If R ≥ Z c , your affected facility is in compliance.
(ii) If R < Z c , your affected facility is not in compliance.
(2) The emission reduction efficiency (R) achieved by the sulfur reduction technology must be determined using the procedures in § 60.5406a(c)(1).
(h) For each collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a compressor station, you must demonstrate continuous compliance with the fugitive emission standards specified in § 60.5397a according to paragraphs (h)(1) through (4) of this section.
(1) You must conduct periodic monitoring surveys as required in § 60.5397a(g).
(2) You must repair or replace each identified source of fugitive emissions as required in § 60.5397a(h).
(3) You must maintain records as specified in § 60.5420a(c)(15).
(4) You must submit annual reports for collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a compressor station as required in § 60.5420a(b)(1) and (7).
§ 60.5416a
What are the initial and continuous cover and closed vent system inspection and monitoring requirements for my centrifugal compressor, reciprocating compressor, pneumatic pump and storage vessel affected facilities?
For each closed vent system or cover at your storage vessel, centrifugal compressor, reciprocating compressor and pneumatic pump affected facilities, you must comply with the applicable requirements of paragraphs (a) through (c) of this section.
(a) Inspections for closed vent systems and covers installed on each centrifugal compressor, reciprocating compressor or pneumatic pump affected facility. Except as provided in paragraphs (b)(11) and (12) of this section, you must inspect each closed vent system according to the procedures and schedule specified in paragraphs (a)(1) and (2) of this section, inspect each cover according to the procedures and schedule specified in paragraph (a)(3) of this section, and inspect each bypass device according to the procedures of paragraph (a)(4) of this section.
(1) For each closed vent system joint, seam, or other connection that is permanently or semi-permanently sealed (e.g., a welded joint between two sections of hard piping or a bolted and gasketed ducting flange), you must meet the requirements specified in paragraphs (a)(1)(i) and (ii) of this section.
(i) Conduct an initial inspection according to the test methods and procedures specified in paragraph (b) of this section to demonstrate that the closed vent system operates with no detectable emissions. You must maintain records of the inspection results as specified in § 60.5420a(c)(6).
(ii) Conduct annual visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in piping; loose connections; liquid leaks; or broken or missing caps or other closure devices. You must monitor a component or connection using the test methods and procedures in paragraph (b) of this section to demonstrate that it operates with no detectable emissions following any time the component is repaired or replaced or the connection is unsealed. You must maintain records of the inspection results as specified in § 60.5420a(c)(6).
(2) For closed vent system components other than those specified in paragraph (a)(1) of this section, you must meet the requirements of paragraphs (a)(2)(i) through (iii) of this section.
(i) Conduct an initial inspection according to the test methods and procedures specified in paragraph (b) of this section to demonstrate that the closed vent system operates with no detectable emissions. You must maintain records of the inspection results as specified in § 60.5420a(c)(6).
(ii) Conduct annual inspections according to the test methods and procedures specified in paragraph (b) of this section to demonstrate that the components or connections operate with no detectable emissions. You must maintain records of the inspection results as specified in § 60.5420a(c)(6).
(iii) Conduct annual visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in ductwork; loose connections; liquid leaks; or broken or missing caps or other closure devices. You must maintain records of the inspection results as specified in § 60.5420a(c)(6).
(3) For each cover, you must meet the requirements in paragraphs (a)(3)(i) and (ii) of this section.
(i) Conduct visual inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in the cover, or between the cover and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on closure devices; and broken or missing hatches, access covers, caps, or other closure devices. In the case where the storage vessel is buried partially or entirely underground, you must inspect only those portions of the cover that extend to or above the ground surface, and those connections that are on such portions of the cover ( e.g., fill ports, access hatches, gauge wells, etc.) and can be opened to the atmosphere.
(ii) You must initially conduct the inspections specified in paragraph (a)(3)(i) of this section following the installation of the cover. Thereafter, you must perform the inspection at least once every calendar year, except as provided in paragraphs (b)(11) and (12) of this section. You must maintain records of the inspection results as specified in § 60.5420a(c)(7).
(4) For each bypass device, except as provided for in § 60.5411a(c)(3)(ii), you must meet the requirements of paragraphs (a)(4)(i) or (ii) of this section.
(i) Set the flow indicator to take a reading at least once every 15 minutes at the inlet to the bypass device that could divert the steam away from the control device to the atmosphere.
(ii) If the bypass device valve installed at the inlet to the bypass device is secured in the non-diverting position using a car-seal or a lock-and-key type configuration, visually inspect the seal or closure mechanism at least once every month to verify that the valve is maintained in the non-diverting position and the vent stream is not diverted through the bypass device. You must maintain records of the inspections according to § 60.5420a(c)(8).
(b) No detectable emissions test methods and procedures. If you are required to conduct an inspection of a closed vent system or cover at your centrifugal compressor, reciprocating compressor, or pneumatic pump affected facility as specified in paragraphs (a)(1), (2), or (3) of this section, you must meet the requirements of paragraphs (b)(1) through (13) of this section.
(1) You must conduct the no detectable emissions test procedure in accordance with Method 21 of appendix A-7 of this part.
(2) The detection instrument must meet the performance criteria of Method 21 of appendix A-7 of this part, except that the instrument response factor criteria in section 8.1.1 of Method 21 must be for the average composition of the fluid and not for each individual organic compound in the stream.
(3) You must calibrate the detection instrument before use on each day of its use by the procedures specified in Method 21 of appendix A-7 of this part.
(4) Calibration gases must be as specified in paragraphs (b)(4)(i) and (ii) of this section.
(i) Zero air (less than 10 parts per million by volume hydrocarbon in air).
(ii) A mixture of methane in air at a concentration less than 10,000 parts per million by volume.
(5) You may choose to adjust or not adjust the detection instrument readings to account for the background organic concentration level. If you choose to adjust the instrument readings for the background level, you must determine the background level value according to the procedures in Method 21 of appendix A-7 of this part.
(6) Your detection instrument must meet the performance criteria specified in paragraphs (b)(6)(i) and (ii) of this section.
(i) Except as provided in paragraph (b)(6)(ii) of this section, the detection instrument must meet the performance criteria of Method 21 of appendix A-7 of this part, except the instrument response factor criteria in section 8.1.1 of Method 21 must be for the average composition of the process fluid, not each individual volatile organic compound in the stream. For process streams that contain nitrogen, air, or other inerts that are not organic hazardous air pollutants or volatile organic compounds, you must calculate the average stream response factor on an inert-free basis.
(ii) If no instrument is available that will meet the performance criteria specified in paragraph (b)(6)(i) of this section, you may adjust the instrument readings by multiplying by the average response factor of the process fluid, calculated on an inert-free basis, as described in paragraph (b)(6)(i) of this section.
(7) You must determine if a potential leak interface operates with no detectable emissions using the applicable procedure specified in paragraph (b)(7)(i) or (ii) of this section.
(i) If you choose not to adjust the detection instrument readings for the background organic concentration level, then you must directly compare the maximum organic concentration value measured by the detection instrument to the applicable value for the potential leak interface as specified in paragraph (b)(8) of this section.
(ii) If you choose to adjust the detection instrument readings for the background organic concentration level, you must compare the value of the arithmetic difference between the maximum organic concentration value measured by the instrument and the background organic concentration value as determined in paragraph (b)(5) of this section with the applicable value for the potential leak interface as specified in paragraph (b)(8) of this section.
(8) A potential leak interface is determined to operate with no detectable organic emissions if the organic concentration value determined in paragraph (b)(7) of this section is less than 500 parts per million by volume.
(9) Repairs. In the event that a leak or defect is detected, you must repair the leak or defect as soon as practicable according to the requirements of paragraphs (b)(9)(i) and (ii) of this section, except as provided in paragraph (b)(10) of this section.
(i) A first attempt at repair must be made no later than 5 calendar days after the leak is detected.
(ii) Repair must be completed no later than 15 calendar days after the leak is detected.
(10) Delay of repair. Delay of repair of a closed vent system or cover for which leaks or defects have been detected is allowed if the repair is technically infeasible without a shutdown, or if you determine that emissions resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of repair. You must complete repair of such equipment by the end of the next shutdown.
(11) Unsafe to inspect requirements. You may designate any parts of the closed vent system or cover as unsafe to inspect if the requirements in paragraphs (b)(11)(i) and (ii) of this section are met. Unsafe to inspect parts are exempt from the inspection requirements of paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment is unsafe to inspect because inspecting personnel would be exposed to an imminent or potential danger as a consequence of complying with paragraphs (a)(1), (2), or (3) of this section.
(ii) You have a written plan that requires inspection of the equipment as frequently as practicable during safe-to-inspect times.
(12) Difficult to inspect requirements. You may designate any parts of the closed vent system or cover as difficult to inspect, if the requirements in paragraphs (b)(12)(i) and (ii) of this section are met. Difficult to inspect parts are exempt from the inspection requirements of paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface.
(ii) You have a written plan that requires inspection of the equipment at least once every 5 years.
(13) Records. Records shall be maintained as specified in this section and in § 60.5420a(c)(9).
(c) Cover and closed vent system inspections for storage vessel affected facilities. If you install a control device or route emissions to a process, you must inspect each closed vent system according to the procedures and schedule specified in paragraphs (c)(1) of this section, inspect each cover according to the procedures and schedule specified in paragraph (c)(2) of this section, and inspect each bypass device according to the procedures of paragraph (c)(3) of this section. You must also comply with the requirements of (c)(4) through (7) of this section.
(1) For each closed vent system, you must conduct an inspection at least once every calendar month as specified in paragraphs (c)(1)(i) through (iii) of this section.
(i) You must maintain records of the inspection results as specified in § 60.5420a(c)(6).
(ii) Conduct olfactory, visual and auditory inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in piping; loose connections; liquid leaks; or broken or missing caps or other closure devices.
(iii) Monthly inspections must be separated by at least 14 calendar days.
(2) For each cover, you must conduct inspections at least once every calendar month as specified in paragraphs (c)(2)(i) through (iii) of this section.
(i) You must maintain records of the inspection results as specified in § 60.5420a(c)(7).
(ii) Conduct olfactory, visual and auditory inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in the cover, or between the cover and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on closure devices; and broken or missing hatches, access covers, caps, or other closure devices. In the case where the storage vessel is buried partially or entirely underground, you must inspect only those portions of the cover that extend to or above the ground surface, and those connections that are on such portions of the cover (e.g., fill ports, access hatches, gauge wells, etc.) and can be opened to the atmosphere.
(iii) Monthly inspections must be separated by at least 14 calendar days.
(3) For each bypass device, except as provided for in § 60.5411a(c)(3)(ii), you must meet the requirements of paragraphs (c)(3)(i) or (ii) of this section.
(i) You must properly install, calibrate and maintain a flow indicator at the inlet to the bypass device that could divert the stream away from the control device or process to the atmosphere. Set the flow indicator to trigger an audible alarm, or initiate notification via remote alarm to the nearest field office, when the bypass device is open such that the stream is being, or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is sounded according to § 60.5420a(c)(8).
(ii) If the bypass device valve installed at the inlet to the bypass device is secured in the non-diverting position using a car-seal or a lock-and-key type configuration, visually inspect the seal or closure mechanism at least once every month to verify that the valve is maintained in the non-diverting position and the vent stream is not diverted through the bypass device. You must maintain records of the inspections and records of each time the key is checked out, if applicable, according to § 60.5420a(c)(8).
(4) Repairs. In the event that a leak or defect is detected, you must repair the leak or defect as soon as practicable according to the requirements of paragraphs (c)(4)(i) through (iii) of this section, except as provided in paragraph (c)(5) of this section.
(i) A first attempt at repair must be made no later than 5 calendar days after the leak is detected.
(ii) Repair must be completed no later than 30 calendar days after the leak is detected.
(iii) Grease or another applicable substance must be applied to deteriorating or cracked gaskets to improve the seal while awaiting repair.
(5) Delay of repair. Delay of repair of a closed vent system or cover for which leaks or defects have been detected is allowed if the repair is technically infeasible without a shutdown, or if you determine that emissions resulting from immediate repair would be greater than the fugitive emissions likely to result from delay of repair. You must complete repair of such equipment by the end of the next shutdown.
(6) Unsafe to inspect requirements. You may designate any parts of the closed vent system or cover as unsafe to inspect if the requirements in paragraphs (c)(6)(i) and (ii) of this section are met. Unsafe to inspect parts are exempt from the inspection requirements of paragraphs (c)(1) and (2) of this section.
(i) You determine that the equipment is unsafe to inspect because inspecting personnel would be exposed to an imminent or potential danger as a consequence of complying with paragraphs (c)(1) or (2) of this section.
(ii) You have a written plan that requires inspection of the equipment as frequently as practicable during safe-to-inspect times.
(7) Difficult to inspect requirements. You may designate any parts of the closed vent system or cover as difficult to inspect, if the requirements in paragraphs (c)(7)(i) and (ii) of this section are met. Difficult to inspect parts are exempt from the inspection requirements of paragraphs (c)(1) and (2) of this section.
(i) You determine that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface.
(ii) You have a written plan that requires inspection of the equipment at least once every 5 years.
§ 60.5417a
What are the continuous control device monitoring requirements for my centrifugal compressor and storage vessel affected facilities?
You must meet the applicable requirements of this section to demonstrate continuous compliance for each control device used to meet emission standards for your storage vessel or centrifugal compressor affected facility.
(a) For each control device used to comply with the emission reduction standard for centrifugal compressor affected facilities in § 60.5380a(a)(1), you must install and operate a continuous parameter monitoring system for each control device as specified in paragraphs (c) through (g) of this section, except as provided for in paragraph (b) of this section. If you install and operate a flare in accordance with § 60.5412a(a)(3), you are exempt from the requirements of paragraphs (e) and (f) of this section. If you install and operate an enclosed combustion device which is not specifically listed in paragraph (d) of this section, you must demonstrate continuous compliance according to paragraphs (h)(1) through (h)(4) of this section.
(b) You are exempt from the monitoring requirements specified in paragraphs (c) through (g) of this section for the control devices listed in paragraphs (b)(1) and (2) of this section.
(1) A boiler or process heater in which all vent streams are introduced with the primary fuel or are used as the primary fuel.
(2) A boiler or process heater with a design heat input capacity equal to or greater than 44 megawatts.
(c) If you are required to install a continuous parameter monitoring system, you must meet the specifications and requirements in paragraphs (c)(1) through (4) of this section.
(1) Each continuous parameter monitoring system must measure data values at least once every hour and record the parameters in paragraphs (c)(1)(i) or (ii) of this section.
(i) Each measured data value.
(ii) Each block average value for each 1-hour period or shorter periods calculated from all measured data values during each period. If values are measured more frequently than once per minute, a single value for each minute may be used to calculate the hourly (or shorter period) block average instead of all measured values.&
(2) You must prepare a site-specific monitoring plan that addresses the monitoring system design, data collection, and the quality assurance and quality control elements outlined in paragraphs (c)(2)(i) through (v) of this section. You must install, calibrate, operate, and maintain each continuous parameter monitoring system in accordance with the procedures in your approved site-specific monitoring plan. Heat sensing monitoring devices that indicate the continuous ignition of a pilot flame are exempt from the calibration, quality assurance and quality control requirements in this section.
(i) The performance criteria and design specifications for the monitoring system equipment, including the sample interface, detector signal analyzer, and data acquisition and calculations.
(ii) Sampling interface (e.g., thermocouple) location such that the monitoring system will provide representative measurements.
(iii) Equipment performance checks, system accuracy audits, or other audit procedures.
(iv) Ongoing operation and maintenance procedures in accordance with provisions in § 60.13(b).
(v) Ongoing reporting and recordkeeping procedures in accordance with provisions in § 60.7(c), (d), and (f).
(3) You must conduct the continuous parameter monitoring system equipment performance checks, system accuracy audits, or other audit procedures specified in the site-specific monitoring plan at least once every 12 months.
(4) You must conduct a performance evaluation of each continuous parameter monitoring system in accordance with the site-specific monitoring plan. Heat sensing monitoring devices that indicate the continuous ignition a pilot flame are exempt from the calibration, quality assurance and quality control requirements in this section.
(d) You must install, calibrate, operate, and maintain a device equipped with a continuous recorder to measure the values of operating parameters appropriate for the control device as specified in paragraph (d)(1), (2), or (3) of this section.
(1) A continuous monitoring system that measures the operating parameters in paragraphs (d)(1)(i) through (viii) of this section, as applicable.
(i) For a thermal vapor incinerator that demonstrates during the performance test conducted under § 60.5413a(b) that combustion zone temperature is an accurate indicator of performance, a temperature monitoring device equipped with a continuous recorder. The monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °Celsius, or ±2.5 °Celsius, whichever value is greater. You must install the temperature sensor at a location representative of the combustion zone temperature.
(ii) For a catalytic vapor incinerator, a temperature monitoring device equipped with a continuous recorder. The device must be capable of monitoring temperature at two locations and have a minimum accuracy of ±1 percent of the temperature being monitored in °Celsius, or ±2.5 °Celsius, whichever value is greater. You must install one temperature sensor in the vent stream at the nearest feasible point to the catalyst bed inlet, and you must install a second temperature sensor in the vent stream at the nearest feasible point to the catalyst bed outlet.
(iii) For a flare, a heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pilot flame. The heat sensing monitoring device is exempt from the calibration requirements of this section.
(iv) For a boiler or process heater, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °Celsius, or ±2.5 °Celsius, whichever value is greater. You must install the temperature sensor at a location representative of the combustion zone temperature.
(v) For a condenser, a temperature monitoring device equipped with a continuous recorder. The temperature monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °Celsius, or ±2.5 °Celsius, whichever value is greater. You must install the temperature sensor at a location in the exhaust vent stream from the condenser.
(vi) For a regenerative-type carbon adsorption system, a continuous monitoring system that meets the specifications in paragraphs (d)(1)(vi)(A) and (B) of this section.
(A) The continuous parameter monitoring system must measure and record the average total regeneration stream mass flow or volumetric flow during each carbon bed regeneration cycle. The flow sensor must have a measurement sensitivity of 5 percent of the flow rate or 10 cubic feet per minute, whichever is greater. You must check the mechanical connections for leakage at least every month, and you must perform a visual inspection at least every 3 months of all components of the flow continuous parameter monitoring system for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if your flow continuous parameter monitoring system is not equipped with a redundant flow sensor; and
(B) The continuous parameter monitoring system must measure and record the average carbon bed temperature for the duration of the carbon bed steaming cycle and measure the actual carbon bed temperature after regeneration and within 15 minutes of completing the cooling cycle. The temperature monitoring device must have a minimum accuracy of ±1 percent of the temperature being monitored in °Celsius, or ±2.5 °Celsius, whichever value is greater.
(vii) For a nonregenerative-type carbon adsorption system, you must monitor the design carbon replacement interval established using a design analysis performed as specified in § 60.5413a(c)(3). The design carbon replacement interval must be based on the total carbon working capacity of the control device and source operating schedule.
(viii) For a combustion control device whose model is tested under § 60.5413a(d), a continuous monitoring system meeting the requirements of paragraphs (d)(1)(viii)(A) and (B) of this section. If you comply with the periodic testing requirements of § 60.5413a(b)(5)(ii), you are not required to continuously monitor the gas flow rate under paragraph (d)(1)(viii)(A) of this section.
(A) The continuous monitoring system must measure gas flow rate at the inlet to the control device. The monitoring instrument must have an accuracy of ±2 percent or better at the maximum expected flow rate. The flow rate at the inlet to the combustion device must not exceed the maximum flow rate determined by the manufacturer.
(B) A monitoring device that continuously indicates the presence of the pilot flame while emissions are routed to the control device.
(2) An organic monitoring device equipped with a continuous recorder that measures the concentration level of organic compounds in the exhaust vent stream from the control device. The monitor must meet the requirements of Performance Specification 8 or 9 of appendix B of this part. You must install, calibrate, and maintain the monitor according to the manufacturer's specifications.
(3) A continuous monitoring system that measures operating parameters other than those specified in paragraph (d)(1) or (2) of this section, upon approval of the Administrator as specified in § 60.13(i).
(e) You must calculate the daily average value for each monitored operating parameter for each operating day, using the data recorded by the monitoring system, except for inlet gas flow rate and data from the heat sensing devices that indicate the presence of a pilot flame. If the emissions unit operation is continuous, the operating day is a 24-hour period. If the emissions unit operation is not continuous, the operating day is the total number of hours of control device operation per 24-hour period. Valid data points must be available for 75 percent of the operating hours in an operating day to compute the daily average.
(f) For each operating parameter monitor installed in accordance with the requirements of paragraph (d) of this section, you must comply with paragraph (f)(1) of this section for all control devices. When condensers are installed, you must also comply with paragraph (f)(2) of this section.
(1) You must establish a minimum operating parameter value or a maximum operating parameter value, as appropriate for the control device, to define the conditions at which the control device must be operated to continuously achieve the applicable performance requirements of § 60.5412a(a)(1) or (2). You must establish each minimum or maximum operating parameter value as specified in paragraphs (f)(1)(i) through (iii) of this section.
(i) If you conduct performance tests in accordance with the requirements of § 60.5413a(b) to demonstrate that the control device achieves the applicable performance requirements specified in § 60.5412a(a)(1) or (2), then you must establish the minimum operating parameter value or the maximum operating parameter value based on values measured during the performance test and supplemented, as necessary, by a condenser design analysis or control device manufacturer recommendations or a combination of both.
(ii) If you use a condenser design analysis in accordance with the requirements of § 60.5413a(c) to demonstrate that the control device achieves the applicable performance requirements specified in § 60.5412a(a)(2), then you must establish the minimum operating parameter value or the maximum operating parameter value based on the condenser design analysis and supplemented, as necessary, by the condenser manufacturer's recommendations.
(iii) If you operate a control device where the performance test requirement was met under § 60.5413a(d) to demonstrate that the control device achieves the applicable performance requirements specified in § 60.5412a(a)(1), then your control device inlet gas flow rate must not exceed the maximum inlet gas flow rate determined by the manufacturer.
(2) If you use a condenser as specified in paragraph (d)(1)(v) of this section, you must establish a condenser performance curve showing the relationship between condenser outlet temperature and condenser control efficiency, according to the requirements of paragraphs (f)(2)(i) and (ii) of this section.
(i) If you conduct a performance test in accordance with the requirements of § 60.5413a(b) to demonstrate that the condenser achieves the applicable performance requirements in § 60.5412a(a)(2), then the condenser performance curve must be based on values measured during the performance test and supplemented as necessary by control device design analysis, or control device manufacturer's recommendations, or a combination or both.
(ii) If you use a control device design analysis in accordance with the requirements of § 60.5413a(c)(1) to demonstrate that the condenser achieves the applicable performance requirements specified in § 60.5412a(a)(2), then the condenser performance curve must be based on the condenser design analysis and supplemented, as necessary, by the control device manufacturer's recommendations.
(g) A deviation for a given control device is determined to have occurred when the monitoring data or lack of monitoring data result in any one of the criteria specified in paragraphs (g)(1) through (6) of this section being met. If you monitor multiple operating parameters for the same control device during the same operating day and more than one of these operating parameters meets a deviation criterion specified in paragraphs (g)(1) through (6) of this section, then a single excursion is determined to have occurred for the control device for that operating day.
(1) A deviation occurs when the daily average value of a monitored operating parameter is less than the minimum operating parameter limit (or, if applicable, greater than the maximum operating parameter limit) established in paragraph (f)(1) of this section or when the heat sensing device indicates that there is no pilot flame present.
(2) If you are subject to § 60.5412a(a)(2), a deviation occurs when the 365-day average condenser efficiency calculated according to the requirements specified in § 60.5415a(b)(2)(viii)(D) is less than 95.0 percent.
(3) If you are subject to § 60.5412a(a)(2) and you have less than 365 days of data, a deviation occurs when the average condenser efficiency calculated according to the procedures specified in § 60.5415a(b)(2)(viii)(D)( 1 ) or ( 2 ) is less than 95.0 percent.
(4) A deviation occurs when the monitoring data are not available for at least 75 percent of the operating hours in a day.
(5) If the closed vent system contains one or more bypass devices that could be used to divert all or a portion of the gases, vapors, or fumes from entering the control device, a deviation occurs when the requirements of paragraph (g)(5)(i) or (ii) of this section are met.
(i) For each bypass line subject to § 60.5411a(a)(3)(i)(A), the flow indicator indicates that flow has been detected and that the stream has been diverted away from the control device to the atmosphere.
(ii) For each bypass line subject to § 60.5411a(a)(3)(i)(B), if the seal or closure mechanism has been broken, the bypass line valve position has changed, the key for the lock-and-key type lock has been checked out, or the car-seal has broken.
(6) For a combustion control device whose model is tested under § 60.5413a(d), a deviation occurs when the conditions of paragraphs (g)(6)(i) or (ii) of this section are met.
(i) The inlet gas flow rate exceeds the maximum established during the test conducted under § 60.5413a(d).
(ii) Failure of the monthly visible emissions test conducted under § 60.5413a(e)(3) occurs.
(h) For each control device used to comply with the emission reduction standard in § 60.5395a(a)(2) for your storage vessel affected facility, you must demonstrate continuous compliance according to paragraphs (h)(1) through (h)(4) of this section. You are exempt from the requirements of this paragraph if you install a control device model tested in accordance with § 60.5413a(d)(2) through (10), which meets the criteria in § 60.5413a(d)(11), the reporting requirement in § 60.5413a(d)(12), and meet the continuous compliance requirement in § 60.5413a(e).
(1) For each combustion device you must conduct inspections at least once every calendar month according to paragraphs (h)(1)(i) through (iv) of this section. Monthly inspections must be separated by at least 14 calendar days.
(i) Conduct visual inspections to confirm that the pilot is lit when vapors are being routed to the combustion device and that the continuous burning pilot flame is operating properly.
(ii) Conduct inspections to monitor for visible emissions from the combustion device using section 11 of EPA Method 22 of appendix A of this part. The observation period shall be 15 minutes. Devices must be operated with no visible emissions, except for periods not to exceed a total of 1 minute during any 15 minute period.
(iii) Conduct olfactory, visual and auditory inspections of all equipment associated with the combustion device to ensure system integrity.
(iv) For any absence of the pilot flame, or other indication of smoking or improper equipment operation ( e.g., visual, audible, or olfactory), you must ensure the equipment is returned to proper operation as soon as practicable after the event occurs. At a minimum, you must perform the procedures specified in paragraphs (h)(1)(iv)(A) and (B) of this section.
(A) You must check the air vent for obstruction. If an obstruction is observed, you must clear the obstruction as soon as practicable.
(B) You must check for liquid reaching the combustor.
(2) For each vapor recovery device, you must conduct inspections at least once every calendar month to ensure physical integrity of the control device according to the manufacturer's instructions. Monthly inspections must be separated by at least 14 calendar days.
(3) Each control device must be operated following the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions. Records of the manufacturer's written operating instructions, procedures, and maintenance schedule must be available for inspection as specified in § 60.5420a(c)(13).
(4) Conduct a periodic performance test no later than 60 months after the initial performance test as specified in § 60.5413a(b)(5)(ii) and conduct subsequent periodic performance tests at intervals no longer than 60 months following the previous periodic performance test.
§ 60.5420a
What are my notification, reporting, and recordkeeping requirements?
(a) You must submit the notifications according to paragraphs (a)(1) and (2) of this section if you own or operate one or more of the affected facilities specified in § 60.5365a that was constructed, modified or reconstructed during the reporting period.
(1) If you own or operate an affected facility that is the group of all equipment within a process unit at an onshore natural gas processing plant, or a sweetening unit at an onshore natural gas processing plant, you must submit the notifications required in § 60.7(a)(1), (3), and (4). If you own or operate a well, centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump, storage vessel, or collection of fugitive emissions components at a well site or collection of fugitive emissions components at a compressor station, you are not required to submit the notifications required in § 60.7(a)(1), (3), and (4).
(2)(i) If you own or operate a well affected facility, you must submit a notification to the Administrator no later than 2 days prior to the commencement of each well completion operation listing the anticipated date of the well completion operation. The notification shall include contact information for the owner or operator; the United States Well Number; the latitude and longitude coordinates for each well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of 1983; and the planned date of the beginning of flowback. You may submit the notification in writing or in electronic format.
(ii) If you are subject to state regulations that require advance notification of well completions and you have met those notification requirements, then you are considered to have met the advance notification requirements of paragraph (a)(2)(i) of this section.
(b) Reporting requirements. You must submit annual reports containing the information specified in paragraphs (b)(1) through (8) and (12) of this section and performance test reports as specified in paragraph (b)(9) or (10) of this section, if applicable. You must submit annual reports following the procedure specified in paragraph (b)(11) of this section. The initial annual report is due no later than 90 days after the end of the initial compliance period as determined according to § 60.5410a. Subsequent annual reports are due no later than same date each year as the initial annual report. If you own or operate more than one affected facility, you may submit one report for multiple affected facilities provided the report contains all of the information required as specified in paragraphs (b)(1) through (8) of this section. Annual reports may coincide with title V reports as long as all the required elements of the annual report are included. You may arrange with the Administrator a common schedule on which reports required by this part may be submitted as long as the schedule does not extend the reporting period.
(1) The general information specified in paragraphs (b)(1)(i) through (iv) of this section for all reports.
(i) The company name, facility site name associated with the affected facility, US Well ID or US Well ID associated with the affected facility, if applicable, and address of the affected facility. If an address is not available for the site, include a description of the site location and provide the latitude and longitude coordinates of the site in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of 1983.
(ii) An identification of each affected facility being included in the annual report.
(iii) Beginning and ending dates of the reporting period.
(iv) A certification by a certifying official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete.
(2) For each well affected facility, the information in paragraphs (b)(2)(i) through (iii) of this section.
(i) Records of each well completion operation as specified in paragraphs (c)(1)(i) through (iv) and (vi) of this section, if applicable, for each well affected facility conducted during the reporting period. In lieu of submitting the records specified in paragraph (c)(1)(i) through (iv) of this section, the owner or operator may submit a list of the well completions with hydraulic fracturing completed during the reporting period and the records required by paragraph (c)(1)(v) of this section for each well completion.
(ii) Records of deviations specified in paragraph (c)(1)(ii) of this section that occurred during the reporting period.
(iii) Records specified in paragraph (c)(1)(vii) of this section, if applicable, that support a determination under 60.5432a that the well affected facility is a low pressure well as defined in 60.5430a.
(3) For each centrifugal compressor affected facility, the information specified in paragraphs (b)(3)(i) through (iv) of this section.
(i) An identification of each centrifugal compressor using a wet seal system constructed, modified or reconstructed during the reporting period.
(ii) Records of deviations specified in paragraph (c)(2) of this section that occurred during the reporting period.
(iii) If required to comply with § 60.5380a(a)(2), the records specified in paragraphs (c)(6) through (11) of this section.
(iv) If complying with § 60.5380a(a)(1) with a control device tested under § 60.5413a(d) which meets the criteria in § 60.5413a(d)(11) and § 60.5413a(e), records specified in paragraph (c)(2)(i) through (c)(2)(vii) of this section for each centrifugal compressor using a wet seal system constructed, modified or reconstructed during the reporting period.
(4) For each reciprocating compressor affected facility, the information specified in paragraphs (b)(4)(i) and (ii) of this section.
(i) The cumulative number of hours of operation or the number of months since initial startup or since the previous reciprocating compressor rod packing replacement, whichever is later. Alternatively, a statement that emissions from the rod packing are being routed to a process through a closed vent system under negative pressure.
(ii) Records of deviations specified in paragraph (c)(3)(iii) of this section that occurred during the reporting period.
(5) For each pneumatic controller affected facility, the information specified in paragraphs (b)(5)(i) through (iii) of this section.
(i) An identification of each pneumatic controller constructed, modified or reconstructed during the reporting period, including the identification information specified in § 60.5390a(b)(2) or (c)(2).
(ii) If applicable, documentation that the use of pneumatic controller affected facilities with a natural gas bleed rate greater than 6 standard cubic feet per hour are required and the reasons why.
(iii) Records of deviations specified in paragraph (c)(4)(v) of this section that occurred during the reporting period.
(6) For each storage vessel affected facility, the information in paragraphs (b)(6)(i) through (vii) of this section.
(i) An identification, including the location, of each storage vessel affected facility for which construction, modification or reconstruction commenced during the reporting period. The location of the storage vessel shall be in latitude and longitude coordinates in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of 1983.
(ii) Documentation of the VOC emission rate determination according to § 60.5365a(e) for each storage vessel that became an affected facility during the reporting period or is returned to service during the reporting period.
(iii) Records of deviations specified in paragraph (c)(5)(iii) of this section that occurred during the reporting period.
(iv) A statement that you have met the requirements specified in § 60.5410a(h)(2) and (3).
(v) You must identify each storage vessel affected facility that is removed from service during the reporting period as specified in § 60.5395a(c)(1)(ii), including the date the storage vessel affected facility was removed from service.
(vi) You must identify each storage vessel affected facility returned to service during the reporting period as specified in § 60.5395a(c)(3), including the date the storage vessel affected facility was returned to service.
(vii) If complying with § 60.5395a(a)(2) with a control device tested under § 60.5413a(d) which meets the criteria in § 60.5413a(d)(11) and § 60.5413a(e), records specified in paragraphs (c)(5)(vi)(A) through (F) of this section for each storage vessel constructed, modified, reconstructed or returned to service during the reporting period.
(7) For the collection of fugitive emissions components at each well site and the collection of fugitive emissions components at each compressor station within the company-defined area, the records of each monitoring survey including the information specified in paragraphs (b)(7)(i) through (xii) of this section. For the collection of fugitive emissions components at a compressor station, if a monitoring survey is waived under § 60.5397a(g)(5), you must include in your annual report the fact that a monitoring survey was waived and the calendar months that make up the quarterly monitoring period for which the monitoring survey was waived.
(i) Date of the survey.
(ii) Beginning and end time of the survey.
(iii) Name of operator(s) performing survey. If the survey is performed by optical gas imaging, you must note the training and experience of the operator.
(iv) Ambient temperature, sky conditions, and maximum wind speed at the time of the survey.
(v) Monitoring instrument used.
(vi) Any deviations from the monitoring plan or a statement that there were no deviations from the monitoring plan.
(vii) Number and type of components for which fugitive emissions were detected.
(viii) Number and type of fugitive emissions components that were not repaired as required in § 60.5397a(h).
(ix) Number and type of difficult-to-monitor and unsafe-to-monitor fugitive emission components monitored.
(x) The date of successful repair of the fugitive emissions component.
(xi) Number and type of fugitive emission components placed on delay of repair and explanation for each delay of repair.
(xii) Type of instrument used to resurvey a repaired fugitive emissions component that could not be repaired during the initial fugitive emissions finding.
(8) For each pneumatic pump affected facility, the information specified in paragraphs (b)(8)(i) through (iii) of this section.
(i) For each pneumatic pump that is constructed, modified or reconstructed during the reporting period, you must provide certification that the pneumatic pump meets one of the conditions described in paragraphs (b)(8)(i)(A), (B) or (C) of this section.
(A) No control device or process is available on site.
(B) A control device or process is available on site and the owner or operator has determined in accordance with § 60.5393a(b)(5) that it is technically infeasible to capture and route the emissions to the control device or process.
(C) Emissions from the pneumatic pump are routed to a control device or process. If the control device is designed to achieve less than 95 percent emissions reduction, specify the percent emissions reductions the control device is designed to achieve.
(ii) For any pneumatic pump affected facility which has been previously reported as required under paragraph (b)(8)(i) of this section and for which a change in the reported condition has occurred during the reporting period, provide the identification of the pneumatic pump affected facility and the date it was previously reported and a certification that the pneumatic pump meets one of the conditions described in paragraphs (b)(8)(ii)(A), (B) or (C) or (D) of this section.
(A) A control device has been added to the location and the pneumatic pump now reports according to paragraph (b)(8)(i)(C) of this section.
(B) A control device has been added to the location and the pneumatic pump affected facility now reports according to paragraph (b)(8)(i)(B) of this section.
(C) A control device or process has been removed from the location or otherwise is no longer available and the pneumatic pump affected facility now report according to paragraph (b)(8)(i)(A) of this section.
(D) A control device or process has been removed from the location or is otherwise no longer available and the owner or operator has determined in accordance with § 60.5393a(b)(5) through an engineering evaluation that it is technically infeasible to capture and route the emissions to another control device or process.
(iii) Records of deviations specified in paragraph (c)(16)(ii) of this section that occurred during the reporting period.
(9) Within 60 days after the date of completing each performance test (see § 60.8) required by this subpart, except testing conducted by the manufacturer as specified in § 60.5413a(d), you must submit the results of the performance test following the procedure specified in either paragraph (b)(9)(i) or (ii) of this section.
(i) For data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site ( https://www3.epa.gov/ttn/chief/ert/ert_info.html ) at the time of the test, you must submit the results of the performance test to the EPA via the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/) .) Performance test data must be submitted in a file format generated through the use of the EPA's ERT or an alternate electronic file format consistent with the extensible markup language (XML) schema listed on the EPA's ERT Web site. If you claim that some of the performance test information being submitted is confidential business information (CBI), you must submit a complete file generated through the use of the EPA's ERT or an alternate electronic file consistent with the XML schema listed on the EPA's ERT Web site, including information claimed to be CBI, on a compact disc, flash drive, or other commonly used electronic storage media to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA's CDX as described earlier in this paragraph.
(ii) For data collected using test methods that are not supported by the EPA's ERT as listed on the EPA's ERT Web site at the time of the test, you must submit the results of the performance test to the Administrator at the appropriate address listed in § 60.4.
(10) For combustion control devices tested by the manufacturer in accordance with § 60.5413a(d), an electronic copy of the performance test results required by § 60.5413a(d) shall be submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test results for that model of combustion control device are posted at the following Web site: epa.gov/airquality/oilandgas/ .
(11) You must submit reports to the EPA via the CEDRI. (CEDRI can be accessed through the EPA's CDX ( https://cdx.epa.gov/) .) You must use the appropriate electronic report in CEDRI for this subpart or an alternate electronic file format consistent with the extensible markup language (XML) schema listed on the CEDRI Web site ( https://www3.epa.gov/ttn/chief/cedri/ ). If the reporting form specific to this subpart is not available in CEDRI at the time that the report is due, you must submit the report to the Administrator at the appropriate address listed in § 60.4. Once the form has been available in CEDRI for at least 90 calendar days, you must begin submitting all subsequent reports via CEDRI. The reports must be submitted by the deadlines specified in this subpart, regardless of the method in which the reports are submitted.
(12) You must submit the certification signed by the qualified professional engineer according to § 60.5411a(d) for each closed vent system routing to a control device or process.
(c) Recordkeeping requirements . You must maintain the records identified as specified in § 60.7(f) and in paragraphs (c)(1) through (16) of this section. All records required by this subpart must be maintained either onsite or at the nearest local field office for at least 5 years. Any records required to be maintained by this subpart that are submitted electronically via the EPA's CDX may be maintained in electronic format.
(1) The records for each well affected facility as specified in paragraphs (c)(1)(i) through (vii) of this section, as applicable. For each well affected facility for which you make a claim that the well affected facility is not subject to the requirements for well completions pursuant to 60.5375a(g), you must maintain the record in paragraph (c)(1)(vi), only.
(i) Records identifying each well completion operation for each well affected facility;
(ii) Records of deviations in cases where well completion operations with hydraulic fracturing were not performed in compliance with the requirements specified in § 60.5375a.
(iii) Records required in § 60.5375a(b) or (f)(3) for each well completion operation conducted for each well affected facility that occurred during the reporting period. You must maintain the records specified in paragraphs (c)(1)(iii)(A) through (C) of this section.
(A) For each well affected facility required to comply with the requirements of § 60.5375a(a), you must record: The location of the well; the United States Well Number; the date and time of the onset of flowback following hydraulic fracturing or refracturing; the date and time of each attempt to direct flowback to a separator as required in § 60.5375a(a)(1)(ii); the date and time of each occurrence of returning to the initial flowback stage under § 60.5375a(a)(1)(i); and the date and time that the well was shut in and the flowback equipment was permanently disconnected, or the startup of production; the duration of flowback; duration of recovery and disposition of recovery ( i.e., routed to the gas flow line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for another useful purpose that a purchased fuel or raw material would serve); duration of combustion; duration of venting; and specific reasons for venting in lieu of capture or combustion. The duration must be specified in hours. In addition, for wells where it is technically infeasible to route the recovered gas to any of the four options specified in § 60.5375a(a)(1)(ii), you must record the reasons for the claim of technical infeasibility with respect to all four options provided in that subparagraph, including but not limited to; name and location of the nearest gathering line and technical considerations preventing routing to this line; capture, reinjection, and reuse technologies considered and aspects of gas or equipment preventing use of recovered gas as a fuel onsite; and technical considerations preventing use of recovered gas for other useful purpose that that a purchased fuel or raw material would serve.
(B) For each well affected facility required to comply with the requirements of § 60.5375a(f), you must maintain the records specified in paragraph (c)(1)(iii)(A) of this section except that you do not have to record the duration of recovery to the flow line.
(C) For each well affected facility for which you make a claim that it meets the criteria of § 60.5375a(a)(1)(iii)(A), you must maintain the following:
( 1 ) Records specified in paragraph (c)(1)(iii)(A) of this section except that you do not have to record: The date and time of each attempt to direct flowback to a separator; the date and time of each occurrence of returning to the initial flowback stage; duration of recovery and disposition of recovery ( i.e. routed to the gas flow line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for another useful purpose that a purchased fuel or raw material would serve.
( 2 ) If applicable, records that the conditions of § 60.5375a(1)(iii)(A) are no longer met and that the well completion operation has been stopped and a separator installed. The records shall include the date and time the well completion operation was stopped and the date and time the separator was installed.
( 3 ) A record of the claim signed by the certifying official that no liquids collection is at the well site. The claim must include a certification by a certifying official of truth, accuracy and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete.
(iv) For each well affected facility for which you claim an exception under § 60.5375a(a)(3), you must record: The location of the well; the United States Well Number; the specific exception claimed; the starting date and ending date for the period the well operated under the exception; and an explanation of why the well meets the claimed exception.
(v) For each well affected facility required to comply with both § 60.5375a(a)(1) and (3), if you are using a digital photograph in lieu of the records required in paragraphs (c)(1)(i) through (iv) of this section, you must retain the records of the digital photograph as specified in § 60.5410a(a)(4).
(vi) For each well affected facility for which you make a claim that the well affected facility is not subject to the well completion standards according to 60.5375a(g), you must maintain:
(A) A record of the analysis that was performed in order the make that claim, including but not limited to, GOR values for established leases and data from wells in the same basin and field;
(B) The location of the well; the United States Well Number;
(C) A record of the claim signed by the certifying official. The claim must include a certification by a certifying official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete.
(vii) For each well affected facility for which you determine according to § 60.5432a that it is a low pressure well, a record of the determination and supporting inputs and calculations.
(2) For each centrifugal compressor affected facility, you must maintain records of deviations in cases where the centrifugal compressor was not operated in compliance with the requirements specified in § 60.5380a. Except as specified in paragraph (c)(2)(vii) of this section, you must maintain the records in paragraphs (c)(2)(i) through (vi) of this section for each control device tested under § 60.5413a(d) which meets the criteria in § 60.5413a(d)(11) and § 60.5413a(e) and used to comply with § 60.5380a(a)(1) for each centrifugal compressor.
(i) Make, model and serial number of purchased device.
(ii) Date of purchase.
(iii) Copy of purchase order.
(iv) Location of the centrifugal compressor and control device in latitude and longitude coordinates in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of 1983.
(v) Inlet gas flow rate.
(vi) Records of continuous compliance requirements in § 60.5413a(e) as specified in paragraphs (c)(2)(vi)(A) through (E) of this section.
(A) Records that the pilot flame is present at all times of operation.
(B) Records that the device was operated with no visible emissions except for periods not to exceed a total of 1 minute during any 15 minute period.
(C) Records of the maintenance and repair log.
(D) Records of the visible emissions test following return to operation from a maintenance or repair activity.
(E) Records of the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions.
(vii) As an alternative to the requirements of paragraph (c)(2)(iv) of this section, you may maintain records of one or more digital photographs with the date the photograph was taken and the latitude and longitude of the centrifugal compressor and control device imbedded within or stored with the digital file. As an alternative to imbedded latitude and longitude within the digital photograph, the digital photograph may consist of a photograph of the centrifugal compressor and control device with a photograph of a separately operating GPS device within the same digital picture, provided the latitude and longitude output of the GPS unit can be clearly read in the digital photograph.
(3) For each reciprocating compressor affected facility, you must maintain the records in paragraphs (c)(3)(i) through (iii) of this section.
(i) Records of the cumulative number of hours of operation or number of months since initial startup or the previous replacement of the reciprocating compressor rod packing, whichever is later. Alternatively, a statement that emissions from the rod packing are being routed to a process through a closed vent system under negative pressure.
(ii) Records of the date and time of each reciprocating compressor rod packing replacement, or date of installation of a rod packing emissions collection system and closed vent system as specified in § 60.5385a(a)(3).
(iii) Records of deviations in cases where the reciprocating compressor was not operated in compliance with the requirements specified in § 60.5385a.
(4) For each pneumatic controller affected facility, you must maintain the records identified in paragraphs (c)(4)(i) through (v) of this section, as applicable.
(i) Records of the date, location and manufacturer specifications for each pneumatic controller constructed, modified or reconstructed.
(ii) Records of the demonstration that the use of pneumatic controller affected facilities with a natural gas bleed rate greater than the applicable standard are required and the reasons why.
(iii) If the pneumatic controller is not located at a natural gas processing plant, records of the manufacturer's specifications indicating that the controller is designed such that natural gas bleed rate is less than or equal to 6 standard cubic feet per hour.
(iv) If the pneumatic controller is located at a natural gas processing plant, records of the documentation that the natural gas bleed rate is zero.
(v) Records of deviations in cases where the pneumatic controller was not operated in compliance with the requirements specified in § 60.5390a.
(5) For each storage vessel affected facility, you must maintain the records identified in paragraphs (c)(5)(i) through (vi) of this section.
(i) If required to reduce emissions by complying with § 60.5395a(a)(2), the records specified in §§ 60.5420a(c)(6) through (8), 60.5416a(c)(6)(ii), and 60.5416a(c)(7)(ii). You must maintain the records in paragraph (c)(5)(vi) of this part for each control device tested under § 60.5413a(d) which meets the criteria in § 60.5413a(d)(11) and § 60.5413a(e) and used to comply with § 60.5395a(a)(2) for each storage vessel.
(ii) Records of each VOC emissions determination for each storage vessel affected facility made under § 60.5365a(e) including identification of the model or calculation methodology used to calculate the VOC emission rate.
(iii) Records of deviations in cases where the storage vessel was not operated in compliance with the requirements specified in §§ 60.5395a, 60.5411a, 60.5412a, and 60.5413a, as applicable.
(iv) For storage vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), records indicating the number of consecutive days that the vessel is located at a site in the oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment. If a storage vessel is removed from a site and, within 30 days, is either returned to the site or replaced by another storage vessel at the site to serve the same or similar function, then the entire period since the original storage vessel was first located at the site, including the days when the storage vessel was removed, will be added to the count towards the number of consecutive days.
(v) You must maintain records of the identification and location of each storage vessel affected facility.
(vi) Except as specified in paragraph (c)(5)(vi)(G) of this section, you must maintain the records specified in paragraphs (c)(5)(vi)(A) through (F) of this section for each control device tested under § 60.5413a(d) which meets the criteria in § 60.5413a(d)(11) and § 60.5413a(e) and used to comply with § 60.5395a(a)(2) for each storage vessel.
(A) Make, model and serial number of purchased device.
(B) Date of purchase.
(C) Copy of purchase order.
(D) Location of the control device in latitude and longitude coordinates in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of 1983.
(E) Inlet gas flow rate.
(F) Records of continuous compliance requirements in § 60.5413a(e) as specified in paragraphs (c)(5)(vi)(F)( 1 ) through ( 5 ) of this section.
( 1 ) Records that the pilot flame is present at all times of operation.
( 2 ) Records that the device was operated with no visible emissions except for periods not to exceed a total of 1 minute during any 15 minute period.
( 3 ) Records of the maintenance and repair log.
( 4 ) Records of the visible emissions test following return to operation from a maintenance or repair activity.
( 5 ) Records of the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions.
(G) As an alternative to the requirements of paragraph (c)(5)(vi)(D) of this section, you may maintain records of one or more digital photographs with the date the photograph was taken and the latitude and longitude of the storage vessel and control device imbedded within or stored with the digital file. As an alternative to imbedded latitude and longitude within the digital photograph, the digital photograph may consist of a photograph of the storage vessel and control device with a photograph of a separately operating GPS device within the same digital picture, provided the latitude and longitude output of the GPS unit can be clearly read in the digital photograph.
(6) Records of each closed vent system inspection required under § 60.5416a(a)(1) and (2) for centrifugal compressors, reciprocating compressors and pneumatic pumps, or § 60.5416a(c)(1) for storage vessels.
(7) A record of each cover inspection required under § 60.5416a(a)(3) for centrifugal or reciprocating compressors or § 60.5416a(c)(2) for storage vessels.
(8) If you are subject to the bypass requirements of § 60.5416a(a)(4) for centrifugal compressors, reciprocating compressors or pneumatic pumps, or § 60.5416a(c)(3) for storage vessels, a record of each inspection or a record of each time the key is checked out or a record of each time the alarm is sounded.
(9) If you are subject to the closed vent system no detectable emissions requirements of § 60.5416a(b) for centrifugal compressors, reciprocating compressors or pneumatic pumps, a record of the monitoring conducted in accordance with § 60.5416a(b).
(10) For each centrifugal compressor or pneumatic pump affected facility, records of the schedule for carbon replacement (as determined by the design analysis requirements of § 60.5413a(c)(2) or (3)) and records of each carbon replacement as specified in § 60.5412a(c)(1).
(11) For each centrifugal compressor affected facility subject to the control device requirements of § 60.5412a(a), (b), and (c), records of minimum and maximum operating parameter values, continuous parameter monitoring system data, calculated averages of continuous parameter monitoring system data, results of all compliance calculations, and results of all inspections.
(12) For each carbon adsorber installed on storage vessel affected facilities, records of the schedule for carbon replacement (as determined by the design analysis requirements of § 60.5412a(d)(2)) and records of each carbon replacement as specified in § 60.5412a(c)(1).
(13) For each storage vessel affected facility subject to the control device requirements of § 60.5412a(c) and (d), you must maintain records of the inspections, including any corrective actions taken, the manufacturers' operating instructions, procedures and maintenance schedule as specified in § 60.5417a(h)(3). You must maintain records of EPA Method 22 of appendix A-7 of this part, section 11 results, which include: Company, location, company representative (name of the person performing the observation), sky conditions, process unit (type of control device), clock start time, observation period duration (in minutes and seconds), accumulated emission time (in minutes and seconds), and clock end time. You may create your own form including the above information or use Figure 22-1 in EPA Method 22 of appendix A-7 of this part. Manufacturer's operating instructions, procedures and maintenance schedule must be available for inspection.
(14) A log of records as specified in § 60.5412a(d)(1)(iii), for all inspection, repair and maintenance activities for each control device failing the visible emissions test.
(15) For each collection of fugitive emissions components at a well site and each collection of fugitive emissions components at a compressor station, the records identified in paragraphs (c)(15)(i) through (iii) of this section.
(i) The fugitive emissions monitoring plan as required in § 60.5397a(b), (c), and (d).
(ii) The records of each monitoring survey as specified in paragraphs (c)(15)(ii)(A) through (I) of this section.
(A) Date of the survey.
(B) Beginning and end time of the survey.
(C) Name of operator(s) performing survey. You must note the training and experience of the operator.
(D) Monitoring instrument used.
(E) When optical gas imaging is used to perform the survey, one or more digital photographs or videos, captured from the optical gas imaging instrument used for conduct of monitoring, of each required monitoring survey being performed. The digital photograph must include the date the photograph was taken and the latitude and longitude of the collection of fugitive emissions components at a well site or collection of fugitive emissions components at a compressor station imbedded within or stored with the digital file. As an alternative to imbedded latitude and longitude within the digital file, the digital photograph or video may consist of an image of the monitoring survey being performed with a separately operating GPS device within the same digital picture or video, provided the latitude and longitude output of the GPS unit can be clearly read in the digital image.
(F) Fugitive emissions component identification when Method 21 is used to perform the monitoring survey.
(G) Ambient temperature, sky conditions, and maximum wind speed at the time of the survey.
(H) Any deviations from the monitoring plan or a statement that there were no deviations from the monitoring plan.
(I) Documentation of each fugitive emission, including the information specified in paragraphs (c)(15)(ii)(I)( 1 ) through ( 12 ) of this section.
( 1 ) Location.
( 2 ) Any deviations from the monitoring plan or a statement that there were no deviations from the monitoring plan.
( 3 ) Number and type of components for which fugitive emissions were detected.
( 4 ) Number and type of difficult-to-monitor and unsafe-to-monitor fugitive emission components monitored.
( 5 ) Instrument reading of each fugitive emissions component that requires repair when Method 21 is used for monitoring.
( 6 ) Number and type of fugitive emissions components that were not repaired as required in § 60.5397a(h).
( 7 ) Number and type of components that were tagged as a result of not being repaired during the monitoring survey when the fugitive emissions were initially found as required in § 60.5397a(h)(3)(ii).
( 8 ) If a fugitive emissions component is not tagged, a digital photograph or video of each fugitive emissions component that could not be repaired during the monitoring survey when the fugitive emissions were initially found as required in § 60.5397a(h)(3)(ii). The digital photograph or video must clearly identify the location of the component that must be repaired. Any digital photograph or video required under this paragraph can also be used to meet the requirements under paragraph (c)(15)(ii)(E) of this section, as long as the photograph or video is taken with the optical gas imaging instrument, includes the date and the latitude and longitude are either imbedded or visible in the picture.
( 9 ) Repair methods applied in each attempt to repair the fugitive emissions components.
( 10 ) Number and type of fugitive emission components placed on delay of repair and explanation for each delay of repair.
( 11 ) The date of successful repair of the fugitive emissions component.
( 12 ) Instrumentation used to resurvey a repaired fugitive emissions component that could not be repaired during the initial fugitive emissions finding.
(iii) For the collection of fugitive emissions components at a compressor station, if a monitoring survey is waived under § 60.5397a(g)(5), you must maintain records of the average calendar month temperature, including the source of the information, for each calendar month of the quarterly monitoring period for which the monitoring survey was waived.
(16) For each pneumatic pump affected facility, you must maintain the records identified in paragraphs (c)(16)(i) through (v) of this section.
(i) Records of the date, location and manufacturer specifications for each pneumatic pump constructed, modified or reconstructed.
(ii) Records of deviations in cases where the pneumatic pump was not operated in compliance with the requirements specified in § 60.5393a.
(iii) Records on the control device used for control of emissions from a pneumatic pump including the installation date, manufacturer's specifications, and if the control device is designed to achieve less than 95 percent emission reduction, a design evaluation or manufacturer's specifications indicating the percentage reduction achieved the control device is designed to achieve.
(iv) Records substantiating a claim according to § 60.5393a(b)(5) that it is technically infeasible to capture and route emissions from a pneumatic pump to a control device or process; including the qualified professional engineer certification according to § 60.5393a(b)(5)(ii)and the records of the engineering assessment of technical infeasibility performed according to § 60.5393a(b)(5)(iii).
(v) You must retain copies of all certifications, engineering assessments and related records for a period of five years and make them available if directed by the implementing agency.
(17) For each closed vent system routing to a control device or process, the records of the assessment conducted according to § 60.5411a(d):
(i) A copy of the assessment conducted according to § 60.5411a(d)(1);
(ii) A copy of the certification according to § 60.5411a(d)(1)(i); and
(iii) The owner or operator shall retain copies of all certifications, assessments and any related records for a period of five years, and make them available if directed by the delegated authority.
§ 60.5421a
What are my additional recordkeeping requirements for my affected facility subject to GHG and VOC requirements for onshore natural gas processing plants?
(a) You must comply with the requirements of paragraph (b) of this section in addition to the requirements of § 60.486a.
(b) The following recordkeeping requirements apply to pressure relief devices subject to the requirements of § 60.5401a(b)(1).
(1) When each leak is detected as specified in § 60.5401a(b)(2), a weatherproof and readily visible identification, marked with the equipment identification number, must be attached to the leaking equipment. The identification on the pressure relief device may be removed after it has been repaired.
(2) When each leak is detected as specified in § 60.5401a(b)(2), the information specified in paragraphs (b)(2)(i) through (x) of this section must be recorded in a log and shall be kept for 2 years in a readily accessible location:
(i) The instrument and operator identification numbers and the equipment identification number.
(ii) The date the leak was detected and the dates of each attempt to repair the leak.
(iii) Repair methods applied in each attempt to repair the leak.
(iv) “Above 500 ppm” if the maximum instrument reading measured by the methods specified in § 60.5400a(d) after each repair attempt is 500 ppm or greater.
(v) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of the leak.
(vi) The signature of the owner or operator (or designate) whose decision it was that repair could not be effected without a process shutdown.
(vii) The expected date of successful repair of the leak if a leak is not repaired within 15 days.
(viii) Dates of process unit shutdowns that occur while the equipment is unrepaired.
(ix) The date of successful repair of the leak.
(x) A list of identification numbers for equipment that are designated for no detectable emissions under the provisions of § 60.482-4a(a). The designation of equipment subject to the provisions of § 60.482-4a(a) must be signed by the owner or operator.
§ 60.5422a
What are my additional reporting requirements for my affected facility subject to GHG and VOC requirements for onshore natural gas processing plants?
(a) You must comply with the requirements of paragraphs (b) and (c) of this section in addition to the requirements of § 60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). You must submit semiannual reports to the EPA via the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/ ).) Use the appropriate electronic report in CEDRI for this subpart or an alternate electronic file format consistent with the extensible markup language (XML) schema listed on the CEDRI Web site ( https://www3.epa.gov/ttn/chief/cedri/ ). If the reporting form specific to this subpart is not available in CEDRI at the time that the report is due, submit the report to the Administrator at the appropriate address listed in § 60.4. Once the form has been available in CEDRI for at least 90 days, you must begin submitting all subsequent reports via CEDRI. The report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted.
(b) An owner or operator must include the following information in the initial semiannual report in addition to the information required in § 60.487a(b)(1) through (4): Number of pressure relief devices subject to the requirements of § 60.5401a(b) except for those pressure relief devices designated for no detectable emissions under the provisions of § 60.482-4a(a) and those pressure relief devices complying with § 60.482-4a(c).
(c) An owner or operator must include the information specified in paragraphs (c)(1) and (2) of this section in all semiannual reports in addition to the information required in § 60.487a(c)(2)(i) through (vi):
(1) Number of pressure relief devices for which leaks were detected as required in § 60.5401a(b)(2); and
(2) Number of pressure relief devices for which leaks were not repaired as required in § 60.5401a(b)(3).
§ 60.5423a
What additional recordkeeping and reporting requirements apply to my sweetening unit affected facilities at onshore natural gas processing plants?
(a) You must retain records of the calculations and measurements required in § 60.5405a(a) and (b) and § 60.5407a(a) through (g) for at least 2 years following the date of the measurements. This requirement is included under § 60.7(f) of the General Provisions.
(b) You must submit a report of excess emissions to the Administrator in your annual report if you had excess emissions during the reporting period. The excess emissions report must be submitted to the EPA via the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/ ).) You must use the appropriate electronic report in CEDRI for this subpart or an alternate electronic file format consistent with the extensible markup language (XML) schema listed on the CEDRI Web site ( https://www3.epa.gov/ttn/chief/cedri/ ). If the reporting form specific to this subpart is not available in CEDRI at the time that the report is due, you must submit the report to the Administrator at the appropriate address listed in § 60.4. Once the form has been available in CEDRI for at least 90 days, you must begin submitting all subsequent reports via CEDRI. The report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted. For the purpose of these reports, excess emissions are defined as specified in paragraphs (b)(1) and (2) of this section.
(1) Any 24-hour period (at consistent intervals) during which the average sulfur emission reduction efficiency (R) is less than the minimum required efficiency (Z).
(2) For any affected facility electing to comply with the provisions of § 60.5407a(b)(2), any 24-hour period during which the average temperature of the gases leaving the combustion zone of an incinerator is less than the appropriate operating temperature as determined during the most recent performance test in accordance with the provisions of § 60.5407a(b)(3). Each 24-hour period must consist of at least 96 temperature measurements equally spaced over the 24 hours.
(c) To certify that a facility is exempt from the control requirements of these standards, for each facility with a design capacity less than 2 LT/D of H2S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H 2 S expressed as sulfur.
(d) If you elect to comply with § 60.5407a(e) you must keep, for the life of the facility, a record demonstrating that the facility's design capacity is less than 150 LT/D of H2S expressed as sulfur.
(e) The requirements of paragraph (b) of this section remain in force until and unless the EPA, in delegating enforcement authority to a state under section 111(c) of the Act, approves reporting requirements or an alternative means of compliance surveillance adopted by such state. In that event, affected sources within the state will be relieved of obligation to comply with paragraph (b) of this section, provided that they comply with the requirements established by the state. Electronic reporting to the EPA cannot be waived, and as such, the provisions of this paragraph do not relieve owners or operators of affected facilities of the requirement to submit the electronic reports required in this section to the EPA.
§ 60.5425a
What parts of the General Provisions apply to me?
Table 3 to this subpart shows which parts of the General Provisions in §§ 60.1 through 60.19 apply to you.
§ 60.5430a
What definitions apply to this subpart?
As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, in subpart A or subpart VVa of part 60; and the following terms shall have the specific meanings given them.
Acid gas means a gas stream of hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) that has been separated from sour natural gas by a sweetening unit.
Alaskan North Slope means the approximately 69,000 square-mile area extending from the Brooks Range to the Arctic Ocean.
API Gravity means the weight per unit volume of hydrocarbon liquids as measured by a system recommended by the American Petroleum Institute (API) and is expressed in degrees.
Artificial lift equipment means mechanical pumps including, but not limited to, rod pumps and electric submersible pumps used to flowback fluids from a well.
Bleed rate means the rate in standard cubic feet per hour at which natural gas is continuously vented (bleeds) from a pneumatic controller.
Capital expenditure means, in addition to the definition in 40 CFR 60.2, an expenditure for a physical or operational change to an existing facility that exceeds P, the product of the facility's replacement cost, R, and an adjusted annual asset guideline repair allowance, A, as reflected by the following equation: P = R × A, where:
(1) The adjusted annual asset guideline repair allowance, A, is the product of the percent of the replacement cost, Y, and the applicable basic annual asset guideline repair allowance, B, divided by 100 as reflected by the following equation:
A = Y × (B ÷ 100);
(2) The percent Y is determined from the following equation: Y = 1.0 − 0.575 log ×, where × is 2011 minus the year of construction; and
(3) The applicable basic annual asset guideline repair allowance, B, is 4.5.
Centrifugal compressor means any machine for raising the pressure of a natural gas by drawing in low pressure natural gas and discharging significantly higher pressure natural gas by means of mechanical rotating vanes or impellers. Screw, sliding vane, and liquid ring compressors are not centrifugal compressors for the purposes of this subpart.
Certifying official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision-making functions for the corporation, or a duly authorized representative of such person if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities applying for or subject to a permit and either:
(i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); or
(ii) The Administrator is notified of such delegation of authority prior to the exercise of that authority. The Administrator reserves the right to evaluate such delegation;
(2) For a partnership (including but not limited to general partnerships, limited partnerships, and limited liability partnerships) or sole proprietorship: A general partner or the proprietor, respectively. If a general partner is a corporation, the provisions of paragraph (1) of this definition apply;
(3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency ( e.g. , a Regional Administrator of EPA); or
(4) For affected facilities:
(i) The designated representative in so far as actions, standards, requirements, or prohibitions under title IV of the Clean Air Act or the regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under part 60.
Collection system means any infrastructure that conveys gas or liquids from the well site to another location for treatment, storage, processing, recycling, disposal or other handling.
Completion combustion device means any ignition device, installed horizontally or vertically, used in exploration and production operations to combust otherwise vented emissions from completions. Completion combustion devices include pit flares.
Compressor station means any permanent combination of one or more compressors that move natural gas at increased pressure through gathering or transmission pipelines, or into or out of storage. This includes, but is not limited to, gathering and boosting stations and transmission compressor stations. The combination of one or more compressors located at a well site, or located at an onshore natural gas processing plant, is not a compressor station for purposes of § 60.5397a.
Condensate means hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at standard conditions.
Continuous bleed means a continuous flow of pneumatic supply natural gas to a pneumatic controller.
Crude oil and natural gas source category means:
(1) Crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and
(2) Natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station.
Custody transfer means the transfer of crude oil or natural gas after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportation.
Dehydrator means a device in which an absorbent directly contacts a natural gas stream and absorbs water in a contact tower or absorption column (absorber).
Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir.
Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit; or
(3) Fails to meet any emission limit, operating limit, or work practice standard in this subpart during startup, shutdown, or malfunction, regardless of whether or not such failure is permitted by this subpart.
Equipment, as used in the standards and requirements in this subpart relative to the equipment leaks of GHG (in the form of methane) and VOC from onshore natural gas processing plants, means each pump, pressure relief device, open-ended valve or line, valve, and flange or other connector that is in VOC service or in wet gas service, and any device or system required by those same standards and requirements in this subpart.
Field gas means feedstock gas entering the natural gas processing plant.
Field gas gathering means the system used transport field gas from a field to the main pipeline in the area.
Flare means a thermal oxidation system using an open (without enclosure) flame. Completion combustion devices as defined in this section are not considered flares.
Flow line means a pipeline used to transport oil and/or gas to a processing facility or a mainline pipeline.
Flowback means the process of allowing fluids and entrained solids to flow from a well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production. The term flowback also means the fluids and entrained solids that emerge from a well during the flowback process. The flowback period begins when material introduced into the well during the treatment returns to the surface following hydraulic fracturing or refracturing. The flowback period ends when either the well is shut in and permanently disconnected from the flowback equipment or at the startup of production. The flowback period includes the initial flowback stage and the separation flowback stage.
Fugitive emissions component means any component that has the potential to emit fugitive emissions of methane or VOC at a well site or compressor station, including but not limited to valves, connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to § 60.5411a, thief hatches or other openings on a controlled storage vessel not subject to § 60.5395a, compressors, instruments, and meters. Devices that vent as part of normal operations, such as natural gas-driven pneumatic controllers or natural gas-driven pumps, are not fugitive emissions components, insofar as the natural gas discharged from the device's vent is not considered a fugitive emission. Emissions originating from other than the vent, such as the thief hatch on a controlled storage vessel, would be considered fugitive emissions.
Gas processing plant process unit means equipment assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.
Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.
Greenfield site means a site, other than a natural gas processing plant, which is entirely new construction. Natural gas processing plants are not considered to be greenfield sites, even if they are entirely new construction.
Hydraulic fracturing means the process of directing pressurized fluids containing any combination of water, proppant, and any added chemicals to penetrate tight formations, such as shale or coal formations, that subsequently require high rate, extended flowback to expel fracture fluids and solids during completions.
Hydraulic refracturing means conducting a subsequent hydraulic fracturing operation at a well that has previously undergone a hydraulic fracturing operation.
In light liquid service means that the piece of equipment contains a liquid that meets the conditions specified in § 60.485a(e) or § 60.5401a(f)(2).
In wet gas service means that a compressor or piece of equipment contains or contacts the field gas before the extraction step at a gas processing plant process unit.
Initial flowback stage means the period during a well completion operation which begins at the onset of flowback and ends at the separation flowback stage.
Intermediate hydrocarbon liquid means any naturally occurring, unrefined petroleum liquid.
Intermittent/snap-action pneumatic controller means a pneumatic controller that is designed to vent non-continuously.
Liquefied natural gas unit means a unit used to cool natural gas to the point at which it is condensed into a liquid which is colorless, odorless, non-corrosive and non-toxic.
Liquid collection system means tankage and/or lines at a well site to contain liquids from one or more wells or to convey liquids to another site.
Local distribution company (LDC) custody transfer station means a metering station where the LDC receives a natural gas supply from an upstream supplier, which may be an interstate transmission pipeline or a local natural gas producer, for delivery to customers through the LDC's intrastate transmission or distribution lines.
Low pressure well means a well that satisfies at least one of the following conditions:
(1) The static pressure at the wellhead following fracturing but prior to the onset of flowback is less than the flow line pressure at the sales meter;
(2) The pressure of flowback fluid immediately before it enters the flow line, as determined under § 60.5432a, is less than the flow line pressure at the sales meter; or
(3) Flowback of the fracture fluids will not occur without the use of artificial lift equipment.
Maximum average daily throughput means the earliest calculation of daily average throughput during the 30-day PTE evaluation period employing generally accepted methods.
Natural gas-driven diaphragm pump means a positive displacement pump powered by pressurized natural gas that uses the reciprocating action of flexible diaphragms in conjunction with check valves to pump a fluid. A pump in which a fluid is displaced by a piston driven by a diaphragm is not considered a diaphragm pump for purposes of this subpart. A lean glycol circulation pump that relies on energy exchange with the rich glycol from the contactor is not considered a diaphragm pump.
Natural gas-driven pneumatic controller means a pneumatic controller powered by pressurized natural gas.
Natural gas liquids means the hydrocarbons, such as ethane, propane, butane, and pentane that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule-Thompson valve, a dew point depression valve, or an isolated or standalone Joule-Thompson skid is not a natural gas processing plant.
Natural gas transmission means the pipelines used for the long distance transport of natural gas (excluding processing). Specific equipment used in natural gas transmission includes the land, mains, valves, meters, boosters, regulators, storage vessels, dehydrators, compressors, and their driving units and appurtenances, and equipment used for transporting gas from a production plant, delivery point of purchased gas, gathering system, storage area, or other wholesale source of gas to one or more distribution area(s).
Nonfractionating plant means any gas plant that does not fractionate mixed natural gas liquids into natural gas products.
Non-natural gas-driven pneumatic controller means an instrument that is actuated using other sources of power than pressurized natural gas; examples include solar, electric, and instrument air.
Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf.
Pneumatic controller means an automated instrument used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature.
Pressure vessel means a storage vessel that is used to store liquids or gases and is designed not to vent to the atmosphere as a result of compression of the vapor headspace in the pressure vessel during filling of the pressure vessel to its design capacity.
Process unit means components assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.
Produced water means water that is extracted from the earth from an oil or natural gas production well, or that is separated from crude oil, condensate, or natural gas after extraction.
Qualified Professional Engineer means an individual who is licensed by a state as a Professional Engineer to practice one or more disciplines of engineering and who is qualified by education, technical knowledge and experience to make the specific technical certifications required under this subpart. Professional engineers making these certifications must be currently licensed in at least one state in which the certifying official is located.
Reciprocating compressor means a piece of equipment that increases the pressure of a process gas by positive displacement, employing linear movement of the driveshaft.
Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes to the atmosphere, or other mechanism that provides the same function.
Recovered gas means gas recovered through the separation process during flowback.
Recovered liquids means any crude oil, condensate or produced water recovered through the separation process during flowback.
Reduced emissions completion means a well completion following fracturing or refracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the gas flow line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere.
Reduced sulfur compounds means H 2 S, carbonyl sulfide (COS), and carbon disulfide (CS 2 ).
Removed from service means that a storage vessel affected facility has been physically isolated and disconnected from the process for a purpose other than maintenance in accordance with § 60.5395a(c)(1).
Returned to service means that a storage vessel affected facility that was removed from service has been:
(1) Reconnected to the original source of liquids or has been used to replace any storage vessel affected facility; or
(2) Installed in any location covered by this subpart and introduced with crude oil, condensate, intermediate hydrocarbon liquids or produced water.
Routed to a process or route to a process means the emissions are conveyed via a closed vent system to any enclosed portion of a process that is operational where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed by chemical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered.
Salable quality gas means natural gas that meets the flow line or collection system operator specifications, regardless of whether such gas is sold.
Separation flowback stage means the period during a well completion operation when it is technically feasible for a separator to function. The separation flowback stage ends either at the startup of production, or when the well is shut in and permanently disconnected from the flowback equipment.
Startup of production means the beginning of initial flow following the end of flowback when there is continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate or produced water.
Storage vessel means a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) which provide structural support. A well completion vessel that receives recovered liquids from a well after startup of production following flowback for a period which exceeds 60 days is considered a storage vessel under this subpart. A tank or other vessel shall not be considered a storage vessel if it has been removed from service in accordance with the requirements of § 60.5395a(c)(1) until such time as such tank or other vessel has been returned to service. For the purposes of this subpart, the following are not considered storage vessels:
(1) Vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive days. If you do not keep or are not able to produce records, as required by § 60.5420a(c)(5)(iv), showing that the vessel has been located at a site for less than 180 consecutive days, the vessel described herein is considered to be a storage vessel from the date the original vessel was first located at the site. This exclusion does not apply to a well completion vessel as described above.
(2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels.
(3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere.
Sulfur production rate means the rate of liquid sulfur accumulation from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element sulfur from acid gas.
Surface site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically affixed.
Sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream.
Total Reduced Sulfur (TRS) means the sum of the sulfur compounds hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl disulfide as measured by Method 16 of appendix A-6 of this part.
Total SO 2
equivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO 2 to the quantity of SO 2 that would be obtained if all reduced sulfur compounds were converted to SO 2 (ppmv or kg/dscm (lb/dscf)).
Underground storage vessel means a storage vessel stored below ground.
Well means a hole drilled for the purpose of producing oil or natural gas, or a well into which fluids are injected.
Well completion means the process that allows for the flowback of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and tests the reservoir flow characteristics, which may vent produced hydrocarbons to the atmosphere via an open pit or tank.
Well completion operation means any well completion with hydraulic fracturing or refracturing occurring at a well affected facility.
Well completion vessel means a vessel that contains flowback during a well completion operation following hydraulic fracturing or refracturing. A well completion vessel may be a lined earthen pit, a tank or other vessel that is skid-mounted or portable. A well completion vessel that receives recovered liquids from a well after startup of production following flowback for a period which exceeds 60 days is considered a storage vessel under this subpart.
Well site means one or more surface sites that are constructed for the drilling and subsequent operation of any oil well, natural gas well, or injection well. For purposes of the fugitive emissions standards at § 60.5397a, well site also means a separate tank battery surface site collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water from wells not located at the well site (e.g., centralized tank batteries).
Wellhead means the piping, casing, tubing and connected valves protruding above the earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. The wellhead does not include other equipment at the well site except for any conveyance through which gas is vented to the atmosphere.
Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.
§ 60.5432a
How do I determine whether a well is a low pressure well using the low pressure well equation?
(a) To determine that your well is a low pressure well subject to § 60.5375a(f), you must determine whether the characteristics of the well are such that the well meets the definition of low pressure well in § 60.5430a. To determine that the well meets the definition of low pressure well in § 60.5430a, you must use the low pressure well equation below:
Where:
(1) P L is the pressure of flowback fluid immediately before it enters the flow line, expressed in pounds force per square inch (psia), and is to be calculated using the equation above;
(2) P R is the pressure of the reservoir containing oil, gas, and water at the well site, expressed in psia;
(3) L is the true vertical depth of the well, expressed in feet (ft);
(4) q o is the flow rate of oil in the well, expressed in cubic feet/second (cu ft/sec);
(5) q g is the flow rate of gas in the well, expressed in cu ft/sec;
(6) q w is the flow rate of water in the well, expressed in cu ft/sec;
(7) ρ o is the density of oil in the well, expressed in pounds mass per cubic feet (lbm/cu ft).
(b) You must determine the four values in paragraphs (a)(4) through (7) of this section, using the calculations in paragraphs (b)(1) through (b)(15) of this section.
(1) Determine the value of the bottom hole pressure, P BH ( psia ), based on available information at the well site, or by calculating it using the reservoir pressure, P R ( psia ), in the following equation:
(2) Determine the value of the bottom hole temperature, T BH ( F ), based on available information at the well site, or by calculating it using the true vertical depth of the well, L (ft) , in the following equation:
T BH ( F ) = (0.014 × L ) + 79.081
(3) Calculate the value of the applicable natural gas specific gravity that would result from a separator pressure of 100 psig, γ gs , using the following equation with: Separator at standard conditions (pressure, p = 14.7 ( psia ), temperature, T = 60 ( F )); the oil API gravity at the well site, γ 0 ; and the gas specific gravity at the separator under standard conditions, γ gp = 0.75:
(4) Calculate the value of the applicable dissolved GOR, Rs (scf/STBO) , using the following equation with: The bottom hole pressure, P BH ( psia ), determined in (b)(1) of this section; the bottom hole temperature, T BH ( F ), determined in (b)(2) of this section; the gas gravity at separator pressure of 100 psig, γ gs , calculated in (b)(3) of this section; the oil API gravity, γ o , at the well site; and the constants, C1, C2, and C3, found in Table A:
Table A—Coefficients for the correlation for R s
Constant | γ API ≤ 30 | γ API > 30
C1 | 0.0362 | 0.0178
C2 | 1.0937 | 1.1870
C3 | 25.7240 | 23.931
(5) Calculate the value of the oil formation volume factor, Bo (bbl/STBO) , using the following equation with: the bottom hole temperature, T BH ( F ), determined in paragraph (b)(2) of this section; the gas gravity at separator pressure of 100 psig, γ gs , calculated in paragraph (b)(3) of this section; the dissolved GOR, Rs (scf/STBO), calculated in paragraph (b)(4) of this section; the oil API gravity, γ o , at the well site; and the constants, C1, C2, and C3, found in Table B:
Table B—Coefficients for the Correlation for B o
Constant | γ API ≤ 30 | γ API > 30
C1 | 4.677 × 10 −4 | 4.670 × 10 −4
C2 | 1.751 × 10 −5 | 1.100 × 10 −5
C3 | −1.811 × 10 −8 | 1.337 × 10 −9
(10) Calculate the critical pressure, P c (psia), and critical temperature, T c (R), using the equations below with: Gas gravity at standard conditions (pressure, P = 14.7 ( psia ), temperature, T = 60 ( F )), γ = 0.75; and where the mole fractions of nitrogen, carbon dioxide and hydrogen sulfide in the gas are X N 2 = 0.168225, X CO 2 = 0.013163, and X H 2 S = 0.013680, respectively:
P c ( psia ) = 678 − 50 · (γ g − 0.5) − 206.7 · X N 2 + 440 · X CO 2 + 606.7 · X H 2 S
T c ( R ) = 326 + 315.7 · (γ g − 0.5) − 240 · X N 2 − 88.3 · X CO 2 + 133.3 · X H 2 S
(11) Calculate reduced pressure, P r , and reduced temperature, T r , using the following equations with: the bottom hole pressure, P BH , as determined in paragraph (b)(1) of this section; the bottom hole temperature, T BH ( F ), as determined in paragraph (b)(2) of this section in the following equations:
(12)(i) Calculate the gas compressibility factor, Z , using the following equation with the reduced pressure, P r , calculated in paragraph (b)(11) of this section:
(ii) The values for A, B, C, D in the above equation, are calculated using the following equations with the reduced pressure, P r , and reduced temperature, T r , calculated in paragraph (b)(11) of this section:
(15) Calculate the flow rate of water in the well, q w ( cu ft/sec ), using the following equation with the water production rate Qw (bbl/day) at the well site:
§§ 60.5433a-60.5499a [Reserved]
Table 1 to Subpart OOOO a of Part 60—Required Minimum Initial SO 2 Emission Reduction Efficiency (Z i )
H 2 S content of acid gas (Y), % | Sulfur feed rate (X), LT/D | 2.0 < X < 5.0 | 5.0 < X < 15.0 | 15.0 < X < 300.0 | X > 300.0
Y > 50 | 79.0 | 88.51X 0.0101 Y 0.0125 or 99.9, whichever is smaller.
20 < Y < 50 | 79.0 | 88.51X 0.0101 Y 0.0125 or 97.9, whichever is smaller | 97.9
10 < Y < 20 | 79.0 | 88.51X 0.0101 Y 0.0125 or 93.5, whichever is smaller | 93.5 | 93.5
Y < 10 | 79.0 | 79.0 | 79.0 | 79.0
Table 2 to Subpart OOOO a of Part 60—Required Minimum SO 2 Emission Reduction Efficiency (Z c )
H 2 S content of acid gas (Y), % | Sulfur feed rate (X), LT/D | 2.0 < X < 5.0 | 5.0 < X < 15.0 | 15.0 < X < 300.0 | X > 300.0
Y > 50 | 74.0 | 85.35X 0.0144 Y 0.0128 or 99.9, whichever is smaller.
20 < Y < 50 | 74.0 | 85.35X 0.0144 Y 0.0128 or 97.5, whichever is smaller | 97.5
10 < Y < 20 | 74.0 | 85.35X 0.0144 Y 0.0128 or 90.8, whichever is smaller | 90.8 | 90.8
Y < 10 | 74.0 | 74.0 | 74.0 | 74.0
X = The sulfur feed rate from the sweetening unit ( i.e., the H 2 S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H 2 S (dry basis) rounded to one decimal place.
Z = The minimum required sulfur dioxide (SO 2 ) emission reduction efficiency, expressed as percent carried to one decimal place. Z i refers to the reduction efficiency required at the initial performance test. Z c refers to the reduction efficiency required on a continuous basis after compliance with Z i has been demonstrated.
As stated in § 60.5425a, you must comply with the following applicable General Provisions:
Table 3 to Subpart OOOO a of Part 60—Applicability of General Provisions to Subpart OOOO a
General provisions citation | Subject of citation | Applies to subpart? | Explanation
§ 60.1 | General applicability of the General Provisions | Yes
§ 60.2 | Definitions | Yes | Additional terms defined in § 60.5430a.
§ 60.3 | Units and abbreviations | Yes
§ 60.4 | Address | Yes
§ 60.5 | Determination of construction or modification | Yes
§ 60.6 | Review of plans | Yes
§ 60.7 | Notification and record keeping | Yes | Except that § 60.7 only applies as specified in § 60.5420a(a).
§ 60.8 | Performance tests | Yes | Performance testing is required for control devices used on storage vessels, centrifugal compressors and pneumatic pumps.
§ 60.9 | Availability of information | Yes
§ 60.10 | State authority | Yes
§ 60.11 | Compliance with standards and maintenance requirements | No | Requirements are specified in subpart OOOOa.
§ 60.12 | Circumvention | Yes
§ 60.13 | Monitoring requirements | Yes | Continuous monitors are required for storage vessels.
§ 60.14 | Modification | Yes | To the extent any provision in § 60.14 conflicts with specific provisions in subpart OOOOa, it is superseded by subpart OOOOa provisions.
§ 60.15 | Reconstruction | Yes | Except that § 60.15(d) does not apply to wells, pneumatic controllers, pneumatic pumps, centrifugal compressors, reciprocating compressors or storage vessels.
§ 60.16 | Priority list | Yes
§ 60.17 | Incorporations by reference | Yes
§ 60.18 | General control device and work practice requirements | Yes
| § 60.19 | General notification and reporting requirement | Yes
81
107
Friday, June 3, 2016
Rules and Regulations
Part III
Environmental Protection Agency
40 CFR Part 49

Federal Implementation Plan for True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector; Amendments to the Federal Minor New Source Review Program in Indian Country To Address Requirements for True Minor Sources in the Oil and Natural Gas Sector; Final Rule
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 49
[EPA-HQ-OAR-2014-0606; FRL-9946-56-OAR]
RIN 2060-AS27
Federal Implementation Plan for True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector; Amendments to the Federal Minor New Source Review Program in Indian Country To Address Requirements for True Minor Sources in the Oil and Natural Gas Sector

AGENCY:
Environmental Protection Agency (EPA).

ACTION:
Final rule.

SUMMARY:
The Environmental Protection Agency (EPA) is finalizing a federal implementation plan (FIP) that applies to new true minor sources and minor modifications at existing true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector that are locating or expanding in Indian reservations or in other areas of Indian country over which an Indian tribe, or the EPA, has demonstrated the tribe's jurisdiction. The FIP satisfies the minor source permitting requirement under the “Federal Minor New Source Review (NSR) Program in Indian Country” (referred to as the “Federal Indian Country Minor NSR rule”). For the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, the FIP requires compliance with emission limitations and other requirements from certain federal emission standards as written at the time of construction or modification for compression ignition and spark ignition engines; process heaters; combustion turbines; fuel storage tanks; glycol dehydrators; completion of hydraulically fractured oil and natural gas wells; reciprocating and centrifugal compressors (except those located at well sites); pneumatic controllers; pneumatic pumps; storage vessels; and fugitive emissions from well sites, compressor stations and natural gas processing plants.
The EPA is also finalizing several amendments to the Federal Indian Country Minor NSR rule, including adding new text regarding the purpose of the program, revising the program overview provision, revising certain provisions to incorporate compliance with the FIP, revising the applicability provision to establish that oil and natural gas sources are required to comply with the FIP unless they either opt to obtain a source-specific permit or are otherwise required to do so, and revising the source registration provision for oil and natural gas sources constructing under this FIP. Also, we are revising the applicability of the Federal Indian Country Minor NSR rule to comport with a court decision that addressed the scope of the EPA's jurisdiction to implement the Federal Indian Country Minor NSR rule in Indian country: Oklahoma Dept. of Environmental Quality v. EPA, 740 F.3d 185 (D.C. Cir. 2014). This court decision has the same effect on the scope of the EPA's jurisdiction under the Federal Major New Source Review Program for Nonattainment Areas in Indian Country and so we are changing the applicability of the Federal Indian Country Nonattainment Major NSR rule as well.

DATES:
This final rule is effective on August 2, 2016.

ADDRESSES:
The EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2014-0606. All documents in the docket are listed on the http://www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., Confidential Business Information 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 electronically through http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:
Mr. Christopher Stoneman, Outreach and Information Division, Office of Air Quality Planning and Standards (C-304-01), Environmental Protection Agency, Research Triangle Park, North Carolina, 27711, telephone number (919) 541-0823, facsimile number (919) 541-0072, email address: stoneman.chris@epa.gov. For questions about the applicability of this action to a particular source, please contact the appropriate EPA region:
• EPA Region 5 (Illinois, Indiana, Michigan, Minnesota, Ohio, and Wisconsin)—Ms. Genevieve Damico, Air Permits Section, Environmental Protection Agency, Region 5, Chicago, Illinois 60604; telephone number (312) 353-4761; fax (312) 385-5501; email address: damico.genevieve@epa.gov.
• EPA Region 6 (Arkansas, Louisiana, New Mexico, Oklahoma, and Texas)—Ms. Bonnie Braganza, Air Permits Section, Multimedia Permitting and Planning Division, Environmental Protection Agency Region 6, Dallas, Texas 75202; telephone number (214) 665-7340; fax number (214) 665-6762; email address: braganza.bonnie@epa.gov.
• EPA Region 8 (Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming)—Ms. Claudia Smith, Air Program, Mail Code 8P-AR, Environmental Protection Agency Region 8, Denver, Colorado 80202; telephone number (303) 312-6520; fax number (303) 312-6520; email address: smith.claudia@epa.gov.
• EPA Region 9 (Arizona, California, Hawaii, Nevada, and Pacific Islands)—Ms. Lisa Beckham, Permits Office, Air Division, Air-3, Environmental Protection Agency Region 9, San Francisco, California 94105; telephone number (415) 972-3811; fax number (415) 947-3579; email address: beckham.lisa@epa.gov.
• All other EPA regions—The permit reviewer for minor sources in Indian country for your EPA region. You can find the list of the EPA permit reviewers at: https://www.epa.gov/tribal-air/tribal-minor-new-source-review. Scroll down to the heading, “Existing Source Registration,” and click on “Reviewing Authority” to access “Environmental Protection Agency's Reviewing Authorities for Permits.”

SUPPLEMENTARY INFORMATION:
The information presented in this preamble is organized as follows:
I. General Information
A. What entities are potentially affected by this final action?
B. Where can I get a copy of this document and other related information?
II. Summary of Final Oil and Natural Gas FIP
A. Overview
B. Eight Federal Rules and Exclusions in FIP
C. Addressing Threatened and Endangered Species and Historic Properties
D. Summary of Final Amendments to the Federal Indian Country Minor NSR Rule
III. Background
A. Federal Indian Country Minor NSR Rule
B. What is a FIP?
C. Oil and Natural Gas Sector
D. EPA Actions Affecting Oil and Natural Gas Minor Sources in Areas Covered by the Federal Indian Country Minor NSR Rule
IV. Summary of Final Action, Comments and Responses
A. Overview of Changes to the FIP and Federal Indian Country Minor NSR Rule
B. Proposed Amendments to the Federal Indian Country Minor NSR Rule
C. Implementation-Related Issues
D. Requirements Relating to Threatened or Endangered Species and Historic Properties
E. Rationale for the FIP
F. The FIP as an Alternative to Source-Specific Permits, General Permits and Permits by Rule
G. Synthetic Minor Sources and Minor Modifications at Major Sources
H. Nonattainment Areas
I. How the EPA Selected Equipment Included in the Proposed FIP
J. Pollutants Included in the Proposed FIP
K. Exclusion of Existing Sources From the Proposed Oil and Natural Gas FIP
L. General Comments ( e.g., Administrative, Incorporate by Reference)
M. Other Comments
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and 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 Risks 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)
J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations
K. Congressional Review Act (CRA)

I. General Information

A. What entities are potentially affected by this final action?
Entities potentially affected by this action consist of owners/operators of facilities included in the following source categories that are located, or planning to locate, in an Indian reservation or in another area of Indian country (as defined in 18 U.S.C. 1151) over which an Indian tribe, or the EPA, has demonstrated that the tribe has jurisdiction where there is no EPA-approved program in place and that are subject to the requirements of the Federal Indian Country Minor NSR rule.
Table 1—Source Categories Affected by This Action
Industry category | NAICS Code ^a | Examples of regulated entities/description of industry category
Oil and Natural Gas Production/Operations | 21111 | Exploration for crude petroleum and natural gas; drilling, completing, and equipping wells; operation of separators, emulsion breakers, desilting equipment, and field gathering lines for crude petroleum and natural gas; and all other activities in the preparation of oil and natural gas up to the point of shipment from the producing property.
| | Production of crude petroleum, the mining and extraction of oil from oil shale and oil sands, the production of natural gas, sulfur recovery from natural gas, and the recovery of hydrocarbon liquids from oil and natural gas field gases.
Crude Petroleum and Natural Gas Extraction | 211111 | Exploration, development and/or the production of petroleum or natural gas from wells in which the hydrocarbons will initially flow or can be produced using normal pumping techniques or production of crude petroleum from surface shales or tar sands or from reservoirs in which the hydrocarbons are semisolids.
Natural Gas Liquid Extraction | 211112 | Recovery of liquid hydrocarbons from oil and natural gas field gases; and sulfur recovery from natural gas.
Drilling Oil and Natural Gas Wells | 213111 | Drilling oil and natural gas wells for others on a contract or fee basis, including spudding in, drilling in, redrilling, and directional drilling.
Support Activities for Oil and Natural Gas Operations | 213112 | Performing support activities on a contract or fee basis for oil and natural gas operations (except site preparation and related construction activities) such as exploration (except geophysical surveying and mapping); excavating slush pits and cellars, well surveying; running, cutting, and pulling casings, tubes, and rods; cementing wells, shooting wells; perforating well casings; acidizing and chemically treating wells; and cleaning out, bailing, and swabbing wells.
Engines (Spark Ignition and Compression Ignition) for Electric Power Generation | ** 2211 | Provision of electric power to support oil and natural gas production where access to the electric grid is unavailable.
^a North American Industry Classification System.
This list is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be potentially affected by this action. To determine whether your facility could be affected by this action, you should examine the applicability criteria in the final Federal Minor NSR Program in Indian Country (40 Code of Federal Regulations (CFR) 49.153), as well as the FIP applicability in § 49.101. If you have any questions regarding the applicability of this action to a particular entity, contact the appropriate person listed in the FOR FURTHER INFORMATION CONTACT section.

B. Where can I get a copy of this document and other related information?
In addition to being available in the docket, an electronic copy of this final rule will also be available on the World Wide Web. Following signature by the EPA Administrator, a copy of this final rule will be posted in the regulations and standards section of our NSR home page located at http://www.epa.gov/nsr and on the tribal NSR page at https://www.epa.gov/tribal-air/tribal-minor-new-source-review.

II. Summary of Final Oil and Natural Gas FIP

A. Overview
We are finalizing a FIP to protect air quality in Indian country due to the impact of new true minor sources ^1 and minor modifications at existing true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector that are locating or expanding in an Indian reservation or in another area of Indian country over which a tribe, or the EPA, has demonstrated that the tribe has jurisdiction. The FIP applies to new and modified true minor sources that are located or expanding in the referenced areas of Indian country designated as attainment, unclassifiable or attainment/unclassifiable. It does not apply to new and modified true minor sources that are located or expanding in referenced areas of Indian country designated nonattainment. The FIP does not apply to minor modification of major sources; such sources are required to obtain a source-specific permit prior to beginning construction starting September 2, 2014, per the Federal Indian Country Minor NSR rule.
^1 Under § 49.52(d), true minor source means a source, not including the exempt emissions units and activities listed in § 49.153(c), that emits, or has the potential to emit, regulated NSR pollutants in amounts that are less than the major source thresholds in § 49.167 or § 52.21, as applicable, but equal to or greater than the minor NSR thresholds in § 49.153, without the need to take an enforceable restriction to reduce its potential to emit to such levels. That is, a true minor source is a minor source that is not a synthetic minor source. The potential to emit includes fugitive emissions, to the extent that they are quantifiable, only if the source belongs to one of the source categories listed in part 51, appendix S, paragraph II.A.4(iii) or § 52.21(b)(1)(iii), as applicable.
However, in response to comments, we are stating here our intent to potentially apply this national FIP's requirements as appropriate to nonattainment areas where the EPA has established a separate, area-specific FIP. In that separate, area-specific action, we would propose—and seek comment on—the application of this FIP's requirements to new and modified true minor sources in those certain areas designated nonattainment. This possible, future extension of coverage of this FIP could provide a mechanism for streamlining permitting in nonattainment areas, protecting air quality and allowing continued oil and natural gas growth in Indian country.
This FIP fulfills the EPA's obligation under the Federal Indian Country Minor NSR rule to issue minor source NSR pre-construction permits. The FIP provides a streamlined, alternative approach that fulfills the permitting requirement, while also ensuring air quality protection through requirements that are unambiguous and legally and practicably enforceable. The FIP approach is also transparent to the public; it is clear to the public what requirements will apply. The FIP reduces burden for sources and the Reviewing Authority and minimizes potential delays in new construction due to compliance with the minor NSR permitting obligation. True minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector are required to comply with the FIP instead of obtaining a source-specific minor source permit, unless a source chooses to opt out of the FIP and to obtain a source-specific minor NSR permit instead. In addition, with advance notice the Reviewing Authority can require a source to obtain a source-specific permit based on local or reservation-specific air quality concerns where the emissions from the source could cause or contribute to a National Ambient Air Quality Standards (NAAQS) or Prevention of Significant Deterioration (PSD) increment violation. To protect the NAAQS, the Reviewing Authority can regulate emissions from operations at the minor source not regulated by the FIP, or can require more stringent emission limitations for operations at the source than would be required by the FIP.
In this FIP, we require owners/operators of oil and natural gas production facilities and natural gas processing plants to comply with eight federal standards to reduce emissions of volatile organic compounds (VOC), nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), particulate matter (PM, PM 10 , PM 2.5 ), hydrogen sulfide (H 2 S), carbon monoxide (CO) and various sulfur compounds from the following units/processes in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector: Compression ignition and spark ignition engines; process heaters; combustion turbines; fuel storage tanks; glycol dehydrators; completion of hydraulically fractured oil and natural gas wells; reciprocating and centrifugal compressors (except those located at well sites); pneumatic controllers; pneumatic pumps, and storage vessels; fugitive emissions from well sites; compressor stations and natural gas processing plants. The oil and natural gas FIP requires compliance with five NSPS and three national emission standards for hazardous air pollutants (NESHAP). ^2 These regulations are listed in Table 2.
^2 Though this FIP only addresses new and modified true minor sources, it is important to note that NESHAPs not only apply to new sources but to existing sources as well.
The eight regulations and the provisions of each that are included in the oil and natural gas FIP are discussed in more detail in this section. The FIP's requirements include emission standards (that contain emission limitations), monitoring, testing, recordkeeping and reporting. For purposes of this FIP, true minor sources must comply with these standards, as they currently exist or as amended in the future, except for those provisions that we specifically exclude under the FIP (unless the source opts-out of the FIP and obtains a source-specific permit or is otherwise required to obtain a source-specific permit by the Reviewing Authority). This includes the amendments to the oil and natural gas NSPS that have become part of the final oil and natural gas NSPS as a result of the 2016 final oil and natural gas NSPS. ^3 Sources subject to this FIP would be subject to any future changes to the eight underlying EPA standards only if they undergo a future minor modification as a true minor sources and would otherwise be subject to those future changes. To help understand the requirements of this oil and natural gas FIP, please see the 2016 final oil and natural gas NSPS and the provisions for each of the eight federal rules ( i.e., five NSPS and three NESHAP) identified in Table 2. ^4 (This FIP does not change the applicability of the specified standards, nor does it relieve sources subject to the standards from complying with them, independently of this FIP.) The excluded provisions are listed below.
^3 “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed and Modified Sources,” U.S. Environmental Protection Agency, signed May 12, 2016, http://www.epa.gov/airquality/oilandgas/actions.html.
^4 The proposed FIP only included six emissions standards; in response to comments, we are adding two more, bringing the total to eight. For a discussion of this expansion and the pertinent comments, see Section IV.I.
Also discussed in this section are features of the FIP and amendments to the Federal Indian Country Minor NSR rule that are largely necessary to facilitate implementation of the FIP.
Table 2—Eight Federal Rules Included in the Oil and Natural Gas FIP for Indian Country ^5
40 CFR part and subpart | Title of subpart | Potentially affected sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector | Location
40 CFR part 63, subpart DDDDD | National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters | Process heaters | http://www.ecfr.gov/cgi-bin/text-idx?SID=9f31077f895e9cb417f5386519941a47&mc=true&node=sp40.14.63.ddddd&rgn=div6.
40 CFR part 63, subpart ZZZZ ^6 | Subpart ZZZZ—National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines | Reciprocating Internal Combustion Engines | http://www.ecfr.gov/cgi-bin/text-idx?c=ecfr;rgn=div6;view=text;node=%3A14.0.1.1.1.1;idno=40;sid=e94dcfde4a04b27290c445a56e635e58;cc=ecfr.
40 CFR part 60, subpart IIII | Standards of Performance for Stationary Compression Ignition Internal Combustion Engines | Compression Ignition Internal Combustion Engines | http://www.ecfr.gov/cgi-bin/text-idx?SID=9f31077f895e9cb417f5386519941a47&mc=true&node=sp40.7.60.iiii&rgn=div6.
40 CFR part 60, subpart JJJJ | Standards of Performance for Stationary Spark Ignition Internal Combustion Engines | Spark Ignition Internal Combustion Engines | http://www.ecfr.gov/cgi-bin/text-idx?SID=9f31077f895e9cb417f5386519941a47&mc=true&node=sp40.7.60.jjjj&rgn=div6.
40 CFR part 60, subpart Kb | Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984 | Fuel Storage Tanks | http://www.ecfr.gov/cgi-bin/text-idx?SID=9f31077f895e9cb417f5386519941a47&mc=true&node=sp40.7.60.k_0b&rgn=div6.
40 CFR part 60, subpart OOOOa (final) | Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced after September 18, 2015 | Storage Vessels, Pneumatic Controllers, Compressors (Reciprocating and Centrifugal), Hydraulically Fractured Oil and Natural Gas Well Completions, Pneumatic Pumps and Fugitive Emissions from Well Sites and Compressor Stations | http://www.epa.gov/airquality/oilandgas/actions.html.
40 CFR part 63, subpart HH | National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities | Glycol Dehydrators | http://www.ecfr.gov/cgi-bin/text-idx?SID=9f31077f895e9cb417f5386519941a47&mc=true&node=sp40.11.63.hh&rgn=div6.
40 CFR part 60, subpart KKKK ^7 | Standards of Performance for New Stationary Combustion Turbines | Combustion Turbines | http://www.ecfr.gov/cgi-bin/text-idx?SID=4090b6cf5eea5cb67940a80906ff09a2&mc=true&node=sp40.7.60.kkkk&rgn=div6.

B. Eight Federal Rules and Exclusions in FIP
This oil and natural gas FIP requires owners/operators of new and modified existing true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector that are located in areas covered by the Federal Indian Country Minor NSR rule to comply with eight federal rules. One of the rules this FIP adopts is certain requirements of the final 40 CFR part 60, subpart OOOOa NSPS. ^8 Requirements under the final NSPS, subpart OOOOa involve standards for oil and natural gas production and natural gas processing. ^9
^5 Three of the eight rules are NESHAPs. Our basis for requiring compliance with NESHAPs in this rule that is designed to fulfill requirements of the Federal Indian Country Minor NSR rule is to address emissions of criteria pollutants. The requirements from the NESHAPs are included because they effectively control emissions of all VOC, not just those that are also HAP. VOC is an NSR-regulated pollutant of concern in the Federal Indian Country Minor NSR rule.
^6 This regulation was not included in the proposed FIP but is being added to the final FIP in response to comments.
^7 Ibid.
^8 Finalized 40 CFR part 60, subpart OOOOa, covers the emission sources covered under existing 40 CFR part 60, subpart OOOO, as well as the added coverage of new, reconstructed and modified emission sources beyond those covered in existing 40 CFR part 60, subpart OOOO. These additional sources are hydraulically fractured oil well completions, pneumatic pumps and fugitive emissions from well sites and compressor stations.
^9 This list includes centrifugal compressors, reciprocating compressors, pneumatic controllers, pneumatic pumps, fugitive emissions from compressor stations, and storage vessels. It excludes sources located in the transmission and storage segment because they are not part of this FIP, which focusses on the oil and natural gas production and natural gas processing segments of the oil and natural gas sector.
We are requiring under this FIP that owners/operators of new true minor sources and modifications of existing true minor sources comply with all applicable requirements of the eight federal rules listed in Table 2 above in effect at the time they begin construction, except for the excluded provisions indicated below. In general, for this FIP, we are excluding specific provisions of the rules for three reasons: (1) They are not relevant ( e.g., equipment that is not used in this sector); (2) they would not apply to the oil and natural gas production and natural gas processing segments of the oil and natural gas sector; (3) they apply only to equipment manufacturers and not to owners/operators.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 40 CFR part 63, subpart DDDDD (NESHAP for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters), as written at the time ^{10} the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source.
^{10} “Written at the time” for a rule means as currently written and as may be amended in the future.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 40 CFR part 63, subpart ZZZZ (NESHAP for Stationary Reciprocating Internal Combustion Engines), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 49 CFR part 60, subpart IIII (Standards of Performance for Stationary Compression Ignition Internal Combustion Engines), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for the following: ^{11}
^{11} In the proposal, we excluded the following provision that we are now not excluding because area sources that are also true minor sources may be subject to this rule: § 60.4200(c)—Am I subject to this subpart? (area sources and exemptions from Title V permits).
• § 60.4200(a)(1)—Am I subject to this subpart? (applies to manufacturers);
• § 60.4200(b)—Not applicable to a stationary ignition internal combustion engine being tested at an engine test cell/stand;
• § 60.4201—What emission standards must I meet for non-emergency engines if I am a stationary compression ignition internal combustion engine manufacturer?;
• § 60.4202—What emission standards must I meet for emergency engines if I am a stationary compression ignition internal combustion engine manufacturer?;
• § 60.4203—How long must my engines meet the emission standards if I am a manufacturer of stationary compression ignition internal combustion engines?;
• § 60.4210—What are my compliance requirements if I am a stationary compression ignition internal combustion engine manufacturer?; and
• § 60.4215—What requirements must I meet for engines used in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands?.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 40 CFR part 60, subpart JJJJ (Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced after September 18, 2015), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for the following:
• § 60.4230(b)—Not applicable to stationary spark ignition internal combustion engines being tested at an engine test cell/stand;
• § 60.4230(c)—Exemption for obtaining a Title V permit for an owner or operator of an area source subject to this part;
• § 60.4231 and § 60.4232—Emission standards for manufacturers;
• § 60.4238 through § 60.4242—Compliance Requirements for Manufacturers; and
• § 60.4247—Mobile source provisions that apply to manufacturers of stationary spark ignition internal combustion engines or equipment containing such engines.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 40 CFR part 60, subpart Kb (Standards of Performance for Volatile Organic Liquid Storage Vessels), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for the following:
• § 60.112b(c)—Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia; and
• § 60.117b(a) and (b)—Delegation of authority.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of part 60, subpart OOOOa (Standards for New and Modified Sources in the Oil and Natural Gas Sector), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for the following: ^{12}
^{12} In the proposal, we excluded the following provision that we are now not excluding because we have expanded the scope of this FIP to include gas processing plants: § 60.5365a(f)(3)—Equipment exemption at processing plant.
• § 60.5365a(h)(4)—Existing sources constructed after August 23, 2011;
• § 60.5370a(c)—Permit exemption;
• § 60.5413a(a)(5)—Exemptions from performance testing—hazardous waste incinerator;
• § 60.5420a(a)(2)(i)—Advance notification requirements for well completions; and
• § 60.5420a(a)(2)(ii)—Advance notification requirements of well completions when subject to state regulation that requires advance notification.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 40 CFR part 63, subpart HH (NESHAP from Oil and Natural Gas Production Facilities), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for the following: ^{13}
^{13} In the proposal, we excluded the following provision that we are now not excluding because we have expanded the scope of this FIP to include gas processing plants: § 63.760(b)(1)(iii)—Equipment located at natural gas processing plants. Similarly, for the same reason, we have also modified the exclusion for § 63.764(c)(2) by removing “and equipment at natural gas processing plants, respectively.”
• § 63.760(a)(2)—Facilities that process, upgrade or store hydrocarbon liquids;
• § 63.760(b)(1)(ii)—Each storage vessel with the potential for flash emissions;
• § 63.760(g)—Recordkeeping for major sources that overlap with other regulations for equipment leaks;
• § 63.764(c)(2)—Requirements for compliance with standards for storage vessels;
• § 63.766—Storage vessel standards; and
• § 63.769—Equipment leak standards.
For purposes of this FIP, owners/operators of true minor sources (and minor modifications at true minor sources) must comply with all of the applicable provisions of 40 CFR part 60, subpart KKKK (Standards of Performance for Stationary Combustion Turbines), as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source.

C. Addressing Threatened and Endangered Species and Historic Properties
We are requiring that, prior to beginning construction, under § 49.104, new true minor sources and minor modifications at existing true minor sources document that potential impacts on threatened and endangered species and historic properties (collectively referred to as “protected resources”) have been assessed. The section provides two options for documenting this assessment: (1) Submittal of documentation to the EPA Regional Office (and to the relevant tribe for the area where the source is located or locating) that a site-specific assessment conducted by another federal agency has been completed for the specific oil and natural gas activity, and that the owner/operator meets all air quality-related requirements as specified within all documents/approvals obtained through that assessment (these requirements are typically implemented and enforced as conditions of an approved Surface Use Plan of Operations and/or Application for Permit to Drill); ^{14} or (2) submittal of documentation to the EPA Regional Office (and to the relevant tribe for the area where the source is located or locating) demonstrating that the source has completed the screening processes specified by the EPA for consideration of threatened and endangered species and historic properties and received a determination from the EPA stating that it has satisfactorily completed these processes. ^{15} (The processes are contained in the following document: “Procedures to Address Threatened and Endangered Species and Historic Properties for the Federal Implementation Plan for Managing Air Emissions from True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector,” https://www.epa.gov/tribal-air/tribal-minor-new-source-review. )
^{14} This assessment will typically be conducted through the National Environmental Policy Act process and result in either a Record of Decision or a Finding of No Significant Impact document.
^{15} This process of source documentation submittal and the EPA's confirmation that it has satisfactorily completed the procedures must occur prior to the source's submittal of its Part 1 Registration Form pursuant to § 49.160(c)(1)(iv).

D. Summary of Final Amendments to the Federal Indian Country Minor NSR Rule
This action finalizes several amendments to the Federal Indian Country Minor NSR rule.
First, we are revising § 49.151(b)(1) to add new text regarding the purpose of the Federal Minor NSR Program in Indian Country. The revised text indicates that the program satisfies the requirements of section 110(a)(2)(C) of the Clean Air Act (CAA) by establishing: (1) A pre-construction permitting program for all new and modified minor sources (minor sources) and minor modifications at major sources located in Indian reservations and other areas of Indian country over which an Indian tribe, or the EPA, has demonstrated that the tribe has jurisdiction and where there is no EPA-approved program in place, and (2) a FIP (§§ 49.101 to 49.105) for true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector that are located in such areas of Indian country.
Second, we are revising § 49.151(c)(1) (and § 49.166(c)(1)) to comport the applicability of the Federal Indian Country Minor NSR rule with a court decision that addressed the scope of the EPA's jurisdiction to implement the Federal Indian Country Minor NSR rule: Oklahoma Dept. of Environmental Quality v. EPA, 740 F.3d 185 (D.C. Cir. 2014) (hereinafter referred to as ODEQ v. EPA ). ^{16} We are also noting in the definition of Indian country in § 49.152(d) (and § 49.167) that the geographic scope of the application of the rule is as specified in § 49.151(c)(1) (and § 49.166(c)(1)). ^{17}
^{16} In that case, the U.S. Court of Appeals for the District of Columbia Circuit vacated the Federal Indian Country Minor NSR rule and Federal Indian Country Nonattainment Major NSR rule with respect to non-reservation areas of Indian country ( i.e., dependent Indian communities and Indian allotments located outside of reservations) in the absence of a demonstration of tribal jurisdiction by the EPA or a tribe.
^{17} We are also revising § 49.166(c)(1) to comport the applicability of the Federal Indian Country Nonattainment Major NSR rule with the ODEQ v. EPA decision. The court decision has the same effect on the scope of the EPA's jurisdiction under the Federal Major New Source Review Program for Nonattainment Areas in Indian Country and so we are changing the applicability of the Federal Indian Country Nonattainment Major NSR rule as well.
Third, we are revising § 49.151(c)(1)(iii)(A) to clarify requirements for oil and natural gas activities with respect to the registration deadline that conforms with the permitting deadline in § 49.151(c)(1)(iii)(B).
Fourth, we are revising § 49.151(c)(1)(iii)(B) to clarify requirements for oil and natural gas activities with respect to the permitting deadline. We are also revising the provision to provide that true minor oil and natural gas sources can either comply with the FIP in lieu of obtaining a minor NSR permit or obtain a minor source permit if the source opts out of the FIP.
Fifth, we are revising § 49.151(d)(1), (2) and (4) to incorporate compliance with the FIP. We are revising § 49.151(d)(1) to indicate that if you begin construction of a new source or modification that is subject to the Federal Indian Country Minor NSR Program after the applicable date ^{18} without either applying for and receiving a permit pursuant to the program or complying with the FIP for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, the owner/operator of the source will be subject to appropriate enforcement action. We are revising § 49.151(d)(2) to indicate that if you do not construct or operate your new source or existing source modification in accordance with the terms of your minor NSR permit or the FIP for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, you will be subject to appropriate enforcement action. We are revising § 49.151(d)(4) to indicate that issuance of a permit or compliance with the FIP for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector does not relieve the owner/operator of a source of the responsibility to comply fully with applicable provisions of any EPA-approved implementation plan or FIP or any other requirements under applicable law.
^{18} This date is September 2, 2014, for all true minor sources, except oil and natural gas true minor sources, and October 3, 2016, for oil and natural gas true minor sources.
Sixth, we are amending § 49.152 by adding a definition for “Startup of production,” which, to ensure consistency across the EPA's regulations for the oil and natural gas sector, points directly to the term as defined under 40 CFR part 60, subpart OOOOa.
Seventh, we are revising §§ 49.153(a)(1)(i)(B) and (a)(1)(ii)(B) to establish that true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector are required to comply with the FIP, unless the owner/operator of a source opts-out or is otherwise required by the EPA to obtain a minor source permit. Existing § 49.153(a)(1)(i)(B) requires the owner/ operator of a new source to determine whether the source's potential to emit (PTE) is equal to or greater than the corresponding minor NSR threshold. If it is, then the source is subject to the pre-construction requirements of the Federal Indian Country Minor NSR rule for that pollutant. The amendment adds a clause to the end of the paragraph stating that for sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, if the PTE for oil and natural gas production sources is equal to or greater than the corresponding minor NSR threshold, such sources shall instead comply with the requirements of §§ 49.101 to 49.105, unless the owner/operator of the source opts-out of the FIP pursuant to § 49.101(b)(2), or is otherwise required by the EPA to obtain a source-specific minor source permit pursuant to § 49.101(b)(3).
Existing § 49.153(a)(1)(ii)(B) requires the owner/operator of modified sources to determine whether the increase in allowable emissions resulting from the modification would be equal to or greater than the minor NSR threshold for the pollutant being evaluated. If it is, then the source is subject to the pre-construction requirements of the Federal Indian Country Minor NSR rule for that pollutant. The amendment adds a clause to the end of the paragraph stating that, for sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, if the PTE for such sources is equal to or greater than the corresponding minor NSR threshold, such sources must instead comply with the requirements of §§ 49.101 to 49.105, unless the owner/operator of the source opts-out of the FIP pursuant to § 49.101(b)(2) or is otherwise required by the EPA to obtain a minor source permit pursuant to § 49.101(b)(3).
Finally, we are revising §§ 49.160(c)(1)(ii) and (iii), adding § 49.160(c)(1)(iv) and revising § 49.160(c)(4). For § 49.160(c)(1)(ii), we are revising the provision to clarify requirements for oil and natural gas activities with respect to the registration deadline that conforms with the permitting deadline in § 49.151(c)(1)(iii)(B). For § 49.160(c)(1)(iii), we are revising the language to indicate that if your true minor source is an oil and natural gas source, and you commence construction or modification of your source on or after October 3, 2016, ^{19} you must report your source's actual emissions (if available) as part of your permit application (source-specific permits), unless you are subject to the FIP. (If you are subject to the FIP, then you must register your oil and natural gas source pursuant to § 49.160(c)(1)(iv).) For source-specific oil and natural gas source permittees, your permit application will be used to fulfill the registration requirements described in § 49.160(c)(2).
^{19} In the proposed FIP action, we had proposed to extend the registration form from the then applicable date of March 2, 2016, to October 3, 2016. We have since finalized amendments to extend the permitting compliance and registration deadlines (“Review of New Sources and Modifications in Indian Country: Extension of Permitting and Registration Deadlines for True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 9109, February 24, 2016, https://www.gpo.gov/fdsys/pkg/FR-2016-02-24/pdf/2016-03623.pdf ).
We are adding § 49.160(c)(1)(iv) to indicate that sources subject to the FIP must still satisfy the requirement to register under the Federal Indian Country Minor NSR rule by using the two registration forms provided by the EPA ^{20} rather than a permit application. The registration form contains the information required in § 49.160(c)(2). Minor sources complying with the FIP for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, must submit the Part 1 Registration Form that contains the information in § 49.160(c)(2) 30 days prior to beginning construction. The Part 2 Registration Form must be submitted within 60 days after the startup of production as defined in § 49.152(d). The source must determine the potential for emissions within 30 days after startup of production. The combination of the Part 1 and Part 2 Registration Form submittals satisfies the requirements in § 49.160(c)(2). The forms are submitted instead of the application form otherwise required in § 49.160(c)(1)(iii). After being reviewed by the permitting authority, completed registration forms will be available online on the appropriate EPA Regional Office Web site.
^{20} The registration forms are available at: https://www.epa.gov/tribal-air/tribal-minor-new-source-review or from the EPA Regional Offices.
For § 49.160(c)(4), we are adding language indicating that submitting a registration form does not relieve a source of the requirement to comply with the FIP for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector if the source or any physical or operational change at the source would be subject to any minor or major NSR rule.

III. Background

A. Federal Indian Country Minor NSR Rule

1. What is the Federal Indian Country Minor NSR rule?
On August 21, 2006, the EPA proposed the regulation: “Review of New Sources and Modifications in Indian Country” (commonly referred to as the Federal Indian Country NSR rule). ^{21} Within this proposed regulation, the EPA proposed to protect air quality in Indian country, as defined in 18 U.S.C. 1151, by establishing a FIP program to regulate, among other matters, the modification and construction of minor stationary sources consistent with the requirements of section 110(a)(2)(c) of the CAA. We refer to this part of the Federal Indian Country NSR rule as the Federal Indian Country Minor NSR rule. Under the Federal Indian Country Minor NSR rule, we proposed to fill a regulatory gap and provide a mechanism for issuing pre-construction permits for the construction of new minor sources and certain modifications of major and minor sources in Indian country. We promulgated final rules on July 1, 2011, ^{22} and the FIP became effective on August 30, 2011.
^{21} “Review of New Sources and Modifications in Indian Country,” U.S. Environmental Protection Agency, 71 FR 48696, August 21, 2006, https://www.gpo.gov/fdsys/pkg/FR-2006-08-21/pdf/06-6926.pdf.
^{22} “Review of New Sources and Modifications in Indian Country,” U.S. Environmental Protection Agency, 76 FR 38748, July 1, 2011, https://www.gpo.gov/fdsys/pkg/FR-2011-07-01/pdf/2011-14981.pdf.
The Federal Indian Country Minor NSR rule applies to new and modified minor stationary sources and to minor modifications at existing major stationary sources located in Indian country where there is no EPA-approved program in place for all new and modified minor sources (minor sources) and minor modifications at major sources located in areas covered by the Federal Indian Country Minor NSR rule.
Tribes can elect to develop and implement their own EPA-approved program under the Tribal Authority Rule, ^{23} but they are not required to do so. ^{24} In the absence of an approved tribal program, the EPA implements this program. Alternatively, tribes can take delegation of the program from the EPA to assist the EPA with administration of the federal program, including acting as the Reviewing Authority for the EPA.
^{23} To obtain eligibility to develop and implement an EPA-approved plan, under the Tribal Authority Rule a tribe must meet four requirements: (1) Be a federally-recognized tribe, (2) have a functioning government, (3) have the legal authority and (4) have the capacity to run the program. For more information go to: “Indian Tribes: Air Quality Planning and Management,” U.S. Environmental Protection Agency, 63 FR 7254, February 12, 1998, http://www.gpo.gov/fdsys/pkg/FR-1998-02-12/pdf/98-3451.pdf.
^{24} Under tribal law, tribes may also be able to establish permit fees under a tribal permitting program, as do most states.
Beginning September 2, 2014, any new stationary sources, other than true minor sources in the oil and natural gas sector, that will emit, or will have the potential to emit, a regulated NSR pollutant in amounts that will be: (a) Equal to or greater than the minor NSR thresholds established in the Federal Indian Country Minor NSR rule; and (b) less than the amount that would qualify the source as a major source or a major modification for purposes of the PSD or nonattainment major NSR programs, must apply for and obtain a minor NSR permit before beginning construction of the new source. Likewise, any existing stationary source (minor or major) must apply for and obtain a minor NSR permit before beginning construction of a physical or operational change that will increase the allowable emissions of the stationary source by more than the specified threshold amounts, if the change does not otherwise trigger the permitting requirements of the PSD or nonattainment major NSR program(s). ^{25}
^{25} A source may, however, be subject to certain monitoring, recordkeeping and reporting (MRR) requirements under the major NSR programs, if the change has a reasonable possibility of resulting in a major modification. A source may be subject to both the Federal Indian Country Minor NSR rule and the reasonable possibility MRR requirements of the major NSR program(s).
Among other things, the Federal Indian Country Minor NSR rule created a framework for the EPA to streamline the issuance of pre-construction permits to true minor sources by using general permits.

2. What is a true minor source and how does it differ from a synthetic minor source?
The designation of a source for the FIP applicability is dependent on the source's PTE. Per § 52.21(b)(4), PTE means the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation or the effect it would have on emissions is federally enforceable. Secondary emissions do not count in determining the potential to emit of a stationary source.
“True minor source,” under the Federal Indian Country Minor NSR rule means a source that emits, or has the potential to emit, regulated NSR pollutants in amounts that are less than the major source thresholds under either the PSD Program at § 52.21, or the Federal Major NSR Program for Nonattainment Areas in Indian Country at §§ 49.166-49.173, but equal to or greater than the minor NSR thresholds in § 49.153, without the need to take an enforceable restriction to reduce its PTE to such levels. A source's PTE includes fugitive emissions, to the extent that they are quantifiable, only if the source belongs to one of the 28 source categories listed in part 51, appendix S, paragraph II.A.4(iii) or § 52.21(b)(1)(iii) of 40 CFR, as applicable.
By contrast, “synthetic minor source” means a source that otherwise has the potential to emit regulated NSR pollutants in amounts that are at or above those thresholds for major sources, but that has voluntarily taken a restriction so that its PTE is less than such amounts. Such restrictions must be enforceable as a legal and practical matter.

3. What is a general permit?
A general permit, for purposes of this action, is a permit document that contains standardized requirements that multiple stationary sources can use. The Federal Indian Country Minor NSR rule specifies the process and requirements for using general permits to authorize construction and modifications at minor sources as a streamlined permitting approach. The EPA may issue a general permit for categories of emissions units or stationary sources that are similar in nature, have substantially similar emissions, and would be subject to the same or substantially similar permit requirements. ^{26} “Similar in nature” refers to size, processes, and operating conditions. The purpose of a general permit is to protect air quality while simplifying the permitting process for similar minor sources. General permits offer a cost-effective means of issuing permits and provide a quicker and simpler mechanism for permitting minor sources than the source-specific permitting process.
^{26} “Review of New Sources and Modifications in Indian Country,” U.S. Environmental Protection Agency, 76 FR 38770, July 1, 2011, https://www.gpo.gov/fdsys/pkg/FR-2011-07-01/pdf/2011-14981.pdf.
The final Federal Indian Country Minor NSR rule contemplated issuance of general permits by the EPA Regional Offices. ^{27} While to date the general permits that we have issued have been national in scope, we will issue general permits on a different geographic scale as appropriate. ^{28}
^{27} If a tribe develops an EPA-approved implementation plan, then under that plan it could also issue its own general permits.
^{28} We may in the future issue general permits on a smaller geographic scale for a particular state or region of the country. In fact, in the first batch of streamlined permits we issued in May 2015, we indicated that EPA Region 9 will be developing a general permit or permit by rule for areas within California for gasoline dispensing facilities. In addition, once the EPA issues a general permit at the national level, Regional Offices serving as Reviewing Authority do grant coverage under nationally-issued general permits (as well as any general permits issued by that region for a smaller geographic area). See “General Permits and Permits by Rule for the Federal Minor New Source Review Program in Indian Country for Five Source Categories,” U.S. Environmental Protection Agency, 80 FR 25068, May 1, 2015, http://www.gpo.gov/fdsys/pkg/FR-2015-05-01/pdf/FR-2015-05-01-FrontMatter.pdf.

B. What is a FIP?
In our proposed rule of September 18, 2015, ^{29} we discussed the concept of a FIP, including our authority to issue FIPs, at great length. There are no currently approved Tribal Implementation Plans (TIPs) that require the issuance of pre-construction permits designed to reduce emissions related to oil and natural gas facilities. As a result, the Federal Indian Country Minor NSR rule serves this purpose. We have concluded that the issuance of source-specific permits to sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector has the potential to overwhelm the system. We initially considered issuing a general permit or permit by rule for these sources, but ultimately concluded that the issuance of a FIP would be a more effective way of addressing the situation for a few reasons. Both a general permit and a permit by rule provide a more streamlined approach for authorizing construction and modification of a source compared to site-specific permitting. However, a general permit still requires a source to submit an application and to obtain approval of coverage from the Reviewing Authority before beginning construction, and would, thus, pose a resource burden on reviewing authorities associated with processing the potentially large volume of requests from true minor sources in the oil and natural sector for coverage. So, from those standpoints a FIP is preferable to a general permit. In comparing a permit by rule to a FIP, the EPA prefers the FIP because it provides more certainty for affected sources than the permit by rule approach and, as discussed below, does not have any significant disadvantages as compared to the permit by rule approach. ^{30}
^{29} “Review of New Sources and Modifications in Indian Country: Federal Implementation Plan for Managing Air Emissions from True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 56554, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21025.pdf.
^{30} For a further discussion comparing these three options, see: “Review of New Sources and Modifications in Indian Country: Federal Implementation Plan for Managing Air Emissions from True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 56554, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21025.pdf.
We believe a FIP is the most appropriate way of implementing the Federal Indian Country Minor NSR rule in that it protects air quality while at the same time reducing the impact on the Reviewing Authority arising from the issuance of source-specific permits for these sources. (The FIP also reduces the burden on industry and other interested stakeholders.) Therefore, in this final action, we have determined that it is necessary or appropriate to exercise our discretionary authority under sections 301(a) and 301(d)(4) of the CAA and § 49.11(a) to protect air quality by promulgating a FIP applicable to true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector in areas covered by the Federal Indian Country Minor NSR rule where there is no EPA-approved program in place that contains legally and practicably enforceable requirements to control and reduce air emissions from such sources.

C. Oil and Natural Gas Sector
In our proposed rule of September 18, 2015, we provided background on the oil and natural gas sector. For a more complete description of the sector, the reader should consult the Advance Notice of Proposed Rulemaking (ANPR) we issued in June 2014. ^{31}
^{31} “Managing Emissions from Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 79 FR 32502, June 5, 2014, http://www.gpo.gov/fdsys/pkg/FR-2014-06-05/pdf/2014-12951.pdf.
The oil and natural gas sector includes operations involved in the extraction and production of oil and natural gas, as well as the processing, transmission and distribution of natural gas. Specifically for oil, the sector includes all operations from the well to the point of custody transfer to an oil transmission pipeline or other means of transportation to a petroleum refinery. For natural gas, the sector includes all operations from the well to the final end user. The oil and natural gas sector can generally be separated into four segments: (1) Oil and natural gas production; (2) natural gas processing; (3) natural gas transmission and storage; and (4) natural gas distribution.

D. EPA Actions Affecting Oil and Natural Gas Minor Sources in Areas Covered by the Federal Indian Country Minor NSR Rule

1. Extension of Permitting Compliance and Registration Deadlines
On January 14, 2014, the EPA published a proposed rule, “General Permits and Permits by Rule for the Federal Minor New Source Review Program in Indian Country,” ^{32} that included two proposed amendments that affected true minor sources in the oil and natural gas sector. The proposed amendments were: (1) The extension of the deadline by which new true minor sources and minor modifications of existing true minor sources in the oil and natural gas sector must receive minor NSR permits prior to commencing construction, from September 2, 2014, to March 2, 2016; and (2) an adjustment to the deadline by which existing true minor sources in the oil and natural gas sector must register, from September 2, 2014, to March 2, 2016. On June 16, 2014, the EPA finalized those amendments as proposed. ^{33} On September 18, 2015, the EPA proposed to extend these dates further to October 3, 2016. ^{34}
^{32} “General Permits and Permits by Rule for the Federal Minor New Source Review Program in Indian Country,” U.S. Environmental Protection Agency, 79 FR 2546, January 14, 2014, http://www.gpo.gov/fdsys/pkg/FR-2014-01-14/pdf/2013-30345.pdf.
^{33} For more information, see: “Review of New Sources and Modifications in Indian Country Amendments to the Registration and Permitting Deadlines for True Minor Sources,” U.S. Environmental Protection Agency, 79 FR 34231, June 16, 2014, http://www.gpo.gov/fdsys/pkg/FR-2014-06-16/pdf/2014-14030.pdf.
^{34} “Review of New Sources and Modifications in Indian Country: Federal Implementation Plan for Managing Air Emissions from True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 56554, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21025.pdf.
On February 24, 2016, ^{35} we finalized three amendments to the Federal Indian Country Minor NSR rule that we had proposed at the same time as the FIP and the other amendments we are finalizing in this action. The amendments are:
^{35} As noted above, we have already finalized amendments to extend the permitting compliance and registration deadlines (“Review of New Sources and Modifications in Indian Country: Extension of Permitting and Registration Deadlines for True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 9109, February 24, 2016, https://www.gpo.gov/fdsys/pkg/FR-2016-02-24/pdf/2016-03623.pdf ).
First, we revised the deadline under § 49.151(c)(1)(iii)(B) by which new and modified true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector that are located in (or planning to locate in) reservation areas of Indian country or other areas of Indian country for which tribal jurisdiction has been demonstrated, must obtain a minor NSR permit prior to beginning construction. We extended the deadline from March 2, 2016, to October 3, 2016, for all true minor sources (both new and modified true minor sources) ^{36} within the oil and natural gas sector located in Indian country.
^{36} The preamble in the February 24, 2016 Federal Register notice mistakenly indicates that the extension also applies to minor modifications at major oil and natural gas sources; this was an error. The rule language itself correctly indicates that the extension applies to only new and modified true minor oil and natural gas sources.
Second, we revised § 49.151(c)(1)(iii)(A) to conform the registration deadline to the extended permitting deadline in § 49.151(c)(1)(iii)(B).
Finally, we revised § 49.160(c)(1)(ii) to conform the registration deadline to the extended permitting deadline in § 49.151(c)(1)(iii)(B).

2. Advance Notice of Proposed Rulemaking
On June 5, 2014, the EPA published an advance notice of proposed rulemaking (ANPR). ^{37} The purpose of the ANPR was to solicit broad feedback on the most effective and efficient means of implementing the Federal Minor NSR Program in Indian Country for sources in the production segment of the oil and natural gas sector. In it, we discussed alternatives to source-specific permits for new and modified minor sources engaged in oil and natural gas production activities. The EPA requested comments on the alternative approaches and other aspects of managing air emissions from oil and natural gas sources in areas covered by the Federal Indian Country Minor NSR rule.
^{37} For more information, see: “Managing Emissions from Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 79 FR 32502, June 5, 2014, http://www.gpo.gov/fdsys/pkg/FR-2014-06-05/pdf/2014-12951.pdf.

3. Proposed FIP and Associated Amendments
On September 18, 2015, the EPA proposed a FIP ^{38} that would apply to new true minor sources and minor modifications at existing true minor sources in the production segment of the oil and natural gas sector that are locating or expanding areas covered by the Federal Indian Country Minor NSR rule. We said that the FIP would satisfy the minor source permitting requirement under the Federal Indian Country Minor NSR rule. The proposed FIP proposed to require compliance with emission limitations and other requirements from six federal emission standards as written at the time of construction or modification for compression ignition and spark ignition engines, compressors (reciprocating and centrifugal), fuel storage tanks, fugitive emissions from well sites and compressor stations, glycol dehydrators, hydraulically fractured oil and natural gas well completions, pneumatic controllers in production, pneumatic pumps, process heaters and storage vessels.
^{38} “Review of New Sources and Modifications in Indian Country: Federal Implementation Plan for Managing Air Emissions from True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 56554, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21025.pdf.
The EPA also proposed several amendments to the Federal Indian Country Minor NSR rule, including adding new text regarding the purpose of the program, revising the program overview provision, establishing a compliance deadline of October 3, 2016 for all true minor sources (both new and modified true minor sources) within the oil and natural gas sector, revising certain provisions to incorporate compliance with the FIP, revising the applicability provision to establish that sources are required to comply with the FIP unless they opt to obtain a source-specific permit or are otherwise required to obtain a source-specific permit, and revising the source registration provision. Also, we proposed to revise the definition of Indian country for purposes of the rule to comport with a court decision that addressed the scope of the EPA's jurisdiction to implement the Federal Indian Country Minor NSR rule: ODEQ v. EPA. This court decision also affects the scope of the EPA's jurisdiction under the Federal Nonattainment Major NSR Program in Indian Country so we proposed changing the definition under the Federal Indian Country Nonattainment Major NSR rule as well.

4. Other Oil and Natural Gas Actions
On September 18, 2015, the EPA proposed updates to the NSPS for the oil and natural gas sector. ^{39} The proposed FIP would adopt the standards from six federal rules, including the oil and natural gas NSPS. Changes to these rules would affect requirements in the FIP because the proposed FIP would adopt all or parts of these six federal emission standards, including future amendments. In addition, on September 18, 2015, the EPA proposed an oil and natural gas source determination rule. ^{40} This action is also connected to this FIP as it would affect how oil and natural gas sources are defined for the purpose of major/minor source determinations.
^{39} “Oil and Natural Gas Sector: Emission Standards for New and Modified Sources,” U.S. Environmental Protection Agency, 80 FR 56593, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21023.pdf.
^{40} “Source Determination for Certain Emission Units in the Oil and Natural Gas Sector,” U.S. Environmental Protection Agency, 80 FR 56579, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21026.pdf.

IV. Summary of Final Action, Comments and Responses

A. Overview of Changes to the FIP and Federal Indian Country Minor NSR Rule
The purpose of this section is to provide an overview of key aspects of our September 2015 proposed rule, our final action, and relevant comments and our responses. The EPA received numerous thoughtful and helpful comments on the proposal. After careful consideration of this input, we are finalizing the FIP with some changes. Overall, here are what we consider to be the most significant changes we are making in this final rule. These changes are discussed in greater detail below (except as noted):
(1) Amending the Federal Indian Country Minor NSR rule in several ways, including:
a. Amending §§ 49.152 and 49.160 of the Federal Indian Country Minor NSR rule to provide for a two-part source registration process, including adding a definition to § 49.152(d) for “Startup of production” that was not proposed but which is necessary to accommodate the modified registration process;
b. Amending §§ 49.151 and 49.160 of the Federal Indian Country Minor NSR rule to clarify how these provisions relate to the FIP, including adjusting references to the oil and natural gas sector so that the provisions being amended function properly with respect to that sector and the final FIP and to reflect the expanded source scope of the final FIP;
c. Amending §§ 49.151 and 49.152 (and §§ 49.166 and 49.167) to update the applicability of the Federal Indian Country Minor NSR rule (and Federal Indian Country Nonattainment Major NSR rule) to comport with a court decision that addressed the scope of the EPA's jurisdiction to implement the Federal Indian Country Minor NSR rule: ODEQ v. EPA; and
d. Amending § 49.160 to clarify that, after October 3, 2016, sources engaged in oil and natural gas activity not subject to the FIP will use their source-specific permit applications for registration (instead of a registration form);
(2) Modifying the draft source registration form that we provided for comment at proposal to:
a. Provide for a two-part source registration process, including making clear that the Part 1 Registration Form is due 30 days prior to beginning construction and that the Part 2 Registration Form is due within 60 days after the startup of production (as defined in § 49.152(d)); ^{41}
^{41} We also make it clear in the Part 2 Registration Form that sources must determine their potential emissions within 30 days after startup of production.
b. Clarify what emissions-related information is required for submittal as part of the Part 2 Form registration process;
c. Clarify that fuel usage and production rates should be provided on an annual basis;
d. Removed the request for emissions and other information for hazardous air pollutants, which are not regulated by the Federal Indian Country Minor NSR rule;
e. Provide a Confidential Business Information disclaimer;
f. Clarify how sources should provide documentation that they are meeting the threatened and endangered species and historic properties criteria under § 49.104 along with the registration form; and
g. Condense and reorganize the request for emissions information to make it clearer to the source;
(3) Providing guidance that we intend to potentially apply this national FIP's requirements as appropriate to nonattainment areas where the EPA has established a separate, area-specific FIP;
(4) Changing the FIP as proposed in several areas:
a. Modifying § 49.101 to change “oil and natural gas production facility” to “oil and natural gas source” and also clearly linking the modified wording to the reworded definition of oil and natural gas source in § 49.102;
b. Replacing the definition of oil and natural gas production facility in § 49.102 with oil and natural gas source, which also includes natural gas processing, but excludes natural gas transmission and distribution;
c. Expanding the scope of the FIP by revising §§ 49.101 and 49.102 to cover non-major gas processing plants and the definition of oil and natural gas source;
d. Adding a subparagraph to § 49.101 to make it clear that the FIP does not apply to minor modifications at major sources;
e. Rewording § 49.104 to specify the information that is acceptable to document that a source has addressed threatened and endangered species and historic properties;
f. Expanding § 49.104 to add the process the Reviewing Authority will use to determine whether the screening procedures provided to the EPA have been satisfactorily completed to address threatened and endangered species and historic properties;
g. Expanding § 49.105 to add two federal standards to the FIP's requirements:
i. 40 CFR part 63, subpart ZZZZ—NESHAP for Stationary Reciprocating Internal Combustion Engines; and
ii. 40 CFR part 60, subpart KKKK—Standards of Performance for New Stationary Combustion Turbines;
h. Adjusting exclusions from this FIP for the following two standards under § 49.105 to reflect the expansion of the scope of the FIP to natural gas processing plants (not discussed below—instead, see Section II.B.):
i. 40 CFR part 60, subpart IIII—Standards of Performance for Stationary Compression Ignition Internal Combustion Engines;
ii. 40 CFR part 60, subpart OOOOa—Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced after September 18, 2015; and
iii. 40 CFR part 63, subpart HH—NESHAP from Oil and Natural Gas Production Facilities; and
i. Clarifying under § 49.105 that the FIP applies not just to true minor sources but to minor modifications at true minor sources as well.

B. Proposed Amendments to the Federal Indian Country Minor NSR Rule

1. Proposed Rule
The EPA proposed amendments to the Federal Indian Country Minor NSR rule, including adding new text regarding the purpose of the program, revising the program overview provision, establishing a compliance deadline of October 3, 2016 for all true minor sources (both new and modified true minor sources) within the oil and natural gas sector, revising certain provisions to incorporate compliance with the FIP, revising the applicability provision to establish that sources are required to comply with the FIP unless they opt to obtain a source-specific permit or are otherwise required to obtain a source-specific permit, and revising the source registration provision. Also, we proposed to revise the definition of Indian country for purposes of the rule to comport with a court decision that addressed the scope of the EPA's jurisdiction to implement the Federal Indian Country Minor NSR rule: ODEQ v. EPA. This court decision also affects the scope of the EPA's jurisdiction under the Federal Major NSR Program in Indian Country, so we proposed to change the definition under the Federal Indian Country Nonattainment Major NSR rule as well.

2. Final Action
As mentioned in Section III.D., we have already finalized three amendments to extend the permitting compliance and registration deadlines for true minor sources in the oil and natural gas sector. ^{42} In today's action, we are finalizing the remainder of the amendments as described in Section II.D., as proposed, with five exceptions:
^{42} “Review of New Sources and Modifications in Indian Country: Extension of Permitting and Registration Deadlines for True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 9109, February 24, 2016, https://www.gpo.gov/fdsys/pkg/FR-2016-02-24/pdf/2016-03623.pdf.
First, we are amending §§ 49.151, 49.153 and 49.160 of the Federal Indian Country Minor NSR rule to clarify how these provisions relate to the FIP, including adjusting references to the oil and natural gas sector so that the provisions being amended function properly with respect to that sector and the final FIP and to reflect the expanded source scope of the final FIP.
Second, we are revising § 49.160(c)(1)(iii) and (iv) as proposed by adding further revisions to provide for a modified, two-part registration process under the Federal Indian Country Minor NSR rule for sources covered by this FIP. We are also modifying the oil and natural gas registration form as made available at proposal by splitting the form into two forms to provide for the two-part source registration process, requiring emissions information from sources after production is started. The changes are described above in Section IV.A.
Third, associated with that change, we are adding a definition to § 49.152(d) for “Startup of production” that was not proposed but which is necessary to accommodate the modified registration process.
Fourth, we are amending § 49.160(c)(1)(iii) to clarify that, after October 3, 2016, sources engaged in oil and natural gas activity not subject to the FIP will use their source-specific permit applications for registration (instead of a registration form).
Finally, we are amending §§ 49.151(c)(1) and 49.152(d) (and §§ 49.166(c)(1) and 49.167) to update the applicability of the Federal Indian Country Minor NSR rule and Federal Indian Country Nonattainment Major NSR rule, respectively, to comport with a court decision that addressed the scope of the EPA's jurisdiction to implement the Federal Indian Country Minor NSR rule: ODEQ v. EPA.

3. Comments and Responses
The following discussion contains comments on the proposed amendments to the Federal Indian Minor NSR rule and our responses. The comments and responses are also addressed in Section 1.0 of the Response to Comment (RTC) Document.

(a) Pre-Construction Permit Requirements
Comment #1: Five commenters expressed concern about the proposed pre-construction requirements and the difficulty in determining PTE before a well starts production due to the unpredictable nature of well development and productivity. Two commenters stated the requirement is burdensome and would lead to inaccurate data due to the unpredictable nature of oil and natural gas production.
Several commenters thought that pre-construction estimated emissions would be of limited value to the EPA and would create confusion for the public once released or used in modeling the effects of oil and natural gas production. One commenter noted that the pre-construction requirements limit the usefulness of the proposed FIP because owners/operators will not have definitive source-specific information before production begins.
One commenter requested that if the EPA were to retain the pre-construction requirements, then the EPA should provide a mechanism for revising emissions estimates after actual emissions are known.
Several commenters pointed to rules or state permitting programs that require post-construction information to be submitted, rather than pre-construction. For example, the Federal Indian Country Minor NSR rule requires operators to submit registration forms within 90 days of initial production. Several commenters pointed to state requirements, which acknowledge the unique challenges of permitting well production sites. Wyoming allows operation prior to permitting as long as the operator satisfies certain emission control requirements. In Colorado, emissions information is not required to be submitted until after drilling, workovers, completions, and testing are completed. North Dakota also has owners/operators submit the oil and natural gas well registration form within 90 days of completion of a well. Commenters believe that providing information after the well begins production will conserve EPA resources and provide the EPA with more accurate information, as well as align permitting processes on Indian lands with state permitting processes on adjacent lands.
As an alternative to pre-construction information, two commenters suggested that the EPA allow owners/operators to provide actual emissions data based on the first 30 days of production, due to the EPA 90 days after startup, similar to 40 CFR part 60, subpart OOOO.
As another alternative to providing pre-construction information, one commenter suggested a two-part approach:
Part 1: 30 days prior to the anticipated first date of production, submit owner/operator information, well location description, production equipment anticipated to be installed, and the anticipated first date of production.
Part 2: Within 60 days after first date of production, supply information on emissions and production rates as part of a notification process. The commenter requested 60 days as that date is used as part of the mineral rights royalty notification processes under the Department of Interior.
The same commenter submitted revisions to the draft registration form that we made available with the September 2015 proposed rule. The commenter asked the EPA to remove actual emissions data and to require operators to submit projected allowable emissions from the equipment, based on the initial production. The commenter stated that if the EPA needs to quantify actual emissions, the information will only be accurate through an emission inventory, versus using data submitted with the permit application, due to the actual emissions decreasing over time.
Response #1: The EPA has revised the Federal Indian Country Minor NSR rule and the registration form to incorporate a two-step registration process for oil and natural gas true minor sources locating or expanding in Indian country, as suggested by commenters. Generally, we prefer to receive registration forms complete with source and emissions information prior to construction, as we proposed and as required in § 49.160 of the Federal Indian Country Minor NSR rule for other source categories. However, we recognize the unique nature of the oil and natural gas industry and believe in this instance a two-part registration process is warranted.
The Part 1 Registration Form will be due 30 days before the source begins construction. The Part 2 Registration Form will be due within 60 days after the “startup of production,” in accordance with the subpart OOOOa definition of startup of production. (For the Part 2 Registration Form, we are adding the definition for “Startup of production” to § 49.152(d), which points directly to the term as defined under 40 CFR part 60, subpart OOOOa.) Sources must determine the potential for emissions within 30 days after startup of production, information which is required as part of the Part 2 Registration Form. The EPA has selected 60 days as the submittal date for the Part 2 Registration Form—the date requested by the commenter—as that timeframe will allow sufficent time for sources to assemble the emissions information required as part of the the Part 2 Registration Form and to submit it to the EPA.
The control requirements from the eight NSPS and NESHAP standards in this FIP will apply during production (the six standards included in the original proposal and two standards being added in the final rule). The owner/operator must account for emissions from startup of production as required in the Part 2 Registration Form submission. We disagree with the commenter about the type of emissions information that must be submitted with the registration form. Pursuant to § 49.160 of the Federal Indian Country Minor NSR rule, sources are required to submit allowable and actual emissions, not just allowable, as requested by the commenter. The owner/operator should calculate an estimate of the actual annual emissions using estimated operating hours, production rates, in-place control equipment, and types of materials processed, stored, or combusted during the upcoming consecutive 12 months.
The source, as documented by an owners/operators should use the definition in EPA's rulemaking on “Source Determination for Certain Emission Units in the Oil and Natural Gas Sector” ^{43} in defining each source on its registration form.
^{43} “Source Determination for Certain Emission Units in the Oil and Natural Gas Sector,” signed May 12, 2016, http://www.epa.gov/airquality/oilandgas/actions/html.

(b) The Definition of Indian Country in § 49.152
Comment #2: Several commenters expressed concern about the EPA's proposed definition change for the term Indian country as used in the rule. Two commenters disagreed with the fourth paragraph added to the definition of Indian country and noted that the EPA should not be vested with power to make determinations or demonstrations about tribal jurisdiction and that any such demonstration of jurisdiction should be left to the sovereign whose jurisdiction is being asserted. The commenters assert that although the EPA has indicated that this should only impact trust lands in Oklahoma, tribal allotments would also be impacted by the change in definition. One commenter recommended that the definition of Indian country include Indian reservation lands for which a TIP approved by the EPA pursuant to 40 CFR part 51 is not in effect, and over which an Indian tribe has demonstrated that it has jurisdiction.
One commenter stated that the EPA should be cautious of how the rule appears. By restating the definition of Indian country in the rule, it appears that the EPA is defining the term. Of course, the EPA cannot change the definition of Indian country through the proposed rule. The term Indian country was defined by Congress in statute. The EPA's regulations cannot change or modify this definition. The commenter suggested that the EPA should make it clear that Indian country is already statutorily defined and simply cross reference the relevant statute.
The commenter further states that the proposed and final rules should not state that the EPA is “revising the definition of Indian Country.” The commenter states that the EPA is doing no such thing. As a result of ODEQ v. EPA, the EPA is required to consider how it will apply the proposed rule in certain portions of Indian country, but the EPA is not revising the definition of Indian country. In other words, ODEQ v. EPA is not about the definition of Indian country, but rather the process the EPA is using to apply the proposed rule to certain parts of Indian country. The commenter recommends that the EPA remove all references to revised definitions of Indian country from the proposed rule. Rather than purporting to revise the definition of Indian country, the commenter suggests that the EPA include a new section discussing the applicability of the proposed rule.
Response #2: Regarding the commenters who expressed concern about the EPA's proposed changes to the sections of the rule that define Indian country, the EPA acknowledges the potential for confusion given that Indian country is a statutorily defined term at 18 U.S.C. 1151. We note that the EPA did not intend to, nor could we, change or in any way affect the statutory definition at 18 U.S.C. 1151 or the manner in which that statute is interpreted and applied for other purposes. Rather, we intended simply to address a 2014 decision of the D.C. Circuit ( ODEQ v. EPA ) that addressed the scope within Indian country of the EPA's authority to administer the Federal Indian Country Minor NSR rule—and, thus, the FIP in this action—and the Federal Indian Country Nonattainment Major NSR rule. ^{44} In that decision, the court invalidated the rules as applied to non-reservation areas of Indian country, unless the EPA or a tribe demonstrates that a tribe has jurisdiciton over such a non-reservation area. The court did not disturb application of the rules to Indian reservations. Our intent was, thus, not to alter the applicable definition of Indian country, but instead to address the scope of applicability of the rules within Indian country in light of the D.C. Circuit decision. To avoid potential confusion, we have altered the manner in which we are addressing this court ruling.
^{44} Oklahoma Dept. of Environmental Quality v. EPA, 740 F.3d 185 (D.C. Cir. 2014).
In the final rule, we have left the Indian country definitions largely intact and simply provided cross-references within the definitional sections of both rules—§§ 49.152 and 49.167—stating that the geographic scope of the rules' applicability will be as specified in the program overview sections of both rules—§§ 49.151 and 49.166. We have then addressed the limitation imposed by the court ruling ( i.e., that the rules will only apply in non-reservation areas of Indian country where there is a demonstration by a tribe or the EPA acting on behalf of a tribe of tribal jurisdiction over such area) in the program overview sections, which are more appropriate provisions in which to address this issue. These changes do not alter the substance of the revisions the EPA had proposed to address the ODEQ v. EPA ruling. Instead, they simply move the needed revisions to more appropriate locations in the rules, and, thus, avoid confusion about the applicable definition of Indian country as a general matter. Further, the EPA notes that the regulatory revisions finalized today to address the ODEQ v. EPA decision apply solely to the Federal Indian Country Minor NSR rule—and, thus, the FIP in today's action—and the Federal Indian Country Nonattainment Major NSR rule. They are not intended to apply to any other matter outside the scope of these rules.
In addition, while the EPA acknowledges the commenter's statement that an Indian tribe's jurisdiction should not need to be demonstrated to exist, the EPA notes that, consistent with the ODEQ v. EPA decision, a demonstration of tribal jurisdiction (either by the EPA or by an Indian tribe) would need to be made to support application of the Federal Indian Country Minor NSR rule in non-reservation areas of Indian country.
The EPA notes that the distinction between reservations and other areas that may be under an Indian tribe's jurisdiction ( i.e., non-reservation areas of Indian country) is derived from a CAA tribal-related provision (CAA section 301(d)(2)(B)). This provision includes a delegation of authority from Congress to eligible Indian tribes over their reservations, but expressly distinguishes other areas within a tribe's jurisdiction. For this reason, tribes seeking to administer their own CAA-regulatory programs would need to demonstrate their jurisdiction over any non-reservation area included in their application. ^{45} By virtue of the ODEQ v. EPA decision, such a demonstration of tribal jurisdiction must also be made (by a tribe or by the EPA) to support application of the Federal Indian Country Minor NSR rule in such non-reservation areas of Indian country.
^{45} For more information go to: “Indian Tribes: Air Quality Planning and Management,” U.S. Environmental Protection Agency, 63 FR 7254, February 12, 1998, http://www.gpo.gov/fdsys/pkg/FR-1998-02-12/pdf/98-3451.pdf.
Comment #3: Further, concerning the definition of Indian country, one commenter disagreed with the EPA's distinction between “on-reservation” and “off-reservation” Indian country and contended that tribes exercise jurisdiction over these lands through existing tribal sovereignty and in accordance with numerous federal programs that affirm tribal authorities and tribal self-determination over these lands and areas. The commenter contends that the distinction was not intended in the CAA and is not consistent with how tribes exercise authority over their lands. Nonetheless, the commenter generally supports the fourth paragraph added to the definition of Indian country, stating that the rule would apply to “all Indian reservation lands where no EPA-approved program is in place and all other areas of Indian country where no EPA-approved program is in place and over which an Indian tribe, or the EPA, has demonstrated that a tribe has jurisdiction.” However, the commenter does not believe that a tribe's jurisdiction has to be “demonstrated” to exist.
Response #3: Regarding the comment on the EPA's distinction between “on-reservation” and “off-reservation” Indian country, the EPA disagrees with the suggested changes. The EPA's revisions reflect the holding in ODEQ v. EPA. The decision acknowledges that either a tribe or the EPA can make such a demonstration of tribal jurisdiction over a non-reservation area of Indian country. Although the EPA is not typically called upon to assess tribal jurisdiction in the context of implementing a federal rule, it is appropriate for the EPA to make such determinations where required. The EPA has experience reviewing tribal jurisdiction in other contexts, most notably where tribes apply to administer regulatory programs under the EPA's statutes. In light of the ODEQ v. EPA decision, such jurisdictional assessments are also relevant for implementing federal permitting under the Federal Indian Country Minor NSR rule in non-reservation areas of Indian country.
Comment #4: One commenter acknowledged the EPA's intent in the proposed rulemaking to protect the reservation airsheds, while allowing for streamlined permitting of minor oil and natural gas sources, and requested that the EPA achieve this goal by developing and implementing the rule in a manner that promotes tribal sovereignty, authority, self-determination and a tribe's ability to develop resources. The commenter emphasized that the EPA should develop the proposed rule in a manner that recognizes that Indian lands are not public lands.
Another commenter noted that the EPA appears in the proposed rule to understand the concern for the oil and natural gas industry to be on tribal lands without tribal authorities having the ability to properly regulate the industry on their own. The commenter encouraged the EPA to recognize this potential situation while maintaining the tribe's choice on who to do business with, as well as retaining the tribe's relative autonomy to create their own pollution plans. The commenter acknowledged that the EPA's intentions in the proposed rule would likely provide better protections than any TIP.
Response #4: The EPA acknowledges that Indian country lands are not public lands and has solicited tribal feedback on the development of a streamlined permitting process that allows for tribes to develop resources on their lands. In doing so, the EPA seeks to protect air quality in Indian country, while also recognizing the importance of oil and natural gas activity as an important source of revenue for tribes, and has developed the FIP accordingly. Moreover, the development of this FIP does not preclude tribes from requesting to assist the EPA with administration of the FIP through a delegation agreement or from developing TIPs, which could include different or additional pollution control plans that tribes feel are needed to preserve air quality given the unique characteristics of their lands. No changes will be made in response to this comment.

C. Implementation-Related Issues

1. Proposed Rule
In the proposed rule, we discussed the effect of the proposed FIP on other Indian Country FIPs.
The FIP proposed in September 2015 was intended to fulfill the requirements of the Federal Indian Country Minor NSR rule to address the air quality impacts of new and modified true minor sources and to impose appropriate air pollution control requirements that protect the NAAQS, while providing an alternative to obtaining source-specific pre-construction approval through the NSR pre-construction permitting process. The proposed FIP was not intended to replace any other FIPs promulgated under the CAA for oil and natural gas sector sources in areas covered by the Federal Indian Country Minor NSR rule. Under the proposed FIP, an oil and natural gas source located in areas covered by the Federal Indian Country Minor NSR rule that is subject to another CAA FIP would have to continue to comply with that FIP and also have to comply with the proposed FIP. Generally, in cases where emission sources are already subject to a CAA FIP with more stringent requirements than those established for equivalent emission sources under the proposed FIP, those sources would be subject to the requirements of both FIPs, but those more stringent requirements supersede the requirements in this proposed FIP and compliance with the more stringent requirements would constitute compliance with both FIPs relative to those particular requirements. Conversely, if requirements for certain emission sources in the proposed FIP are more stringent than requirements for equivalent emission sources in another applicable CAA FIP, then those sources would be subject to the requirements of both FIPs, but the requirements in the proposed FIP supersede the requirements for equivalent emission sources in the other FIP and compliance with the more stringent requirements in the FIP would constitute compliance with the requirements of both FIPs relative to those particular requirements. In the case of the FIP for Oil and Natural Gas Well Production Facilities on the Fort Berthold Indian Reservation (FBIR FIP) ^{46} at §§ 49.4161-49.4168, ^{47} we defer to less stringent requirements in other federal CAA rules to avoid duplicative requirements. The FBIR FIP provides an exception to the general concept that the more stringent set of requirements govern.
^{46} In the proposed September 2015 FIP, we referred to “other FIPs” rather than just the FBIR FIP. Upon further review, we realize that the FBIR FIP is the only case of a FIP that illustrates an exception to the general concept.
^{47} “Approval and Promulgation of Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nation), North Dakota,” U.S. Environmental Protection Agency, 78 FR 17836, March 22, 2013, https://www.gpo.gov/fdsys/pkg/FR-2013-03-22/pdf/2013-05666.pdf.
In the September 2015 proposed FIP, we specifically addressed how it related to the FBIR FIP. The FBIR FIP is not a permitting program and does not exempt facilities from any federal CAA permitting requirements, which includes compliance with this FIP. Similarly, the proposed oil and natural gas FIP would not exempt facilities from complying with the FBIR FIP. The EPA recognizes that the VOC control requirements under the FBIR FIP are in some instances more stringent than those in the proposed FIP. For example, in the proposed FIP, we indicated that a new or modified oil and natural gas well production facility that is subject to the FBIR FIP—and also subject to the proposed FIP—would still need to comply with the FBIR FIP for casing head natural gas emissions and heater treater produced natural gas emissions. Requirements for these units were not contained in the proposed FIP.

2. Final Action
In this final action we are not changing our proposal in terms of how this FIP relates to other Indian country FIPs. However, there were several comments in this area that we are responding to below that relate to the proposal.

3. Comments and Responses
The following discussion contains comments on issues related to the FIP and our responses. The comments and responses are also addressed in Section 2.0 of the RTC Document.
Comment #5: One commenter requested that the EPA clarify how numerical VOC emission limitations will be applied through compliance with 40 CFR part 63, subpart HH, when the subpart has numerous compliance options that often do not contain specific numerical emission limitations. The commenter noted that the proposed FIP would create enforceable VOC emission reductions for glycol dehydrators through the requirements of 40 CFR part 63, subpart HH, using HAPs as a surrogate for VOCs.
Response #5: The FIP does not impose a separate VOC limit for glycol dehydration units that are subject to 40 CFR part 63, subpart HH ( i.e., independently of the FIP, the source will have to comply with the HAP control requirements, which also effectively control VOC and may or may not involve numerical emissions limitations). While the EPA recognizes that 40 CFR part 63, subpart HH, specifies several different control requirements depending on several factors ( e.g., major/area source status of the facility, actual natural gas throughput of the dehydrators, urban/rural location), any dehydrators subject to those standards will satisfy compliance with the FIP for those units by fully complying with the MACT standard. We have not made any changes in response to this comment.
Comment #6: One commenter stated that the proposed oil and natural gas FIP falls short in meeting several core objectives for permitting oil and natural gas sector facilities. The commenter stated that the foundation of the proposed FIP is still based on site-specific reviews, which by definition will inhibit its streamlining capabilities, and that this poses an obstacle to permitting. This could place future oil and natural gas development in Indian country at a disadvantage compared to more streamlined options available under state jurisdictions.
Response #6: The EPA disagrees that the foundation of the proposed FIP is based on source-specific permit reviews. While source-specific permits remain an option available to sources that do not wish to comply with the FIP, apart from addressing threatened and endangered species and historic properties, those sources that do wish to comply with the FIP need only register in accordance with the provisions of § 49.160(c)(1)(iv). This streamlined permitting mechanism allows for sources to begin construction 30 days after submittal of the Part 1 registration information. We have not made any changes in response to this comment.
Comment #7: One commenter requested that the EPA clarify how the proposed FIP will provide practical enforceability when several of the six rules included in the proposed FIP, such as 40 CFR part 63, subpart HH, do not contain practically enforceable requirements. The commenter noted that, because several of the standards do not contain practically enforceable requirements, sources that wish to restrict their PTE will be forced to obtain a source-specific permit. The commenter stated that the proposed FIP would fail to achieve the objective of providing sources a streamlined approach for obtaining legal and practically enforceable emission limitations.
Response #7: A source has to be a true minor source to use the FIP. The FIP is not intended to provide a mechanism for establishing synthetic minor sources. We have not made any changes in response to this comment.
Comment #8: One commenter (a state agency) noted that North Dakota regulations for natural gas capture have been enforced on the Fort Berthold Indian Reservation under multiple tax and regulatory agreements between the state and tribes. The commenter stated that the proposed rule will increase the number and complexity of conflicts with North Dakota regulations and the existing negotiated agreements. One commenter stated that the proposed rule could have significant impacts on their ability to administer their oil and natural gas regulatory program, and recommended that the proposed rule recognize and give deference to existing state and tribal agreements for natural gas permitting and regulation.
Response #8: The FIP adopted through this final action only applies to sources locating in Indian country and does not impose any requirements on sources located on state lands. The EPA also notes that the State of North Dakota has not been approved by the EPA to administer any program under the federal CAA on the Fort Berthold Indian Reservation. The EPA notes that there are no new requirements included as part of the FIP, only those rules already applicable to oil and natural gas sources under existing federal NSPS and NESHAP rules are included. We have not made any changes in response to this comment.
Comment #9: One commenter stated that the Federal Indian Country Minor NSR rule and the FIP should provide industry more flexible compliance options that are cost effective without compromising significant emissions reductions. The commenter suggested that the Federal Indian Country Minor NSR rule and the FIP should include an early action program, noting that, considering the uncertainty surrounding ozone standard designations in the Uinta Basin, an early action program would remove the risk for industry investments in emission reductions by ensuring appropriate credit for those investments. The commenter also suggested that the Federal Indian Country Minor NSR rule and the FIP should include an option for portfolio-wide emissions compliance, noting that a portfolio-wide approach would provide many operators the needed flexibility to more efficiently and cost-effectively achieve system-wide emission reductions that meet regulatory goals.
Response #9: Ozone Advance is the early action program that the EPA is offering to promote local efforts aimed at reducing ozone. ^{48} The program, which began in 2012, is available to states, local governments, and tribes that are interested in working proactively and collaboratively with the EPA to select and implement measures and programs that may reduce ozone air quality levels in attainment areas. Other stakeholders, such as industry, are encouraged to become actively involved in these efforts. Ozone Advance will continue to be available in conjunction with the Federal Indian Country Minor NSR rule, this FIP and any future, final FIPs developed for specific areas. As appropriate, such FIPs could consider portfolio-wide options allowing operators to reduce their emissions across entire tribal areas. We have not made any changes in response to this comment at this time.
^{48} For more information, go to: www.epa.gov/advance.
Concerning “credit”, the EPA cannot pre-approve State Implementation Plan (SIP)/TIP “credit” for emission reductions in areas that are not the subject of a nonattainment designation. However, early actions to improve air quality can both serve to prevent areas from becoming nonattainment and better position an area to comply with the requirements associated with an eventual nonattainment designation. For example, early emission reduction actions could potentially receive “credit” in future SIPs/TIPs if an area is eventually designated nonattainment with a Moderate or higher classification, either in terms of reflecting a lower baseline from which additional reductions are needed to meet reasonable further progress goals or, if they occur after the baseline year, as a measure that shows progress toward attainment.
If emission reductions occur after the baseline year, the area may take credit for those reductions subject to CAA requirements, such as demonstrating that the reductions are surplus, quantifiable, enforceable, and permanent. The state or tribe would also need to meet any other relevant requirement in CAA section 110 and/or section 172, and if the measure is voluntary, the state or tribe would need to make an enforceable commitment to ensure that the estimated emission reductions are achieved. Credit earned in this manner means that fewer additional emission reductions will be needed to meet reasonable further progress goals and to demonstrate attainment, thereby bringing the finish line of attainment with the ozone NAAQS closer.

D. Requirements Relating to Threatened or Endangered Species and Historic Properties

1. Proposed Rule
In the proposed rule, we proposed requirements for true minor oil and natural gas sources relating to threatened and endangered species and historic properties. The Endangered Species Act (ESA) requires federal agencies to ensure, in consultation with the U.S. Fish and Wildlife Service and/or the National Marine Fisheries Service (the Services), that any action they authorize, fund, or carry out will not likely jeopardize the continued existence of any listed threatened and endangered species, or destroy or adversely modify the designated critical habitat of such species. The National Historic Preservation Act (NHPA) requires federal agencies to take into account the effects of their undertakings on historic properties— i.e., properties that are either listed on, or eligible for listing on, the National Register of Historic Places—and to provide the Advisory Council on Historic Preservation (the Council) a reasonable opportunity to comment on such undertakings.
In developing the proposed FIP, EPA considered issues regarding listed species and historic properties and included provisions designed to ensure appropriate review of potential impacts on these protected resources. Although the individual coverage of each source that would operate under the FIP would not constitute a separate triggering action for ESA or NHPA purposes, we believe that the proposed FIP's procedures relating to listed threatened and endangered species and historic properties provide an appropriate site-specific means of addressing issues regarding potential impacts on those resources in connection with issuance of the FIP and, thus, in connection with sources that could be covered under the FIP. We provided two options, as follows, for sources to meet the proposed FIP's requirements regarding these resources:
(1) For sources for which a prior ESA and/or NHPA assessment has been completed, in the proposed FIP we indicated that, where Federal Land Managers (FLMs) have concluded ESA and/or NHPA compliance as part of the process in which an oil and natural gas operator makes an Application to Drill (APD) in connection with a particular source—whether as part of the FLM's NEPA review or otherwise—the source would be able to rely on that prior review for compliance with the proposed FIP's listed species (if prior ESA compliance has occurred) and historic properties (if prior NHPA compliance has occurred) requirements. No further assessment of impacts on these resources would be required by the proposed FIP as any such assessment would be duplicative of the prior work conducted by the FLM(s). We would require that documentation of completion of the APD process be provided before the owner/operator begins construction under the FIP.
(2) For sources for which no prior ESA and/or NHPA assessment has been completed, in the proposed FIP we indicated that those facilities must first complete screening procedures relevant to the particular resource that have not previously been reviewed before the owner/operator can begin construction under the proposed FIP. These screening procedures are similar to those currently in place for existing general permits and permits by rule in areas covered by the Federal Indian Country Minor NSR rule that must be completed before the owner/operator can begin construction under those general permits and permits by rule. ^{49} We stated that the review of the screening procedures would be similar to our procedure for general permits and permits by rule, for the proposed FIP, where once an owner/operator completes the screening procedures, ^{50} they would submit documentation to the EPA Regional Office and receive written verification of completion before beginning construction. As we explained in the development of both the general permits and permits by rule for the “General Permits and Permits by Rule for the Federal Minor New Source Review Program in Indian Country,” ^{51} to ensure listed species and critical habitats and historic properties are protected, we developed a framework for those permitting mechanisms requiring the source owner/operator to identify and assess potential effects on protected resources before obtaining coverage. Requiring this assessment aids in identifying any concerns related to potential impacts on listed species/critical habitat or historic properties early in the process when the greatest opportunities to mitigate or avoid any impacts—including changes to the facility's location or footprint—are available. The EPA believes that requiring a similar process in the air quality permit by rule, the general air quality permit, and the proposed FIP will streamline the process for all concerned: the applicants, the EPA, the tribes, and any resource experts such as the Services or historic preservation officers.
^{49} These procedures are available for sources potentially subject to this proposed FIP in a document entitled: “Procedures to Address Threatened and Endangered Species and Historic Properties for the Federal Implementation Plan for True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector,” https://www.epa.gov/tribal-air/tribal-minor-new-source-review.
^{50} Ibid.
^{51} “General Permits and Permits by Rule for the Federal Minor New Source Review Program in Indian Country,” 79 FR 2546, January 14, 2014, http://www.gpo.gov/fdsys/pkg/FR-2014-01-14/pdf/2013-30345.pdf.

2. Final Action
In the final FIP, we have not changed the overall approach for requiring sources to address threatened and endangered species and historic properties. We are continuing to provide two options for sources to address threatened and endangered species and historic properties. ^{52} However, we are modifying § 49.104 of the proposed FIP to further specify what information will be accepted to document that a source has addressed threatened and endangered species and historic properties through actions by another federal agency. We are also clarifying that for sources providing documentation to the effect that they satisfy the criteria under § 49.104(a)(1) through a prior assessment conducted by another federal agency, that they can submit the documentation with the Part 1 Registration Form.
^{52} Note that the two options for addressing threatened and endangered species and historic properties in the final FIP have also been made available to other source categories for which we have issued general permits and permits by rule, albeit in a different manner. Rather than prescribe the options in regulation, we have made the options available as part of the procedures information we have provided as attachments to the Request for Coverage Forms and the Notification of Coverage Forms for the general permits and permits by rule we have issued, respectively.
With respect to specific documentation requirements, the final FIP requires the owner/operator to submit to the EPA Regional Office (and to the tribe where the source is located/locating) documentation demonstrating that prior ESA and/or NHPA compliance has been completed by another federal agency in connection with the specific oil and natural gas activity operated under the FIP. The appropriate documents would have to clearly show that the other Federal agency had met its statutory obligations under both the ESA and NHPA. A simple reference to a Record of Decision (ROD) or other final decision document will not be acceptable. An example of acceptable documentation would be a letter from the Fish and Wildlife Service (FWS) for ESA or a historic preservation office for NHPA stating they agree with the assessment for the subject project and that the relevant sections of those statutes have been satisfied by the agency conducting the review of the proposed oil and natural gas activity. In addition, if a biological assessment and/or biological opinion have been prepared as part of the assessment under the ESA, then copies of those documents shall also be provided. The owner/operator must be in compliance with all measures required as part of that prior ESA and/or NHPA process.
With respect to the process for sources using the screening procedures provided by the EPA for threatened and endangered species and historic properties, we indicated in the proposal that we would follow criteria similar to that used for general permits and permits by rule where the completed screening procedures are submitted to the EPA Regional office for review and written approval is obtained before beginning construction. Therefore, we are paralleling the procedures used for Permits by Rule in § 49.104(a)(2) of the FIP to address submittal and review of completed screening procedures. Within 30 days of receipt of a source's documentation, the Reviewing Authority must provide a determination by letter to the source that: (1) The documentation satisfactorily demonstrates completion of the threatened and endangered species and historic property screening procedures; or (2) the documentation is not adequate and additional information is needed. If the initial submittal is deficient, the Reviewing Authority will note any such deficiencies and may offer further direction on completing the screening procedures. Once the source has addressed the noted deficiencies, it must submit revised screening procedure documentation for review. An additional 15-day review notification period will be used for the Reviewing Authority to determine whether the screening procedures have been satisfied. Provided that they have, the Reviewing Authority will then send the source a letter indicating approval. The source must obtain a letter from the Reviewing Authority indicating that the source has adequately completed the processes regarding threatened and endangered species and historic properties before it can begin construction under the FIP. This process of source documentation submittal and the EPA's confirmation that it has satisfactorily completed the procedures must occur prior to the source's submittal of its Part 1 Registration Form pursuant to § 49.160(c)(1)(iv).

3. Comments and Responses
The following discussion contains comments on requirements relating to threatened or endangered species and historic properties and our responses. The comments and responses are also addressed in Section 2.0 of the RTC Document.
Comment #10: Two commenters expressed concern about the EPA's authority to impose requirements relating to threatened or endangered species and historic properties in the proposed national FIP. These commenters stated that where there is no federal nexus, the EPA has no jurisdiction to require ESA or NHPA consultations. These commenters also noted that the EPA is not a surface land management agency and does not have jurisdiction on state and private lands to require such consultations where a federal nexus does not exist. Another commenter claimed that imposition of these ESA and NHPA requirements as conditions of using the FIP is unlawful and unreasonable. The commenter stated that it is unlawful because the ESA and NHPA are triggered only when a federal action is taken, and that as EPA acknowledges in the preamble, the use of the FIP by an affected source does not require any federal action. Therefore, the commenter believes that there is no need or justification for imposing ESA or NHPA requirements when an affected source avails itself of the FIP.
Response #10: We disagree with the commenters' statement that the EPA lacks authority to require assessments of potential impacts on these resources as sources are covered under the FIP. Consistent with the EPA's authority under the CAA, the EPA has built the screening procedures into the FIP as an adequate and appropriate means of addressing potential impacts on these resources. Given the intended scope of the FIP, it would be very difficult, if not impossible, for the EPA to evaluate such potential impacts in all areas where the FIP might apply. As a result, the EPA has concluded that the only way to address potential impacts on these resources in conjunction with the FIP, which is intended to provide a streamlined mechanism for complying with the Federal Indian Country Minor NSR rule, is to require the owners/operators to do it. Although the EPA is not a land management agency, the EPA is the federal agency promulgating the FIP, which will cover sources irrespective of whether they locate on federal or non-federal land. The EPA understands that completing the screening procedures will impose some burden on covered sources. However, the EPA has attempted to streamline these procedures to the extent practicable while ensuring appropriate consideration of the resources. We have not made any changes to the ESA/NHPA procedures as a result of these comments.
Comment #11: Four commenters expressed concern that the FIP's requirements for additional analysis addressing listed species and historic properties where a prior assessment by another federal agency has not been completed will lead to lengthy permitting delays. One commenter stated that the added secondary layer of listed species and historic property approval proposed by the EPA will add delay and expense, while duplicating existing protections for species and cultural resources. One commenter stated that the inclusion of site-specific reviews for listed species and historic properties contradicts the EPA's statement in the preamble that the purpose of the FIP is to provide a “streamlined” approach to permitting minor oil and natural gas sources on Indian lands, which would be accomplished in part by imposing “unambiguous” requirements on affected sources. The commenter asserted that case-specific listed species and historic property review is the antithesis of an unambiguous process.
Response #11: The EPA has promulgated the FIP to streamline the NSR permitting process to allow sources to avoid potential delays associated with individual source permitting. In connection with issuance of the FIP—which provides the relevant CAA authorization for sources to construct—the EPA has also added the threatened and endangered species and historic property screening procedures as an appropriate means of addressing potential impacts on these resources as sources are covered under the FIP. As indicated below, the EPA does not view coverage of individual sources under the FIP as separate ESA or NHPA triggering events. However, given the intended scope of the FIP, it would be very difficult, if not impossible, for the EPA to evaluate the potential impacts on the relevant resources in all areas where the FIP might apply. As a result, the EPA has concluded that the only way to address these impacts in conjunction with issuing this FIP, which is intended to provide a streamlined mechanism for complying with the Federal Indian Country Minor NSR rule, is to require owners/operators to do it. The EPA has, however, provided significant streamlining opportunities in this process by providing an avenue for covered sources to rely on prior listed species/historic property assessments done in connection with other federal agency permits or authorizations, and the EPA anticipates that many of the covered sources will have undergone such prior assessments and, thus, will require no further analysis. If analysis is required in those few cases where no prior assessment is available, the EPA has provided straightforward procedures for sources to complete their own assessments. ^{53} No changes were made as a result of this comment.
^{53} To find these procedures, go to: https://www.epa.gov/tribal-air/tribal-minor-new-source-review.
Comment #12: Two commenters stated that, while federal actions trigger ESA consultation and NHPA review, compliance with the FIP itself is not a federal action triggering ESA and NHPA review. One of these commenters noted that the EPA acknowledged in the preamble that the use of the FIP by an affected source does not require any federal action. The other commenter stated that many of the new sources and modifications undertaken in reliance on this FIP will have already been authorized by another federal action that complies with ESA and NHPA, and that compliance with the FIP by these new sources and modifications is not the federal action. The commenter added that for projects that have not undergone some earlier or concurrent federal authorization process, compliance with the FIP is not the federal action. The commenter further indicated that NESHAPs and NSPS present an analogous situation—sources complying with NESHAPs and NSPS across the country do not trigger ESA and NHPA reviews.
Another commenter noted that the approach the EPA is taking with the FIP is unique as compared to any other directly applicable substantive CAA rule. For example, EPA recently proposed changes to 40 CFR part 60, subpart OOOO, which also applies to affected sources that would be covered by the FIP (40 CFR part 60, subpart OOOO, is included in the proposed FIP). The commenter noted that there is no mention of ESA or NHPA in the 40 CFR part 60, subpart OOOOa, proposal. In the commenter's view, like the FIP, 40 CFR part 60, subpart OOOO (and the proposed 40 CFR part 60, subpart OOOOa), effectively authorize the construction of new sources and modification of existing sources. And, like the FIP, 40 CFR part 60, subpart OOOO, applies directly to affected sources without any need or requirement for case-specific authorization or decision-making. The commenter asserts that the difference in approach between the proposed FIP and other directly applicable CAA substantive rules is unexplained and unexplainable and that there is no justification for imposing ESA and NHPA requirements under the FIP.
Response #12: The EPA agrees that each separate coverage under the FIP does not constitute an action that triggers ESA/NHPA. However, the EPA disagrees that the listed species and historic property screening procedures included in the FIP impose ESA or NHPA compliance requirements on covered sources. These screening procedures are intended to be an appropriate means of addressing potential impacts on the relevant resources in connection with the EPA's issuance of the FIP, which provides CAA authorization for sources to construct in lieu of individual or other permitting under the Federal Indian Country Minor NSR rule.
The screening procedures are requirements of the FIP—not of the ESA or NHPA—and are consistent with the EPA's authority under the CAA. These requirements are appropriate for the FIP, which, as noted above, provides CAA authorization for sources to construct without the need for separate NSR permitting. By contrast, NSPSs and NESHAPs impose emission reduction requirements on sources, but are not separate authorizations for construction. We have not made any changes as a result of these comments.
Comment #13: One commenter expressed concern about the potential burdens associated with the listed species and historic property compliance provisions and urged the EPA to clarify when an affected facility is permitted to rely on a prior NEPA analysis to fulfill these requirements. This commenter asked the EPA to clarify that the prior NEPA review need not be conducted simultaneously with the construction or modification of the affected facility, referring to cases where the BIA or BLM may have completed an applicable NEPA review well in advance of the specific construction activity. This commenter also requested that the EPA consider whether programmatic environmental impact statements (EISs) can satisfy the relevant requirements, noting that programmatic EISs can address both ESA and NHPA issues on a reservation-by-reservation basis in a manner that addresses both the historic resources and endangered species that may be present in a given area. This commenter stated that allowing individual sources to rely on prior ESA and NHPA analyses in a programmatic EIS can provide further streamlining benefits that will reduce the costs of implementation, while ensuring that environmental goals are met.
Response #13: The EPA has added regulatory text to the final rule to clarify the documentation that needs to be submitted with the Part 1 Registration Form, what the documentation must show, and the process by which it must be submitted. The documentation must demonstrate that, for the project site operating under the FIP, another Federal agency ( e.g., BLM or BIA) had met its applicable statutory obligations under the ESA and NHPA in connection with its involvement with the project. An example of acceptable documentation would be a letter from the FWS (for ESA) or a historic preservation office (for NHPA) stating that the project has been reviewed, and the relevant statutes have been satisfied by the agency conducting the review, that any impacts of the project have been assessed, and any appropriate mitigation included. Such letters may, for instance, include a concurrence from FWS that a project will have no likely adverse effects on listed species or critical habitat.
Comment #14: One commenter requested that the EPA provide a procedure for reviewing the ESA and NHPA analyses conducted by other agencies ( e.g., BIA and BLM) to ensure that it is adequate and sufficient. The commenter stated that the EPA must ensure that emissions from a proposed project do not adversely impact threatened or endangered species or their habitat. The commenter added that the many sensitive cultural sites and areas of special cultural and spiritual significance to tribes and their members must receive the full protection they deserve under the law.
Response #14: The EPA appreciates the commenter's concern that listed species and historic properties, including properties of specific interest to Indian tribes, receive appropriate consideration and protection. The EPA believes as a general matter that the agencies with relevant resource expertise ^{54} ( e.g., the U.S. Fish and Wildlife Service and Tribal and State Historic Preservation Officers) are best qualified to ensure that the considerations the commenter is raising related to threatened and endangered species and cultural resources are addressed. The EPA has thus included appropriate screening procedures in the FIP to ensure that a complete assessment of covered projects occurs, either as part of a separate federal agency's prior compliance with the ESA and NHPA in connection with a source, or during a source's screening review under the FIP if no such prior assessment is available. In either scenario, the expert resource agencies will be appropriately involved in the consideration of any impacts on the resources and in the development of any relevant mitigation measures. The EPA will then ensure that sources have successfully completed the assessment process, that the documentation is available, and that the sources are in compliance with the FIP's requirements, including requirements with adequate measures to address air quality issues.
^{54} These experts possess the knowledge—and, under their statutes and regulations, the authority and responsibility—necessary to assess impacts on protected resources and to judge the adequacy of any mitigation measures needed to protect those resources.
By way of example, the EPA envisions the process could work as follows: an oil and natural gas owner/operator submits a request to drill to BLM or BIA; BLM/BIA initiate a comprehensive review of the project's potential impacts on the protected resources and engage in any required consultations with the expert resource agencies prior to approving new oil and natural gas activity; these consultations and assessments address direct and indirect effects of the action on the protected resources; the process concludes with relevant concurrences or other final decisions regarding the project's impacts and identification of any mitigation measures; and the source submits required information to the EPA under the FIP to demonstrate compliance with the ESA and NHPA as part of the prior review. The EPA notes that this process may occur as part of a review by the other federal agency under NEPA, in which case the EPA may be involved as one of the reviewing agencies of the NEPA assessment. In light of the degree of involvement of the land management federal agencies in project oversight and the expertise of the resource agencies, the EPA anticipates that this process will result in appropriate consideration of any impacts on the protected resources and that additional involvement by the EPA in that review would not provide meaningful additional input. The EPA has revised the regulatory text to specify what documentation relating to another Federal agency's compliance with ESA and NHPA is acceptable to demonstrate that these requirements are met.

E. Rationale for the FIP

1. Proposed Rule
In the section of the preamble on the rationale for the proposed FIP, we addressed four topics:
• Choice of a FIP as an alternative to source-specific permits, general permits and permits by rule;
• How we select which equipment to include in the proposed FIP;
• Why we are excluding existing sources from the proposed oil and natural gas FIP; and
• Why we proposed to extend the permitting deadline for oil and natural gas true minor sources in areas covered by the Federal Indian Country Minor NSR rule?
We are addressing the first three topics in Sections IV. E., H. and J. below, respectively. The fourth topic concerning the extension has already been addressed in a separate final action. ^{55}
^{55} “Review of New Sources and Modifications in Indian Country: Extension of Permitting and Registration Deadlines for True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 81 FR 9109, February 24, 2016, https://www.gpo.gov/fdsys/pkg/FR-2016-02-24/pdf/2016-03623.pdf .
Generally, with respect to the rationale for the FIP, we indicated that our proposal represented a proper exercise of our authority under § 49.11(a) of the Tribal Authority Rule which states that the EPA shall promulgate without unreasonable delay such FIP provisions as are necessary or appropriate to protect air quality, consistent with the provisions of sections 301(a) and 301(d)(4), if a tribe does not submit a TIP meeting the completeness criteria of 40 CFR part 51, appendix V, or does not receive EPA approval of a submitted tribal implementation plan (see § 49.11(a)). We indicated that the proposed FIP would apply to new and modified true minor sources that are located or expanding in the referenced areas of Indian country designated as attainment, unclassifiable or attainment/unclassifiable. It would not apply to new and modified true minor sources that are located or expanding in referenced areas of Indian country designated nonattainment. Thus, underlying the proposal was the EPA's belief that the FIP as proposed would be protective of air quality in areas of Indian country designated attainment, attainment/unclassifiable and unclassifiable but not areas designated nonattainment. Sources locating or expanding in areas designated as nonattainment would be required to obtain source-specific permits pursuant to the Federal Indian Country minor NSR rule, thereby allowing the EPA to include any requirements needed to provide air quality protection beyond that provided by the FIP. In addition, the EPA retains the authority under the FIP to require sources locating or expanding in areas designated attainment, attainment/unclassifiable and unclassifiable to obtain source-specific permits if it determines that this is necessary to protect air quality in a particular area. The FIP as proposed included a comprehensive set of standards, including the requirements under 40 CFR part 60, subpart OOOOa, which has undergone revision and reflects the latest in oil and natural gas control measures.

2. Final Action
The EPA continues to believe that this final FIP that relies on eight federal standards for its requirements will be protective of air quality in attainment, attainment/unclassifiable and unclassifiable areas, provided the EPA retains the ability to require source-specific permits and/or area-specific FIPs where needed to protect air quality in specific areas. Below are several comments on this issue and our responses.

3. Comments and Responses
The following discussion contains comments on issues related to the rationale for the proposed FIP and our responses. The comments and responses are also addressed in Section 3.0 of the RTC Document.
Comment #15: One commenter stated that the EPA has provided no assurance that the regulations included in the FIP will adequately address air quality problems in Indian country and ensure compliance with all applicable standards, including the NAAQS, PSD Program, and the visibility protection program. The commenter noted that, although the EPA proposes a FIP to streamline the permitting process, the proposed FIP does not achieve the goals of the case-by-case permitting the EPA established in the Federal Indian Country Minor NSR rule—namely adequate protection of public health and the environment. The proposed FIP would allow minor oil and natural gas sources to forego pre-construction review and permitting altogether and instead simply self-certify that they will comply with the six regulations that already apply within Indian country. The EPA has provided no analysis of whether these six regulations will adequately address the air quality problems in Indian country or ensure compliance with the NAAQS, PSD Program, and the visibility protection program.
Response #15: The EPA believes that the eight regulations included in the final rule represent a robust set of control measures that are adequate to protect air quality in Indian country in attainment, attainment/unclassifiable and unclassifiable areas. The EPA can require source-specific permits where needed to further protect air quality in these areas.
In addition, the Federal Indian Country Minor NSR rule does not require an air quality analysis in all instances for minor source permits even in the context of a source-specific permit. While § 49.154(c)(1)(i) indicates that we will consider “[l]ocal air quality” in determining whether to issue a source-specific permit, it does not require an air quality analysis and in fact § 49.154(d) establishes specific circumstances in which the Reviewing Authority can require the owner/operator to conduct an air quality impacts analysis (AQIA). Air quality factors are just one consideration with a source-specific permit. We have not made any changes as a result of this comment.
Comment #16: One commenter stated that the EPA did not conduct any control technology review, air quality impacts analysis, or dispersion modeling for the proposed FIP.
Response #16: The EPA's analysis and review consisted of establishing a set of requirements that we believe are sufficient to protect the NAAQS and PSD increments in attainment, attainment/unclassifiable and unclassifiable areas with the caveat that the EPA can require source-specific permits where needed to further protect air quality in a given area. Moreover, all eight regulations included in this FIP are based on the EPA's analyses of available technologies. The FIP requires compliance with the most current version of these regulations. So, the control requirements in this FIP will stay up to date, as these rules are based on the most current technologies. Finally, as noted above, the Federal Indian Country Minor NSR rule does not require an air quality analysis in all instances when a permit is issued even with a source-specific permit. No changes were made as a result of this comment.
Comment #17: One commenter expressed concern about the lack of any requirements in the proposed FIP for air quality monitoring and modeling, and recommended that the proposed FIP include requirements to improve air quality monitoring and modeling within Indian country. This commenter noted that the air quality in many areas of Indian country with oil and natural gas development exceeds federal public health standards for ozone and particulates. The commenter expressed concern that, without adequate monitoring, the EPA cannot ensure that it is protecting public health from the emissions associated with oil and natural gas development. This commenter stated that the most efficient and expedient method of providing such a monitoring network is requiring operators to install and operate monitors. The commenter noted that the EPA has authority under CAA section 114 to require operators to install and operate ambient air quality monitors.
Response #17: With respect to monitoring, the EPA works closely with tribes, as well as state and local partners, to implement and maintain a national ambient air monitoring program. In many cases, ambient networks include more monitors than are required by minimum requirements in the EPA's monitoring regulations. The EPA Regional Administrators have the authority to require additional monitoring in a variety of situations; such authority is specifically noted throughout the language in Appendix D to 40 CFR part 58, Network Design Criteria for Ambient Air Quality Monitoring. Accordingly, the EPA believes that the current authority to require monitoring above minimum requirements is sufficient to support this final rule and the need to employ additional air quality monitoring in areas of Indian country where the air quality may not be fully characterized. As the commenter points out, the EPA has the authority under section 114 of the CAA to require air quality monitoring if it determines that this is necessary in a particular areas. For these reasons, we do not believe that including monitoring requirements in this rule is necessary. Additionally, the EPA is exploring alternative sensor technology that can be used to compliment traditional compliance-based monitoring based on Federal Reference Method or Federal Equivalent Method monitoring equipment. The EPA anticipates that alternative sensor technology may be used in the future as a screening tool to determine if longer term monitoring with more specialized equipment is needed.
Regarding modeling, as noted above, the Federal Indian Country Minor NSR rule does not require an air quality analysis (and the modeling that would accompany it) in all instances when a permit is issued even with a source-specific permit. With respect to the final FIP, we do not believe that modeling is necessary; rather, we believe that the suite of eight federal regulations that constitute the FIP's set of control requirements are sufficent to protect air quality in areas of Indian country designated attainment, attainment/unclassifiable and unclassifiable. We have not made any changes in response to this comment.
With respect to air quality in areas of Indian country with oil and natural gas development, currently we are not seeing widespread air quality problems. Based on air quality data for 2012-2014, ^{56} (outside of Oklahoma) there are only two counties that meet three criteria: Have Indian country present; have design values (DVs) above the level of the current ozone NAAQS (70 parts per billion [ppb]); and have oil and natural gas activity. The two counties that meet these three criteria are in Utah and are: Duchesne and Uintah Counties. ^{57} The majority of the land area in both of these counties is on the Uintah and Ouray Reservation. For the Uintah and Ouray Reservation, we have sufficient concerns about the air quality impacts from existing sources that we plan to propose a separate reservation-specific FIP.
^{56} The EPA will not designate areas as nonattainment based on these data, but likely based on 2014-2016 data.
^{57} Supporting information can be found in: Docket ID No. EPA-HQ-OAR-2014-0606.
For areas designated nonattainment for NAAQS (2008 ozone NAAQS, 2006 and 2012 PM 2.5 NAAQS), based on air quality DVs for 2012-2014, there are not any areas that meet three criteria: Have Indian country present; have DVs above the level of the NAAQS; and have oil and natural gas activity. ^{58}
^{58} Ibid.
Comment #18: One commenter expressed concern about the lack of enforcement requirements in the FIP. The commenter noted that the proposed FIP provides few, if any, enforcement tools, and requested that the EPA clarify, add, and expand enforcement requirements in the final rule. The commenter encouraged the EPA to implement Next Generation Compliance techniques (such as self-certification and photographic verification, per 40 CFR part 60, subpart OOOO) in the final rule, and recommended that the EPA should also robustly pursue standard enforcement procedures in Indian country.
Response #18: Since the EPA is relying on the monitoring, recordkeeping and reporting requirements in the eight rules underlying this final FIP to be comprehensive in ensuring compliance, we do not feel that additional, separate compliance measures are needed. The requirements in the eight rules are independently enforceable under those rules as well as being enforceable under the FIP. An owner/operator is responsible for correctly permitting its sources. If it is later determined that the source is not complying with the emission limitations and standards prescibed in the eight rules as required by the FIP, the EPA can take enforcement action to bring a source into compliance. The EPA can also enforce major source requirements in situations where it is determined that a source emitted or has the potential to emit pollutants in major source amounts. We have not made any changes as a result of this comment.

F. The FIP as an Alternative to Source-Specific Permits, General Permits and Permits by Rule

1. Proposed Rule
With respect to source-specific permits, we proposed that owners/operators of new and modified true minor oil and natural gas sources that meet all of the following criteria must comply with the requirements contained in §§ 49.101 through 49.105 of the proposed FIP, unless the owner/operator opts-out of the FIP and instead obtains a source-specific permit per proposed § 49.101(b)(2) and (3):
• The facility is an oil and natural gas production facility as defined in proposed § 49.102;
• The oil and natural gas production facility is located in areas covered by the Federal Indian Country Minor NSR rule as defined in § 49.152(d) as proposed to be amended in the action;
• The oil and natural gas production facility is a new true minor source or a minor modification of an existing true minor source as determined under § 49.153;
• The oil and natural gas production facility begins construction or modification on or after October 3, 2016, the proposed extended permitting deadline date; and
• The oil and natural gas production facility is not located in a designated nonattainment area (the proposed FIP would only apply to true minor sources in the oil and natural gas sector locating or expanding in areas designated as attainment, attainment/unclassifiable or unclassifiable).
Under the proposed FIP, sources covered by the Federal Indian Country Minor NSR rule that do not meet all of the criteria listed above are not eligible to use the FIP and must, therefore, obtain a source-specific permit prior to beginning construction, on or after October 3, 2016.
If a source owner/operator does not want to comply with the FIP, they have the option to apply for a source-specific permit instead to meet the obligation under § 49.151(c)(1)(iii)(B) of the Federal Indian Country Minor NSR rule to obtain a permit prior to commencing construction of a new true minor source or modification of an existing true minor source. As part of the FIP, we proposed specific rule language in § 49.101(b)(2) to allow true minor sources proposing to construct on or after the proposed, extended deadline date of October 3, 2016, to opt-out of the default FIP if preferred by the owner/operator. We proposed that an owner/operator of a source otherwise subject to the proposed FIP can opt out and seek a source-specific permit under § 49.151(c)(1)(iii).
We also proposed that the EPA, or other Reviewing Authority, may require owners/operators to obtain a source-specific permit in lieu of complying with the proposed FIP to ensure protection of the NAAQS. Under § 49.101(b)(3), we proposed to specify that the Reviewing Authority may require an owner/operator of a source proposing to construct in certain areas of Indian country on or after October 3, 2016, to apply for a source-specific permit for a new true minor source or minor modification of an existing true minor source where necessary to protect air quality. In particular, the Reviewing Authority may determine that the source is not sufficiently controlled under the proposed FIP to protect the NAAQS in the area of the proposed project ( e.g., if the measured DV for the area is close to or above the level of the NAAQS). In that circumstance, the Reviewing Authority can require the minor source to obtain a source-specific permit. The agency recommends that at the time of registration, the owner/operator of new and modified sources contact the Reviewing Authority about the air quality status of the area, and the need to obtain a source-specific permit.
Concerning the selection of a FIP as an alternative to source-specific permits, general permits and permits by rule, in the ANPR, we committed to developing an alternative to source-specific permits primarily to avoid delays in new construction due to the burden of processing hundreds of true minor source permits in a timely manner. A FIP provides a regulatory tool that protects air quality, streamlines implementation and compliance assurance, and meets the EPA's obligation to permit minor NSR sources. The alternatives—source-specific permits, general permits and permits by rule—do not satisfy all of these concerns, which we explain in the preamble of the September 18, 2015 action proposing the FIP.
Unlike NSR general permits and permits by rule, which cannot be used to address existing sources, a FIP could extend to existing sources; this is a key distinction between general permits and permits by rule versus a FIP. However, the proposal did not contain requirements for existing sources. We indicated that our plan is to address existing sources, to the extent necessary, in the context of area- or reservation-specific FIPs designed to address areas or reservations with air quality issues (including nonattainment or possible nonattainment areas), as they arise, that are associated with oil and natural gas activities. Such FIP(s) would need to address, as necessary, requirements for existing sources, as well as additional requirements beyond those in this proposal for new and modified sources.

2. Final Action
After carefully considering the comments received, we have decided to retain the FIP as the streamlined mechanism for permitting true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector in Indian country. We believe that our initial reasoning laid out in our proposal is still sound in light of comments received. We also believe that we need to retain the provision in the FIP as proposed with respect to source-specific permits. In the final FIP under § 49.101(b)(2), owners/operators of facilities that meet the criteria specified for eligibility in the FIP can choose to obtain a source-specific permit in lieu of complying with the FIP as specified in 40 CFR 49.155 before beginning construction; any such source would not be required to comply with the requirements of §§ 49.101 to 49.105. In addition, under § 49.101(b)(3) of the final FIP, with advance notice owners/operators of facilities that meet the criteria specified for eligibility in the FIP can be required by the Reviewing Authority to obtain a source-specific permit to ensure protection of the NAAQS as specified in 40 CFR 49.155 before beginning construction; any such source would not be required to comply with §§ 49.101 to 49.105.

3. Comments and Responses
The following discussion contains comments on issues related to the choice of FIP as an alternative to source-specific permits, general permits and permits by rule and our responses. The comments and responses are also addressed in Section 4.0 of the RTC Document.
Comment #19: One commenter proposed that a general permit or permit by rule would be the best permitting approach for Indian country and could allow for legally and practically enforceable limits. They further suggested that ambient air quality impact modeling could be used to develop the general permit or permit by rule to ensure protection of the NAAQS.
Response #19: In the ANPR, the EPA committed to developing an alternative to source-specific permits primarily to avoid delays in new construction due to our inability to process potentially thousands of true minor oil and natural gas source permits in an acceptable timeframe. Comments received on the ANPR and on the proposed FIP were generally supportive of a FIP approach, which we are finalizing. As indicated above, we continue to believe that the FIP approach can best protect air quality in attainment, attainment/unclassifiable and unclassifiable areas, while providing streamlined permitting. We do not believe that modeling is necessary to ensure air quality protection in attainment, attainment/unclassifiable and unclassifiable areas given the comprehensive nature of the requirements in the eight standards underlying this FIP.
Comment #20: Several commenters expressed concern that a FIP would not provide an opportunity for comment about a specific facility's coverage under a FIP. In particular, commenters noted that there may be concerns specific to particular sites that are not addressed within the existing FIP. One commenter noted that under a FIP, tribes and the public are only provided a one-time opportunity to provide feedback on the proposed rule and would not be provided the opportunity to comment on individual sources proposed in their tribal area.
Response #20: The EPA agrees with the importance of providing opportunity for comment on the FIP. The EPA held three public hearings across the country ^{59} to solicit comments on the proposed FIP and also extended the public comment period on the proposed FIP by 21 days from November 14, 2015 until December 4, 2015. If the EPA requires a source-specific permit or develops an area-specific FIP, there will be additional opportunity for public comment on those specific permitting actions at that time.
^{59} The dates and locations of the hearings were as follows: Denver, Colorado, September 23, 2015; Dallas, Texas, September 23, 2015; and Pittsburgh, Pennsylvania, September 29, 2015. “Source Determination for Certain Emission Units in the Oil and Natural Gas Sector; Oil and Natural Gas Sector: Emission Standards for New and Modified Sources; and Review of New Sources and Modifications in Indian Country: Federal Implementation Plan for Managing Air Emissions From True Minor Sources Engaged in Oil and Natural Gas Production in Indian Country,” U.S. Environmental Protection Agency, 80 FR 51991, August 27, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-08-27/pdf/2015-21255.pdf .
In addition, new and modified sources under the FIP will have to register and provide source information and emissions. Each completed registration will be added to the EPA Regional Office Web sites. ^{60} If a citizen has information that a particular source may not be complying with the FIP, or that compliance with the FIP may not be sufficient due to air quality concerns in a particular area, the information could be brought to the EPA's attention.
^{60} For example, for EPA Region 8, the following Web site will be used to provide the completed registration forms: https://www.epa.gov/caa-permitting/tribal-nsr-permitting-region-8 .
Comment #21: One commenter requested a commitment from the EPA to provide funding to tribes for the development of TIPs to regulate minor oil and natural gas sources specific to areas under their jurisdiction, including the potential future regulation of existing minor sources. One commenter expressed an interest in developing a TIP. The commenter noted that the EPA promulgated the “Tribal Authority Rule” in 1998 to provide more detailed criteria and procedures for tribes to be treated as states under the CAA if they seek CAA program approval, and that tribes are authorized to develop a comprehensive TIP and to seek full authority to monitor and enforce the NAAQS within their reservation. The commenter expressed interest in exploring the possibility of working toward a TIP so that it may one day assume primacy over certain regulatory functions and gradually expand its authority.
Response #21: The EPA supports tribes developing their own air programs and, as desired, TIPs. The EPA has historically provided funding and other technical support towards this goal, and we will continue to seek tribal air funding and support. In particular, we anticipate proactively supporting development of TIPs, especially in areas with air quality DVs above the NAAQS.
Comment #22: Several commenters expressed concern about provisions in the proposed FIP allowing the EPA the discretion to require source-specific permitting to “ensure attainment of the NAAQS” on a case-by-case basis. This might particularly affect areas in Indian country where design values are close to the current ozone NAAQS of 70 ppb. In addition, commenters expressed concern that given the 30-day notice provided for under the FIP, the notification that a facility has been denied coverage under the FIP and will be required to obtain a source-specific permit might be received only at the last minute, causing financial burden on operators that have already initiated procurement of construction materials and labor. The commenters explained that the EPA should provide the criteria by which they will require source-specific permits, and should consider including modeling demonstrations as part of source-specific permitting. One commenter objected to the broad and unrestricted manner under which the FIP allows the EPA to require a source to obtain a source-specific permit, and requested that the EPA provide more definitive language on what critieria it would use to disallow a source to construct under the FIP and to require a source-specific permit.
Response #22: The EPA continues to believe that this FIP will be protective of air quality in attainment, attainment/unclassifiable and unclassifiable areas of Indian country, provided we retain the ability to require source-specific permitting as needed to protect air quality. The EPA intends to make those determinations on a case-by-case basis. Factors we will consider include: Levels of measured air quality relative to the NAAQS and rates of growth in oil and natural gas production activity and associated changes in emissions. Any decision to require source-specific permitting will apply to the entire area in question and to all sources planning to locate or expand in such area and we will provide advance notice to owners/operators and tribes in the affected area prior to a programmatic, area-wide imposition of source-specific permitting.
Comment #23: Several commenters encouraged the EPA to develop reservation-specific or region-specific FIPs that account for particular air quality concerns and that are consistent with the permitting rules and requirements of the surrounding states. This will help level the playing field between neighboring permitting jurisdictions and ensure that oil and natural gas development on tribal lands is not disadvantaged solely due to permitting differences. One commenter specifically referred to the Uintah and Ouray Indian Reservation, which is a tribal area at risk of nonattainment designation under the lowered ozone standard. The commenter noted that revenue generated from oil and natural gas development in this area is an important part of the tribal and regional economy. One commenter suggested that the EPA not wait until certain areas are re-designated as nonattainment to develop area-specific FIPs, but that the EPA should develop area-specific FIPs for areas in danger of re-designation immediately, notably the Uinta Basin and the San Juan Basin.
One commenter stated that the EPA should define “necessary or appropriate” by identifying more specific criteria for when reservation-specific FIPs will be issued. The commenter suggested that one such criterion would be ozone concentrations close to the NAAQS. The commenter further recommended that the EPA should base its decision on the availability of two years of valid monitoring data, considering data from all available, reliable monitors, regardless of whether the EPA has certified them as regulatory monitors.
Response #23: The EPA continues to believe that this FIP will be protective of air quality in attainment, attainment/unclassifiable and unclassifiable areas of Indian country. We, nevertheless, have the authority to promulgate reservation-specfic FIPs if we determine that it is necessary or appropriate to protect air quality. The EPA intends to make those determinations on a case-by-case basis. Factors we will consider include: Levels of air quality the area in question is experiencing relative to the NAAQS, rates of growth in oil and natural gas production activity, and associated changes in emissions in the area in question. We will work with tribes in developing any area-specific FIP that we determine is necessary or appropriate to protect air quality and will provide notice and an opportunity for comment prior to the promulgation of an area-specific FIP.
Comment #24: One commenter noted that tribal areas across the country currently include thousands of wells, and that there are thousands more forthcoming. Accordingly, all of this activity gives rise to ever-increasing emissions, exposes tribal members to harmful air toxics and impacts visibility in Class I areas such as national parks and wilderness areas. In addition, oil and natural gas sector emissions include large quantities of methane, which contributes to climate change. The commenter encourages the EPA to develop national uniform requirements to protect public health and welfare and to mitigate the severity of climate change.
Response #24: The EPA agrees with the commenters that oil and natural gas development in tribal areas results in emissions of harmful air toxics and other pollutants of concern. To mitigate these impacts, the proposed FIP included a uniform set of requirements from six current federal rules that apply in all tribal areas. In addition to these six, the EPA is adding two additional rules to the final FIP: 40 CFR part 60, subpart KKKK, and 40 CFR part 63, subpart ZZZZ. This suite of eight federal rules ensures: (1) Comprehensive application of the latest control technologies and unit processes found in the oil and natural gas sector; and (2) that the sector is controlled under the FIP. In addition, as needed to protect air quality, the EPA will continue to develop area-specific FIPs and/or utilize source-specific permitting for areas with poor or degraded air quality. The Federal Indian Country Minor NSR rule is not intended to address climate change per se; however, compliance with a number of the included rules will lead to co-reductions in emissions of methane, which is a potent greenhouse gas (GHG).
Comment #25: One commenter requested to have certain activities not considered modifications, including in-kind replacement of internal combustion and temporary engines, as well as control device additions, removals, and replacements as allowed by federal rules. This would allow operators to move equipment off site to perform needed repairs or maintenance to avoid production delays and to mitigate potential hazards associated with on-site maintenance.
Response #25: On May 30, 2014, the EPA finalized revisions to the Federal Indian Country Minor NSR rule that exempted certain internal combustion engines from the permitting requirements under the rule. ^{61} These included certain emergency generators and stationary engines with a horsepower rating less than 50. The final rule also provided guidance to industry specifically in response to a comment regarding the relocation or replacement of single pieces of equipment ( e.g., an internal combustion engine) in the oil and natural gas sector. The source owner/operator should verify with its Reviewing Authority that the “matching” situation described in the preamble to the final May 30, 2014 rule, and its stated outcome, applies to its case. Concerning control device additions, removals, and replacements, a broad exclusion for consideration as a modification cannot be given. Changes regarding control devices have the potential to increase emissions, and, thus, the potential emissions impact would have to be assessed by the owner/operator. To the extent that these changes result in emissions increases that fall below the minor NSR thresholds or satisfy the criteria under the definition of modification in § 49.152, there would be no requirement to register the unit(s) or to make a change to a prior registration. Under § 49.152, the following exemptions to modifications apply:
^{61} “Review of New Sources and Modifications in Indian Country—Amendments to the Federal Indian Country Minor New Source Review Rule,” U.S. Environmental Protection Agency, 79 FR 31035, May 30, 2014, https://www.gpo.gov/fdsys/pkg/FR-2014-05-30/pdf/2014-11499.pdf.
• A physical or operational change does not include routine maintenance, repair or replacement.
• An increase in the hours of operation or in the production rate is not considered an operational change unless such change is prohibited under any permit condition that is enforceable as a practical matter.
• A change in ownership at a stationary source.
• The emissions units and activities listed in § 49.153(c).

G. Synthetic Minor Sources and Minor Modifications at Major Sources

1. Proposed Rule
With respect to synthetic minor sources, in the September 2015 proposed FIP, the EPA did not structure the requirements to accommodate the creation of synthetic minor sources. ^{62} In the Background portion of the notice, we noted that in May 2015 we took final action ^{63} on a set of general permits and permits by rule in which we also authorized the use of general permits established under the program to create synthetic minor sources. We did this by including requirements in the general permits that otherwise major sources could comply with to reduce their PTE to below major source levels. We indicated in that action that general permits (and not permits by rule) can serve as an appropriate mechanism for creating synthetic minor sources because permits by rule do not provide for the same level of review and scrutiny by the Reviewing Authority as general permits. They also do not provide the same level of public participation. More specifically, in the May 2015 final action, based on comments received, we decided to issue final general permits for two categories (and not the three others) that involve more complex operations and multiple pollutants because the general permit approval process provides an opportunity for case-specific Reviewing Authority review. Because permits by rule do not involve the same level of review, the EPA did not finalize the use of permits by rule to create synthetic minor sources.
^{62} Per § 49.152(d), synthetic minor source means a source that otherwise has the potential to emit regulated NSR pollutants in amounts that are at or above those for major sources in § 49.167, § 52.21 or § 71.2, as applicable, but that has taken a restriction so that its potential to emit is less than such amounts for major sources. Such restrictions must be enforceable as a practical matter.
^{63} “General Permits and Permits by Rule for the Federal Minor New Source Review Program in Indian Country for Five Source Categories,” U.S. Environmental Protection Agency, 80 FR 25068, May 1, 2015, http://www.gpo.gov/fdsys/pkg/FR-2015-05-01/pdf/FR-2015-05-01-FrontMatter.pdf.
With respect to minor modifications at major sources, we did not address the issue per se in the proposed FIP, but we did address how to treat such cases in the permitting documents associated with the final May 2015 rule. ^{64} In the Request for Coverage and Notification of Coverage Forms ^{65} from the May 2015 rule, the EPA established requirements that sources include all existing, new and modified units in their PTE determinations for purposes of comparing that PTE to the major source thresholds. This exercise is necessary for determining eligibility for the general permits. If the sum of the potential emissions from all of these units exceeds the major source threshold, then the source is not eligible for the general permit. Effectively, this precludes minor modifications at major sources from general permit eligibility. ^{66} Such sources require source-specific permits that undergo Reviewing Authority review. We did provide an exception in the May 2015 action for otherwise major sources that are willing to accept certain emissions limits, throughput, fuel and other limits and become synthetic minor sources, provided that the limits accepted by the source would lower source-wide PTE to below the major source NSR thresholds, counting emissions from all new, modified and existing units.
^{64} Ibid.
^{65} These forms can be found at: https://www.epa.gov/tribal-air/tribal-minor-new-source-review.
^{66} Minor modifications at major sources are also, of course, not covered by the permits by rule we have issued thus far for reasons similar to the reasons for general permits.

2. Final Action
After careful consideration of the comments, we continue to believe that the FIP is not an appropriate mechanism for establishing synthetic minor sources. We have, therefore, not made any changes to the FIP to accommodate its use to create synthetic minor sources. As indicated above, the EPA has an established policy that requires the Reviewing Authority have the opportunity to review any requests from a source for synthetic minor status; the FIP does not provide that opportunity.
In this final action, we are also not modifying the FIP to authorize modifications at major sources. The FIP is being made available to true minor sources in lieu of a true minor source permit. As mentioned above, the general permits (and, as noted, permits by rule) the EPA has issued to date are for true minor sources and are not available for minor modifications at major sources. Since the FIP is in lieu of a minor source permit, similar to non-oil and natural gas sources, minor modifications at major sources must have source-specific permits that have undergone Reviewing Authority review. As noted above, we do allow general permits to create synthetic minor sources, which could involve a minor modification at a major source. Since we are not allowing for the creation of synthetic minor sources under the FIP for the reasons explained above, we are not allowing for the FIP to cover minor modifications at major sources.
By definition, major sources are more complex than minor sources and, as noted above, we believe such complexity necessitates that a review—under a general permit or source-specific permit—needs to be conducted for all permitting-type changes, whether to obtain synthetic minor status or for a modification at an existing major source. Since this FIP does not provide for any EPA source-specific permit review, and is intended as a streamlining alternative to source-specific permitting, we do not believe it is appropriate to cover modifications at major sources in this FIP.
We have added regulatory text to § 49.101 to make it clear that the FIP does not apply to minor modifications at major sources.

3. Comments and Responses
The following discussion contains comments on the use of the FIP for establishing synthetic minor sources and minor modifications at major sources as an alternative to source-specific permits, general permits and permits by rule and our responses. The comments and responses are also addressed in Section 4.0 of the RTC Document.
Comment #26: Several commenters requested that the EPA provide a mechanism for obtaining synthetic minor permits under the FIP. One commenter noted that there are a number of emission units common at oil and natural gas facilities that are not subject to the six federal regulations included in the proposed FIP, and that, therefore, would not be eligible for federally enforceable limits that are available for units covered under the six other rules. The commenter stated that unless such provisions were included, an overwhelming number of operators in Indian country will have to obtain source-specific permits. One commenter noted that most states with significant oil and natural gas production have streamlined permitting mechanisms ( e.g., general permits or permits by rule) in place for synthetic minor sources, as does the Fort Berthold Indian Reservation FIP. Another commenter noted that this would disadvantage oil and natural gas development on tribal lands because companies may prefer to locate where streamlined synthetic minor permitting options are available. It was also suggested that other limits, such as those imposed by tribal authorities or the BLM, be considered “enforceable as a practical matter” when considering the PTE and permit level. One commenter suggested insertion of the following language to allow for federally enforceable limits for emission units not subject to the six other rules:
(a) Sources not subject to NSPS or NESHAPs may elect to comply with a NSPS or NESHAP under this FIP as a mechanism to establish enforceable conditions on the source's potential to emit. Once the source elects to be subject to the NSPS or NESHAP, the NSPS or NESHAP are enforceable against the source under this FIP.
(b)(i) Sources may elect to be subject to one or more facility-wide emission limits listed below.
a. 249 tons per year of any NSR regulated pollutant in an attainment area;
b. 99 tons per year of any NSR regulated pollutant in any nonattainment area;
c. 24 tons per year of total hazardous air pollutants;
d. 9 tons per year of any single hazardous air pollutant;
e. 99 tons per year of any regulated pollutant;
(ii) The facility-wide emission limits are 12-month rolling limits. Once a source elects coverage under this paragraph, the source must demonstrate compliance every month based on emissions of the prior 12 months.
(iii) Sources subject to this paragraph shall demonstrate compliance and determine emissions based on the monitoring and recordkeeping dictated in any NSPS or NESHAP for the types of equipment covered under the facility-wide emissions limit.
(iv) Sources subject to this paragraph shall monitor emissions and emissions-related data and keep records consistent with NSPS or NESHAP monitoring and recordkeeping for the types of equipment covered by the emissions limit for the purposes of compliance with this paragraph, even if such equipment is not subject to the NSPS or NESHAP.
The commenter suggested that the EPA allow for flexibility in synthetic minor limits in terms of production, throughput, or hours of operation. One commenter suggested that the EPA provide a general permit, or separate general permits for different unit types, pursuant to § 49.156 with a suite of standards that would allow for federally enforceable limits on units not subject to the six other rules included in the proposed FIP. Several commenters suggested that self-certification could be included in provisions allowing for synthetic minor limits, and that this would reduce the burden on the EPA to have to issue synthetic minor limits under a source-specific permit.
Response #26: The current Federal Indian Country Minor NSR rule only allows the permitting of synthetic minor sources on a source-specific basis. The EPA's review is necessary to establish synthetic minor limits because without the verification that the required controls and associated compliance provisions will accomplish their objective, the source is a major source. Due to the streamlined nature of the oil and natural gas FIP, such review is not part of the FIP's process, which only requires source registration. Synthetic minor sources are more appropriately permitted under source-specific permits as they provide an opportunity for case-specific, Reviewing Authority evaluation.
Moreover, the EPA's Reviewing Authorities in our Regional Offices have seen no evidence of a high volume of requests for synthetic minor permits from oil and natural gas sources. Nor did commenters provide information on the volume of synthetic minor status requests to support the need for a synthetic minor option. Sources subject to the FIP are free to seek a source-specific sythetic minor permit pursuant to § 49.158.
No changes will be made as a result of this comment.
Comment #27: Several commenters requested that the EPA provide a mechanism under the FIP to allow for construction of minor modifications at major sources, as well as modifications at synthetic minor sources. One commenter noted that modifications occurring at major sources may be of the same type and size as a modification at a true minor source, yet these situations would be treated differently under the proposed FIP as they would require time-consuming source-specific permits. One commenter noted that the EPA should not use the term “minor modifications at true minor sources” in the rule because all modifications at a true minor source are covered under minor NSR. One commenter requested that the EPA replace references to “minor modifications at existing true minor oil and natural gas sources” with “minor modifications at existing oil and natural gas sources.” In addition, the commenter requested that the FIP allow for minor modifications at major sources as such modifications are allowed under the Federal Indian Country Minor NSR rule (§ 49.151). The proposed verbiage revisions would reflect that such modification at major sources were covered under the FIP.
Response #27: The July 2011 Federal Indian Country Minor NSR rule provided for the streamlining of the permitting of true minor sources through the use of general permits (and eventually permits by rule), with the permitting of minor modifications at major sources requiring source-specific permitting. As indicated above in the discussion of the general permits and permits by rule that the EPA has already issued under the Federal Indian Country Minor NSR rule, this FIP is not a permitting option available for minor modifications at major sources. Major sources are more complicated than minor sources, and modifications at major sources are likely to be as well. Such sources require the in-depth review of source-specific permits. By streamlining less significant actions ( i.e., true minor sources), we are freeing up resources for the EPA to address actions at the larger, more complex sources. As this FIP is limited to true minor sources (see response to comments above), the suggested change is not necessary and no change will be made as a result of this comment.
Comment #28: One commenter requested that the EPA amend the Federal Indian Country Minor NSR rule to expand the definition of enforceability to allow limits to be considered “enforceable as a practical matter” to mean that a limit or standard is legally and praticably enforceable if a government authority, federal or tribal, has the right to enforce it. In particular, the commenter suggested that such limits could be imposed by the BLM or a tribal authority.
Response #28: The definition of “enforceable as a practical matter” in § 49.152 states that an emission limitation or other standard is legally enforceable if the reviewing authority has the right to enforce it. Under this FIP, the EPA is the Reviewing Authority. Therefore, limits or other standards that are not enforceable by the EPA cannot be considered and no change will be made to the definition as a result of this comment.

H. Nonattainment Areas

1. Proposed Rule
In the proposed rule, we addressed the issue of how to address nonattainment areas under the proposed FIP given that it only applies to attainment, attainment/unclassifiable and unclassifiable areas. It would not apply to any areas designated nonattainment. We indicated that the EPA or tribes will need to develop area-specific plans if and when areas of Indian country become nonattainment for ozone or other NAAQS pollutants. At that time, any such area that has oil and natural gas minor source activity may require additional controls on existing (and new and modified) sources in order to achieve attainment of the NAAQS. One source of potential control options will be the EPA's CTGs for oil and natural gas activity that the EPA has made available for comment and will finalize in 2016. ^{67}
^{67} For more information, go to: https://www3.epa.gov/airquality/oilandgas/index.html.

2. Final Action
The EPA has not made any changes to the final FIP's requirements as it relates to nonattainment areas. The FIP does not apply in such areas. Before or after such an area is designated as nonattainment, we will promulgate an area-specific FIP for existing sources if we determine that it is “necessary or appropriate” pursuant to the Tribal Authority Rule. At that time, we will determine whether the final FIP should apply in the area or whether something more is required and will include in the area-specific FIP a provision or provisions putting the FIP, or some variation thereof, into effect in the area. The public will have an opportunity to comment on any such expansion of coverage of this FIP in the separate, area-specific action.

3. Comments and Responses
The following discussion contains comments on our proposal that the FIP does not apply in nonattainment areas and our responses. The comments and responses are also addressed in Section 4.0 of the RTC Document.
Comment #29: Several commenters requested that the EPA include provisions in the FIP to allow for streamlined permitting of minor oil and natural gas sources in nonattainment areas, including permitting in areas during the transition period between the time an area is designated as nonattainment and the time a FIP to control emissions adequately in such nonattainment area is in place. One commenter noted that with the lowered ozone standard, this issue may become particularly problematic in certain areas, most notably the Uinta Basin. Commenters requested that the FIP continue to provide for minor source permitting in such areas until a basin-specific permitting program becomes effective under the implementation planning process. Because an attainment plan is not due until three years after an area becomes nonattainment, the absence of a vehicle to allow for continuing minor source permitting would require source-specific permits during this transition period and would disadvantage oil and natural gas development in Indian country. One commenter suggested that the FIP continue as the permitting vehicle during the transition period, and that the EPA develop area-specific FIPs for re-designated areas that would supersede the national FIP upon issuance.
Response #29: The EPA recognizes the potential for certain tribal areas to be designated as nonattainment for the new ozone standard. Currently, the permitting mechanism in place under the Federal Indian Country Minor NSR rule for oil and natural gas sources wishing to locate in nonattainment areas is limited to source-specific permits. We believe that this FIP as designed will be protective of air quality in attainment, attainment/unclassifiable and unclassifiable areas, but will not necessarily be protective in nonattainment areas without further action to reduce emissions from existing sources. Therefore, we are stating our intent to potentially apply this national FIP's requirements as appropriate to nonattainment areas where the EPA has established a separate, area-specific FIP action. In that separate, area-specific action we would propose—and seek comment on—the application of this FIP's requirements to new and modified true minor sources in those certain areas designated nonattainment.
It is important to note that the geographic scope of this FIP cannot be extended to cover any nonattainment areas without the EPA first proposing to apply its requirements to such an area through a separate rulemaking subject to notice and an opportunity to comment. We are here merely expressing our intent to use the approach described above in the future to provide coverage for new and modified true minor sources in Indian country nonattainment areas, should such areas exist, where the EPA believes that the FIP, or some variation thereof, in combination with an area-specific FIP, is sufficient to protect air quality.
Our expression of intent to consider adopting this FIP in nonattainment areas as an accompaniment to an area-specific FIP addressing existing sources is in direct response to comments requesting that this FIP be extended to tribal nonattainment areas at least for a period of time after designation and until it is replaced by another FIP that addresses new and modified sources. A factor in considering whether to extend the coverage of this FIP is if we believe that existing source emissions will be reduced to a great enough extent to allow room for further growth of the industry in the area, while also protecting air quality. As noted above, the public will have an opportunity to comment on any such expansion of coverage of this FIP in the separate, area-specific action.

I. How the EPA Selected Equipment Included in the Proposed FIP

1. Proposed Rule
The proposed oil and natural gas FIP focused on the production segment of the oil and natural gas sector, because we believed this segment includes the majority of the true minor sources in the sector that would need to obtain a minor source permit in areas covered by the Federal Indian Country Minor NSR rule. In the preamble to the proposed rule, we described the natural gas production segment as ending where the natural gas enters a natural gas processing plant. In situations where there is no processing plant, the natural gas production segment ends at the point where the natural gas enters the transmission segment for long-line transport. The crude oil production segment ends at the storage and load-out terminal which is the point of custody transfer to an oil pipeline or for transport of the crude oil to a petroleum refinery via trucks or railcars. The petroleum refinery is not considered part of the oil and natural gas sector.
In determining which equipment to include in the proposed oil and natural gas FIP, we reviewed the EPA regulations that apply to emission units within the oil and natural gas production segment. We have relied substantially on analyses performed in support of the 2015 proposed NSPS, subpart OOOOa, to help determine which emission units the EPA should consider regulating in the oil and natural gas sector in areas covered by the Federal Indian Country Minor NSR rule as part of this proposed FIP. ^{68} In addition to the production segment sources proposed to be covered under NSPS, subpart OOOOa, in the proposed FIP, we proposed requirements from existing EPA standards for three emission sources not covered by the proposed NSPS, subpart OOOOa, because they are present at oil and natural gas production sites and emit NO X and/or VOC: Engines, process heaters and glycol dehydration units. Three of the six federal rules in the proposed FIP regulate these air emissions sources, among others. Therefore, we determined that a combination of existing federal regulations and the 2015 proposed NSPS, subpart OOOOa, provides a comprehensive and consistent regulatory approach for addressing true minor oil and natural gas production sources in areas covered by the Federal Indian Country Minor NSR rule.
^{68} “Oil and Natural Gas Sector: Standards for Crude Oil and Natural Gas Facilities. Background Technical Support Document for the Proposed New Source Performance Standards 40 CFR part 60, subpart OOOOa,” U.S. Environmental Protection Agency, August 2015, EPA-HQ-OAR-2010-0505-5021, http://www.regulations.gov.
We concluded that these federal regulations include emission limitations that are technically and economically feasible, and cost effective because we have vetted the existing regulations via the public comment process and sources are currently complying with these federal standards, including new and modified sources in the oil and natural gas sector located in areas covered by the Federal Indian Country Minor NSR rule. The referenced NSPS are all promulgated pursuant to the EPA's authority under CAA section 111. Under CAA section 111(a), the emission limitations for all the affected sources, except process heaters and glycol dehydrators, “reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines have been adequately demonstrated.” We refer to this level of control as the Best System of Emission Reduction (BSER). In determining BSER, we typically conduct a technology review that identifies what emission reduction systems exist and how much they reduce air pollution in practice. For each control system identified, we also evaluate its costs and other impacts.
The NESHAP for process heaters and glycol dehydrators are promulgated pursuant to the EPA's authority under CAA section 112. Under CAA section 112(d)(3), the emission limitations for glycol dehydrators and process heaters at major sources of hazardous air pollutants (HAPs) reflect the application of maximum achievable control technology (MACT). The MACT emission limitation for new sources cannot be less stringent than the emission control achieved in practice by the best-controlled similar source, without considering costs. In addition, under CAA section 112(d)(5), the emission reduction requirements for triethylene glycol dehydrators at area sources reflect “generally available control technology” (GACT). For GACT there is no statutory minimum level of emissions reduction for new or existing sources and costs can be considered. We proposed that the oil and natural gas FIP require sources to comply with the applicable MACT (for glycol dehydrators and process heaters located at major sources of HAP) or GACT (for glycol dehydrators located at area sources of HAP) emission limitations. Because the individual HAP pollutants regulated from glycol dehydrators by the NESHAP (and to some degree from process heaters, as well) for oil and natural gas production sources are also VOC, which are regulated NSR pollutants, the proposed FIP would create enforceable VOC reduction requirements for glycol dehydrators and process heaters. HAPs would serve as a surrogate for VOC with respect to emission limitations, monitoring, testing and compliance. In addition, compliance with the 40 CFR part 63, subpart DDDDD, MACT also provides beneficial reductions of other non-targeted NSR pollutants, i.e., NO X .
We indicated that the rationale supporting the applicability, emission limitations, monitoring, recordkeeping, reporting, and other provisions for each of the six federal rules is found in the preambles and background documents for those rulemakings. The six federal rules are available on the Electronic Code of Federal Regulations at: http://www.ecfr.gov/cgi-bin/ECFR?page=browse.

2. Final Action
In response to comments, we are expanding the scope of the FIP to provide coverage of natural gas processing plants. In § 49.102, we have modified the definition of oil and natural gas source (termed oil and natural gas production facility in the proposal) to facilitate this expansion.
In part due to this expansion (resulting from our response to comments), we are also modifying § 49.105 of the proposed FIP by adding two federal standards to the FIP's set of requirements:
• 40 CFR part 63, subpart ZZZZ—NESHAP for Stationary Reciprocating Internal Combustion Engines; and
• 40 CFR part 60, subpart KKKK—Standards of Performance for New Stationary Combustion Turbines.
Adding these standards to the FIP will provide standards for combustion turbines at gas processing plants and expand the standards in the FIP covering reciprocating internal combustion engines.

3. Comments and Responses
The following discussion contains comments related to how the EPA selected equipment included in the proposed FIP and our responses. The comments and responses are also addressed in Section 5.0 of the RTC Document.
Comment #30: One commenter expressed concern that, in the absence of a FIP condition expressly requiring installation of equipment subject to the six other EPA rules included in the proposed FIP, a source could utilize second-hand equipment with no applicable NSPS or NESHAP requirement and, thus, operate with no control technology requirements or emission limitations as required by § 49.154(c). The commenter recommended adding language to §§ 49.101 and § 49.105 expressly requiring installation of equipment subject to the six other rules included in the proposed FIP.
Response #30: The EPA believes that the commenter's proposal is not workable as it would limit operators to only installing equipment that is regulated by an EPA standard. Mandating the use of equipment that meets an EPA standard runs contrary to the FIP's intent of applying a consistent set of national requirements across Indian country. In some instances sources may need to use a piece of equipment that is not subject to an EPA standard. Instead, our approach under the FIP is to require that equipment subject to one or more of the eight EPA standards comply with those standards for purposes of the FIP. As long as the equipment in question can meet the limits to which they are subject, regardless of the mechanism used to do so, the owner/operator should be able to use that equipment. We believe that this approach is sufficient to protect air quality in attainment, attainment/unclassifiable and unclassifiable areas. No change will be made as a result of this comment.
Comment #31: Three commenters asked the EPA to expand the scope of the proposed rule to include minor oil and natural gas sources outside the production segment. All three commenters requested that natural gas processing plants be added; two commenters requested that natural gas transmission and storage facilities be added, and one commenter requested that natural gas distribution facilities be added. One commenter asked the EPA to indicate whether it intends to regulate any or all of these segments in the future, and if so, what is the EPA's projected timetable. One commenter recommended that the language in § 49.101(b)(1)(i) be modified to read:
“The facility is an oil and natural gas production facility or natural gas processing plant as defined in § 49.102;”
Response #31: In response to these comments, the EPA has determined to expand the regulatory language in the FIP to cover true minor natural gas processing plants. The EPA has added the requirements of 40 CFR part 60, subpart KKKK, to the list of standards to cover turbines at compressor stations. The EPA notes that it is not necessary to add 40 CFR 60, subpart KKK—Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing Plants for Which Construction, Reconstruction, or Modification Commenced After January 20, 1984, and on or Before August 23, 2011, or 40 CFR part 60, subpart LL—Standards of Performance for SO 2 Emission from Onshore Gas Processing for which Construction Commenced after January 20, 1984, and on or Before August 23, 2011. These rules are already included in the current FIP requirements because they are already included in the oil and natural gas NSPS rule at 40 CFR part 60, subpart OOOOa. The EPA is also adding the requirements of 40 CFR 63, subpart ZZZZ—National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines to the FIP in the final rule. We are comfortable with including these additional facilities under the FIP to cover true minor natural gas processing facilities because the rules will require adequate control and we do not feel that source-specific review is necessary just as we do not regard it as necessary (unless we make an exception for air quality concerns) for true minor sources in the oil and natural gas production segment of the oil and natural gas sector.
With respect to the timetable for any future regulation of the oil and natural gas sector, all segments in the sector are already subject to regulation by the EPA under the Federal Indian Country Minor NSR rule. However, only certain segments are included in this FIP because we believe that the vast majority of true minor sources in the oil and natural gas sector are in the oil and natural gas production and natural gas processing segments of the sector.
Comment #32: One commenter stated that the proposed definition for “oil and natural gas production facility” should be revised to exclude references to mobile and temporary sources, such as well drilling, completion, workover activities, and portable non-self-propelled equipment because the CAA expressly precludes application of NSR and title V to mobile sources, such as portable, engine-powered well-drilling equipment and portable reciprocating internal combustion engines. The commenter recommended that the EPA should make it clear that these sources are not subject to air permitting requirements under the oil and natural gas FIP. This same commenter stated that the proposed oil and natural gas production facility definition does not include common unit operations such as water treatment, sweetening units (acid gas removal units), truck loading, and dew point suppression skids. The commenter noted that language such as “low to medium pressure, small diameter” are arbitrary descriptions for gathering pipelines, and that these equipment are better described by purpose ( i.e., to gather field gas). The commenter recommended the following change to the oil and natural gas production facility definition. They recommended the following additions and deletions:
• Adding “water” to the list of materials to be separated or treated;
• Adding the following items to the list of production components: Natural gas sweetening, truck loading. and dew point suppression skids; and
• Deleting the following items from the list of production components: Well drilling, completion and workover processes and portable non-self-propelled apparatuses associated with those operations; and low to medium pressure, smaller diameter, gathering pipelines and related components that collect and transport the oil, natural gas and other materials and wastes from the wells or well pads.
Response #32: The EPA has replaced the definition of “oil and natural gas production facility” in § 49.102 as proposed with “oil and natural gas source.” The new definition incorporates some of the suggestions recommended by the commenter. We did not include the segments of transmission or distribution of natural gas in the definition because they do not fall within the scope of coverage of this FIP. ^{69} However, we believe that completion and workover processes should not be removed from the definition because they are stationary sources regulated under 40 CFR part 60, subpart OOOOa. This makes the treatment of these sources under the FIP definition (§ 49.102) consistent with definitions related to the oil and natural gas sector in 40 CFR part 60, subpart OOOOa; 40 CFR part 63, subpart HH; and the FBIR FIP.
^{69} This FIP only covers the oil and natural gas production and natural gas processing segments of the oil and natural gas sector because we believe that the vast majority of true minor sources in the oil and natural gas sector are in those two segments.
Comment #33: One commenter recommended that specific oil and natural gas exploration and production equipment be regulated under the proposed FIP. Specific equipment recommended for inclusion in the FIP includes: Drill rigs, liquids unloading, dehydrators, truck loadout, and phase separation. The commenter recommended that plunger lifts be required for all liquids unloading. The commenter recommended that dehydrators be required to control VOC by 95 percent by using a condenser.
Response #33: The EPA feels that the original suite of six federal rules proposed to be included in the FIP, in conjunction with the two additional federal rules added under this final action, combine to adequately control emissions from oil and natural gas facilities for purposes of the FIP. It should be noted that drilling rig engines are not considered stationary sources for purposes of permitting under the Federal Indian Country Minor NSR rule, and dehydrators are addressed under 40 CFR part 63, subpart HH (National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities), which is one of the eight federal rules included in the FIP. No change has been made as a result of this comment.
Comment #34: One commenter recommended that the proposed FIP include regulation of emissions from well completions for both oil and natural gas wells, as well as casinghead gas and associated gas emissions. The commenter referenced recommendations in an ICF International report (ICF International, Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas Industries (March 2014), at 3-3, available at: http://www.edf.org/sites/default/files/methane_cost_curve_report.pdf ).
Response #34: The FIP includes the recently revised Standards of Performance for New and Modified Sources in the Oil and Natural Gas Sector (40 CFR part 60, subpart OOOOa), which requires control of oil and natural gas well completions for hydraulically fractured wells. Casinghead gas and associated gas emissions from venting or flaring during ongoing production are not currently addressed under the eight federal rules included in the final FIP; however, if those emissions sources are regulated under a future revision of subpart OOOOa, then they would automatically fall under the requirements of this FIP at true minor sources. No change has been made as a result of this comment.
Comment #35: Two commenters recommended that the EPA clarify the definition of natural gas processing plant by revising it to be consistent with the definition in other air rules. Both commenters stated that the EPA should clarify that a Joule-Thompson valve, dew point depression valve, or an isolated or standalone Joule-Thompson skid does not make a site a natural gas processing plant. Both commenters recommended that the EPA reference or include in § 49.102 the definition of a natural gas processing plant contained in 40 CFR part 60, subpart OOOO (§ 60.5430).
Response #35: The FIP proposal did not include a definition of natural gas processing plant. In this final action we are modifying § 49.102 to revise the definition of an “oil and natural gas production facility” (now “oil and natural gas source”) to make the treatment of these sources under the FIP definition (§ 49.102) consistent with definitions related to the oil and natural gas sector in 40 CFR part 60, subpart OOOOa; 40 CFR part 63, subpart HH; and the FBIR FIP. We have also included natural gas processing plant as part of the definition of “oil and natural gas source” under § 49.102.
One of the two commenters recommending including the definition of gas processing plant from 40 CFR part 60, subpart OOOO, provided incorrect language for the definition. Nonetheless, we have concluded that adding a definition for natural gas processing plant to the FIP is unnecessary; including natural gas processing plant in the definition of source is sufficient to extend the coverage of this FIP to non-major natural gas processing plants. At the beginning of § 49.102 we make it clear that all terms not defined in the section shall have the meaning given them in 40 CFR part 60, subpart OOOOa, among other sources, which would include how natural gas processing plant is defined in the subpart.
Comment #36: One commenter noted that the current list of referenced federal NSPS and NESHAP regulations does not include 40 CFR part 63, subpart ZZZZ—National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines. The commenter stated that the EPA should make it clear in the preamble and ensure that no regulatory language of the FIP excludes oil and natural gas sources from relying on subpart ZZZZ to limit the PTE of engines to be able to qualify for the FIP. The commenter recommended that subpart ZZZZ be included in the list of referenced rules (at § 49.105(g)) as follows:
“For sources that are subject to subpart ZZZZ, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines, for purpose of this FIP, sources must comply with all of the applicable provisions of the standard as written as of [INSERT DATE OF FINAL PROMULGATION OF O&G FIP]:”
Response #36: The EPA has included the requirements of 40 CFR part 63, subpart ZZZZ, into the final FIP as requested by the commenter. As with all of the appplicable requirements from all eight of the regulations referenced in this FIP, a source can rely on the reductions required by 40 CFR part 63, subpart ZZZZ, to reduce its PTE.
Comment #37: One commenter recommended that the FIP require all new compressor engines to install steam injection and control technologies such as low-emission combustion retrofit, selective catalytic reduction (SCR), or selective non-catalytic reduction (SNCR) and to require existing sources to retrofit with the appropriate control. The commenter further recommended that the EPA should require the use of electric motors for new engines unless the operator shows it is infeasible to do so. One commenter recommended that the FIP require all external combustion units to control NO X emissions with SNCR, SCR, or a combination of SCR plus low NO X burners.
Response #37: The proposed FIP incorporates control requirements for internal and external combustion units in accordance with 40 CFR part 63, subpart DDDDD (National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters); 40 CFR part 63, subpart ZZZZ (National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines); 40 CFR part 60, subpart IIII (Standards of Performance for Stationary Compression Ignition Internal Combustion Engines); 40 CFR part 60, subpart JJJJ (Standards of Performance for Stationary Spark Ignition Internal Combustion Engines); and 40 CFR part 60, subpart KKKK (Standards of Performance for New Stationary Combustion Turbines). In the development of the FIP, we have relied on the analysis conducted in the development of these existing rules to determine adequate control technology requirements for these types of sources. The FIP only applies to new true minor sources and modifications at existing true minor sources thus does not address the control of emissions from existing source.

J. Pollutants Included in the Proposed FIP

1. Proposed Rule
In the preamble to the proposed rule, we indicated that the pollutants emitted from the activities regulated through the proposed Federal Indian Country Minor NSR rule (regulated NSR pollutants) include: VOC, NO X , SO 2 , PM, PM 10 , PM 2.5 , H 2 S, CO and various sulfur compounds. Hydrogen sulfide and SO 2 are emitted from production and processing operations that handle and treat sour gas. ^{70}
^{70} Sour gas is natural gas with more than 5.7 milligrams of H 2 S per normal cubic meters (0.25 grains/100 standard cubic feet), see AP-42 Compilation of Air Pollutant Emission Factors, Chapter 5.0 Introduction to Petroleum Industry, Section 5.3 Natural Gas Processing, available at: http://www.epa.gov/ttnchie1/ap42/ch05/final/c05s03.pdf .

2. Final Action
In the final FIP, there is no change in the pollutants covered.

3. Comments and Responses
The following discussion contains comments related to the pollutants included in the proposed FIP and our responses. The comments and responses are also addressed in Section 6.0 of the RTC Document.
Comment #38: One commenter recommended that the EPA expand the pollutants regulated in the proposed FIP to include methane. The commenter noted that, in the proposed FIP, the EPA states that it will include the requirements of the proposed, amended 40 CFR part 60, subpart OOOOa, in the FIP. The commenter stated that adding methane to the list of pollutants covered by the rule would provide operators and tribes with certainty that the parts of the NSPS rule governing methane emissions also apply in Indian country.
Response #38: The Federal Indian Country Minor NSR rule does not regulate GHGs, which include methane. The FIP is implementing the Federal Indian Country Minor NSR rule for the oil and natural gas sector, and, therefore, does not regulate GHGs. However, it is worth noting that, while the rule does not directly regulate methane, any controls that effectively control VOC emissions will also control methane emissions. In addition, in the event that subpart OOOOa as adopted requires control of methane, methane emissions will be reduced. No change has been made as a result of this comment.

K. Exclusion of Existing Sources From the Proposed Oil and Natural Gas FIP

1. Proposed Rule
In the proposed rule, the EPA indicated that, while the Federal Indian Country Minor NSR rule only addresses new and modified sources, including such sources in the oil and natural gas sector, the EPA believes that managing emissions from existing oil and natural gas sources in some areas of Indian country also may be important. This is because of the significant emissions associated with existing activity in the oil and natural gas sector in some areas of Indian country and the resultant need to protect public health and the environment. Addressing existing sources through a FIP could be useful in areas of Indian country for which surrounding state requirements apply to existing oil and natural gas sources located on lands that are within a state's jurisdiction. In doing so, EPA would consider tribes' views and interests, including any interest in promoting economic development.
While EPA believes that it has the necessary authority to promulgate a FIP regulating existing sources should it determine that it is necessary or appropriate to do so, in the September 2015 action, we proposed that the FIP only apply to new and modified true minor sources in the production segment of the oil and natural gas sector. In the proposed rule, we indicated that the proposed FIP for new and modified true minor sources in the oil and natural gas production segment locating or located in Indian reservations (and other areas of Indian country over which an Indian tribe, or the EPA, has demonstrated that the tribe has jurisdiction) would apply to all such areas designated attainment, attainment/unclassifiable, or unclassifiable. It would not apply to any areas designated nonattainment. The Federal Indian Country Minor NSR rule allows us to manage minor source emission increases in Indian country and to ensure that new source emissions do not cause or contribute to a NAAQS or PSD increment violation. We are concerned that the rapid growth of the oil and natural gas production segment, in combination with existing exploration and production activities, could result, or in some cases already has resulted, in adverse air quality impacts, especially in light of the approximately 6,300 existing true minor source registrations received in the EPA Region 8 Office for facilities in the oil and natural gas sector. ^{71} However, we believe that the most appropriate means for addressing impacts from existing sources is through area- or reservation-specific FIPs and not through a national FIP. If we determine that it is “necessary or appropriate” to exercise our discretionary authority under sections 301(a) and 301(d)(4) of the CAA and 40 CFR 49.11(a) of our implementing regulations, we will publish a proposed area- or reservation-specific FIP that provides an opportunity for full public review and comment. At a minimum, the EPA or tribes will need to develop area-specific plans if and when areas of Indian country become nonattainment for ozone or other NAAQS pollutants. At that time, any such area that has oil and natural gas minor source activity may require additional controls on existing (and new and modified) sources in order to achieve attainment of the NAAQS. One source of information for control options will be the EPA's control techniques guidelines (CTGs) for oil and natural gas activity that the EPA has made available for comment and will finalize in 2016. ^{72}
^{71} In the Federal Indian Country Minor NSR rule, EPA established a registration program that required owners/operators of existing true minor sources to file a one-time registration with the appropriate Reviewing Authority by March 1, 2013. The EPA's Region 8 Office has received about 6,300 registrations from true minor sources in the oil and natural gas sector. This far exceeded the amount received from sources in any other category.
^{72} For more information, go to: https://www3.epa.gov/airquality/oilandgas/index.html .
We believe that existing sources are best addressed through tailored, federal or tribal air quality plans because each basin producing oil and/or natural gas possesses different geological and meteorological characteristics and, thus, the primary fossil fuel resource extracted can be very different in quality and type and the impacts from emissions associated with extraction activities can vary widely. For example, the predominant resource extracted from the Bakken Pool ^{73} is a light, volatile oil, while the primary resource extracted from the Uintah Basin is a heavy, thick oil. Each of these types, in many cases, call for different sets of control requirements that are best addressed through tailored plans versus a national FIP.
^{73} Bakken Pool means oil produced from the Bakken, Three Forks, and Sanish formations.
We believe that through tailored plans a number of cost-effective emission reduction measures could be applied to existing emission units to balance new growth by mitigating the potential for adverse air quality impacts from overall increases in emissions. A number of state air pollution control agencies already regulate some existing emissions from this segment. ^{74} For example, in February 2014, Colorado adopted additional regulations for oil and natural gas production operations that include such requirements as expanding nonattainment area pneumatic controller requirements statewide and reducing venting and flaring of gas streams at well sites, among other control strategies. ^{75} In addition, these regulations determined leak detection and repair monitoring to be cost effective at oil and natural gas production facilities. Some technologies may even provide the industry with cost savings due to recovered product. For example, the EPA's Natural Gas Star program estimates that adding a vapor recovery unit to a storage tank could pay for itself in 3 to 37 months, and thereafter result in cost savings. ^{76}
^{74} See, e.g., L. Gribovicz, WRAP, “Analysis of States' and EPA Oil and Gas Air Emissions Control Requirements for Oil and Gas Emissions Control Requirements for Selected Basins in the Western United States (2013 Update),” Nov. 8, 2013, available at http://www.wrapair2.org/pdf/2013-11x_O&G%20Analysis%20(master%20w%20State%20Changes%2011-08).pdf .
^{75} See Colorado Dept. of Public Health and Environment, Air Quality Control Commission Web site at http://www.colorado.gov/cs/Satellite/CDPHE-AQCC/CBON/1251647985820 .
^{76} See “Lessons Learned from Natural Gas STAR Partners; Installing Vapor Recovery Units on Storage Tanks,” available at http://epa.gov/gasstar/documents/ll_final_vap.pdf on the EPA's Natural Gas Star Web site: http://epa.gov/gasstar/index.html .

2. Final Action
The final FIP does not address existing oil and natural gas sources. As we discussed in our proposal, this FIP is used in lieu of source-specific permits to fulfill our requirement under the Federal Indian Country Minor NSR rule to issue pre-construction permits to new and modified sources. Further, when we proposed the Federal Indian Country Minor NSR rule on August 21, 2006, we asked for comment on how to address existing sources and we presented four options. ^{77} Of the proposed options, in response to comments, we chose to require that existing sources have to register with their Reviewing Authority, including the submittal of emissions data, with no additional requirements, unless they modify the existing source. While one of the options presented was not to include any requirements for existing sources, and would have been more consistent with state minor NSR programs, we stated that collecting source emissions data was necessary to successfully implement the minor source program. We still believe that to be the case today and that an area-specific FIP is the most appropriate way to address emissions from existing sources.
^{77} “Review of New Sources and Modifications in Indian Country,” U.S. Environmental Protection Agency, 71 FR 48696, August 21, 2006, https://www.gpo.gov/fdsys/pkg/FR-2006-08-21/pdf/06-6926.pdf .
In addition, we are indicating in this final action that in the future (subject to notice and comment) the requirements of this FIP may be extended to certain areas designated nonattainment for which the EPA has issued an area-specific FIP. This possible, future extension of coverage of this FIP could provide a mechanism for the EPA to provide streamlined permitting in nonattainment areas where we have addressed existing sources, providing air quality protection and a way to allow continued oil and natural gas growth in Indian country where it represents an important source of tribal government revenue. So, while we are not regulating existing sources in this action, we do believe that existing sources will need to be addressed before new and modified emissions can occur in nonattainment areas.
Finally, on March 10, 2016, the Obama Administration and the EPA announced the next step in reducing emissions of methane from the oil and natural gas industry: Moving to regulate emissions from existing sources. The agency is beginning with a formal process to require companies operating existing oil and natural gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions. ^{78}
^{78} For more information, go to: http://www3.epa.gov/airquality/oilandgas/methane.html .

3. Comments and Responses
The following discussion contains comments related to the exclusion of existing sources from the proposed FIP and our responses. The comments and responses are also addressed in Section 7.0 of the RTC Document.
Comment #39: Several commenters submitted comments on the subject of regulating existing sources in the proposed FIP. Three commenters recommended that the EPA regulate existing sources; one commenter recommended that the EPA create a voluntary process for existing sources to register and to be regulated under the FIP; three commenters agreed with the EPA's position not to regulate existing sources; and one commenter recommended that the EPA regulate existing sources only in the context of area-specific rules. One of the commenters favoring the regulation of existing sources noted that there is substantial evidence demonstrating that existing oil and natural gas sources are responsible for considerable air pollution emissions within Indian country, and that a FIP is the only method by which the EPA may regulate existing sources. This commenter further noted that many areas of Indian country are already in nonattainment despite the six regulations already in place, and that it might be necessary for the EPA to regulate existing sources in other areas in order to prevent them from slipping into nonattainment. One of the commenters recommended that the EPA develop an approach for regulating existing true minor source oil and natural gas facilities in Indian country apart from the Proposed Rule that not only takes into account those parts of Indian country where the EPA finds an area- or reservation FIP is necessary for existing sources, but addresses existing sources throughout all of Indian country. Such an approach could include the use of FIPs, general permits, or permits by rule.
The three commenters requesting that the EPA not regulate existing sources recommended that regulation of existing sources should be addressed in the context of area-specific rulemakings, developed on a regional basis in a way that reflects local air quality characteristics, current air quality data, and emissions inventories. One of the commenters requesting that the EPA address existing sources in the context of area-specific rulemakings suggested that not all existing minor sources should be regulated in the same manner; the EPA should target those sources most directly contributing to air quality degradation. This commenter further recommended that, should the EPA choose to regulate existing sources, the EPA should apply control requirements to existing source emissions in a flexible manner, gradually increasing enforcement as appropriate.
Response #39: The purpose of the proposed FIP was to address pre-construction permitting for new and modified true minor sources locating or located in reservation areas of Indian country and other areas of Indian country over which a tribe has jurisdiction in order to satisfy the requirements of the Federal Indian Country Minor NSR rule. We chose this approach both because of our concern that the number of applications for source-specific permits from true minor sources in the oil and natural gas sector would overwhelm the available resources of the Reviewing Authority and to provide consistency in the regulation of such sources throughout the areas where the Federal Indian Country Minor NSR rule is in effect. The proposed FIP does not address existing sources, unless they undergo modification. We see no reason to change that in the final FIP. Rather, as discussed above, we believe the best way to address emissions from existing sources is through a reservation- or area-specific FIP if and when we determine that one is necessary or appropriate to protect air quality. In addition to satisfying the requirements of the Federal Indian Country Minor NSR rule, we believe that the final FIP addressing only new and modified true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector is sufficient to protect air quality in all of the areas to which it applies regardless of the current level of oil and natural gas production and natural gas processing activities in any particular area. The exception to this statement is the Uintah and Ouray Reservation in Utah. For the Uintah and Ouray Reservation, we have sufficient concerns with the impact of emissions from existing sources that we plan to propose a separate reservation-specific FIP addressing such sources. Similarly, we will consider promulgating such reservation- or area-specific FIPs in the future as we believe necessary or appropriate to protect air quality.
Comment #40: One commenter recommended that specific existing oil and natural gas production equipment be regulated under the proposed FIP, including: Reciprocating compressors, centrifugal compressors, liquids unloading at existing wells, glycol dehydrators, liquid storage vessels, and pneumatic controllers.
The commenter recommended that the EPA require: (1) The replacement of the rod packing of existing reciprocating compressors every 36 months or 26,000 hours of operation; (2) replacement of wet seal configurations on centrifugal compressors with one that utilizes dry seals or that captures the emissions from the oil degassing unit; (3) that plunger lifts be required for all liquids unloading; (4) that dehydrators control VOC by 95 percent with a condenser; (5) that storage vessels capture VOC emissions via a closed vent system and route those emissions to a beneficial use; and (6) that high bleed pneumatic controllers be replaced with low-bleed controllers except when technically necessary.
Response #40: As stated above, the purpose of the FIP, as proposed and as finalized herein, is to satisfy the requirements of the Federal Indian Country Minor NSR rule, and not to regulate existing sources.
Comment #41: One commenter recommended that the proposed FIP be revised to require regular Leak Detection and Repair (LDAR) surveys at all new and existing facilities, including well pads, other production facilities, gathering compressor stations, and natural gas processing plants that are not covered under 40 CFR part 60, subparts KKK and OOOO. This commenter recommended that instrument-based LDAR surveys be carried out quarterly on all sources in the production segment and that auditory, visual, and olfactory inspections should be performed monthly.
Response #41: The EPA proposed to add LDAR requirements for well sites and compressor stations, including gathering and boosting stations, to 40 CFR part 60, subpart OOOOa, rule in September 2015. ^{79} As those requirements have been incorporated into the final subpart OOOOa regulation ^{80} —and, thus, the FIP—any LDAR requirements finalized under 40 CFR part 60, subpart OOOOa, are part of the FIP. Thus, new and modified true minor sources subject to the FIP will be required to comply with certain LDAR requirements. As noted in response to Comments #39 and #40, and for the reasons stated therein, we did not propose to regulate existing sources under the FIP, and the final FIP does not regulate existing sources.
^{79} “Oil and Natural Gas Sector: Emission Standards for New and Modified Sources in the Oil and Natural Gas Sector,” U.S., Environmental Protection Agency, 80 FR 56593, September 18, 2015, https://www.gpo.gov/fdsys/pkg/FR-2015-09-18/pdf/2015-21023.pdf.
^{80} “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed and Modified Sources,” signed May 12, 2016, http://www.epa.gov/airquality/oilandgas/actions.html.

L. General Comments ( e.g., Administrative, Incorporation by Reference)

1. Proposed Rule
The proposed FIP proposed to require that owners/operators of oil and natural gas production facilities comply with six federal rules, as applicable, to reduce emissions of certain pollutants from certain equipment and processes present at oil and natural gas sources. For purposes of the proposed FIP, we proposed that compliance with these rules would effectively satisfy the NSR permitting requirement. Therefore, we proposed that true minor oil and natural gas sources subject to these applicable standards would have to comply with these standards as they currently exist and as they may be amended in the future, except for those provisions that we specifically excluded. (The proposed FIP would not have changed the applicability of the specified standards, nor would it have relieved sources subject to the standards from having to comply with them, independently of the proposed FIP.)

2. Final Action
In the final FIP, we are using the same approach that we proposed: To satisfy the FIP, sources must comply with the requirements of the six federal standards (and two other standards, which are being added in response to comments), to the extent that they apply, as they exist at the time construction begins.

3. Comments and Responses
The following discussion contains comments related to general comments and our responses. The comments and responses are also addressed in Section 8.0 of the RTC Document.
Comment #42: One commenter noted that the proposed language for § 49.105 requires that oil and natural gas sources using the FIP registration process comply with six specific federal NSPS and NESHAP regulations. The commenter stated that “The proposed rule appears to make an “evergreen” incorporation by reference— i.e., whenever the oil and natural gas FIP is invoked, the rule appears to require application of the then-current version of each incorporated regulation.” The commenter stated that it is beyond the EPA's authority to make an evergreen incorporation by reference because any amendment of the incorporated rules would result in an amendment to the oil and natural gas FIP, which effectively would be accomplished without notice and comment rulemaking for the FIP. The commenter recommended that the EPA incorporate into the oil and natural gas FIP the rules as they stand at the time the FIP is promulgated, noting that the FIP can easily be amended later if significant changes are made to the underlying rules. The commenter recommended that the text of § 49.105 be revised to directly incorporate by reference each of the six rules.
Response #42: The EPA notes that, under 1 CFR part 51, it cannot incorporate other regulations by references. It believes the proposed approach to including the NSPS and NESHAP standards in the FIP is the most efficient method of maintaining consistency with the applicable standards. Having to amend the FIP every time a standard is changed would be burdensome and create ambiguity for sources. We disagree that we lack the authority to adopt this approach through notice and comment rulemaking. While some of the requirements with which sources must comply may change over time, this does not result in a de facto amendment of the FIP. Rather, the FIP at all times requires compliance with the eight other rules, to the extent that they apply. Even in the absence of the FIP, sources subject to any of the eight other rules would be required to comply with those standards as they exist at the time the source begins construction. The public will have ample opportunity to comment on any proposed changes to the standards themselves. No changes have been made as a result of this comment.
Comment #43: One commenter noted that there is a typographical error in the reference to the proposed 40 CFR part 60, subpart OOOOa, standard; the word “applicable” should be included, as it is in the references to the other five regulations.
Response #43: The EPA has corrected the error in the final rule.

M. Other Comments
The following discussion contains comments that did not fall into another section and were not covered by the proposal but merit a response. The comments and responses are also addressed in Section 9.0 of the RTC Document.
Comment #44: One commenter stated that the final rule should not implement a setback requirement. The commenter stated that including a setback requirement undermines tribal sovereignty, contravenes explicit requirements embodied in existing Indian mineral leases, and is contrary to existing BIA regulations. The commenter also noted that the EPA cannot exceed the authority granted by Congress. The commenter characterized setback requirements as unnecessary regulations, stating that the tribes can determine the appropriate setback distance.
Response #44: There was no setback requirement in the proposed FIP, and the EPA is not adding a setback requirement in the final rule. No changes have been made as a result of this comment.
Comment #45: Two commenters submitted comments on whether state requirements should be the basis for the FIP requirements. One commenter recommended that, if the EPA chooses not to regulate existing sources throughout Indian country, then the EPA should at least regulate existing sources located in states that already do so. The commenter noted that putting state and tribal lands on a level playing field will protect the health of tribal members. The commenter also noted that, in order to comply with the requirements of Executive Order 12898, the EPA should regulate existing sources on tribal lands that are located within states that already regulate existing sources. Another commenter stated that it is not appropriate to apply state regulations to Indian country. Reservation- or region-specific FIPs should be developed that address tribes' concerns and the unique characteristics of the regions or reservations at issue.
Response #45: As discussed above, and for the reasons stated, the FIP does not regulate existing sources. Further, a mere desire to “level the playing field” is not a sufficient, sole basis for imposing requlatory requirements on oil and natural gas source owners/operators. Rather, the EPA would need to determine that the state law requirements in question were necessary or appropriate. No changes have been made as a result of this comment.

V. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
This action is not a significant regulatory action and was, therefore, not submitted to the Office of Management and Budget (OMB) for review.

B. Paperwork Reduction Act (PRA)
This action does not impose any new information collection burden under the PRA. OMB has previously approved the information collection activities contained in the Federal Indian Country Minor NSR rule and has assigned OMB control number 2060-0003. This action establishes a FIP which serves as a mechanism for true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector locating or located in areas covered by the Federal Indian Country Minor NSR rule to satisfy the requirements of that rule other than by obtaining a source-specific minor source permit. Because it substitutes for a source-specific permit, which would contain information collection activities covered by the Information Collection Request for Federal Indian Country Minor NSR rule issued in July 2011, it does not impose any new obligations or enforceable duties on any state, local or tribal government or the private sector. In addition, the information collection activities contained in the eight rules that are referenced in this FIP have also been previously approved by OMB. ^{81}
^{81} 40 CFR part 60, subpart Kb: Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984 (OMB Control No. 2060-0074); 40 CFR part 60, subpart IIII: Standards of Performance for Stationary Compression Ignition Internal Combustion Engines (OMB Control No. 2060-0590); 40 CFR part 60, subpart JJJJ: Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (OMB Control No. 2060-0610); 40 CFR part 60, subpart OOOOa: Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced after September 18, 2015 (OMB Control No. 2060-0673); 40 CFR part 63, subpart DDDDD: National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (OMB Control No. 2060-0616); 40 CFR part 63, subpart HH: National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities (OMB Control No. 2060-0417); 40 CFR part 63, subpart ZZZZ: National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (OMB Control No. 2060-0548); and 40 CFR part 60, subpart KKKK: Standards of Performance for New Stationary Combustion Turbines (OMB Control No. 2060-0582).

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. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden or otherwise has a positive economic effect on the small entities subject to the rule. The EPA analyzed the impact on small entities of streamlined permitting under the Federal Indian Country Minor NSR rule ^{82} and determined that it would not have a significant economic impact on a substantial number of small entities. (By allowing sources to avoid having to obtain source-specific permits, this FIP also relieves regulatory burden.) This action merely implements a particular aspect of the Federal Indian Country Minor NSR rule. We have, therefore, concluded that this action will have no net regulatory burden for all directly regulated small entities.
^{82} “Review of New Sources and Modifications in Indian Country,” U.S. Environmental Protection Agency, 76 FR 38748, July 1, 2011, https://www.federalregister.gov/articles/2011/07/01/2011-14981/review-of-new-sources-and-modifications-in-indian-country.

D. Unfunded Mandates Reform Act (UMRA)
This action does not contain any unfunded mandates, as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action imposes no enforceable duty on any state, local or tribal government or the private sector. It simply provides one option for sources to comply with the Federal Indian Country Minor NSR rule. The Federal Indian Country Minor NSR rule itself, not this FIP, imposes the obligation that true minor sources in areas covered by the Federal Indian Country Minor NSR rule obtain a minor source NSR permit prior to commencing construction. This FIP merely provides a streamlined mechanism for meeting that obligation.

E. Executive Order 13132: Federalism
This action does not have federalism implications. It would 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 has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. The EPA conducted outreach on this rule via ongoing monthly meetings with tribal environmental professionals in the development of the proposed action. This action reflects tribal comments on, and priorities for, developing a streamlined approach for permitting true minor sources in the oil and natural gas sector in areas covered by the Federal Indian Country Minor NSR rule. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes (May 4, 2011), ^{83} the EPA offered consultation on the proposed FIP to elected tribal officials, but no tribe requested a consultation.
^{83} For more information, go to: https://www.epa.gov/tribal/epa-policy-consultation-and-coordination-indian-tribes.
One tribal commenter did raise concerns about consultation in their written comments . The commenter recommended that, in order to develop an effective and equitable FIP, the EPA should first consult with the Ute Indian Tribe so that the Tribe can offer its expertise, experience, and input into developing the FIP. The commenter stated that the EPA should not attempt to revise the definition of Indian country. The Ute Indian Tribe requested that the EPA engage the Tribe in additional government-to-government consultation once the EPA has reviewed comments on the proposed rule and is prepared to discuss those comments and any changes to the proposed rule. After the comment period for this rulemaking closed in December, we followed up on the Ute Indian Tribe's request and it was determined that the requested consultation was no longer necessary.
The EPA agrees with the commenter that consultation with affected tribes is important to development of a successful FIP. The EPA remains available to consult with tribes in regards to issues that affect them, or proactively in connection with tribal efforts to develop a TIP. The EPA has reached out to tribes during the development of this FIP. The EPA notes that the Mandan, Hidatsa, and Arikara Nation expressed an interest in working with us to develop this FIP, although the Tribe did not submit comments on the proposed FIP.
We have made changes to the FIP proposal as a result of tribal comments. Most notably, at the request of a tribal commenter, we have clarified that we are not changing the definition of Indian country. Instead, we are clarifying the geographic applicability of the FIP with respect to areas of Indian country.
As the FIP is implemented, we will continue to provide regular outreach to tribes to ensure we address issues concerning the FIP if and when they arise. The EPA is always available for consultation with any interested tribe.

G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks
This action is not subject to Executive Order 13045 because it is not economically significant as defined in EO 12866, and because the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children.

H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution or Use
This action is not subject to Executive Order 13211, because it is not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act (NTTAA)
This action does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. This rule implements certain aspects of the Federal Indian Country Minor NSR rule.
Our primary goal in developing this FIP is to ensure that air resources in areas covered by the Federal Indian Country Minor NSR rule will be protected in the manner intended by the CAA. This action will help ensure air quality protection in areas covered by the Federal Indian Country Minor NSR rule, by including in a FIP a comprehensive set of control requirements for new and modified true minor source in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector. In addition, through this FIP, we seek to establish a mechanism that provides an effective and efficient method for implementing a pre-construction permitting program for true minor sources in the oil and natural gas sector in areas covered by the Federal Indian Country Minor NSR rule. Under this rule we are finalizing an approach that enables a streamlined process, which helps promote economic development by minimizing delays in new construction; and provides a process comparable to those programs operated outside of Indian county, which helps tribes compete for new oil and natural gas production and natural gas processing in areas covered by the Federal Indian Country Minor NSR rule.

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 is not a “major rule” as defined by 5 U.S.C. 804(2).

List of Subjects in 40 CFR Part 49
Environmental protection, Administrative practices and procedures, Air pollution control, Indians, Indians-law, Indians-tribal government, Intergovernmental relations, Reporting and recordkeeping requirements.
Dated: May 12, 2016.
Gina McCarthy,

Administrator.
For the reasons set forth in the preamble, 40 CFR part 49 is amended as follows:

PART 49—INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT
1. The authority citation for part 49 continues to read as follows:

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

Subpart C—General Federal Implementation Plan Provisions
2. Subpart C of part 49 is amended by adding an undesignated center heading and §§ 49.101 through 49.105 to read as follows:

Federal Implementation Plan for Managing Air Emissions From True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector
§ 49.101
Introduction.
(a) What is the purpose of §§ 49.101 through 49.105 ? Sections 49.101 through 49.105 adopt legally and practicably enforceable requirements to control and reduce emissions of volatile organic compounds, nitrogen oxides, sulfur dioxide, particulate matter (PM, PM 10, PM 2.5 ), hydrogen sulfide, carbon monoxide and various sulfur compounds from new and modified true minor sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector.
(b) Am I subject to §§ 49.101 through 49.105 ? You are subject to the requirements if you:
(1) Own or operate a new true minor oil and natural gas source or an existing true minor oil and natural gas source undergoing modification as determined pursuant to § 49.153(a) that meets the criteria specified in paragraphs (b)(1)(i) through (v) of this section. Then you shall comply with the requirements of §§ 49.104 and 49.105, unless you obtain a source-specific permit as specified in paragraph (b)(2) or (3) of this section.
(i) The source is an oil and natural gas source as defined in § 49.102;
(ii) The oil and natural gas source as defined in § 49.102 is located in Indian country as defined in § 49.152(d), within the geographic scope of the Federal Minor New Source Review Program in Indian Country, as specified in § 49.102;
(iii) The oil and natural gas source as defined in § 49.102 is a new true minor source or a minor modification of an existing true minor source, as determined under § 49.153;
(iv) The oil and natural gas source as defined in § 49.102 begins construction or modification on or after October 3, 2016; and
(v) The oil and natural gas source as defined in § 49.102 is not located in a designated nonattainment area.
(2) Owners/operators of sources that meet the criteria specified in paragraph (b)(1) of this section that choose to obtain a source-specific permit as specified in § 49.155 before beginning construction are not required to comply with the requirements of §§ 49.101 through 49.105.
(3) Owners/operators of sources that meet the criteria specified in paragraph (b)(1) of this section that the Reviewing Authority requires to obtain a source-specific permit to ensure protection of the National Ambient Air Quality Standards as specified in § 49.155 before beginning construction are not required to comply with §§ 49.101 through 49.105.
(c) When must I comply with §§ 49.101 through 49.105 ? You must comply with §§ 49.101 through 49.101 on or after October 3, 2016.
(d) This Federal Implementation Plan (FIP) does not apply to minor modifications at major sources.
§ 49.102
Definitions.
As used in §§ 49.101 through 49.105, all terms not defined herein shall have the meaning given them in the Clean Air Act, in subparts A and OOOOa of 40 CFR part 60, in the Prevention of Significant Deterioration regulations at 40 CFR 52.21, or in the Federal Minor New Source Review Program in Indian Country at § 49.152. The following terms shall have the specific meanings given them:
Oil and natural gas source means a stationary source engaged in the extraction and production of oil and natural gas and/or the processing of natural gas, including the wells and all related processes used in the extraction, production, recovery, lifting, stabilization, and separation or treatment of oil, water, and/or natural gas (including condensate). Oil and natural gas production and processing components may include, but are not limited to: Wells and related casing head; tubing head and “Christmas tree” piping; pumps; compressors; heater treaters; separators; storage vessels; pneumatic devices; stationary engines; natural gas sweetening; truck loading; dewpoint suppression skids; natural gas dehydrators; completion and workover processes; gathering pipelines and related components that collect and transport the oil, natural gas and other materials and wastes from the wells or well pads; and natural gas processing plants.
Oil and natural gas well means a single well that extracts subsurface reservoir fluids containing a mixture of oil and/or natural gas, and water.
Owner/operator means any person who owns, leases, operates, controls, or supervises an oil and natural gas source.
Regional Administrator means the Regional Administrator of an EPA Region or an authorized representative of the Regional Administrator.
§ 49.103
Delegation of authority of administration to Indian tribes.
(a) What is the purpose of this section ? The purpose of this section is to establish the process by which a Regional Administrator may delegate to a federally-recognized tribe the authority to assist the EPA with administration of this FIP (§§ 49.101 through 49.105). This section provides for administrative delegation and does not affect the eligibility criteria under § 49.6 for treatment in the same manner as a state or a tribe's ability to obtain approval of a tribal implementation plan under § 49.7.
(b) How does a tribe request delegation ? In order to be delegated authority to assist us with administration of this FIP, the authorized representative of a federally-recognized tribe must submit a request to a Regional Administrator that:
(1) Identifies the specific provisions for which delegation is requested;
(2) Identifies the Indian Reservation or other affected areas of Indian country for which delegation is requested;
(3) Includes a statement by the applicant's legal counsel (or equivalent official) that includes the following:
(i) A statement that the applicant is a tribe recognized by the Secretary of the Interior;
(ii) A descriptive statement that is consistent with the type of information described in § 49.7(a)(2) demonstrating that the applicant is currently carrying out substantial governmental duties and powers over a defined area;
(iii) A description of the laws of the tribe that provide adequate authority to administer the Federal rules and provisions for which delegation is requested; and
(iv) A demonstration that the tribal agency that will be responsible for administration has the technical capability and adequate resources to administer the FIP provisions for which delegation is requested.
(c) How is the delegation of administrative authority accomplished ? (1) A Delegation of Authority Agreement will set forth the terms and conditions of the administrative delegation, will specify the rule and provisions that the tribe shall be authorized to implement on behalf of the EPA, and shall be entered into by the Regional Administrator and the tribe. The Agreement will become effective upon the date that both the Regional Administrator and the authorized representative of the tribe have signed the Agreement. Once the delegation becomes effective, the tribe will be responsible, to the extent specified in the Agreement, for assisting us with administration of this FIP and shall act as the Regional Administrator as that term is used in these regulations. Any Delegation of Authority Agreement will clarify the circumstances in which the term “Regional Administrator” found throughout this FIP is to refer only to the EPA Regional Administrator and when it is intended instead to refer to the EPA Regional Administrator or a federally-recognized tribe.
(2) A Delegation of Authority Agreement may be modified, amended, or revoked, in part or in whole, by the Regional Administrator after consultation with a tribe.
(d) How will any Delegation of Authority Agreement be publicized ? The Regional Administrator shall publish a notice in the Federal Register informing the public of any Delegation of Authority Agreement with a tribe to assist us with administration of all or a portion of this FIP and will identify such delegation in the Code of Federal Regulations. The Regional Administrator shall also publish an announcement of the Delegation of Authority Agreement in local newspapers.
§ 49.104
Requirements regarding threatened or endangered species and historic properties.
(a) What are sources required to do to address threatened or endangered species and historic properties? An owner/operator subject to the requirements contained in §§ 49.101 through 49.105 to satisfy its obligation under § 49.151(c)(1)(iii)(B) to obtain a minor NSR permit shall meet either paragraph (c)(1) or (2) of this section, as appropriate.
(1) Prior completion of assessment by another federal agency. The owner/operator shall submit to the EPA Regional Office (and to the relevant tribe for the area where the source is located/locating) valid documentation demonstrating that prior Endangered Species Act (ESA) and/or National Historic Preservation Act (NHPA) compliance has been completed by another federal agency in connection with the specific oil and natural gas activity operated under this FIP (we would consider a document no longer valid if the issuing agency has reopened consultation for the prior approval). The appropriate documents shall clearly show that the other federal agency had met its obligations under both the ESA and NHPA. A simple reference to a Record of Decision or other final decision document will not be acceptable. For listed species, acceptable documentation can include a copy of a letter or biological opinion from the U.S. Fish and Wildlife Service addressing the effects of the project on listed species and critical habitat and demonstrating compliance by the federal action agency with ESA requirements. Where the federal action agency prepares a biological assessment of the action as part of its ESA compliance, that document shall also be provided to the EPA Regional Office. For historic properties, acceptable documentation can include: a letter from the appropriate historic preservation office, or a memorandum of agreement with that office, addressing the effects of the project on historic properties and demonstrating compliance by the federal action agency with NHPA requirements. All documentation shall be attached to the Part 1 Registration Form submitted in accordance with § 49.160(c)(1)(iv).
(2) Screening procedures completed by the owner/operator. The owner/operator shall submit to the EPA Regional Office (and to the relevant tribe for the area where the source is located/locating) documentation demonstrating that it has completed the screening procedures specified for consideration of threatened and endangered species and/or historic properties and receive written confirmation from the EPA stating that it has satisfactorily completed these procedures. This process of source documentation submittal and the EPA's confirmation that it has satisfactorily completed the procedures must occur prior to the source's submittal of its Part 1 Registration Form pursuant to § 49.160(c)(1)(iv). (The procedures are contained in the following document: “Procedures to Address Threatened and Endangered Species and Historic Properties for the Federal Implementation Plan for Managing Air Emissions from True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector,” https://www.epa.gov/tribal-air/tribal-minor-new-source-review ). Review of your submittal will be conducted by the Reviewing Authority in accordance with the procedure in paragraphs (a)(2)(i) and (ii) of this section:
(i) Within 30 days of receipt of your documentation, by letter to you, the Reviewing Authority must provide one of the following determinations:
(A) The documentation satisfactorily demonstrates completion of the screening procedures; or
(B) The documentation is not adequate, and additional information is needed. If the initial submittal is deficient, the Reviewing Authority will note any such deficiencies and may offer further direction on completing the screening procedures. Once you have addressed the noted deficiencies you must resubmit your revised screening procedure documentation for review. An additional 15-day review notification period will be used for the Reviewing Authority to determine whether the listed species and/or historic property screening procedures have been satisfied. If the Reviewing Authority makes such a determination, they will send you a letter stating that conclusion.
(ii) You must obtain a letter from the Reviewing Authority indicating that the source has adequately completed the screening procedures before you can submit the Part 1 Registration Form under § 49.160(c)(1)(iv) and begin construction under this FIP.
(b) [Reserved]
§ 49.105
Requirements.
(a) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 63, subpart DDDDD (National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source.
(b) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 63, subpart ZZZZ (NESHAP for Stationary Reciprocating Internal Combustion Engines), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source.
(c) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 60, subpart IIII (Standards of Performance for Stationary Compression Ignition Internal Combustion Engines), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for paragraphs (c)(1) through (7) of this section:
(1) Section 60.4200(a)(1)—Am I subject to this subpart? (applies to manufacturers);
(2) Section 60.4200(b)—Not applicable to a stationary spark ignition internal combustion engine being tested at an engine test cell/stand;
(3) Section 60.4201—What emission standards must I meet for non-emergency engines if I am a stationary compression ignition internal combustion engine manufacturer?;
(4) Section 60.4202—What emission standards must I meet for emergency engines if I am a stationary compression ignition internal combustion engine manufacturer?;
(5) Section 60.4203—How long must my engines meet the emission standards if I am a manufacturer of stationary compression ignition internal combustion engines?;
(6) Section 60.4210—What are my compliance requirements if I am a stationary compression ignition internal combustion engine manufacturer?; and
(7) Section 60.4215—What requirements must I meet for engines used in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands?
(d) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 60, subpart JJJJ (Standards of Performance for Stationary Spark Ignition Internal Combustion Engines), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for paragraphs (d)(1) through (5) of this section:
(1) Section 60.4230(b)—Not applicable to stationary spark ignition internal combustion engines being tested at an engine test cell/stand;
(2) Section 60.4230(c)—Exemption for obtaining a Title V permit if owner or operator of an area source subject to this part;
(3) Sections 60.4231 and 60.4232—Emission standards for manufacturers;
(4) Sections 60.4238 through 60.4242—Compliance Requirements for Manufacturers; and
(5) Section 60.4247—Mobile source provisions that apply to manufacturers of stationary spark ignition internal combustion engines or equipment containing such engines.
(e) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 60, subpart Kb (Standards of Performance for Volatile Organic Liquid Storage Vessels), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for paragraphs (e)(1) and (2) of this section:
(1) Section 60.112b(c)—Source-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia; and
(2) Section 60.117b(a) and (b)—Delegation of authority.
(f) For true minor sources (and minor modifications at true minor sources) that are subject to subpart OOOOa (Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced after September 18, 2015), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for paragraphs (f)(1) through (5) of this section:
(1) Section 60.5365a(h)(4)—Existing sources constructed after August 23, 2011;
(2) Section 60.5370a(c)—Permit exemption;
(3) Section 60.5413a(a)(5)—Exemptions from performance testing—hazardous waste incinerator;
(4) Section 60.5420a(a)(2)(i)—Advance notification requirements for well completions; and
(5) Section 60.5420a(a)(2)(ii)—Advance notification requirements of well completions when subject to state regulation that requires advance notification.
(g) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 63, subpart HH (National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities), for purposes of this FIP, sources must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source, except for paragraphs (g)(1) through (6) of this section:
(1) Section 63.760(a)(2)—Facilities that process, upgrade or store hydrocarbon liquids;
(2) Section 63.760(b)(1)(ii)—Each storage vessel with the potential for flash emissions;
(3) Section 63.760(g)—Recordkeeping for major sources that overlap with other regulations for equipment leaks;
(4) Section 63.764(c)(2)—Requirements for compliance with standards for storage vessels;
(5) Seciton 63.766—Storage vessel standards; and
(6) Section 63.769—Equipment leak standards.
(h) For true minor sources (and minor modifications at true minor sources) that are subject to 40 CFR part 60, subpart KKKK (Standards of Performance for Stationary Combustion Turbines), for purposes of this FIP, the owner/operator must comply with all of the applicable provisions of the standard as written at the time the owner/operator begins construction on the new true minor source or on the minor modification at an existing true minor source.
3. Section 49.151 is amended by revising paragraphs (b)(1), (c)(1) introductory text, (c)(1)(iii)(A) and (B), and (d)(1), (2), and (4) to read as follows:
§ 49.151
Program overview.
* * * * *
(b) * * *
(1) It satisfies the requirements of section 110(a)(2)(C) of the Act by establishing a pre-construction permitting program for all new and modified minor sources (minor sources) and minor modifications at major sources located in Indian country and by establishing a Federal Implementation Plan (§§ 49.101 through 49.105) for true minor sources in the oil and natural gas production and natural gas processing segments that are located in Indian country.
* * * * *
(c) When and where does this program apply? (1) The provisions of this program apply in all Indian reservation lands where no EPA-approved program is in place and all other areas of Indian country where no EPA-approved program is in place and over which an Indian tribe, or the EPA, has demonstrated that a tribe has jurisdiction, according to the implementation schedule in paragraphs (c)(1)(i) through (iii) of this section:
* * * * *
(iii) * * *
(A) If you own or operate an existing true minor source in Indian country (as defined in § 49.152(d)), you must register your source with the Reviewing Authority in your area by March 1, 2013. If your true minor source is not engaged in an oil and natural gas activity and you commence construction after August 30, 2011, and before September 2, 2014, you must also register your source with the Reviewing Authority in your area within 90 days after the source begins operation. If your true minor source is engaged in an oil and natural gas activity and you commence construction after August 30, 2011, and before October 3, 2016, you must register your source with the Reviewing Authority in your area within 90 days after the source begins operation. You are exempt from these registration requirements if your true minor source is subject to § 49.138.
(B) If your true minor source is not engaged in an oil and natural gas activity and you wish to begin construction of a new true minor source or a minor modification at an existing true minor source on or after September 2, 2014, you must first obtain a permit pursuant to §§ 49.154 and 49.155 (or a general permit/permit by rule pursuant to § 49.156, if applicable). If your true minor source is an oil and natural gas source, as defined in § 49.102, and you wish to begin construction of a new true minor source or a minor modification at an existing true minor source on or after October 3, 2016, you must either comply with the Federal Implementation Plan for sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector that are located in Indian country (§§ 49.101 through 49.105) from the day you begin construction or opt out of those requirements pursuant to § 49.101(b)(2) and instead obtain a minor source permit pursuant to §§ 49.154 and 49.155 before beginning construction. Alternatively, you may be required by the EPA, pursuant to § 49.101(b)(3), to obtain a minor source permit pursuant to §§ 49.154 and 49.155 before beginning construction. All proposed new sources or modifications of existing sources are also subject to the registration requirements of § 49.160, except for sources that are subject to § 49.138.
* * * * *
(d) * * *
(1) If you begin construction of a new source or modification that is subject to this program after the applicable date specified in paragraph (c) of this section without applying for and receiving a permit pursuant to this program or complying with the Federal Implementation Plan at §§ 49.101 through 49.105 for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, you will be subject to appropriate enforcement action.
(2) If you do not construct or operate your source or modification in accordance with the terms of your minor NSR permit or the Federal Implementation Plan for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector at §§ 49.101 through 49.105, you will be subject to appropriate enforcement action.
* * * * *
(4) Issuance of a permit or compliance with the Federal Implementation Plan for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector at §§ 49.101 through 49.105 does not relieve you of the responsibility to comply fully with applicable provisions of any EPA-approved implementation plan or Federal Implementation Plan or any other requirements under applicable law.
* * * * *
4. Section 49.152 is amended in paragraph (d) by revising the introductory text and adding paragraph (4) to the definition of “Indian country” and adding in alphabetical order the definition “Startup of production” to read as follows:
§ 49.152
Definitions.
* * * * *
(d) * * *
Indian country, as defined in 18 U.S.C. 1151, means the following as applied to this program:
* * * * *
(4) The geographic scope of applicability of this rule is as specified in § 49.151(c)(1).
* * * * *
Startup of production is as defined at § 60.5430a.
* * * * *
5. Section 49.153 is amended by revising paragraphs (a)(1)(i)(B) and (a)(1)(ii)(B) to read as follows:
§ 49.153
Applicability.
(a) * * *
(1) * * *
(i) * * *
(B) Step 2. Determine whether your proposed source's potential to emit for the pollutant that you are evaluating, (including fugitive emissions, to the extent they are quantifiable, only if the source belongs to one of the source categories listed pursuant to section 302(j) of the Act), is equal to or greater than the corresponding minor NSR threshold in Table 1 of this section. If it is, then you are subject to the pre-construction requirements of this program for that pollutant, except that sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector shall instead comply with the requirements of the Federal Implementation Plan at §§ 49.101 through 49.105, unless you opt-out of the Federal Implementation Plan pursuant to § 49.101(b)(2) in which case you are subject to the pre-construction requirements of this program for that pollutant or are required by the EPA to obtain a minor source permit pursuant to § 49.101(b)(3). If it is not, then proceed to Step 3 (paragraph (a)(1)(ii)(C) of this section).
(ii) * * *
(B) Step 2. Determine whether the increase in allowable emissions from the proposed modification (calculated using the procedures of paragraph (b) of this section) would be equal to or greater than the minor NSR threshold in Table 1 of this section for the pollutant that you are evaluating. If it is, then you are subject to the pre-construction requirements of this program for that pollutant, except oil and natural gas production and natural gas processing sources shall instead comply with the requirements of the Federal Implementation Plan at §§ 49.101 through 49.105, unless you opt-out of the Federal Implementation Plan pursuant to § 49.101(b)(2) in which case you are subject to the pre-construction requirements of this program for that pollutant or are required by the EPA to obtain a minor source permit pursuant to § 49.101(b)(3). If it is not, then proceed to Step 3 (paragraph (a)(1)(ii)(C) of this section).
* * * * *
6. Section 49.160 is amended by revising paragraphs (c)(1)(ii) and (iii), adding paragraph (c)(1)(iv), and revising paragraph (c)(4) to read as follows:
§ 49.160
Registration program for minor sources in Indian country.
* * * * *
(c) * * *
(1) * * *
(ii) If your true minor source is not engaged in an oil and natural gas activity, and you commence construction after August 30, 2011, and before September 2, 2014, then you must register your source with the Reviewing Authority within 90 days after the source begins operation. If your new true minor source or minor modification of an existing true minor source is engaged in an oil and natural gas activity, and you commence construction after August 30, 2011, and before October 3, 2016, then you must register your source with the Reviewing Authority within 90 days after the source begins operation.
(iii) If your true minor source is not engaged in an oil and natural gas activity, and you commence construction or modification of your source on or after September 2, 2014, and your source is subject to this rule, then you must report your source's actual emissions (if available) as part of your permit application and your permit application information will be used to fulfill the registration requirements described in paragraph (c)(2) of this section. If your true minor source is engaged in an oil and natural gas activity, and you commence construction or modification of your source on or after October 3, 2016, then you must report your source's actual emissions (if available) as part of your permit application (source-specific permits), unless you are subject to the Federal Implementation Plan under §§ 49.101 through 49.105 (where the requirements under paragraph (c)(1)(iv) of this section shall be met). Your permit application for oil and natural gas production and natural gas processing sources seeking a source-specific permit will be used to fulfill the registration requirements described in paragraph (c)(2) of this section.
(iv) Minor sources complying with §§ 49.101 through 49.105 for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector, as defined in § 49.102, must submit the Part 1 Registration Form 30 days prior to beginning construction that contains the information in paragraph (c)(2) of this section. The Part 2 Registration Form must be submitted within 60 days after the startup of production as defined in § 49.152(d), which include emissions information. The source must determine the potential for emissions within 30 days after startup of production. The combination of the Part 1 and Part 2 Registration Forms submittals satisfies the requirements in paragraph (c)(2) of this section. The forms are submitted to the EPA instead of the application form required in paragraph (c)(1)(iii) of this section. The forms are available at: https://www.epa.gov/tribal-air/tribal-minor-new-source-review or from the EPA Regional Offices.
* * * * *
(4) Duty to obtain a permit or to comply with the Federal Implementation Plan for sources in the oil and natural gas production and natural gas processing segments of the oil and natural gas sector. Submitting a registration form does not relieve you of the requirement to obtain any required permit, including a pre-construction permit, or to comply with the Federal Implementation Plan for the oil and natural gas production and natural gas processing segments of the oil and natural gas sector if your source or any physical or operational change at your source would be subject to any minor or major NSR rule.
* * * * *
7. Section 49.166 is amended by revising paragraph (c)(1) to read as follows:
§ 49.166
Program overview.
* * * * *
(c) When and where does this program apply ? (1) The provisions of this program apply to new major sources and major modifications at existing major sources located in nonattainment areas in all Indian reservation lands where no EPA-approved program is in place and all other areas of Indian country where no EPA-approved program is in place and over which an Indian tribe, or the EPA, has demonstrated that a tribe has jurisdiction, and where there is no EPA-approved nonattainment major NSR program beginning on August 30, 2011. The provisions of this program apply only to new sources and modifications that are major for the regulated NSR pollutant(s) for which the area is designated nonattainment.
* * * * *
8. Section 49.167 is amended by revising the introductory text and adding paragraph (4) to the definition of “Indian country” to read as follows:
§ 49.167
Definitions.
* * * * *
Indian country, as defined in 18 U.S.C. 1151, means the following as applied to this program:
* * * * *
(4) The geographic scope of applicability of this rule is as specified in § 49.166(c)(1).
* * * * *
81
107
Friday, June 3, 2016
Rules and Regulations
Part IV
Department of Agriculture
Rural Business-Cooperative Service
Rural Utilities Service
7 CFR Parts 4279 and 4287

Guaranteed Loanmaking and Servicing Regulations; Final Rule
DEPARTMENT OF AGRICULTURE
Rural Business-Cooperative Service
Rural Utilities Service
7 CFR Parts 4279 and 4287
RIN 0570-AA85
Guaranteed Loanmaking and Servicing Regulations

AGENCY:
Rural Business-Cooperative Service and Rural Utilities Service, USDA.

ACTION:
Final rule.

SUMMARY:
The Rural Business-Cooperative Service (Agency) is an agency within the Rural Development mission area of the United States Department of Agriculture (USDA) responsible for administering the Business and Industry (B&I) Guaranteed Loan Program. The B&I Guaranteed Loan Program is authorized by the Consolidated Farm and Rural Development Act and provides loan guarantees to banks and other approved lenders to finance private businesses located in rural areas.
The Agency published a proposed rule on September 15, 2014, that proposed changes to refine the regulations for the B&I Guaranteed Loan Program in an effort to improve program delivery, clarify the regulations to make them easier to understand, and reduce delinquencies. The changes to the program are expected to reduce the subsidy rate and thereby lower program subsidy costs over time as the rule is implemented. By lowering the subsidy rate, the Agency may be able to provide greater leverage for the budget authority provided by Congress. This will allow the Agency to guarantee a higher total dollar amount of loan requests and, assuming the same average size of loans being guaranteed, to guarantee more loans. These changes could also result in increased lending activity, expanded business opportunities, and creation of more jobs in rural areas.

DATES:
Effective August 2, 2016.

FOR FURTHER INFORMATION CONTACT:
Brenda Griffin, Rural Development, Business Programs, U.S. Department of Agriculture, 1400 Independence Avenue SW., Stop 3224, Washington, DC 20250-3224; email: brenda.griffin@wdc.usda.gov; telephone (202) 720-6802.

SUPPLEMENTARY INFORMATION:

Executive Summary

Purpose of the Regulatory Action
The Agency is promulgating these regulations to improve program delivery, clarify the regulations to make them easier to understand, and reduce delinquencies. The changes should reduce the cash outflows and increase the cash inflows associated with the B&I Guaranteed Loan Program portfolio, resulting in a lower subsidy rate. A lower subsidy rate should result in increased lending activity, the expansion of business opportunities, and the creation of more jobs in rural areas. Changes originated from informal third party comments and Agency experience in administering the program, including observations from assessment reviews and recommendations from the Agency's internal Business Programs Advisory Team.
The Agency believes the changes in the rule may increase lending activity, resulting in the expansion of business opportunities and the creation of more jobs in rural America, and improve the program's effectiveness by improving the prosperity of rural residents through guarantees of targeted investments that may improve rural competitiveness, facilitate industrial conversion, and enable rural residents to profit from private sector activity. The revisions contained herein may improve the efficiency and effectiveness of the program and make the regulation more customer friendly and easier to understand. The Agency thinks that errors may be reduced because the guidelines and requirements will be clearer and better organized.
The rule's incremental effect to the public will be to nominally increase the burden for lenders seeking to be an eligible lender and for “new” investors in projects that receive B&I loan guarantees after the Loan Note Guarantee is issued by a total of approximately $4,800 per year. The cost to participating lenders and borrowers was estimated to be approximately $2.5 million. The cost to the Federal government to administer the program was estimated to be approximately $2.1 million.

Summary of the Major Provisions of the Regulatory Action
This rule replaces the B&I Guaranteed Loan Program regulations under 7 CFR parts 4279 and 4287, which will not significantly depart from the current program of loan guarantees for businesses in rural areas.
The rule strengthens criteria for non-regulated lenders to participate in the program. It also codifies provisions of the 2008 Farm Bill, including two types of rural area exceptions and eligibility of local foods projects and cooperative equity security guarantees. The rule also includes provisions for New Markets Tax Credits and the Cooperative Stock Purchase Program. Changes are also made to the loan scoring criteria. Loan servicing changes include the termination of interest accrual to the lender after 90 days from the most recent delinquency effective date or to a holder the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter. Additionally, attorney/legal fees that the lender can claim in the liquidation process will be reduced from full reimbursement to being shared equally between the lender and the Agency. The rule also adds the ability to obtain personal and corporate guarantees from those owning 20 percent of the business when there is a sale of the borrower's stock.
Eligible lenders for the program include regulated lenders (formerly known as “traditional lenders”) and Agency-approved non-regulated lenders (formerly known as “other lenders”). Insurance companies will no longer be considered traditional or regulated lenders under the program. However, insurance companies will be able to apply to become Agency-approved eligible lenders by meeting criteria of a non-regulated lender established in the regulation. Historically, insurance companies have had significant default and loss rates in the Agency B&I Guaranteed Loan portfolio and merit closer scrutiny. Lenders will have to execute a new Lender's Agreement to originate new guaranteed loans; however, existing lenders are bound by their existing Lender's Agreements and must continue to service existing guaranteed loans in their portfolio regardless of whether they wish to originate new guaranteed loans.
Criteria to become an approved non-regulated lender for the B&I program will be strengthened under this final rule due to higher than usual default and loss rates for this type of lender in the Agency B&I Guaranteed Loan portfolio. Non-regulated lenders will be able to become eligible lenders for a 3-year period and may request renewals to continue originating loans under the program. Non-regulated lenders will have to have and maintain 10 percent tangible balance sheet equity, which is up from the 7 percent previously required. Non-regulated lenders will have to have a record of successfully making at least 10 commercial loans annually totaling at least $1 million for each of the last 5 years, with lender's delinquent commercial loan portfolio over that period not exceeding 6 percent of all commercial loans made and 3 percent in commercial loan losses based on the original principal loan amount. In addition, non-regulated lenders will have to maintain a loss reserve, have a line of credit issued by a regulated lender, and undergo a credit examination that must be acceptable to the Agency. These requirements are being strengthened to ensure participation in the program by lenders that have a thorough knowledge of commercial lending and high standards of professional competence to operate a successful lending program.
Under the B&I program, a rural area is generally any area of a State other than a city or town that has a population of greater than 50,000 inhabitants and any urbanized area contiguous and adjacent to such a city or town. In making this determination, the Agency will use the latest decennial census from the U.S. Census Bureau. The 2008 Farm Bill added the ability to make two different types of rural area exceptions, which was incorporated into the Consolidated Farm and Rural Development Act. Section 343(a)(13)(E) of the Consolidated Farm and Rural Development Act (7 U.S.C. 1991(a)(13)(E)) states: “Notwithstanding any other provision of this [definition], in determining which census blocks in an urbanized area are not in a rural area . . ., the [Agency] shall exclude any cluster of census blocks that would otherwise be considered not in a rural area only because the cluster is adjacent to not more than 2 census blocks that are otherwise considered not in a rural area under this [definition].” Additionally, the Under Secretary for Rural Development may determine that areas are “rural in character,” and therefore eligible for the program, under certain circumstances. Any determination made by the Under Secretary under this provision will be to areas that are determined to be “rural in character” in accordance with the first provision of Section 343(a)(13)(D) of the Consolidated Farm and Rural Development Act (7 U.S.C. 1991(a)(13)(D)) and are within: (1) An urbanized area that has two points on its boundary that are at least 40 miles apart, which is not contiguous or adjacent to a city or town that has a population of greater than 150,000 inhabitants or the urbanized area of such city or town or (2) an area within an urbanized area contiguous and adjacent to a city or town of greater than 50,000 inhabitants that is within a quarter mile of a rural area.
The eligibility section is revised to include cooperative equity security guarantees as eligible loan purposes in accordance with the 2008 Farm Bill and the purchase of stock in a business by employees forming an Employee Stock Ownership Plan or worker cooperative. Separate sections of the regulation specifically address the requirements for New Markets Tax Credits and cooperative equity security guarantees, as well as requirements for the cooperative stock purchase program. The purchase of stock in a cooperative or Employee Stock Ownership Plan (ESOP) is limited to $600,000 per loan, which is the threshold for using the short application process; however, cooperatives and ESOPs may still obtain loan guarantees in amounts up to $25 million ($40 million for rural cooperative organizations that process value-added agricultural commodities) in accordance with § 4279.119.
The eligibility section is revised to include projects that process, distribute, aggregate, store, and/or market locally or regionally produced agricultural food products to support community development and farm and ranch income. This is also a provision of the 2008 Farm Bill. The term “locally or regionally produced agricultural food product” means any agricultural food product that is raised, produced, and distributed in the locality or region in which the final product is marketed, so that the distance the product is transported is less than 400 miles from the origin of the product or within the State in which the product is produced, as defined by Section 310B(g)(9)(A)(i) of the Consolidated Farm and Rural Development Act (7 U.S.C. 1932(g)(9)(A)(i)). Food products could be raw, cooked, or a processed edible substance, beverage, or ingredient used or intended for use or for sale in whole or in part for human consumption. A significant amount of the food product sold by the borrower must be locally or regionally produced, and a significant amount of the locally or regionally produced food product must be sold locally or regionally. Projects may be located in urban areas, as well as rural areas. Funding priority will be given to projects that provide a benefit to underserved communities. In accordance with Section 310B(g)(9)(A)(ii) of the Consolidated Farm and Rural Development Act (7 U.S.C. 1932(g)(9)(A)(ii)), an underserved community is a community (including an urban or rural community and an Indian tribal community) that has limited access to affordable, healthy foods, including fresh fruits and vegetables, in grocery retail stores or farmer to consumer direct markets and that has either a high rate of hunger or food insecurity or a high poverty rate (which the Agency will assess from the most recent decennial census).
The ineligible loan purpose section is being modified to permit distribution or payment to an immediate family member of the owner to accommodate intergenerational business acquisitions. Previously, no loan proceeds could be distributed to a close relative of the owner who retained an ownership interest in the borrower. This is being changed so that an immediate family member of the owner, partner, or stockholder can purchase the business from an owner, partner, or stockholder when the seller does not retain an ownership interest and the Agency determines the price paid to be reasonable.
A definition for a high-priority project is being added to the rule. A high-priority project is defined as one that scores more than half of the points available under the scoring criteria outlined in the priority scoring section.
In an effort to reduce the cost for the taxpayer, increased percentages of guarantee will be limited to loans of $5 million and less that are either high-priority projects or where the lender needs the higher percentage of guarantee because of its legal or regulatory lending limit. Additionally, reduced guarantee fees will only be available on loans of $5 million or less, unless an authorizing statute provides otherwise ( e.g., the Alaska Roadless Areas statute).
Previously, the interest rate on the guaranteed portion of the loan could not exceed the unguaranteed portion of the loan. This was to prevent the Agency from paying a higher loss on the guaranteed portion than it otherwise would have if the interest on the guaranteed portion was equal to or less than the unguaranteed portion. This requirement has been relaxed to prevent lenders from having to set floors and ceilings to remain compliant with this requirement. The rule now allows for the interest rate on the guaranteed portion to be higher than the unguaranteed portion in situations where a fixed rate on the guaranteed portion becomes a higher rate than the variable rate on the unguaranteed portion due to the normal fluctuation in the approved variable interest rate.
Although credit quality standards have not changed, the credit quality section is being modified to be in line with the “five Cs” of credit (capacity, capital, collateral, conditions, character). The Agency's policy on standardized collateral discounting has also been added. The Agency is adding the ability to require guarantees from persons whose ownership in the borrower is held indirectly through other companies.
The Agency is relaxing the requirement for business plans with the application for loans where the use of loan proceeds is exclusively for debt refinancing and fees. The Agency is also revising the requirement for 3 years of historical financial statements for parent, subsidiary, and affiliated companies to only require current financial statements. Additionally, the number of attachments that need to be included as part of a complete application for loans of $600,000 and less are reduced.
Loan scoring criteria, which is used to fund projects by priority, is being modified to award more points for the leveraging of B&I program dollars and providing quality jobs. The administrative points section has also been modified to account for community economic development strategies and State strategic plans and to allow for the awarding of points for projects that will fulfill an Agency initiative, such as the biobased product initiative or the Investing in Manufacturing Communities Partnership initiative. The rule now allows for 150 possible priority points.
Loan servicing requirements under the B&I program have been clarified. The annual conference between the lender and the Agency can be held via teleconference. This change is not meant to replace a face-to-face annual lender conference. However, it does give some flexibility when face-to-face lender visits are not practical. The lender may contract loan servicing activities. However, the lender remains responsible for complying with all requirements of the regulations. The contracting out of any loan servicing activities does not relieve the lender of its responsibility to comply with the statutes and regulations governing the program. The rule also clarifies that the Agency will not allow the write-down of debt while leaving the borrower in business, except as directed or ordered under the Bankruptcy Code, and that no new promissory notes may be issued to process a transfer and assumption since the Loan Note Guarantee references a specifically dated promissory note(s) with specific amount(s). The lender may use an allonge to the existing promissory note to facilitate the transaction.
Lenders will also be able to utilize balloon payments to restructure a guaranteed loan in default in a workout situation as long as there is a reasonable prospect for success and the remaining life of the collateral supports the workout terms.
Lenders will provide the loan classification of the guaranteed loan at loan closing rather than 90 days after the loan has closed. Additionally, lenders must notify the Agency when a borrower is 30 days past due and cannot cure the delinquency within 30 days. The lender must also provide a monthly default status report, as opposed to bimonthly. This will allow the Agency to be more responsive to delinquencies.
The lender can proceed with liquidation after the loan has been properly accelerated while the Agency has the liquidation plan under review. This will allow the lender to take such action as appropriate to protect the interest of the lender and the Agency while the liquidation plan is under review by the Agency. The appraisal requirement threshold will be increased from $100,000 to $250,000 on all collateral to be released, and the requirement for a current appraisal for collateral to be liquidated will be increased from $200,000 to $250,000. The $250,000 threshold is consistent with Office of Management and Budget (OMB) guidelines set forth in OMB Circular A-129.
The future recoveries section has been modified. The lender must use reasonable efforts to attempt collection from any party still liable for the guaranteed loan. Any net proceeds from that effort must be split pro rata between the lender and the Agency based on the percentage of guarantee. To the extent any party to the loan has a written agreement with the Agency to repay all or part of any loss claim paid by the Agency, any collection on that agreement will not be split with the lender. This is because the Federal government has collection remedies available to it that are not available to the lender and that are not intended to benefit private parties.
Several changes have been made in an effort to reduce the cost to the taxpayer in guaranteeing business and industry loans. Reasonable attorney/legal fees that the lender can claim in the liquidation process, as well as a Chapter 7 or Liquidating 11 bankruptcy, have been reduced from full reimbursement to being shared equally between the lender and the Agency. The Agency will not allow default or penalty interest to be charged to the borrower. This could cause the Agency to pay a loss when a solution could have been possible if the interest rate had not been increased. Additionally, the rule clarifies that late payment fees and interest on interest will not be covered by the guarantee. The Agency has added the ability to require personal or corporate guarantees from those owning 20 percent or more of the borrower when stock of the borrower is sold.
A significant change that is expected to decrease the cost to the taxpayer is that interest accrual is limited to any lender to 90 days from the most recent delinquency effective date and any holder the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter. A holder is a person or entity, other than the lender, who owns all or part of the guaranteed portion of the loan. The Agency was finding instances where holders were collecting interest on the guaranteed portion of the loan for a much longer period of time than other holders on the same loan. This was costing the Agency a substantial amount of money in interest paid and complicating the administration of the defaulted loan.

Executive Order 12866, Regulatory Planning and Review
This rule has been reviewed under Executive Order (EO) 12866 and has been determined to be economically significant. The EO defines an “economically significant regulatory action” as one that is likely to result in a rule that may: (1) Have an annual effect on the economy of $100 million or more or adversely affect, in a material way, the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities; (2) create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; (3) materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in this EO. This rule was determined to be economically significant because the changes to the B&I Guaranteed Loan Program regulations are estimated to have an impact on the economy of more than $100 million.

Programs Affected
The Catalog of Federal Domestic Assistance program number assigned to the B&I Guaranteed Loan Program is 10.768.

Executive Order 12372, Intergovernmental Review of Federal Programs
B&I guaranteed loans are subject to the Provisions of Executive Order 12372, which require intergovernmental consultation with State and local officials. The Agency will conduct intergovernmental consultation in accordance with 2 CFR part 415, subpart C.

Executive Order 12988, Civil Justice Reform
This rule has been reviewed under Executive Order 12988, Civil Justice Reform. The Agency has determined that this rule meets the applicable standards provided in section 3 of the Executive Order. Additionally, (1) all State and local laws and regulations that are in conflict with this rule will be preempted; (2) no retroactive effect will be given to the rule; and (3) administrative appeal procedures, if any, must be exhausted before litigation against the Department or its agencies may be initiated, in accordance with the regulations of the National Appeals Division of USDA at 7 CFR part 11.

Executive Order 13132, Federalism
The policies contained in this rule do not have any substantial direct effect on States, on the relationship between the Federal government and the States, or on the distribution of power and responsibilities among the various levels of government. Nor does this rule impose substantial direct compliance costs on State and local governments. Therefore, consultation with States is not required.

Executive Order 13175, Consultation and Coordination With Indian Tribal Governments
This Executive Order imposes requirements on the Agency in the development of regulatory policies that have tribal implications or preempt tribal laws. Rural Development has determined that this rule does not have a substantial direct effect on one or more Indian tribe(s) or on either the relationship or the distribution of powers and responsibilities between the Federal government and Indian tribes. Thus, this rule is not subject to the requirements of Executive Order 13175. If a tribe determines that this rule has implications of which Rural Development is not aware and would like to engage with Rural Development on this rule, please contact Rural Development's Native American Coordinator at (720) 544-2911 or AIAN@wdc.usda.gov.

Regulatory Flexibility Act
Under section 605(b) of the Regulatory Flexibility Act, 5 U.S.C. 605(b), the Agency certifies that this rule will not have a significant economic impact on a substantial number of small entities. This rule affects lenders that utilize the B&I Guaranteed Loan Program and any potential lenders that may utilize the program in the future. There are approximately 1,117 active lenders in the B&I portfolio. The Agency estimates that approximately 50 percent of the lenders that utilize the program are small community banks that are considered a small entity, as defined by the Regulatory Flexibility Act. Therefore, the Agency has determined that this final rule will have an impact on a substantial number of small entities.
However, the Agency has determined that the economic impact of the rule on these small lenders will not be significant. Many of the changes being implemented in the rule are tweaks to the program that lenders have suggested at a series of lender roundtable meetings or during annual lender visits that do not have any economic impact on the lenders. The most significant change in the rule that affects lenders is the criteria to become an approved non-regulated lender. This change by itself, however, does not have a significant economic impact on a substantial number of entities as it affects less than 2 percent of the active lenders (approximately 21 non-regulated lenders). Based on the data in the Paperwork Reduction Act (PRA) burden package, the Agency estimates the cost of the rule to be approximately $1,600 per non-regulated lender. This is based on determining which of the estimated costs in the PRA burden package would be incurred by the lenders applying for and participating in the program, and the estimated number of lenders. The Small Business Administration's definition of a small business for lenders is total assets of $500 million or less. The Agency selected 20 small lenders at random to determine their total assets. Based on 2014 data, the range of total assets for these 20 lenders is $52.6 million to $476 million. The average cost of $1,600 per non-regulated lender represents less than 0.003 percent of the total assets of the smallest of these 20 lenders. Therefore, this rule will not have a significant impact on a substantial number of small entities.

Unfunded Mandates Reform Act
This rule contains no Federal mandates (under the regulatory provisions of Title II of the Unfunded Mandates Reform Act of 1995) for State, local, and tribal governments or the private sector. Thus, this rule is not subject to the requirements of sections 202 and 205 of the Unfunded Mandates Reform Act of 1995.

Environmental Impact Statement
This rule has been reviewed in accordance with 7 CFR part 1970, “Environmental Policies and Procedures.” The Agency has determined that this action does not constitute a major Federal action significantly affecting the quality of the human environment, and in accordance with the National Environmental Protection Policy Act of 1969 (NEPA), 42 U.S.C. 4321 et seq., an Environmental Impact Statement is not required.
Under this program, the Agency conducts a NEPA review for each application received. To date, no significant environmental impacts have been reported, and Findings of No Significant Impact have been issued for each approved application. Taken collectively, the applications show limited potential for significant adverse cumulative effects.

Paperwork Reduction Act
The information collection requirements contained in this final rule have been submitted to the Office of Management and Budget (OMB) for review and approval.

E-Government Act Compliance
Rural Development is committed to complying with the E-Government Act to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to Government information and services and for other purposes.

I. Background
Rural Development administers a multitude of Federal programs for the benefit of rural America, ranging from housing and community facilities to infrastructure and business development. Its mission is to increase economic opportunity and improve the quality of life in rural communities by providing the leadership, infrastructure, access to capital, and technical support that enables rural communities to prosper. To achieve its mission, Rural Development provides financial support, including direct loans, grants, and loan guarantees, and technical assistance to help improve the quality of life and provide the foundation for economic development in rural areas.
The B&I Guaranteed Loan Program was authorized by the Rural Development Act of 1972. The loans are made by private lenders to rural businesses for the purpose of creating new businesses, expanding existing businesses, and for other purposes that create employment opportunities in rural America. Businesses in rural areas are eligible for this program. Rural area, as defined by 7 CFR 4279.108(c), is generally defined as any area other than a city or town of more than 50,000 inhabitants and the urbanized area contiguous and adjacent to such a city or town. The types of borrowers that are served by the B&I Guaranteed Loan Program are cooperative organizations, corporations, partnerships, or other legal entities organized and operated on a profit or nonprofit basis; Indian tribes on a Federal or State reservation or other federally recognized tribal group; public bodies; or individuals, provided the borrower is engaged in, or proposing to engage in, a business. Loans can be made for a variety of purposes, including business acquisition, expansion or improvement; purchase of real estate, machinery and equipment, or supplies; limited debt refinancing; and working capital. The rate and term of the loan is negotiated between the business and the lender.
The regulations for the B&I Guaranteed Loan Program were rewritten in 1996 to streamline and simplify the regulations for the program while shifting primary responsibility for loan documentation and analysis from the Agency to the lenders to make the program more responsive to the needs of lenders and rural businesses.

II. Discussion of Comments Received on the Proposed Rule
The Agency received a total of 717 comments from 233 commenters. Approximately 277 comments received supported the rule as written, and approximately 170 of the comments resulted in minor changes to the rule. The remaining comments were adverse to certain proposed changes in the rule. The following is a discussion of the comments received on the proposed rule.
Fourteen comments were received on the definitions section. One commenter recommended revising the agricultural production definition to clarify that “for fiber or food for human consumption” only applies to the breeding, raising, feeding, or housing of livestock and not to the cultivation, growing, or harvesting of crops, which should remain ineligible no matter what the purpose of the crop. This comment was adopted. One commenter recommended deleting the definition of “person” and revising the definition of “borrower” to avoid confusion. This comment was not adopted because “person” is a standard legal definition, which means a person or entity, and is used many times throughout the rule. Two commenters recommended changing the definition of delinquency to “a scheduled loan payment that is more than 90 days past due and cannot be cured within 30 days.” These comments were not adopted because loans are considered delinquent by many lenders when the payment is not made by the payment due date. The Agency is already allowing for more time by considering a loan delinquent when the loan payment is 30 days past due and cannot be cured within 30 days, which effectively is 60 days late. One commenter recommended revising the energy project definition so that projects that have energy outputs that are a by-product of operations, or that the Agency otherwise determines is not an energy project, would not be subject to the increased equity requirements for energy projects. This comment was adopted. One commenter recommended changing the definition of high-priority project to exclude State Director and Administrator priority points from the total number of priority points because of the discretionary nature of those points, which was not adopted. The Agency feels that the reasons to award State Director and Administrator priority points are compelling and are not adequately captured under other categories. Additionally, not counting State Director and Administrator points would likely lead to errors in calculating a project's priority score. Five commenters supported the definition of high-priority project as proposed. Additionally, one commenter recommended adding a definition for “farm or ranch”, another recommended adding a definition for “residential housing”, and one commenter recommended adding a definition for “business plan” and “feasibility study.” These comments were not adopted. Definitions for these terms are not necessary because these are commonly used terms that are generally understood and have caused no confusion in the past.
Forty-five comments were received on the eligible lenders section. One commenter recommended mortgage companies that are approved by the Rural Housing Service be considered regulated lenders for the B&I program. This comment was not adopted because housing lenders are generally not commercial lenders and usually do not have adequate expertise in commercial lending. Four commenters recommended that Community Development Financial Institutions (CDFI) be considered regulated lenders. These comments were not adopted because CDFIs are not subject to credit examination and supervision by either an agency of the United States or a State. One commenter recommended either eliminating non-regulated lenders or further strengthening the criteria for them to be considered eligible, such as requiring the lender to have a line of credit issued by a regulated lender and requiring the lender to submit that line of credit information and their audited financial statements for review annually. The Agency is adopting part of this comment. The Agency will require non-regulated lenders to have a line of credit issued by a regulated lender and to submit their audited financial statements annually but will not be eliminating non-regulated lenders because they are an additional source of funding for businesses in rural areas.
Six commenters recommended allowing only regulated lenders to participate in the B&I program. These comments were not adopted because the Agency is strengthening eligibility criteria for non-regulated lenders but does not intend to deny all non-regulated lenders access to the program. Historically, non-regulated lenders have provided a meaningful lending source to businesses in rural areas, and the Agency believes the strengthened criteria to become a non-regulated lender will ensure that non-regulated lenders participating in the program have adequate commercial lending experience to operate a successful lending program. Fifteen comments were received on the 3-year renewal process for non-regulated lenders. Eleven commenters were against a 3-year renewal process, two suggested a 5-year renewal process with existing approved lenders being grandfathered in, one suggested only grandfathering in existing approved lenders in good standing, and one recommended automatic renewal as long as the lender is in good standing. None of these comments were adopted for the following reasons. First, the Agency needs to implement a renewal process to maintain a list of actively approved lenders. Second, there is currently no vehicle to ensure non-regulated lenders continue to meet lender eligibility criteria once they are initially approved. Third, all non-regulated lenders must meet the new criteria to be an eligible non-regulated lender; therefore, they must reapply. Lastly, a 5-year period is too long a period of time for the Agency to review a lender's information to ensure they continue to meet the requirements of an eligible lender. Seven comments were received with regard to the specific requirements set forth in section 4279.29(b)(1)(ii) that a non-regulated lender must meet, including suggested changes to the number of commercial loans and delinquency percentage required. These comments were not adopted as the Agency is strengthening eligibility criteria for non-regulated lenders, and those suggestions do not accomplish that objective. Three comments were received that did not support the requirement for a loan loss reserve of 3 percent for non-regulated lenders. The Agency recognizes that many lenders use a loan loss reserve coverage ratio to establish the amount of a loan loss reserve, but this requires regular screening of a lender's loan portfolio, which is not something the Agency can easily manage. According to the Federal Administrator of National Banks, the amount set aside for loan losses is about 2 to 2.5 percent of outstanding loan receivables, depending on the quality of the loans in the portfolio, which indicates the 3 percent requirement is not out of line for a non-regulated lender. Four comments were received recommending that credit examinations performed by Aeris, formerly known as the CDFI Assessment and Ratings System, be accepted as an acceptable credit examination. The Agency concurs with this suggestion. However, these comments do not require a rule change and will be addressed administratively. One commenter recommended the credit examination requirement be stricken, which was not adopted because non-regulated lenders need to undergo some type of examination to give the Agency a level of comfort approving them as non-regulated lenders for the program. Two commenters recommended not requiring audited financial statements for non-regulated lenders (a current requirement), which was also not adopted. The Agency needs to better monitor its approved non-regulated lenders and is requiring not only an audited financial statement at the time of application and renewal but annually as review of financial statements is a routine way of monitoring. Lastly, one commenter recommended deleting the requirement that rates and fees charged by non-regulated lenders must not be greater than those charged by similarly located regulated commercial lenders. This comment was adopted because section 4279.120 allows the lender to establish charges and fees for the loan provided they are similar to those normally charged other applicants for the same type of loan in the ordinary course of business.
Two comments were received with regard to environmental issues. One commenter suggested that the new environmental proposed rule and the B&I proposed rule be aligned, which the Agency will ensure. Another commenter suggested that the Agency use the site assessment from the lender for the Agency's requirements, which could not be adopted because of National Environmental Policy Act of 1969 requirements.
One comment was received with regard to audits for public bodies and nonprofits suggesting that the rule align with 2 CFR part 200, subpart F. This comment was adopted.
Seven comments were received suggesting specifically stating that amendments may be made to the Conditional Commitment, which were adopted. The Agency made changes to the rule to clarify that the Conditional Commitment can be modified.
Nine comments were received with regard to limiting interest accrual to holders. Three commenters indicated they did not believe the liquidity event of one investor should force the repurchase of a loan by the Agency, and one commenter indicated that one holder should not be able to initiate a claim and dictate the timeline for other holders. These comments were taken into consideration. The Agency agrees and has implemented these concepts by providing that for loans closed on or after the effective date of the final rule, the lender or the Agency will issue an interest termination letter to the holder(s) establishing the termination date for interest accrual. The guarantee will not cover interest to any holder accruing after the greater of: 90 Days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter. Four commenters supported the regulation change as proposed, and one commenter recommended that the new interest cap for lenders appear in the Full Faith and Credit section for consistency since the interest cap for holders is reflected there. This comment was adopted.
One commenter recommended a requirement that the lender submit to the holder its pro rata share of payments within 5 business days, which was not adopted. The regulation indicates the payment should be remitted promptly, and the Agency declines to define “promptly” or set a specific time period for the lender to remit payment to the holder. Based upon discussions with some of the largest secondary market holders, lenders typically take as much as 30 days to process and remit payments to holders.
One commenter suggested clarifying that a holder typically notifies the lender and the Agency of reassignments after a sale and recommended changing reference of the Bond Market Association to the Securities Industry and Financial Markets Association. Both recommendations were adopted. Another commenter recommended language stating that holders are encouraged to consult with the Agency in order to validate authenticity of guaranteed loans they purchase, which also was adopted.
Two commenters suggested the minimum retention section be modified to allow lenders to sell the unguaranteed portion in any way as long as they buy back and retain the minimum 5 percent of the total loan amount. These suggestions were not adopted because of the potential for fraud or abuse. One commenter recommended clarifying that under the multi-note system, the lender does not retain title to the notes. This comment was adopted.
Fourteen comments were received on the repurchase from holder section. Ten commenters recommended that the “lender is encouraged to repurchase” text be stricken, and three others recommended that the “in the opinion of lender” text be stricken. Both of these provisions are in the current rule, as well as the Biorefinery Assistance Program regulation, although one sentence was added to emphasize the benefit to the lender. This was added to encourage lenders to repurchase guaranteed loans in default versus the Agency having to repurchase them. As such, the suggestions to strike the text were not adopted. One commenter suggested adding “if the default is not cured” to the repurchase text for clarification, which was adopted along with integrating paragraph (c) of § 4279.78 into paragraph (a).
One commenter suggested that a form be developed in lieu of requiring an indemnity bond when documents are lost, stolen, destroyed, mutilated, or defaced. This comment was not adopted because an indemnity bond is the only way the Agency is guaranteed to be made whole in the event the Agency erroneously makes payment on both an original and duplicate document. One commenter recommended § 4279.84(b)(4) be neutered to apply to both single note and multi-note options, which was adopted.
The Agency invited public comment as to whether guaranteed loans should be made to businesses that do not meet citizenship requirements, if the facility being financed will create new or save existing jobs for rural U.S. residents and when loan funds are used only for fixed assets that will remain in the United States. Sixteen comments were received with regard to the citizenship requirement for corporations or other non public-body type borrowers. Fifteen comments supported removing the citizenship requirement, and one did not. As such, the rule was revised to remove the citizenship requirement for corporations or other non public-body type borrowers if the facility being financed will create new or save existing jobs for rural U.S. residents and when loan funds are used only for fixed assets that will remain in the United States. The B&I program is focused on the creation and retention of jobs in rural America. It is critical that jobs be created and retained in the United States, and this provision will help to achieve that.
Nine comments were received with regard to rural area exceptions. Eight of the comments support addition of the Farm Bill language, and one suggested that the language for rural area exceptions in § 4279.108(c)(6) be rewritten, which was not adopted due to the text's statutory nature.
Twenty-one comments were received with regard to eligible uses of funds. Four commenters support the enhanced and clarified uses of funds as proposed. Two commenters recommended that nursing homes and assisted living facilities be specifically listed as eligible loan purposes for clarification because the ineligible loan purpose/entity section uses the term “or other residential housing.” These comments were adopted. One commenter recommended clarifying that the purchase and development of land, buildings, etc., is for commercial or industrial properties, which was also adopted. One commenter recommended requiring documentation that newly proposed residential units as part of mixed-use properties be necessary to fill a lack of currently available housing. This comment was not adopted because in mixed-use properties, the housing component is critical to project viability. One commenter recommended recasting the existing lender debt sentence to state existing lender debt refinancing may not exceed 50 percent of the overall loan instead of existing lender debt refinancing must be less than 50 percent of the overall loan. This comment was adopted. One commenter recommended stating that “except for the refinancing of lines of credit”, debt being refinanced must have been for an eligible loan purpose. This comment was adopted. The same commenter further suggested that this paragraph reiterate that loans to borrowers with facilities located in both rural and non-rural areas will be limited to the amount necessary to finance the facility located in the eligible rural area. This comment was not adopted because § 4279.108(c) already states this and reiteration is not necessary. One commenter recommended removing industries undergoing adjustment from terminated Federal agricultural price and income support programs or increased competition from foreign trade as an eligible loan purpose. This comment was not adopted as the provision is required by Section 310B(a)(2)(D) of the Consolidated Farm and Rural Development Act. Seven comments were received with regard to energy projects. One commenter indicated energy projects should be eligible regardless of whether the project is eligible for the Rural Energy for America Program (REAP), which was not accepted because the intent of this provision was to steer energy projects to the REAP program to the extent possible. Two comments from the same commenter were received with regard to expanding eligibility for “next phase” technology, which were not adopted because there is too much risk involved with next-phase technology. Energy projects are risky by nature, but requiring the energy project to be commercially available reduces risk. Three comments were received with regard to locally or regionally produced agricultural food products. Two commenters recommended allowing only non-rural local foods projects when the project assists rural businesses and creates and/or saves jobs in the surrounding rural communities. These comments were not adopted because they conflict with the statute. There could be projects in non-rural areas that serve underserved communities that do not necessarily provide an economic benefit to the surrounding rural communities, assist rural businesses, or create and/or save jobs in the surrounding rural communities. One commenter recommended the Agency retain the current policy that projects that are eligible under the locally or regionally produced agricultural food products initiative may be located in urban areas, as well as rural areas. This comment was adopted.
Four commenters support the addition of the cooperative stock/cooperative equity sections, and two commenters recommended not requiring a prospectus and striking reference to Securities Exchange Commission regulations for cooperatives since cooperatives are exempt from these requirements. These comments were adopted.
Thirteen comments were received on the New Markets Tax Credit (NMTC) program. One commenter stated that unless legislation is passed to continue the NMTC program, the entire section should be stricken. As Section 141 of Division Q of the Consolidated Appropriations Act of 2016, which was signed into law on December 18, 2015, extended the NMTC program through 2019 and the fact that Community Development Entities (CDE) have several years to deploy allocated funds, this comment was not adopted. One commenter suggested reserving guarantee authority for a pilot program, but this comment was not adopted because the Agency has no authority to reserve funding for an NMTC pilot program. One commenter suggested incorporating a requirement for “reasonable and customary fees” or the approved unwind at the end of the NMTC compliance period to include the sub-CDE conferring some significant percentage, if not all, of the NMTC subsidy to the Qualified Active Low Income Business (QALICB). This comment was adopted since § 4279.120 allows the lender to establish charges and fees for the loan. Furthermore, the regulation was revised to require the plan to unwind the fund be included in the guaranteed loan application to the Agency. Two commenters suggested that the rule be clarified that the guarantee is provided to a loan made to a qualified business in a rural area, and two commented that the Agency should consider allowing the guarantee to attach to the leveraged loan(s) made to the upper-tier investment fund, both of which were adopted. One commenter suggested clarifying that the guarantee could only attach to the QALICB's loan, which was not adopted because, as a result of other comments, the rule has been expanded to include a lender's leveraged loan to accommodate the mechanics of the NMTC program. The entire section was restructured to separate guarantees for QALICBs' loans and guarantees for lenders' leveraged loans. Three commenters recommended a “direct tracing” method. These suggestions were also adopted. Two commenters suggested that CDEs should not have to provide audited financial statements and loan performance statistics to become an eligible non-regulated lender. These comments were not adopted because CDEs must meet the requirements of § 4279.29(b) to be an approved non-regulated lender.
Fifty comments were received on the ineligible loan purpose/entity type section. One commenter suggested that § 4279.117 be revised to align with Section 363 of the Consolidated Farm and Rural Development Act to include as an ineligible loan purpose any project that drains, dredges, fills, levels, or otherwise manipulates a wetland, which was adopted. One commenter suggested that transactions among immediate family members that are not arm's length transactions be value-validated via an appropriate appraisal, which was also adopted. Another commenter recommended clarifying what documentation would be obtained from the selling immediate family member to ensure they are not trying to circumvent the regulation by staying on running/operating or assisting with the business. This comment does not require a rule change. The Agency will provide administrative guidance to clarify that the selling immediate family member is prohibited from having an ownership interest in the business but that does not preclude the former owner from remaining as an employee of the business during a transitional period. One commenter recommended a sentence be added to more specifically state that documented construction or installation costs may not include any profit or wages to related persons/entities and that all such work must be done at cost. This comment was adopted. One commenter recommended that a selling immediate family member be allowed to maintain a minority ownership interest in the borrower. This recommendation was not adopted because the business must be acquired in full to be a business acquisition in accordance with § 4279.113(b). One commenter recommended that “on account of an ownership interest” be added and that the Agency allow reasonable overhead, developer fees, and profit in line with market standards. These comments were not adopted because the addition of “on account of an ownership interest” does not add anything to the sentence and the Agency only allows construction or installation work to be done by an affiliate at cost with no profit to the affiliate. Three comments were received questioning the prohibition of guaranteeing projects in excess of $1 million that would likely result in the transfer of jobs from one area to another and increase direct employment by more than 50 employees. These comments were not adopted because this is a statutory provision. Five commenters stated that campgrounds should be an eligible loan purpose. These comments were adopted, and campgrounds and resort trailer parks will not be listed as ineligible loan purposes. Campgrounds and resort trailer parks will be added to the list of examples under tourist and recreation facilities in the eligible loan purpose section. Eight commenters stated that apartments, duplexes, and other housing projects that would not be eligible for multi-family housing programs should be an eligible loan purpose. These comments were not adopted because these types of projects do not generally provide lasting community benefits and create or save quality jobs, and guarantee authority would be better utilized for projects that do. One commenter suggested clarification of the prohibition on supporting inherently religious activities, specifically as it relates to the financing of hospitals with chapels, funeral homes conducting religious services, or event centers that periodically host weddings. This comment was not adopted because it is already addressed at 7 CFR part 16. In line with the Faith Based Initiative, the Agency revised its provision precluding the funding of “church-controlled” organizations to precluding the funding of “inherently religious activity.” While mere control by a church no longer disqualifies a proposed applicant, it is the Agency's position that religious entities are charitable organizations and, as such, must not exceed the 10 percent cap on charitable donations. One commenter suggested allowing next-phase technology, which was not adopted because the B&I program only guarantees projects that are commercially available, which by definition would exclude next-phase technology. There is too much risk involved with next-phase technology. Energy projects are risky by nature, but requiring the energy project to be commercially available reduces risk. Thirteen commenters recommended that debt service reserves be eligible. These comments were adopted, and debt service reserves were removed as an ineligible loan purpose. One commenter indicated the conflict of interest prohibition was overly broad and not well defined. The text is broad by design to provide flexibility while encompassing any conflict of interest situation. The Agency is available to provide eligibility determinations, which would enable applicants to determine whether a conflict of interest exists. One commenter suggested defining “lender's officers” and asked what the rationale was for removing the lender's directors, stockholders, or other owners from the prohibition and what documentation would be required on what policies the lender has in place to remove the lender's director, stockholder, or other owner from the decisionmaking process. The intent of this revision was to allow a borrower's owner who has a nominal interest (less than 5 percent) in the lender or who is a member of the lender's board of directors (as long as they are not also officers) to still have the lender provide the guaranteed loan to the borrower. The suggestion to add a definition for “lender's officers” was not adopted because it is not necessary, although additional language was added to address the concern of the lender's director, stockholder, or other owner being removed from the decisionmaking process. Two commenters recommended that charitable organizations engaged in or proposing to engage in a business be eligible. These comments were adopted when it can be demonstrated that not more than 10 percent of a charitable organization's revenue is generated from tax deductible charitable donations. A charitable organization proposing to engage in a business could charter that business separately as a for-profit business.
One hundred and seventy five comments were received supporting allowing an owner to stay involved in a phased ownership buyout by employees for ESOPs and worker cooperatives. Three commenters recommended a specific eligibility provision for worker cooperative and ESOP stock purchases. These comments were adopted. Two commenters recommended that there be a limited time period where the transferred business must be fully employee owned upon completion. One of those suggestions was a 5-year period, which was adopted. One commenter suggested a more detailed description of the kind of stock to be transferred/financed, and one commenter suggested allowing loan guarantees in stages. These comments were adopted, and a new section was added to address staged financing and the transfer of stock within cooperatives.
Fifteen comments were received on the loan guarantee limit section. One commenter suggested a guarantor loan limit of $50 million, which was adopted. One commenter suggested that the Agency clarify how legal or regulatory lending limits would impact the percentage of guarantee. The legal or regulatory lending limit does not impact the percentage of guarantee per se. As long as the lender's legal lending limit would otherwise prevent it from being able to make the loan to the borrower, a lender may request up to a 90 percent guarantee. Two commenters recommended that guarantees of up to 90 percent be allowed for local and regional food enterprise loans of up to $10 million. Seven commenters recommended guarantees of up to 90 percent remain for loans of up to $10 million. These comments were not adopted because the $5 million loan limit for increased percentages of guarantee mirrors the loan limit for reduced guarantee fees, and these are steps the Agency is taking to reduce the cost of administering the program. Four comments were received supporting the limitation of increased percentages of guarantee to loans of $5 million or less.
Ten comments were received on the fees and charges section. Seven commenters recommended that reduced guarantee fees be available for all loans, regardless of loan amount. These comments were not adopted because there is a negative impact on program subsidy for reduced guarantee fees, and the Agency is trying to reduce the costs of administering the program. One commenter suggested deleting “or fundamental structural changes in its economic base” in the criteria for allowing a reduced guarantee fee, which was adopted because the priority scoring section no longer contains that clause. Two commenters recommended that the responsibility to ensure that annual renewal fees have been paid be that of the lender. These comments were accepted as the requirement is directed at the lender.
Twenty comments were received on the interest rate section. Three commenters addressed interest rate swaps, which the current regulation allows. One commenter recommended that interest rate swaps not be allowed because they expose users to interest rate and credit risk. Two commenters, however, pointed out that borrowers who opt for a variable rate loan will not have the opportunity to hedge against rising interest rates if interest rate swaps are not allowed. The Agency notes that it has long been its policy for the B&I Guaranteed Loan Program that interest rates are negotiated between the lender and the borrower, including instances of interest rate swaps. As noted by the commenters, interest rate swaps may benefit some borrowers and may expose other borrowers to interest rate and credit risk. On balance, the Agency has decided retain its long-standing policy of allowing interest rate swaps under this program. The Agency points out that the loan guarantees it issues under this program covers only the principal and interest on the guaranteed loans and does not cover any fees associated with interest rate swaps. One commenter suggested that a variable interest rate be tied to a base rate published in a national or regional financial publication, which was adopted. One commenter recommended that interest rates on the unguaranteed portion be allowed at the outset to be lower than the guaranteed portion if the adjustment period on the unguaranteed portion is shorter than the guaranteed portion, which would represent a lower rate risk to the bank. This comment was not adopted because allowing the guaranteed portion to have a higher interest rate would cause the Agency to pay more on a loss than it otherwise would if the guaranteed portion was equal to or less than the unguaranteed portion. Seven commenters support the new provision providing that lenders do not have to set interest rate floors and ceilings to remain in compliance with the regulation. Four commenters support the addition of the requirement that the lender's promissory note may not contain provisions for default or penalty interest. Three commenters recommended this provision be stricken. These comments were not adopted because allowing default interest rates could cause the borrower to continue in default because of the higher payment, which increases the likelihood of the Agency having to pay a loss. One commenter recommended adding a provision that the lender may not charge late payment fees for the same reason; however, this comment was not adopted because the Agency believes there needs to be some incentive for the borrower to get its payments in on time.
One commenter suggested clarifying what is meant by project cash flow statements, which was adopted. Administrative text was added to the Instruction to provide clarification.
Sixteen comments were received on collateral requirements. One commenter recommended that intangible assets not be allowed to serve as primary collateral and recommended minor changes to the rule text, both of which were adopted. Three commenters suggested tying collateral discount rates to the Federal Deposit Insurance Corporation (FDIC) supervisory loan-to-value limitations. These comments were not adopted because FDIC supervisory loan-to-value limitations only apply to real estate, and there are no set limitations for machinery and equipment or accounts receivables and inventory. Furthermore, the loan-to-value limitations are excluded when loans are guaranteed or insured by the U.S. Government when the amount of the guarantee or insurance is at least equal to the portion of the loan that exceeds the supervisory loan-to-value limit. Five commenters stated they did not believe there was a need to change the current language because lender regulatory requirements define collateral and appropriate discounts. These comments were not adopted because changes are necessary to bring consistency in collateral requirements. Seven comments were received on the requirement for reviewed financial statements when there is a predominant reliance on inventory and/or receivable collateral that exceeds $250,000. Four of these commenters mistakenly thought if the loan amount exceeds $250,000, reviewed financial statements would be required and recommended the threshold be $1 million. These comments were not adopted because reviewed financial statements would only be required when there is a predominant reliance on inventory and/or receivable collateral that exceeds $250,000, which will usually only be applicable for working capital loans. If receivables and inventory are the predominant or only collateral for a loan, the Agency must ensure collateral for these types of loans is adequate.
Thirty-six comments were received with regard to equity. Three commenters suggested reducing the tangible balance sheet equity requirement for new businesses from 20 percent to 10 percent. These comments were not adopted because startup businesses are generally cost intensive, and those that are financed with more equity and less debt are more likely to succeed. Two commenters indicated that Generally Accepted Accounting Principles (GAAP) accounting allows related entities to transfer assets to one another at fair market value and asked why the Agency would not allow such a transaction if it is in accordance with GAAP. The Agency adopted the comments and modified the sentence to allow it when in accordance with GAAP and evidence is provided that the transaction was entered into at market terms. One commenter indicated clarification was needed on owner subordinated debt and asked if payments could be made on the subordinated debt and whether interest could be paid on the subordinated debt. This comment was accepted, and administrative text was added to the Instruction to clarify that as it is the principal amount of cash being injected as owner subordinated debt that the Agency will consider equity when calculating tangible balance sheet equity, no payments can be made on this subordinated debt because the cash must remain in the business for the life of the loan. This would not, however, preclude interest from being paid on the subordinated debt as long as the guaranteed loan is current and there are no loan agreement/covenant violations. Because the regulation requires an injection of cash in exchange for the subordinated debt, an owner would not be able to create a subordinated debt note in lieu of drawing a salary because the salary is drawn over time, and the reduction of expenses is not the same as an immediate cash injection. One commenter recommended that subordinated debt of non-owner parties be allowed the same consideration as owner subordinated debt. This comment was not adopted because debt is a liability of the business and is therefore not equity. Owner subordinated debt is only allowed when cash is injected into the business for the life of the loan. One commenter recommended that the Agency consider removing the tangible balance sheet equity requirement and allowing appraisal surplus, which was not adopted. The tangible balance sheet equity requirement cannot be removed as the Consolidated Farm and Rural Development Act contains a provision requiring that no loan commitment be conditioned upon an applicant investment in excess of 10 percent in the business or industrial enterprise unless special circumstances warrant (the Agency determined that startup businesses and energy projects are special circumstances), and review of the balance sheet is the only way to ascertain an applicant's investment in the business. Three commenters suggested removing the tangible balance sheet equity requirement and replacing it with a well-established lending industry metric, such as a leverage or debt-to-worth ratio. These comments were accepted, as a debt-to-worth ratio requirement is already specifically in the rule. Tangible balance sheet equity is the same as a debt-to-worth ratio, simply expressed as a percentage. Three commenters suggested allowing “off balance sheet” items, such as fully subordinated owner debt, stand-by debt, and equity in commonly owned real estate. Aside from fully subordinated owner debt that is already allowed, debt, stand-by or otherwise, is classified as a liability and is not equity. Therefore, this comment is not being accepted. Appraisal surplus is not allowed because it is the asset's book value that is reflected on the balance sheet. Furthermore, appraisals fluctuate widely, and an asset's book value is a more conservative and reliable approach to valuing an asset for equity purposes. Five commenters suggested adding back depreciation. These suggestions were not adopted. As financial statements must be prepared in line with GAAP standards and depreciation is a GAAP concept, it is the asset's depreciated value that is considered in the tangible balance sheet equity calculation. If a business has depreciated its assets in accordance with GAAP for tax purposes, it cannot add that depreciation back in for purposes of meeting the tangible balance sheet equity requirement. One commenter suggested allowing energy projects to meet the equity requirement at issuance of the Loan Note Guarantee, which was not adopted. The practice of allowing loans to close not having met the equity requirement would complicate administration of the program and tie up guarantee authority for projects that otherwise meet the equity requirement. One commenter suggested requiring an independent accountant to prepare the loan closing balance sheet. This comment was not adopted because it would be overly burdensome to require the balance sheet, on which the lender's certification is based, to be prepared by an independent accountant. Four commenters suggested removing the requirement for the loan closing balance sheet to be prepared by an accountant. These comments were adopted. Since it is the lender that is required to make the certification, it would be up to the lender whether or not to require an accountant to prepare the loan closing balance sheet. Two commenters suggested the timing of the tangible balance sheet equity requirement be at issuance of the Loan Note Guarantee versus loan closing. These comments were not adopted because the regulation has always required the Loan Note Guarantee to be issued coincident with or immediately after loan closing, and the regulation has always required the lender's loan agreement to contain all of the requirements of the Conditional Commitment (the tangible balance sheet equity requirement being one of those requirements). However, the Agency was finding that loans were being closed without having met the equity requirement and, in some cases, loans were closed with the hopes that retained earnings would increase at some point in the future to meet the equity requirement. This practice was tying up guarantee authority for projects that met the equity requirement. As a result of these findings, the regulation was changed in 2006 as a corrective action to clarify that equity was to be met at loan closing. Four comments were received with regard to the requirement for real estate holding companies and operating companies to be co-borrowers. These comments were taken into consideration, and the Agency added the ability for this requirement to be waived when the Agency determines that adequate justification exists. Two commenters suggested that the requirement for co-borrowers that are independent operations to both meet the equity requirement individually be removed. These comments were not adopted to prevent situations where a company unrelated to the project is made a co-borrower to compensate for the “borrower” not meeting the equity requirement, which effectively is a circumvention of the regulation. One commenter suggested that GAAP apply to sole proprietorships, which was not adopted because very few B&I loans are made to sole proprietors, and personal financial statements do not typically account for depreciation. One commenter recommended that the rule retain the ability for the Administrator to reduce the borrower's equity requirement, which is accepted as the regulation continues to provide the Administrator discretion to reduce the equity requirement. One commenter suggested adding the word “all” to the requirement for financial statements that meet or exceed industry standards when requesting a reduction in the equity requirement, which was adopted.
Nine comments were received on the personal and corporate guarantee section. One commenter suggested adding a provision where guarantees are not required from owners who are legally prohibited from providing guarantees, which was adopted. One commenter suggested adding the words “for existing businesses” to the guarantee exception language, which was also adopted because, in practice, only an existing business would be able to demonstrate cash flow and profitability. Two commenters suggested adding the exception language back into the rule. These comments were accepted. The exception language still exists but was simply moved to another paragraph. Five commenters suggested removing the ability for the Agency to obtain guarantees from persons whose ownership interest in the borrower is held indirectly through intermediate entities. These comments were not adopted because often times, borrowers are owned by shell companies, whose guarantees are typically worth little. The Agency needs to have the ability to obtain guarantees where the financial strength lies, which is typically the principal(s) of the business, who may be layers up the ownership chain.
Ten comments were received on the financial statement section. One commenter suggested adding “Except for audited financial statements required by § 4279.71 of this chapter, the lender will determine the type and frequency . . .,” which was adopted. Two commenters suggested increasing the threshold where the Agency may require audited financial statements from $3 million to $10 million, which were also adopted. One commenter suggested requiring an independent accountant to prepare the annual financial statements. This comment was not adopted because it would be overly burdensome to require annual financial statements to be prepared by an independent accountant. Six commenters recommended language be added to allow for the approval of the loan with the requirement for audited financial statements to be provided in subsequent years, as opposed to requiring audited financial statements at the onset of the loan. These comments were not adopted as the lender already has the ability to require future audited financial statements if they wish, and it is not necessary to specifically state they have this ability in the rule.
Eight comments were received on the appraisal section. One commenter suggested adding a requirement for lenders to follow their primary regulator's policies relating to appraisals and evaluations when collateral values are under the $250,000 threshold for requiring an appraisal, which was adopted. Six commenters suggested adding “unless it is a well-established industry norm to use business valuations in calculating the value of the enterprise and is in accordance with the lender's loan policies” to the statement that values attributed to business valuations or as a going concern are not allowed. Although these comments were not adopted, the Agency changed the regulatory text to require that values of both tangible and intangible assets be reported individually/separately in the appraisal. Business valuations or going concern values will be deducted from the reconciled fair market value of the hard assets for purposes of calculating collateral coverage. One commenter recommended requiring a Certified Appraisal by a Certified Machinery and Equipment Appraiser, which was not adopted because this is not a normal banking practice.
Twelve comments were received with regard to feasibility studies. One commenter suggested not requiring a feasibility study from an existing business expanding its facility if the existing facility is sufficient to service the new debt, which was adopted. One commenter recommended removing the requirement for a feasibility study for all biofuels projects, regardless of whether they are new or existing, which was also adopted. Since feasibility studies are required for new businesses and may be required for existing businesses where there is a significant change in operations, this requirement has been determined not to be necessary. Two commenters recommended that feasibility studies conducted with funding from other programs, such as the Value-Added Producer Grants, the Rural Business Enterprise Grants, and the Rural Cooperative Development Grants, be accepted as fulfilling the feasibility study requirement. These commenters further recommended that the Agency work with lenders and borrowers to secure alternative grant funding for development of feasibility studies. These comments were accepted as the Agency currently accepts feasibility studies funded with other programs as long as they meet the requirements of § 4279.150. While the borrower is ultimately responsible for securing any grant funding, the Agency does assist in securing grant funding for development of feasibility studies. Three commenters recommended that feasibility studies not be required for all new businesses. These comments were not adopted because current Agency policy is to obtain feasibility studies for startups/new businesses or when there is a significant change in operations in an existing business, and this provision simply codifies current Agency policy. Five commenters recommended defining “significantly.” These comments were not adopted because “significant” and “significantly” are used many times throughout the rule, and there may be unintended consequences of defining such a generic term. The Agency will rely on the commonly used definition of the term, meaning a noticeably or measurably large amount.
Thirty-nine comments were received on the application section. One commenter suggested requiring additional information in order to complete the priority score sheet. This comment was accepted, and, although it is already covered by § 4279.161(b)(19), text was added to clarify any information needed to score the project will be required. Nine comments were received supporting the reduction of historical financial information for any parent, affiliates, or subsidiaries from 3 years to current financial statements only. One commenter suggested adding that projections must be prepared in line with GAAP standards for clarification, which was adopted. Three commenters recommended that the Agency not require a loan agreement or ratios in the loan agreement. These comments were not adopted because the loan agreement needs to contain basic loan covenants, including ratios, and the Agency should review the draft loan agreement to ensure it complies with the regulation. At the time of issuance of the Loan Note Guarantee is too far along in the process to learn there may be problems with the loan agreement because, typically, the loan agreement has been executed by the lender and borrower by the time the lender requests issuance of the Loan Note Guarantee. One commenter recommended revising the citation for intergovernmental consultation comments to 2 CFR part 415, subpart C, which was adopted. One commenter suggested that the technical review of the appraisal, which is required by § 4279.144(a), be added to the appraisal requirement in the application section, which was adopted. Seven commenters recommended that the Agency continue to issue Conditional Commitments subject to receipt of satisfactory appraisals. These comments were accepted, although the ability to issue Conditional Commitments subject to receipt of satisfactory appraisals remains. Four commenters suggested removing “at the Agency's discretion” with regard to not requiring a business plan when loan proceeds are used exclusively for debt refinancing and fees in order to remove the burden of decisionmaking from local officials, which may be arbitrary in nature. Six commenters supported doing away with business plans when debt is being refinanced. Two commenters recommended the Agency conduct outreach to make lenders and borrowers aware of the abbreviated application option, and one further recommended that the Agency develop guidelines for common factors that constitute a “significant risk.” The Agency agrees with these comments and will adopt administrative text to address the concern. Three commenters support reducing the amount of documents required for the short application form/process, and one commenter suggested removing the short application form/process in its entirety, which was not adopted because the Consolidated Farm and Rural Development Act requires a simplified application form/process.
Thirteen comments were received on priority scoring. Four commenters support the changes in priority scoring. One commenter recommended deleting the requirement for lenders to consider Agency priorities when choosing projects for guarantee. This comment was not adopted because lenders are not discouraged from submitting applications that would receive a low priority score. They are simply required to consider priorities for scoring, especially the categories they have control over, such as the interest rate category. This requirement is in the current rule. With regard to the categories for loan-to-job ratio, one commenter suggested the Agency add language to explain how jobs should be counted and incorporate a verification component to the scoring criteria. This comment does not need to be addressed because this point category was deleted. Five commenters suggested that the Farmer Mac II rate not be utilized for priority scoring. These comments were accepted, and this point category was deleted as well. The proposal was in response to a concern that it was difficult for fixed rate loans to qualify for priority points using the Wall Street Journal Prime +1 and +1.5 equivalents. One commenter suggested that “an agricultural resource value-added product” be removed in the scoring section because the definition for this term was incorporated into “natural resource value added product.” This comment was adopted. One commenter suggested removing reference to the Work Opportunity Tax Credit Program because program authority expired December 31, 2013, and has not been extended to date. This comment was adopted as well.
Ten comments were received on planning and performance development. Two commenters suggested that “or similar document issued by the relevant building jurisdiction” be included with the requirement for a Notice of Completion, which were adopted. One commenter recommended that the Agency clarify that a project architect or engineer may be a person with demonstrated experience to confirm that the budget is adequate for the planned development, which was also adopted. Five commenters recommended the Agency allow independent monitoring by a reputed nationwide firm during construction as an alternative to a performance bond as long as the contract guarantees project construction. These comments were taken into consideration, and the Agency will allow contracts with independent disbursement and monitoring firms where project construction and completion are guaranteed. One commenter recommended breaking a sentence into two sentences, which was not adopted because a third option was added due to other comments, and restructure of this sentence makes it clear there are several alternatives. One commenter recommended that § 4279.167(c) be revised to remove reference to the Americans with Disabilities Act and insert reference to the Architectural Barriers Act Accessibility Standard, which was adopted.
One commenter recommended that a timeframe be established for responding to preapplications, and five commenters recommended that that timeframe be 30 days. These comments were not adopted in this rule because the Instruction contains an entire preapplication processing section; however, administrative text was added to the preapplication processing section instructing staff to respond to preapplications within 30 days.
One commenter recommended that a transfer of lender request be received in writing from the current lender, the proposed lender, and the borrower, which aligns with the substitution of lender requirements in the servicing regulation, and one commenter recommended deleting a semicolon. Both of these suggestions were adopted.
Three comments were received on the conditions precedent to issuance of the guarantee section. One commenter again recommended that the regulation specify that the loan closing balance sheet must be prepared by an independent accountant, which was not adopted because it would be overly burdensome to require the balance sheet, on which the lender's certification is based, to be prepared by an independent accountant. One commenter suggested that a form be developed for the lender's certification, which was not adopted because simply signing a form would not provide the Agency with the same level of comfort as when a lender has to actually prepare the certification on its own letterhead. One commenter suggested adding a definition for “accountant” and emphasized that if the lender has to make the certification, it should be up to the lender who prepares the balance sheet. Part of this recommendation was adopted. The Agency has decided not to require the loan closing balance sheet to be prepared by an accountant. Since the lender is required to make the certification that tangible balance sheet equity was met, it would be up to the lender whether or not to require an accountant to prepare the balance sheet.
One commenter recommended a field be created in the USDA Lender Interactive Network Connection (LINC) to prompt the lender to complete the loan classification. The Agency agrees with this recommendation and will adopt it administratively. One commenter recommended that § 4287.107(b) include the lender's ability to enter the loan classification in LINC if they remit the guarantee fee via LINC, which was also adopted. Five commenters support requiring the lender to establish the loan classification at loan closing. Five commenters support allowing the flexibility to have teleconferences to complete the Agency and lender annual lender conferences. One commenter recommended that the Agency only allow annual lender conferences to be held via teleconference if the lender has supplied all required servicing reports to the Agency. This comment was not adopted because face-to-face visits can be costly and allowing annual conferences to be held by teleconference not only reduces the cost to the lender, it reduces the cost of administering the program for the Agency. One commenter recommended clarification of a “reasonable attempt to obtain financial statements.” This was not adopted because it is not necessary and allows for flexibility in determining what is reasonable. Reasonable attempts could be documented telephone calls or written letters to the lender.
Nine commenters support increasing the requirement for an appraisal from $100,000 to $250,000. One commenter recommended allowing subordination of lien positions when it would “not adversely affect the potential for collection of the B&I loan through repayment or liquidation” instead of stating when it would be in “the best financial interest of the Agency.” This comment was adopted. One commenter recommended changing the word “loan” to “collateral” in the lien priorities paragraph, which was also adopted. Five commenters recommended that subordinations to lines of credit be extended from 1 year to 3 years. These recommendations were not adopted because it would increase the program's subsidy cost. The proposed rule initially proposed subordinations to lines of credit for up to 3 years but was reduced to 1 year during the clearance process due to the increase.
Sixteen comments were received on the transfer and assumption section. One commenter recommended clarifying whether the value of the collateral being transferred in a transfer and assumption situation is to be calculated on a discounted or non-discounted basis. This comment was adopted, and the words “fair market” will be added to clarify that the value of the collateral is the market value, not the discounted market value. One commenter suggested revising § 4287.134(g) to add “unless a guarantor is being released from liability in accordance with paragraph (c) of the section.” This comment was adopted. Five commenters support clarification that no new notes can be issued upon an assumption. Eight commenters stated the Agency should not charge a transfer fee for a transfer and assumption, and one commenter suggested the fee be lower. These comments were adopted, and the Agency will not charge a transfer fee for a transfer and assumption.
One commenter suggested that § 4287.135(d) be revised to strike “or a lender has been merged with or acquired by another lender” and § 4287.135(b) be revised to add “merged with or” to the second sentence of the paragraph. This comment was adopted.
One commenter suggested adding a statement indicating the Agency may not look as favorably on a request for deferral when a lender's unguaranteed loans are also not deferred. This comment was taken into consideration, and the Agency has decided to require the lender's unguaranteed loan(s) and any stockholder loans to also be deferred or put under a moratorium during the period of deferment or moratorium of the guaranteed loan.
Two commenters indicated that paying only 90 days of interest is not conducive for the bank to work with the borrower and recommended a longer period of time, and six commenters indicated that the Agency should modify the changes to the accrual of interest to better account for expenses and uncertainty that occur during a loan default. These comments were taken into consideration, but the Agency has decided to limit interest accrual to the lender to 90 days from the most recent delinquency effective date and to the holder the greater of: 90 Days from the most recent delinquency effective date as reported by the lender or 30 days from the date of an interest termination letter. One commenter suggested clarifying whether interest on a protective advance that is paid 95 days after the most recent delinquency effective date would be covered. This comment was not adopted because the regulation is clear that the guarantee will not cover interest on the protective advance accruing after 90 days from the most recent delinquency effective date. The Agency is reducing the cost of administering the program, and this is one step to achieve that objective. One commenter suggested adding “not to exceed every 60 days” to the requirement that the lender periodically report to the Agency on the progress of liquidation. This comment was adopted. One commenter recommended a definition of “potential liquidation value” and suggested that the Agency include those things that would impact the fair market value versus potential liquidation value. This comment was not adopted because a definition of potential liquidation value is not necessary, and it is the appraiser's responsibility to establish what would impact fair market value. One commenter suggested clarifying whether interest accrual stops after 90 days to the Agency when the Agency becomes the holder. This comment was adopted.
One commenter suggested that the determination of loss and payment section include a time limit that the lender has to sell collateral it has acquired as a result of liquidation, such as 24 months for real estate. After that time period, the Agency could reduce the loss claim by 25 percent every 6 months, so that after 48 months, the lender would be unable to collect anything further under the Loan Note Guarantee. This comment was not adopted because it was too restrictive. No other Federal agency is imposing such restrictions on their lenders, and this proposal may harm future lender participation in the program because the lending community may view this as punitive. One commenter indicated there were contradictory statements with regard to how attorney/legal fees will be handled in liquidation and bankruptcy scenarios. This comment was adopted, and the rule was rewritten to provide clarification that attorney/legal fees are liquidation expenses and that the lender and the Agency will share in those expenses equally. Fifteen commenters suggested that liquidation expenses, litigation expenses, and bankruptcy expenses be shared on a pro rata basis versus being shared equally. These comments were not adopted because the Agency is reducing the cost of administering the program as part of this rulemaking, and sharing the costs with the lender equally achieves that objective. Additionally, these expenses are deducted from collateral sale proceeds prior to allocating pro rata shares of the sale proceeds. To share in the expenses on a pro rata basis would likely lead to errors in calculating estimated and final reports of loss.
Several general comments were received. One commenter pointed out that the regulation and current forms use the terms “reasonably prudent,” “prudent,” and “reasonable and prudent” and recommended that “reasonable and prudent,” be utilized throughout the regulation and accompanying forms. This comment was taken into consideration, and changes were made for consistency. However, the Agency chose to use “reasonably prudent” in a majority of the occurrences. One commenter recommended a more detailed explanation of the benefit of extending loan guarantees for employees to buy-out selling owners, who may remain for a transitional period to teach the employees how to run the firm, which was adopted administratively. One commenter suggested reviewing forms, giving them consistent numbers, and removing reference to the Section 9006 program on the forms. This comment is outside the scope of this rule and will be addressed administratively. One commenter recommended a handbook to promote consistency among the State Offices. This comment is outside the scope of this rule and will be addressed administratively. One commenter recommended the Agency not use a fiscal and transfer agent. The proposed rule published in the Federal Register on September 15, 2014, did not address use of a fiscal and transfer agent and, as such, is outside the scope of this rulemaking. One commenter recommended the Agency adopt a national loan registry system to help verify the validity of guaranteed loans. This comment was not adopted as there are privacy and funding issues with regard to a national loan registry system. One commenter recommended that Agency personnel be better utilized to avoid “bottlenecks” in the processing of loans. This comment is outside the scope of this rule and will be addressed administratively. Lastly, there were two comments made with regard to dividing appropriated funding into subsidized and non-subsidized segments. While this will not be contemplated with this rulemaking, it remains a topic of discussion.

List of Subjects for 7 CFR Parts 4279 and 4287
Loan programs—Business and industry, Direct loan programs, Economic development, Energy, Energy efficiency improvements, Grant programs, Guaranteed loan programs, Renewable energy systems, Rural areas, and Rural development assistance.
For the reasons set forth in the preamble, parts 4279 and 4287 of title 7 of the Code of Federal Regulations are amended as follows:

PART 4279—GUARANTEED LOANMAKING
1. The authority citation for part 4279 is revised to read as follows:

Authority:
5 U.S.C. 301; and 7 U.S.C. 1989.
2. Revise Subpart A to read as follows:

Subpart A—General
Sec.
4279.1
Introduction.
4279.2
Definitions and abbreviations.
4279.3-4279.14
[Reserved]
4279.15
Exception authority.
4279.16
Appeals.
4279.17-4279.28
[Reserved]
4279.29
Eligible lenders.
4279.30
Lenders' functions and responsibilities.
4279.31-4279.43
[Reserved]
4279.44
Access to records.
4279.45-4279.58
[Reserved]
4279.59
Environmental requirements.
4279.60
Civil rights impact analysis.
4279.61
Equal Credit Opportunity Act.
4279.62-4279.70
[Reserved]
4279.71
Public bodies and nonprofit corporations.
4279.72
Conditions of guarantee.
4279.73-4279.74
[Reserved]
4279.75
Sale or assignment of guaranteed loan.
4279.76
[Reserved]
4279.77
Minimum retention.
4279.78
Repurchase from holder.
4279.79-4279.83
[Reserved]
4279.84
Replacement of document.
4279.85-4279.99
[Reserved]
4279.100
OMB control number.

Subpart A—General
§ 4279.1
Introduction.
(a) This subpart contains general regulations for making and servicing Business and Industry (B&I) loans guaranteed by the Agency and applies to lenders, holders, borrowers, and other parties involved in making, guaranteeing, holding, servicing, or liquidating such loans. This subpart is supplemented by subpart B of this part, which contains loan processing regulations, and subpart B of part 4287 of this chapter, which contains loan servicing regulations.
(b) The lender is responsible for ascertaining that all requirements for making, securing, servicing, and collecting the loan are complied with.
(c) Whether specifically stated or not, whenever Agency approval is required, it must be in writing. Copies of all forms and regulations referenced in this subpart may be obtained from any Agency office and from the USDA Rural Development Web site at http://www.rd.usda.gov/publications. Whenever a form is designated in this subpart, it is initially capitalized and its reference includes predecessor and successor forms, if applicable.
§ 4279.2
Definitions and abbreviations.
(a) Definitions. The following definitions apply to this subpart:
Administrator. The Administrator of Rural Business-Cooperative Service within the Rural Development mission area of the U.S. Department of Agriculture.
Affiliate. An entity that is related to another entity by owning shares or having an interest in the entity, by common ownership, or by any means of control.
Agency. The Rural Business-Cooperative Service or successor Agency assigned by the Secretary of Agriculture to administer the B&I Guaranteed Loan Program. References to the National or State Office should be read as prefaced by “Agency” or “Rural Development” as applicable.
Agricultural production. The breeding, raising, feeding, or housing of livestock for fiber or food for human consumption and the cultivation, growing, or harvesting of crops.
Annual renewal fee. The annual renewal fee is a fee that is paid once a year by the lender and is required to maintain the enforceability of the Loan Note Guarantee.
Appraisal surplus. The difference between the fair market value of an asset and its depreciated book value when the fair market value is higher.
Arm's-length transaction. A transaction between ready, willing, and able disinterested parties that are not affiliated with or related to each other and have no security, monetary, or stockholder interest in each other.
Assignment Guarantee Agreement. Form RD 4279-6, “Assignment Guarantee Agreement,” is the signed agreement among the Agency, the lender, and the holder containing the terms and conditions of an assignment of a guaranteed portion of a loan, using the single note system.
Bankruptcy Code. The provisions of title 11 of the United States Code or any successor statute.
Biofuel. A fuel derived from Renewable Biomass.
Bond. A form of debt security in which the authorized issuer (borrower) owes the bond holder (lender) a debt and is obligated to repay the principal and interest (coupon) at a later date(s) (maturity). An explanation of the type of bond and other bond stipulations must be attached to the bond issuance.
Borrower. The person that borrows, or seeks to borrow, money from the lender, including any party liable for the loan except for guarantors.
Certificate of Incumbency and Signature. Form RD 4279-7, “Certificate of Incumbency and Signature,” is used to validate authenticity of Agency representatives' signatures on Forms RD 4279-4, 4279-5, and 4279-6.
Collateral. The asset(s) pledged by the borrower to secure the loan.
Commercially available. A system that has a proven operating history for at least 1 year specific to the proposed application. Such a system is based on established design and installation procedures and practices. Professional service providers, trades, large construction equipment providers, and labor are familiar with installation procedures and practices. Proprietary and the balance of system equipment and spare parts are readily available, and service is readily available to properly maintain and operate the system. An established warranty exists for major parts and labor. If the system is currently commercially available only outside of the United States, authoritative evidence of the foreign operating history, performance, and reliability is required in order to address the proven operating history.
Conditional Commitment. Form RD 4279-3, “Conditional Commitment,” is the Agency's notice to the lender that the loan guarantee it has requested is approved subject to the completion of all conditions and requirements set forth by the Agency and outlined in the attachment to the Conditional Commitment.
Conflict of interest. A situation in which a person has competing personal, professional, or financial interests that prevents the person from acting impartially.
Cooperative organization. An entity that is legally chartered as a cooperative or an entity that is not legally chartered as a cooperative but is owned and operated for the benefit of its members, with returns of residual earnings paid to such members on the basis of patronage.
Debt Collection Improvement Act. The Debt Collection Improvement Act of 1996, 31 U.S.C. 3701 et seq. requires that any monies that are payable or may become payable from the United States under contracts and other written agreements to any person not an agency or subdivision of a State or local government may be subject to certain collection options, such as administrative offset, for a delinquent debt the person owes to the United States.
Default. The condition that exists when a borrower is not in compliance with the promissory note, the loan agreement, or other documents relating to the loan. Default could be a monetary or non-monetary default.
Deficiency judgment. A monetary judgment rendered by a court of competent jurisdiction after foreclosure and liquidation of all collateral securing the loan.
Delinquency. A loan for which a scheduled loan payment is more than 30 days past due and cannot be cured within 30 days.
Energy projects. Commercially available projects that generate energy or power or projects that produce biofuel. Projects that have energy outputs that are a by-product of operations or that the Agency otherwise determines is not an energy project are not subject to the increased equity requirement for energy projects required by § 4279.131(d)(1).
Existing business. A business that has been in operation for at least 1 full year. Mergers or changes in the business name or legal type of entity of a business that has been in operation for at least 1 full year are considered to be existing businesses as long as there is not a significant change in operations. Newly-formed entities that are buying existing businesses will be considered an existing business as long as the business being bought remains in operation and there is no significant change in operations.
Existing lender debt. A debt owed by a borrower to the same lender that is applying for or has received the Agency guarantee.
Fair market value. The price that could reasonably be expected for an asset in an arm's-length transaction between a willing buyer and a willing seller under ordinary economic and business conditions.
Future recovery. Funds collected by the lender after a final loss claim is processed.
High impact business development investment. A business that scores at least 25 points under § 4279.166(b)(4).
High-priority project. A project that scores more than 50 percent of the priority points available under § 4279.166(b)(1) through (5).
Holder. A person, other than the lender, who owns all or part of the guaranteed portion of the loan with no servicing responsibilities. When the single note option is used and the lender assigns a part of the guaranteed note to an assignee, the assignee becomes a holder only when the Agency receives notice and the transaction is completed through the use of the Assignment Guarantee Agreement.
Immediate family. Individuals who live in the same household or who are closely related by blood, marriage, or adoption, such as a spouse, domestic partner, parent, child, sibling, aunt, uncle, grandparent, grandchild, niece, nephew, or cousin.
In-house expenses. Expenses associated with activities that are routinely the responsibility of a lender's internal staff or its agents. In-house expenses include, but are not limited to, employees' salaries, staff lawyers, travel, and overhead.
Interest. A fee paid by a borrower to the lender as a form of compensation for the use of money. When money is borrowed, interest is paid as a fee over a certain period of time (typically months or years) to the lender as a percentage of the principal amount owed. The term interest does not include default or penalty interest or late payment fees or charges.
Interim financing. A temporary or short-term loan made with the clear intent when the loan is made that it will be repaid through another loan that provides permanent financing. Interim financing is frequently used to pay construction and other costs associated with a planned project, with permanent financing to be obtained after project completion.
Lender. The eligible lender approved by the Agency to make, service, and collect the Agency guaranteed loan that is subject to this subpart. Agency approval of the lender will be evidenced by an outstanding Form RD 4279-4, “Lender's Agreement,” between the Agency and the lender.
Lender's Agreement. Form RD 4279-4, “Lender's Agreement,” or predecessor form, between the Agency and the lender setting forth the lender's loan responsibilities.
Liquidation expenses. Costs directly associated with the liquidation of collateral, including preparing collateral for sale ( e.g., repairs and transport) and conducting the sale ( e.g., advertising, public notices, auctioneer expenses, and foreclosure fees). Liquidation expenses do not include in-house expenses. Legal/attorney fees are considered liquidation expenses provided that the fees are reasonable, as determined by the Agency, and cover legal issues pertaining to the liquidation that could not be properly handled by the lender and its in-house counsel.
Loan agreement. The agreement between the borrower and lender containing the terms and conditions of the loan and the responsibilities of the borrower and lender.
Loan classification. The process by which loans are examined and categorized by degree of potential loss in the event of default.
Loan Note Guarantee. Form RD 4279-5, “Loan Note Guarantee,” issued and executed by the Agency, containing the terms and conditions of the guarantee.
Loan packager. A person, other than the applicant borrower or lender, that prepares a loan application package.
Loan service provider. A person, other than the lender of record, that provides loan servicing activities to the lender.
Loan-to-discounted value. The ratio of the dollar amount of a loan to the discounted dollar value of the collateral pledged as security for the loan.
Loan-to-value. The ratio of the dollar amount of a loan to the dollar value of the collateral pledged as security for the loan.
Local government. A county, municipality, town, township, village, or other unit of general government, including tribal governments, below the State level.
Material adverse change. Any change in circumstance associated with a guaranteed loan, including the borrower's financial condition or collateral, that, individually or in the aggregate, has jeopardized, or could be reasonably expected to jeopardize, loan performance.
Natural resource value-added product. Any naturally occurring resource, including agricultural resources, that is processed to add value or to generate renewable energy from a natural resource.
Negligent loan origination. The failure of a lender to perform those services that a reasonably prudent lender would perform in originating its own portfolio of loans that are not guaranteed. The term includes the concepts of failure to act, not acting in a timely manner, or acting in a manner contrary to the manner in which a reasonably prudent lender would act.
Negligent loan servicing. The failure of a lender to perform those services that a reasonably prudent lender would perform in servicing (including liquidation of) its own portfolio of loans that are not guaranteed. The term includes the concepts of failure to act, not acting in a timely manner, or acting in a manner contrary to the manner in which a reasonably prudent lender would act.
New business. A startup or otherwise new business that has been in operation for less than 1 full year. New businesses include newly-formed entities leasing space or building ground-up facilities, even if the owners of the new or startup business own affiliated businesses doing the same kind of business.
Parity. A lien position whereby two or more lenders share a security interest of equal priority in collateral. In the event of default, each lender will be affected on an equal basis.
Participation. Sale of an interest in a loan by the lead lender to one or more participating lenders wherein the lead lender retains the note, collateral securing the note, and all responsibility for managing and servicing the loan. Participants are dependent upon the lead lender for protection of their interests in the loan. The relationship is typically formalized by a participation agreement. The participants and the borrower have no rights or obligations to one another.
Person. An individual or entity.
Poverty. A community or area (including a county, city, or equivalent such as parish, borough, municipio, or census designated place) where at least 20 percent of the population have income below the poverty line.
Pro rata. On a proportional basis.
Promissory note. Evidence of debt with stipulated repayment terms. “Note” or “promissory note” shall also be construed to include “Bond” or other evidence of debt, where appropriate.
Protective advances. Advances made by the lender for the purpose of preserving and protecting the collateral where the debtor has failed to, and will not or cannot, meet its obligations to protect or preserve collateral. Protective advances include, but are not limited to, advances affecting the collateral made for property taxes, rent, hazard and flood insurance premiums, and annual assessments. Legal/attorney fees are not a protective advance.
Public body. A municipality, county, or other political subdivision of a State; a special purpose district; an Indian tribe on a Federal or State reservation or other federally-recognized Indian tribe; or an organization controlled by any of the above.
Renewable biomass. (1) Materials, pre-commercial thinnings, or invasive species from National Forest System land or public lands (as defined in section 103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1702)) that:
(i) Are by-products of preventive treatments that are removed to reduce hazardous fuels; to reduce or contain disease or insect infestation; or to restore ecosystem health;
(ii) Would not otherwise be used for higher-value products; and
(iii) Are harvested in accordance with applicable law and land management plans and the requirements for old-growth maintenance, restoration, and management direction of paragraphs (2), (3), and (4) of subsection (e) of section 102 of the Healthy Forests Restoration Act of 2003 (16 U.S.C. 6512) and large-tree retention of subsection (f) of that section; or
(2) Any organic matter that is available on a renewable or recurring basis from non-Federal land or land belonging to an Indian or Indian Tribe that is held in trust by the United States or subject to a restriction against alienation imposed by the United States, including:
(i) Renewable plant material, including feed grains; other agricultural commodities; other plants and trees; and algae; and
(ii) Waste material, including crop residue; other vegetative waste material (including wood waste and wood residues); animal waste and by-products (including fats, oils, greases, and manure); and food and yard waste.
Report of loss. Form RD 449-30, “Guaranteed Loan Report of Loss,” used by lenders when reporting a financial loss under an Agency guarantee.
Rural Development. The mission area of USDA that is comprised of the Rural Business-Cooperative Service, the Rural Housing Service, and the Rural Utilities Service and is under the policy direction and operational oversight of the Under Secretary for Rural Development.
Spreadsheet. A table containing data from a series of financial statements of a business over a period of time. A financial statement analysis normally contains spreadsheets for balance sheet and income statement items and includes a cash flow analysis and commonly used ratios. The spreadsheets enable a reviewer to easily scan the data, spot trends, and make comparisons.
State. Any of the 50 States of the United States, the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, the Commonwealth of the Northern Mariana Islands, the Republic of Palau, the Federated States of Micronesia, and the Republic of the Marshall Islands.
Subordination. An agreement among the lender, borrower, and Agency whereby lien priorities on certain assets pledged to secure payment of the guaranteed loan will be reduced to a position junior to, or on parity with, the lien position of another loan.
Tangible balance sheet equity. Tangible equity divided by tangible assets. Formula: ((Assets—intangible assets)—liabilities)/(Assets—intangible assets) or (Equity—intangible assets)/(Assets—intangible assets).
Transfer and assumption. The conveyance by a borrower to an assuming borrower of the assets, collateral, and liabilities of the loan in return for the assuming borrower's binding promise to pay the outstanding debt.
USDA Lender Interactive Network Connection (LINC). The portal Web site currently at https://usdalinc.sc.egov.usda.gov/ used by lenders to update loan data in the Agency's Guaranteed Loan System. Current LINC capabilities include loan closing and status reporting.
Veteran. For the purposes of assigning priority points, a veteran is a person who is a veteran of any war, as defined in title 38 U.S.C. 101(12).
Working capital. Current assets available to support a business' operations and growth. Working capital is calculated as current assets less current liabilities.
(b) Abbreviations. The following abbreviations apply to this subpart:
B&I—Business and Industry
CFR—Code of Federal Regulations
DCIA—Debt Collection Improvement Act
FDIC—Federal Deposit Insurance Corporation
FSA—Farm Service Agency
GAAP—Generally Accepted Accounting Principles of the United States
LINC—USDA Lender Interactive Network Connection
NAD—National Appeals Division
OMB—Office of Management and Budget
REAP—Rural Energy for America Program
U.S.—United States of America
USDA—U.S. Department of Agriculture
(c) Accounting terms. Accounting terms not otherwise defined in this part shall have the definition ascribed to them under GAAP.
§§ 4279.3-4279.14
[Reserved]
§ 4279.15
Exception authority.
The Administrator may, on a case-by-case basis, grant an exception to any requirement or provision of this subpart provided that such an exception is in the best financial interests of the Federal government. Exercise of this authority cannot be in conflict with applicable law.
§ 4279.16
Appeals.
Applicants, borrowers, lenders, and holders have appeal or review rights for Agency decisions made under this subpart, subpart B of this part, or subpart B of part 4287 of this chapter. Programmatic decisions based on clear and objective statutory or regulatory requirements are not appealable; however, such decisions are reviewable for appealability by the National Appeals Division (NAD). The borrower, lender, and holder can appeal any Agency decision that directly and adversely impacts them. For an adverse decision that impacts the borrower, the lender and borrower must jointly execute a written request for appeal for an alleged adverse decision made by the Agency. An adverse decision that only impacts the lender may be appealed by the lender only. An adverse decision that only impacts the holder may be appealed by the holder only. A decision by a lender adverse to the interest of the borrower is not a decision by the Agency, whether or not concurred in by the Agency. Appeals will be conducted by USDA NAD and will be handled in accordance with 7 CFR part 11.
§§ 4279.17-4279.28
[Reserved]
§ 4279.29
Eligible lenders.
An eligible lender must be domiciled in a State as defined in § 4279.2 or the District of Columbia and must not be debarred or suspended by the Federal government. If the lender is under a cease and desist order, or similar constraint, from a Federal or State agency, the lender must inform the Agency. The Agency will evaluate the lender's eligibility on a case-by-case basis, given the risk of loss posed by the cease and desist order. The Agency will only approve loan guarantees for lenders with adequate capital to fund and cover potential liquidation expenses for guaranteed loans it proposes to make and adequate experience and expertise to make, secure, service, and collect B&I loans. The lender must provide documentation as to its capital and experience in commercial lending. The lender and the Agency will execute a Lender's Agreement for each lender approved to participate in the program. If a valid Lender's Agreement already exists, it is not necessary to execute a new Lender's Agreement with each loan guarantee; however, a new Lender's Agreement must be executed with any existing lenders making new loans on or after August 2, 2016. The Agency may revoke a lender's eligible status at any time for cause, including those examples cited in § 4279.29(c).
(a) Regulated lenders. A regulated lender is any Federal or State chartered bank, Farm Credit Bank, other Farm Credit System institution with direct lending authority, Bank for Cooperatives, Savings and Loan Association, Savings Bank, or mortgage company that is part of a bank-holding company. These entities must be subject to credit examination and supervision by either an agency of the United States or a State. Eligible lenders may also include the National Rural Utilities Cooperative Finance Corporation and credit unions provided that they are subject to credit examination and supervision by either the National Credit Union Administration or a State agency.
(b) Non-regulated lenders. The Agency may consider an applicant lender that does not meet the criteria of paragraph (a) of this section for eligibility to become a guaranteed lender for a 3-year period provided that the Agency determines that the applicant lender has the legal authority to operate a lending program and sufficient lending expertise and financial strength to operate a successful lending program. When the applicant lender is a multi-tiered entity, it will be considered in its entirety. Insurance companies (formerly included as traditional lenders) and non-regulated lenders (formerly known as other lenders) previously approved as guaranteed lenders prior to August 2, 2016 must reapply to become an approved non-regulated lender in order to originate new guaranteed loans. However, both insurance companies and non-regulated lenders that have executed a Lender's Agreement must continue to service the guaranteed loans in their portfolios in accordance with that agreement.
(1) In order to become an eligible lender, non-regulated lenders must:
(i) Have been making commercial loans for at least 5 years;
(ii) Have a record of successfully making at least 10 commercial loans annually totaling at least $1 million for each of the last 5 years, with lender's delinquent commercial loan portfolio over this period not exceeding (a) 6 percent of all commercial loans made and (b) 3 percent in commercial loan losses (based on the original principal loan amount);
(iii) Have and maintain tangible balance sheet equity of at least 10 percent of tangible assets and sufficient funds available to disburse the guaranteed loans it proposes to approve within the first 6 months of being approved as a guaranteed lender;
(iv) Have and maintain a line of credit issued by a regulated lender that is acceptable to the Agency;
(v) Agree to establish and maintain an Agency approved loss reserve equal to 3 percent of each B&I loan closed and agree to increase the loss reserve for anticipated losses as required by the Agency;
(vi) Have adequate policies and procedures to ensure that internal credit controls provide adequate loanmaking and servicing guidance; and
(vii) Have undergone a credit examination at its own expense from a recognized independent reviewer acceptable to the Agency. The applicant lender should consult with the Agency prior to receiving an examination to ensure the examiner will be acceptable.
(2) A non-regulated lender that wishes consideration to become a guaranteed lender must submit a request in writing to the Agency. The Agency will notify the prospective lender whether the lender's request for eligibility is approved or rejected. If rejected, the Agency will notify the prospective lender, in writing, of the reasons for the rejection. The lender must include in its written request the following:
(i) An audited financial statement not more than 1 year old that evidences the lender has the required tangible balance sheet equity and the resources to successfully meet its responsibilities;
(ii) A copy of any license, charter, or other evidence of authority to engage in the proposed loanmaking and servicing activities. If licensing by the State is not required, an attorney's opinion stating that licensing is not required and that the entity has the legal authority to engage in the proposed loanmaking and servicing activities must be submitted;
(iii) Information on lending experience, including length of time in the lending business; range and volume of lending and servicing activity, including a list of the industries for which it has provided financing; status of its loan portfolio, including a list of loans in the portfolio with each loan's current loan classification code and delinquency and loss rates as outlined in § 4279.29(b)(1)(ii); experience of management and loan officers; sources of funds for the proposed loans; office location and proposed lending area; an estimate of the number and size of guaranteed loan applications the lender will develop; and proposed rates and fees, including loan origination, loan preparation, and servicing fees;
(iv) A copy of the examination required under paragraph (b)(1)(vii) of this section; and
(v) Documentation as to how the lender will fulfill the requirements of § 4279.30.
(3) Non-regulated lenders must submit audited financial statements to the Agency annually for monitoring purposes.
(4) Renewal of eligible lender status to continue making B&I loans is not automatic. Eligible lender status will lapse 3 years from the date of Agency approval and execution of the Lender's Agreement unless the lender obtains a renewal. A lender whose eligible status has lapsed must continue to service any outstanding loans guaranteed under this part but may not submit requests for new loan guarantees. Lenders whose eligibility has lapsed may file a subsequent request under this subsection. Lenders requesting renewal must complete and execute a new Lender's Agreement, along with a written update of the eligibility criteria required by this section for approval. Lenders requesting renewal must resubmit the information required by paragraph (b)(2) of this section and must address how the lender is complying with each of the required criteria described in paragraph (b)(1) of this section. The written update of the eligibility criteria must also include any change in the persons designated to process and service Agency guaranteed loans or change in the operating methods used in the processing and servicing of loans since the original or last renewal date of eligible lender status. The lender must provide this information to the Agency at least 60 days prior to the expiration of the existing agreement to be assured of a timely renewal.
(c) Revocation of eligible lender status. The Agency may revoke a lender's status at any time for cause. Cause for revoking eligible status includes:
(1) Failure to maintain status as an eligible lender as set forth in § 4279.29 of this subpart;
(2) Knowingly submitting false information when requesting a guarantee or basing a guarantee request on information known to be false or which the lender should have known to be false;
(3) Making a guaranteed loan with deficiencies that may cause losses not to be covered by the Loan Note Guarantee, such as negligent loan origination;
(4) Conviction of the lender or its officers for criminal acts in connection with any loan transaction whether or not the loan was guaranteed by the Agency;
(5) Violation of usury laws in connection with any loan transaction whether or not the loan was guaranteed by the Agency;
(6) Failure to obtain and maintain the required security for any loan guaranteed by the Agency;
(7) Using loan funds guaranteed by the Agency for purposes other than those specifically approved by the Agency in the Conditional Commitment or amendment thereof in accordance with § 4279.173(b);
(8) Violation of any term of the Lender's Agreement;
(9) Failure to correct any Agency-cited deficiency in loan documents in a timely manner;
(10) Failure to submit reports required by the Agency in a timely manner;
(11) Failure to process Agency guaranteed loans as would a reasonably prudent lender;
(12) Failure to provide for adequate construction planning and monitoring in connection with any loan to ensure that the project will be completed with the available funds and, once completed, will be suitable for the borrower's needs;
(13) Repetitive recommendations for servicing actions or guaranteed loans with marginal or substandard credit quality or that do not comply with Agency requirements;
(14) Negligent loan origination;
(15) Negligent loan servicing;
(16) Failure to conduct any approved liquidation of a loan guaranteed by the Agency or its predecessors in a timely and effective manner and in accordance with the approved liquidation plan; or
(17) Violation of applicable nondiscrimination law, including, but not limited to, statutes, regulations, USDA Departmental Regulations, the USDA Non-Discrimination Statement, and the Equal Credit Opportunity Act. USDA's Non-Discrimination Statement is located at the following Web site: http://www.usda.gov/wps/portal/usda/usdahome?navtype=FT&navid=NON_DISCRIMINATION.
(d) Debarment of lender. The Agency may debar a lender in addition to the revocation of the lender's status.
§ 4279.30
Lenders' functions and responsibilities.
(a) General. (1) Lenders have the primary responsibility for the successful delivery of the guaranteed loan program. Any action or inaction on the part of the Agency does not relieve the lender of its responsibilities to originate and service the loan guaranteed under this subpart, subpart B of this part, and subpart B of part 4287 of this chapter. Lenders may contract for services but are ultimately responsible for underwriting, loan origination, loan servicing, and compliance with all Agency regulations. No person may act as, or work for, both a loan packager and loan service provider on the same guaranteed loan. All lenders obtaining or requesting a loan guarantee are responsible for:
(i) Processing applications for guaranteed loans;
(ii) Developing and maintaining adequately documented loan files, which must be maintained for at least 3 years after any final loss has been paid;
(iii) Recommending only loan proposals that are eligible and financially feasible;
(iv) Properly closing the loan and obtaining valid evidence of debt and collateral in accordance with sound lending practices prior to disbursing loan proceeds;
(v) Keeping an inventory accounting of all collateral items and reconciling the inventory of all collateral sold during loan servicing, including liquidation;
(vi) Monitoring construction and operation;
(vii) Distributing loan funds;
(viii) Servicing guaranteed loans in a prudent manner, including liquidation if necessary;
(ix) Reporting all conflicts of interest, or appearances thereof, to the Agency;
(x) Following Agency regulations and agreements; and
(xi) Obtaining Agency approvals or concurrence as required.
(2) This subpart, subpart B of this part, and subpart B of part 4287 of this chapter contain the regulations for this program, including the lenders' responsibilities. If a lender fails to comply with these requirements, the Agency may reduce any loss payment in accordance with the applicable regulations.
(b) Credit evaluation. The lender must analyze all credit factors associated with each proposed loan and apply its professional judgment to determine that the credit factors, considered in combination, ensure loan repayment. The lender must have an adequate underwriting process to ensure that loans are reviewed by persons other than the originating officer, and there must be good credit documentation procedures. The Agency will only issue guarantees for loans that are sound and have reasonable assurance of repayment. The Agency will not issue guarantees for marginal or substandard loans.
(c) Environmental responsibilities. Lenders are responsible for becoming familiar with Federal environmental requirements; considering, in consultation with the prospective borrower, the potential environmental impacts of their proposals at the earliest planning stages; and developing proposals that minimize the potential to adversely impact the environment.
(1) Lenders must assist the borrower in providing details of the project's impact on the environment and historic properties in accordance with 7 CFR part 1970, “Environmental Policies and Procedures,” (or successor regulation), when applicable; assist in the collection of additional data when the Agency needs such data to complete its environmental review of the proposal; and assist in the resolution of environmental problems.
(2) Lenders must ensure the borrower has:
(i) Provided the necessary environmental information to enable the Agency to undertake its environmental review process in accordance with 7 CFR part 1970, “Environmental Policies and Procedures,” or successor regulation, including the provision of all required Federal, State, and local permits;
(ii) Complied with any mitigation measures required by the Agency; and
(iii) Not taken any actions or incurred any obligations with respect to the proposed project that will either limit the range of alternatives to be considered during the Agency's environmental review process or that will have an adverse effect on the environment.
(3) Lenders must alert the Agency to any environmental issues related to a proposed project or items that may require extensive environmental review.
§§ 4279.31-4279.43
[Reserved]
§ 4279.44
Access to records.
The lender must permit representatives of the Agency (or other agencies of the United States) to inspect and make copies of any records of the lender pertaining to Agency guaranteed loans during regular office hours of the lender or at any other time upon agreement between the lender and the Agency. In addition, the lender must cooperate fully with Agency oversight and monitoring of all lenders involved in any manner with any guarantee to ensure compliance with this subpart, subpart B of this part, and subpart B of part 4287 of this chapter. Such oversight and monitoring will include, but is not limited to, reviewing lender records and meeting with lenders in accordance with subpart B of part 4287 of this chapter.
§§ 4279.45-4279.58
[Reserved]
§ 4279.59
Environmental requirements.
The Agency is responsible for ensuring that the requirements of the National Environmental Policy Act of 1969 (under 40 CFR part 1500) and related compliance actions, such as Section 106 of the National Historic Preservation Act (under 36 CFR part 800) and Section 7 of the Endangered Species Act, are met and will complete the appropriate level of environmental review in accordance with 7 CFR part 1970, “Environmental Policies and Procedures,” or successor regulation. Because development of the loan application occurs simultaneously with development of the environmental review, applicants, including lenders and borrowers, must not take any actions or incur any obligations that would either limit the range of alternatives to be considered in the environmental review or that would have an adverse effect on the environment. Satisfactory completion of the environmental review process must occur prior to issuance of the Conditional Commitment to the lender.
§ 4279.60
Civil rights impact analysis.
Issuance of a Conditional Commitment is conditioned on the Agency being able to satisfactorily complete a civil rights impact analysis.
§ 4279.61
Equal Credit Opportunity Act.
In accordance with the Equal Credit Opportunity Act (15 U.S.C. 1691 et seq. ), with respect to any aspect of a credit transaction, neither the lender nor the Agency will discriminate against any applicant on the basis of race, color, religion, national origin, sex, marital status, or age (providing the applicant has the capacity to contract), or because all or part of the applicant's income derives from a public assistance program, or because the applicant has, in good faith, exercised any right under the Consumer Protection Act. The lender must comply with the requirements of the Equal Credit Opportunity Act as contained in the Federal Reserve Board's Regulation implementing that Act (see 12 CFR part 202) prior to loan closing.
§§ 4279.62-4279.70
[Reserved]
§ 4279.71
Public bodies and nonprofit corporations.
Audits will be required of any public body, nonprofit corporation or Indian Tribe that receives a guaranteed loan that meets the thresholds established by 2 CFR part 200, subpart F. Any audit provided by a public body, nonprofit corporation, or Indian Tribe required by this paragraph will be considered adequate to meet the audit requirements of the B&I program for that year.
§ 4279.72
Conditions of guarantee.
A loan guarantee under this part will be evidenced by a Loan Note Guarantee issued by the Agency. The provisions of this part and part 4287 of this chapter will apply to all outstanding guarantees. In the event of a conflict between the guarantee documents and these regulations as they exist at the time the documents are executed, these regulations will control.
(a) Full faith and credit. A guarantee under this part constitutes an obligation supported by the full faith and credit of the United States and is incontestable except for fraud or misrepresentation of which a lender or holder has actual knowledge at the time it becomes such lender or holder or which a lender or holder participates in or condones. The guarantee will be unenforceable to the extent that any loss is occasioned by a provision for interest on interest or default or penalty interest. In addition, the guarantee will be unenforceable by the lender to the extent any loss is occasioned by the violation of usury laws, use of loan proceeds for unauthorized purposes, negligent loan origination, negligent loan servicing, or failure to obtain or maintain the required security regardless of the time at which the Agency acquires knowledge thereof. Any losses occasioned will be unenforceable to the extent that loan funds were used for purposes other than those specifically approved by the Agency in its Conditional Commitment or amendment thereof in accordance with § 4279.173(b). The Agency may for cause terminate or reduce the Loan Note Guarantee at any time. The Agency will guarantee payment as follows:
(1) To any holder, 100 percent of any loss sustained by the holder on the guaranteed portion of the loan it owns and on interest due on such portion less any outstanding servicing fee. For those loans closed on or after August 2, 2016, the lender or the Agency will issue an interest termination letter to the holder(s) establishing the termination date for interest accrual. The guarantee will not cover interest to any holder accruing after the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter.
(2) To the lender, subject to the provisions of this part and subpart B of part 4287 of this chapter, the lesser of:
(i) Any loss sustained by the lender on the guaranteed portion, including principal and interest (for loans closed on or after August 2, 2016, the guarantee will not cover note interest to the lender accruing after 90 days from the most recent delinquency effective date) evidenced by the notes or assumption agreements and secured advances for protection and preservation of collateral made with the Agency's authorization; or
(ii) The guaranteed principal advanced to or assumed by the borrower and any interest due thereon. For loans closed on or after August 2, 2016, the guarantee will not cover note interest to the lender accruing after 90 days from the most recent delinquency effective date.
(b) Rights and liabilities. When a guaranteed portion of a loan is sold to a holder, the holder will succeed to all rights of the lender under the Loan Note Guarantee to the extent of the portion purchased. The full, legal interest in the note must remain with the lender, and the lender will remain bound to all obligations under the Loan Note Guarantee, Lender's Agreement, and Agency program regulations. A guarantee and right to require purchase will be directly enforceable by a holder notwithstanding any fraud or misrepresentation by the lender or any unenforceability of the guarantee by the lender, except for fraud or misrepresentation of which the holder had actual knowledge at the time it became the holder or in which the holder participates in or condones. The lender will reimburse the Agency for any payments the Agency makes to a holder on the lender's guaranteed loan that, under the Loan Note Guarantee, would not have been paid to the lender had the lender retained the entire interest in the guaranteed loan and not conveyed an interest to a holder.
(c) Payments. A lender will receive all payments of principal and interest on account of the entire loan and must promptly remit to the holder its pro rata share thereof, determined according to its respective interest in the loan, less only the lender's servicing fee.
§§ 4279.73-4279.74
[Reserved]
§ 4279.75
Sale or assignment of guaranteed loan.
The lender may sell all or part of the guaranteed portion of the loan on the secondary market or retain the entire loan. The lender must fully disburse and properly close a loan prior to sale of the note(s) on the secondary market. The lender cannot sell or participate any amount of the guaranteed or unguaranteed portion of the loan to the borrower or its parent, subsidiary, or affiliate or to officers, directors, stockholders, other owners, or members of their immediate families. The lender cannot share any premium received from the sale of a guaranteed loan in the secondary market with a loan packager or other loan service provider. If the lender desires to market all or part of the guaranteed portion of the loan at or subsequent to loan closing, such loan must not be in default. Lenders may use either the single note or multi-note system as outlined in paragraphs (a) and (b) of this section. The lender may also obtain participation in the loan under its normal operating procedures; however, the lender must retain title to the notes if any of them are unguaranteed and retain the lender's interest in the collateral.
(a) Single note system. The entire loan is evidenced by one note, and one Loan Note Guarantee is issued. The lender must retain title to the note, retain the lender's interest in the collateral, and retain the servicing responsibilities for the guaranteed loan. When the loan is evidenced by one note, the lender may not at a later date cause any additional notes to be issued. The lender may assign all or part of the guaranteed portion of the loan to one or more holders by using an Assignment Guarantee Agreement. The lender must complete and execute the Assignment Guarantee Agreement and return it to the Agency for execution prior to holder execution. In order to validate authenticity, holders are encouraged to consult with the Agency. Additionally, a Certificate of Incumbency and Signature may be requested. The holder, with written notice to the lender and the Agency, may reassign the unpaid guaranteed portion of the loan, in full, sold under the Assignment Guarantee Agreement. Holders may only reassign the entire guaranteed portion they have received and cannot subdivide or further split the guaranteed portion of a loan or retain an interest strip. Upon notification and completion of the Assignment Guarantee Agreement, the assignee shall succeed to all rights and obligations of the holder thereunder. Subsequent assignments require notice to the lender and Agency using any format, including that used by the Securities Industry and Financial Markets Association (formerly known as the Bond Market Association), together with the transfer of the original Assignment Guarantee Agreement. The Agency will neither execute a new Assignment Guarantee Agreement to effect a subsequent reassignment nor reissue a duplicate Assignment Guarantee Agreement unless the original was lost, stolen, destroyed, mutilated, or defaced in accordance with § 4279.84. The Assignment Guarantee Agreement clearly states the percentage and corresponding amount of the guaranteed portion it represents and the lender's servicing fee. A servicing fee may be charged by the lender to a holder and is calculated as a percentage per annum of the unpaid balance of the guaranteed portion of the loan assigned by the Assignment Guarantee Agreement. The Agency is not and will not be a party to any contract between the lender and another party where the lender sells its servicing fee. The Agency will not acknowledge, approve, nor have any liability to any of the parties of this contract.
(b) Multi-note system. Under this option, the lender may provide one note for the unguaranteed portion of the loan and no more than 10 notes for the guaranteed portion. All promissory notes must reflect the same payment terms. The lender must retain its interest in the collateral and servicing responsibilities for the guaranteed loan. When the lender selects this option, the holder will receive one of the borrower's executed notes and a Loan Note Guarantee. The Agency will issue a Loan Note Guarantee for each note, including the unguaranteed note, to be attached to each note. An Assignment Guarantee Agreement will not be used when the multi-note option is utilized.
§ 4279.76
[Reserved]
§ 4279.77
Minimum retention.
The lender is required to hold in its own portfolio a minimum of 5 percent of the original total loan amount. The amount required to be maintained must be of the unguaranteed portion of the loan and cannot be participated to another. The lender may enter into no agreement that reduces its exposure below the minimum 5 percent it is required to retain in its portfolio. The lender may sell the remaining amount of the unguaranteed portion of the loan only through participation.
§ 4279.78
Repurchase from holder.
(a) Repurchase by lender. A lender has the option to repurchase the unpaid guaranteed portion of the loan from a holder within 30 days of written demand by the holder when the borrower is in default not less than 60 days on principal or interest due on the loan; or when the lender has failed to remit to the holder its pro rata share of any payment made by the borrower within 30 days of the lender's receipt thereof. The repurchase by the lender must be for an amount equal to the unpaid guaranteed portion of principal and accrued interest less the lender's servicing fee. The holder must concurrently send a copy of the demand letter to the Agency. The lender must accept an assignment without recourse from the holder upon repurchase. For those loans closed on or after August 2, 2016, the lender or the Agency will issue an interest termination letter to the holder(s) establishing the termination date for interest accrual if the default is not cured. The guarantee will not cover interest to any holder accruing after the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter. If, in the opinion of the lender, repurchase of the guaranteed portion of the loan is necessary to adequately service the loan, the holder must sell the guaranteed portion of the loan to the lender for an amount equal to the unpaid principal and interest on such portion less the lender's servicing fee. The lender must not repurchase from the holder for arbitrage or other purposes to further its own financial gain. Any repurchase must only be made after the lender obtains the Agency's written approval. If the lender does not repurchase the guaranteed portion from the holder, the Agency may, at its option, purchase such guaranteed portion for servicing purposes. The lender is encouraged to repurchase the loan to facilitate the accounting of funds, resolve any loan problems, and prevent default, where and when reasonable. The benefit to the lender is that it may resell the guaranteed portion of the loan in order to continue collection of its servicing fee if the default is cured. When the lender repurchases the guaranteed portion from the secondary market for servicing purposes, the lender must discontinue interest accrual if Federal or State regulators place the loan in non-accrual status if the default is not cured within 90 days. The lender will notify the holder and the Agency of its decision.
(b) Agency repurchase. (1) The lender's servicing fee will stop on the date that interest was last paid by the borrower when the Agency purchases the guaranteed portion of the loan from a holder. The lender cannot charge such servicing fee to the Agency and must apply all loan payments and collateral proceeds received to the guaranteed and unguaranteed portions of the loan on a pro rata basis.
(2) If the Agency repurchases 100 percent of the guaranteed portion of the loan and becomes the holder, interest accrual on the loan will cease, and the Agency will not continue collection of the annual renewal fee from the lender.
(3) If the lender does not repurchase the unpaid guaranteed portion of the loan as provided in paragraph (a) of this section, the Agency will purchase from the holder the unpaid principal balance of the guaranteed portion together with accrued interest to date of repurchase, less the lender's servicing fee, within 30 days after written demand to the Agency from the holder. For those loans closed on or after August 2, 2016, the lender or the Agency will issue an interest termination letter to the holder(s) establishing the termination date for interest accrual. The guarantee will not cover interest to any holder accruing after the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter. Once the holder makes demand upon the Agency, the request cannot be rescinded.
(4) When the guaranteed loan has been delinquent more than 60 days and no holder comes forward, the Agency may issue a letter to the holder(s) establishing the cutoff date for interest accrual. Accrued interest to be paid the holder will be calculated from the date interest was last paid on the loan with a cutoff date being no more than 90 days from the date of the most recent delinquency effective date as reported by the lender.
(5) When the lender has accelerated the account and holds all or a portion of the guaranteed loan, an estimated loss claim (loan in the liquidation process) must be filed by the lender with the Agency within 60 days. Accrued interest paid to the lender will be calculated from the date interest was last paid on the loan with a cutoff date being no more than 90 days from the most recent delinquency effective date as reported by the lender.
(6) The holder's demand to the Agency must include a copy of the written demand made upon the lender. The holder must also include evidence of its right to require payment from the Agency. Such evidence must consist of either the original of the Loan Note Guarantee properly endorsed to the Agency or the original of the Assignment Guarantee Agreement properly assigned to the Agency without recourse, including all rights, title, and interest in the loan. When the single-note system is utilized and the initial holder has sold its interest, the current holder must present the original Assignment Guarantee Agreement and an original of each Agency-approved reassignment document in the chain of ownership, with the latest reassignment being assigned to the Agency without recourse, including all rights, title, and interest in the guarantee. The holder must include in its demand the amount due, including unpaid principal, unpaid interest to date of demand, and interest subsequently accruing from date of demand to proposed payment date. The Agency will be subrogated to all rights of the holder.
(7) Upon request by the Agency, the lender must promptly furnish a current statement certified by an appropriate authorized officer of the lender of the unpaid principal and interest then owed by the borrower on the loan and the amount then owed to any holder, along with the information necessary for the Agency to determine the appropriate amount due the holder. Any discrepancy between the amount claimed by the holder and the information submitted by the lender must be resolved between the lender and the holder before payment will be approved. Such conflict will suspend the running of the 30-day payment requirement.
(8) Purchase by the Agency neither changes, alters, nor modifies any of the lender's obligations to the Agency arising from the loan or guarantee nor does it waive any of the Agency's rights against the lender. The Agency will have the right to set-off against the lender all rights inuring to the Agency as the holder of the instrument against the Agency's obligation to the lender under the program.
§§ 4279.79-4279.83
[Reserved]
§ 4279.84
Replacement of document.
(a) The Agency may issue a replacement Loan Note Guarantee or Assignment Guarantee Agreement that was lost, stolen, destroyed, mutilated, or defaced to the lender or holder upon receipt of an acceptable certificate of loss and an indemnity bond.
(b) When a Loan Note Guarantee or Assignment Guarantee Agreement is lost, stolen, destroyed, mutilated, or defaced while in the custody of the lender or holder, the lender must coordinate the activities of the party who seeks the replacement documents and submit the required documents to the Agency for processing. The requirements for replacement are as follows:
(1) A certificate of loss, notarized and containing a jurat, which includes:
(i) Name and address of owner;
(ii) Name and address of the lender of record;
(iii) Capacity of person certifying;
(iv) Full identification of the Loan Note Guarantee or Assignment Guarantee Agreement, including the name of the borrower, the Agency's case number, date of the Loan Note Guarantee or Assignment Guarantee Agreement, face amount of the evidence of debt purchased, date of evidence of debt, present balance of the loan, percentage of guarantee, and, if an Assignment Guarantee Agreement, the original named holder and the percentage of the guaranteed portion of the loan assigned to that holder. Any existing parts of the document to be replaced must be attached to the certificate;
(v) A full statement of circumstances of the loss, theft, destruction, defacement, or mutilation of the Loan Note Guarantee or Assignment Guarantee Agreement; and
(vi) For the holder, evidence demonstrating current ownership of the Loan Note Guarantee and promissory note or the Assignment Guarantee Agreement. If the present holder is not the same as the original holder, a copy of the endorsement of each successive holder in the chain of transfer from the initial holder to present holder must be included. If copies of the endorsement cannot be obtained, best available records of transfer must be submitted to the Agency ( e.g., order confirmation, canceled checks, etc.).
(2) An indemnity bond acceptable to the Agency must accompany the request for replacement except when the holder is the United States, a Federal Reserve Bank, a Federal corporation, a State or territory, or the District of Columbia. The bond must be with surety except when the outstanding principal balance and accrued interest due the present holder is less than $1 million, verified by the lender in writing in a letter of certification of balance due. The surety must be a qualified surety company holding a certificate of authority from the Secretary of the Treasury and listed in Treasury Department Circular 570.
(3) All indemnity bonds must be issued and payable to the United States of America acting through the Agency. The bond must be in an amount not less than the unpaid principal and interest. The bond must hold the Agency harmless against any claim or demand that might arise or against any damage, loss, costs, or expenses that might be sustained or incurred by reasons of the loss or replacement of the instruments.
(4) The Agency will not attempt to obtain, or participate in the obtaining of, replacement notes from the borrower. The holder is responsible for bearing the costs of note replacement if the borrower agrees to issue a replacement instrument. Should such note be replaced, the terms of the note cannot be changed. If the evidence of debt has been lost, stolen, destroyed, mutilated, or defaced, such evidence of debt must be replaced before the Agency will replace any instruments.
§§ 4279.85-4279.99
[Reserved]
§ 4279.100
OMB control number.
In accordance with the Paperwork Reduction Act of 1995, the information collection requirements contained in this subpart have been submitted to the Office of Management and Budget (OMB) under OMB Control Number 0570-0069 for OMB approval.
3. Revise Subpart B to read as follows:

Subpart B—Business and Industry Loans
Sec.
4279.101
Introduction.
4279.102
Definitions and abbreviations.
4279.103
Exception authority.
4279.104
Appeals.
4279.105-4279.107
[Reserved]
4279.108
Eligible borrowers.
4279.109-4279.112
[Reserved]
4279.113
Eligible uses of funds.
4279.114
[Reserved]
4279.115
Cooperative stock/cooperative equity.
4279.116
New Markets Tax Credit program.
4279.117
Ineligible purposes and entity types.
4279.118
[Reserved]
4279.119
Loan guarantee limits.
4279.120
Fees and charges.
4279.121-4279.124
[Reserved]
4279.125
Interest rates.
4279.126
Loan terms.
4279.127-4279.130
[Reserved]
4279.131
Credit quality.
4279.132
Personal and corporate guarantees.
4279.133-4279.135
[Reserved]
4279.136
Insurance.
4279.137
Financial statements.
4279.138-4279.143
[Reserved]
4279.144
Appraisals.
4279.145-4279.149
[Reserved]
4279.150
Feasibility studies.
4279.151-4279.160
[Reserved]
4279.161
Filing preapplications and applications.
4279.162-4279.164
[Reserved]
4279.165
Evaluation of application.
4279.166
Loan priority scoring.
4279.167
Planning and performing development.
4279.168
Timeframe for processing applications.
4279.169-4279.172
[Reserved]
4279.173
Loan approval and obligating funds.
4279.174
Transfer of lenders.
4279.175-4279.179
[Reserved]
4279.180
Changes in borrower.
4279.181
Conditions precedent to issuance of the Loan Note Guarantee.
4279.182-4279.186
[Reserved]
4279.187
Refusal to execute Loan Note Guarantee.
4279.188-4279.199
[Reserved]
4279.200
OMB control number.

Subpart B—Business and Industry Loans
§ 4279.101
Introduction.
(a) Content. This subpart contains loan processing regulations for the Business and Industry (B&I) Guaranteed Loan Program. It is supplemented by subpart A of this part, which contains general guaranteed loan regulations, and subpart B of part 4287 of this chapter, which contains loan servicing regulations.
(b) Purpose. The purpose of the B&I Guaranteed Loan Program is to improve, develop, or finance business, industry, and employment and improve the economic and environmental climate in rural communities. This purpose is achieved by bolstering the existing private credit structure through the guarantee of quality loans that will provide lasting community benefits. It is not intended that the guarantee authority will be used for marginal or substandard loans or for relief of lenders having such loans.
(c) Documents. Whether specifically stated or not, whenever Agency approval is required, it must be in writing. Copies of all forms and regulations referenced in this subpart may be obtained from any Agency office and from the USDA Rural Development Web site at http://www.rd.usda.gov/publications. Whenever a form is designated in this subpart, that designation includes predecessor and successor forms, if applicable, as specified by the Agency.
§ 4279.102
Definitions and abbreviations.
The definitions and abbreviations in § 4279.2 are applicable to this subpart.
§ 4279.103
Exception authority.
Section 4279.15 applies to this subpart.
§ 4279.104
Appeals.
Section 4279.16 applies to this subpart.
§§ 4279.105-4279.107
[Reserved]
§ 4279.108
Eligible borrowers.
(a) Type of entity. A borrower may be a cooperative organization, corporation, partnership, or other legal entity organized and operated on a profit or nonprofit basis; an Indian tribe on a Federal or State reservation or other federally recognized tribal group; a public body; or an individual. A borrower must be engaged in or proposing to engage in a business. A business may include manufacturing, wholesaling, retailing, providing services, or other activities that will provide employment and improve the economic or environmental climate.
(b) Citizenship. Individual borrowers must be citizens of the United States or reside in the United States after being legally admitted for permanent residence. For purposes of this subpart, citizens and residents of the Republic of Palau, the Federated States of Micronesia, American Samoa, Guam, the Commonwealth of the Northern Mariana Islands, and the Republic of the Marshall Islands are considered U.S. citizens. Individuals that reside in the United States after being legally admitted for permanent residence must provide a permanent green card as evidence of eligibility. Private entity borrowers must demonstrate, to the Agency's satisfaction, that loan funds will remain in the United States and the facility being financed will primarily create new or save existing jobs for rural U.S. residents.
(c) Rural area. The business financed with a guaranteed loan under this subpart must be located in a rural area, except for cooperative organizations financed in accordance with § 4279.113(j)(2) and local foods projects financed in accordance with § 4279.113(y)(2). Loans to borrowers with facilities located in both rural and non-rural areas will be limited to the amount necessary to finance the facility located in the eligible rural area, except for those cooperative organizations financed in accordance with § 4279.113(j)(2) and those local foods projects financed in accordance with § 4279.113(y)(2).
(1) Rural areas are any area of a State other than a city or town that has a population of greater than 50,000 inhabitants and any urbanized area contiguous and adjacent to such a city or town. In making this determination, the Agency will use the latest decennial census of the United States.
(2) For the purposes of this definition, cities and towns are incorporated population centers with definite boundaries, local self government, and legal powers set forth in a charter granted by the State.
(3) For the Commonwealth of Puerto Rico, the island is considered rural, except for the San Juan Census Designated Place (CDP) and any other CDP with greater than 50,000 inhabitants. However, CDPs with greater than 50,000 inhabitants, other than the San Juan CDP, may be eligible if they are determined to be “not urban in character.”
(4) For the State of Hawaii, all areas within the State are considered rural, except for the Honolulu CDP within the County of Honolulu.
(5) For the Republic of Palau, the Federated States of Micronesia, American Samoa, Guam, the Commonwealth of the Northern Mariana Islands, and the Republic of the Marshall Islands, the Agency will determine what constitutes a rural area based on available population data.
(6) Notwithstanding any other provision of this definition, in determining which census blocks in an urbanized area are not in a rural area, the Agency will exclude any cluster of census blocks that would otherwise be considered not in a rural area only because the cluster is adjacent to not more than two census blocks that are otherwise considered not in a rural area under this definition.
(7) The Under Secretary, whose authority may not be redelegated, may determine that an area is “rural in character.” Any determination made by the Under Secretary under this provision will be to areas that are determined to be “rural in character” and are within: An urbanized area that has two points on its boundary that are at least 40 miles apart, which is not contiguous or adjacent to a city or town that has a population of greater than 150,000 inhabitants or the urbanized area of such city or town; or an area within an urbanized area contiguous and adjacent to a city or town of greater than 50,000 inhabitants that is within 1/4 mile of a rural area.
(i) Units of local government may petition the Under Secretary for a “rural in character” designation by submitting a petition to both the appropriate Rural Development State Director and the Administrator on behalf of the Under Secretary. The petition must document how the area meets the requirements of paragraph (c)(7) of this section and discuss why the petitioner believes the area is “rural in character,” including, but not limited to, the area's population density; demographics; topography; and how the local economy is tied to a rural economic base. Upon receiving a petition, the Under Secretary will consult with the applicable Governor and Rural Development State Director and request comments within 10 business days, unless those comments were submitted with the petition. The Under Secretary will release to the public a notice of a petition filed by a unit of local government not later than 30 days after receipt of the petition by way of notice in a local newspaper and notice on the applicable Rural Development State Office Web site. The Under Secretary will make a determination not less than 15 days, but no more than 60 days, after the release of the notice. The public notice will appear for at least 3 consecutive days if published in a daily newspaper or otherwise in two consecutive publications. Upon a negative determination, the Under Secretary will provide to the petitioner an opportunity to appeal a determination to the Under Secretary for reconsideration, and the petitioner will have 10 business days to appeal the determination and provide further information for consideration.
(ii) Rural Development State Directors may also initiate a request to the Under Secretary to determine if an area is “rural in character.” A written recommendation should be sent to the Administrator, on behalf of the Under Secretary, that documents how the area meets the statutory requirements of paragraph (c)(7) of this section and discusses why the State Director believes the area is “rural in character,” including, but not limited to, the area's population density; demographics; topography; and how the local economy is tied to a rural economic base. Upon receipt of such a request, the Administrator will review the request for compliance with the “rural in character” provisions and make a recommendation to the Under Secretary. Provided a favorable determination is made, the Under Secretary will consult with the applicable Governor and request comments within 10 business days, unless gubernatorial comments were submitted with the request. A public notice will be published by the State Office in accordance with paragraph (c)(7)(i) of this section. There is no appeal process for requests made on the initiative of the State Director.
(d) Other credit. All applications for assistance will be accepted and processed without regard to the availability of credit from any other source.
(e) Prohibition under Agency programs. No loans guaranteed by the Agency will be conditioned on any requirement that the recipients of such assistance accept or receive electric or other services from any particular utility, supplier, or cooperative.
§§ 4279.109-4279.112
[Reserved]
§ 4279.113
Eligible uses of funds.
Eligible uses of funds must be consistent with § 4279.101(b) and § 4279.108(a) and include, but are not limited to, the following:
(a) Purchase and development of land, buildings, and associated infrastructure for commercial or industrial properties, including expansion or modernization.
(b) Business acquisitions provided that jobs will be created or saved. A business acquisition is considered the acquisition of an entire business, not a partial stock acquisition in a business.
(c) Leasehold improvements when the lease contains no reverter clauses or restrictive clauses that would impair the use or value of the property as security for the loan. The term of the lease must be equal to or greater than the term of the loan.
(d) Constructing or equipping facilities for lease to private businesses engaged in commercial or industrial operations. Financing for mixed-use properties, involving both commercial business and residential space, is authorized provided that not less than 50 percent of the building's projected revenue will be generated from business use.
(e) Purchase of machinery and equipment.
(f) Startup costs, working capital, inventory, and supplies in the form of a permanent working capital term loan.
(g) Debt refinancing when it is determined that the project is viable and refinancing is necessary to improve cash flow and create new or save existing jobs. Debt being refinanced must be debt of the borrower reflected on its balance sheet. The lender's analysis must document that, except for the refinancing of lines of credit, the debt being refinanced was for an eligible loan purpose under this subpart. Except as provided for in paragraph (j)(3) of this section, existing lender debt may be included provided that, at the time of application, the loan being refinanced has been closed and current for at least the past 12 months (current status cannot be achieved by the lender forgiving the borrower's debt or servicing actions that impact the borrower's repayment schedule), and the lender is providing better rates or terms. Unless the amount to be refinanced is owed directly to the Federal government or is federally guaranteed, existing lender debt may not exceed 50 percent of the overall loan.
(h) Takeout of interim financing. Guaranteeing a loan that provides for permanent, long-term financing after project completion to pay off a lender's interim loan will not be treated as debt refinancing provided that the lender submits a complete preapplication or application that proposes such interim financing prior to closing the interim loan. The borrower must take no action that would have an adverse impact on the environment or limit the range of alternatives to be considered by the Agency during the environmental review process. The Agency will not guarantee takeout of interim financing loans that prevent a meaningful environmental assessment prior to Agency loan approval. Even for projects with interim financing, the Agency cannot approve the loan and issue a Conditional Commitment until the environmental process is complete. The Agency assumes no responsibility or obligation for interim loans.
(i) Purchase of membership, stocks, bonds, or debentures necessary to obtain a loan from Farm Credit System institutions and other lenders provided the purchase is required for all of their borrowers and is the minimum amount required.
(j) Loans to cooperative organizations.
(1) Guaranteed loans to eligible cooperative organizations may be made in principal amounts up to $40 million if the project is located in a rural area, the cooperative facility being financed provides for the value-added processing of agricultural commodities, and the total amount of loans exceeding $25 million does not exceed 10 percent of the funds available for the fiscal year.
(2) Guaranteed loans to eligible cooperative organizations may also be made in non-rural areas provided:
(i) The primary purpose of the loan is for a facility to provide value-added processing for agricultural producers that are located within 80 miles of the facility;
(ii) The applicant satisfactorily demonstrates that the primary benefit of the loan will be to provide employment for rural residents;
(iii) The principal amount of the loan does not exceed $25 million; and
(iv) The total amount of loans guaranteed under this paragraph does not exceed 10 percent of the funds available for the fiscal year.
(3) An eligible cooperative organization may refinance an existing B&I loan provided the existing loan is current and performing; the existing loan is not and has not been in monetary default (more than 30 days late) or the collateral of which has not been converted; and there is adequate security or full collateral for the new guaranteed loan.
(k) The purchase of cooperative stock by individual farmers or ranchers in a farmer or rancher cooperative or the purchase of transferable cooperative stock in accordance with § 4279.115(a); or the purchase of stock in a business by employees forming an Employee Stock Ownership Plan or worker cooperative in accordance with § 4279.115(c).
(l) The purchase of preferred stock or similar equity issued by a cooperative organization or a fund that invests primarily in cooperative organizations in accordance with § 4279.115(b).
(m) Taxable corporate bonds when the bonds are fully amortizing and comply with all provisions of § 4279.126, and the bond holder (lender) retains 5 percent of the bond in accordance with § 4279.77. The bonds must be fully secured with collateral in accordance with § 4279.131(b). The bonds must only provide for a trustee when the trustee is totally under the control of the lender. The bonds must provide no rights to bond holders other than the right to receive the payments due under the bond. For instance, the bonds must not provide for bond holders replacing the trustee or directing the trustee to take servicing actions, such as accelerating the bonds. Convertible bonds are not eligible under this paragraph due to the potential conflict of interest of a lender having an ownership interest in the borrower.
(1) The bond issuer (borrower) must not issue more than 11 bonds, with no more than 10 of those bonds being guaranteed under this program. The bond issuer must obtain the services and opinion of an experienced bond counsel who must present a legal opinion stating that the bonds are legal, valid, and binding obligations of the issuer and that the issuer has adhered to all applicable laws.
(2) The bond holder must purchase all of the bonds and comply with all Agency regulations. There must be a bond purchase agreement between the issuer and the bond holder. The bond purchase agreement must contain similar language to what is required to be in a loan agreement in accordance with § 4279.161(b)(11) and must not be in conflict with subparts A or B of part 4279 or subpart B of part 4287 of this chapter. The bond holder is responsible for all servicing of the loan (bond), although the bond holder may contract for servicing assistance, including contracting with a trustee who remains under the lender's total control.
(n) Interest (including interest on interim financing) during the period before the first principal payment becomes due or when the facility becomes income producing, whichever is earlier.
(o) Fees and charges outlined in § 4279.120(a), (c) and (d).
(p) Feasibility studies.
(q) Agricultural production, when not eligible for Farm Service Agency (FSA) farm loan programs assistance and when it is part of an integrated business also involved in the processing of agricultural products. Any agricultural production considered for guaranteed loan financing must be owned, operated, and maintained by the business receiving the loan for which a guarantee is provided. Except for cooperative stock purchase loans in accordance with § 4279.115(a), independent agricultural production operations are not eligible, even if not eligible for FSA farm loan programs assistance.
(1) The agricultural-production portion of any loan must not exceed 50 percent of the total loan or $5 million, whichever is less.
(2) This paragraph does not preclude financing the following types of businesses:
(i) Commercial nurseries engaged in the production of ornamental plants, trees, and other nursery products, such as bulbs, flowers, shrubbery, flower and vegetable seeds, sod, and the growing of plants from seed to the transplant stage; and forestry, which includes businesses primarily engaged in the operation of timber tracts, tree farms, forest nurseries, and related activities, such as reforestation.
(ii) The growing of mushrooms or hydroponics.
(iii) The boarding and/or training of animals.
(iv) Commercial fishing.
(v) Aquaculture, including conservation, development, and utilization of water for aquaculture.
(r) Educational or training facilities.
(s) Industries undergoing adjustment from terminated Federal agricultural price and income support programs or increased competition from foreign trade.
(t) Community facility projects that are not listed as an ineligible loan purpose in § 4279.117.
(u) Nursing homes and assisted living facilities where constant medical care is provided and available onsite to the residents. Independent living facilities are considered residential in nature and are not eligible in accordance with § 4279.117(d).
(v) Tourist and recreation facilities, including hotels, motels, bed and breakfast establishments, and resort trailer parks and campgrounds, except as prohibited under ineligible purposes in § 4279.117.
(w) Pollution control and abatement.
(x) Energy projects that are not eligible for the Rural Energy for America Program (REAP) (7 CFR part 4280, subpart B), unless sufficient funding is not available under REAP, and when the facility has been constructed according to plans and specifications and is producing at the quality and quantity projected in the application. This does not preclude the guarantee of joint REAP/B&I projects. Eligible energy projects must be commercially available. Eligible energy projects also include those that reduce reliance on nonrenewable energy resources by encouraging the development and construction of solar energy systems and other renewable energy systems (including wind energy systems and anaerobic digesters for the purpose of energy generation), including the modification of existing systems in rural areas.
(1) Projects that produce renewable biomass or biofuel as an output must utilize commercially available technologies and have completed two operating cycles at design performance levels prior to issuance of a Loan Note Guarantee.
(2) Projects that produce steam or electricity as an output must have met acceptance test performance criteria acceptable to the Agency and be successfully interconnected with the purchaser of the output. An executed power purchase agreement acceptable to the Agency will be required prior to issuance of a Loan Note Guarantee.
(3) Performance or acceptance test requirements for all other energy projects will be determined by the Agency on a case-by-case basis.
(y) Projects that process, distribute, aggregate, store, and/or market locally or regionally produced agricultural food products to support community development and farm and ranch income, subject to each of the following:
(1) The term “locally or regionally produced agricultural food product” means any agricultural food product that is raised, produced, and distributed in the locality or region in which the final product is marketed, so that the distance the product is transported is less than 400 miles from the origin of the product, or within the State in which the product is produced. Food products could be raw, cooked, or a processed edible substance, beverage, or ingredient used or intended for use or for sale in whole or in part for human consumption.
(2) Projects may be located in urban areas, as well as rural areas.
(3) A significant amount of the food product sold by the borrower is locally or regionally produced, and a significant amount of the locally or regionally produced food product is sold locally or regionally. The Agency is choosing not to set a threshold for “significant” but reserves the right to do so in periodic notices in the Federal Register .
(4) The borrower must include in an appropriate agreement, with retail and institutional facilities to which the borrower sells locally or regionally produced agricultural food products, a requirement to inform consumers of the retail or institutional facilities that the consumers are purchasing or consuming locally or regionally produced agricultural food products.
(5) The Agency will give funding priority to projects that provide a benefit to underserved communities in accordance with § 4279.166(b)(4)(i)(G). An underserved community is a community (including an urban or rural community and an Indian tribal community) that has limited access to affordable, healthy foods, including fresh fruits and vegetables, in grocery retail stores or farmer to consumer direct markets and that has either a high rate of hunger or food insecurity or a high poverty rate as reflected in the most recent decennial census or other Agency-approved census.
§ 4279.114
[Reserved]
§ 4279.115
Cooperative stock/cooperative equity.
(a) Cooperative stock purchase program. The Agency may guarantee loans for the purchase of cooperative stock by individual farmers or ranchers in a farmer or rancher cooperative established for the purpose of processing an agricultural commodity. The cooperative may use the proceeds from the stock sale to recapitalize, to develop a new processing facility or product line, or to expand an existing production facility. The cooperative may contract for services to process agricultural commodities or otherwise process value-added agricultural products during the 5-year period beginning on the operation startup date of the cooperative in order to provide adequate time for the planning and construction of the processing facility of the cooperative. Loan proceeds must remain in the cooperative from which stock was purchased, and the cooperative must not reinvest those funds into another entity. The Agency may also guarantee loans for the purchase of transferable stock shares of any type of existing cooperative, which would primarily involve new or incoming members. Such stock may provide delivery or some form of participation rights and may only be traded among cooperative members. Paragraphs (5) through (7) of this section are not applicable for guaranteed loans for the purchase of transferable cooperative stock.
(1) The maximum loan amount is the threshold established in § 4279.161(c), and all applications will be processed in accordance with § 4279.161(c).
(2) The maximum term is 7 years.
(3) The lender will, at a minimum, obtain a valid lien on the stock, an assignment of any patronage refund, and the ability to transfer the stock to another party, or otherwise liquidate and dispose of the collateral in the event of a borrower default.
(4) The lender must complete a written credit analysis of each stock purchase loan and a complete credit analysis of the cooperative prior to making its first stock purchase loan.
(5) The borrower may provide financial information in the manner that is generally required by commercial agricultural lenders.
(6) A feasibility study of the cooperative is required for startup cooperatives and may be required by the Agency for existing cooperatives when the cooperative's operations will be significantly affected by the proceeds that were generated from the stock sale.
(7) The Agency will conduct an appropriate environmental assessment on the processing facility and will not process individual applications for the purchase of stock until the environmental assessment on the cooperative processing facility is completed. Typically, an individual loan for the purchase of cooperative stock is considered a categorical exclusion.
(b) Cooperative equity security guarantees. The Agency may guarantee loans for the purchase of preferred stock or similar equity issued by a cooperative organization or for a fund that invests primarily in cooperative organizations. In either case, the guarantee must significantly benefit one or more entities eligible for assistance under the B&I program.
(1) “Similar equity” is any special class of equity stock that is available for purchase by non-members and/or members and lacks voting and other governance rights.
(2) A fund that invests “primarily” in cooperative organizations is determined by its percentage share of investments in and loans to cooperatives. A fund portfolio must have at least 50 percent of its loans and investments in cooperatives to be considered eligible for loan guarantees for the purchase of preferred stock or similar equity.
(3) The principal amount of the loan will not exceed $10 million.
(4) The maximum term is 7 years or no longer than the specified holding period for redemption as stated by the stock offering, whichever is less.
(5) All borrowers purchasing preferred stock or similar equity must provide documentation of the terms of the offering that includes compliance with State and Federal securities laws and financial information about the issuer of the preferred stock to both the lender and the Agency.
(6) Issuer(s) of preferred stock must be a cooperative organization or a fund and must be able to issue preferred stock to the public that, if required, complies with State and Federal securities laws.
(7) A fund must use a loan guaranteed under this subpart to purchase preferred stock that is issued by cooperatives.
(8) The lender will, at a minimum, obtain a valid lien on the preferred stock, an assignment of any patronage refund, and the ability to transfer the stock to another party, or otherwise liquidate and dispose of the collateral in the event of a borrower default. For the purpose of recovering losses from loan defaults, lenders may take ownership of all equities purchased with such loans, including additional shares derived from reinvestment of dividends.
(9) Shares of preferred stock that are purchased with guaranteed loan proceeds cannot be converted to common or voting stock.
(10) In the absence of adequate provisions for investors' rights to early redemption of preferred stock or similar equity, a borrower must request from a cooperative or fund issuing such equities a contingent waiver of the holding or redemption period in advance of share purchases. This contingent waiver provides that in the event a borrower defaults on a loan financed under the guaranteed loan program, the borrower waives any ownership rights in the stock, and the lender and Agency will then have the right to redeem the stock.
(11) Guaranteed loans for the purchase of preferred stock must be prepaid in the event a cooperative or fund that issued the stock exercises an early redemption. If the cooperative enters into bankruptcy, to the extent the cooperative can redeem the preferred stock, the borrower is required to repay the loan from the redemption of the stock.
(c) Employee ownership succession. The Agency may guarantee loans for conversions of businesses to either cooperatives or Employee Stock Ownership Plans (ESOP) within 5 years from the date of initial transfer of stock.
(1) The maximum loan amount is the threshold established in § 4279.161(c), and all applications will be processed in accordance with § 4279.161(c).
(2) The maximum term is 7 years.
(3) The lender will, at a minimum, obtain a valid lien on the stock, an assignment of any patronage refund, and the ability to transfer the stock to another party, or otherwise liquidate and dispose of the collateral in the event of a borrower default.
(4) The lender must complete a written credit analysis of each stock purchase loan and a complete credit analysis of the cooperative or ESOP prior to making its first stock purchase loan.
(5) If a cooperative is organized, the selling owner(s) become members with special control rights to protect their stake in the business while a succession plan is implemented. At the completion of the stock transfer, selling owners may retain their membership in the cooperative provided that their control rights are the same as all other members. Any special covenants that selling owners may have held must be extinguished upon completion of the transfer.
(6) If an ESOP is organized for transferring ownership to employees, selling owner(s) may not retain ownership in the business after 5 years from the date of the initial transfer of stock.
§ 4279.116
New Markets Tax Credit program.
This section identifies the provisions specific to guaranteed loans involving projects that include new markets tax credits available under the New Markets Tax Credit (NMTC) program. Such applicants and applications must comply with the provisions in subparts A and B of this part, except as modified in this section.
(a) Loan guarantees for Qualified Active Low Income Community Businesses (QALICB). (1) To be an eligible lender for a loan guarantee that involves NMTCs, the organization must meet the applicable eligibility criteria in § 4279.29 as otherwise modified by paragraphs (a)(1)(i) and (ii) of this section.
(i) Sub-entities under the control of a non-regulated lender approved as a lender for this program do not need to separately meet the requirements of § 4279.29(b). An eligible non-regulated lender may modify its list of eligible sub-entities under its control at any time by notifying the Agency in writing.
(ii) In order to take advantage of the requirement exemption in paragraph (a)(1)(i) of this section, the non-regulated lender must include in its application to be a lender each sub-entity under its control and must clearly define the multiple-entity organizational and control structure. In addition, the lender must include each such sub-entity in the audited financial statements, commercial loan portfolio, and commercial loan performance statistics.
(2) The provisions of § 4279.117(q) notwithstanding, a lender that is a Department of Treasury certified Community Development Entity (CDE) or subsidiary of a CDE (sub-CDE) may have an ownership interest in the borrower provided that each of the conditions specified in paragraphs (a)(2)(i) through (iv) of this section is met.
(i) The lender does not have an ownership interest in the borrower prior to the guaranteed loan application.
(ii) The lender does not take a controlling interest in the borrower.
(iii) The lender cannot provide equity or take an ownership interest in a borrower at a level that would result in the lender owning 20 percent or more interest in the borrower.
(iv) In its guaranteed loan application, the lender provides an Agency-approved exit strategy when the NMTCs expire after the seventh year. The CDE's (or sub-CDE's) exit strategy must include a general plan to address the lender's equity in the project, and, if the lender will divest its equity interest, how this will be accomplished and the impact on the borrower.
(3) Notwithstanding § 4279.117(p), a CDE's (or sub-CDE's) ownership interest in the borrower does not constitute a conflict of interest. The Agency will mitigate the potential for or appearance of a conflict of interest by requiring appropriate loan covenants regarding limitations on dividends and distributions of earnings be established, as well as other covenants in accordance with § 4279.161(b)(11). The Agency will also ensure that the lender limits waivers of loan covenants and future modifications of loan documents.
(4) For purposes of calculating tangible balance sheet equity, the CDE's or sub-CDE's loan that is subordinated to the guaranteed loan will be considered equity when calculating tangible balance sheet equity. The QALICB's financial statements must be prepared in accordance with GAAP.
(b) Loan guarantees for the leveraged lender. The provisions of § 4279.117(s) notwithstanding, a sub-CDE may be an eligible borrower as specified in paragraph (b)(1) of this section. Paragraphs (b)(2) through (13) of this section identify modifications to subpart B of this part that apply when the eligible borrower is a sub-CDE.
(1) To be an eligible borrower for a NMTC loan, each of the following conditions must be met:
(i) The sub-CDE must be established for a single specific NMTC investment;
(ii) The lender is not an affiliate of the sub-CDE;
(iii) One hundred percent of the guaranteed loan funds are or will be loaned by the sub-CDE to the QALICB, as defined by applicable regulations of the Internal Revenue Service and are or will be used by the QALICB in accordance with §§ 4279.113 and 4279.117. All of the B&I guaranteed loan funds must be “passed through” the sub-CDE to the QALICB through a direct tracing method. The QALICB's project must be the ultimate use of the B&I guaranteed loan funds; and
(iv) The QALICB meets the requirements of § 4279.108.
(2) The provisions of § 4279.119 apply except that the loan guarantee limits apply to the QALICB and not to the sub-CDE, who would otherwise be understood to be the “borrower.”
(3) Section 4279.126 applies to both the borrower (sub-CDE) and the QALICB. The terms and payment schedule of the lender's loan to the sub-CDE must be at least equal to the terms and payment schedule of the sub-CDE's loan to the QALICB. An Agency approved unequal or escalating schedule of principal and interest payments may be used for a NMTC loan. The lender may require additional principal repayment by a co-borrower, such as an owner or principal of the QALICB. The lender or sub-CDE may require a debt repayment reserve fund or sinking fund; however, such fund is not in lieu of a principal repayment schedule in accordance with § 4279.126 as amended by this paragraph.
(4) Except for § 4279.131(b), section 4279.131 applies to both the lender's loan to the sub-CDE and the sub-CDE's loan to the QALICB. Section 4279.131(b) applies only to the sub-CDE's loan to the QALICB. Section 4279.116(a)(4) also applies when calculating tangible balance sheet equity.
(5) The personal and corporate guarantee provisions of § 4279.132 and the insurance provisions of § 4279.136 apply only to the QALICB and the sub-CDE's loan to the QALICB.
(6) Section 4279.137 applies to both the borrower (sub-CDE) and the QALICB.
(7) Sections 4279.144 and 4279.150 apply to both the QALICB and the sub-CDE's loan to the QALICB.
(8) Section 4279.161 applies to both the borrower (sub-CDE) and the QALICB. As part of the application completed by the lender in accordance with § 4279.161, the application documentation must include comparable information for the loan (using the B&I guaranteed loan funds) between the sub-CDE and QALICB. The requirements of § 4279.161 apply to the loan application, application analysis and underwriting, and loan documents between the sub-CDE and QALICB. The lender must include these materials in its guaranteed loan application to the Agency.
(9) The environmental requirements specified in § 4279.165(b) apply to both the loan between the sub-CDE and QALICB and the QALICB's project.
(10) When assigning the priority score to a NMTC loan application under § 4279.166, the Agency will score the project based on the sub-CDE's loan to the QALICB, the QALICB, and the QALICB's project as the ultimate use of B&I guaranteed loan funds.
(11) When complying with the planning and performing development provisions in § 4279.167, the lender is responsible for ensuring that both the sub-CDE's loan to the QALICB and the QALICB's project comply with the provisions in § 4279.167.
(12) Section 4279.180 applies to both the sub-CDE (borrower) and the QALICB.
(13) Section 4279.181 applies to both the sub-CDE (borrower) and the QALICB.
§ 4279.117
Ineligible purposes and entity types.
(a) Distribution or payment to an individual or entity that will retain an ownership interest in the borrower or distribution or payment to a beneficiary of the borrower. Distribution or payment to a member of the immediate family of an owner, partner, or stockholder will not be permitted, except for a change in ownership of the business where the selling immediate family member does not retain an ownership interest and the Agency determines the price paid to be reasonable. As this type of transaction is not an arm's length transaction, reasonableness of the price paid will be based upon an appraisal. In situations where there is common ownership or an otherwise closely-related company is being paid to do construction or installation work for a borrower, only documented costs associated with construction or installation can be paid with loan proceeds. Documented construction or installation costs may not include any profit or wages to a related person, and all work must be done at cost with no profit built into the cost. This paragraph does not apply to transfers of ownership for ESOPs or worker cooperatives, to cooperatives where the cooperative pays the member for product or services, or where member stock is transferred among members of the cooperative in accordance with § 4279.115.
(b) Projects in excess of $1 million that would likely result in the transfer of jobs from one area to another and increase direct employment by more than 50 employees. However, this limitation is not to be construed to prohibit assistance for the expansion of an existing business entity through the establishment of a new branch, affiliate, or subsidiary of such entity if the establishment of such branch, affiliate, or subsidiary will not result in an increase in unemployment in the area of original location or in any other area where such entity conducts business operations, unless there is reason to believe that such branch, affiliate, or subsidiary is being established with the intention of closing down the operations of the existing business entity in the area or its original location or in any other area where it conducts such operations.
(c) Projects in excess of $1 million that would increase direct employment by more than 50 employees, which is calculated to or likely to result in an increase in the production of goods, materials, or commodities, or the availability of services or facilities in the area, when there is not sufficient demand for such goods, materials, commodities, services, or facilities to employ the efficient capacity of existing competitive commercial or industrial enterprises, unless such financial or other assistance will not have an adverse effect upon existing competitive enterprises in the area.
(d) The financing of timeshares, residential trailer parks, housing development sites, apartments, duplexes, or other residential housing, except as authorized in § 4279.113(d).
(e) Owner-occupied housing, such as bed and breakfasts, hotels and motels, storage facilities, etc., are only allowed when the pro rata value of the owner's living quarters, based on square footage, is deducted from the use of loan proceeds.
(f) Guaranteeing lease payments or any lines of credit.
(g) Guaranteeing loans made by other Federal agencies.
(h) Loans made with the proceeds of any obligation the interest on which is excludable from income under 26 U.S.C. 103 or a successor statute. Funds generated through the issuance of tax-exempt obligations shall neither be used to purchase the guaranteed portion of any Agency guaranteed loan nor shall an Agency guaranteed loan serve as collateral for a tax-exempt issue. The Agency may guarantee a loan for a project that involves tax-exempt financing only when the guaranteed loan funds are used to finance a part of the project that is separate and distinct from the part that is financed by the tax-exempt obligation, and the guaranteed loan has at least a parity security position with the tax-exempt obligation.
(i) Guarantees supporting inherently religious activities, such as worship, religious instruction, proselytization, or to pay costs associated with acquisition, construction, or rehabilitation of structures for inherently religious activities, including the financing of multi-purpose facilities where religious activities will be among the activities conducted.
(j) Businesses that derive more than 10 percent of annual gross revenue (including any lease income from space or machines) from gambling activity, excluding State-authorized lottery proceeds.
(k) Businesses deriving income from activities of a prurient sexual nature or illegal activities.
(l) Racetracks or facilities for the conduct of races by animals, professional or amateur drivers, jockeys, etc.
(m) Golf courses and golf course infrastructure, including par 3 and executive golf courses.
(n) Cemeteries.
(o) Research and development projects and projects that involve technology that is not commercially available.
(p) Any project that the Agency determines creates a conflict of interest or an appearance thereof between any party related to the project.
(q) Guarantees where the lender or any of the lender's officers has an ownership interest in the borrower or is an officer or director of the borrower or where the borrower or any of its officers, directors, stockholders, or other owners have more than a 5 percent ownership interest in the lender. Any of the lender's directors, stockholders, or other owners that are officers, directors, stockholders, or other owners of the borrower must be recused from the decisionmaking process.
(r) Other than cooperative stock purchase loans and cooperative equity security guarantees in accordance with § 4279.115, guarantees supporting investment or arbitrage or speculative real estate investment.
(s) Lending institutions, investment institutions, or insurance companies.
(t) Charitable or fraternal organizations. Businesses that derive more than 10 percent of annual gross revenue from tax deductible charitable donations, based on historical financial statements required by § 4279.161(b), are considered charitable organizations for the purpose of this paragraph. Fees for services rendered or that are otherwise ineligible for deduction under the Internal Revenue Code are not considered tax deductible charitable donations.
(u) Any business located within the Coastal Barriers Resource System that does not qualify for an exception as defined in section 6 of the Coastal Barriers Resource Act, 16 U.S.C. 3501 et seq.
(v) Any business located in a special flood or mudslide hazard area as designated by the Federal Emergency Management Agency in a community that is not participating in the National Flood Insurance Program unless the project is an integral part of a community's flood control plan.
(w) Any project that drains, dredges, fills, levels, or otherwise manipulates a wetland or engages in any activity that results in impairing or reducing the flow, circulation, or reach of water, except in the case of activity related to the maintenance of previously converted wetlands. This does not apply to loans for utility lines.
§ 4279.118
[Reserved]
§ 4279.119
Loan guarantee limits.
(a) Loan amount. The total amount of B&I loans to one borrower (including the guaranteed and unguaranteed portions, the outstanding principal and interest balance of any existing B&I guaranteed loans, and the new loan request) must not exceed $10 million, except as outlined in paragraphs (a)(1) and (2) of this section. In addition to the borrower loan limit, there is a guarantor loan limit of $50 million.
(1) The Administrator may, at the Administrator's discretion, grant an exception to the $10 million limit for loans of $25 million or less under the following circumstances:
(i) The project to be financed is a high-priority project as defined in § 4279.2. Priority points will be awarded in accordance with the criteria contained in § 4279.166;
(ii) The lender must document to the satisfaction of the Agency that the loan will not be made and the project will not be completed if the guaranteed loan is not approved; and
(iii) The percentage of guarantee will not exceed 60 percent. No exception to this requirement will be approved under paragraph (b) of this section for loans exceeding $10 million.
(2) The Secretary, whose authority may not be redelegated, may approve guaranteed loans in excess of $25 million, at the Secretary's discretion, for rural cooperative organizations that process value-added agricultural commodities in accordance with § 4279.113(j)(1).
(b) Percentage of guarantee. The percentage of guarantee, up to the maximum allowed by this section, is a matter of negotiation between the lender and the Agency. The maximum percentage of guarantee is 80 percent for loans of $5 million or less, 70 percent for loans between $5 and $10 million, and 60 percent for loans exceeding $10 million. For subsequent guaranteed loans, the maximum percentage of guarantee will be based on the cumulative amount of outstanding principal and interest of any existing B&I guaranteed loans and the new loan request. Notwithstanding the preceding, the Administrator may, at the Administrator's discretion, grant an exception allowing guarantees of up to 90 percent on loans of $5 million or less if the conditions of either paragraph (b)(1) or (b)(2) are met. Each fiscal year, the Agency will establish a limit on the maximum portion of guarantee authority available for that fiscal year that may be used to guarantee loans with an increased percentage of guarantee. The Agency will publish a notice announcing this limit in the Federal Register .
(1) The project to be financed is a high-priority project as defined in § 4279.2. Priority points will be awarded in accordance with the criteria contained in § 4279.166; or
(2) The lender documents, to the satisfaction of the Agency, that the loan will not be made and the project will not be completed due to the bank's legal or regulatory lending limit if the higher percentage of guarantee is not approved.
§ 4279.120
Fees and charges.
There are two types of non-refundable fees—the guarantee fee and the annual renewal fee. These fees are to be paid by the lender but may be passed on to the borrower.
(a) Guarantee fee. The guarantee fee is paid at the time the Loan Note Guarantee is issued and may be included as an eligible use of guaranteed loan proceeds. The amount of the guarantee fee is determined by multiplying the total loan amount by the guarantee fee rate by the percentage of guarantee. The rate of the guarantee fee is established by the Agency in an annual notice published in the Federal Register . Subject to annual limits set by the Agency in the published notice, the Agency may charge a reduced guarantee fee if requested by the lender for loans of $5 million or less when the borrower's business:
(1) Supports value-added agriculture and results in farmers benefiting financially,
(2) Promotes access to healthy foods, or
(3) Is a high impact business development investment as defined in § 4279.2 and applied in accordance with § 4279.166(b)(4) and is located in a rural community that:
(i) Is experiencing long-term population decline;
(ii) Has remained in poverty for the last 30 years;
(iii) Is experiencing trauma as a result of natural disaster;
(iv) Is located in a city or county with an unemployment rate 125 percent of the Statewide rate or greater; or
(v) Is located within the boundaries of a federally recognized Indian tribe's reservation or within tribal trust lands or within land owned by an Alaska Native Regional or Village Corporation as defined by the Alaska Native Claims Settlement Act.
(b) Annual renewal fee. The annual renewal fee is paid by the lender to the Agency once a year. Payment of the annual renewal fee is required in order to maintain the enforceability of the guarantee as to the lender.
(1) The Agency will establish the rate of the annual renewal fee in an annual notice published in the Federal Register . The amount of the annual renewal fee is determined by multiplying the outstanding principal loan balance as of December 31 of each year by the annual renewal fee rate by the percentage of guarantee. The rate that is in effect at the time the loan is obligated remains in effect for the life of the guarantee on the loan.
(2) Annual renewal fees are due on January 31. Payments not received by April 1 are considered delinquent and, at the Agency's discretion, may result in the Agency terminating the guarantee to the lender. The Agency will provide the lender 30 calendar days' notice that the annual renewal fee is delinquent before terminating the guarantee. Holders' rights will continue in effect as specified in Form RD 4279-5, “Loan Note Guarantee,” and Form RD 4279-6, “Assignment Guarantee Agreement,” unless the holder took possession of an interest in the Loan Note Guarantee knowing the annual renewal fee had not been paid. Until the Loan Note Guarantee is terminated by the Agency, any delinquent annual renewal fees will bear interest at the note rate, and any delinquent annual renewal fees, including any interest due thereon, will be deducted from any loss payment due the lender. For loans where the Loan Note Guarantee is issued between October 1 and December 31, the first annual renewal fee payment is due January 31 of the second year following the date the Loan Note Guarantee was issued.
(3) Lenders are prohibited from selling guaranteed loans on the secondary market if there are unpaid annual renewal fees.
(c) Routine lender fees. The lender may establish charges and fees for the loan provided they are similar to those normally charged other applicants for the same type of loan in the ordinary course of business, and these fees are an eligible use of loan proceeds. The lender must document such routine fees on Form RD 4279-1, “Application for Loan Guarantee.” The lender may charge prepayment penalties and late payment fees that are stipulated in the loan documents, as long as they are reasonable and customary; however, the Loan Note Guarantee will not cover either prepayment penalties or late payment fees.
(d) Professional services. Professional services are those rendered by persons generally licensed or certified by States or accreditation associations, such as architects, engineers, accountants, attorneys, or appraisers, and those rendered by loan packagers. The borrower may pay fees for professional services needed for planning and developing a project. Such fees are an eligible use of loan proceeds provided that the Agency agrees that the amounts are reasonable and customary. The lender must document these fees on Form RD 4279-1.
§§ 4279.121-4279.124
[Reserved]
§ 4279.125
Interest rates.
The interest rate for the guaranteed loan will be negotiated between the lender and the borrower and may be either fixed or variable, or a combination thereof, as long as it is a legal rate. Interest rates will not be more than those rates customarily charged borrowers for loans without guarantees and are subject to Agency review and approval. Lenders are encouraged to utilize the secondary market and pass interest-rate savings on to the borrower.
(a) A variable interest rate must be a rate that is tied to a published base rate, published in a national or regional financial publication, agreed to by the lender and the Agency. The variable interest rate must be specified in the promissory note and may be adjusted at different intervals during the term of the loan, but the adjustments may not be more often than quarterly. The lender must incorporate, within the variable rate promissory note at loan closing, the provision for adjustment of payment installments. The lender must fully amortize the outstanding principal balance within the prescribed loan maturity in order to eliminate the possibility of a balloon payment at the end of the loan.
(b) It is permissible to have different interest rates on the guaranteed and unguaranteed portions of the loan provided that the rate of the guaranteed portion does not exceed the rate on the unguaranteed portion, except for situations where a fixed rate on the guaranteed portion becomes a higher rate than the variable rate on the unguaranteed portion due to the normal fluctuations in the approved variable interest rate.
(c) Any change in the base rate or fixed interest rate between issuance of Form RD 4279-3, “Conditional Commitment,” and Form RD 4279-5 must be approved in writing by the Agency. Approval of such change must be shown as an amendment to the Conditional Commitment in accordance with § 4279.173(b) and must be reflected on Form RD 1980-19, “Guaranteed Loan Closing Report.”
(d) The lender's promissory note must not contain provisions for default or penalty interest nor will default or penalty interest, interest on interest, or late payment fees or charges be paid under the Loan Note Guarantee.
§ 4279.126
Loan terms.
(a) The length of the loan term must be the same for both the guaranteed and unguaranteed portions of the loan. The maximum repayment for loans for real estate will not exceed 30 years; machinery and equipment repayment will not exceed the useful life of the machinery and equipment or 15 years, whichever is less; and working capital repayment will not exceed 7 years. The term for a debt refinancing loan may be based on the collateral the lender will take to secure the loan.
(b) A loan's maturity will take into consideration the use of proceeds, the useful life of assets being financed and those used as collateral, and the borrower's ability to repay the loan.
(c) Only loans that require a periodic payment schedule that will retire the debt over the term of the loan without a balloon payment will be guaranteed.
(d) The first installment of principal and interest will, if possible, be scheduled for payment after the facility is operational and has begun to generate income. However, the first full installment must be due and payable within 3 years from the date of the promissory note and be paid at least annually thereafter. In cases where there is an interest-only period, interest will be paid at least annually from the date of the note.
(e) There must be no “due-on-demand” clauses without cause. Regardless of any “due-on-demand” with cause provision in a lender's promissory note, the Agency must concur in any acceleration of the loan unless the basis for acceleration is monetary default.
§§ 4279.127-4279.130
[Reserved]
§ 4279.131
Credit quality.
The Agency will only guarantee loans that are sound and that have a reasonable assurance of repayment. The lender is responsible for conducting a financial analysis that involves the systematic examination and interpretation of information to assess a company's past performance, present condition, and future viability. The lender is primarily responsible for determining credit quality and must address all of the elements of credit quality in a comprehensive, written credit analysis, including capacity (sufficient cash flow to service the debt), collateral (assets to secure the loan), conditions (borrower, economy, and industry), capital (equity/net worth), and character (integrity of management), as further described in paragraphs (a) through (e) of this section. The lender's analysis is the central underwriting document and must be sufficiently detailed to describe the proposed loan and business situation and document that the proposed loan is sound. The lender's analysis must include a written discussion of repayment ability with a cash-flow analysis, history of debt repayment, borrower's management, necessity of any debt refinancing, and credit reports of the borrower, principals, and any parent, affiliate, or subsidiary. The lender's analysis must also include spreadsheets and discussion of the 3 years of historical balance sheets and income statements (for existing businesses) and 2 years of projected balance sheets, income statements, and cash flow statements, with appropriate ratios and comparisons with industrial standards (such as Dun & Bradstreet or the Risk Management Association). All data must be shown in total dollars and also in common size form, obtained by expressing all balance sheet items as a percentage of assets and all income and expense items as a percentage of sales.
(a) Capacity/cash flow. The lender must make all efforts to ensure the borrower has adequate working capital or operating capital and to structure or restructure debt so that the borrower has adequate debt coverage and the ability to accommodate expansion.
(b) Collateral. The lender must ensure that the collateral for the loan has a documented value sufficient to protect the interest of the lender and the Agency. The discounted collateral value must be at least equal to the loan amount.
(1) The lender must discount collateral consistent with the sound loan-to-discounted value policy outlined in paragraphs (b)(1)(i) through (iv) of this section. The type, quality, and location of collateral are relevant factors used to assess collateral adequacy and appropriate levels of discounting. Other factors to be considered in the discounted value of collateral must include the marketability and alternative uses of the collateral. That is, specialized buildings or equipment will be discounted greater than multi-purpose facilities or equipment. When using discounts other than those outlined in paragraphs (b)(1)(i) through (b)(1)(iv) and when in accordance with paragraph (b)(2), the lender must document why such discounts are appropriate.
(i) A maximum of 80 percent of current fair market value will be given to real estate. Special purpose real estate must be assigned less value.
(ii) A maximum of 70 percent of cost or current fair market value will be given to machinery, equipment, and furniture and fixtures and will be based on its marketability, mobility, useful life, specialization, and alternative uses, if any.
(iii) A maximum of 60 percent of book value will be assigned to acceptable inventory and accounts receivable; however, all accounts over 90 days past due, contra accounts, affiliated accounts, and other accounts deemed not to be acceptable collateral, as determined by the Agency, will be omitted. Calculations to determine the percentage to be applied in the analysis are to be based on the realizable value of the accounts receivable taken from a current aging of accounts receivable from the borrower's most recent financial statement. At a minimum, reviewed annual financial statements will be required when there is a predominant reliance on inventory and/or receivable collateral that exceeds $250,000. Except for working capital loans, term debt must not be dependent upon accounts receivable and inventory to meet collateral requirements.
(iv) No value will be assigned to unsecured personal, partnership, or corporate guarantees.
(2) Some businesses are predominantly cash-flow oriented, and where cash flow and profitability are strong, loan-to-value discounts may be adjusted accordingly with satisfactory documentation. A loan primarily based on cash flow must be supported by a successful and documented financial history. Under no circumstances must the loan-to-value of the collateral (loan-to-fair market value) ever be equal to or greater than 100 percent.
(3) Intangible assets cannot serve as primary collateral.
(4) A parity or junior lien position may be considered provided the loan-to-discounted value is adequate to secure the guaranteed loan in accordance with this section.
(5) The entire loan must be secured by the same security with equal lien priority for the guaranteed and unguaranteed portions of the loan. The unguaranteed portion of the loan will neither be paid first nor given any preference or priority over the guaranteed portion.
(c) Conditions. The lender must consider the current status of the borrower, overall economy, and industry for which credit is being extended. The regulatory environment surrounding the particular business or industry must also be considered. Businesses in areas of decline will be required to provide strong business plans that outline how they differ from the current trends. Local, regional, and national condition of the industry must be addressed.
(d) Capital/equity. (1) A minimum of 10 percent tangible balance sheet equity (or a maximum debt to tangible net worth ratio of 9:1) will be required at loan closing for borrowers that are existing businesses. A minimum of 20 percent tangible balance sheet equity (or a maximum debt to tangible net worth ratio of 4:1) will be required at loan closing for borrowers that are new businesses. For energy projects, the minimum tangible balance sheet equity requirement range will be between 25 percent and 40 percent (or a maximum debt to tangible net worth ratio between 3:1 and 1.5:1) at loan closing, considering whether the business is an existing business with a successful financial and management history or a new business; the value of personal/corporate guarantees offered; contractual relationships with suppliers and buyers; credit rating; and strength of the business plan/feasibility study.
(2) Tangible balance sheet equity will be determined based upon financial statements prepared in accordance with GAAP. The capital/equity requirement must be met in the form of either cash or tangible earning assets contributed to the business and reflected on the borrower's balance sheet. Transfers of assets at fair market value between related parties, which are not arm's length transactions, must be in accordance with GAAP and require evidence that the transaction was entered into at market terms. Tangible equity cannot include appraisal surplus, bargain purchase gains, or intangible assets. Owner subordinated debt may be included when the subordinated debt is in exchange for cash injected into the business that remains in the business for the life of the guaranteed loan. The note or other form of evidence must be submitted to the Agency in order for subordinated debt to count towards meeting the tangible balance sheet equity requirement.
(3) The lender must certify, in accordance with § 4279.181(a)(9)(i), that the capital/equity requirement was determined, based on a balance sheet prepared in accordance with GAAP, and met, as of the date the guaranteed loan was closed, giving effect to the entirety of the loan in the calculation, whether or not the loan itself is fully advanced. A copy of the loan closing balance sheet must be included with the lender's certification.
(4) In situations where a real estate holding company and an operating entity are dependent upon one another's operations and are effectively one business, they must be co-borrowers, unless waived by the Agency when the Agency determines that adequate justification exists to not require the entities to be co-borrowers. The capital/equity requirement will apply to all borrowing entities on a consolidated basis, and financial statements must be prepared both individually and on a consolidated basis.
(5) In situations where co-borrowers are independent operations, the capital/equity requirement will apply to all co-borrowers on an individual basis.
(6) For sole proprietorships and other situations where business assets are held personally, financial statements must be prepared using only the assets and liabilities directly attributable to the business. Assets, plus any improvements, must be valued at the lower of cost or fair market value.
(7) Increases in the equity requirement may be imposed by the Agency. A reduction in the capital/equity requirement for existing businesses may be permitted by the Administrator under the following conditions:
(i) Collateralized personal and/or corporate guarantees, in accordance with § 4279.132, when feasible and legally permissible, are obtained; and
(ii) All pro forma and historical financial statements indicate the business to be financed meets or exceeds the median quartile (as identified in the Risk Management Association's Annual Statement Studies or similar publication) for the current ratio, quick ratio, debt-to-worth ratio, and debt coverage ratio.
(e) Character. The lender must conduct a thorough review of key management personnel to ensure that the business has adequately trained and experienced managers. The borrower and all owners with a 20 percent or more ownership interest must have a good credit history, reflecting a record of meeting obligations in a timely manner. If there have been credit problems in the past, the lender must provide a satisfactory explanation to show that the problems are unlikely to recur.
§ 4279.132
Personal and corporate guarantees.
(a) Full, unconditional personal and/or corporate guarantees for the full term of the loan are required from those owning 20 percent or more interest in the borrower, where legally permissible, unless the Agency grants an exception. The Agency may grant an exception for existing businesses only when the lender requests it and documents to the Agency's satisfaction that collateral, equity, cash flow and profitability indicate an above-average ability to repay the loan. Partial guarantees for the full term of the loan at least equal to each owner's percentage of interest in the borrower times the loan amount may be required in lieu of full, unconditional guarantees when the guarantors' percentages equal 100 percent so that the loan is fully guaranteed.
(b) When warranted by an Agency assessment of potential financial risk, the Agency may require the following:
(1) Guarantees to be secured;
(2) Guarantees of parent, subsidiaries, or affiliated companies owning less than a 20 percent interest in the borrower; and
(3) Guarantees from persons whose ownership interest in the borrower is held indirectly through intermediate entities.
(c) All personal and corporate guarantors must execute Form RD 4279-14, “Unconditional Guarantee,” and any guarantee form required by the lender. The Agency will retain the original, executed Form RD 4279-14.
(1) Any amounts paid by the Agency on behalf of an Agency guaranteed loan borrower will constitute a Federal debt owed to the Agency by the guaranteed loan borrower.
(2) Any amounts paid by the Agency pursuant to a claim by a guaranteed program lender will constitute a Federal debt owed to the Agency by a guarantor of the loan, to the extent of the amount of the guarantor's guarantee.
(3) In all instances under paragraphs (c)(1) and (2) of this section, interest charges will be assessed in accordance with 7 CFR 1951.133.
§§ 4279.133-4279.135
[Reserved]
§ 4279.136
Insurance.
The lender is responsible for ensuring that required insurance is maintained by the borrower.
(a) Hazard. Hazard insurance with a standard clause naming the lender as mortgagee or loss payee, as applicable, is required for the life of the guaranteed loan. The amount must be at least equal to the replacement value of the collateral or the outstanding balance of the loan, whichever is the greater amount.
(b) Life. The lender may require a collateral assignment of life insurance to insure against the risk of death of persons critical to the success of the business. When required, coverage must be in amounts necessary to provide for management succession or to protect the business. The Agency may require life insurance on key individuals for loans where the lender has not otherwise proposed such coverage. The cost of insurance and its effect on the applicant's working capital must be considered, as well as the amount of existing insurance that could be assigned without requiring additional expense.
(c) Worker compensation. Worker compensation insurance is required in accordance with State law.
(d) Flood. National flood insurance is required in accordance with applicable law.
(e) Other. The lender must consider whether public liability, business interruption, malpractice, and other insurance is appropriate to the borrower's particular business and circumstances and must require the borrower to obtain such insurance as is necessary to protect the interests of the borrower, the lender, or the Agency.
§ 4279.137
Financial statements.
Except for audited financial statements required by § 4279.71, the lender will determine the type and frequency of submission of financial statements by the borrower and any guarantors. At a minimum, annual financial statements prepared by an accountant in accordance with GAAP are required, except for personal financial statements and cooperative stock purchase loans in accordance with § 4279.115(a) that do not have to be prepared in accordance with GAAP. However, if the loan amount exceeds $10 million or if circumstances warrant, the Agency may require annual audited financial statements.
§§ 4279.138-4279.143
[Reserved]
§ 4279.144
Appraisals.
Lenders must obtain appraisals for real estate and chattel collateral when the value of the collateral exceeds $250,000. For collateral values under this threshold, lenders must follow their primary regulator's policies relating to appraisals and evaluations or, if the lender is not regulated, normal banking practices and generally accepted methods of determining value. Lenders must use the fair market value as established by the appraisal and discounting policies outlined in § 4279.131(b) to meet the discounted collateral coverage requirements of this subpart. Lenders are responsible for ensuring that appraisal values adequately reflect the actual value of the collateral. The Agency will require documentation that the appraiser has the necessary experience and competency to appraise the property in question. Appraisals must not be more than 1 year old, and a more recent appraisal may be requested by the Agency in order to reflect more current market conditions. For loan servicing purposes, an appraisal may be updated in lieu of a complete new appraisal when the original appraisal is more than 1 year old but less than 2 years old. Failure by the lender to follow these requirements will be considered not acting in a reasonably prudent manner.
(a) All real property appraisals associated with Agency guaranteed loanmaking and servicing transactions must meet the requirements contained in the Financial Institutions Reform, Recovery and Enforcement Act (FIRREA) of 1989, and the appropriate guidelines contained in Standards 1 and 2 of the Uniform Standards of Professional Appraisal Practices (USPAP) and be performed by a State Certified General Appraiser. Notwithstanding any exemption that may exist for transactions guaranteed by a Federal government agency, all appraisals obtained by the lender for loanmaking and servicing must conform to the Interagency Appraisal and Evaluations Guidelines established by the lender's primary Federal or State regulator. All appraisals must include consideration of the potential effects from a release of hazardous substances or petroleum products or other environmental hazards on the fair market value of the collateral, if applicable. The lender must complete and submit its technical review of the appraisal. For construction projects, the lender must use the “as-completed” market value of the real estate to determine value of the real estate property.
(b) Values of both tangible and intangible assets, including values attributed to business valuation or as a going concern, must be reported individually/separately in the appraisal as values attributed to business valuation or as a going concern will be deducted from the reconciled fair market value of the hard assets for purposes of calculating collateral coverage.
(c) Chattels with values under the $250,000 threshold must be evaluated in accordance with the lender's primary regulator's policies relating to appraisals and evaluations or, if the lender is not regulated, normal banking practices and generally accepted methods of determining value. Chattel appraisals must reflect the age, condition, and remaining useful life of the equipment. If the appraisal is completed by a State licensed/certified appraiser, the appraisal report must comply with USPAP Standards 7 and 8.
§§ 4279.145-4279.149
[Reserved]
§ 4279.150
Feasibility studies.
A feasibility study, by a qualified independent consultant acceptable to the Agency, is required for new businesses. The Agency may require a feasibility study for existing businesses when the project will significantly affect the borrower's operations, and cash flow from the existing facility is not sufficient to service the new debt. At a minimum, a feasibility study must include an evaluation of the economic, market, technical, financial, and management feasibility and an executive summary that reaches an overall conclusion as to the business' chance of success. The income approach of an appraisal is not an acceptable feasibility study.
§§ 4279.151-4279.160
[Reserved]
§ 4279.161
Filing preapplications and applications.
Borrowers and lenders are encouraged to file preapplications and obtain Agency comments before completing an application. However, if they prefer, borrowers and lenders may file a complete application without filing a preapplication. The Agency will neither accept nor process preapplications and applications unless a lender has agreed to finance the proposal. For borrowers other than individuals, a Dun and Bradstreet Universal Numbering System (DUNS) number is required, which can be obtained online at http://fedgov/dnd.com/webform . Guaranteed loans exceeding $600,000 must be submitted under the requirements specified in paragraph (b) of this section. However, guaranteed loans of $600,000 and less may be submitted under the requirements of either paragraph (b) or (c) of this section.
(a) Preapplications. Lenders may file preapplications by submitting the following to the Agency:
(1) A letter or preliminary lender credit analysis, signed by the lender, containing the following:
(i) Name of the proposed borrower, organization type, address, contact person, Federal tax identification number, email address, and telephone number;
(ii) Name of the proposed lender, address, telephone number, contact person, email address, and lender's Internal Revenue Service (IRS) identification number;
(iii) Amount of the loan request, percent of guarantee requested, and the proposed rates and terms;
(iv) Description of collateral to be offered with estimated value(s) and the amount and source of equity to be contributed to the project;
(v) A brief description of the project, products or services provided, and availability of raw materials and supplies; and
(vi) The number of current full-time equivalent jobs, the number of jobs to be created as a result of the proposed loan, and the overall average wage rate.
(2) The borrower's current (not more than 90 days old) balance sheet and year-to-date income statement. For existing businesses, also include balance sheets and income statements for the last 3 years; and
(3) A completed Form RD 4279-2, “Certification of Non-Relocation and Market Capacity Information Report,” if the proposed loan is in excess of $1 million and will increase direct employment by more than 50 employees.
(b) Applications. Lenders must submit the information specified in paragraphs (b)(1) through (19) of this section when filing an application with the Agency.
(1) A completed Form RD 4279-1.
(2) A completed Form RD 4279-2, if the proposed loan is in excess of $1 million and will increase direct employment by more than 50 employees, unless already submitted in accordance with § 4279.161(a)(3).
(3) Environmental review documentation in accordance with 7 CFR part 1970, “Environmental Policies and Procedures,” or successor regulation.
(4) A personal or commercial credit report from an acceptable credit reporting company for each individual or entity owning 20 percent or more interest in the borrower, except for those corporations listed on a major stock exchange. Credit reports are not required for elected and appointed officials when the applicant is a public body or non-profit corporation.
(5) Commercial credit reports for the borrower(s) and any parent, affiliate, and subsidiary companies.
(6) Current (not more than 90 days old) financial statements for any parent, affiliate, and subsidiary companies.
(7) Current (not more than 90 days old) personal and corporate financial statements of any guarantors.
(8) For all borrowers, a current (not more than 90 days old) balance sheet and year-to-date income statement, a pro forma balance sheet projected for loan closing, and projected balance sheets, income statements, and cash flow statements for the next 2 years. Projections must be prepared in line with GAAP standards and supported by a list of assumptions showing the basis for the projections. In the event processing of the loan is not complete within 90 days, a current set of financial statements will be required every 90 days.
(9) For borrowers that are existing businesses, balance sheets and income statements for the last 3 years. If the business has been in operation for less than 3 years, balance sheets and income statements for all years for which financial information is available.
(10) The lender's comprehensive, written credit analysis of the proposal, as described in § 4279.131.
(11) A draft loan agreement. A final loan agreement must be executed by the lender and borrower before the Agency issues a Loan Note Guarantee and must contain any additional requirements imposed by the Agency in its Conditional Commitment. The loan agreement must establish prudent, adequate controls to protect the interests of the lender and Agency. At a minimum, the following requirements must be included in the loan agreement:
(i) Type and frequency of borrower and guarantor financial statements to be required for the duration of the loan;
(ii) Prohibition against assuming liabilities or obligations of others;
(iii) Limitations on dividend payments and compensation of officers and owners;
(iv) Limitation on the purchase and sale of equipment and other fixed assets;
(v) Restrictions concerning consolidations, mergers, or other circumstances and a limitation on selling the business without the concurrence of the lender;
(vi) Maximum debt-to-net worth ratio; and
(vii) Minimum debt service coverage ratio.
(12) Intergovernmental consultation comments in accordance with 2 CFR part 415, subpart C, or successor regulation, unless exemptions have been granted by the State single point of contact.
(13) Appraisals, accompanied by a copy of the appropriate environmental site assessment, if available, and the technical review of the appraisals required by § 4279.144(a).
(14) A business plan or similar document that must include a description of the business and project; management experience; sources of capital; products, services, and pricing; marketing plan; proposed use of funds; availability of labor, raw materials, and supplies; contracts in place; distribution channels; and the names of any corporate parent, affiliates, and subsidiaries with a description of the relationship. A business plan may be omitted if the information is included in a feasibility study. A business plan may also be omitted when loan proceeds are used exclusively for debt refinancing and fees.
(15) Independent feasibility study, if required.
(16) For companies listed on a major stock exchange or subject to the Securities and Exchange Commission regulations, a copy of SEC Form 10-K, “Annual Report Pursuant to sections 13 or 15(d) of the Securities Exchange Act of 1934.”
(17) For health care facilities, a certificate of need, if required by statute or State law.
(18) For guaranteed loan applications for five or more residential units, including nursing homes and assisted-living facilities, an Affirmative Fair Housing Marketing Plan that is in conformance with 7 CFR 1901.203(c)(3).
(19) Any additional information required by the Agency to make a decision, including any information needed to score the project in accordance with § 4279.166.
(c) Applications of $600,000 and less. Guaranteed loan applications may be processed under this paragraph if the request does not exceed $600,000, provided the Agency determines that there is not a significant increased risk of a default on the loan. A lender may need to resubmit an application under paragraph (b) of this section if the application under this paragraph does not contain sufficient information for the Agency to make a decision to guarantee the loan. Applications submitted under this paragraph must include the information contained in paragraphs (b)(1) (with the short application box marked at the top of Form RD 4279-1), (b)(3), (b)(8) through (10), (b)(12), and (b)(13) of this section. The lender must have the documentation identified in paragraph (b) of this section, with the exception of paragraph (b)(2), available in its file for review.
§§ 4279.162-4279.164
[Reserved]
§ 4279.165
Evaluation of application.
(a) General review. The Agency will evaluate the application and make a determination whether the borrower is eligible, the proposed loan is for an eligible purpose, there is reasonable assurance of repayment ability, there is sufficient collateral and equity, and the proposed loan complies with all applicable statutes and regulations. If the Agency determines it is unable to guarantee the loan, it will inform the lender in writing.
(b) Environmental requirements. The environmental review process must be completed, in accordance with 7 CFR part 1970, “Environmental Policies and Procedures,” or successor regulation, prior to loan approval.
§ 4279.166
Loan priority scoring.
The Agency will consider applications and preapplications in the order they are received by the Agency; however, for the purpose of assigning priority points as described in paragraph (b) of this section, the Agency will compare an application to other pending applications that are competing for funding. The Agency may establish a minimum loan priority score to fund projects from the National Office reserve and will publish any minimum loan priority score in a notice published in the Federal Register .
(a) When applications on hand otherwise have equal priority, the Agency will give preference to applications for loans from qualified veterans.
(b) The Agency will assign priority points on the basis of the point system contained in this section. The Agency will use the application and supporting information to determine an eligible proposed project's priority for available guarantee authority. To the extent possible, all lenders must consider Agency priorities when choosing projects for guarantee. The lender must provide necessary information related to determining the score, if requested.
(1) Population priority. Projects located in an unincorporated area or in a city with a population under 25,000 (10 points).
(2) Demographics priority. The priority score for demographics priority will be the total score for the following categories:
(i) Located in an eligible area of long-term population decline according to the last three decennial censuses (5 points);
(ii) Located in a rural county that has had 20 percent or more of its population living in poverty based on the last three decennial censuses (10 points);
(iii) Located in a rural community that is experiencing trauma as a result of natural disaster (5 points);
(iv) Located in a city or county with an unemployment rate 125 percent of the Statewide rate or greater (5 points);
(v) Located within the boundaries of a Federally recognized Indian tribe's reservation, within tribal trust lands, or within land owned by an Alaska Native Regional or Village Corporation as defined by the Alaska Native Claims Settlement Act (5 points); and
(vi) Business is owned by a qualified veteran as defined by § 4279.2 (5 points).
(3) Loan features. The priority score for loan features will be the total score for each of the following categories:
(i) Lender will price the guaranteed loan at an interest rate equal to or less than the equivalent of the Wall Street Journal published Prime Rate plus 1.5 percent (5 points);
(ii) Lender will price the guaranteed loan at an interest rate equal to or less than the equivalent of the Wall Street Journal published Prime Rate plus 1 percent (5 points);
(iii) The Agency guaranteed loan is less than 60 percent of project cost (5 points);
(iv) The Agency guaranteed loan is less than 50 percent of project cost (5 points);
(v) The Agency guaranteed loan is less than 40 percent of project cost (5 points); and
(vi) For loans not requesting an exception under § 4279.119(b), the percentage of guarantee is 10 or more percentage points less than the maximum allowable for a loan of its size (5 points).
(4) High impact business investment priorities. The priority score for high impact business investment will be the total score for the following categories:
(i) Business/industry. The priority score for business/industry will be the total score for the following:
(A) Industry that is not already present in the community (5 points);
(B) Business that has 20 percent or more of its sales in international markets (5 points);
(C) Business that offers high value, specialized products and/or services that command high prices (5 points);
(D) Business that provides an additional market for existing local businesses (5 points);
(E) Business that is locally owned and managed (5 points);
(F) Business that will produce a natural resource value-added product (5 points); and
(G) Business that processes, distributes, aggregates, stores, and/or markets locally or regionally produced agricultural food products to underserved communities in accordance with § 4279.113(y)(5) (10 points).
(ii) Occupations. The priority score for occupations will be the total score for the following:
(A) Business that creates or saves jobs with an average wage exceeding 125 percent of the Federal minimum wage (5 points);
(B) Business that creates or saves jobs with an average wage exceeding 150 percent of the Federal minimum wage (5 points); and
(C) Business that offers a healthcare benefits package to all employees, with at least 50 percent of the premium paid by the employer (5 points).
(5) Administrative points. The State Director may assign up to 10 additional points to an application to account for Statewide distribution of funds, natural disasters or economic emergency conditions, community economic development strategies, State strategic plans, fundamental structural changes in a community's economic base, or projects that will fulfill an Agency initiative. In addition to the State Director assigned points, if an application is considered in the National Office, the Administrator may assign up to an additional 10 points to account for geographic distribution of funds, emergency conditions caused by economic problems or natural disasters, or projects that will fulfill an Agency initiative.
§ 4279.167
Planning and performing development.
(a) Design policy. The lender must ensure that all facilities constructed with program funds are designed, and costs estimated, by an independent professional, utilizing accepted architectural, engineering, and design practices. The Agency may require an independent professional architect on complex projects. The lender must ensure the design conforms to applicable Federal, State, and local codes and requirements. The lender must also ensure that the project will be completed with available funds and, once completed, will be used for its intended purpose and produce in the quality and quantity proposed in the completed application approved by the Agency. Once construction is completed, the lender must provide the Agency with a copy of the Notice of Completion or similar document issued by the relevant building jurisdiction.
(b) Issuing the Loan Note Guarantee prior to project completion. If the lender requests that the Loan Note Guarantee be issued prior to construction or completion of a project, the lender must have a construction monitoring plan acceptable to the Agency and undertake the added responsibilities set forth in this paragraph. The lender must monitor the progress of construction and undertake the reviews and inspections necessary to ensure that construction conforms to applicable Federal, State, and local code requirements; proceeds are used in accordance with the approved plans, specifications, and contract documents; and that funds are used for eligible project costs. The lender must expeditiously report any problems in project development to the Agency.
(1) In cases of takeout of interim financing where the Loan Note Guarantee is issued prior to construction or completion of a project, the promissory note must contain the terms and conditions of the interim financing and the permanent financing and convert the interim financing to the permanent note as the Loan Note Guarantee can only be placed on one note.
(2) Prior to disbursement of construction funds, the lender must have:
(i) A complete set of plans and specifications for the project on file;
(ii) A detailed timetable for the project with a corresponding budget of costs setting forth the parties responsible for payment. The timetable and budget must be agreed to by the borrower;
(iii) A person, who may be the project architect or engineer, with demonstrated experience relating to the project's industry, confirm that the budget is adequate for the planned development;
(iv) A firm, fixed-price construction contract with an independent general contractor with costs and provisions for change order approvals, a retainage percentage, and a disbursement schedule; a 100 percent performance/payment bond on the borrower's contractor; or a contract with an independent disbursement and monitoring firm where project construction and completion are guaranteed. A bonding agent must be listed on Treasury Circular 570; and
(v) Contingencies in place to handle unforeseen cost overruns without seeking additional guaranteed assistance. These are to be agreed to by the borrower.
(3) Once construction begins, the lender is to:
(i) Use any borrower funds in the project first;
(ii) Ensure that the project is built to support the functions at the level and quality contemplated by the borrower through the use of accepted architectural and engineering practices. There is no absolute requirement that the goal be achieved by the use of a professional inspection. However, if after careful review, it appears that the use of a professional inspector is the only method that ensures the project is built to support the functions at the level and quality contemplated by the borrower through the use of accepted architectural and engineering practices, one may be required by the Agency. If one is required, inspections must be made by a qualified, independent inspector prior to any progress payment. If other less expensive or rigorous methods will achieve the same result, they may be utilized. The decision will be made on a case-by-case basis and must be reasonable under the specific circumstances of the case;
(iii) Obtain lien waivers from all contractors and materialmen prior to any disbursement; and
(iv) Provide at least monthly, written reports to the Agency on fund disbursement and project status.
(4) Once construction is completed, the lender is to provide the Agency with a copy of the Notice of Completion or similar document issued by the relevant building jurisdiction.
(c) Compliance with other Federal laws. Lenders must comply with other applicable Federal laws, including Equal Employment Opportunities, the Equal Credit Opportunity Act, the Fair Housing Act, and the Civil Rights Act of 1964. Guaranteed loans that involve the construction of or addition to facilities that accommodate the public must comply with the Architectural Barriers Act Accessibility Standard. The borrower and lender are responsible for ensuring compliance with these requirements.
(d) Environmental responsibilities. The lender must ensure that the borrower has:
(1) Provided the necessary environmental information to enable the Agency to undertake its environmental review process in accordance with 7 CFR part 1970, “Environmental Policies and Procedures,” or successor regulation, including the provision of all required Federal, State, and local permits;
(2) Complied with any mitigation measures required by the Agency; and
(3) Not taken any actions or incurred any obligations with respect to the proposed project that would either limit the range of alternatives to be considered during the Agency's environmental review process or that would have an adverse effect on the environment.
§ 4279.168
Timeframe for processing applications.
All complete guaranteed loan applications will be approved or disapproved within 60 days, unless approval is prevented by a lack of guarantee authority or there are delays resulting from public comment requirements of the environmental assessment or outstanding DOL clearance issues.
§§ 4279.169-4279.172
[Reserved]
§ 4279.173
Loan approval and obligating funds.
(a) Upon approval of a loan guarantee, the Agency will issue a Conditional Commitment to the lender, containing conditions under which a Loan Note Guarantee will be issued. No Conditional Commitment can be issued until the loan is obligated. If a Loan Note Guarantee is not issued by the Conditional Commitment expiration date, the Conditional Commitment may be extended at the request of the lender and only if there has been no material adverse change in the borrower or the borrower's financial condition since issuance of the Conditional Commitment. If the Conditional Commitment is not accepted, the Conditional Commitment may be withdrawn and funds may be deobligated. Likewise, if the Conditional Commitment expires, funds may be deobligated.
(b) If certain conditions of the Conditional Commitment cannot be met, the lender and borrower may request changes to the Conditional Commitment. Within the requirements of the applicable regulations and prudent lending practices, the Agency may negotiate with the lender and the borrower regarding any proposed changes to the Conditional Commitment. Any changes to the Conditional Commitment must be documented by written amendment to the Conditional Commitment.
(c) The borrower must comply with all Federal requirements then in effect for receiving Federal assistance.
§ 4279.174
Transfer of lenders.
(a) The Agency may approve the substitution of a new eligible lender in place of a former lender who has been issued and has accepted an outstanding Conditional Commitment when the Loan Note Guarantee has not yet been issued, provided that there are no changes in the borrower's ownership or control, loan purposes, or scope of project, and the loan terms and conditions in the Conditional Commitment and the loan agreement remain the same. Any request for a transfer of lender must be submitted in writing by the current lender, the proposed lender, and the borrower. The original lender must state the reason(s) it no longer desires to be the lender for the project.
(b) Unless the new lender is already an approved lender, the Agency will analyze the new lender's servicing capability, eligibility, and experience prior to approving the substitution. The substituted lender must execute a new part B of Form 4279-1, “Application for Loan Guarantee;” Form RD 4279-4, “Lender's Agreement” (unless a valid Lender's Agreement with the Agency already exists); and complete a new lender's analysis in accordance with § 4279.131. The new lender may also be required to provide other updated application items outlined in § 4279.161(b).
§§ 4279.175-4279.179
[Reserved]
§ 4279.180
Changes in borrower.
Any changes in borrower ownership or organization prior to the issuance of the Loan Note Guarantee must meet the eligibility requirements of the program and be approved by the Agency.
§ 4279.181
Conditions precedent to issuance of the Loan Note Guarantee.
(a) The lender must not close the loan until all conditions of the Conditional Commitment are met. When loan closing plans are established, the lender must notify the Agency. Coincident with, or immediately after loan closing, the lender must provide the following to the Agency:
(1) An executed Form RD 4279-4, unless a valid Lender's Agreement exists that was issued after August 2, 2016;
(2) Form RD 1980-19 and appropriate guarantee fee;
(3) Copy of the executed promissory note(s);
(4) Copy of the executed loan agreement;
(5) Copy of the executed settlement statement;
(6) Original, executed Forms RD 4279-14, as required;
(7) Any other documents required to comply with applicable law or required by the Conditional Commitment.
(8) Borrower's loan closing balance sheet, supporting paragraph (a)(9)(i) of the lender certification, demonstrating required tangible balance sheet equity; and
(9) The lender's certification to each of the following certifications:
(i) The capital/equity requirement was determined, based on a balance sheet prepared in accordance with GAAP, and met, as of the date the guaranteed loan was closed, giving effect to the entirety of the loan in the calculation, whether or not the loan itself is fully advanced.
(ii) All requirements of the Conditional Commitment have been met.
(iii) No major changes have been made in the lender's loan conditions and requirements since the issuance of the Conditional Commitment, unless such changes have been approved by the Agency in writing.
(iv) There is a reasonable prospect that the guaranteed loan and other project debt will be repaid on time and in full (including interest) from project cash flow according to the terms proposed in the application for loan guarantee.
(v) All planned property acquisition has been or will be completed, all development has been or will be substantially completed in accordance with plans and specifications, conforms with applicable Federal, State, and local codes, and costs have not exceeded the amount approved by the lender and the Agency.
(vi) The borrower has marketable title to the collateral then owned by the borrower, subject to the instrument securing the loan to be guaranteed and to any other exceptions approved in writing by the Agency.
(vii) The loan has been properly closed, and the required security instruments have been properly executed or will be obtained on any acquired property that cannot be covered initially under State law.
(viii) Lien priorities are consistent with the requirements of the Conditional Commitment. No claims or liens of laborers, subcontractors, suppliers of machinery and equipment, materialmen, or other parties have been filed against the collateral, and no suits are pending or threatened that would adversely affect the collateral.
(ix) When required, personal and/or corporate guarantees have been obtained in accordance with § 4279.132.
(x) The loan proceeds have been or will be disbursed for purposes and in amounts consistent with the Conditional Commitment (or Agency-approved amendment thereof) and the application submitted to the Agency. When applicable, the entire amount of the loan for working capital has been disbursed to the borrower, except in cases where the Agency has approved disbursement over an extended period of time and funds are escrowed so that the settlement statement reflects the full amount to be disbursed.
(xi) All truth-in-lending and equal credit opportunity requirements have been met.
(xii) There has been neither any material adverse change in the borrower's financial condition nor any other material adverse change in the borrower, for any reason, during the period of time from the Agency's issuance of the Conditional Commitment to the issuance of the Loan Note Guarantee regardless of the cause or causes of the change and whether or not the change or causes of the change were within the lender's or borrower's control. The lender must address any assumptions or reservations in the requirement and must address all adverse changes of the borrower, any parent, affiliate, or subsidiary of the borrower, and guarantors.
(xiii) Neither the lender nor any of the lender's officers has an ownership interest in the borrower or is an officer or director of the borrower, and neither the borrower nor its officers, directors, stockholders, or other owners have more than a 5 percent ownership interest in the lender.
(xiv) The loan agreement includes all measures identified in the Agency's environmental impact analysis for this proposal with which the borrower must comply for the purpose of avoiding or reducing adverse environmental impacts of the project's construction or operation.
(xv) If required, hazard, flood, liability, workers compensation, and life insurance are in effect.
(b) The Agency may, at its discretion, request copies of additional loan documents for its file.
(c) When the Agency is satisfied that all conditions for the guarantee have been met, the Agency will issue the Loan Note Guarantee and the following documents, as appropriate.
(1) Assignment Guarantee Agreement. In the event the lender uses the single note option and assigns the guaranteed portion of the loan to a holder, the lender, holder, and the Agency will execute Form RD 4279-6 in accordance with § 4279.75(a); and
(2) Certificate of Incumbency. If requested by the lender, the Agency will provide the lender with a certification on Form RD 4279-7, “Certificate of Incumbency and Signature,” of the signature and title of the Agency official who signs the Loan Note Guarantee, Lender's Agreement, and Assignment Guarantee Agreement.
§§ 4279.182-4279.186
[Reserved]
§ 4279.187
Refusal to execute Loan Note Guarantee.
If the Agency determines that it cannot execute the Loan Note Guarantee, the Agency will promptly inform the lender of the reasons and give the lender a reasonable period within which to satisfy the objections. If the lender satisfies the objections within the time allowed, the Agency will issue the Loan Note Guarantee. If the lender requests additional time in writing and within the period allowed, the Agency may grant the request.
§§ 4279.188-4279.199
[Reserved]
§ 4279.200
OMB control number.
In accordance with the Paperwork Reduction Act of 1995, the information collection requirements contained in this rule have been submitted to the Office of Management and Budget (OMB) under OMB Control Number 0570-0069 for OMB approval.

PART 4287—SERVICING
4. The authority citation for part 4287 is revised to read as follows:

Authority:
5 U.S.C. 301; 7 U.S.C. 1932(a); 7 U.S.C. 1989.
5. Revise Subpart B to read as follows:

Subpart B—Servicing Business and Industry Guaranteed Loans
Sec.
4287.101
Introduction.
4287.102
Definitions and abbreviations.
4287.103
Exception authority.
4287.104-4287.105
[Reserved]
4287.106
Appeals.
4287.107
Routine servicing.
4287.108-4287.111
[Reserved]
4287.112
Interest rate changes.
4287.113
Release of collateral.
4287.114-4287.122
[Reserved]
4287.123
Subordination of lien position.
4287.124
Alterations of loan instruments.
4287.125-4287.132
[Reserved]
4287.133
Sale of corporate stock.
4287.134
Transfer and assumption.
4287.135
Substitution of lender.
4287.136
Lender failure.
4287.137-4287.144
[Reserved]
4287.145
Default by borrower.
4287.146-4287.155
[Reserved]
4287.156
Protective advances.
4287.157
Liquidation.
4287.158
Determination of loss and payment.
4287.159-4287.168
[Reserved]
4287.169
Future recovery.
4287.170
Bankruptcy.
4287.171-4287.179
[Reserved]
4287.180
Termination of guarantee.
4287.181-4287.199
[Reserved]
4287.200
OMB control number.

Subpart B—Servicing Business and Industry Guaranteed Loans
§ 4287.101
Introduction.
(a) This subpart supplements subparts A and B of part 4279 of this chapter by providing additional requirements and instructions for servicing and liquidating all B&I Guaranteed Loans. This includes Drought and Disaster, Disaster Assistance for Rural Business Enterprises, Business and Industry Disaster, and American Recovery and Reinvestment Act guaranteed loans.
(b) The lender is responsible for servicing the entire loan and must remain mortgagee and secured party of record, notwithstanding the fact that another party may hold a portion of the loan.
(c) Whether specifically stated or not, whenever Agency approval is required, it must be in writing. Copies of all forms and regulations referenced in this subpart may be obtained from any Agency office and from the USDA Rural Development Web site at http://www.rd.usda.gov/publications. Whenever a form is designated in this subpart, that designation includes predecessor and successor forms, if applicable, as specified by the Agency.
§ 4287.102
Definitions and abbreviations.
The definitions and abbreviations contained in § 4279.2 of this chapter apply to this subpart.
§ 4287.103
Exception authority.
Section 4279.15 of this chapter applies to this subpart.
§§ 4287.104-4287.105
[Reserved]
§ 4287.106
Appeals.
Section 4279.16 of this chapter applies to this subpart.
§ 4287.107
Routine servicing.
The lender is responsible for servicing the entire loan and for taking all servicing actions that a reasonably prudent lender would perform in servicing its own portfolio of loans that are not guaranteed. The lender may contract for services but is ultimately responsible for underwriting, loan origination, loan servicing, and compliance with all Agency regulations. Form RD 4279-4, “Lender's Agreement,” is the contractual agreement between the lender and the Agency that sets forth some of the lender's loan servicing responsibilities. These responsibilities include, but are not limited to, periodic borrower visits, the collection of payments, obtaining compliance with the covenants and provisions in the loan agreement, obtaining and analyzing financial statements, ensuring payment of taxes and insurance premiums, maintaining liens on collateral, keeping an inventory accounting of all collateral items, and reconciling the inventory of all collateral sold during loan servicing, including liquidation.
(a) Lender reports and annual renewal fee. The lender must report the outstanding principal and interest balance and the current loan classification on each guaranteed loan semiannually (at June 30 and December 31), using either the USDA Lender Interactive Network Connection (LINC) system or Form RD 1980-41, “Guaranteed Loan Status Report.” The lender must transmit the annual renewal fee to the Agency in accordance with § 4279.120(b) of this chapter calculated based on the December 31 semiannual status report.
(b) Loan classification. The lender must provide the loan classification or rating under its regulatory standards as of loan closing, using either the LINC system or Form 1980-19, “Guaranteed Loan Closing Report.” When the lender changes the loan classification in the future, the lender must notify the Agency within 30 days, in writing, of any change in the loan classification.
(c) Agency and lender conference. At the Agency's request, the lender must consult with the Agency to ascertain how the guaranteed loan is being serviced and that the conditions and covenants of the loan agreement are being enforced.
(d) Borrower financial reports. The lender must obtain, analyze, and forward to the Agency the borrower's and any guarantor's annual financial statements required by the loan agreement within 120 days of the end of the borrower's fiscal year. The lender must analyze these financial statements and provide the Agency with a written summary of the lender's analysis, ratio analysis, and conclusions, which, at a minimum, must include trends, strengths, weaknesses, extraordinary transactions, violations of loan covenants and covenant waivers proposed by the lender, any routine servicing actions performed, and other indications of the financial condition of the borrower. Spreadsheets of the financial statements must also be included. Following the Agency's review of the lender's financial analysis, the Agency will provide a written report of any concerns to the lender. Any concerns based upon the Agency's review must be addressed by the lender. If the lender makes a reasonable attempt to obtain financial statements but is unable to obtain the borrower's cooperation, the failure to obtain financial statements will not impair the validity of the Loan Note Guarantee.
(e) Protection of Agency interests. If the Agency determines that the lender is not in compliance with its servicing responsibilities, the Agency reserves the right to take any action the Agency determines necessary to protect the Agency's interests with respect to the loan. If the Agency exercises this right, the lender must cooperate with the Agency to rectify the situation. In determining any loss, the Agency will assess against the lender any cost to the Agency associated with such action.
§§ 4287.108-4287.111
[Reserved]
§ 4287.112
Interest rate changes.
(a) The borrower, lender, and holder (if any) may collectively initiate a permanent or temporary reduction in the interest rate of the guaranteed loan at any time during the life of the loan upon written agreement among these parties. The lender must obtain prior Agency concurrence and provide a copy of the modification agreement to the Agency. If any of the guaranteed portion has been purchased by the Agency, the Agency (as a holder) will affirm or reject interest rate change proposals in writing.
(b) No increases in interest rates will be permitted, except the normal fluctuations in approved variable interest rates, unless a temporary interest rate reduction occurred.
(c) The interest rate, after adjustments, must comply with the interest rate requirements set forth in § 4279.125 of this chapter.
(d) The lender is responsible for the legal documentation of interest-rate changes by an endorsement or any other legally effective amendment to the promissory note; however, no new notes shall be issued. The lender must provide copies of all legal documents to the Agency.
§ 4287.113
Release of collateral.
(a) Within the parameters of paragraph (c) of this section, lenders may, over the life of the loan, release collateral (other than personal and corporate guarantees) with a cumulative value of up to 20 percent of the original loan amount without Agency concurrence if the proceeds generated are used to reduce the guaranteed loan or to buy replacement collateral. Working assets, such as accounts receivable, inventory, and work-in-progress that are routinely depleted or sold and proceeds used for the normal course of business operations may be used in and released for routine business purposes without prior concurrence of the Agency as long as the loan has not been accelerated.
(b) If a release of collateral does not meet the requirements of paragraph (a) of this section, the lender must complete a written evaluation to justify the release and obtain written Agency concurrence in advance of the release.
(c) Collateral must remain sufficient to provide for adequate collateral coverage. The lender must support all releases of collateral with a value exceeding $250,000 with a current appraisal on the collateral being released. The appraisal must meet the requirements of § 4279.144 of this chapter. The cost of this appraisal will not be paid for by the Agency. The Agency may, at its discretion, require an appraisal of the remaining collateral in cases where it has been determined that the Agency may be adversely affected by the release of collateral. The sale or release of the collateral must be based on an arm's length transaction, and there must be adequate consideration for the release of collateral. Such consideration may include, but is not limited to:
(1) Application of the net proceeds from the sale of collateral to the borrower's debts in order of their lien priority against the sold collateral;
(2) Use of the net proceeds from the sale of collateral to purchase other collateral of equal or greater value for which the lender will obtain as security for the benefit of the guaranteed loan with a lien position equal or superior to the position previously held;
(3) Application of the net proceeds from the sale of collateral to the borrower's business operation in such a manner that a significant improvement to the borrower's debt service ability will be clearly demonstrated. The lender's written request must detail how the borrower's debt service ability will be improved; or
(4) Assurance that the release of collateral is essential for the success of the business, thereby furthering the goals of the program. Such assurance must be supported by written documentation from the lender acceptable to the Agency.
§ 4287.114-4287.122
[Reserved]
§ 4287.123
Subordination of lien position.
A subordination of the lender's lien position must be requested in writing by the lender and concurred with in writing by the Agency in advance of the subordination. The lender's subordination proposal must include a financial analysis of the servicing action and be fully supported by current financial statements of the borrower and guarantors that are less than 90 days old.
(a) The subordination of lien position must enhance the borrower's business and not adversely affect the potential for collection of the B&I loan through repayment or liquidation.
(b) The lien to which the guaranteed loan is subordinated is for a fixed dollar limit and for a fixed term after which the guaranteed loan lien priority will be restored.
(c) Collateral must remain sufficient to provide for adequate collateral coverage. The Agency may require a current independent appraisal in accordance with § 4279.144 of this chapter.
(d) Lien priorities must remain for the portion of the collateral that was not subordinated.
(e) A subordination to a line of credit cannot exceed 1 year. The term of the line of credit cannot be extended.
§ 4287.124
Alterations of loan instruments.
The lender must neither alter nor approve any alterations or modifications of any loan instrument without the prior written approval of the Agency.
§ 4287.125-4287.132
[Reserved]
§ 4287.133
Sale of corporate stock.
Any sale or transfer of corporate stock must be approved by the Agency in writing and must be to an eligible individual or entity in accordance with § 4279.108(a) and 4279.108(b) of this chapter. In the event a portion of the borrower's stock is sold or transferred, the Agency may require personal or corporate guarantees from those then owning a 20 percent or more interest in the borrower in accordance with § 4279.132 of this chapter.
§ 4287.134
Transfer and assumption.
The lender may request a transfer and assumption of a guaranteed loan in situations where the total indebtedness, or less than the total indebtedness, is transferred to another eligible borrower on the same or different terms. A transfer and assumption of the borrower's operation can be accomplished before or after the loan goes into liquidation. However, if the collateral has been purchased through foreclosure or the borrower has conveyed title to the lender, no transfer and assumption is permitted. Additionally, no transfer and assumption is permitted when the Agency has repurchased 100 percent of the guaranteed portion of the loan.
(a) Documentation of request. All transfers and assumptions must be approved in writing by the Agency and must be to an eligible borrower. The lender must provide credit reports for each individual or entity owning 20 percent or more interest in the transferee, along with such other documentation as the Agency may request to determine eligibility. In accordance with § 4279.132 of this chapter, the Agency will require personal and/or corporate guarantee(s) from all owners that have a 20 percent or more ownership interest in the transferee. When warranted by an Agency assessment of potential financial risk, the Agency may also require guarantees of parent, subsidiaries, or affiliated companies (owning less than a 20 percent interest in the borrower) and may require security for any guarantee. The new borrower must sign Form RD 4279-1, “Application for Loan Guarantee,” and any guarantors of the guaranteed loan must sign Form RD 4279-14, “Unconditional Guarantee.”
(b) Terms. Loan terms may be changed with the concurrence of the Agency, all holders, and the transferor (including guarantors) if the transferor has not been or will not be released from liability. Any new loan terms must be within the terms authorized by § 4279.126 of this chapter.
(c) Release of liability. The transferor, including any guarantor, may be released from liability only with prior Agency written concurrence and only when the fair market value of the collateral being transferred is at least equal to the amount of the loan being assumed and is supported by a current appraisal and a current financial statement of the transferee. The Agency will not pay for the appraisal. If the transfer is for less than the debt, for a release of liability, the lender must demonstrate to the Agency that the transferor and guarantors have no reasonable debt-paying ability considering their assets and income in the foreseeable future.
(d) Proceeds. The lender must credit any proceeds received from the sale of collateral before a transfer and assumption to the transferor's guaranteed loan debt in order of lien priority before the transfer and assumption is closed.
(e) Additional loans. Loans to provide additional funds in connection with a transfer and assumption must be considered a new loan application, which requires submission of a complete Agency application in accordance with § 4279.161(b) of this chapter.
(f) Credit quality. The lender will provide a credit analysis of the proposal that addresses capacity (sufficient cash flow to service the debt), capital (net worth), collateral (assets to secure the debt), conditions (of the borrower, industry trends, and the overall economy), and character (integrity of the transferee management) in accordance with § 4279.131 of this chapter.
(g) Appraisals. If the proposed transfer and assumption is for the full amount of the Agency guaranteed loan, the Agency will not require an appraisal, unless a guarantor is being released from liability in accordance with paragraph (c) of this section. If the proposed transfer and assumption is for less than the full amount of the Agency guaranteed loan, the Agency will require an appraisal on all of the collateral being transferred, and the amount of the assumption must not be less than this appraised value. The lender is responsible for obtaining this appraisal, which must conform to the requirements of § 4279.144 of this chapter. The Agency will not pay the appraisal fee or any other costs associated with this transfer.
(h) Documents. Prior to Agency approval, the lender must provide the Agency a written legal opinion that the transaction can be properly and legally transferred and assurance that the conveyance instruments will be appropriately filed, registered, and recorded.
(1) The lender must not issue any new promissory notes. The assumption must be completed in accordance with applicable law and must contain the Agency case number of the transferor and transferee. The lender must provide the Agency with a copy of the transfer and assumption agreement. The lender must ensure that all transfers and assumptions are noted on all original Loan Note Guarantees.
(2) A new loan agreement, consistent in principle with the original loan agreement, must be executed to establish the terms and conditions of the loan being assumed. An assumption agreement can be used to establish the loan covenants.
(3) Upon execution of the transfer and assumption, the lender must provide the Agency with a written legal opinion that the transfer and assumption is completed, valid, and enforceable, and certification that the transfer and assumption is consistent with the conditions outlined in the Agency's conditions of approval for the transfer and complies with all Agency regulations.
(i) Loss/repurchase resulting from transfer. (1) Any resulting loss must be processed in accordance with § 4287.158.
(2) If a holder owns any of the guaranteed portion, such portion must be repurchased by the lender or the Agency in accordance with § 4279.78 of this chapter.
(j) Related party. If the transferor and transferee are affiliated or related parties, any transfer and assumption must be for the full amount of the debt.
(k) Cash downpayment. The lender may allow the transferee to make cash downpayments directly to the transferor provided:
(1) The transfer and assumption is made for the total indebtedness;
(2) The lender recommends that the cash be released, and the Agency concurs prior to the transaction being completed. The lender may require that an amount be retained for a defined period of time as a reserve against future defaults. Interest on such account may be paid periodically to the transferor or transferee as agreed;
(3) The lender determines that the transferee has the repayment ability to meet the obligations of the assumed guaranteed loan, as well as any other indebtedness; and
(4) Any payments by the transferee to the transferor will not suspend the transferee's obligations to continue to meet the guaranteed loan payments as they come due under the terms of the assumption.
(l) Annual renewal fees. The lender must pay any annual renewal fee published in the Federal Register and then in effect at the time the loan is closed for the duration of the Loan Note Guarantee. Annual renewal fees are due for the entire year even if the Loan Note Guarantee is terminated before the end of the year.
§ 4287.135
Substitution of lender.
After the issuance of a Loan Note Guarantee, the lender is prohibited from selling or transferring the entire loan without the prior written approval of the Agency. Because the Loan Note Guarantee is associated with a specific promissory note and cannot be transferred to a new promissory note, the lender must transfer the original promissory note to the new lender, who must agree to its current loan terms, including the interest rate, secondary market holder (if any), collateral, loan agreement terms, and guarantors. The new lender must also obtain the original Loan Note Guarantee, original personal and corporate guarantee(s), and the loan payment history from the transferor lender. If the new lender wishes to modify the loan terms after acquisition, the new lender must submit a request to the Agency.
(a) The Agency may approve the substitution of a new lender if:
(1) The proposed substitute lender:
(i) Is an eligible lender in accordance with § 4279.29 of this chapter and is approved as such;
(ii) Is able to service the loan in accordance with the original loan documents; and
(iii) Agrees in writing to acquire title to the unguaranteed portion of the loan held by the original lender and assumes all original loan requirements, including liabilities and servicing responsibilities.
(2) The substitution of the lender is requested in writing by the borrower, the proposed substitute lender, and the original lender of record, if still in existence.
(b) The Agency will not pay any loss or share in any costs ( e.g., appraisal fees and environmental assessments) with a new lender unless a relationship is established through a substitution of lender in accordance with paragraph (a) of this section. This includes situations where a lender is merged with or acquired by another lender and situations where the lender has failed and been taken over by a regulatory agency such as the Federal Deposit Insurance Corporation (FDIC) and the loan is subsequently sold to another lender.
(c) Where the lender has failed and been taken over by the FDIC and the loan is liquidated by the FDIC rather than being sold to another lender, the Agency will pay losses and share in costs as if the FDIC were an approved substitute lender.
(d) In cases where there is a substitution of the lender, the Agency and the new lender must execute a new Form RD 4279-4, “Lender's Agreement,” unless a valid Lender's Agreement already exists with the new lender.
§ 4287.136
Lender failure.
(a) Uninsured lender. The lender or insuring agency cannot arbitrarily change the Lender's Agreement and related documents on the guaranteed loan, and the Agency will make the successor to the failed institution aware of the statutory and regulatory requirements. If the acquiring institution is not an eligible lender as set forth in § 4279.29 of this chapter, the Loan Note Guarantee will not be enforceable, and the institution must promptly apply to become an eligible lender. The failure of the uninsured lender to become an eligible lender will result in the Loan Note Guarantee being unenforceable. A new lender approved by the Agency will be afforded the benefits of the Loan Note Guarantee in the sharing of any loss and eligible expenses subject to the limits that are set forth in the regulations governing the program.
(b) Insured lender. The FDIC and the Agency have entered into an Inter-Agency Agreement and all parties are to abide by this Agreement or successor document(s). This document sets forth the duties and responsibilities of each Agency when an institution fails. The lender must take such action that a reasonably prudent lender would take if it did not have a Loan Note Guarantee to protect the lender and Agency's mutual interest.
§ 4287.137-4287.144
[Reserved]
§ 4287.145
Default by borrower.
The lender's primary responsibilities in default are to act prudently and expeditiously, to work with the borrower to bring the account current or cure the default through restructuring if a realistic plan can be developed, or to accelerate the account and conduct a liquidation in a manner that will minimize any potential loss. The lender may initiate liquidation subject to submission and approval of a complete liquidation plan.
(a) The lender must notify the Agency when a borrower is more than 30 days past due on a payment and the delinquency cannot be cured within 30 days or when a borrower is otherwise in default of covenants in the loan agreement by promptly submitting Form RD 1980-44, “Guaranteed Loan Borrower Default Status,” or processing the Default Status report in LINC. The lender must update the loan's status each month using either Form RD 1980-44 or the LINC Default Status report until such time as the loan is no longer in default. If a monetary default exceeds 60 days, the lender must meet with the Agency and, if practical, the borrower to discuss the situation.
(b) In considering options, the prospects for providing a permanent cure without adversely affecting the risk to the Agency and the lender is the paramount objective.
(1) Curative actions (subject to the rights of any holder and Agency concurrence) include, but are not limited to:
(i) Deferment of principal and/or interest payments;
(ii) An additional unguaranteed temporary loan by the lender to bring the account current;
(iii) Reamortization of or rescheduling the payments on the loan;
(iv) Transfer and assumption of the loan in accordance with § 4287.134;
(v) Reorganization;
(vi) Liquidation; and
(vii) Changes in interest rates with the Agency's, the lender's, and any holder's approval. Any interest payments must be adjusted proportionately between the guaranteed and unguaranteed portion of the loan.
(2) The term of any deferment, rescheduling, reamortization, or moratorium will be limited to the lesser of the remaining useful life of the collateral or remaining limits as set forth in § 4279.126 of this chapter (excluding paragraph (c)). During a period of deferment or moratorium on the guaranteed loan, the lender's unguaranteed loan(s) and any stockholder loans must also be under deferment or moratorium. Balloon payments are permitted as a loan servicing option as long as there is a reasonable prospect for success and the remaining life of the collateral supports the action.
(3) In the event of a loss or a repurchase, the lender cannot claim default or penalty interest, late payment fees, or interest on interest. If the restructuring includes the capitalization of interest, interest accrued on the capitalized interest will not be covered by the guarantee. Consequently, it is not eligible for repurchase from the holder and cannot be included in the loss claim.
(c) Debt write-downs for an existing borrower, where the same principals retain control of and decisionmaking authority for the business, are prohibited, except as directed or ordered under the Bankruptcy Code.
(d) For loans closed on or after August 2, 2016, in the event of a loss, the guarantee will not cover note interest to the lender accruing after 90 days from the most recent delinquency effective date.
(e) For loans closed on or after August 2, 2016, the lender or the Agency will issue an interest termination letter to the holder(s) establishing the termination date for interest accrual. The guarantee will not cover interest to any holder accruing after the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter.
(f) For repurchases of guaranteed loans, refer to § 4279.78 of this chapter.
§ 4286.146-4287.155
[Reserved]
§ 4287.156
Protective advances.
Protective advances are advances made by the lender for the purpose of preserving and protecting the collateral where the debtor has failed to, will not, or cannot meet its obligations. Lenders must exercise sound judgment in determining that the protective advance preserves collateral and recovery is actually enhanced by making the advance. Lenders cannot make protective advances in lieu of additional loans. A protective advance claim will be paid only at the time of the final report of loss payment.
(a) The maximum loss to be paid by the Agency will never exceed the original loan amount plus accrued interest times the percentage of guarantee regardless of any protective advances made.
(b) In the event of a final loss, protective advances will accrue interest at the note rate and will be guaranteed at the same percentage of guarantee as provided for in the Loan Note Guarantee. The guarantee will not cover interest on the protective advance accruing after 90 days from the most recent delinquency effective date.
(c) Protective advances must constitute an indebtedness of the borrower to the lender and be secured by the security instruments. Agency written authorization is required when the cumulative total of protective advances exceeds $200,000 or 10 percent of the aggregate outstanding balance of principal and interest, whichever is less.
§ 4287.157
Liquidation.
In the event of one or more incidents of default or third party actions that the borrower cannot or will not cure within a reasonable period of time, the lender, with Agency consent, must liquidate the loan. In accordance with § 4287.145(d), for loans closed on or after August 2, 2016, in the event of a loss, the guarantee will not cover note interest to the lender accruing after 90 days from the most recent delinquency effective date.
(a) Decision to liquidate. A decision to liquidate must be made when the lender determines that the default cannot be cured through actions such as those contained in § 4287.145, or it has been determined that it is in the best interest of the Agency and the lender to liquidate. The decision to liquidate or continue with the borrower must be made as soon as possible when one or more of the following exist:
(1) A loan is 90 days behind on any scheduled payment and the lender and the borrower have not been able to cure the delinquency through actions such as those contained in § 4287.145.
(2) It is determined that delaying liquidation will jeopardize full recovery on the loan.
(3) The borrower or lender is uncooperative in resolving the problem or the Agency or lender has reason to believe the borrower is not acting in good faith, and it would improve the position of the guarantee to liquidate immediately.
(b) Repurchase of loan. When the decision to liquidate is made, if any portion of the loan has been sold or assigned under § 4279.75 of this chapter and not already repurchased, provisions will be made for repurchase in accordance with § 4279.78 of this chapter.
(c) Lender's liquidation plan. The lender is responsible for initiating actions immediately and as necessary to assure a prompt, orderly liquidation that will provide maximum recovery. Within 30 days after a decision to liquidate, the lender must submit a written, proposed plan of liquidation to the Agency for approval. The liquidation plan must be detailed and include at least the following:
(1) Such proof as the Agency requires to establish the lender's ownership of the guaranteed loan promissory note and related security instruments and a copy of the payment ledger, if available, that reflects the current loan balance, accrued interest to date, and the method of computing the interest;
(2) A full and complete list of all collateral, including any personal and corporate guarantees;
(3) The recommended liquidation methods for making the maximum collection possible on the indebtedness and the justification for such methods, including recommended action for acquiring and disposing of all collateral and collecting from guarantors;
(4) Necessary steps for preservation of the collateral;
(5) Copies of the borrower's most recently available financial statements;
(6) Copies of each guarantor's most recently available financial statements;
(7) An itemized list of estimated liquidation expenses expected to be incurred along with justification for each expense;
(8) A schedule to periodically report to the Agency on the progress of liquidation, not to exceed every 60 days;
(9) Estimated protective advance amounts with justification;
(10) Proposed protective bid amounts on collateral to be sold at auction and a breakdown to show how the amounts were determined. A protective bid may be made by the lender, with prior Agency written approval, at a foreclosure sale to protect the lender's and the Agency's interest. The protective bid will not exceed the amount of the loan, including expenses of foreclosure, and must be based on the liquidation value considering estimated expenses for holding and reselling the property. These expenses include, but are not limited to, expenses for resale, interest accrual, length of time necessary for resale, maintenance, guard service, weatherization, and prior liens;
(11) If a voluntary conveyance is considered, the proposed amount to be credited to the guaranteed debt;
(12) Legal opinions, if needed by the lender's legal counsel; and
(13) An estimate of fair market and potential liquidation value of the collateral. If the value of the collateral is $250,000 or more, the lender must obtain an independent appraisal report meeting the requirements of § 4279.144 of this chapter for the collateral securing the loan, which reflects the fair market value and potential liquidation value. For collateral values under this threshold, lenders must follow their primary regulator's policies relating to appraisals and evaluations or, if the lender is not regulated, normal banking practices and generally accepted methods of determining value. The liquidation appraisal of the collateral must evaluate the impact on market value of any release of hazardous substances, petroleum products, or other environmental hazards. The independent appraiser's fee, including the cost of the environmental site assessment, will be shared equally by the Agency and the lender. In order to assure prompt action, the liquidation plan can be submitted with an estimate of collateral value, and the liquidation plan may be approved by the Agency subject to the results of the final liquidation appraisal.
(d) Approval of liquidation plan. The lender's liquidation plan must be approved by the Agency in writing. The lender and Agency must attempt to resolve any Agency concerns. If the liquidation plan is approved by the Agency, the lender must proceed expeditiously with liquidation and must take all legal action necessary to liquidate the loan in accordance with the approved liquidation plan. The lender must update or modify the liquidation plan when conditions warrant, including a change in value based on a liquidation appraisal. If the liquidation plan is not approved by the Agency, the lender must take such actions that a reasonably prudent lender would take without a guarantee and keep the Agency informed in writing. The lender must continue to develop a liquidation plan in accordance with this section.
(e) Acceleration. The lender will proceed to accelerate the indebtedness as expeditiously as possible when acceleration is necessary, including giving any notices and taking any other legal actions required. The guaranteed loan will be considered in liquidation once the loan has been accelerated and a demand for payment has been made upon the borrower. The lender must obtain Agency concurrence prior to the acceleration of the loan if the sole basis for acceleration is a nonmonetary default. In the case of monetary default, prior approval by the Agency of the lender's acceleration is not required, although Agency concurrence must still be given not later than at the time the liquidation plan is approved. The lender will provide a copy of the acceleration notice or other acceleration document to the Agency.
(f) Filing an estimated loss claim. When the lender owns any of the guaranteed portion of the loan, the lender must file an estimated loss claim once a decision has been made to liquidate if the liquidation is expected to exceed 90 days. The estimated loss payment will be based on the liquidation value of the collateral. For the purpose of reporting and loss claim computation, for loans closed on or after August 2, 2016, the guarantee will not cover note interest to the lender accruing after 90 days from the most recent delinquency effective date. The Agency will promptly process the loss claim in accordance with applicable Agency regulations as set forth in § 4287.158.
(g) Accounting and reports. The lender must account for funds during the period of liquidation and must, in accordance with the Agency-approved liquidation plan, provide the Agency with reports on the progress of liquidation including disposition of collateral, resulting costs, and additional procedures necessary for successful completion of the liquidation.
(h) Transmitting payments and proceeds to the Agency. When the Agency is the holder of a portion of the guaranteed loan, the lender must transmit to the Agency its pro rata share of any payments received from the borrower, liquidation, or other proceeds using Form RD 1980-43, “Lender's Guaranteed Loan Payment to Rural Development.”
(i) Abandonment of collateral. When the lender adequately documents that the cost of liquidation would exceed the potential recovery value of certain collateral and receives Agency concurrence, the lender may abandon that collateral. When the lender makes a recommendation for abandonment of collateral, it must comply with 7 CFR part 1970, “Environmental Policies and Procedures.”
(j) Personal or corporate guarantees. The lender must take action to maximize recovery from all personal and corporate guarantees, including seeking deficiency judgments when there is a reasonable chance of future collection.
(k) Compromise settlement. Compromise settlements must be approved by the lender and the Agency. Complete current financial information on all parties obligated for the loan must be provided. At a minimum, the compromise settlement must be equivalent to the value and timeliness of that which would be received from attempting to collect on the guarantee. The guarantor cannot be released from liability until the full amount of the compromise settlement has been received. In weighing whether the compromise settlement should be accepted, among other things, the Agency will weigh whether the comparison is more financially advantageous than collecting on the guarantee.
(l) Litigation. In all litigation proceedings involving the borrower, the lender is responsible for protecting the rights of the lender and the Agency with respect to the loan and keeping the Agency adequately and regularly informed, in writing, of all aspects of the proceedings. If the Agency determines that the lender is not adequately protecting the rights of the lender or the Agency with respect to the loan, the Agency reserves the right to take any legal action the Agency determines necessary to protect the rights of the lender, on behalf of the lender, or the Agency with respect to the loan. If the Agency exercises this right, the lender must cooperate with the Agency. Any cost to the Agency associated with such action will be assessed against the lender.
§ 4287.158
Determination of loss and payment.
Unless the Agency anticipates a future recovery, the Agency will make a final settlement with the lender after the collateral is liquidated or after settlement and compromise of all parties has been completed. The Agency has the right to recover losses paid under the guarantee from any party that may be liable.
(a) Report of loss form. Form RD 449-30, “Loan Note Guarantee Report of Loss,” will be used for reporting and calculating all estimated and final loss determinations.
(b) Estimated loss. In accordance with the requirements of § 4287.157(f), the lender must prepare an estimated loss claim, based on liquidation appraisal value, and submit it to the Agency. When the lender is conducting the liquidation and owns any or all of the guaranteed portion of the loan, the lender must file an estimated loss claim once a decision has been made to liquidate if the liquidation will exceed 90 days. The estimated loss payment will be based on the liquidation value of the collateral.
(1) Such estimate will be prepared and submitted by the lender on Form RD 449-30 using the basic formula as provided on the report, except that the liquidation appraisal value will be used in lieu of the amount received from the sale of collateral. Interest accrual eligible for payment under the guarantee on the defaulted loan will be discontinued when the estimated loss is paid.
(2) A protective advance claim will be paid only at the time of the final report of loss payment.
(c) Final loss. Within 30 days after liquidation of all collateral is completed (except for certain unsecured personal or corporate guarantees as provided for in this section), the lender must prepare a final report of loss and submit it to the Agency. If the lender holds all or a portion of the guaranteed loan, the Agency will not guarantee interest to the lender accruing after 90 days from the most recent delinquency effective date. The Agency will not guarantee interest to any holder accruing after the greater of: 90 days from the date of the most recent delinquency effective date as reported by the lender or 30 days from the date of the interest termination letter. Before approval by the Agency of any final loss report, the lender must account for all funds during the period of liquidation, disposition of the collateral, all costs incurred, and any other information necessary for the successful completion of liquidation. Upon receipt of the final accounting and report of loss, the Agency may audit all applicable documentation to determine the final loss. The lender must make its records available and otherwise assist the Agency in making any investigation. The documentation accompanying the report of loss must support the amounts reported as losses on Form RD 449-30.
(1) The lender must make a determination regarding the collectability of unsecured personal and corporate guarantees. If reasonably possible, the lender must promptly collect or otherwise dispose of such guarantees in accordance with § 4287.157(j) prior to completion of the final loss report. However, in the event that collection from the guarantors appears unlikely or will require a prolonged period of time, the lender must file the report of loss when all other collateral has been liquidated. Unsecured personal or corporate guarantees outstanding at the time of the submission of the final loss claim will be treated as a future recovery with the net proceeds to be shared on a pro rata basis by the lender and the Agency. Debts owed to the Agency (Federal debt) may be collected using DCIA authority. The Agency may consider a compromise settlement of Federal debt after it has processed a final report of loss and issued a 60 day due process letter. Any funds collected on Federal debt will not be shared with the lender.
(2) The lender must document that all of the collateral has been accounted for and properly liquidated and that liquidation proceeds have been accounted for and applied correctly to the loan.
(3) The lender must provide receipts and a breakdown of any protective advance amount as to the payee, purpose of the expenditure, date paid, and evidence that the amount expended was proper.
(4) The lender must provide receipts and a breakdown of liquidation expenses as to the payee, purpose of the expenditure, date paid, and evidence that the amount expended was proper. Liquidation expenses are recoverable only from liquidation proceeds. The Agency may approve attorney/legal fees as liquidation expenses provided that the fees are reasonable, require the assistance of attorneys, and cover legal issues pertaining to the liquidation that could not be properly handled by the lender and its employees.
(5) The lender must support accrued interest by documenting how the amount was accrued. If the interest rate was a variable rate, the lender must include documentation of changes in both the selected base rate and the loan rate.
(6) The Agency will pay loss payments within 60 days after it has reviewed the complete final loss report and accounting of the collateral.
(d) Loss limit. The amount payable by the Agency to the lender cannot exceed the limits set forth in the Loan Note Guarantee.
(e) Liquidation expenses. The Agency will deduct liquidation expenses from the liquidation proceeds of the collateral. The lender cannot claim any liquidation expenses in excess of liquidation proceeds. Any changes to the liquidation expenses that exceed 10 percent of the amount proposed in the liquidation plan must be approved by the Agency. Reasonable attorney/legal expenses will be shared by the lender and Agency equally, including those instances where the lender has incurred such expenses from a trustee conducting the liquidation of assets. The lender cannot claim the guarantee fee or the annual renewal fee as authorized liquidation expenses, and no in-house expenses of the lender will be allowed. In-house expenses include, but are not limited to, employee's salaries, staff lawyers, travel, and overhead.
(f) Rent. The lender must apply any net rental or other income that it receives from the collateral to the guaranteed loan debt.
(g) Payment. Once the Agency approves Form RD 449-30 and supporting documents submitted by the lender:
(1) If the loss is greater than any estimated loss payment, the Agency will pay the additional amount owed by the Agency to the lender.
(2) If the loss is less than the estimated loss payment, the lender must reimburse the Agency for the overpayment plus interest at the note rate from the date of payment.
§§ 4287.159-4287.168
[Reserved]
§ 4287.169
Future recovery.
Unless notified otherwise by the Agency, after the final loss claim has been paid, the lender must use reasonable efforts to attempt collection from any party still liable on any loan that was guaranteed. Any net proceeds from that effort must be split pro rata between the lender and the Agency based on the percentage of guarantee. Any collection of Federal debt made by the United State from any liable party to the guaranteed loan will not be split with the lender.
§ 4287.170
Bankruptcy.
(a) Lender's responsibilities. It is the lender's responsibility to protect the guaranteed loan and all of the collateral securing it in bankruptcy proceedings, including taking actions that result in greater recoveries and not taking actions that would not likely be cost-effective. These responsibilities include, but are not limited to, the following:
(1) Monitoring confirmed bankruptcy plans to determine borrower compliance, and, if the borrower fails to comply, seeking a dismissal of the bankruptcy plan;
(2) Filing a proof of claim, where necessary, and all the necessary papers and pleadings concerning the case;
(3) Attending and, where necessary, participating in meetings of the creditors and all court proceedings;
(4) Requesting modifications of any bankruptcy plan whenever it appears that additional recoveries are likely; and
(5) Keeping the Agency adequately and regularly informed in writing of all aspects of the proceedings.
(6) The lender must submit a default status report when the borrower defaults and every 30 days until the default is resolved or a final loss claim is paid by the Agency. The default status report will be used to inform the Agency of the bankruptcy filing, the plan confirmation date, when the plan is complete, and when the borrower is not in compliance with the plan.
(7) With written Agency consent, the lender and Agency will equally share the cost of any independent appraisal fee to protect the guaranteed loan in any bankruptcy proceedings.
(b) Reports of loss during bankruptcy. In bankruptcy proceedings, payment of loss claims will be made as provided in this section. Attorney/legal fees and protective advances as a result of a bankruptcy are only recoverable from liquidation proceeds.
(1) Estimated loss payments. (i) If a borrower has filed for bankruptcy and all or a portion of the debt has been discharged, the lender must request an estimated loss payment of the guaranteed portion of the accrued interest and principal discharged by the court. Only one estimated loss payment is allowed during the bankruptcy. All subsequent claims of the lender during bankruptcy will be considered revisions to the initial estimated loss. A revised estimated loss payment may be processed by the Agency, at its option, in accordance with any court-approved changes in the bankruptcy plan. Once the bankruptcy plan has been completed, the lender is responsible for submitting the documentation necessary for the Agency to review and adjust the estimated loss claim to reflect any actual discharge of principal and interest and to reimburse the lender for any court-ordered interest-rate reduction under the terms of the bankruptcy plan.
(ii) The lender must use Form RD 449-30 to request an estimated loss payment and to revise any estimated loss payments during the course of the bankruptcy plan. The estimated loss claim, as well as any revisions to this claim, must be accompanied by documentation to support the claim.
(iii) Upon completion of a bankruptcy plan, the lender must complete Form RD 1980-44 and forward it to the Agency.
(iv) Upon completion of the bankruptcy plan, the lender must provide the Agency with the documentation necessary to determine whether the estimated loss paid equals the actual loss sustained. If the actual loss sustained as a result of the bankruptcy is less than the estimated loss, the lender must reimburse the Agency for the overpayment plus interest at the note rate from the date of payment of the estimated loss. If the actual loss is greater than the estimated loss payment, the lender must submit a revised estimated loss claim in order to obtain payment of the additional amount owed by the Agency to the lender.
(2) Bankruptcy loss payments. (i) The lender must request a bankruptcy loss payment of the guaranteed portion of the accrued interest and principal discharged by the court for all bankruptcies when all or a portion of the debt has been discharged. Unless a court approves a subsequent change to the bankruptcy plan that is adverse to the lender, only one bankruptcy loss payment is allowed during the bankruptcy. Once the court has discharged all or part of the guaranteed loan and any appeal period has run, the lender must submit the documentation necessary for the Agency to review and adjust the bankruptcy loss claim to reflect any actual discharge of principal and interest.
(ii) The lender must use Form RD 449-30 to request a bankruptcy loss payment and to revise any bankruptcy loss payments during the course of the bankruptcy. The lender must include with the bankruptcy loss claim documentation to support the claim, as well as any revisions to this claim.
(iii) Upon completion of a bankruptcy plan, restructure, or liquidation, the lender must either complete Form RD 1980-44 and forward it to the Agency or enter the data directly into LINC.
(iv) If an estimated loss claim is paid during a bankruptcy and the borrower repays in full the remaining balance without an additional loss sustained by the lender, a final report of loss is not necessary.
(3) Interest rate losses as a result of bankruptcy reorganization. (i) For guaranteed loans approved prior to August 2, 2016:
(A) Interest losses sustained during the period of the bankruptcy plan will be processed in accordance with paragraph (b)(1) of this section.
(B) Interest losses sustained after the bankruptcy plan is confirmed will be processed annually when the lender sustains a loss as a result of a permanent interest rate reduction that extends beyond the period of the bankruptcy plan.
(C) If a bankruptcy loss claim is paid during the operation of the bankruptcy plan and the borrower repays in full the remaining balance without an additional loss sustained by the lender, a final report of loss is not necessary.
(ii) For guaranteed loans approved on or after August 2, 2016, the Agency will not compensate the lender for any difference in the interest rate specified in the Loan Note Guarantee and the rate of interest specified in the bankruptcy plan.
(4) Final bankruptcy loss payments. The Agency will process final bankruptcy loss payments when the loan is fully liquidated.
(5) Application of loss claim payments. The lender must apply estimated loss payments first to the unsecured principal of the guaranteed portion of the debt and then to the unsecured interest of the guaranteed portion of the debt. In the event a court attempts to direct the payments to be applied in a different manner, the lender must immediately notify the Agency in writing.
(6) Protective advances. If approved protective advances, as authorized by § 4287.156, were incurred in connection with the initiation of liquidation action and were required to provide repairs, insurance, etc., to protect the collateral as a result of delays in the case of failure of the borrower to maintain the security prior to the borrower having filed bankruptcy, the protective advances together with accrued interest, are payable under the guarantee in the final loss claim.
(c) Expenses during bankruptcy proceedings. (1) Under no circumstances will the guarantee cover liquidation expenses in excess of liquidation proceeds.
(2) Expenses, such as reasonable attorney/legal fees and the cost of appraisals incurred by the lender as a direct result of the borrower's bankruptcy filing, are considered liquidation expenses. Liquidation expenses must be reasonable, customary, and provide a demonstrated economic benefit to the lender and the Agency. Lender's in-house expenses, which are those expenses that would normally be incurred for administration of the loan, including in-house lawyers, are not covered by the guarantee. Liquidation expenses must be deducted from collateral sale proceeds. The lender and Agency will share liquidation expenses equally. To accomplish this, the lender will deduct 50 percent of the liquidation expenses from the collateral sale proceeds.
(3) When a bankruptcy proceeding results in a liquidation of the borrower by a bankruptcy trustee, expenses will be handled as directed by the court, and the lender cannot claim liquidation expenses for the sale of the assets.
(4) If the property is abandoned by the bankruptcy trustee and any relief from the stay has been obtained, the lender will conduct the liquidation in accordance with § 4287.157.
(5) Proceeds received from the partial sale of collateral during bankruptcy may be used by the lender to pay reasonable costs associated with the partial sale, such as freight, labor, and sales commissions. Reasonable use of proceeds for this purpose must be documented with the final loss claim.
(6) Reasonable and customary liquidation expenses in bankruptcy may be deducted from liquidation proceeds of collateral.
§§ 4287.171-4287.179
[Reserved]
§ 4287.180
Termination of guarantee.
The Loan Note Guarantee will terminate under any of the following conditions:
(a) Upon full payment of the guaranteed loan;
(b) Upon full payment of any loss obligation; or
(c) Upon written notice from the lender to the Agency that the guarantee will terminate 30 days after the date of notice, provided that the lender holds all of the guaranteed portion and the Loan Note Guarantee is returned to the Agency to be canceled.
§§ 4287.181-4287.199
[Reserved]
§ 4287.200
OMB control number.
In accordance with the Paperwork Reduction Act of 1995, the information collection requirements contained in this rule have been submitted to the Office of Management and Budget (OMB) under OMB Control Number 0570-0069 for OMB approval.
Dated: May 26, 2016.
Lisa Mensah,

Under Secretary, Rural Development.
81
107
Friday, June 3, 2016
Proposed Rules
Part V
Federal Communications Commission
47 CFR Part 69

Developing a New Regulatory Framework for Business Data Services (Special Access); Proposed Rule
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 69
[WC Docket Nos. 16-143, 15-247, 05-25 and RM-10593; FCC 16-54]
Developing a New Regulatory Framework for Business Data Services (Special Access)

AGENCY:
Federal Communications Commission.

ACTION:
Proposed rule.

SUMMARY:
In this document, the Federal Communications Commission seeks comment on replacing the existing, fragmented regulatory regime applicable to business data services (BDS) ( i.e., special access services) with a new technology-neutral framework, the Competitive Market Test, which subjects non-competitive markets to tailored regulation, and competitive markets to minimal oversight.

DATES:
Comments are due on or before June 28, 2016; reply comments are due on or before July 26, 2016. Written comments on the Paperwork Reduction Act proposed information collection requirements must be submitted by the public, Office of Management and Budget (OMB), and other interested parties on or before August 2, 2016.

ADDRESSES:
You may submit comments, identified by WC Docket Nos. 16-143, 15-247, 05-25 and RM-10593, by any of the following methods:
• Federal Communications Commission's Web site:
http://apps.fcc.gov/ecfs/. Follow the instructions for submitting comments.
• People With Disabilities: Contact the FCC to request reasonable accommodations (accessible format documents, sign language interpreters, CART, etc.) by email: FCC504@fcc.gov or phone: 202-418-0530 or TTY: 202-418-0432.
For detailed instructions for submitting comments and additional information on the rulemaking process, see the SUPPLEMENTARY INFORMATION section of this document. In addition to filing comments with the Secretary, a copy of any comments on the Paperwork Reduction Act information collection requirements contained herein should be submitted to the Federal Communications Commission via email to PRA@fcc.gov and to Nicole Ongele, Federal Communications Commission, via email to Nicole.Ongele@fcc.gov.

FOR FURTHER INFORMATION CONTACT:
Christopher Koves, Pricing Policy Division, Wireline Competition Bureau, 202-418-8209 or Christopher.Koves@fcc.gov. For additional information concerning the Paperwork Reduction Act information collection requirements contained in this document, send an email to PRA@fcc.gov or contact Nicole Ongele at (202) 418-2991.

SUPPLEMENTARY INFORMATION:
This is a summary of the Commission's Further Notice of Proposed Rulemaking (FNPRM), WC Docket Nos. 16-143, 15-247, 05-25 and RM-10593, FCC 16-54, released May 2, 2016. The summary is based on the public redacted version of the document, the full text of which is available here: https://apps.fcc.gov/edocs_public/attachmatch/FCC-16-54A1.pdf. To request alternative formats for persons with disabilities ( e.g. accessible format documents, sign language, interpreters, CARTS, etc.), send an email to fcc504@fcc.gov or call the Commission's Consumer and Governmental Affairs Bureau at (202) 418-0530 or (202) 418-0432 (TTY). Pursuant to Sections 1.415 and 1.419 of the Commission's rules, 47 CFR 1.415, 1.419, interested parties may file comments and reply comments on or before the dates indicated on the first page of this document. Comments may be filed using the Commission's Electronic Comment Filing System (ECFS). See Electronic Filing of Documents in Rulemaking Proceedings, 63 FR 24121 (1998), http://www.fcc.gov/Bureaus/OGC/Orders/1998/fcc98056.pdf.
• Electronic Filers: Comments may be filed electronically using the Internet by accessing the ECFS: http://apps.fcc.gov/ecfs/.
• Paper Filers: Parties who choose to file by paper must file an original and one copy of each filing. If more than one docket or rulemaking number appears in the caption of this proceeding, filers must submit two additional copies for each additional docket or rulemaking number.
Filings can be sent by hand or messenger delivery, by commercial overnight courier, or by first-class or overnight U.S. Postal Service mail. All filings must be addressed to the Commission's Secretary, Office of the Secretary, Federal Communications Commission.
○ All hand-delivered or messenger-delivered paper filings for the Commission's Secretary must be delivered to FCC Headquarters at 445 12th St. SW., Room TW-A325, Washington, DC 20554. The filing hours are 8:00 a.m. to 7:00 p.m. All hand deliveries must be held together with rubber bands or fasteners. Any envelopes and boxes must be disposed of before entering the building.
○ Commercial overnight mail (other than U.S. Postal Service Express Mail and Priority Mail) must be sent to 9300 East Hampton Drive, Capitol Heights, MD 20743.
○ U.S. Postal Service first-class, Express, and Priority mail must be addressed to 445 12th Street SW., Washington, DC 20554.
People with Disabilities: To request materials in accessible formats for people with disabilities (braille, large print, electronic files, audio format), send an email to fcc504@fcc.gov or call the Consumer & Governmental Affairs Bureau at 202-418-0530 (voice), 202-418-0432 (tty).

I. Introduction
1. Business data service (BDS) is critical to the delivery of innovative broadband services for businesses and government institutions and is a major contributor to the nation's economy. Incumbent LECs and competitive providers reported revenues of almost $45 billion for 2013 for the sale of dedicated services. It is, however, important to recognize that BDS is an important input (sometimes self-supplied) in the broader market for enterprise services, which include voice, Internet, private network, web-security, cloud connection, and other digital services. Available information suggests that the annual revenues for the broader enterprise services industry could exceed $75 billion annually.
2. In this FNPRM, we provide our analysis to date of the 2015 Collection. We then seek comment on a number of proposals to establish a new regulatory paradigm for BDS to more appropriately address the technological changes occurring today and to facilitate the continued evolution of the type of robust competition that will result in ever-improving services for American businesses and consumers. To that end, the FNPRM seeks to develop a technology-neutral framework that no longer classifies BDS through the legacy prism of traditional services and company classifications. Rather, the Commission seeks to enter a new era where regulatory determinations are made based on whether a market is competitive and the concomitant regulatory obligations apply to all providers, looking to legitimate differences in products, places, and customers. The goals of this FNPRM are supported by the joint principles recently announced by INCOMPAS and Verizon urging the Commission to “adopt a permanent framework for regulating all dedicated services in a technology neutral manner.” That two of the entities who were once diametrically opposed have joined together urging the Commission to adopt such principles is further evidence of the evolution in the BDS market today and the need for this new paradigm to harmonize regulation with the changing technology.

II. Further Notice of Proposed Rulemaking

A. Competition Analysis

1. Our Approach
3. We analyze the data collected and the evidence submitted in this proceeding to reach preliminary evaluations as to the degree of competiveness in BDS markets. Our public interest evaluation necessarily encompasses the “broad aims of the Communications Act,” which include, among other things, a deeply rooted preference for preserving and enhancing competition in relevant markets with increased private sector deployment of advanced services. In conducting this analysis, we take a forward-looking view of technological and market changes.
4. We examine the effectiveness (and likely effectiveness) of competitive restraints, to identify where market power exists in BDS markets. We focus our analysis on BDS prices, and terms and conditions, and consider the effectiveness of current competitive restraints and whether market power, where it exists, has enabled unreasonable pricing or other practices or an ability to unlawfully exclude competition.
5. To distinguish product markets, we generally look to include products in the same market if they are reasonably interchangeable, with differences in price, quality, and service capability being relevant. In the case of geographic markets, we look to supply, rather than demand substitution. For both product and geographic markets, we do not believe it is necessarily required to engage a formal hypothetical monopolist test considering likely consumer substitution if a hypothetical monopolist imposed at least a small but significant and non-transitory increase in price (SSNIP), taking a more direct approach to demonstrate the use of market power.

2. Product Markets
6. In our data collection we defined BDS as a dedicated end-to-end telecommunications service. Leading technologies of this type are DS1s and DS3s, typically carried over copper pairs, which account for the majority of the BDS revenue in 2013 according to these data. DS3 lines carry about 30 times the bandwidth of a DS1 line, which is a symmetric 1.5 Mbps service. It is also possible to achieve higher bandwidth levels over other circuit-based technologies. An alternative to circuit-based technology is packet-based service, more commonly delivered over fiber optic cable or HFC cable using a standard called DOCSIS. Fiber can deliver higher bandwidth and service levels, and most new investment is in fiber optic and coaxial cable, and in next generation DOCSIS 3.1 electronics. Cable companies also provide BDS at competitive rates over the coaxial-fiber hybrid technology, commonly referred to as “Ethernet over DOCSIS,” that have characteristics of BDS carried over fiber: It can be used to provide access to the Internet and point-to-point communications (such as a virtual private network); it is generally available at symmetric bandwidths up to 10 Mbps; and is often supplied with service reliability guarantees, even if not at the same level as what is typically offered over fiber. We agree with several commenters recognizing that since this proceeding began in 2005, there has been significant innovation, investment and deployment of IP-based technologies, and DOCSIS relied on by cable companies, and that increasingly business customers purchase these technologies instead of TDM services. However, many business customers continue to rely on TDM services.
7. We described best efforts services above. Several commenters, including certain competitive LECs, claim that best efforts Ethernet over DOCSIS provided by cable companies does not provide the requisite dedicated access needed by certain, notably mid-sized and larger business customers and carriers, even if it meets other demands. Other commenters contend the Commission should include best efforts DOCSIS cable service within a broader product market definition.
8. We believe it is likely that best effort services may not be in the same product market or markets as BDS. The prices of best efforts services are considerably lower than the prices of roughly comparable BDS. Compared with BDS, best effort services are less reliable, notably in terms of guaranteed uptime, and other service level guarantees; in some cases do not offer higher bandwidths; and characteristically lack upload/down symmetry. Although fit for many customer purposes, best efforts services do not meet the requirements of all BDS purchasers, nor is it offered by sellers as a product intended for all customers. Sellers generally distinguish best effort services from other BDS products to meet customer needs at the right price point, and organize sales efforts accordingly. Finally, underlying characteristics of the way best efforts services are supplied can make it hard for certain higher quality BDS to be supplied on the same network as best efforts services. We seek comment on this view.
9. If two readily available services have substantially different prices, then they are likely dissimilar (otherwise buyers would prefer the cheaper service which would constrain the price of the other service). Best efforts services are uniformly the least cost alternative offered by carriers, with the lowest functionality. Prices for best efforts services typically start at levels consistent with residential broadband service, increasing as service speed, capacity and reliability increase. For example, “Comcast's Business Internet service is available for purchase online starting at $69 per month for its 16/3 Mbps service.” Verizon similarly offers a variety of best efforts services under $100, beginning with a “Starter” package with speeds up to: 1 Mbps download/384 Kbps upload (“Best for: Single—person business, Light Internet use”) to the “Fastest” with speeds up to 10-15 Mbps download/1 Mbps upload (“Best for: Multiple employees, Online-based business eCommerce with orders”), with prices ranging from $39.99 to 94.99 per month. Verizon's Fios ranges from 50/50 Mbps to 500/500 Mbps, with prices from $49.99 to 269.99 per month. TWC offers six best efforts products online, ranging from $14.99 for (“up to”) 2 Mbps download/1 Mbps upload to $64.99 for (“up to”) 50 Mbps download/5 Mbps upload. In contrast to these best efforts services, TWC's average monthly BDS pricing ranges from [REDACTED].
10. That demand exists for symmetric [REDACTED], and customers do not switch to available best efforts services with at least as much bandwidth in both directions that are priced at approximately one tenth of that level (compare with the FiOS 50/50 price of $49.99), implies some customers must value certain characteristics of BDS highly relative to best efforts service. This suggests such customers would be unlikely to be tempted to switch to a best efforts service even if its price were to fall by a significant amount. It also suggests a customer currently purchasing a best efforts service would not switch to a BDS with a price of several multiples of the best efforts service, even if the BDS price were to fall significantly.
11. In fact, the characteristics of best efforts service and BDS appear to be very different. BDS comes with substantial reliability guarantees and functionality that do not accompany best efforts services, leading us to the view that the two services do not play important roles in constraining the quality-adjusted prices of each other. Consistent with the observed price differences between the different types of services, some end users do not require “mission critical” connectivity, and prefer best efforts services to BDS, prioritizing cost savings over reliability and specific functionality. Other end users are willing to pay considerably more for services that include greater (particularly upload) speeds, are more reliable, and come with more rigorous guarantees. Sprint, for example, [REDACTED]. Best efforts services do not satisfy these requirements.
12. BDS uptime reliability is also generally higher than with best efforts services. For example, Windstream on its Web site contrasts an Ethernet Internet service with a 99.99% uptime guarantee with cable (presumably) best efforts services, while best efforts services do not typically come with such guarantees. AT&T's best efforts Broadband SLA applicable to its High Speed Internet Business Edition family of services (AT&T U-verse® HSI-Business Edition; AT&T High Speed Internet Business Edition; and FastAccess® Business DSL) comes with a guarantee of 99.9% uptime. The AT&T “three nines” service (99.9%) service permits approximately 8.76 hours of downtime a year, plus disclosed allowances for many other downtime events, which are material to the offering and, as discussed immediately above, would not be acceptable for many users. “Comcast best efforts Business Internet service is sold without SLAs or contractual performance objectives.” Comcast best effort offers include seven Internet packages online ranging from a 3 Mbps, “Economy Plus” service to a 2000 Mbps, “Xfinity Gigabit Pro” service; each of the seven Comcast services include a disclaimer, “Actual speeds vary and are not guaranteed.” And in contrast Comcast BDS, like those of Windstream and AT&T, come with considerably greater reliability guarantees. Comcast “business class data services come with a variety of performance metrics and assurances,” which for Ethernet transport services include an SLA “committing to [REDACTED] for fiber-based service and [REDACTED] for HFC-based service, with penalties for failure to meet those service levels.” Similarly, without a guaranteed throughput speed, “Time Warner Cable offers six Internet speed options, up to 50 Mbps in most locations and up to 300 Mbps in select areas.” Time Warner Cable guarantees for its Business Internet Access (BIA) service vary slightly from Comcast, “[w]hile TWC's BIA service may be just as [REDACTED], leading certain customers to choose one service over the other.” Moreover, as discussed above, the price differences for these services are large, suggesting customers highly value the product differential BDS has over best effort services.
13. We seek comment on these analyses. We ask whether the Commission should consider alternative factors or aspects of the market and invite parties to submit alternative evidence in the record.
14. Some commenters argue that packet BDS place competitive pressure on TDM BDS. TDM BDS offers point-to-point connectivity in essentially the same way that packet BDS does. Since each technology can be used for the same purposes, this suggests that they are in the same product market. This is not to say that there are no differences between packet and TDM services. For example, while both perform similar roles, Ethernet is more easily scaled.
15. But Existing Customers Can Face High Switching Costs. Record evidence suggests that once a customer has installed a business data service, it faces high costs in switching. Consequently, switching most commonly occurs when a customer outgrows its service, for example, requiring a demand not available on their current service, or because they need the functionality of a different technology (most usually leading to a switch from TDM to packet BDS). In particular, high switching costs can both slow the transition from TDM to packet BDS and limit the potential market for packet BDS which could in turn limit investment.

3. Customer Markets
16. Carriers organize how they market around distinct fairly similar customer groups. These customer groups also have their own distinct characteristics, and hence distinct service requirements. As Comcast explains, “although all of Comcast's business class data services may be used by various types of customers, the unique needs of certain customers may make one service more appropriate than others.” Put together these facts suggest the possibility of separate customer markets. In particular, if supply to a first customer group cannot be readily extended to supply to a second, then supply to the first customer group may not place material competitive constraints on supply to the second. We seek comment on whether such customer markets are possible in the supply of business data services, and if so, what these are. We are particularly interested in the extent that multisite customers may fall into such a category as we propose below.
17. At a high level, possible customer categories are retail purchasers of business data services and carrier purchasers. These groups, in turn, could be further subdivided. Retail purchasers of business data services come in all shapes and sizes, and include retail businesses, governmental and educational institutions, and other enterprises that require dedicated enterprise services. Their needs vary depending on, among other factors, the number of employees and locations they have, the volume of their traffic, and the technological sophistication of the services they require. Many call for a competitive wholesale BDS access market. Large businesses are especially likely to require “high quality phone and Internet services” that “depend upon special access services as the building blocks of their corporate networks, from workhorse DS1s to the growing number of Ethernet connections to the highest capacity OCns.” Medium-sized and small businesses also require “advanced IP and fiber connections,” which are “mission critical.” Retail banks, for example, “rely heavily on broadband service” to enable “financial transactions and provide [customer] support in a timely fashion.” Reliable broadband connections also allow brick and mortar companies to meet customer needs “as efficiently and effectively as possible” and to “enhance the customer shopping and buying experience.”
18. Most larger, sometimes called enterprise, customers require connections to more than one site, and some, such as retail banks, and large retail sales outlets, may require many sites in diverse locations, often in areas with limited business density. Moreover, at many of these locations such large customers may only have low bandwidth requirements, even if each connection must have a high degree of reliability (for example, in the case of a retailing outlet, to ensure rapid credit card processing) and/or be highly secure (in the case of a retail bank). Larger customers are typical users of dedicated fiber-based, symmetric services; some have service demands for a limited geographic area while others require service for any number of locations within the country. Multi-location customers are often provisioned by BDS providers that “have a broad regional footprint without significant gaps in coverage to serve large enterprises with multiple sites across given geographic regions effectively.” Such providers may be relatively rare. We seek comment on our implicit finding below that such “spread-out” multi-site customers may be sufficiently distinct from other customers to constitute a separate market (below we find that competitive supply to other customers may not place a competitive constraint on supply to these “spread-out” multi-site customers), especially to the extent that such customers require lower bandwidth, highly reliable, services in areas with lower business densities, may not face the same competitive choices as other customers.
19. Carrier purchasers are different again. They are typically large and sophisticated buyers, with substantial capacity to leverage scale, for example, in seeking tenders to supply. Wireless carriers rely on business data services to connect their radio towers to their mobile switching centers. Mobile carriers purchase business data services often with bandwidths of around 50 Mbps and greater, but small cell demands, which look set to grow, may generally require lower bandwidths, and may require backhaul to many locations with low levels of business density. Sprint, a purchaser of wireless backhaul transit services, explains that it requires a specific BDS capable of more than traditional copper twisted pair and coaxial cable can support. Even where next-generation HFC is available, it is more suitable for mid-range demands. Sprint, for example, describes Ethernet over HFC as a poor substitute for fiber-based services because [REDACTED]. Sprint specifically notes that its macrocell sites [REDACTED] and a service level guarantee not available for generally best efforts or mid-tiered products.
20. Competitive LECs purchase BDS wholesale to sell retail services to end users. They do this where the purchasing competitive LEC does not currently have network and where extending their networks would not be profitable. While competitive LEC demand reflects end-user demand and so is highly diverse, competitive LECs again have the ability to leverage scale. We seek comment on whether carrier purchasers have countervailing power even when dealing with an entity that may otherwise have market power, and whether they need different protections than end users.

4. Geographic Markets
21. In this section, we express the view that the likely BDS geographic market, even for lower bandwidth services, likely extends beyond the area of the average Census block in which there is BDS demand. We come to this assessment by focusing on supply-side substitution, and seek comment on how we might refine this definition.
22. Relevant geographic markets are often determined by estimating demand side response if a hypothetical monopolist in a specified region, facing competition from beyond that region, tried to set prices above competitive levels. In this industry, given that most BDS customers would not shift their location to purchase special access from a different carrier, we focus on the supply response, that is—under what circumstances, if any, will nearby suppliers geographically extend their existing facilities distances to obtain new consumers. If suppliers were generally willing to extend their networks to meet nearby demand, then they would place a degree of competitive pressure on the prices nearby customers would face.
23. Geography also impacts product substitution. In certain areas, higher bandwidth services are not available due to the lack of technical capability. Available service could be limited in speed and capability to best efforts and similar, lower-level service levels that are provisioned over copper and coaxial lines. Increased service speeds, capacity, and guarantees are not available unless and until a BDS provider builds or extends new facilities (such as fiber or a hybrid technology) in a range close enough to the customer to readily extend a service that replaces best effort. Sprint points out, for example, that Ethernet over HFC “is not yet available in all business locations served by ILEC special access—nor at most cellular tower sites.”
24. We consider it unlikely that BDS supply in one part of an MSA would constrain the provision of BDS where it is demanded everywhere in the MSA. However, we also see good evidence that the presence of fiber competition not only could be expected to impact, but actually can impact, supply of lower bandwidth services over the whole Census block in which that fiber is located. This suggests a geographic market definition for lower bandwidth BDS lies somewhere above the average area of the Census block with BDS demand and below the MSA. We seek comment on these assessments and how to refine them. We seek this information for the purpose of developing an administratively feasible test for determining where we can replace regulation with market forces.
25. In the Suspension Order, the Commission explained that “demand varies significantly within any MSA, with highly concentrated demand in areas far smaller than the MSA” and some areas with little or no demand. Our record reinforces that view. The Commission stated that competitive entry is considerably less likely to occur in areas of low demand, regardless of whether other areas within the MSA contain sufficient demand to warrant competitive entry. The Commission also observed that “competitors have a strong tendency to enter in concentrated areas of high business demand, and have not expanded beyond those areas despite the passage of more than a decade since the grant of Phase II relief.”
26. The distances competitive LECs are generally willing to extend their facilities to reach potential customers beyond the locations they currently reach are quite short. These distances, which vary among competitive LECs and business opportunities, typically range from [REDACTED]. In fact, the distance Comcast will generally build within [REDACTED]. Similarly, TDS Metrocom estimates the average length of its competitive LEC's fiber laterals is [REDACTED]. Most [REDACTED]. If an end point of a “transport facility is outside a [central business district], and perhaps the first ring of suburbs . . . the competitive presence is far less. . . . As a result, these non-[central business district] areas are largely served only by ILEC facilities.” Buildouts of [REDACTED] and farther occur, but variables, including cost and demand factors, entailing traditional return-on-investment calculations, become increasingly determinative as the distance from a cost-effective and viable fiber junction point increases, which “are often collocated at or housed near ILEC central offices.” Incumbent LECs have similar buildout criteria. AT&T, for example, “engineering guidelines demonstrate that AT&T engineers its network to maintain lateral distances at or below about [REDACTED].
27. Responses to the data request indicate that competitive buildout to customers becomes increasingly less likely with a potential customer at a location [REDACTED] or farther away. Narrative descriptions of how far competitive carriers will buildout broadly align with observations of data submitted. For example, Cbeyond reported its “maximum build distance” is a “distance of [REDACTED] from existing lit fiber of a competitive fiber provider.” TDS METROCOM explained, “If the location is beyond [REDACTED] experience has shown us that customers are not willing to pay the extra monthly cost that would be required to pay for such an expensive build.” Cablevision Lightpath reported [REDACTED] buildout parameters, requiring a potential customer “be within [REDACTED] of a splice point in [its] core network,” excluding certain areas of density, and “[i]f [REDACTED] from splice point, no business case is required [while] [b]uild[ing] [REDACTED] from splice point involves ROI [analysis].” XO similarly notes that “[REDACTED] or less from its existing fiber infrastructure” is most attractive, while “buildings that are 200 feet or less from exiting fiber assets are of particular interest.” The distances and build criteria reported by Submitting Parties are generally in-line with that the Department of Justice in 2006. Beyond these general distances (and to a lesser extent within these distances), carriers typically rely on long-term loyalty agreement to guarantee a return-of-investment.
28. These buildout distances, which rarely exceed [REDACTED] are orders of magnitude less than those encountered in an MSA. For example, the smallest MSA, Carson City, Nevada has a land area of 144.7 square miles. If competitive fiber is deployed in the center of Carson City, it will be 6.9 miles from Mound House, Nevada, or 5.8 miles from Indian Hills, Nevada. Moreover, the Carson City MSA is quite small. The land area of the average MSA, 2,494.5 square miles, is 17.2 times larger than the Carson City MSA. In fact, the largest MSA, Riverside-San Bernardino-Ontario, California, has a land area of 27,263.4 square miles. If competitive fiber is deployed in the center of Riverside, it would be 20.6 miles from Chino, California. Indeed, MSAs are large geographic areas that “often contain smaller geographic areas across which competitive conditions are widely disparate.” As the Commission has observed, “MSAs are comprised of communities that share a locus of commerce, but not necessarily common economic characteristics as they relate to telecommunications facilities deployment . . . Due to the wide variability in market characteristics within an MSA, MSA-wide conclusions would substantially over-predict the presence of actual deployment, as well as the potential ability to deploy.”
29. Census tracts are large relative to the deployment distances discussed immediately above. If the median Census tract in which we observe BDS demand were a circle, it would be approximately 1.5 miles across. Moreover, the geography of Census tracts vary significantly. A circular tract at the 75th percentile would be around 2.6 miles across. In contrast, if the median Census block were a circle, then it would be approximately 0.2 miles across. Again Census blocks can be significantly larger than the median. If the Census block at the 75th percentile were circular, then it would be around 0.4 miles across. This analysis suggests that a supplier's presence anywhere in most, if not all, Census blocks could have a material competitive effect on other suppliers. It also suggests that a supplier's presence anywhere in smaller Census tracts could have a material competitive effect on other suppliers. This is consistent with the analysis contained in the Rysman White Paper, and in the Baker Declaration, which suggests that the presence of a fiber competitor can have material competitive effects on lower bandwidth services in Census blocks in which we see BDS demand.
30. We seek comment on how close competition must be to place material competitive pressure on supply at a given location, and whether this distance might vary with the nature, most notably the bandwidth, of the BDS in question. We also seek comment on how such analysis might be developed, and call for that analysis to be undertaken. For example, recognizing that Census tracts and Census blocks vary in size, we recently placed in the secure data enclave information on the distance from all locations with BDS demand to the nearest competitive providers' fiber networks. Consequently, regression analysis might be used to identify the range over which distant networks no longer have material competitive effects.

5. Concentration by Any Measure Appears High in This Industry
31. In this section, we report several measures of geographic concentration, including at the national level. What these measures show are uniformly high levels of concentration. While we remain agnostic as to what the right unit or units of geography are for measuring concentration (noting these might also vary for different services and customer groups), we expressly reject the idea that many, if any, BDS markets are national in scope (it is unlikely that a supplier's presence in Miami constrains prices in Seattle). To the extent that markets are not national, national measures of concentration likely understate both market concentration measures and the shares of incumbent LECs. While national revenue shares make sense from the perspective of incumbent LECs, whose territories do not overlap, and which, in aggregate, cover all price cap territories, national shares greatly exaggerate competitive LEC presence, since there are many geographically diverse, and in some cases very small, competitive LECs, none of which competes across all the incumbent price cap LECs' footprints.
32. As part of our data collection, carriers reported their aggregate BDS revenues. These provide an approximate indication of the revenue shares of different provider types supplying sophisticated services to end users, that is, of revenue shares in the supply of BDS and more complex managed services. As the pie chart below shows independent competitive LECs, that is, competitive LECs not affiliated with incumbent LECs, only capture 18% of BDS revenues. However, this estimate is subject to three biases, which in aggregate overstate the shares of independent LECs. First, a greater proportion of incumbent LECs' sales of BDS and managed services are BDS as compared with competitive LECs, a bias that likely overstates incumbent LEC revenue shares. Second, because a valid measure of concentration would measure facilities-based revenues, rather than resale revenues, and because a substantial proportion of incumbent LEC BDS sales are to competitive LECs who then resell those services, the preceding bias is likely to be more than offset (managed service revenues earned on the resale of incumbent LEC BDS will be greater than the LEC BDS sales to the resellers). Third, there is the bias identified immediately above from measuring national shares.
33. In 2013, cable companies reported nearly two billion in BDS sales (or less than 5% of all sales). However, because cable BDS revenues have been growing at around 20 percent per year, by the end of 2016 cable BDS revenues will be close to $3.5 billion (likely still less than eight percent of BDS revenues).
34. This section considers the extent to which in 2013 there was competition, as indicated by various measures of the number of rivals (for example, by counting or excluding competition based on UNEs and/or HFC with DOCSIS 3.0) at the level of the unique location, Census block and ZIP code. We take this broad approach because, as discussed above, we are agnostic as to the exact geographic range of BDS markets. In particular, we do not yet know is how much competitive pressure different forms of supply place on other suppliers, or how many suppliers, accounting for their differences, are sufficient to make prices effectively competitive (matters we have sought comment on above). Moreover, the Rysman White Paper suggests that competitive effects may occur at the level of the building, even when there are additional competitive effects from more distant competition. Under all these measures, market concentration is large. For example, when counting fiber, and DOCSIS 3.0 over HFC and UNE supply as forms of competition, we find more than ten percent of unique locations with BDS demand are supplied by one provider, and that slightly over half of such locations are only supplied by two providers (so 2/3 rds of such locations have only a choice of one or two suppliers).
35. Table 3 considers how many unique locations have one through six suppliers in the location, under two measures of competition. In both cases, the incumbent LEC is considered ubiquitous, and ILEC-affiliated supply is counted as competitive, but in the first case (the left side of the table), only competitors with fiber in the building are counted, while in the second, competition over UNEs is also counted. Under both cases, more than half of all unique locations only have one supplier, and less than five percent have three or more.
36. In 2013, cable companies reported being able to serve something just over 150,000 unique locations (or less than 15 percent of unique locations with BDS demand), almost entirely on their own facilities (cable companies make limited use of UNEs). Looking forward, if cable adds 20 percent more lines every year (in line with historic BDS revenue growth), then at the end of 2016 cable would be able to serve over 260,000 unique locations. However, in 2013, cable provision of BDS was much more limited than it is today. In particular, BDS was not typically supplied over HFC. Looking forward, it may already be or soon will be the case that cable companies are able to supply BDS everywhere they have deployed DOCSIS 3.0. We seek comment on this. Counting cable supply as being capable of reaching every unique location with BDS demand in every Census block that cable reports as being able to serve greatly increases the extent of competition at the level of unique location. Table 4 shows the resulting number of providers that can supply one through six buildings. More than half of unique locations are only supplied by one or two providers, and more than ten percent have only one supplier.
37. Firm concentration falls as the square areas of the geographic region under examination increases. Table 5 provides the number of Census blocks with BDS demand that have one through six fiber suppliers (so is similar to the left half of Table 3 in that it excludes UNE competition). It shows that around 16 percent of Census blocks with BDS demand are only served by an incumbent LEC (compared with more than 75 percent in Table 3), while more half of such Census blocks have a choice of two suppliers (compared with more than 20 percent in Table 3). It remains true that nearly 70 percent of Census blocks with BDS demand have two or fewer competitors capable of serving a unique location in the block.
38. Table 5 also gives an indication of the strength of different classes of providers. For example, incumbent-affiliated competitive LECs have very few facilities indeed. This is true even if competition over UNEs is added in (not shown in the table) and is indicative of the extent to which incumbent-affiliated competitive LECs rely on other incumbent LECs' BDS.

6. Entry and Entry Barriers
39. Similar to the antitrust enforcement agencies, we consider entry by competitors to be an important part of our analysis of competition. The viability of potential competition is significantly affected by barriers to entry, which are “cost[s] of production that must be borne by competitors entering a market that is not borne by an incumbent already operating in the market,” as well as conditions that impact entry. Both costs and conditions exist in the BDS market with enough significance in any measure of a geographic market to deter rapid competitive entry or expansion, including “high capital expenditures, large sunk costs, long lead times, scale economies, and cost disadvantages.” High barriers to entry at local levels may particularly affect competitive entry or expansion to service customers with national and multi-region demand that requires “an extensive network footprint to be able offer services widely.” The competitive provider's footprint most often includes a combination of locally-based facilities owned by the competitor and network access purchased from the regional incumbent or other competitors, which may be available at a regulated UNE- (by the incumbent LEC) or unregulated wholesale-basis (by a LEC or, in some instances, a cable company or other competitive LEC). Although there is evidence of potential competitors becoming increasingly relevant, commenters assert substantial barriers limit the timelines, likelihood, and sufficiency of entry to counteract anticompetitive effects in BDS markets.
40. The passage of the 1996 Act increased the Commission's focus on how barriers to entry impact competitive buildout. Like incumbent LECs, competitive LECs build facilities to meet consumer demand. Deploying facilities requires incurring costs that vary, “among other things, on the length of the laterals and fiber rings built, the nature of the electronics added, whether the lines are buried, and local regulations ( e.g., a city may require replacement of cobblestones on scenic streets).” In addition to deploying facilities, a provider frequently needs to obtain building access and/or rights of way to reach the building.
41. The barriers to entry do not materially differ whether the technology being deployed is TDM- or Ethernet-based. As Ad Hoc notes, “[t]he underlying transport facilities for Ethernet services are the same as the underlying transport facilities for TDM services,” which is consistent with AT&T's observation that “Ethernet is simply a service that can be provided over many different types of transport facilities, including copper, fiber, coaxial, and wireless facilities.” BT adds that it is reasonable to conclude that that the main Ethernet access cost elements—duct, fiber, and electronics—do not vary much across service speeds up to 1 Gbps.” Legacy TDM services require the same transport facilities and, in most geographic areas, the incumbent already provides TDM service and therefore has an advantage over a new entrant. That historical incumbent advantage allows the incumbent LEC to lower its costs through its “initial control of all customers” and “us[ing] the same rights of way, trenches, conduit, wires, poles, building access, riser, truck rolls, employees, outside plant, central office equipment, administrative expenses, and other legacy inputs that they use when the provision TDM-based special access services.”
42. One recent study asserts that current barriers are sufficient to deter new construction in most business locations. Certain issues cannot be easily overcome, such as “when the building owner refuses to grant the CLEC access or charges a high access fee, or when it is difficult or costly to obtain rights of way to a specific building ( e.g., pole access or costs of burying lines).” Also, competitive carriers can connect their networks to “customer locations that are near to their fiber transport facilities, where the customer at the location is suitable for the competitive carrier's service offerings, and where the revenues associated with the location are sufficient to make loop deployment profitable.” Areas of low BDS demand, which would include most suburban and rural areas, present additional issues for those considering an extension of facilities, principally a lack of a timely potential for a positive return on investment. Charter, for example, notes how in its [REDACTED]. Cablevision Lightpath also faced issues outside of its traditional, denser, region because [REDACTED]. Many simply avoid higher-cost areas, such as, [REDACTED].
43. In addition to deploying their own facilities, competitive LECs extend their network reach by purchasing incumbent LEC facilities at a regulated price on an unbundled basis or at non-regulated wholesale prices. Obtaining UNEs often is the most economical way to reach a new customer for a competitive LEC, and it is important to account for the effects of UNE competition. However, UNE competition has its limits. UNEs are not always available “because of insufficient or insufficiently-conditioned facilities, regulatory or contractual constraints.” And even with significant investment in facilities in an area, competitors “must depend heavily access to on the incumbent LECs' facilities and services to serve its customers.” When purchasing from the incumbent LEC, proximity to a collocation point near the customer lowers cost, meaning costs increase the farther the competitor's facilities are located from the potential customer. UNE reliance, therefore, is successful “only in some locations, only for some customers, and only to some extent.”
44. Competitive LECs also lease dedicated, non-regulated, wholesale services to connect to commercial buildings over non-UNE facilities from incumbent LECs or other competitive LECs. Even competitive LECs with well-developed regional fiber rings rely on an incumbent or competitive LEC wholesale inputs for last-mile connections. Leasing last-mile dedicated services from the ubiquitous incumbent LEC oftentimes is the only option due to a lack of competitive build-out. Level 3, for example, explains that it “usually has no choice but to lease dedicated services from the incumbent LEC in order to reach locations that Level 3 cannot reach with its own network.”
45. While wholesale access can be a cost effective means for a competitive LEC to expand its reach, such a wholesale purchaser cannot place competitive pressure on supply of the underlying facility that it purchases, but rather can only compete by being more efficient at retailing. Thus, we do not consider competition over resold lines as a material competitive restraint on any facility-based supplier with market power. Moreover, we are told that in some cases an incumbent LEC's wholesale prices can be near or above retail levels (sometimes referred to as a “price squeeze”). Similarly, we are told that rates below retail, available through many incumbent LEC purchase agreements, also can create barriers to entry when they include “penalty clauses and loyalty discount provisions in their wholesale contracts” that are not related to a competitive efficiency and simply have the effect of raising the rival's cost. XO, for example, generally declines to build facilities when doing so will increase its risk of falling short of a minimum purchase requirement under an incumbent LEC commitment plan. Level 3 similarly reports added costs due to incumbent LEC loyalty agreements, which forecloses an opportunity to purchase from other lower-priced wholesale inputs. In the end, competition is constrained. A motivated and efficient competitive LEC, such as Level 3—the largest competitive LEC and the third largest provider of fiber optic internet access (based on coverage area) in the United States—only “deploy[s] new loops to approximately 3,000 to 4,000 commercial buildings in the U.S. each year.”
46. Cable providers encounter similar barriers to entry, even within their incumbent franchise areas, although their in-region networks present economies of scale, similar to incumbent LECs, and present lower barriers for in-region expansion, compared to other competitive LECs. Nevertheless, for traditional competitive LECs and cable companies alike, “loop deployment costs are distance-sensitive,” limiting competitive reach, even if cable companies would likely have “lower loop deployment costs in areas where they have deployed extensive transport networks.” As CenturyLink notes, even cable companies must incur significant investment costs and rely on the networks of others to expand their footprints.”
47. Efforts to enter and expand in markets are being made with success, however, which has required investment and new networking initiatives to address barriers to entry. Comcast, for example, has recently established a new business unit to target Fortune 1000 businesses. But to reach Fortune 1000 companies, and satisfy their varying and broad geographic requirements, Comcast could not rely on its own facilities alone. To compete, “[i]t struck wholesale agreements with other cable companies including Charter, Time Warner Cable, Cox, Cablevision, and Mediacom, and it acquired Contingent Network Services—a managed services firm with “aggregation or wholesale relationships with many other CLECs, ILECs, [and] small cable providers.” Some companies are more risk-adverse or sensitive to barriers than others, however. Charter, for example, notes that a “partner model creates high transaction costs, as multiple networks and personnel must be coordinated, and these costs impact the price at which these services can be offered.”
48. Incumbent LECs face lower overall barriers within region and barriers similar to independent competitive LECs out-of-region. Within region, the Commission has recognized that incumbents can “increase capacity on many special access routes at a relatively low incremental cost (relative to the total cost of trenching and placing poles, manholes, conduit, fiber, and copper, and securing rights and access) by adding or upgrading terminating electronics.” Carriers with incumbent LEC and competitive LEC affiliated entities confirm the lower incumbent LEC barriers to entry. For example, TDS, which operates both incumbent LEC and competitive LEC subsidiaries, has explained that “it is generally far less expensive and more efficient for TDS ILEC to deploy new fiber to business customer locations than is the case for TDS CLEC.” Windstream, which also operates both incumbent LEC and competitive LEC businesses, has found that “ILECs continue to enjoy a dramatic advantage over CLECs in the average cost per building of new last-mile fiber deployment—an advantage that is largely attributable to the incumbents' much larger market shares, which is 6+ a direct result of the ILEC first mover advantage rooted in the monopoly era.” As TDS explains, this is because (1) “business customer locations are, on average, located much closer to TDS ILEC's existing fiber plant than TDS CLEC's”; (2) “TDS ILEC possesses many advantages due [to] its operation of a preexisting network along potential fiber routes”; and (3) “TDS CLEC must incur much higher equipment and fiber splicing costs than TDS ILEC when deploying new fiber.”
49. High barriers to entry and carrier agreements that have the effect of preventing switching over an extended time create “low elasticities of demand for the incumbent and low elasticities of supply for competitors.” Such low elasticities respectively mean few customers switch away from a supplier due to an increase in price, and few suppliers are able to switch away from resale to reliance on new network deployment. If the service had lower barriers of entry, customers would be more able to switch carriers when faced with higher prices or unfavorable or inefficient supply agreement terms and conditions. Level 3, for example, reports that it must purchase “a large percentage of its overall dedicated services requirements” under what it terms “lock-in” agreements, which mean it cannot switch to purchasing from a lower-priced competitive providers when a lower rate is available. The resulting higher downstream prices, therefore, offset any claimed efficiencies brought by the so-called lock-in requirements.
50. It would be a mistake to assume, however, that all barriers to entry are insurmountable, or that they exist to the same degree everywhere. The record and our data collection support the view that competition is growing, and that potential competition, appropriately defined, is important. When investments are made to self-provision facilities to customers, competitors typically first look to a region, such as a metropolitan region, and then focus on deploying facilities, such as fiber construction, to reach specific buildings. “[U]rban centers where costs are low ( e.g., zero or low mileage) and demand is significant” are attractive to competitive LECs. For many competitive LECs, “the reach of an embedded network can extend beyond the location of its current connections to serve additional customers in the surrounding region.” XO, for example, “entered initially by building metro rings in dense areas of major cities, since these could aggregate traffic from more users and hence were more economical.” Many competitor carriers prefer to provide services over their own network facilities because it allows greater efficiency and permits flexibility to control the type and quality of the competitor's service offerings. After deploying a “core fiber network . . . extending laterals requires significantly smaller capital expenditure per unit of bandwidth” resulting in a lower-cost expansion. Relying solely on independent lateral facilities without a core fiber presence, in contrast (by carrying traffic from a single location), limits scale of economies and requires significant customer spend to justify investing in facilities. Other advantages with a region-first approach include familiarity with local marketplace, which can be useful for a local sales force.
51. The great entry success story has been that of cable. Less than a decade ago cable largely provided no businesses services of any kind that were materially different from the services marketed to residential customers. Yet, for more than half a decade cable business revenues have experienced compound annual growth rate of 20 percent, starting with the smallest business customers and working their way up to the largest. More recently, cable began offering BDS services over HFC, as well as fiber, and has forced even the largest incumbent LECs to focus on maintaining market share. In addition, Israel et al., estimate, based on our data collection, that over the course of 2013, competitive LECs' “bandwidth grew at six times the growth of the rate of the ILECs”.

7. Evidence of Market Power in the Delivery of DS1 and DS3 Services and Lack Thereof for Higher Bandwidth Services
52. Our own analysis, the Rysman White Paper, and the Baker Declaration, provide direct evidence of market power in the supply of various services. We seek comment on validity of these analyses, on how they might be extended, or tested. At the same time, we recognize that no analysis is ever perfect, and look for comments on what the broad evidence available to us ultimately says about competition and market power, even if alternative theories cannot be entirely ruled out. Key pieces of evidence before us are regression analyses that show price effects due to the presence of competition, which imply that in the absence of competition prices are higher than they otherwise would be; the fact the price capped incumbent LECs have no headroom under our price caps, and have been in that situation for at least several years; that competition in areas with pricing flexibility lowers prices more than in price cap areas; and that incumbent-affiliated competitive LECs do not appear to be focused on facility-based or UNE competition (with some interesting exceptions). We also note that the Rysman White Paper concludes that there may not be market power in the supply BDS at bandwidths in excess of approximately 50 Mbps and seek comment on this analysis.
53. A central finding in the Rysman White Paper is that, in regressions controlling for a range of other factors, competitive supply in a unique location is correlated in both statistically and economically significant ways with lower ILEC prices for DS1s and DS3s at that location. Similarly, the Rysman White Paper finds that competitive supply in a unique location anywhere in a Census block, and competitive supply anywhere in the Census tract, is correlated in both statistically and economically significant ways with lower prices within the Census block. Analysis in the Baker Declaration comes to similar conclusions, though others have criticized the Baker Declaration. We seek comment on these analyses, on how such analyses might be extended, further verified or disproved, and indeed for additional analysis from interested parties.
54. As a result of the CALLS Order, the price cap indices for BDS services have been frozen (outside of exogenous cost adjustments) since 2004. Over the period since then, there has been no evidence that the price caps have been a source of any kind of financial stress to the incumbent LECs. Yet, at the same time, the price capped incumbent LECs have essentially raised prices up to the maximum allowed by the price caps. In our view, this does not suggest that over the last decade or more our caps were too harsh, and rates as constrained by the caps were too low, and this was the reason the price capped incumbent LECs kept their prices at the top of the cap. Consequently, it is our view that the fact that the price capped incumbent LECs have kept their prices at the top of the cap is additional evidence of market power.
55. Price cap incumbent LECs file their respective annual access charge tariff filings to become effective on or around July 1st of each year. In that filing, price cap incumbent LECs file Tariff Review Plans (TRPs) to demonstrate that the carrier's Actual Price Index (API) does not exceed its Price Cap Index (PCI). To the extent that a carrier's API is less than its PCI, the difference, often referred to as “head room,” is a measure of the extent to which such a carrier is able to increase its rates under the price cap rules. By calculating the average ratio of the API to the PCI, based on the APIs and PCIs in each carrier's TRPs, we can determine how close each carrier is to the maximum prices it is permitted to charge overall. The ratios, based on the TRPs, demonstrate that the six largest price cap incumbent LECs have been charging close to maximum prices for the last four tariff years. This also implies that if the price capped carrier had any headroom in previous years, then in or prior to 2012 took advantage of that headroom and raised its prices effectively eliminating that headroom.
56. As demonstrated from the table above, the APIs of the six largest price cap incumbent LECs are more than 99 percent of their PCIs. Therefore, the largest carriers have almost zero headroom under the price caps; even a small rate increase would likely cause the carriers' APIs to exceed their PCIs.
57. The Rysman White Paper finds evidence that prices in areas granted pricing flexibility respond more to competition than prices in pure price capped areas. We seek comment on the validity of this finding, and whether it might be evidence that granting incumbent LECs the ability to offer contract tariffs allows them to respond more effectively to competitive pressures in pricing flexibility areas, and if so, does this support allowing contract tariffs throughout areas we might designate in a future order as non-competitive. We also seek comment on the Rysman White Paper finding that in price cap only areas competitive effects are smaller than in pricing flexibility I and II areas. Is that a valid finding, and if so does it indicate less competition in pricing flexibility areas, or something else?
58. The Approach to Competition of Competitive LECs Affiliated with Incumbent LECs. Competitive LECs affiliated with incumbent LECs have engaged in limited facilities-based investment relative to certain other competitive LECs and in some cases have avoided the use of UNEs. In particular, the [REDACTED].
59. The Rysman White Paper finds little statistical relationship between the presence of local fiber-based competition and lower incumbent LEC prices for BDS above 45 Mbps. At least three possibilities could account for this observation: (1) Competition broadly exists for these services, (2) to the extent any competition existed, it was too little competition to produce material competitive effects, or (3) there are too little data and/or too many uncontrolled for variables for a statistical relationship to emerge. However, given limited complaints in the record about higher bandwidth services, and evidence that competitive LEC market share of fibered buildings is much higher than its general share, we recognize that supply of higher bandwidth services may often be more competitive than supply of lower bandwidth services. We, however, seek comment on this assessment. Is it correct generally? If so, could it be incorrect in particular cases that are sufficiently important that the Commission should consider action specific to those cases? How should any conclusion reached in the future about the nature of higher bandwidth services be applied, given the data on geographic areas, different categories of customers, and other factors?

B. New Technology Neutral Regulatory Framework for Business Data Services
60. The BDS market has changed substantially since this proceeding was initiated, both in terms of technology and providers. While the price cap LECs maintain substantial market power in some areas for some services, it is clear the market will continue to evolve and that market power and market positions are likely to shift over the next ten to fifteen years and beyond. The Commission's prior adoption of bright line rules based on what turned out to be a poor measure of the presence of competition led to some of the problems we start to solve today.
61. Some parties to the proceeding have raised objections to being fully included in the new framework. We note that business data services are telecommunications services, regardless of the provider supplying the service. BDS providers are therefore common carriers. And as such, with the unique exception of Verizon's forbearance, the providers are subject to Title II in the provision of their services, including packet-based BDS services such as Ethernet. Sections 201 and 202 of the Act require that the rates, terms, and conditions under which common carriers provide telecommunications services, such as the broadband data services we address herein, must be just, reasonable, and not unjustly or unreasonably discriminatory. These requirements are enforced through section 208 of the Act, which permits any person to file a complaint against any common carrier for acts or omissions in violation of the Act or a Commission rule or order.
62. The presence, and use, of market power can inhibit the evolution of a competitive market, both through prices and terms and conditions. For example, we examine certain terms and conditions in the Tariff Investigation Order and prescribe changes to address terms we found to be unreasonable and, in some cases, anticompetitive. This Order and its findings in this and other areas will provide substantial precedent to guide the Commission in its consideration of any section 208 complaints challenging the reasonableness of conduct in the provision of business data services. Likewise, the Commission seeks comment in this FNPRM on significant issues such as the basis for determining the presence of material competitive effects that would support the removal of direct rate regulation in some areas for some services. Such analysis will provide further guidance for resolving the threshold question whether the services are offered in a non-competitive area, in any complaint asserting unreasonable conduct under sections 201 and 202.
63. While a case-by-case adjudication under section 208 is one option to provide guidance for what is reasonable conduct in light of the market analysis conducted in this proceeding, we find clear rules of the road will be valuable to all broadband data service providers as the market evolves. Accordingly, in this FNPRM, we propose a new regulatory framework for broadband data service that distinguishes between broadband data service providers based on market circumstances, rather than technology or the happenstance of prior Commission action and inaction.
64. The proposed technology-neutral framework will apply depending on the classification of a specific market as either competitive or non-competitive. This framework will depend on the adoption of a new Competitive Market Test to then determine whether market power is present and we additionally seek comment on such test below. As another significant piece of the technology neutral framework, we additionally propose actions to change the regulatory structure for the historically dominant price cap LECs. These proposed rules will establish a path towards technology-neutral regulation for broadband data services, while protecting against harm from lack of competition where it continues to exist.

C. Statutory Authority for New Regulatory Framework
65. Sections 201 and 202 of the Communications Act are foundational requirements for all telecommunications services, designed to ensure that such services are offered to the public on just and reasonable rates, terms and conditions, and that services are not offered on an unreasonably discriminatory basis.
66. These sections have served as the statutory basis for a wide range of rules and other actions over the years. In addition to providing the substantive authority for various rules and requirements, section 201(b) states that the Commission “may prescribe such rules and regulations as may be necessary in the public interest to carry out the provisions of this Act.”
67. We propose that sections 201 and 202 of the Act serve as an adequate basis of statutory authority for actions that the Commission would take to create and implement the Technology-Neutral Framework that we propose to apply to BDS going forward. We have forborne from tariffing provisions for many BDS providers over the years. In this FNPRM, the Commission proposes to transition away from tariffing requirements for the last portion of BDS (incumbent LEC TDM), and to establish benchmarked prices for non-TDM services. We note that the Verizon/INCOMPAS Joint Letter urges that the Commission should make clear “that all providers offering dedicated services are subject to Title II of the Communications Act, including Sections 201 and 202 of the Communications Act.” The Commission seeks comment on whether its authority to ensure just and reasonable prices, terms and conditions under sections 201 and 202, and its explicit rulemaking authority in section 201(b), is adequate to require price cap filings for TDM services and benchmarked prices for non-TDM services.
68. Commenters have noted that the Commission's existing price cap regime was adopted with reference to section 204. If the Commission were to forbear from tariffing provisions for incumbent LEC TDM services, as it has with respect to the incumbent LECs' non-TDM services and all BDS telecommunications services of competitive providers, could it continue to require price cap filings for incumbent LEC TDM services in non-competitive markets based solely on the statutory authority in section 201(b)? Likewise, could the Commission use benchmarked prices to ensure that non-TDM services in non-competitive markets are offered on just and reasonable prices, as required by section 201? If not, why not, and what additional authority or action would be needed?
69. The Commission's proposed Technology-Neutral Framework also would place certain limits on terms and conditions of BDS to ensure that they are offered on just, reasonable, and not unreasonably discriminatory terms, especially in non-competitive markets. We seek comment on whether sections 201 and 202 provide the Commission with the statutory authority to take such actions. If not, why not, and what additional authority or action would be needed?
70. A fundamental aspect of the new Technology-Neutral Framework for BDS would be the adoption of new triggers to determine whether markets are competitive or non-competitive. We seek comment on whether sections 201 and 202 are themselves sufficient to support the adoption of such triggers, which could be used to determine whether (and if so, where) regulations are required to ensure that rates, terms and conditions of BDS services are just and reasonable. We note that such triggers have been tied in the past to the Commission's authority under sections 201-205, and we seek comment on whether the Commission should rely on additional sources of authority.
71. Some entities have suggested that the Commission address certain issues such as wholesale pricing under section 251, where Congress has imposed specific resale requirements. However, section 251 has an explicit savings clause, which states: “Nothing in this section shall be construed to limit or otherwise affect the Commission's authority under section 201.” Does the savings clause indicate that the Commission has ample statutory authority to address resale issues for BDS under section 201 authority, notwithstanding that the statute imposes particular resale requirements on certain types of providers in sections 251(b) (local exchange carriers) and 251(c)(4) (incumbent local exchange carriers)? If not, why not, and what additional authority or action would be needed?
72. Are there any other statutory provisions that the Commission should consider invoking to support a Technology-Neutral Framework for BDS? For example, section 706 of the 1996 Act provides that the Commission “shall encourage the deployment on a reasonable and timely basis of advanced telecommunications capability to all Americans (including, in particular, elementary and secondary schools and classrooms) by utilizing, in a manner consistent with the public interest, convenience, and necessity, price cap regulation, regulatory forbearance, measures that promote competition in the local telecommunications market, or other regulating methods that remove barriers to infrastructure investment.” Does that section have any particular applicability to the actions proposed in this FNPRM, such as promoting competition for BDS and removing obstacles to technology transitions?
73. Finally, we seek comment on whether any transitional or incremental policy actions are appropriate as the Commission considers and moves to comprehensively reform the BDS regulatory framework. Are there incremental changes the Commission could take as it evaluates broader reforms and a Competitive Market Test that furthers our goals? Should we adopt any transition to a new Competitive Market Test and, if so, how should we structure the transition?

D. Competitive Market Test
74. We propose to replace the 1999 pricing flexibility regime with a new regulatory framework for BDS. The new framework, as proposed, builds on the analysis of the 2015 Collection to establish a comprehensive Competitive Market Test to determine whether a relevant market is competitive or non-competitive. Where competition is sufficient in a relevant market, based on objective criteria to measure competitive effects, the Commission is proposing to rely upon market forces to constrain rates, terms, and conditions. That is, we propose to subject markets determined competitive to minimal regulation to protect consumers as proposed in Part V.E. The Commission would subject relevant markets, determined non-competitive, to specific rules as proposed in Part V.F on the ground that customers in those markets are being harmed. A separate question concerns the scope of regulation in a non-competitive market, and whether it should apply to all or some providers and, if some, which ones and on what basis (such as market power)—and we seek comment on these questions below. The ultimate goal going forward is to apply regulatory obligations on a technology and provider neutral basis where it is necessary to protect and promote competition.
75. On the criteria for the Competitive Market Test, we invite comment. Initially, we are proposing a test, which focuses on multiple factors, including bandwidth, different customer classes, business density, and the number of providers in areas consisting of census blocks where each block in the relevant market meets the specified criteria. As described above, the data and our analysis suggests that competition is lacking in BDS at or below 50 Mbps in many circumstances, and that competition is present in BDS above 50 Mbps in many circumstances. Such evidence will guide how the Commission uses product market characteristics in applying the Competitive Market Test to a relevant market. We seek comment on the appropriate factors to include in the test and, in particular, the appropriate weight to attribute to the various factors in application of the test. With any test criteria and for application of the test as a whole, we seek comment on how to create a test that is simple to administer and, to this end, ask about the commercial practicalities and administrative feasibility of any particular approach. We also seek comment on how any approach would further our goals of promoting competition and investment.
76. We propose to apply the Competitive Market Test across all geographic areas served by price cap carriers. The Commission would use publicly available information, the 2015 Collection, and other information in the record to apply the test to create a list of geographic areas that are deemed competitive and non-competitive by relevant product market. To provide certainty but also ensure accuracy of the data, we seek comment on whether the Commission should reapply the test every three years for example, with updated data to reflect changes in business density or the number of providers in a geographic area. Once the initial competitive/non-competitive determination is made, we seek comment on a process to address instances where a provider or purchaser disagrees with the determination finding and suggestions for the appropriate standards and procedures to govern that process.
77. The pricing flexibility framework adopted in 1999 based regulatory relief on the presence of third-party collocations in the incumbent LEC's wire centers, which were considered proxies for competition in the marketplace. In 2012 the Commission concluded after a substantial review that, despite the many administrative benefits to reliance on the triggers, collocations are a poor proxy for predicting the entry of facilities-based competition and suspended, on an interim basis, further automatic grants of pricing flexibility. The Commission found the 1999 regime retained unnecessary regulation in areas that were very likely to be very competitive and deregulated over large areas where competition was unlikely to occur.
78. Our review of the 2015 Collection supports the Commission's earlier findings that the existing triggers do not reflect the existing competitive nature of the market. Specifically, in 97.9 percent of the wire center territories where a cable competitive LEC has reported locations—where the connection to the location is not a UNE obtained from an incumbent LEC, a cable company has not collocated in the wire center. Of these wire centers, 62 percent remain subject to price cap regulation without pricing flexibility for channel terminations. If we include census blocks where a cable company reported having DOCSIS 3.0 coverage for 2013 for the National Broadband Map, the percentage of wire center territories without any collocations from the cable company increases to 98.4 percent. Of these wire centers, 66 percent remain subject to price cap regulation without pricing flexibility for channel terminations. This strongly shows the collocation triggers are substantially underestimating the entry of facilities-based competition from cable companies for last-mile facilities and hindering deregulation.
79. When we look at all competitive providers and remove locations with UNEs, in 32.3 percent of the wire center territories where the Commission has granted the incumbent LEC pricing flexibility for channel terminations, competitive providers have reported no locations where they own or lease, pursuant to an indefeasible right of use (IRU), a connection to a location. If we expand the inquiry to include census blocks where a cable company reported having DOCSIS 3.0 coverage for 2013 for the National Broadband Map, this percentage decreases to 24.7 percent. This shows that collocations at a substantial percentage of wire centers do not accurately predict the entry of facilities-based competition for last-mile connections.
80. We now believe it is appropriate to modernize our triggers to ensure we capture all competitive entrants. Therefore, we propose to abandon the collocation-based competition showings for channel terminations and other dedicated transport services for determining regulatory relief for incumbent LECs. Instead, we propose to apply a new Competitive Market Test. Our intent, discussed in more detail below, is to create a framework that is provider and technology neutral. Our goal is also to create a framework that is simple and minimizes regulation only to the extent necessary to ensure rates are just and reasonable.

1. Business Data Service Definition
81. A definition for BDS is critical to any new regulatory framework. We suggest below a definition similar to the definition used for dedicated services in the 2015 Collection. Specifically, we would define BDS as a telecommunications service that: Transports data between two or more designated points at a rate of at least 1.5 Mbps in both directions (upstream/downstream) with prescribed performance requirements that typically include bandwidth, reliability, latency, jitter, and/or packet loss. BDS does not include “best effort” services, e.g., mass market BIAS such as DSL and cable modem broadband access.
82. We seek comment on this definition and ask whether the definition should include minimum performance guarantees, such as 99.99 percent reliability. Also we seek comment on whether we should reduce the minimum symmetrical speed to 1 Mbps to account for dedicated service offerings below 1.5 Mbps.

2. Multi-Factor Competitive Market Test—Relevant Market(s) and Test Criteria
83. We are guided by traditional economic principles in identifying relevant market(s) and the competition criteria for a Competitive Market Test. We also consider, and seek comment on, the administrative feasibility and commercial practicalities of any particular approach both for providers as well as the Commission. A proposal under consideration, as discussed in more detail below, is to define the relevant market for applying a test along customer classes and varying bandwidths in geographic areas consisting of census blocks, including groupings of census blocks. The proposed criteria for the test would focus on business density and the number of providers in the relevant market area.
84. The Commission has traditionally applied the pricing flexibility competitive showings to two different BDS segments, channel terminations and other dedicated transport services. There is little discussion in the Pricing Flexibility Order as to why the Commission chose these two particular service categories. Historically, incumbent LECs tariffed these services separately, and the charges reflected different traffic sensitivities. The Commission explained in the Pricing Flexibility Order that a lower competitive showing was required for other dedicated transport services because these services, which move traffic from one point of concentration to another, require “less investment per unit of traffic,” than channel terminations. The Commission found that competitors were more likely to enter the market to provide other dedicated transport services than channel terminations. Looking at how non-cable competitive LECs have deployed their networks, we find this approach holds true today for those types of providers (and as discussed above, appears as much driven by bandwidth demand as it does by the channel termination/transport distinction).
85. Developing a new framework, however, gives us the opportunity to re-evaluate the triggers and product markets used in the application of a competitive test to ensure that they reflect technology transitions and the current market. Today, competitors, and even incumbent LECs with their forborne services, do not typically offer consumers BDS by charging a customer separately for transport, last-mile access, and channel mileage. They instead offer connectivity at certain bandwidth levels and performance guarantees and packaged communications solutions that include a transmission component to meet the demands of different types of customers. Our framework should reflect how the market operates today.
86. Moreover, the needs of the customer dictate the service offerings. As discussed in our competition analysis and as providers have told us, different types of customers have different needs. A small business with less than 20 employees at one location is unlikely to need the multi-office networking connectivity, or even the same level of bandwidth capacity, as would a large enterprise customer. The needs of a mobile operator to backhaul aggregated traffic from cell sites are different than the needs of a retail chain wanting to securely process credit transactions. The needs of competitive LECs, as wholesale customers, for last mile access as an input for their own service offerings differ from the needs of retail end users. And as the needs change by customer class so do the service substitutes, the economics of providing service, and the likelihood of facilities-based entry by competitors.
87. We therefore seek comment on whether to apply our Competitive Market Test based on different BDS customer classes at varying bandwidths and ask for comment on whether, and if so how, the Commission should separate the product market by customer type and bandwidth. For example, should the customer classes consist of the following categories: Small business with less than 20 employees, mid-sized businesses with 20-500 employees, national/enterprise businesses with 500+ employees that typically require service at multiple locations? And should we adopt a separate product market to address the cell site backhaul needs of mobile providers and another one for sales to wholesale customers? We seek comment on the benefits of segmenting product markets by customer class and whether the data supports such an approach. In lieu of customer classes by size of retail customers, should we instead have fewer customer classes, such as just wholesale, mobile backhaul, and retail? Or are the benefits of using customer classes outweighed by the burdens due to the complexity and practicality of implementing such a framework?
88. To the extent the Commission adopts such an approach, we seek comment on whether we should also subdivide the relevant product markets by bandwidth to capture the varying demand and competition levels within each customer class. For example, we could divide the wholesale segment into BDS ≤50 Mbps and >50 Mbps. In developing the appropriate bandwidth overlay, we can look to evidence in the record and our own analysis of the 2015 Collection as to the level of competition at different bandwidth levels. To what extent, should evidence indicating that the supply of BDS above 50 Mbps tends to be more competitive than the supply of BDS at lower bandwidths factor into this overlay? We seek comment on whether 100 Mbps or some other bandwidth level is better supported by the evidence in particular market segments? Should we recognize different tiers of products (or distinct product markets) based on differences in speed? Should the bandwidth overlay levels vary depending on a particular customer class? Should the relevant bandwidth level(s) be static or evolve over time? For example, should product market re-evaluation be made part of the review conducted in light of future data collections?
89. We seek comment on these issues and encourage commenters to suggest other alternatives for consideration. Commenters should address whether a customer class/bandwidth approach would appropriately capture the nature of competition in these markets, whether the approach is administratively feasible, the appropriate bandwidth and/or product-feature categories, and whether we should include additional customer classes or make other modifications to the classes identified. For example, is it correct to base a product market identification on speed or do we need to factor in as well additional performance features and, if so, which ones should be used and how should multiple product features be used to identify different product markets? We also seek comment on how various approaches would further our goal of promoting competition and investment for BDS services.
90. In 1999, the Commission chose to grant pricing flexibility on an MSA and non-MSA basis with the intent of defining “geographic areas narrowly enough so that the competitive conditions within each area are reasonably similar, yet broadly enough to be administratively workable.” The Commission in the Suspension Order concluded “MSAs have generally failed to reflect the scope of competitive entry.” In reaching this conclusion, the Commission found “that business demand can vary significantly across an MSA” and that competitive entry tends to occur in smaller areas with the highest density of business establishments. The GAO reached a similar conclusion in 2006.
91. Our analysis of the 2015 Collection further confirms these findings. According to our analysis, the price regressions of incumbent LEC rates for DS1 and DS3 lines show consistent negative effects for the presence of competition in the building, and the census block, much of which is both economically and statistically significant. In addition, the regressions show some effects for the presence of competitive fiber in the census block, even if that fiber is not connected to any buildings in the block.
92. Given our analysis, we seek comment on using census blocks as the geographic area for applying the Competitive Market Test. We also ask whether using a more granular area, e.g., the building or cell site location as the relevant geographic market, or whether a larger geographic area is appropriate. For example, if the geographic area were the building location, the provider's regulatory obligations could change building-by-building, which could make it difficult not only for regulators but also for providers trying to offer services to customers at multiple locations. Could a building approach reduce the challenges to determining the necessary proximity to fiber, thereby simplifying administration? A census block or even census tract approach would create a similar patchwork of geographic areas with different regulatory treatment. Census blocks in metropolitan areas are also often very small in size. For example, according to AT&T, “[t]he average size of census blocks in MSAs with demand for special access services is only about one-seventh of a square mile.” However, we anticipate that areas adjacent to a census block will often have similar business density and facilities-based competitor characteristics resulting in a similar determination as to the level of competition.
93. Our goal is to learn from past experiences and to not repeat the errors of the 1999 pricing flexibility regime by granting relief too broadly to cover areas where competition is not present or unlikely to occur.
94. We seek comment on these proposals. Commenters should address the administrative feasibility of the proposals and how each option would impact the goal of promoting competition and investment in the BDS market. We also invite commenters to suggest alternative geographic units and ask commenters to explain how any alternative is supported by the data and furthers our goals.
95. Our intent, as with any of the proposals under consideration, is to focus regulation on areas where actual or potential competition is insufficient to ensure rates, terms and conditions are at just and reasonable levels. We believe that bright-line criteria are best suited to meet these goals. Based on our review, we have identified two possible criteria for determining whether or not a market is competitive, i.e., business density and the number of providers in the relevant geographic area. We seek comment on these criteria below and whether alternative or additional criteria should be incorporated into the test.
96. Our analysis shows there is a significant correlation between business density and the presence, or likelihood, of competition. We therefore seek comment on the appropriate business density metric for the Competitive Market Test. Should we use the number of businesses establishments in a defined geographic area, the number employees, the level of payroll, or some other variable that is readily available and shown to be a good proxy for business demand? For example, should we look to any census block with more than some number of businesses establishments per square mile? Also to what extent should a different density standard apply when evaluating mobile backhaul? The deployment of cell sites may not necessarily correspond to business density and may more likely relate to population density or public travel areas. Should the Commission instead focus on the density of existing cell sites in a census block area when evaluating a mobile backhaul market? If so, what is the appropriate cell site density metric?
97. Our analysis further shows that the competitive effect on pricing increases as the number of competitors in the area increases. How should we incorporate this into a bright-line trigger? The Commission in the Qwest Phoenix Order found a market with only two competitors, a duopoly, not sufficiently competitive. Should we require more than two facilities-based competitors in any area for a competitive trigger? Are there instances where having just one or two competitors is sufficient given the bandwidth level and business density in a given area? There is also the question of whether the type of competitor in the market makes a difference? Should we weight competition from a cable company differently than a non-cable competitive LEC or vice versa? If so, should this different weighting vary with bandwidth levels? There is also the question of how we identify the presence of a competitor in the area. Is it enough for a competitor to have one served location in the area? Is it enough for a cable company to just have DOCSIS 3.0 coverage over their HFC network in the area or should we weight an HFC network differently based on the presence of Metro-E capable nodes in the area? Should we also base the presence of a competitor on the presence of their fiber in the area or is it the presence of a competitor's fiber node in the area? For each customer class and bandwidth level, should we only count competitors in the area that are currently offering such services to that customer class within the stated bandwidth level?
98. We seek comment on the administratively feasibility of using the above test criteria, and encourage commenters to suggest alternative test metrics.
99. Our goal in creating the Competitive Market Test is to adopt a formula using available data, e.g., publicly available business density information and information provided in the 2015 Collection, and information from the National Broadband Map on the presence of facilities-based providers in a given geographic area, to determine whether or not a relevant market in areas served by price cap carriers is competitive.
100. The Competitive Market Test matrix would generate lists of census blocks or whatever geographic area the Commission adopts for each relevant market determined competitive and non-competitive. The corresponding regulatory obligations would then apply to markets within the relevant geographic area going forward, e.g., census block areas. We seek comment on how to ensure that this information is disclosed in a transparent, easily accessible format. For example, should the Commission create a central repository for information on its Web site that could contain an interactive map, which reviewers could filter by product class like the National Broadband Map? Or alternatively or in addition to a map, should the Commission simply create a publicly available database, which simply contains lists of relevant geographic areas by product market as competitive and non-competitive? Commenters should address which approach would be the easiest to administer and simplest for providers.
101. To provide certainty but also ensure that data are accurate and updated, we seek comment on re-applying the Competitive Market Test across all areas served by price cap carriers every three years to account for example, for changes in business density and the presence of facilities-based providers in geographic areas. This periodic reassessment could coincide with our separate proposal discussed in Part V.J to collect data from providers on their supply capabilities every three years starting in 2018. The re-application of the Competitive Market Test matrix using updated data would likely result in changes to the market delineation established by its prior application. For example, the Commission could subsequently determine a relevant market area, previously considered non-competitive, as competitive based on the updated data. And the opposite might also be true.
102. A periodic reassessment reduces burdens on providers as well as the Commission and balances the need to ensure accurate data. We generally seek comment on the administrative feasibility of this approach, both as a whole and as to its individual parts. We also welcome suggestions for alternative approaches. We additionally seek comment on whether we should provide some implementation period to allow providers to conform operations following the application of the Competitive Market Test before any new regulatory obligations resulting from the determination of a relevant market as competitive or non-competitive are effective? If so, how long of a period should we provide? Commenters should also address the commercial practicalities of changing the regulatory treatment of a relevant market area every few years? For example, how could this impact contractual obligations with customers and to what extent could commercial providers adjust or account for a potentially changing regulatory environment every few years? Should the Commission re-apply the Competitive Market Test less frequently, like every five years?

3. Post-Determination Process
103. We ask to what extent and how the Commission should give providers and purchasers an opportunity to challenge the determinations rendered. We seek comment on how best to structure such a process to minimize administrative burdens on providers, purchasers, and the Commission.
104. We seek comment on the timing and frequency of such post-determination challenges. Should the Commission open a window to permit challenges within a specified period of time after the Competitive Market Test determinations are rendered, e.g., 30 or 60 days? If commenters believe that challenges should be permitted on a rolling basis, how would that impact market certainty and the transactions between providers and purchasers of BDS services?
105. We also seek comment on how to build upon lessons learned from the Connect America Fund challenge process. Based on the Connect America Fund experience, we believe a specific, bright-line test is appropriate to ensure that the Commission has data necessary to evaluate the merits of any challenges. We propose that parties seeking to challenge an area determined non-competitive to be designated as competitive should have the burden of proof to provide data demonstrating that the given area satisfies the Competitive Market Test. Should the same hold true of a challenge that a competitive market is non-competitive? What standards or showing should the challenger have to make to overcome a Competitive Market Test determination? For example, should challengers be required to submit new maps of fiber? In addition to providing challengers with access to data collection results subject to confidentiality restrictions, should the Commission give challengers a limited right of discovery to obtain information from providers to help make their requisite showing? If so, should the petitioner be required to meet a threshold evidentiary burden to initiate discovery and what should that be?
106. Should there be a different process if a provider challenges that an area determined competitive is non-competitive? What standard should apply? Is pricing data relevant or just the number of providers? Should the burden shift upon a prima facie showing? If so, what should constitute a prima facie case?
107. To the extent the Commission adopts product markets, how should such product markets factor into a challenge process? For example, what evidence would be necessary to show that a certain class of business customers face competition but smaller businesses do not?
108. In evaluating any challenges, should we limit filings to an affirmative case and a response? Should all challengers be required to submit certifications from officers attesting to the accuracy? We seek comment on how the Commission could build upon lessons from the Connect America Fund challenge processes to improve the implementation and reduce burdens for providers and the Commission.
109. We also seek comment on the how the Commission should implement the results of a post-determination challenge. If a challenge were successful, we propose that any determination for the relevant market changed from competitive to non-competitive as a result of the challenge (thereby changing the regulatory treatment of the relevant market area) would apply prospectively. If a successful challenge resulted in the change of a determination in 2017 to competitive, hypothetically, how should the Commission treat this relevant market area when it comes time to reapply the Competitive Market Test in a later year, like 2018? Should the Commission just reapply the test at that time, which could then trigger another round of challenges for that relevant market depending on the outcome of the determination?
110. Any post-determination process that allows for challenges or even a request for waiver raises serious administrative feasibility and burden concerns for the agency. The Commission must weigh the equitable benefits of allowing such a process to prevent undue harm to providers and customers in the relevant markets against these concerns. We seek comment on the above questions and invite commenters to suggest alternatives balancing benefit and burden.

4. Regulation for Provider(s) in Areas Determined Non-Competitive
111. Once the Competitive Market Test is applied, we ask which provider(s) should be subject to the specific rules that apply to markets determined non-competitive. Should such rules only apply to the largest BDS provider in the non-competitive market as measured by network coverage, locations served, revenues or some other metric or metric combinations? If so, how would we define the appropriate measure of “largest” ( e.g., share of customers, share of revenue)? If we borrow upon antitrust principles and Commission precedent that focused on dominance, should we focus on the provider with the largest market share and therefore market power? Should we focus on the provider with the largest market share? If so, what is the appropriate measure of market share?
112. Alternatively, should we apply specific rules to any firm in the non-competitive market that has a near ubiquitous network in the local territory and rights of way? This could result in specific rules applying to more than one firm in the non-competitive area. Another approach is to apply this framework to all BDS providers in the non-competitive area. However, such an approach could apply additional regulation to new entrants with little or no market share. Given our desire to promote new competitive entry, should new entrants or providers with market share below a certain threshold not be subject to all or some of the proposed rules applicable to non-competitive markets? If so, what is the appropriate market share where providers should be exempt from such framework and why? Is there a better way to encourage new entrants?
113. We seek comment on these questions. Commenters should consider the regulation that would apply, as proposed in Part V.F where the Competitive Market Test resulted in a finding of a non-competitive service area. For example, if it were merely that our proposed benchmarks would apply to disputes about whether a price is just and reasonable, this may not impact providers that currently price below the benchmark. Other proposals, such as limitations on terms and conditions, may be more onerous.
114. Commenters should specifically address the potential impacts on infrastructure investment, innovation, administrative feasibility, and commercial practicalities of any particular approach. We also ask commenters to explain how each approach minimizes regulation to where necessary to ensure that rates, terms and conditions are just and reasonable in the absence of competitive pressures to do so. Commenters should also address the Commission's ability to implement any particular approach given the previous grants of forbearance authority to incumbent LECs for packet-based and optical carrier transmission services.

E. Rules Applying to All Markets
115. We first propose limited requirements that would apply to the provision of BDS in all markets, both competitive and non-competitive. All BDS providers are common carriers and, are subject to sections 201 and 202 of the Act. The Commission has long relied on these provisions to ensure just, reasonable and non-discriminatory conduct by competitive telecommunications service providers and we do so here. We have, however, identified an area for which a general prohibition could be valuable in our effort to facilitate the evolution of competitive markets. The proposed rule would limit the use of NDAs to block providers from sharing, subject to appropriate protective orders, the terms of business data services commercial agreements with the Commission and other government entities with oversight responsibilities. Such agreements have restricted competitive LECs from providing information that we believe would have been useful in the course of this proceeding and we find that they could inhibit the Commission's oversight of the business data services market going forward. We additionally seek comment on certain terms and conditions we found unlawful in the Tariff Investigation Order and whether such provisions should be prohibited in connection with the provision of BDS either generally or more narrowly in non-competitive markets. These proposed requirements would be technology neutral in nature and would form a part of our proposed overarching framework for the regulation of BDS generally.

1. Non-Disclosure Agreements
116. We seek comment on prohibiting the use of NDAs or their functional equivalents in business data service commercial agreements that restrict providers' and purchasers' ability to disclose information to the Commission or other government entities with oversight responsibilities. Competitive LECs have asserted that such requirements preclude them from sharing information with the Commission that would inform the Commission's oversight of the business data services market. We recognize that such agreements contain commercially sensitive information and underscore our continuing commitment to ensure the protection of confidential information submitted to the Commission through our protective orders.
117. We acknowledge the important role NDAs play in ensuring the protection of confidential information in commercial agreements. Parties to a commercial agreement have the right to seek protection of their confidential information and would be unlikely to enter into such commercial agreements without reasonable assurance that their sensitive business information would not be compromised. The Commission is fully cognizant of this need and ensures confidential data submitted by parties is accorded all necessary protections, principally through the use of protective orders. Protective orders have almost universally fulfilled their purpose. In the rare cases that confidential information has been misused by a party, the Commission has undertaken appropriate steps to ensure the protective orders are enforced.
118. While we respect the importance of protecting parties' confidential information, the Commission must also ensure its access to the information necessary to discharge its core statutory duties. NDAs that obstruct this access may unreasonably interfere with the core oversight functions of the Commission and undermine the public interest in a full and complete record on which the Commission can base its decisions. We therefore propose several alternative prohibitions and restrictions on NDAs for business data service commercial agreements. First, we seek comment on adopting a prohibition on NDAs for commercial agreements that bar the provision to the Commission of any information regarding a commercial agreement. While such NDAs may be uncommon, should any such NDAs be permitted? We seek comment on the effect allowing such NDAs would have on the Commission's fact finding efforts and on its ability to base its decisions on all relevant information. We also seek comment on whether there are any circumstances which would justify precluding parties' ability to share any information in such a blanket fashion.
119. Second, we seek comment on whether the Commission should prohibit NDAs that effectively require the Commission's legal compulsion before parties are able to produce information from a business data service commercial agreement. Do NDAs that require parties to disclose confidential information only when required to do so by the Commission unduly restrict the Commission's access to information necessary to discharge its statutory functions? To what extent does this kind of constraint in practice restrict the Commission's ability to access information to the small number of cases where it is both aware of the existence of a commercial agreement and can devote the time and resources necessary for issuing an express direction for the production of information from the agreement? To what extent do such NDAs place the Commission in a quandary where it can only access information it specifically seeks, the existence and substance of which the parties are bound not to disclose?
120. Finally, we seek comment on whether we should prohibit NDAs that limit parties to disclosing information subject to an NDA only in response to a request by the Commission (in a notice of proposed rulemaking, a public notice or otherwise). Such a prohibition would allow parties to disclose information to the Commission on a voluntary basis at their own initiative and apart from any express request by the Commission. We note that the Commission has previously imposed rules effectively requiring a prior request from the Commission before parties could disclose information subject to an NDA. Section 51.301(c)(1) of the Commission's rules states that “a nondisclosure agreement that precludes [a] party from providing information requested by the Commission” is a violation of the section 251 duty to negotiate in good faith. Should the Commission adopt similar restrictions on NDAs in business data services commercial agreements? Would such an approach to NDAs impact parties' advocacy before the Commission? Would it still constrain the Commission's access to important information from commercial agreements? As with NDAs that require legal compulsion prior to disclosure, how would the Commission know to request disclosure of information in commercial agreements that it may have no way of knowing existed?
121. Eliminating the requirement of a prior request for information would effectively enable parties to disclose information from a commercial agreement on a voluntary basis. We seek comment on whether this is an appropriate approach for the Commission to take. TDS Metrocom notes that NDAs impact parties' ability to fully participate in the rulemaking process. It states that the “practice of subjecting the rates, terms, and conditions of commercial Ethernet agreements to confidentiality restrictions impedes TDS CLEC's ability to advocate in support of new rules and detect unreasonable and discriminatory rates.” Would allowing parties to disclose voluntarily information from a commercial agreement enable fuller and freer advocacy by those parties? Would it also assist the Commission in identifying issues that it otherwise would be unaware of? We also seek comment on how the Commission would ensure the confidentiality of such information once disclosed to the Commission. To the extent the information was related to an existing proceeding, the Commission would presumably either have already adopted a suitable protective order or would be able to do so in response to such a submission. What steps should the Commission take to ensure the protection of such information if the information was not related to an existing proceeding? Are there any other steps the Commission should take to ensure the protection of confidential information voluntarily submitted by a party?
122. Additionally, we seek comment on whether there are other types of NDAs or confidentiality provisions that may inhibit the Commission's discharge of its core oversight and fact finding functions. If so, we seek comment on whether the Commission should also prohibit these or take some other action to modify them. We seek comment on how any rules the Commission adopts related to NDAs or other confidentiality provisions should affect existing contracts? Finally, how would the Commission implement a prohibition on NDAs that restrict its access to information contained in commercial agreements?

2. Scope of Application of Terms and Conditions Requirements Adopted in the Tariff Investigation Order
123. In this section of the FNPRM, we seek comment on the scope of application of the three requirements we adopt in the accompanying Tariff Investigation Order to other tariff pricing plans not subject to the tariff investigation and to commercial agreements for IP based business data services such as Ethernet. We also seek comment on whether such requirements should be applied in non-competitive markets or more generally in all markets.
124. In the Designation Order, the Bureau designated for investigation “all-or-nothing” provisions in certain incumbent LEC tariff pricing plans that required customers that participate in one of the plans to make all of their TDM purchases out of that single plan. In the Tariff Investigation Order, we determined that all-or-nothing provisions are unreasonable and anti-competitive because they restrict a customer's purchase options from both incumbent LECs and other providers.
125. We seek comment on whether we should extend the Tariff Investigation Order's prohibition on all-or-nothing provisions in the plans under investigation to a general prohibition on all-or-nothing provisions in all business data services, including both tariffed offerings and commercial agreements, and whether such a prohibition should be imposed in noncompetitive markets or in all markets. We seek comment on whether other pricing plans or other providers use all-or-nothing provisions or provisions that have materially similar effects for purchasers of TDM or packet business data services. How common are such provisions in TDM tariffs or Ethernet commercial agreements? If all-or-nothing provisions are used in other tariffs or in commercial agreements, what is the business justification for using them? What impact do all-or-nothing restrictions have on the transition to IP business data services? How, if at all, are such requirements different for Ethernet than TDM business data services? Do Ethernet commercial agreements raise any special considerations that would merit unique consideration? Do these provisions help providers lower costs or create efficiencies? If so, we seek quantification of these costs and whether there is any rational relationship between these costs and efficiencies generated by all-or-nothing provisions? Additionally, we seek comment on whether we should impose such a prohibition on noncompetitive markets or all markets.
126. We also seek comment on potential issues regarding the implementation of a prohibition on all-or-nothing requirements. To the extent there are other tariffed incumbent LEC pricing plans or contract tariffs that contain all-or-nothing provisions, how should the Commission implement this proposed prohibition? Should such a prohibition be effective immediately upon publication in the Federal Register ? Should it consider a transition period to allow parties to implement this rule? If so, what would be an appropriate transition period for phasing out these provisions? Should the Commission institute a fresh look opportunity to enable customers of existing pricing plans with all-or-nothing restrictions to remedy the effects of these restrictions prior to the expiration of their current, often long term, pricing plans.
127. Multiple purchases under a single plan. We also seek comment on whether we should find unreasonable restrictions on customers' ability to participate in an incumbent tariff pricing plan more than one time concurrently. In other words, should customers be restricted from splitting their purchases under one pricing plan into two or more separate agreements and managing those separately? Some incumbent LEC tariff pricing plans address this issue and expressly restrict customers to participating in a single version of a pricing plan at any one point in time. For example, the RCP in the CenturyLink Tariff F.C.C. No. 11 states: “A customer can have only one RCP in effect at a time.” We seek comment on whether other pricing plans impose a similar requirement in this or other ways.
128. We seek comment on whether these restrictions on customers are reasonable. Should incumbent LECs effectively force customers to aggregate all their purchases into a single purchase under a pricing plan? Would eliminating such restrictions and allowing customers to split their overall purchases under a pricing plan into separate purchases under that plan provide them with greater flexibility in managing their purchases? Would it allow competitive LECs to better manage increasing shortfall penalty liability in a declining TDM market that is transitioning to packet business data services? We also seek comment on the business rationale for such a requirement. What additional management or tracking burdens would this impose on incumbent LECs and how significant would they be? Can such costs or burdens be quantified? How would any such administrative burdens compare with the benefits of added flexibility for customers in the business data services market?
129. We also seek comment on whether such restrictions are used in Ethernet commercial agreements. If so, commenters should cite examples and discuss the impact they have on customers' flexibility in managing their Ethernet purchases. Would allowing customers to treat their purchases under one Ethernet commercial agreement as separate purchases impose any burdens on providers of business data services? Would the benefits of increased flexibility outweigh any such burdens? Should the Commission prohibit such restrictions solely in noncompetitive markets or should it prohibit them in all markets?
130. Shortfall penalties are fees that are imposed for violations of percentage-based commitments, which competitive LECs assert require them to maintain a large proportion of their total spend with an incumbent LEC provider to obtain discounts and circuit portability typically necessary for wholesale providers. In the Tariff Investigation Order, we found shortfall penalties that provided compensation beyond a price cap LEC's expectation damages were unreasonable and directed certain price cap LECs to remove such provisions from their tariffs under investigation and directed them to make tariff revisions consistent with the terms of the order. We seek comment in this FNPRM on whether we should prohibit the assessment of shortfall penalties that provide compensation beyond expectation damages. Should we prohibit such penalties both in tariff pricing plans and in commercial agreements and should any such prohibition be imposed only on noncompetitive markets or also on competitive markets?
131. We now seek further comment on the reasonableness of shortfall penalties that are contained either in tariff pricing plans that were not the subject of the Bureau's tariff investigation or are contained in commercial agreements for the sale of IP-based business data services. We seek comment on whether shortfall penalties should reflect the economic costs of breaching an agreement or whether they should be set at some other level. Would unreasonable and excessive penalties impair providers' ability to transition to IP based business data services? Could such penalties negatively affect wholesale competition and end-user customers in the form of higher prices, reduced innovation, and reduced investment in broadband services?
132. We seek comment on whether the standard for assessing the reasonableness of shortfall penalties that we adopted in the Tariff Investigation Order should be applied more broadly to all providers of TDM and packet-based BDS through either tariff pricing plans or commercial agreements and either in noncompetitive markets or in all markets. We propose that any action we take in this regard should be applied on a technology neutral manner. Would such a standard allow providers to recover from their customers in the event of a breach sufficient, insufficient or excessive damages? We seek comment on the wide variety of methodologies for calculating shortfall penalties both in tariff provisions and commercial agreements. Commenters advocating for other measures of reasonableness for shortfall penalties should explain their concerns with the proposed standard and identify an alternative standard and provide examples.
133. We seek comment on what approach would best ensure that both parties to a contract, whether through a tariff or a commercial agreement, receive the benefit of their bargain. Would a higher ceiling on reasonable penalties distort market incentives and lead to a windfall for providers? Would a lower ceiling be sufficient to compensate providers? We note that some incumbent LEC plans assess shortfall penalties that are a fraction of full expectation damages for DS1 and DS3 services. Would it be reasonable to require incumbent LECs to apply these lower penalty calculation methods to all plans? If providers currently have shortfall penalties that are a fraction of expectation damages in some of their plans or agreements, should they be allowed to adopt higher penalties without first substantiating a reasonable basis for an increase? What showing should such providers have to make? For example, if carriers claim shortfall penalties are necessary to recover their risks and costs, should they be required to make a cost showing or some other financial demonstration to justify the level of the shortfall penalty?
134. We also seek comment on the impact of shortfall provisions in tariff pricing plans on customers' Ethernet purchase and construction decisions. The record shows that, if these penalties are not set equitably and reasonably, they can provide incumbent LECs with economic leverage that may cause competitive LEC customers to forgo purchasing IP-based business data services and other services from potential competitors or self-provisioning these services over their own networks. For example, competitive LECs have provided evidence that the decline in TDM sales has exposed wholesale buyers to ever-increasing shortfall penalties, which in concert with high purchase commitments and the need for circuit portability, have “left them no choice but to commit to purchasing large volumes of Ethernet from incumbent LECs in return for relief from the penalties.” Would ensuring the reasonableness of shortfall penalties provide relief for competitive LECs that claim to experience pressure to make most if not all Ethernet purchases from price cap LECs where a shortfall liability is present?
135. Finally, we seek more specific comment on the framework that should be applied to ensure the reasonableness of shortfall penalties in commercial agreements for the provision of IP-based business data services both in noncompetitive and competitive markets. Competitive LECs have provided evidence of the use of shortfall fees in Ethernet commercial agreements. We seek comment on the use of shortfall fees in commercial agreements generally. How common is the use of shortfall fees in commercial agreements, overlay agreements, and other agreements for the provision of Ethernet service? How are such fees calculated and by what methodology are they set? How do they impact the dynamics of the market for Ethernet services? What are the economic costs that providers and purchasers face in the event of a breach? What is the best way to structure shortfall penalties in Ethernet commercial agreements so that they reasonably compensate providers while not excessively penalizing purchasers?
136. Early termination fees, as distinguished from shortfall or other fees, are charges assessed on a purchaser under business data services tariff pricing plans if a purchaser exits the plan prior to the expiration of the purchaser's term commitment. In the Tariff Investigation Order, we found early termination fees to be unreasonable when they allow the incumbent LEC seller to recover damages that exceed the lesser of either: (1) The revenues the incumbent LEC would have received if the purchaser had retained the circuit or circuits through the end of the term commitment; or (2) the revenues the incumbent LEC would have received if the purchaser had paid the lesser discount corresponding to the shorter term the purchaser actually used the circuit or circuits. We also found that certain tariffs at issue contained early termination provisions in excess of this measure of damage, concluded such provisions are unjust and unreasonable practices under section 201(b), and directed the incumbent LECs to revise their tariffs accordingly. We now seek comment on whether and how the Commission should consider imposing constraints on early termination fees beyond the plans subject to the tariff investigation and what the scope of such constraints should be.
137. We first seek comment on imposing limits on early termination fees in other price cap LEC tariff pricing plans and contract tariffs for the provision of TDM based services. Competitive LECs assert that incumbent LECs failed to provide cost justification or other support for the early termination fees they charge. For example, in the tariff investigation, the Joint CLECs argue that incumbent LECs did not attempt to “quantify [their] fixed and incremental costs or the extent to which both have already been recovered over many years of charging customers for DS1 and DS3 services.” Sprint also asserts that incumbent LECs are “unable to explain why it is reasonable to impose penalty amounts that bear no relationship to the costs of [ ] early termination, and that frequently exceed even the amount the customer would pay if it met its commitment level.” On the other hand, incumbent LECs assert that early termination provisions are necessary to enforce term commitments and that they are calculated reasonably. For example, AT&T argues that early termination provisions in its tariffs are “lower than what the customer would have paid if they had held the circuit to term.” CenturyLink contends that “[e]arly termination fees help ensure that at least a portion of the expected revenue stream on which CenturyLink's investment was premised will continue over the life of the customer's commitment, and to provide some compensation to CenturyLink if it does not.”
138. We seek comment on the use of early termination fees more generally and on their potential impact on the development of competition and the technology transitions. Are early termination fees that penalize customers beyond the full cost of the term plan they agreed to reasonable? We seek comment on whether we should extend and apply the framework we adopted in the Tariff Investigation Order to other providers of TDM and Ethernet-based business data services either solely in noncompetitive markets or in all markets. That framework entailed capping early termination fees at the lesser of either: (1) The revenues the incumbent LEC would have received if the purchaser had retained the circuit or circuits through the end of the term commitment; or (2) the revenues the incumbent LEC would have received if the purchaser had paid the lesser discount corresponding to the shorter term the purchaser actually used the circuit or circuits.
139. In commenting on this proposal, commenters should address the following questions. Do these two measures adequately compensate providers without excessively penalizing customers? Are there other ways to calculate a reasonable early termination penalty? Would a cost-based calculation be appropriate? Are there any circumstances where a penalty that compensates providers beyond their opportunity cost is reasonable? If so, please describe such circumstances and what evidence a provider could use to establish that such a penalty is reasonable? What showing should the Commission require if a provider seeks to raise its existing early termination fees? Commenters are invited to discuss factors that the Commission might take into consideration in calculating reasonable early termination penalties, such as cost studies, revenue expectations, avoided maintenance and administrative costs, and any alternative means of valuing parties' expectations.
140. A number of existing tariff pricing plans set early termination fees lower than this proposed standard. Some assess fees that represent only a fraction of the incumbent LEC's revenue expectations under the plan. These penalty amounts were filed as part of the incumbent LECs' tariffs and therefore presumably provide reasonable compensation to the incumbent LEC in the case of a customer's breach of its term commitment. We therefore seek comment on whether we should impose an upper bound on what we would consider a reasonable early termination fee that is lower than the incumbent LEC's revenue expectations under its plan. To the extent commenters suggest lower limits for early termination fees, they should provide business and cost justification for their recommendations.
141. Further, we seek comment on whether, in the case of the retirement of a copper network, to require providers to eliminate any early termination fee liability where the termination is caused by the provider electing to discontinue the plan or service that is the subject of the term commitment. In such cases, where it is the provider's decision to cancel the service, is eliminating early termination fees appropriate so as not to penalize the customer? Are there any circumstances under which providers could reasonably assess early termination fees in this situation?
142. We also seek comment on any unique issues that would arise in applying this prohibition on early termination fees in commercial agreements for Ethernet-based business data services, either solely in noncompetitive markets or in all markets. Do overlay or other commercial agreements for the provision of Ethernet-based service assess early termination penalties? At what level are these penalties set? How are early termination penalties calculated in these commercial agreements? What are the economic costs that providers and purchasers face in the event of a breach? What is the best way to structure early termination fees in Ethernet commercial agreements to ensure that such fees reasonably compensate providers while not excessively penalizing purchasers?

F. Rules Applying to Non-Competitive Markets
143. We next propose requirements that would apply to the provision of business data services only in those markets that are characterized as non-competitive. These rules are intended to provide clear guidance as to what conduct is just and reasonable in a non-competitive market and thereby facilitate the resolution of disputes through commercial negotiations and we seek comment generally on what actions should be taken to ensure that conduct is just and reasonable in a non-competitive market. Providers with market power are able to exercise such market power to the detriment of their customers. Recognizing that the market is evolving and competition may develop in many markets not currently subject to material competitive effects, these rules are intended to constrain potentially anti-competitive conduct while also providing the flexibility to allow all providers to respond to competition. Like the limited rules that would be applicable in all markets, these proposed requirements would be technology neutral in nature and would form a part of our proposed overarching framework for the regulation of BDS generally.

1. Price Cap Regulation
144. We believe that we should continue to apply price caps to business data services now subject to price cap regulation to the extent an application of our proposed Competitive Market Test determines that such price regulation is necessary or such services are not otherwise made subject to an alternative pricing mechanism. The principal price cap services are TDM business data services ( i.e., DS1 and DS3 services). Elsewhere in this order, we propose a number of actions that will impact how and to which services price caps will continue to apply. As described above, we propose to adopt a Competitive Market Test as a basis for determining which broadband data services are competitive or non-competitive. And, as described below, we propose to remove competitive TDM services from price cap regulation. We further propose to subject non-competitive TDM services to price cap regulation and allow for providers to enter into individually negotiated agreements for such services. Finally, we propose and seek comment on maintaining price caps for non-competitive TDM services consistent with these proposals on a non-tariffed basis. While we seek comment on our view and each of these proposals individually, we ask commenters to keep all these proposed actions in mind and address advantages or concerns with their collective impact as appropriate in their comments.
145. We also seek comment on the scope of the application of rate regulation in non-competitive markets to packet-based BDS (and, as well, to TDM BDS). At some point in the future, there may be non-competitive BDS markets in which TDM is no longer available. In such a case, how would we regulate the non-competitive business data services? How do we ensure the regulation we adopt here is technology-neutral and sufficient to permit it to be applied to such a non-competitive BDS market?
146. As discussed above, the record makes clear that the market for lower-bandwidth TDM business data services such as those currently subject to price caps is non-competitive in significant measure. Firms with market power do not have incentives to price services at just and reasonable levels consistent with section 201 of the Act. We believe that the price cap system, as modified by any measures we adopt in this proceeding, will limit the extent to which price cap LECs can exercise their market power over non-competitive TDM BDS rates. When properly applied, price cap regulation replicates the beneficial incentives of competition in the provision of business data services while balancing ratepayer and stockholder interests. The price cap indices provide benchmarks of price cap LEC cost changes that encourage them to become more productive and innovative by permitting them to retain reasonably higher earnings. Those indices are designed to limit the prices price cap LECs charge for service to just and reasonable levels. By establishing limits on prices carriers can charge for business data services, and placing downward pressure on those limits or “caps,” price caps creates a regulatory environment that incentivizes carriers to become more productive and forces them to pass a portion of their cost savings to ratepayers.
147. We are not aware of any other presently available alternative to price cap regulation that more effectively balances the interests of ratepayers and carriers. For instance, extending Phase II pricing flexibility relief to services presently under price caps would be inconsistent with our findings that these services are provided in non-competitive areas. Applying rate of return regulation, in contrast, would entail overcoming daunting administrative challenges and would dampen firms' incentives to become more productive. And consistent with our proposal below to apply a technology-neutral anchor or benchmark pricing system to all business data services, we also propose to use TDM BDS rates as the benchmark for establishing reasonable packet-based BDS rates. Accordingly, we believe we should continue applying price cap regulation to BDS, including TDM DS1 or DS3 services, to the extent an application of our proposed Competitive Market Test determines such services are non-competitive. We invite comment on the above analysis and on these views.
148. We invite comment on extending price cap regulation to business data services presently subject to Phase II pricing flexibility to the extent an application of our proposed Competitive Market Test determines such services are non-competitive consistent with our proposal below. We believe that we should not take that step—or indeed apply any sort of ex ante pricing regulation—where our analysis shows that the market is competitive. We invite comment on this approach.
149. A productivity-based X factor and a corresponding inflation measure had been a fundamental feature of the Commission's price cap system from the system's inception in 1987 until the adoption of the CALLS plan. This balance reflected two propositions that we believe are essential to any effort to ensure reasonable rates in non-competitive markets: (a) That the service provider have an opportunity to recover its costs of service; and (b) that the ratepayer benefit from any decrease in those costs in much the same way as a customer in a competitive market benefits from cost decreases. We believe we should restore this balance between ratepayer and price cap carrier interests by incorporating a productivity-based X factor into our price caps system for business data services on a forward-going basis. We invite comment on this view. We also ask whether we should make any adjustments to current price caps to reflect any past productivity gains that were not reflected in our past regulatory regimes. Below, we propose corresponding action to regulate the rates of IP-based BDS in non-competitive markets.
150. The goal of price cap regulation is to have rates and output levels roughly mirror rates and output levels in a competitive market, at least on average over an extended period of time. If inflation outpaces productivity growth, price cap rates may become unreasonably low. Conversely, if productivity growth outpaces inflation, companies with market power will be able to charge unreasonably high rates. Our current system, in which the X-factor equals its inflation measure, implicitly assumes that changes in business data services productivity perfectly offset inflation in the general economy. We think such a perfect offset likely did not occur in the business data services industry during the period since the expiration of the CALLS plan. Given the rapid growth in business data services output, and the ever-increasing economies of scale with respect to providing business data services, per unit costs likely have decreased significantly since that time. We seek comment on whether this analysis is correct and, if so, whether this productivity trend will continue.
151. Over the period since the expiration of the CALLS plan, as technology has evolved and for other business reasons, price cap LECs, like other LECs, have been consolidating TDM switches, placing soft-switches, increasing fiber deployments, and decreasing maintenance costs. We believe that, as a consequence, business data services productivity growth has significantly outpaced inflation and therefore that the price cap LECs are likely charging unreasonably high rates. In a regulatory environment where prices fail to reflect productivity gains and, consequently, carriers set prices too high, end users will purchase less of the services produced, and the quantity of output will be lower than if prices were set at a competitive level. The productivity of which the plant is capable will not be realized.
152. We note that some price cap LECs assert that their costs have risen and the fact that the X factor has been set equal to the GDP-PI has forced them to charge below-cost prices. We are skeptical of this claim: These price cap LECs have not provided any evidence to support their claim that business data services productivity increases have departed from historical patterns and now lag behind productivity increases in the economy as a whole. Additionally, we note that no price cap LEC has filed any request that we examine the frozen productivity factor in light of their claimed increased costs. But even if we were to accept the price cap LECs' claim, that would only prove that we need to restore the fundamental balance between carriers and ratepayers inherent in the Commission's price cap system.
153. Competitive LECs, in contrast, maintain that price cap LECs have been reaping the benefits of cost-saving productivity gains and have not passed these cost savings to customers. If the competitive LECs are correct—as our analysis strongly suggests, prices are higher than an appropriate X-factor would have produced. We therefore believe we should incorporate a productivity-based X factor into our price caps system for business data services. We invite comment on the above analysis and this approach.
154. We agree with Sprint that we should explore all available methodologies for determining a productivity-based X-factor for business data services. Accordingly, we seek comment on several methodologies and ask the parties to suggest additional alternatives that they believe will lead to reasonable rates for those business data services regulated under price caps.
155. We believe that we should balance potential precision with administrative feasibility in deciding how to set a productivity-based X-factor. Measuring past productivity and predicting its future trajectory are inexact sciences; we are not required “to enter precise predictive judgments on all questions as to which neither [our] staff nor interested commenters [are] able to supply certainty.” On the contrary, we believe that we may properly rely on available data to estimate productivity growth in the provision of business data services and use that estimate to calculate a reasonable productivity-based X factor. We invite comment on this analysis and on how we should balance potential precision with administrative feasibility in setting a productivity-based X-factor.
156. We invite comment below on three methodologies for calculating a productivity-based X-factor and corresponding price cap indices adjustments. We think these methodologies capture cost-reduction incentives while mimicking competitive-market outcomes by using projections of productivity gains, rather than actual values, based on historical trends. They calculate possible productivity-based X-factors by taking the difference between an economy-wide rate of inflation and the growth rate of industry input prices and the projected growth rate of a firm's productivity level.
157. Our calculations rely on three data sources: (a) The U.S. Bureau of Labor Statistics' (BLS's) Capital, Labor, Energy, Materials, and Services (KLEMS) data; (b) data from the peer review process in connection with the deployment of the Commission's Connect America Cost Model (CACM); and (c) those data in combination with cost data that TDS submitted in this proceeding. We seek comment on whether data from these sources provide a reasonable basis for calculating a productivity-based X factor. Do they properly balance potential precision with administrative feasibility? Are there alternative sources of data that would more precisely calculate productivity increases in the provision of business data services? If so, would the additional precision associated with obtaining those data and using them to calculate a productivity-based X-factor outweigh the associated burdens?
158. The KLEMS data used in our calculations are publicly available, annual industry-level data on industry-level measures of input prices and total factor productivity (TFP) for the telecommunications and broadcasting industries. We seek comment on any adjustments to the KLEMS data that we should make to improve its utility as a measure of business data services productivity. We seek comment on the relevant years for which we should use KLEMS data.
159. In response to a peer review of the CACM, the CACM was used to generate cost share data for ten cost categories. Are there other cost categories that we should include or should we exclude some of these cost categories from our calculations? Does combining CACM peer review data with company-specific data, such as the TDS data used in calculating the proposed X factor and corresponding adjustments to price cap indices, provide a more precise estimate of business data services productivity growth? Are there other sources of available company-specific cost data that would increase that precision?
160. We invite comment on whether we should require price cap LECs to submit their expense matrix data from 2005 to 2015? If so, should we require that these data be reported using the categories previously required under the Commission's rules and, if not, what categories should we specify? Would the benefits from these data outweigh the burdens?
161. We ask whether we should require the price cap LECs to submit cost studies, as Sprint suggests, to help us determine business data services productivity growth. If so, what methodology should we specify for those costs studies? Would the benefits from relying on company-specific data from these cost studies, as opposed to economy-wide or industry-wide KLEMS and CAPM data, outweigh the burdens?
162. We invite comment on whether and, if so, how we may use the pricing data collected in this proceeding to supplement our other calculations. Would regressions comparing prices for DS1 and DS3 services in competitive and non-competitive areas provide proxies for the minimum amount that prices should have fallen in non-competitive areas and, if so, how we should use those proxies in setting an X-factor and price cap indices adjustments? We seek comment on the pros and cons of using regressions to supplement other X-factor calculations. We ask the parties to submit their own regressions.
163. We seek comment on whether we should incorporate a consumer productivity dividend into our price cap system. If so, how should we calculate that dividend? Should we incorporate a dividend component into any X-factor that we set? Should we include such a dividend in a price cap indices adjustment if we decide to take that approach?
164. GDP-PI ( i.e., the gross domestic product price index) is a measure of inflation incorporated into the Commission's price cap index formula as one of three basic components in addition to the X-factor and exogenous cost adjustments.
165. The Commission currently uses the BEA chain-weighted GDP-PI to measure inflation. We find that this measure accurately reflects cost changes that carriers face without being susceptible to carrier influence or manipulation. We propose that we should continue to use GDP-PI as the inflation measure in the price cap index formula consistent with BEA's measure for purposes of setting the X Factor. We seek comment on this proposal.
166. In the 2005 Special Access NPRM, the Commission invited comment on a series of additional issues relating to price caps. These issues included: (a) Whether the price cap index formula for business data services should include a growth or “g” factor to account for any demand growth effects that are not reflected in an X factor; (b) whether the Commission should require price cap LECs to share a portion of their business data services earnings with ratepayers through adjustments to the price cap indices; (c) whether the Commission should retain a low-end adjustment mechanism for price cap LECs that have not implemented pricing flexibility; and (d) whether the Commission should subdivide its special access price cap basket into additional or different categories and subcategories.
167. We ask the parties to update the record on each of these issues. We also ask whether there are any additional issues we should resolve to help ensure that our price cap system produces reasonable rates for business data services in non-competitive markets.
168. A growth or “g” factor would allow ratepayers to benefit from at least of portion of any business data services demand growth effects that are not reflected in a productivity-based X-factor. We invite comment on whether we should adopt a “g” factor and, if so, how we should calculate it. We also ask how we should how we should measure demand growth and how we can ensure that any “g” factor does not double count growth already reflected in a productivity-based X-factor. We ask, in particular, whether demand growth benefits not reflected in an X factor should be shared between business data services providers and their customers. Should any “g” factor we adopt be applied only on a going-forward basis, or should we also adjust the price caps indices to account for prior demand growth?
169. Earnings sharing allows ratepayers to benefit from business data services profitability and was a feature of the Commission price cap regime until 1997. In abolishing sharing, the Commission found that it blunted price cap LECs' efficiency incentives and that eliminating it would remove vestiges of rate of return regulation from the price cap system. We find these reasons persuasive and therefore believe that we should not reinstate sharing. We invite comment on this approach.
170. The low-end adjustment permits price cap LECs that earn a rate of return 100 basis points or more below the prescribed rate of return for rate-of-return carriers to increase their price cap indices in the next year to a level that would allow them to earn 100 basis points below that rate of return. This mechanism is available to all price cap LECS that have not implemented pricing flexibility. In the 2005 Special Access NPRM, the Commission tentatively concluded that, if it were to continue to apply price caps to business data services, it should retain a low-end adjustment mechanism for price cap LECs that have not implemented pricing flexibility.
171. In this FNPRM, we propose below to replace the current pricing flexibility framework with a new technology-neutral framework. Under the proposed framework, price cap LECs' TDM BDS in non-competitive markets will be subject to price caps and can be offered through individually negotiated agreements, a regime that parallels in most practical respects the Phase I pricing rules. And price cap LECs' TDM BDS in competitive markets will be removed from price cap regulation and offered pursuant to commercial agreements. We invite comment on how our action on this proposed paradigm should affect our consideration of whether we should retain a low-end adjustment as part of our price cap system. In particular, should we allow business data services providers that provide their TDM services under these varying regimes to seek low-end adjustments? If so, how can we assure that the providers' claimed earnings on services provided under price caps accurately reflect their costs of providing those services?
172. In March 2016, the Commission reduced the prescribed rate of return for rate-of-return carriers from 11.25 percent to 9.75 percent, subject to a transition. Effective July 1, 2016, this transition will reduce the 11.25 percent rate of return by 25 basis points per year until it reaches the represcribed 9.75 percent on July 1, 2021. We ask that the parties address whether we should use this reduced rate of return to measure eligibility for a low-end adjustment in the event we retain that mechanism. If so, how, if at all, should we adjust the percentage that determines eligibility for a low-end adjustment and the level to which price cap indices are retargeted as this transition proceeds? Specifically, should we use the 9.75 percent prescribed rate of return in considering low-end adjustments when it is effective or should the applicable rate of return track the rate of return transition?
173. A price cap basket is a broad grouping of services, such as TDM services. Prices for services in a given basket are capped by its price cap index. Placing services together in the same basket limits the LEC's pricing flexibility and incentives to shift costs. Within the special access service basket, services currently are grouped into service categories and subcategories. Similar services are grouped together into service categories within a single basket to act as a substantial bar on the LEC's ability to engage in anticompetitive behavior.
174. In the 2005 Special Access NPRM, the Commission sought comment on the categories and subcategories the Commission should establish in a special access basket if we continued to apply price cap regulation to business data services. In response, commenters proposed a number of changes to the categories and subcategories for the special access basket. We ask interested parties to update their comments with respect to the special access basket categories and subcategories in light of technological and operational changes that have occurred in the business data services marketplace since 2005.
175. We seek comment on whether the special access basket should be subdivided into more than one basket, and whether the baskets should be further subdivided into categories and subcategories. We ask whether should use a single basket or multiple baskets and the advantages and disadvantages of each approach. What categories and subcategories should we establish in a BDS basket if we adopt a price cap method to regulate BDS prices? Should we retain without modification for BDS the existing special access category and subcategories? If not, parties should identify the specific categories and subcategories of BDS that they contend we should adopt.
176. We ask parties to discuss the advantages and disadvantages of having a BDS basket with relatively few categories or subcategories compared to one with many. We also seek comment on what criteria and data we should examine to determine which services to place in which categories or subcategories. We ask parties proposing categories or subcategories, to explain in detail the bases for their proposed categories or subcategories, and to support their proposals with data and studies.
177. Should we establish separate categories or subcategories based on BDS line densities? For example, channel termination services extending between a LEC end office and a customer premise in areas where there are more than 10,000 special access lines per square mile could be placed in a particular subcategory.
178. For the same reasons that the Commission eliminated the lower pricing bands, we believe that there should be no lower band for service categories or subcategories to restrict the price cap LECs' downward pricing flexibility. We seek comment on this approach. We likewise seek comment on the upper band value to limit the price cap LECs' upward pricing flexibility for the categories or subcategories. Should we retain five percent as the value? Should we use different values for different categories or subcategories? What criteria and data should we use to determine these values?
179. We invite comment on whether business data services productivity gains have outpaced inflation during the period since June 30, 2005, the date the CALLS plan expired. We ask that the parties support their position on this issue with detailed data and economic analysis. We seek comment on whether in the event we conclude that business data services productivity gains outpaced inflation during that period, we should adjust the baseline price cap levels to capture those gains for ratepayers. As noted above, we propose that a new forward-looking productivity factor should be applied to TDM services in non-competitive markets (with corresponding rate regulation for IP-based BDS in non-competitive markets).
180. As indicated above, our X-factor and price cap indices adjustment calculations rely on BLS's KLEMS data; the Commission's CACM peer review data; and CACM peer review data in combination with TDS cost data. We think our X-factor calculations capture cost-reduction incentives while mimicking competitive-market outcomes by using projections of productivity gains, rather than actual values, based on historical trends. We use a proxy for the growth rate of input prices, a measure of economy-wide rate of inflation based on a national price index ( i.e., GDP-PI) adjusted to account for systematic difference between the growth rates of national prices and telecommunications industry-specific input prices. To adjust the price cap index to account for the historic productivity X-factor, this estimation of X is subtracted from the annual change in the GDP-PI to determine the annual change in the price cap index.
181. We calculate the X-factor by subtracting from the change in GDP-PI, the change in industry prices and add the change in industry total factor productivity (TFP). The change in industry TFP is the difference between the change in TFP for price cap LECs and the change in TFP for the overall U.S. economy. We calculate an input price differential reflecting the historical difference in the average annual rate of change in price cap LEC input prices as compared with the historical average annual rate of change in the economy as a whole. These two factors are then added together for each year and subtracted from the measure of the change in the rate of inflation ( i.e. the change in GDP-PI).
182. Applying this basic calculation, we apply various data sources and models for estimating the inputs in the X-factor equation. From these calculations, we develop a forward-looking X-factor adjustment to the price cap index applied annually.
183. Method One—KLEMS Model. Our first set of calculations rely on KLEMS from BEA and the U.S. Department of Labor's Bureau of Labor Statistics (BLS). The BLS maintains yearly KLEMS statistics on Broadcasting and Telecommunications. These industry-level measures of input prices and total factor productivity (TFP) are publically available. This is the most granular level of industry detail for which KLEMS data is available on a regular and consistent basis. Input price indexes are available for each of the five components of KLEMS—capital (K), labor (L), energy (E), non-energy materials (M), and services purchased from other businesses (S).
184. Commission staff computed three X-factor estimates using KLEMS data: (1) The first estimate uses growth rates that are averaged over all years for which we have data, 1997 through 2013; (2) the second considers only the years for which data would have been available in 2005, 1997 through 2003; and (3) the third considers data from 2005 (the year in which the CALLS plan ended) through 2013. The year 1997 provides a helpful starting point as the last year in which the Commission prescribed a productivity-based X-factor and 2013 represents the year for which the business data services data was collected. The results are as follows:
185. Method Two—Connect America Cost Model. Our second set of calculations uses data from the CACM peer review process. In the 2011 USF/ICC Transformation Order, the Commission adopted CACM to provide a forward-looking estimate by census block of the costs of providing a voice and broadband-capable network for use in determining Connect America Fund support for broadband necessary to serve price cap areas. The Commission's response to a peer review of the CACM set forth data, including shares and estimates of changing prices, for ten cost categories. Relying on cost models and industry financial accounts, the Commission staff determined the key cost components of business data services supply, estimated their shares, and estimated changes in the input prices of each key component. These calculations relied on the following input categories and estimates of the cost shares of each of these categories: Labor, fiber, poles, conduit, drop, optical net terminal, fiber pedestals, splitters, electronics, and land/buildings.
186. The CACM methodology provides base information about the key costs of supplying business data services. The CACM was developed to estimate the costs of a mass market residential broadband fiber-to-the-premise network that also is used to provide telephone service, and was built to also provide business data services. Consequently, it is essentially a model of the costs of an incumbent LEC supply, but with a focus on residential rather than business data services. Despite this, there are no reasons to think that either (1) the underlying cost categories of the CACM or (2) the rates of change in input prices of these cost categories would be significantly different for business data services than for residential data services. The CACM peer review response provides at least a very rough indication of shares even though its modeling is not limited to business data services.
187. For each category, Commission staff calculated low and high estimates for changes in input prices. Two measures, one high and one low, were used for changes in total factor productivity. The low estimate for net impact on costs applies the low estimate for input prices and the high estimate for productivity. The high estimate for net impact on costs applies the high estimate for input price and the low estimate for productivity. Weighted averages were computed for both low and high estimate, where the weights were the cost category shares. Commission staff calculated the net impact on costs which equals the change in industry input prices plus the change in industry TFP. The results are as follows:
188. Method Three—TDS and Connect America Cost Model. Our third set of calculations is a modification of method two, relying on CACM calculation supplemented with data provided by TDS Telecom (TDS). The TDS data consist of booked financial data on TDS's incumbent LEC operations. Commission staff used these data as an alternative set of input categories. However, the TDS categories, other than those for labor and real estate, were not at the same level of detail as in the same CACM calculations. This required that the TDS categories for switching and transmission be mapped to the remaining eight CACM categories. The results are as follows:
189. We invite comment on whether these methodologies provide a reasonable basis for assessing industry productivity for use in X-factor and price cap indices adjustment and whether we should use them for such purpose. How precise are they? Are there alternative methodologies that would provide comparable or greater precision at comparable, or lower, cost? If so, we ask the parties to describe those methodologies in detail and to explain how we should apply them.
190. Are the data used in our calculations reliable? Are other, more detailed data available that would more accurately portray productivity trends? Do data that provide broad measures of large economic sectors, like the KLEMS data, provide the most reliable data for measuring BDS productivity trends in relation to production trends in the overall economy? Or are telecommunications-specific data, like the CAPM data, or company-specific data, like the TDS data, preferable? We ask the commenters to address the relative merits of each of these categories of data and to suggest additional sources of reliable data within each category.
191. The calculations present three different time periods that we could use to determine a productivity-based X-factor and, if we decide to take that course, price cap indices adjustments. We ask whether these time periods accurately capture BDS productivity trends for such purposes and, if not, which other time periods would provide increased accuracy and why.
192. Finally, we ask the parties to recommend, based on our analysis or their proposed alternative, whether we should make adjustments to the X factor and price cap indices. We also seek comment on capping existing price cap indices and ask whether this should be done in all areas or just certain areas with pricing flexibility. We ask commenters to explain the basis for their recommendation and explain how such approaches would impact competition and the technology transitions.
193. We seek comment below in this FNPRM on applying the substance of the current Phase I pricing flexibility requirements to TDM BDS offered in non-competitive areas. To implement such proposal, we also seek comment above on extending price cap regulation to TDM BDS offered in non-competitive areas that presently are subject to Phase II pricing flexibility. We now seek comment on how we would move such services back into price caps. Because the services we now consider currently are subject to Phase II pricing flexibility, their rates have been moved out of price cap constrained tariffs and are, in some cases, higher than they would have been had they been consistently constrained by the price caps. What, if any, changes to the currently applicable rates should be made as part of a transition back into price caps and why? If so, how should such changes be implemented? Does this transition raise any special considerations? We seek comment on these questions.
194. We propose that if the Commission adopts a new X-factor or otherwise requires adjustments to the price cap indices, price cap carriers would implement the associated rate decreases by submitting TRPs ( i.e., Tariff Review Plans) and special access tariff revisions for all rate elements associated with special access. Such TRPs would set forth the calculations underlying the API, and demonstrate that the revised API for the special access basket does not exceed the revised price cap index. We seek comment on this proposal.
195. How shall we adjust the price cap indices if the Commission adopts a new X-factor or otherwise requires adjustments to the price cap indices? Should the rate decreases that result from these actions apply to all rate elements associated with special access services, or should carriers be permitted to choose the manner in which the decreases are made as long as the revised API for the special access basket does not exceed the revised price cap index? What process should the Commission employ for purposes of implementing a new X-factor or any required adjustments to the price cap indices? In this regard, we invite comment on implementation issues such as the timing for complying with the required rate reductions, what should be included in related TRP submissions and tariff filings, and carrier certification requirements.

2. Anchor or Benchmarking Pricing
196. In non-competitive markets, absent guidance as to the range of rates that would be considered reasonable, a provider could exercise market power through the charging of supracompetitive rates. As discussed above, TDM BDS rates currently are constrained to some extent by price caps. In this section, we propose and seek comment on a methodology to ensure that, in non-competitive markets, rates for Ethernet business data services not subject to price cap regulation are just and reasonable. We emphasize that the proposed mechanism described below would be used in those markets where the Commission determines, based on an application of the Competitive Market Test, the market is non-competitive such that it is likely competition is not constraining rates to just and reasonable levels. That said, the proposed methodology is not prescriptive, and is intended to facilitate providers and customers negotiating reasonable commercial agreements.
197. We first took action to protect against concerns regarding Ethernet pricing during the transition to IP in the Emerging Wireline Order by adopting an interim rule to ensure that incumbent LEC BDS providers that are discontinuing legacy TDM services offer Ethernet services, used as wholesale inputs by competitive carriers, at reasonably comparable rates, terms, and conditions. This interim rule applies to two categories of services: (1) BDS services at DS1 speed and above; and (2) commercial wholesale platform services such as AT&T's Local Service Complete and Verizon's Wholesale Advantage. The interim reasonably comparable wholesale access requirement is a condition to a grant of an incumbent LEC's discontinuance application imposed under our authority pursuant to section 214(c) of the Act, and helps “bridg[e] the gap” between the current competitive situation and the completion of the BDS rulemaking. The condition that the rule imposes expires when “all of the following have occurred: (1) The Commission identifies a set of rules and/or policies that will ensure rates, terms, and conditions for special access services are just and reasonable; (2) the Commission provides notice such rules are effective in the Federal Register ; and (3) such rules and/or policies become effective.” The rules and policies that we propose establishing from this FNPRM are intended to meet the first prong of the Emerging Wireline Order's standards governing expiration of the condition. Once we adopt permanent rules subsequent to this FNPRM, we will provide the Federal Register notice called for in the second prong, which will announce the effective date called for in the third prong. We anticipate that the condition the interim rule imposes will expire as of the effective date of our permanent pricing rules for BDS, absent action staying or overturning our rules and policies. We further discuss our various methods for considering a permanent pricing methodology below.
198. In this FNPRM, we propose an anchor pricing or benchmarking approach to replace, as it applies to BDS, the interim rule currently in effect. We consider three options below. The first option is to rely on regulated TDM service prices to anchor the prices of similar packet services. This option would be effective only where TDM prices could be expected to reasonably constrain the rates for higher speed packet-based services. In that case, we could decline to otherwise regulate packet-based BDS rates. If, however, we were unable to determine that regulated TDM prices would provide a reasonable constraint on packet-based BDS, a second option would be to establish one regulated price for packet-based BDS, for example, establish a regulated rate for a 10 Mbps Ethernet service, which could serve as an anchor for nearby-bandwidth packet-based BDS, and could arguably constrain those rates. Our third option is to initially use reasonably comparable prices for regulated TDM services as a benchmark to help the Commission determine whether rates for various packet-based BDS are just and reasonable, but over time using, as a benchmark, the packet-based BDS prices established under this approach. Price cap TDM rates do not have a single rate for a particular TDM service but a series of rates that, when combined, create a rate. How should we account for differences in rate structures between price-capped TDM rates and packet-based BDS?
199. We seek comment on which option we should use and how such a pricing regime should operate. We believe we should adopt the third option—using regulated TDM prices, but over time using the packet-based BDS prices established under this approach as a benchmarking tool in determining whether packet-based BDS rates are just and reasonable, similar to the interim rule adopted in the Emerging Wireline Order. We believe this option would be most effective in constraining rates and most consistent with the Commission's goals of promoting facilities-based competition and facilitating technology transitions. We question whether, under the first option, TDM services could effectively constrain the prices for higher speed packet-based services in the current environment of increasing demand for high-bandwidth services. In addition, such reliance may create incentives at odds with our goal of facilitating the technology transitions. We also question the desirability of the second option, establishing rates for one tier of packet-based BDS, for two reasons. First, because it is doubtful that such an approach could reasonably constrain a relatively wide range of bandwidths (for example, it is unlikely that a 25 Mbps anchor price would effectively constrain prices for 2 Mbps and 50 Mbps services). Second, for reasons similar to our hesitation to bring such services under price cap regulation, any price regulation where the Commission would be establishing rates for carriers to charge (even for just one service) would still add reporting and monitoring burdens on carriers, which could inhibit innovation. In contrast, we believe the third option would be the least burdensome and most effective in encouraging competition through commercial negotiation. We seek comment on these various options and our views.
200. Certain parties have suggested we could use a cost model to establish benchmarks for packet-based BDS Ethernet services. For instance, as noted above, the CACM was used to provide a forward-looking estimate by census block of the costs of providing a voice and broadband-capable network for use in determining Connect America Fund support for broadband necessary to serve price cap areas. We seek comment on whether we could either establish a new cost model or modify an existing cost model to provide a basis for establishing Ethernet rate benchmarks within price cap incumbent LEC service areas to the extent that price regulation might otherwise apply? What would be the benefits of a model-based approach in contrast to the anchor or benchmarking approaches described above? Is there a particular model that we should consider? What would be the benefits of establishing a new model instead of modifying an existing model?
201. Although packet-based BDS have largely been provided outside of price cap regulation, we expect adoption of an anchor or benchmarking pricing mechanism would provide many of the advantages of price caps and other forms of pricing regulation without some of the disadvantages. Through the adoption of price cap regulation, the Commission attempted to encourage incumbent LECs to innovate and increase efficiencies in providing service. However, bringing more services under our price caps would entail reporting and monitoring costs which we can avoid under our proposed anchor or benchmarking approach (since such an approach, in part by its expression, and in part through setting of precedents in adjudications, will encourage parties to negotiate reasonable terms and conditions). We seek comment on this approach. Would our proposed approach work effectively to constrain prices and increase innovation? Would one of the alternative forms be more effective than our proposed approach?
202. We note that the Verizon/INCOMPAS Joint Letter suggests that the Commission should rely on ex ante rate regulation in relevant markets with insufficient competition. We seek comment on the principles in the Verizon/INCOMPAS Joint Letter. How would we implement ex ante pricing regulation that would further the goals of constraining prices and ensuring just and reasonable rates and be imposed on a technology neutral basis? How would such regulation be implemented on an operational basis?
203. As described above, we propose to use as a benchmark for reasonable packet-based BDS rates the price of the most comparable legacy TDM technology and base the reasonableness of the price on that service level, even if the services are provided using a new or different technology. Over time, as TDM benchmarks are discontinued, packet-based BDS rates established as being fair and reasonable under this approach would serve as a continuing benchmark. We seek comment on this proposal. How would this methodology be implemented? Should this price be a ceiling for the rates of various packet-based services or should it merely be used as a tool to determine whether rates are reasonable? Would this method be a workable solution to ensure that packet-based BDS rates are just and reasonable? If not, what alternative solutions should the Commission consider?
204. We believe we should impose anchor or benchmarking pricing only in non-competitive markets. Is that the correct determination? Why or why not? Would there be reasons to impose anchor or benchmarking pricing in competitive markets? We believe that in effectively competitive markets, anchor or benchmarking pricing would not be necessary because competition would be sufficient to constrain prices to just and reasonable levels. We also believe that anchor or benchmarking pricing would not be appropriate where we find sufficient material competitive effects under the Competitive Market Test, even where that means competition is not necessarily driving prices to effectively competitive levels. This is because we must account for limitations on our ability to establish what a competitive price is, the harms of unintended consequences from regulatory action (for example, to the extent regulatory action encourages waste through rent-seeking), as well as its administrative costs. Is that a reasonable approach? If not, what impact would anchor or benchmarking pricing have on areas that already have material competitive effects?
205. We seek comment on the scope of the application of rate regulation in non-competitive markets to packet-based BDS (and, as well, to TDM BDS). In non-competitive areas, should all providers be subject to rate regulation or should only some providers be so impacted? If the latter, how should we determine which providers? So, for example, should rate regulation apply only to the largest providers (and how would such an outcome be implemented as market shares change over time)? Conversely, should we consider adopting a rule that providers with less than a certain percentage of market share would not be subject to rate regulation on the ground that smaller providers likely represent new entrants? Or should we use another factor than market share were we to adopt this approach, such as the ubiquity of infrastructure capable of delivering BDS service in a relevant geographic market, or the effective ability of a provider to reach some percentage of potential BDS customers? We seek general comment on the scope of rate regulation in non-competitive markets.
206. We propose above to evaluate the reasonableness of rates for packet-based BDS by benchmarking them against the incumbent LEC's TDM price for the most comparable level of service available, and over time, as TDM services are discontinued, benchmarking them against packet-based BDS rates established as being just and reasonable under this approach. For example, the anchor price for a particular market for a 5 Mbps Ethernet service would be the cost of the closest TDM equivalent offered by the incumbent LEC, which, for example, might be a DS1. This would not imply that the price of the Ethernet service should be the same as that of the nearest equivalent service, but only that the Commission would judge whether the 5 Mbps service price was just and reasonable in the light of the DS1 price. In this example, the Commission could determine that the 5 Mbps service price should not exceed the price of the DS1 multiplied by 3.3 (= 5 / 1.5), given the prices of higher bandwidth services usually fall more than proportionately with bandwidth, and that Ethernet services are considered to have a lower cost in supply than legacy TDM services. Would this anchor price approach be workable? If not—what method should the Commission utilize? If it is workable, would the proposed upper bound, that the ratio of the price of a packet-based BDS with a bandwidth in excess of a regulated TDM service to the price of the TDM service should not exceed the ratio the packet-based BDS bandwidth to the TDM service bandwidth, be reasonable? What about for packet-based BDS for which the nearest comparable TDM service has a higher bandwidth?
207. We seek comment on this proposal. Does it adequately cover situations in which an obvious comparable TDM service does not exist in a given market? We welcome comment on any alternative or additional ways for providers to address the situation where it is difficult to find a comparable TDM service offering on which to base the anchor price.
208. In addition to the bandwidth of the service offering, should the rates differ based on the technology, service tier, geographic location, quality of service, or any other factors? How should these differences be accounted for in determining the ultimate rate ceilings that providers are permitted to charge at or below for their packet-based BDS? How would any discounts commonly provided for TDM services influence the benchmark rates? Are there any other issues that should be accounted for that may affect the ultimate rates (either higher or lower) than the benchmark set by our anchor price? If so, what are they, and why should BDS providers be entitled to adjust their rates accordingly? How do we ensure that carriers are not permitted to increase prices above the benchmark by imposing unreasonable charges on related services, such as special construction?
209. Our anchor or benchmark prices must adjust to changes in economic conditions and advancements in technology and productivity that impact the costs of providing services. Specifically, how would anchor prices be established once incumbent LECs have fully transitioned from TDM to packet-based services? To address this challenge, at least over the medium term, we propose to make permanent, after the interim rule expires, the current network transition requirement adopted in the Emerging Wireline Order which requires an ILEC discontinuing TDM service to offer a comparable packet service at comparable prices. We seek comment on that approach, and also on how best to establish an anchor or benchmark price for the potential situation where, due to increased bandwidth demands, sales of low bandwidth Ethernet services decline and have been replaced by broad demand for higher bandwidth BDS. Is this situation too speculative to consider regulatory approaches at this point? In particular, would our proposal to use as a benchmark any packet-based BDS with prices that were established under this approach work? Is this approach sufficiently technology-neutral, and if not, is there a more appropriate technology-neutral alternative? Would this approach over time be likely to become unmoored as TDM services are discontinued and as the minimum bandwidth of service offerings rise? What other factors would cause the Commission to reset anchor or benchmark pricing? Should anchor or benchmark pricing be revisited on a regular, recurring basis? In any case, is it likely there will be any need for regulation of such higher bandwidth services or are there reasons to believe that, as this transition takes place, such services will take on the characteristics of low bandwidth services, including a lack of competitive supply for such services?
210. In the Enterprise Broadband Forbearance Orders, the Commission granted forbearance from the application of dominant carrier regulation, including tariffing, to certain of the petitioning incumbent LECs' broadband telecommunications services. The forbearance grants did not include all price cap incumbent LECs and only included certain IP services being offered at the time of the grants, resulting in some inconsistency regarding the tariffing of IP-services. Upon implementation of an anchor or benchmarking pricing methodology, we believe we should continue the forbearance from tariffing for all packet-based services currently subject to forbearance. In addition, we believe we should expand the forbearance to include all price cap incumbent LECs and all packet-based services. We believe that forbearance from tariffing will allow for greater use of commercial negotiations, which will facilitate innovative integrated service offerings designed to meet changing market conditions and will increase customers' ability to obtain service arrangements that are specifically tailored to their individualized needs. We seek comment on these views. Would this approach be consistent with the three-part test in section 10(a) of the Act? What impact would a more comprehensive forbearance from tariffing have on the development of packet-based BDS? Would greater flexibility lead to more competitive pricing and offerings? How should the increased use of forbearance from tariffing requirements be implemented? Should the detariffing be mandatory or should carriers be permitted to file permissive tariffs? Should there be any grandfathering for services that are currently offered pursuant to tariff?
211. The success of the proposed anchor or benchmarking pricing framework will rest in part on parties having access to generally available rates that comply with the anchor or benchmarking pricing requirements. Our primary goal under anchor or benchmarking pricing would be to create a framework of technology-neutral regulation that will facilitate the emergence of competition. We want to minimize burdens on market participants and not increase barriers to market entry. Tariffing has the potential to impose burdensome obligations and may prevent more competitive offerings from being introduced by limiting flexibility and the ability to individually tailor product offerings. The disclosure tariffs require, however, is a positive aspect in non-competitive areas because it can help combat unjust and unreasonable rates, terms, and conditions. Requiring BDS providers to disclose their rates, terms, and conditions publically would provide a clear check as to whether they are compliant with our anchor pricing requirements. Do these potential transparency benefits outweigh potential benefits to competition that would arise from forbearance from tariffing requirements? Are there other potential benefits to tariffs that we should consider? We now turn to a proposed public disclosure requirement that would offset any negative impact of forbearance from tariffing requirements.
212. We believe we should require providers affected by our proposed anchor or benchmarking pricing regime to publicly disclose their generally available rates, terms, and conditions. The rates in these public disclosures should be consistent with the anchor or benchmarking pricing rules we adopt and should be available to customers on the carrier's Web site. We seek comment on these proposals. How should disclosure of rates be implemented? Is posting on a carrier's Web site sufficient?
213. Currently, the Emerging Wireline Order's reasonably comparable standard helps ensure that providers are offering just and reasonable rates when they seek to discontinue certain legacy TDM services. Accordingly, we have temporary policies in place that should help ease any unjust and unreasonable rates in the Ethernet BDS market where legacy TDM services are discontinued. With this in mind, what is a reasonable timeline for implementing the new anchor or benchmarking pricing methodology? Should the timeline be linked to the determinations under the Competitive Market Test? What types of changes and preparations would providers need to undertake to switch to the anchor or benchmark prices that would justify time for a transition? If a transition is needed, how long should it last to ensure that providers are ready and customers are provided relief in as timely a manner as possible?
214. Some BDS providers and purchasers enter into contracts with terms that last for several years, especially in the context of receiving term discounts. We do not intend to intervene where sufficient material competitive effects keep rates at just and reasonable levels. However, should the Commission need to take additional action after adoption of our proposed anchor or benchmarking pricing regime, it is well-established that “[u]nder the Sierra-Mobile doctrine, the Commission has the power to prescribe a change in contract rates when it finds them to be unlawful, and to modify other provisions of private contracts when necessary to serve the public interest.” Such a need may arise, for example, when contract terms last long after adoption of our regime, which would prevent the rates from falling to just and reasonable level under our anchored prices. We note that an agency may modify or abrogate a valid contract “only if it harms the public interest.” Under what circumstances should we exercise our authority under the Sierra-Mobile doctrine to abrogate such contracts that remain inconsistent with the benchmarked rates under our anchor pricing system? In the context of the prices for BDS, under what, if any, circumstances would rates above the anchor or benchmark price justify contract abrogation?
215. We do not envision that our anchor or benchmarking pricing methodology will impose any additional reporting requirements on carriers that offer the Ethernet services falling under these new anchor or benchmark rates. We have, however, proposed to require public disclosure of generally available terms and conditions. We invite commenters to explain whether any reporting requirements should be imposed to ensure that providers comply with our rules and that those rules serve the purposes for which they were designed. If reporting requirements should be implemented, what form should they take? Should we require certification that providers are in compliance? Are there any other requirements we should consider, and what are the costs and benefits of adopting additional requirements?
216. We expect the Commission's enforcement process and declaratory ruling process will be critical components of our proposed anchor or benchmarking pricing methodology that will help ensure our new rules prevent providers from offering packet-based BDS at rates, terms, and conditions that are unjust and unreasonable. For example, interested parties may file complaints alleging that particular BDS providers' rates, terms, and conditions are unjust, unreasonable, or unjustly or unreasonably discriminatory. Based on these complaints, we would then evaluate the rates providers' charge to determine whether they are just and reasonable. This determination would be made based on the facts before us in each individual circumstance. In response to complaints, providers of Ethernet BDS could make arguments about why the services at issue cost more to provide than the TDM services to which we would look to benchmark prices. BDS providers, in addition, may seek declaratory rulings that the rates they charge for services subject to our anchor pricing system are just and reasonable. Such declaratory rulings will provide BDS providers certainty that they are in compliance with our new anchor or benchmarking pricing regime. We seek comment on whether the complaint and declaratory ruling processes would be reasonable processes to utilize in enforcing the proposed pricing methodology. Should we adopt a timeframe for resolving these complaints or declaratory rulings? Where the Commission concludes that the rates for BDS services were unjust and unreasonable, should providers be found liable for refunds? Are there better approaches to meeting these goals?

3. Wholesale Pricing
217. Certain competitive LECs argue that business data services providers are charging them wholesale rates higher than the retail rates those same providers charge end user customers, and that such wholesale rates are unreasonable. These competitive LECs argue that when business data services providers price their wholesale services higher than their retail services, this can result “in a price squeeze, preventing [competitors] from competing with the RBOCs for the sale of Ethernet service to end users.” As evidence of this price squeeze, Windstream cites the fact that the “ILECs' wholesale Guidebook rates bear little relationship to real retail prices. [REDACTED] which is below its wholesale Guidebook rate for an Ethernet at the same capacity level and term ($1,225) as well as its DS3 three-year rate ($1,232.50).” TDS also argues that the “RBOCs were offering Ethernet service to wholesale customers such as TDS CLEC at a price higher than they sold the same service at retail, even though they avoided some significant costs when selling at wholesale.” Windstream adds that, [REDACTED].
218. These allegations raise concerns that are not novel. The Commission previously has recognized that incumbent LECs can “strategically manipulate the price of their direct competitors' wholesale inputs to prevent competition in the downstream retail market.” While our proposed framework would move away from regulating providers based on their historical categorizations, we find it likely that providers in non-competitive markets have similar abilities and incentives to engage in such price manipulation. We believe that existing rules may apply to these concerns regarding wholesale pricing, and that addressing such concerns in our proposed framework may provide helpful guidance. We also note that the Verizon/INCOMPAS Joint Letter states that “[t]here should be a relationship between wholesale and retail pricing” for business data services.
219. We seek proposals for and comment on adopting rules, under sections 201 and 202(a), ensuring just and reasonable wholesale rates that would be applicable to provider(s) in non-competitive markets. Are there other sources of authority that we should consider? How do we best ensure that we employ sources of authority that operate in a technology-neutral manner?
220. We ask commenters to explain how frequently business data services providers charge wholesale customers rates that exceed the corresponding retail rate. Does the practice vary depending on bandwidth levels or other product features? Are there other examples of this practice, and if so where is such pricing taking place? Windstream argues that such practices violate “Section 251(b)(1) as an `unreasonable or discriminatory condition[] or limitation[]' that results in a failure to provide carrier customers and end users services `subject to the same conditions,' and violates prohibitions of sections 201 and 202 against unjust and unreasonable as well as unreasonably discriminatory practices and charges.” We invite commenters to explain whether charging higher rates for wholesale business data services than for comparable retail services would violate the Act and our rules. We also seek comment on the view that, because of avoided costs or other factors, reasonable wholesale rates should be lower than retail. Do the services wholesale customers tend to purchase use different portions of the incumbent LECs' networks than the services retail customers purchase? Are there differences in the incumbent LECs' expenses for sales, marketing, customer service, technical support, and uncollectibles between wholesale and retail customers? If there are differences justifying a discount, how would we determine the just and reasonable discount that would apply to wholesale rates?
221. We seek comment on what if any steps should be taken to ensure that customers have a basis for determining whether wholesale rates are just and reasonable under existing or proposed rules. For example, what steps are incumbent LECs currently taking to disclose the lowest retail price to potential customers under existing rules? Are such processes effective, or should we take additional measures to ensure that potential customers are aware of the lowest retail price? For example, should we require some form of public disclosure, such as on a carrier's Web site? Would such a disclosure put purchasers in a better position to know whether the rates they are charged are just and reasonable? Are there other requirements we should adopt regarding wholesale rates?
222. Finally, we seek comment on the relationship between any requirement concerning wholesale rates and the rate regulation we have proposed for TDM and packet-based services in non-competitive markets. Should both approaches be used? One or the other? Or are there certain markets (by service, geography, customers or some combination of factors) for which the relationship between wholesale and retail rates is most salient?

4. Terms and Conditions
223. As part of the technology neutral framework for regulating business data services, we propose prohibiting tariff and other contractual arrangements that condition the sale of business data services in a non-competitive market on the sale of such services in a competitive market. Such rules would be applied on a technology neutral basis. We seek comment on both the harms such agreements may impose and on implementation of any prohibition in light of the ongoing purchase agreements for such services that may contain tying arrangements. How do we balance current business expectations of customers and providers against the long term harms such arrangements may impose on the evolution of the competitive market for business data services? We address specifically three types of tying arrangements that have been identified in the record: IP migration provisions, typically found in incumbent LEC tariff pricing plans, provisions that leverage incumbent LEC tariff pricing plan penalty liability to induce sales of Ethernet and other services, and geographic tying. To what extent, if at all, would a prohibition on tying obviate the need to identify multi-location customers, or any other class of customers, for purposes of the application of the Competitive Markets Test or alternative regulatory approach? Are there any other actions that the Commission should consider to address issues arising from customers who are purchasing a service that spans competitive and non-competitive markets?
224. IP migration provisions are common among incumbent LEC pricing plans. These provisions allow customers to count Ethernet purchases toward fulfillment of their TDM commitments. We seek comment on whether we should prohibit such provisions as unreasonable tying arrangements. To what extent do such provisions encourage and facilitate incumbent LECs' leveraging of their dominance in the provision of TDM business data services to increase sales of their Ethernet services? How do the price cap incumbent LECs' market positions differ between the TDM and Ethernet business data services markets that are usually covered by the tariff containing such provisions? We seek comment on whether and, if so, to what extent incumbent LEC IP migration provisions advantage incumbent LECs competing for Ethernet sales. If IP migration provisions were eliminated from incumbent LEC tariff pricing plans, what would be the impact on customers of those plans? To what extent have customers relied on IP migration provisions to meet their commitments under TDM pricing plans? What volume of Ethernet purchases would be affected? If customers were unable to count such purchases toward fulfillment of their TDM commitments, what potential penalties would they incur? How would a prohibition, if adopted, best be implemented? Should customers be allowed a “fresh look” period to re-evaluate their tariff commitments or other transition period to allow customers to adapt their purchasing arrangements? Would this unreasonably deprive price cap incumbent LECs of the benefit of their bargain? How could such a prohibition best be applied in a technology-neutral manner? What implementation questions are raised by our proposal to eliminate tariffing? What additional factors should the Commission consider?
225. As explained above, competitive LECs have more recently alleged incumbent LECs use tariff pricing plan penalty liability as leverage to induce competitive LECs to agree to large Ethernet purchases from the incumbent LECs. They claim that these practices represent unreasonable tying arrangements and could extend incumbent LECs' dominance of TDM business data services to IP services. We seek comment on prohibiting the use of provisions that offset penalty liability from tariff pricing plans in Ethernet commercial agreements. We note that such provisions appear in multiple commercial agreements submitted by the four large incumbent LECs in response to the Bureau's tariff investigation. How pervasive are these practices? What is their impact on competition for Ethernet services? What would be the impact of eliminating such provisions on buyers, sellers and the market generally? To what extent do such agreements contain change of law provisions in anticipation of changes such as this? We also seek comment on the use of other provisions in commercial agreements that tie the sale of Ethernet services to the sale of services by providers in non-competitive markets. Finally, if the Commission were to bar the use of such provisions in Ethernet commercial agreements, how should the Commission implement such a requirement? Should the Commission, as some competitive LECs have advocated, require commercial agreements that link purchases to tariffed penalties or other tariff provisions be filed with the Commission as a contract tariff? What should the parameters be of such a requirement? Would any other type of linkage require such agreement to be filed as a tariff? How could such a prohibition best be applied in a technology-neutral manner?
226. First, we recognize that in the competition analysis above we find that the competitive triggers adopted in the Pricing Flexibility Order were poor measures of competition. In this FNPRM, however, we propose a new framework that includes a Competitive Market Test to determine areas that are competitive and non-competitive. The assertions and arguments concerning tying across markets subject to different levels of market concentration remain relevant in the new regulatory framework. We seek additional comment on whether and to what extent we should be concerned geographic tying could take place under the proposed technology-neutral framework and, if so, what remedial action we should take.
227. While prohibiting such tying arrangements would minimize potential harm, it would also eliminate the ability of providers and purchasers to link TDM purchases and Ethernet purchases in any way, including the use of IP migration provisions in TDM tariffed services and the use of credits to offset penalty liability conditioned on the purchase of Ethernet service from the provider. It is clear from the record that linking DSn purchases and Ethernet purchases involves material short term benefits for purchasers as they attempt to manage the effects of the decline in TDM services and the transition to IP services. Some competitive LECs advocate in favor of such arrangements and incumbent LECs generally defend their reasonableness. Considering the benefits of these arrangements may be particularly relevant given the current decline in TDM sales and the consequent penalty liabilities that decline involves.
228. The Commission has established as one of its priorities facilitating technology transitions. While we share the concerns of commenters that incumbent LECs may have the incentive and ability to leverage their market position in TDM services to increase their Ethernet sales, we also recognize that addressing the harms of tying TDM BDS to Ethernet services may require a more nuanced approach to reflect the implications of such a prohibition on the technology transition. AT&T states that such restrictions would “artificially discourage the replacement of TDM services with Ethernet services.” We seek comment on approaches that would encourage the transition to Ethernet while limiting an incumbent LEC's ability to leverage its market position in the provision of TDM BDS to gain a similar position in the provision of Ethernet offerings. Are there other ways to provide both parties with the benefits from these arrangements while limiting the harms to competition in the market for business data services? We also seek comment on ways to allow the benefits of such arrangements during a defined period of time to facilitate the industry's transition to IP services.
229. Finally, we seek comment on how we should implement any prohibition on tying arrangements the Commission may adopt. What effect would adopting such a prohibition have on existing tariff and contractual arrangements in tariffs and commercial agreements? Should the Commission consider either grandfathering existing agreements or providing a transition period to allow parties to adapt their agreements to reflect such a prohibition? Should there be a “fresh” look period to allow customers to reallocate their purchases in light of the modifications or prohibitions we propose to tying arrangements?
230. Percentage commitments are requirements included in some incumbent LEC tariff pricing plans that require customers to commit to buy, over the term of the plan, a high percentage of the amount of services they elect to purchase when initiating or renewing purchases through a tariff pricing plan. Given the framework we adopted in the Tariff Investigation Order that addresses the special access marketplace by focusing on penalties, we declined to take action on percentage commitments in that Order. We seek comment on whether this approach is sufficient to ensure that percentage commitments will not harm competition, impede investment and deployment of facilities-based competitive networks, or hinder the transition to IP-based business data services.
231. We also seek to broaden our inquiry into minimum percentage commitments in this FNPRM and seek comment on the impact percentage commitments have on the provision of TDM based business data services. With regard to the TDM based market, how prevalent is the use of such commitments in tariff pricing plans and contract tariffs beyond those investigated in the Bureau's tariff investigation? What impact do such commitments have systemically on the market for TDM based business data services? How do they vary? Competitive LECs claim that such commitments tend to “lock up” or foreclose significant portions of the market for TDM based business data services, impairing competition and inhibiting technology transition. Is that still the case? Incumbent LECs assert in the tariff investigation that the decline in TDM based business data services market effectively rendered the competitive LECs' lock up arguments moot. We seek comment on whether that is in fact the case or whether percentage commitments operate differently in a declining market. What is their effect in a declining TDM market? What remedies would be appropriate to ensure that percentage commitments are reasonable and allow incumbent LECs the flexibility to manage their businesses while also minimizing the potential harms associated with “locking in” competitive LEC customers? Should the Commission consider prohibiting the use of percentage commitments, limiting the level at which the commitment is set, or taking some other remedial step to ensure they do not negatively impact the market?
232. We also seek comment on the use of percentage commitments in commercial agreements for the sale of packet based business data services such as Ethernet. Competitive LECs cite the incumbent LECs' use of such requirements in Ethernet commercial agreements and claim incumbent LECs are attempting to lock up or control their Ethernet purchases. Competitive LECs cite in particular the fact that their Ethernet commercial agreements with incumbent LECs typically involve large scale purchases and involve the sale of other telecommunications services such as mobile wireless and long distance service. How commonly are percentage commitments used in Ethernet commercial agreements and at what percentage levels are they set? How do they impact the market for Ethernet business data services? Should the fact that commercial agreements can involve such large scale purchases impact our analysis? If the Commission found percentage commitments were impacting the Ethernet market, what remedies should the Commission consider adopting? To the extent commenters suggest the adoption of remedies, they should also address how such remedies should be implemented.
233. Term commitments require customers that participate in a term pricing plan to commit to continue to make those purchases for a set term of months or years. Term commitments in tariff pricing plans vary considerably from one year to as long as ten years. We declined to address term commitments in the Tariff Investigation Order, instead addressing competitive LECs' concerns by prohibiting penalties that exceed the incumbent LECs' expectation damages. We seek comment on whether action on term commitments is necessary to ensure that they will not harm competition, impede investment and deployment of facilities-based competitive networks, or hinder the transition to IP-based business data services. We also seek to broaden our inquiry into term commitments in this FNPRM and seek comment on the impact term commitments have on the provision of TDM based business data services generally. How prevalent is the use of such commitments in tariff pricing plans and contract tariffs beyond those investigated in the Bureau's tariff investigation? What impact do such commitments have systemically on the market for TDM based business data services? In the tariff investigation, the incumbent LECs submitted data that showed that the average term lengths for agreements under the plans at issue was considerably longer than the term lengths typically reported by competitive LECs. It also showed that a very high percentage of all sales in the plans at issue—over 97 percent—occur in plans longer than three years. Are longer term agreements in any way evidence of a seller's market power? Do incumbent LEC term plans that are longer than most competitive LEC plans tend to inhibit the technology transition or otherwise impact competition in the TDM based market? What remedies would be appropriate to ensure that term commitments are reasonable and allow incumbent LECs the flexibility to manage their businesses while also minimizing the potential harms associated with the alleged “locking in” competitive providers?
234. We also seek comment on the use of term commitments in commercial agreements for the sale of IP based business data services such as Ethernet. How do term commitments in Ethernet commercial agreements compare with those in TDM tariff pricing plans and contract tariffs? To what extent do term commitments impact the Ethernet market? How does the length of term commitments offered by competitive providers in Ethernet commercial agreements compare with the length of term commitments offered by incumbent LECs? What remedies, if any, should the Commission consider adopting either to limit or condition term commitments in Ethernet commercial agreements? To the extent commenters suggest the adoption of remedies, they should also address how such remedies should be implemented. To the extent that the Commission should consider restrictions on term commitments, should such restrictions apply solely to non-competitive markets or more broadly to all markets?
235. Under upper percentage thresholds, if a buyer's purchases increase more than a set percentage above their initial volume commitment during the term of the plan, the buyer is required either to commit to an increased purchase volume or to pay an overage penalty. We did not address upper percentage thresholds in the Tariff Investigation Order, but instead seek comment on whether we should adopt a broad prohibition on such requirements in non-competitive areas.
236. We seek comment on whether the use of upper percentage thresholds in tariffs and contract tariffs generally is an unreasonable practice. As discussed above, in both the Tariff Investigation Order and earlier in this FNPRM, the price cap LECs' all-or-nothing requirements often served to restrict customer options and inhibit the ability of competitive LEC customers to plan for their network evolution. Such unreasonable restrictions also may have contributed to the asserted lock in effect of upper percentage thresholds. We seek comment on whether the price cap LECs' arguments about their potential risk exposure when customers add large amounts of circuits to their plans with portability are more persuasive if the customer has the choice to place its demand in a term plan without portability when adding new circuits to its agreements with the price cap LEC. We seek comment on whether upper percentage thresholds are unreasonable and should be prohibited for providers of TDM business data services in non-competitive markets. Under what circumstances might upper percentage provisions be found reasonable? In the record, incumbents LECs argued they incurred risks and costs when an increase in purchases reached a certain point; however, they failed to provide any financial information on what these costs are or how they are related to actual upper percentages or overage penalties that are used. We seek comment on what showing a carrier should be required to make if it supports such a provision. Will removing the all-or-nothing requirements from the providers' tariffs provide the flexibility customers need to make different choices if they do not want to increase their spend under an upper percentage threshold? If we were to adopt a prohibition on upper percentage thresholds, what is an appropriate transition period for phasing out these provisions?
237. We seek comment on the extent to which commercial agreements for the provision of Ethernet-based service assess upper percentage thresholds. We also seek comment on whether these provisions are found elsewhere in the telecommunications industry or offered by other carriers other than in incumbent LEC tariffs. Are upper percentage thresholds in Ethernet commercial agreements unreasonable and, if so, should the Commission prohibit them in this context as well? Should such a prohibition apply solely to non-competitive markets or more broadly to all markets?
238. Overage penalties effectively function as the enforcement mechanism for the upper volume thresholds addressed in the previous section of this FNPRM. We did not address overage penalties in the Tariff Investigation Order, but instead seek further comment here. We seek comment on the use of overage penalties to enforce upper percentage thresholds in TDM based tariffs and contract tariffs. If the Commission does not eliminate upper percentage thresholds, we seek comment on the circumstances under which the Commission should find overage penalties to be unreasonable. For example, in the Tariff Investigation Order, we determined that shortfall penalties that exceeded the seller's revenue expectations were unreasonable. We seek comment on whether this is an appropriate approach to assessing overage penalties as well. How would such a measure work in the case of an overage? How should the Commission determine a seller's revenue expectations in an overage situation? Are there alternative approaches to determining the outer bound of reasonableness for overage penalties? Commenters advocating for the use of a different measure of reasonable overage penalties should explain their reasons for not applying the standard used to assess shortfall penalties and identify an alternative standard using examples. What is the best way to structure overage penalties to ensure that the fees reasonably compensate providers while not excessively penalizing purchasers?
239. We also seek comment on whether and to what extent overage penalties are contained in commercial agreements for the provision of Ethernet business data services. Is it reasonable to include such penalties in agreements for Ethernet business data services in non-competitive areas? If so, how do these contracts calculate these penalties? If the Commission decides to eliminate overage penalties or impose limitations on them, how should it implement those decisions? Would there be any need for the Commission to consider adopting any transitional rules to facilitate implementation? Should such a prohibition apply solely to non-competitive markets or more broadly to all markets?
240. Competitive LECs have asserted certain provisions in incumbent LEC tariff pricing plans that apply upon expiration of a purchaser's agreement to buy services tend to lock purchasers into re-committing to purchase under those plans under essentially the same prices, terms and conditions of their previous agreements. These provisions include requirements for automatic renewal of subscription agreements under the same terms and conditions as a previous agreement and requirements that force buyers to pay higher, undiscounted month-to-month rates immediately upon expiration of an agreement. Competitive LECs claim these provisions impair competition and inhibit technology transitions. We seek comment on the reasonableness of such provisions in tariffs and commercial agreements in areas where competition is not present. We also seek comment on existing so-called “evergreen” provisions in some tariff pricing plans that allow customers to extend service under the same prices, terms and conditions for certain periods of time following the expiration of an agreement, including whether we should require such provisions in tariffs and commercial agreements in non-competitive markets.
241. Incumbent LEC tariff pricing plans commonly contain provisions related to the expiration of a purchaser's agreement. It is inherent in the relatively long-term nature of the need for and provision of business data services that parties generally must renegotiate their agreements at the expiration of an agreement in order to continue the service arrangement. Parties typically negotiate the terms and conditions of a subsequent agreement as they approach the end of the term of an existing agreement. The provisions we seek comment on—automatic renewals and requirements to revert to undiscounted, month to month rates—may impose unreasonable constraints on purchasers whose agreements have expired in light of the long term nature of broadband data services agreements and the substantial logistics required to move purchases to other providers or construct facilities to self-provision.
242. Provisions requiring automatic renewal of agreements are included in certain incumbent LEC tariff pricing plans. For example, the Commitment Discount Plan (CDP) in Verizon Tariff No. 1 states “[i]f the CDP Customer does not notify the Telephone Company of its choice during the two (2) month extension, a new CDP will begin based on the previously effective commitment period.” We propose to prohibit automatic renewal provisions in tariff pricing plans and contract tariffs for the provision of TDM based broadband data services in non-competitive areas as an unreasonable constraint on purchasers' ability to modify their commitments or seek alternative providers to supply their needs. We seek comment on whether automatic renewal provisions are unreasonable. We also seek comment on how common they are and how frequently they are invoked in practice. What is the practical impact of such provisions on purchasers' options at the expiration of an agreement? How do they impact the dynamics between the parties as they renegotiate their arrangements? How do they impact the flexibility and the timeframe customers have to negotiate or to develop alternative sources of supply? Do competitive LECs also impose automatic renewal provisions in their business data service sales agreements? We also seek comment on whether such provisions are used in commercial agreements for Ethernet business data services? Additionally, are such provision included in agreements for managed services sold to retail end users? Finally, we seek comment on whether such a prohibition should apply solely to non-competitive markets or more broadly to all markets?
243. Given the comments in the record, we are particularly concerned that incumbent providers have the incentive and ability to use the expiration of a contract as an opportunity to increase charges for ongoing service and use that as leverage to induce customers to recommit to their pricing plans. In areas without sufficient competition, these provisions have the potential to put increased pressure on customers to renew contracts with incumbent providers, even if the terms are unfavorable, to avoid paying higher rates for an extended period of time. We therefore believe that any provision that enables a provider to increase its rates upon the expiration of either a tariff or commercial agreement for TDM or Ethernet-based service in areas without sufficient competition is unreasonable under section 201 of the Act.
244. We seek comment on our view and on the following additional questions. How do such provisions constrain purchasers' options at the end of an agreement? Could the reversion to month to month rates be understood as, in effect, a penalty enforcing the re-subscription to a subsequent agreement? How reasonable is it to assess month to month rates, after a purchaser has already fulfilled its commitments under a previous agreement which presumably compensated the incumbent LEC for the circuits involved? Do competitive LECs also impose such a requirement at the expiration of their sales agreements? If we were to require the modification of such provisions, should the Commission determine that evergreen provisions are a more reasonable alternative?
245. We note that incumbent LECs argue that one of the benefits to a provider of offering term discount plans is that the plans allow it “to recover its costs over the life of the plan.” If the life of the plan has ended, and the incumbent LEC has presumably recovered its costs apart from on-going maintenance costs, is there any justification for allowing the incumbent LEC to increase the price and charge higher rates upon termination? How do these higher rates compare to the shortfall penalties that customers pay if they terminate their plans early? We also seek comment on whether an automatic reversion to undiscounted rates is a feature common to IP based Ethernet commercial agreements. To the extent such provisions appear in Ethernet commercial agreements, should the Commission consider prohibiting or otherwise restricting them? Finally, should such any such prohibition or restriction apply solely to non-competitive markets or more broadly to all markets?
246. We also seek comment on so-called “evergreen” provisions that allow a purchaser to continue to purchase services under the same terms and conditions following the expiration of an agreement as it had under the expired agreement. We seek comment on whether the Commission should require the inclusion of evergreen provisions in tariff pricing plans and commercial agreements for business data services in non-competitive markets. Would requiring carriers to provide evergreen status on a monthly basis following the expiration of an agreement provide purchasers flexibility in assessing their options or transitioning their purchases to IP based services? Would it be reasonable to impose such a requirement on providers in markets without sufficient competition, which would be assured additional purchases of their services under terms they have already agreed to?
247. We also seek comment on whether Ethernet commercial agreements commonly include evergreen provisions to ensure continued service at the same rates, terms and conditions following the expiration of an agreement. Are such provisions more common in Ethernet agreements than in TDM pricing plans? With regard to applying this framework to the provision of Ethernet-based business data service, do parties face the same constraints when negotiating agreements for TDM services and Ethernet-based services after a contract's expiration? Are there special terms and conditions that only apply when parties are negotiating a move from a provider's TDM services to a provider's Ethernet-based services and, if so, what impact do those terms and conditions have on the provision of Ethernet services? We also seek comment on whether a mandate for evergreen provisions should apply solely to non-competitive markets or more broadly to all markets.
248. We seek comment on whether required evergreen status should be time limited. If so, what would be a reasonable period of time that would provide flexibility to purchasers but also not unreasonably extend uncertainty for providers in non-competitive areas? Should customers be allowed to pay monthly rates equal to those under the original agreement for up to one year past the contract's expiration? Would this provide sufficient time to account for the average length of contract negotiations and to protect the interests of both parties? Do contract renewal negotiations typically extend beyond one year, and if they do, are there examples of providers that are willing to continue offering rates at the same level as those in the expired deal? We seek comment on this time period and whether a shorter or longer term would be more appropriate.

G. Alternative Approaches To Reforming BDS That Fulfill Core Goals
249. In addition to seeking comment on the new regulatory framework outlined above, we invite commenters to suggest alternative frameworks to apply to BDS. Are there other regulatory frameworks that would minimize regulation where competition is sufficient to constrain BDS rates, terms, and conditions and focus regulatory action on circumstances in which sufficient competition is lacking? All proposals should address the commercial practicalities and administrative feasibility of applying the alternative framework and explain how it furthers the Commission's core goals of promoting investment, innovation, competition, and protecting customers in the BDS marketplace.
250. In Part V.D.2 above, we invite comment a Competitive Market Test that focuses on product markets, customer classes, business density, and the number of facilities-based providers in a given geographic area, such as the census block. In this section, we seek comment on alternative approaches and criteria for determining whether or not a market is competitive. Commenters proposing such an alternative should explain how it will further the Commission's core goals in application and address administrative feasibility.
251. In Part V.D.5 we ask for comment as to which provider(s) specific rules in a non-competitive market should apply and how the Commission should determine whether to apply specific regulation to a particular provider, including the use of market shares, in non-competitive markets. In this section, we seek alternative proposals that would ensure that the Commission limits regulation to that which is necessary to ensure just and reasonable rates, terms and conditions within a non-competitive market while still encouraging new market entrants. Should we use a test of market power and, if so, how should market power be defined and how would such a market-power test be applied in a way that minimizes burdens on providers and the Commission? As to the scope of regulation, should we focus on the conditions in non-competitive markets and consider regulations that would apply generally or should we apply specific rules only to certain entrants, and if so, which ones? And how can we maintain and/or create incentives for new entry? How should we consider the potential presence of barriers to entry and policies that might serve to lower artificial barriers to entry? In general, what is the best form of regulation of a non-competitive market? As in Part V.D.5, we ask commenters to consider the impact of alternative new regulatory frameworks on investment and innovation.
252. For any proposed frameworks submitted in response to this section, commenters should explain how any triggers would be applied, which provider(s) would be subject to regulation and how such regulation would be implemented and enforced. For example, would there be tariffs or another mechanism? How would any alternative market test be applied, and would there be a process for challenges? Commenters submitting proposals they believe are simpler than the framework proposed above should explain why and how the administration would differ from the alternative proposals in this FNPRM.
253. While we have focused in the immediately preceding paragraphs on alternative tests of market competitiveness, we also encourage commenters to consider and suggest higher-level alternative regulatory regimes that would further the Commission's core goals.

H. Deregulation of the Pricing Process
254. In this section, we consider modifications to existing pricing mechanisms to implement the technology neutral regulatory framework for business data services proposed above. The proposed actions are intended to remove significant regulatory burdens, maintain price cap constraints where necessary to ensure just and reasonable rates, and create incentives to facilitate the technology transitions. First, we propose to replace the current pricing flexibility regime with rules based on the results of the Competitive Market Test. Under such rules, we would move competitive services out of price caps and move non-competitive services into a structure that provides the protections of price caps while allowing providers to negotiate individual contracts. Second, we propose a path to detariff TDM business data services while maintaining price caps on a detariffed basis. Finally, we seek comment on a voluntary mechanism that would provide carriers with the flexibility to adjust price cap rates for TDM BDS when replacement packet-based business data services are available.
255. We recognize that in this FNPRM we propose a number of changes to our interrelated regulatory rules. Specifically, in addition to the proposals in this section, we propose adopting a price cap productivity factor and relying on price cap TDM rates as benchmarks for non-competitive IP rates. We seek comment on any impacts that various proposals may have on each other.

1. Replacement of Pricing Flexibility Rules
256. In this section, we seek comment on the rules that will apply to TDM services currently subject to regulation under price caps as well as the pricing flexibility rules under the new regulatory framework. Here, we propose and seek comment on changes to the existing pricing flexibility rules.
257. We propose to treat competitive TDM and packet-based BDS on a technology neutral basis and propose further to remove TDM BDS determined to be competitive under the Competitive Market Test from price cap regulation and apply the competitive regulatory framework proposed above to these services. We seek comment on these proposals. Are there any reasons to treat competitive TDM differently from other competitive business data services? Are there implementation concerns with regulating these competitive services in this manner? Why or why not? If so, we seek proposals for addressing such concerns. If we adopt these proposals, should we require mandatory detariffing?
258. The Competitive Market Test will likely find some business data services are non-competitive and draw boundaries for such findings on a level more granular than an MSA, the current pricing flexibility boundary. Accordingly, it is possible that such non-competitive business data services may currently be regulated under price caps, Phase I pricing flexibility or Phase II pricing flexibility rules. Regardless of their current status, a non-competitive finding is a determination that we cannot rely on competition to constrain rates, terms and conditions to just and reasonable levels. We thus would need to have rules in place to constrain rates to just and reasonable levels. Our analysis of the application of the pricing flexibility rules indicates that customers have often benefited from individually negotiated contracts, and we believe that allowing such contracts will facilitate the development of a competitive market where possible. In order to constrain rates to just and reasonable levels and preserve the benefit of negotiated contracts where available, we propose to subject non-competitive TDM business data services, regardless of the currently applicable price cap and pricing flexibility rules, to a single, light-handed price cap regime that protects customers while providing flexibility to facilitate competition as it evolves. Specifically, we propose to apply the substance of the current Phase I pricing flexibility requirements to TDM business data services offered in non-competitive areas and seek comment on this proposal. Do parties support this proposal, why or why not? What concerns, administrative or otherwise, are raised by this proposal? Commenters asserting such services should be treated differently based on their current regulatory status should explain why that is consistent with the overall framework we propose in this order.
259. We seek comment on what changes to our current Phase I pricing flexibility rules are necessary to apply their substance to non-competitive TDM business data services. We propose to base our application of those rules and any necessary rule modifications on our authority under sections 201 and 202 of the Act. We seek comment on this proposal.

I. Additional Regulatory Incentives for Price Cap Carriers
260. We seek comment on potential regulatory forbearance and flexibility that will permit price cap incumbent LECs to continue to facilitate the technology transition, and to have increased incentives to develop innovative products and services.
261. We believe that implementation of our proposal for broadband data services offered in competitive markets would require that we forbear from the tariffing requirements in section 203 of the Act to the extent a BDS provider is currently subject to those requirements. We seek comment on this view and on the benefits of detariffing to customers and carriers in a competitive area. We also seek comment on whether the Commission should forbear from sections 204 and 205 of the Act. We propose forbearing to the extent necessary to implement our proposed framework and to condition the forbearance on the continuing existence of a competitive market under the Competitive Market Test. We expressly contemplate that should a market become non-competitive, then all of the regulation of non-competitive markets would apply, including price cap regulation. We invite comment on these proposals and on whether such conditional forbearance would meet the statutory forbearance criteria.
262. We propose the Commission make a similar finding for BDS in non-competitive areas, including TDM services under the section 10(a) standard, allowing forbearance from the tariffing requirements of section 203 of the Act, but continuing to require price cap regulation. We seek comment on this proposal, including the costs and benefits of tariffing in a non-competitive market or a market in which competition may be evolving over time. How would such a regulatory approach work to meet the goals of our proposed framework? How should the Commission consider the effect of any such forbearance on competition as set forth in section 10(b)? If the Commission decides to forbear from section 203, should it require mandatory detariffing as it did with interstate interexchange services or should it allow permissive tariffing? What would be the benefits of either approach? Should the Commission consider forbearing from sections 204 and 205 for these services? Would relief from tariffing and other provisions meet the statutory forbearance criteria? Would such relief provide additional incentives for innovation and development of new services? How would such relief benefit consumers and businesses? If providers continue to file similar information with the Commission as a tariff, we ask whether this impacts commenters' views on the benefits and burdens of such approach.
263. While we find above that TDM and packet-based BDS are in the same product market, these services are not identical and we also recognize significant switching costs in the market. We believe our regulatory framework can and should take account of legitimate differences in the provision of these services. We seek comment on how to do so and how to harmonize our goal of technological neutrality with the application of price cap regulation? Are there other methods of regulation that we should consider applying to these services or packet-based BDS to achieve our goals?
264. We note that without tariff filings, carriers would not receive the protection pursuant to section 204(a) of the Act of deemed lawful status for filing tariffs on a streamlined basis. This status immunizes carriers from damages liability for the periods in which the streamlined tariffs are in effect. We seek comment on how removing this protection would impact carriers and customers and the remedies available for rate challenges, including potential retroactive refunds. Should we provide carriers the option of permissive tariffing that would allow incumbent LECs to retain the “deemed lawful” protections of section 204(a) if the carrier should choose that option?
265. How, if at all, should the Commission modify its price cap filing rules in light of any forbearance from tariffing requirements? Under current rules, price cap incumbent LECs are required to submit a yearly filing to demonstrate that the carrier's API does not exceed its PCI. Would any additional rules be necessary to provide for adding new services? We seek comment on how any such filing should occur. Should the Commission maintain the yearly annual access charge filing requirement for this showing? Are there other alternatives that would ensure compliance with the price cap rules? Without tariff filings, how should the Commission best ensure that price cap incumbent LECs are offering rates consistent with their price cap filings? How should the Commission address a violation? Absent tariff filings, how would the Commission examine the newly filed rates or require the price cap incumbent LEC to modify its rates, to the extent appropriate, in the event of a violation? Would the Commission need to take formal action against the carrier and, if so, what form would that take? Are there other means for the Commission to review changes to a carrier's rates without the tariff filing requirement? Would the public disclosure requirement discussed below be sufficient?
266. What additional rules or procedures would be necessary to address rate or discount plan changes that would have resulted in a tariff filing absent forbearance? For example, under our current rules, a price cap LEC that grandfathers or otherwise discontinues a rate discount plan would be reducing the rate options for that service, which would constitute a rate restructure pursuant to section 61.49(e) of our rules, requiring the carrier to file supporting materials sufficient to make the adjustments to each affected API and SBI. Such a change may or may not impact the price cap, depending on the impact such a change will have on customer choices going forward. For example, if the price cap LEC grandfathers a service that has no customers, it potentially will have no impact on the carrier's API or SBI. The same is not true when a carrier grandfathers a pricing plan with substantial customers. We seek comment on what, if any, new requirements are necessary to ensure effective operation of the price cap as carriers begin to discontinue various discount plans.
267. Even if the Commission decides to forbear from tariffing requirements, we understand the importance of transparency for the price cap incumbent LEC's TDM rates. Accordingly, we propose to require price cap incumbent LECs to publicly disclose the rates, terms, and conditions for services currently subject to tariffing requirements. We seek comment on this proposal. How should disclosure of rates be implemented? Is posting on a carrier's Web site sufficient? Should the public disclosure requirement be limited to non-competitive markets?
268. As the technology transition continues to progress, one option for promoting an efficient move from TDM services to packet-based business data services is to allow BDS providers, on an entirely voluntary basis, the option to place some or all of their packet-based services under price cap regulation by including them in the special access basket. Moving these services into the basket would create flexibility for the provider to make rate adjustments to services within the confines of the cap. This would allow carriers flexibility to set prices for both packet-based services and TDM services based on the relative cost of and demand for these services, as would be the case in a competitive market. At the same time, the price cap would minimize the carriers' ability to charge non-competitive prices. We seek comment on this voluntary option. If the Commission were to permit this option, how should it be implemented? Would it incentivize technology transitions? Should packet-based services be placed in a separate service category and/or subcategories within the special access basket? If so, should pricing flexibility within the packet-based service category and/or subcategories be limited to an annual increase of five percent, relative to the percentage change in the PCI, the same percentage that applies to existing special access service categories and subcategories? Should providers be able to utilize this option at any time, or should there be a window or multiple windows of opportunity for when it would be available?

J. Forbearance Grants and Deemed Grants

1. Verizon Deemed Grant
269. As discussed above, in 2006 Verizon's Enterprise Broadband Forbearance Petition was deemed granted by operation of law after the Commission did not act on that petition within the statutory time limit. Consistent with Enterprise Broadband Forbearance Orders and with the Commission's unanimous commitment to apply the AT&T Forbearance Order to Verizon, we propose to reverse the Verizon deemed grant to the extent it encompasses forbearance relief not granted other carriers. We additionally propose that this decision would extend to Hawaiian Tel and to the legacy Verizon portions of FairPoint and Frontier, which were “Verizon telephone companies” at the time of the deemed grant. We invite comment on these proposals and ask whether such action would be consistent with the statutory forbearance criteria.

2. Other Forbearance Actions
270. In this FNPRM, we propose a number of interrelated changes to our regulation of business data services, many of which would allow or require carriers to detariff business data services that are presently provided subject to the tariffing requirements in section 203. Implementing those proposed changes would require that we expand the prior forbearance from section 203 to additional business data services providers and additional business data services. We believe we should expand that forbearance to the extent necessary to implement any regulatory changes we adopt in this proceeding. We invite comment on this view and on whether such forbearance would be consistent with the statutory forbearance criteria.

3. Legal Standard and Procedure
271. We believe that we have statutory authority to reverse a forbearance grant and a forbearance “deemed grant” by the failure of the Commission to act within the deadline of section 10(c). As the D.C. Circuit has observed, the Commission's forbearance actions—and the forbearance relief “deemed granted” to Verizon—are “not chiseled in marble.” Instead, the Commission may “reassess” that forbearance as it “reasonably see[s] fit based on changes in market conditions, technical, capabilities, or policy approaches to regulation” of business data services. We invite comment on the legal standard we would need to meet to reverse forbearance that has been deemed granted. Where, as here, Verizon does not oppose reversal of its deemed granted forbearance to place it on the same footing with other carriers as part of our proposed new framework, we believe that this standard is met. We invite comment on this analysis.
272. While we choose to address potential forbearance reversal in this rulemaking proceeding, we do not here consider whether rulemaking procedures are required for a reversal of forbearance. Nor are we, in taking this procedural approach here, classifying forbearance proceedings as necessarily requiring rulemaking procedures. The Commission has previously declined to classify forbearance as either adjudication or rulemaking. Rather, we find only that it is appropriate to address the proposed reversal here through a rulemaking proceeding.

K. Monitoring the Marketplace Going Forward
273. To update the analysis of the BDS industry going forward, we propose to conduct a periodic collection of data every three years, starting with the collection of year-end 2017 data. We seek comment on this proposal and alternative mechanisms that would assure our market definitions and competition analysis are updated on a regular basis.

1. Mandatory Periodic Collection
274. We propose to require BDS providers to submit information similar to what was collected previously for 2013, starting in 2018 and submitting 2017 data. In light of our experience with the data collection and analysis conducted, significantly paring down the number of providers required to report and the amount of reported information to those data categories most relevant to our analysis is appropriate. As with the earlier collection, we plan to focus on obtaining data on market structure, pricing, demand, and responses to competitive pressures. We propose, however, to eliminate many of the questions directed at providers related to terms and conditions, coverage footprints for “best efforts” services, marketing materials, disconnection policies, and short term and long-range promotional and advertising strategies. Our prior experience shows that the burden on filers of collecting such information going forward is not justified by the corresponding benefits of having this information for our core market analysis. We do not underestimate the importance of best efforts service, however, but can account for this service by using the information already collected by the Commission annually pursuant to the FCC Form 477 (Local Telephone Competition and Broadband Reporting). We also propose to not collect data from BDS purchasers on a mandatory basis and to instead use voluntary survey sampling of purchasers as discussed below. These changes would substantially decrease the burden on filers while providing the Commission with the data necessary to periodically update its analysis.

2. Providers Covered by the Periodic Collection Requirement
275. We propose to narrow the scope of our collection to minimize burdens on smaller providers where possible without compromising our analysis. While we would require all price cap incumbent LECs to provide data, we are considering excluding from the periodic collection those competitive providers below a set threshold based on either location with connection, number of BDS customers, or BDS revenues.
276. We continue to analyze whether the exclusion of providers below various thresholds will significantly impact the results of our price regressions and other methods of analysis. We seek comment on this proposal generally and ask for commenters to suggest appropriate thresholds and to quantify the potential impact of any exclusion on our analysis of the BDS industry.

3. Required Data and Information
277. Based on what we have learned, the most valuable data to our analysis is on the providers' locations with connections and billing information. Accordingly, we propose to require incumbent LECs to report locations where they have connections and provided BDS over the applicable period consistent with the information collected for questions II.B.2-3 in the 2015 Collection. Competitive providers would report locations where they have in-service or idle connections consistent with the reporting requirements for questions II.A.3-4 in the 2015 Collection. The reported locations would include all locations to which the competitive provider has a fiber connection (whether idle or in-service). Providers would also submit monthly billing information for the applicable period to the billed circuit element and linked to the served location consistent with the reporting requirements for questions II.A.12-14 for competitive providers and II.B.4-6 for incumbent LECs in the 2015 Collection.
278. Other categories of information required from providers as taken from the 2015 Collection would include the reporting of:
• BDS revenues for applicable period separated by customer and technology as required by questions II.A.15-16 for competitive providers and questions II.B.8-9 for incumbent LECs;
• Wire centers subject to price cap regulation by incumbent LECs for the applicable period as required by question II.B.7;
• Fiber network maps and information on fiber nodes by competitive providers as required by question II.A.5; and
• Information on recent RFPs from competitive providers as required by question II.A.11.
279. During the course of the Bureau's review of the collected 2013 data and ex parte discussions with stakeholders, we have also identified additional categories of questions or variations of previous categories of questions for which we propose to collect from all covered providers to assist with updating the Commission's analysis. These categories are as follows:
• A report on the different categories of BDS offered, including the different bandwidth speeds offered and the performance level guarantees offered with each type of service;
• Descriptions of how the provider structures its market operations to focus on particular classes of customers and the package of services marketed to each customer class;
• Information on BDS customer churn data, wins and losses over the applicable period, and the provider type to whom they are winning or losing customers to the extent known;
• Internal business documents assessing competitive pressures in the marketplace and changes to business operations in response to competitive pressures;
• Information to better track customer purchases across providers;
• Data on managed services purchased, which include a BDS component; and
• Information specific to the sale of leased lines to, and use by, carrier customers.
280. We believe this additional information would help the Commission further assess BDS demand by different classes of customers, the needs of those customer classes, and the level of competition in the marketplace. These changes would also address recommendations for improvements by our outside economic consultant. We seek comment on the proposed data points discussed above. In addition, depending on the ultimate criteria adopted for a Competitive Market Test, we seek comment on alternative data points for collection so the Commission can better measure the effectiveness of the Competitive Market Test criteria and revaluate and update its market definitions.

4. Voluntary Survey of Purchasers
281. We propose to not require BDS purchasers to submit data on a mandatory basis as with the previous collection given the burdens associated with such reporting compared to the value of the data for our analysis. The Commission instead proposes to conduct, with the assistance of a third-party, a voluntary survey of BDS purchasers, starting in 2017. The survey would include a sampling of wholesale and retail customers, a sampling of businesses of different sizes: small, medium, and large, and a sampling of mobile wireless providers.
282. The survey would collect information on, but not limited to, the BDS needs of the customer ( e.g., establishing virtual or private networks, accessing data centers or cloud-based services, accessing the Internet, and processing credit card transactions, among other information), the number of business locations requiring service, the performance levels required by the customer ( e.g., the service guarantees required on reliability, latency, packet loss, jitter, and mean time to repair), the purchaser's bandwidth requirements (symmetrical and/or asymmetrical), the BDS provider(s) they purchase from, the purchase and substitutability of “best efforts” services to meet their BDS needs, the extent to which they purchase BDS using fixed wireless, other potential BDS substitutes, number of available providers to fulfill BDS needs in a given area, types of BDS typically purchased by the customer ( e.g., Ethernet at certain speeds or DS1s and DS3s), prices typically paid for each type of BDS, any problems encountered with obtaining BDS (availability, timing, problematic terms and conditions, and the like), total BDS expenditures over the prior calendar year, the extent to which purchaser buys TDM products and plans to purchase such legacy services over the next three years. We seek comment on this proposal and on other potential categories of information to include in the survey.

5. Timing of the Collection
283. We believe that a periodic collection every three years is reasonable for our oversight needs. We seek comment on this view. This collection period would minimize the burden on filers while still allowing the Commission to timely gather data to update its analysis and monitor competition. The BDS industry is changing and significant developments can occur from year-to-year. By collecting data every three years, the Commission can effectively take stock of these changing trends. That said, we propose to conduct the first periodic collection in 2018, for year-end 2017 data. This would mean more than a three-year gap from the 2013 data but is reasonable to give covered providers time to update their systems to better track the information requested.

III. Procedural Matters

A. Ex Parte Requirements
284. This proceeding shall be treated as a “permit-but-disclose” proceeding in accordance with the Commission's ex parte rules. Persons making ex parte presentations must file a copy of any written presentation or a memorandum summarizing any oral presentation within two business days after the presentation (unless a different deadline applicable to the Sunshine period applies). Persons making oral ex parte presentations are reminded that memoranda summarizing the presentation must (1) List all persons attending or otherwise participating in the meeting at which the ex parte presentation was made, and (2) summarize all data presented and arguments made during the presentation. Memoranda must contain a summary of the substance of the ex parte presentation ad not merely a list of the subjects discussed. More than a one or two sentence description of the views and arguments presented is generally required. If the oral presentation consisted in whole or in part of the presentation of data or arguments already reflected in the presenter's written comments, memoranda or other filings in the proceeding, the presenter may provide citations to such data or arguments in his or her prior comments, memoranda, or other filings (specifying the relevant page and/or paragraph numbers where such data or arguments can be found) in lieu of summarizing them in the memorandum. Documents shown or given to Commission staff during ex parte meetings are deemed to be written ex parte presentations and must be filed consistent with rule 1.1206(b). In proceedings governed by rule 1.49(f) or for which the Commission has made available a method of electronic filing, written ex parte presentations and memoranda summarizing oral ex parte presentations, and all attachments thereto, must be filed through the electronic comment filing system available for that proceeding, and must be filed in their native format ( e.g., .doc, .xml, .ppt, searchable .pdf). Participants in this proceeding should familiarize themselves with the Commission's ex parte rules.

B. Paperwork Reduction Act Analysis
285. This FNPRM contains proposed new information collection requirements. The Commission, as part of its continuing effort to reduce paperwork burdens, invites the general public and the OMB and other Federal agencies to comment on the information collection requirements contained in this document, as required by the PRA, Public Law 104-13. In addition, pursuant to the Small Business Paperwork Relief Act of 2002, Public Law 107-198, see 44 U.S.C. 3506(c)(4), we seek specific comment on how we might further reduce the information collection burden for small business concerns with fewer than 25 employees.

C. Initial Regulatory Flexibility Analysis
286. As required by the Regulatory Flexibility Act of 1980 (RFA), the Commission has prepared an Initial Regulatory Flexibility Analysis (IRFA) for this FNPRM, of the possible significant economic impact on small entities of the policies and rules addressed in this document. The IRFA is set forth as Appendix D. Written public comments are requested on this IRFA. Comments must be identified as responses to the IRFA and must be filed by the deadlines for comments on the FNPRM provided on or before the dates indicated on the first page of this document. The Commission's Consumer and Governmental Affairs Bureau, Reference Information Center, will send a copy of this FNPRM, including the IRFA, to the Chief Counsel for Advocacy of the Small Business Administration (SBA).

IV. Ordering Clauses
287. Accordingly, it is ordered that, pursuant to sections 1, 2, 4(i)-(j), 10, 201(b), 202(a), 203, 204(a), 205, 303(r), and 403 of the Communications Act of 1934, as amended, 47 U.S.C. 151, 152, 154(i)-(j), 160, 201(b), 202(a), 203, 204(a), 205, 303(r), and 403 this Tariff Investigation Order and FNPRM is adopted.
288. It is further ordered that, pursuant to the applicable procedures set forth in sections 1.415 and 1.419 of the Commission's Rules, 47 CFR 1.415, 1.419, interested parties may file comments on the FNPRM and the application of the prohibition on all-or-nothing provisions in the tariff pricing plans subject to the tariff investigation to existing agreements on or before June 28, 2016, and reply comments on or before July 26, 2016.
289. It is further ordered that the Commission's Consumer & Governmental Affairs Bureau, Reference Information Center, shall send a copy of this FNPRM, including the Initial Regulatory Flexibility Analyses to the Chief Counsel for Advocacy of the Small Business Administration.

Initial Regulatory Flexibility Act Analysis
1. As required by the Regulatory Flexibility Act of 1980, as amended (RFA), the Commission has prepared this Initial Regulatory Flexibility Analysis (IRFA) of the possible significant economic impact on a substantial number of small entities from the policies and rules proposed in this FNPRM. The Commission requests written public comment on this IRFA. Comments must be identified as responses to the IRFA and must be filed by the deadlines for comments on the FNPRM provided in the item. The Commission will send a copy of the FNPRM, including this IRFA, to the Chief Counsel for Advocacy of the Small Business Administration (SBA). In addition, the FNPRM and IRFA (or summaries thereof) will be published in the Federal Register .

A. Need for, and Objectives of, the Proposed Rules
2. Technology-Neutral Framework. In the FNPRM the Commission proposes to replace the existing, fragmented regulatory regime applicable to business data services (BDS) ( i.e., special access services) with a new technology-neutral framework—the Competitive Market Test—which subjects non-competitive markets to tailored regulation, and competitive markets to minimal oversight. The pricing flexibility framework adopted in 1999 based regulatory relief from dominant carrier regulations on the presence of third-party collocations in the incumbent local exchange carrier's (LEC's) wire centers, which were considered proxies for competition in the marketplace. The Commission's review of the 2015 Collection data supports the Commission's earlier findings that collocations are a poor proxy for predicting the entry of facilities-based competition and the 1999 regime retained unnecessary regulation in areas that were likely competitive and deregulated over large areas where competition was unlikely to occur. The Commission therefore proposes to abandon the collocation-based competition showings for determining regulatory relief for incumbent LECs and, instead, proposes to apply a new Competitive Market Test and seeks comment on a regulatory framework going forward.
3. Competitive Analysis. The Commission sets forth its analysis of the extent of competition in the supply of BDS, based on its analysis of the 2015 Collection, and stakeholders' comments, and seeks comment on these findings. As far as the BDS product market, the Commission finds that “best efforts” BIAS do not appear to be a substitute for BDS whereas packet-based BDS, including HFC, is a substitute for TDM-based BDS, and product markets are subdivided by customer requirements and BDS performance characteristics. As far as the BDS geographic market, geographic concentration on any measure is high. The Commission found that supply of BDS with a bandwidth in excess of 50 Mbps tends to be more competitive than supply of BDS with lower bandwidths and allowing ILECs to offer contract tariffs benefits BDS purchasers and suppliers. The Commission seeks comment on how many competitive choices are necessary to ensure a competitive market, how important is potential competition, whether facility-based supply beyond half a mile has a material effect on prices and whether prices vary by the type of supply. Finally, the Commission seeks comment on a white paper prepared by an outside econometrician engaged by the Commission, Dr. Marc Rysman, conducting an independent competition analysis of the BDS market.
4. Competitive Market Test. As a replacement to the pricing flexibility rules, the Commission proposes a Competitive Market Test to determine the extent to which particular geographic areas and customer classes are subject to sufficient competition. In the FNPRM, the Commission proposes to define “business data services” (BDS) as a telecommunications service that transports data between two or more designated points at a rate of at least 1.5 Mbps in both directions (upstream/downstream) with prescribed performance requirements that include bandwidth, reliability, latency, jitter, and packet loss. The Commission, however, proposes excluding “best effort” services, e.g., mass market broadband Internet access service (BIAS) such as DSL and cable modem broadband access. The Commission is considering a test, which focuses on bandwidth, different customer classes, business density, and the number of providers in areas consisting of census blocks where each block in the relevant market meets the specified criteria. The Commission asks about applying the Competitive Market Test across all areas served by price cap carriers every three years to account for changes in business density and the presence of facilities-based providers in geographic areas. The Commission asks to what extent and how the Commission should give providers and purchasers an opportunity to challenge the determinations rendered.
5. Rules Applicable to All Markets. The Commission proposes limited requirements applicable to all competitive and non-competitive BDS markets. First, the Commission seeks comment on prohibiting the use of nondisclosure agreements (NDAs) in BDS commercial agreements that restrict parties ability to provide information to the Commission, effectively require legal compulsion to produce information, and limit parties disclosure to a response to a request by the Commission ( e.g. Notice of Proposed Rulemaking). Second, the Commission asks for comment on the appropriate treatment of the three types of tariff terms identified as unreasonable in the accompanying Tariff Investigation Order- “all-or-nothing” provisions, shortfall penalties, and early termination fees—as well as other contractual terms and conditions that have been subject to public comment. The Commission seeks comment on whether these provisions should be applied in non-competitive markets or more generally in all markets.
6. Non-Competitive Markets. The Commission proposes a tailored set of rules to safeguard customers in non-competitive markets, including the use of price regulation. In the FNPRM, the Commission proposes to continue to apply price cap regulation to time-division multiplexing (TDM)-based BDS in non-competitive markets, including non-competitive areas subject to pricing flexibility. The Commission also seeks comment on the application of rate regulation in non-competitive markets to packet-based BDS. The Commission proposes to incorporate into its price cap system a productivity-based “X-factor”—an adjustment to the price ceiling carriers can change reflecting the extent to which carriers overall outperform economy-wide productivity to ensure they are passing these gains to ratepayers while recovering their costs of service. We seek comment on the methodologies and data sources we should use to calculate the X-factor, including a staff-produced productivity study, and the corresponding price cap adjustments as well as the components of the price cap system.
7. Anchor Pricing and Benchmarking. In the FNPRM, the Commission proposes to adopt an anchor pricing or benchmarking approach for BDS in non-competitive markets to replace the interim rule adopted in the Emerging Wireline Order. We likewise believe that that anchor or benchmark pricing would not be appropriate in competitive markets. The Commission considers three options: (1) Relying on regulated TDM-based services pricing to anchor prices for similar packet-based services, (2) establishing a price for packet-based BDS which could serve as an anchor for similar packet-based services, and (3) initially using reasonably comparable prices for TDM-based services as a benchmark for packet-based services to determine whether those rates are just and reasonable. The Commission proposes to adopt the third option but seeks comment on this proposal and any associated implementation issues. Upon implementation of anchor pricing or benchmarking, we propose to continue forbearing from tariffing all packet-based services and to expand forbearance to include all price cap carriers and all packet-based services because this will allow for greater commercial negotiation and innovation. For carriers subject to these requirements, we propose to require them to publically disclose their generally available rates, terms and conditions and seek comment on this proposal. The Commission seeks comment on whether any reporting requirements should be imposed and whether the complaint and declaratory ruling process is reasonable to ensure compliance with the proposed framework. The Commission also seeks proposals for ensuring just and reasonable wholesale rates applicable in non-competitive markets such as whether providers are charging higher rates for wholesale than retail BDS, whether we should require public disclosure of these rates.
8. Terms and Conditions. The Commission proposes generally prohibiting tariff and other contractual “tying” arrangements that condition the sale of BDS in a non-competitive market on the sale of such services in a competitive market. The Commission also proposes prohibiting automatic renewal provisions in tariff pricing plans and contract tariffs for the provision of TDM-based broadband data services in non-competitive areas. The Commission proposes to find unreasonable any provision that enables a provider to increase its rates upon the expiration of either a tariff or commercial agreement for TDM-based or Ethernet-based service in non-competitive areas. Finally, the Commission seeks comment on tariff or commercial agreements containing percentage commitments to increase commitments if they reach a percentage threshold, overage penalties for going over volume commitments, automatic renewal provisions, undiscounted month-to-month pricing, and “evergreen” provisions that allow a purchaser to continue under same terms and conditions as under an expired agreement. In addition to seeking comment on the new regulatory framework, the Commission invites comment on alternative frameworks to apply to BDS.
9. Pricing Deregulation. The Commission proposes a set of deregulatory rules to govern competitive markets, using the Act's statutory authority to ensure that the provision of telecommunications services is just and reasonable. The Commission proposes that tariffs should not be used as part of the regulation of any BDS. The Commission proposes removing TDM-based BDS determined to be competitive from price cap regulation and apply a competitive regulatory framework, proposing a path to detariff time-division multiplexing (TDM)-based services while maintaining price caps. The Commission proposes forbearing from tariffing requirements to the extent necessary to implement our proposed framework, conditioned on the continuing presence of competition. The Commission proposes a similar finding for BDS in non-competitive areas, including TDM-based services but continue to require price cap regulation. The Commission seeks comment on how the Commission should modify its filing rules if it forbears from tariffing requirements. The Commission proposes to apply Phase I pricing flexibility requirements to TDM-based BDS in non-competitive areas and seeks comment on this proposal and any necessary changes to this approach.
10. Forbearance Grants and Deemed Grants. In order for the new regulatory framework be applied in a technology-neutral manner, the Commission proposes to eliminate the current exemption for certain Verizon services from the basic provisions of the Act governing just and reasonable offerings of telecommunications services. The Commission invites comment on the legal standard we would need to meet to reverse Verizon's forbearance that has been deemed granted, stating its belief that this standard is met in a rulemaking proceeding. Additionally, the Commission proposes extending this decision to reverse forbearance to Hawaiian Telecom and to the legacy Verizon portions of FairPoint and Frontier and invites comment on these proposals. At the same time, the Commission proposes to expand forbearance to the extent necessary to implement any regulatory changes adopted in this proceeding, many of which would allow or require carriers to detariff BDS, and invites comment on this proposal.

B. Legal Basis
11. The legal basis for any action that may be taken pursuant to the FNPRM is contained in sections 1, 2, 4(i)-(j), 10, 201, 202(a), 203, 204(a), 205, 208, 251, 303(r), and 403 of the Communications Act of 1934, as amended, 47 U.S.C. 151, 152, 154(i)-(j), 160, 201(b), 202(a), 203, 204(a), 205, 208, 251, 303(r), and 403.

C. Description and Estimate of the Number of Small Entities To Which the Rules Would Apply
12. The RFA directs agencies to provide a description of, and where feasible, an estimate of the number of small entities that may be affected by the proposed rules, if adopted. The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.” In addition, the term “small business” has the same meaning as the term “small-business concern” under the Small Business Act. A small-business concern” is one which: (1) Is independently owned and operated; (2) is not dominant in its field of operation; and (3) satisfies any additional criteria established by the Small Business Administration (SBA).

1. Total Small Entities
13. Our proposed action, if implemented, may, over time, affect small entities that are not easily categorized at present. We therefore describe here, at the outset, three comprehensive, statutory small entity size standards. First, nationwide, there are a total of approximately 28.2 million small businesses, according to the SBA, which represents 99.7% of all businesses in the United States. In addition, a “small organization” is generally “any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.” Nationwide, as of 2007, there were approximately 1,621,215 small organizations. Finally, the term “small governmental jurisdiction” is defined generally as “governments of cities, towns, townships, villages, school districts, or special districts, with a population of less than fifty thousand.” Census Bureau data for 2011 indicate that there were 90,056 local governmental jurisdictions in the United States. We estimate that, of this total, as many as 89,327 entities may qualify as “small governmental jurisdictions.” Thus, we estimate that most governmental jurisdictions are small.

2. Broadband Internet Access Service Providers
14. The rules adopted in the Order apply to broadband Internet access service providers. The Economic Census places these firms, whose services might include Voice over Internet Protocol (VoIP), in either of two categories, depending on whether the service is provided over the provider's own telecommunications facilities ( e.g., cable and DSL ISPs), or over client-supplied telecommunications connections ( e.g., dial-up ISPs). The former are within the category of Wired Telecommunications Carriers, which has an SBA small business size standard of 1,500 or fewer employees. These are also labeled “broadband.” The latter are within the category of All Other Telecommunications, which has a size standard of annual receipts of $32.5 million or less. These are labeled non-broadband. According to Census Bureau data for 2007, there were 3,188 firms in the first category, total, that operated for the entire year. Of this total, 3144 firms had employment of 999 or fewer employees, and 44 firms had employment of 1,000 employees or more. For the second category, the data show that 2,383 firms operated for the entire year. Of those, 2,346 had annual receipts below $32.5 million per year. Consequently, we estimate that the majority of broadband Internet access service provider firms are small entities.
15. The broadband Internet access service provider industry has changed since this definition was introduced in 2007. The data cited above may therefore include entities that no longer provide broadband Internet access service, and may exclude entities that now provide such service. To ensure that this FRFA describes the universe of small entities that our action might affect, we discuss in turn several different types of entities that might be providing broadband Internet access service. We note that, although we have no specific information on the number of small entities that provide broadband Internet access service over unlicensed spectrum, we include these entities in our Final Regulatory Flexibility Analysis.

3. Wireline Providers
16. Incumbent Local Exchange Carriers (Incumbent LECs). Neither the Commission nor the SBA has developed a small business size standard specifically for incumbent LEC services. The closest applicable size standard under SBA rules is for the category Wired Telecommunications Carriers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 1,307 carriers reported that they were incumbent LEC providers. Of these 1,307 carriers, an estimated 1,006 have 1,500 or fewer employees and 301 have more than 1,500 employees. Consequently, the Commission estimates that most providers of incumbent LEC service are small businesses that may be affected by rules adopted pursuant to the Order.
17. Competitive Local Exchange Carriers (Competitive LECs), Competitive Access Providers (CAPs), Shared-Tenant Service Providers, and Other Local Service Providers. Neither the Commission nor the SBA has developed a small business size standard specifically for these service providers. The appropriate size standard under SBA rules is for the category Wired Telecommunications Carriers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 1,442 carriers reported that they were engaged in the provision of either competitive local exchange services or competitive access provider services. Of these 1,442 carriers, an estimated 1,256 have 1,500 or fewer employees and 186 have more than 1,500 employees. In addition, 17 carriers have reported that they are Shared-Tenant Service Providers, and all 17 are estimated to have 1,500 or fewer employees. In addition, 72 carriers have reported that they are Other Local Service Providers. Of the 72, seventy have 1,500 or fewer employees and two have more than 1,500 employees. Consequently, the Commission estimates that most providers of competitive local exchange service, competitive access providers, Shared-Tenant Service Providers, and other local service providers are small entities that may be affected by rules adopted pursuant to the Order.
18. We have included small incumbent LECs in this present RFA analysis. As noted above, a “small business” under the RFA is one that, inter alia, meets the pertinent small business size standard ( e.g., a telephone communications business having 1,500 or fewer employees), and “is not dominant in its field of operation.” The SBA's Office of Advocacy contends that, for RFA purposes, small incumbent LECs are not dominant in their field of operation because any such dominance is not “national” in scope. We have therefore included small incumbent LECs in this RFA analysis, although we emphasize that this RFA action has no effect on Commission analyses and determinations in other, non-RFA contexts.
19. Interexchange Carriers. Neither the Commission nor the SBA has developed a small business size standard specifically for providers of interexchange services. The appropriate size standard under SBA rules is for the category Wired Telecommunications Carriers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 359 carriers have reported that they are engaged in the provision of interexchange service. Of these, an estimated 317 have 1,500 or fewer employees and 42 have more than 1,500 employees. Consequently, the Commission estimates that the majority of interexchange carriers are small entities that may be affected by rules adopted pursuant to the Order.
20. Operator Service Providers (OSPs). Neither the Commission nor the SBA has developed a small business size standard specifically for operator service providers. The appropriate size standard under SBA rules is for the category Wired Telecommunications Carriers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 33 carriers have reported that they are engaged in the provision of operator services. Of these, an estimated 31 have 1,500 or fewer employees and two have more than 1,500 employees. Consequently, the Commission estimates that the majority of OSPs are small entities that may be affected by rules adopted pursuant to the Order.
21. Prepaid Calling Card Providers. Neither the Commission nor the SBA has developed a small business size standard specifically for prepaid calling card providers. The appropriate size standard under SBA rules is for the category Telecommunications Resellers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 193 carriers have reported that they are engaged in the provision of prepaid calling cards. Of these, an estimated all 193 have 1,500 or fewer employees and none have more than 1,500 employees. Consequently, the Commission estimates that the majority of prepaid calling card providers are small entities that may be affected by rules adopted pursuant to the Order.
22. Local Resellers. The SBA has developed a small business size standard for the category of Telecommunications Resellers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 213 carriers have reported that they are engaged in the provision of local resale services. Of these, an estimated 211 have 1,500 or fewer employees and two have more than 1,500 employees. Consequently, the Commission estimates that the majority of local resellers are small entities that may be affected by rules adopted pursuant to the Order.
23. Toll Resellers. The SBA has developed a small business size standard for the category of Telecommunications Resellers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 881 carriers have reported that they are engaged in the provision of toll resale services. Of these, an estimated 857 have 1,500 or fewer employees and 24 have more than 1,500 employees. Consequently, the Commission estimates that the majority of toll resellers are small entities that may be affected by rules adopted pursuant to the Order.
24. Other Toll Carriers. Neither the Commission nor the SBA has developed a size standard for small businesses specifically applicable to Other Toll Carriers. This category includes toll carriers that do not fall within the categories of interexchange carriers, operator service providers, prepaid calling card providers, satellite service carriers, or toll resellers. The closest applicable size standard under SBA rules is for Wired Telecommunications Carriers. Under that size standard, such a business is small if it has 1,500 or fewer employees. According to Commission data, 284 companies reported that their primary telecommunications service activity was the provision of other toll carriage. Of these, an estimated 279 have 1,500 or fewer employees and five have more than 1,500 employees. Consequently, the Commission estimates that most Other Toll Carriers are small entities that may be affected by the rules and policies adopted pursuant to the Order.
25. 800 and 800-Like Service Subscribers. Neither the Commission nor the SBA has developed a small business size standard specifically for 800 and 800-like service (toll free) subscribers. The appropriate size standard under SBA rules is for the category Telecommunications Resellers. Under that size standard, such a business is small if it has 1,500 or fewer employees. The most reliable source of information regarding the number of these service subscribers appears to be data the Commission collects on the 800, 888, 877, and 866 numbers in use. According to our data, as of September 2009, the number of 800 numbers assigned was 7,860,000; the number of 888 numbers assigned was 5,588,687; the number of 877 numbers assigned was 4,721,866; and the number of 866 numbers assigned was 7,867,736. We do not have data specifying the number of these subscribers that are not independently owned and operated or have more than 1,500 employees, and thus are unable at this time to estimate with greater precision the number of toll free subscribers that would qualify as small businesses under the SBA size standard. Consequently, we estimate that there are 7,860,000 or fewer small entity 800 subscribers; 5,588,687 or fewer small entity 888 subscribers; 4,721,866 or fewer small entity 877 subscribers; and 7,867,736 or fewer small entity 866 subscribers.

4. Wireless Providers—Fixed and Mobile
26. The broadband Internet access service provider category covered by this Order may cover multiple wireless firms and categories of regulated wireless services. Thus, to the extent the wireless services listed below are used by wireless firms for broadband Internet access service, the proposed actions may have an impact on those small businesses as set forth above and further below. In addition, for those services subject to auctions, we note that, as a general matter, the number of winning bidders that claim to qualify as small businesses at the close of an auction does not necessarily represent the number of small businesses currently in service. Also, the Commission does not generally track subsequent business size unless, in the context of assignments and transfers or reportable eligibility events, unjust enrichment issues are implicated.
27. Wireless Telecommunications Carriers (except Satellite). Since 2007, the Census Bureau has placed wireless firms within this new, broad, economic census category. Under the present and prior categories, the SBA has deemed a wireless business to be small if it has 1,500 or fewer employees. For the category of Wireless Telecommunications Carriers (except Satellite), census data for 2007 show that there were 1,383 firms that operated for the entire year. Of this total, 1,368 firms had employment of 999 or fewer employees and 15 had employment of 1,000 employees or more. Since all firms with fewer than 1,500 employees are considered small, given the total employment in the sector, we estimate that the vast majority of wireless firms are small. Wireless Communications Services. This service can be used for fixed, mobile, radiolocation, and digital audio broadcasting satellite uses. The Commission defined “small business” for the wireless communications services (WCS) auction as an entity with average gross revenues of $40 million for each of the three preceding years, and a “very small business” as an entity with average gross revenues of $15 million for each of the three preceding years. The SBA has approved these definitions. 218-219 MHz Service. The first auction of 218-219 MHz spectrum resulted in 170 entities winning licenses for 594 Metropolitan Statistical Area (MSA) licenses. Of the 594 licenses, 557 were won by entities qualifying as a small business. For that auction, the small business size standard was an entity that, together with its affiliates, has no more than a $6 million net worth and, after federal income taxes (excluding any carry over losses), has no more than $2 million in annual profits each year for the previous two years. In the 218-219 MHz Report and Order and Memorandum Opinion and Order, we established a small business size standard for a “small business” as an entity that, together with its affiliates and persons or entities that hold interests in such an entity and their affiliates, has average annual gross revenues not to exceed $15 million for the preceding three years. A “very small business” is defined as an entity that, together with its affiliates and persons or entities that hold interests in such an entity and its affiliates, has average annual gross revenues not to exceed $3 million for the preceding three years. These size standards will be used in future auctions of 218-219 MHz spectrum.
28. 2.3 GHz Wireless Communications Services. This service can be used for fixed, mobile, radiolocation, and digital audio broadcasting satellite uses. The Commission defined “small business” for the wireless communications services (“WCS”) auction as an entity with average gross revenues of $40 million for each of the three preceding years, and a “very small business” as an entity with average gross revenues of $15 million for each of the three preceding years. The SBA has approved these definitions. The Commission auctioned geographic area licenses in the WCS service. In the auction, which was conducted in 1997, there were seven bidders that won 31 licenses that qualified as very small business entities, and one bidder that won one license that qualified as a small business entity.
29. 1670-1675 MHz Services. This service can be used for fixed and mobile uses, except aeronautical mobile. An auction for one license in the 1670-1675 MHz band was conducted in 2003. One license was awarded. The winning bidder was not a small entity.
30. Wireless Telephony. Wireless telephony includes cellular, personal communications services, and specialized mobile radio telephony carriers. As noted, the SBA has developed a small business size standard for Wireless Telecommunications Carriers (except Satellite). Under the SBA small business size standard, a business is small if it has 1,500 or fewer employees. According to Commission data, 413 carriers reported that they were engaged in wireless telephony. Of these, an estimated 261 have 1,500 or fewer employees and 152 have more than 1,500 employees. Therefore, a little less than one third of these entities can be considered small.
31. Broadband Personal Communications Service. The broadband personal communications services (PCS) spectrum is divided into six frequency blocks designated A through F, and the Commission has held auctions for each block. The Commission initially defined a “small business” for C- and F-Block licenses as an entity that has average gross revenues of $40 million or less in the three previous calendar years. For F-Block licenses, an additional small business size standard for “very small business” was added and is defined as an entity that, together with its affiliates, has average gross revenues of not more than $15 million for the preceding three calendar years. These small business size standards, in the context of broadband PCS auctions, have been approved by the SBA. No small businesses within the SBA-approved small business size standards bid successfully for licenses in Blocks A and B. There were 90 winning bidders that claimed small business status in the first two C-Block auctions. A total of 93 bidders that claimed small business status won approximately 40 percent of the 1,479 licenses in the first auction for the D, E, and F Blocks. On April 15, 1999, the Commission completed the reauction of 347 C-, D-, E-, and F-Block licenses in Auction No. 22. Of the 57 winning bidders in that auction, 48 claimed small business status and won 277 licenses.
32. On January 26, 2001, the Commission completed the auction of 422 C and F Block Broadband PCS licenses in Auction No. 35. Of the 35 winning bidders in that auction, 29 claimed small business status. Subsequent events concerning Auction 35, including judicial and agency determinations, resulted in a total of 163 C and F Block licenses being available for grant. On February 15, 2005, the Commission completed an auction of 242 C-, D-, E-, and F-Block licenses in Auction No. 58. Of the 24 winning bidders in that auction, 16 claimed small business status and won 156 licenses. On May 21, 2007, the Commission completed an auction of 33 licenses in the A, C, and F Blocks in Auction No. 71. Of the 12 winning bidders in that auction, five claimed small business status and won 18 licenses. On August 20, 2008, the Commission completed the auction of 20 C-, D-, E-, and F-Block Broadband PCS licenses in Auction No. 78. Of the eight winning bidders for Broadband PCS licenses in that auction, six claimed small business status and won 14 licenses.
33. Specialized Mobile Radio Licenses. The Commission awards “small entity” bidding credits in auctions for Specialized Mobile Radio (SMR) geographic area licenses in the 800 MHz and 900 MHz bands to firms that had revenues of no more than $15 million in each of the three previous calendar years. The Commission awards “very small entity” bidding credits to firms that had revenues of no more than $3 million in each of the three previous calendar years. The SBA has approved these small business size standards for the 900 MHz Service. The Commission has held auctions for geographic area licenses in the 800 MHz and 900 MHz bands. The 900 MHz SMR auction began on December 5, 1995, and closed on April 15, 1996. Sixty bidders claiming that they qualified as small businesses under the $15 million size standard won 263 geographic area licenses in the 900 MHz SMR band. The 800 MHz SMR auction for the upper 200 channels began on October 28, 1997, and was completed on December 8, 1997. Ten bidders claiming that they qualified as small businesses under the $15 million size standard won 38 geographic area licenses for the upper 200 channels in the 800 MHz SMR band. A second auction for the 800 MHz band was held on January 10, 2002 and closed on January 17, 2002 and included 23 BEA licenses. One bidder claiming small business status won five licenses.
34. The auction of the 1,053 800 MHz SMR geographic area licenses for the General Category channels began on August 16, 2000, and was completed on September 1, 2000. Eleven bidders won 108 geographic area licenses for the General Category channels in the 800 MHz SMR band and qualified as small businesses under the $15 million size standard. In an auction completed on December 5, 2000, a total of 2,800 Economic Area licenses in the lower 80 channels of the 800 MHz SMR service were awarded. Of the 22 winning bidders, 19 claimed small business status and won 129 licenses. Thus, combining all four auctions, 41 winning bidders for geographic licenses in the 800 MHz SMR band claimed status as small businesses.
35. In addition, there are numerous incumbent site-by-site SMR licenses and licensees with extended implementation authorizations in the 800 and 900 MHz bands. We do not know how many firms provide 800 MHz or 900 MHz geographic area SMR service pursuant to extended implementation authorizations, nor how many of these providers have annual revenues of no more than $15 million. One firm has over $15 million in revenues. In addition, we do not know how many of these firms have 1,500 or fewer employees, which is the SBA-determined size standard. We assume, for purposes of this analysis, that all of the remaining extended implementation authorizations are held by small entities, as defined by the SBA.
36. Lower 700 MHz Band Licenses. The Commission previously adopted criteria for defining three groups of small businesses for purposes of determining their eligibility for special provisions such as bidding credits. The Commission defined a “small business” as an entity that, together with its affiliates and controlling principals, has average gross revenues not exceeding $40 million for the preceding three years. A “very small business” is defined as an entity that, together with its affiliates and controlling principals, has average gross revenues that are not more than $15 million for the preceding three years. Additionally, the lower 700 MHz Service had a third category of small business status for Metropolitan/Rural Service Area (MSA/RSA) licenses—“entrepreneur”—which is defined as an entity that, together with its affiliates and controlling principals, has average gross revenues that are not more than $3 million for the preceding three years. The SBA approved these small size standards. An auction of 740 licenses (one license in each of the 734 MSAs/RSAs and one license in each of the six Economic Area Groupings (EAGs)) commenced on August 27, 2002, and closed on September 18, 2002. Of the 740 licenses available for auction, 484 licenses were won by 102 winning bidders. Seventy-two of the winning bidders claimed small business, very small business or entrepreneur status and won a total of 329 licenses. A second auction commenced on May 28, 2003, closed on June 13, 2003, and included 256 licenses: 5 EAG licenses and 476 Cellular Market Area licenses. Seventeen winning bidders claimed small or very small business status and won 60 licenses, and nine winning bidders claimed entrepreneur status and won 154 licenses. On July 26, 2005, the Commission completed an auction of 5 licenses in the Lower 700 MHz band (Auction No. 60). There were three winning bidders for five licenses. All three winning bidders claimed small business status.
37. In 2007, the Commission reexamined its rules governing the 700 MHz band in the 700 MHz Second Report and Order. An auction of 700 MHz licenses commenced January 24, 2008 and closed on March 18, 2008, which included, 176 Economic Area licenses in the A Block, 734 Cellular Market Area licenses in the B Block, and 176 EA licenses in the E Block. Twenty winning bidders, claiming small business status (those with attributable average annual gross revenues that exceed $15 million and do not exceed $40 million for the preceding three years) won 49 licenses. Thirty three winning bidders claiming very small business status (those with attributable average annual gross revenues that do not exceed $15 million for the preceding three years) won 325 licenses.
38. Upper 700 MHz Band Licenses. In the 700 MHz Second Report and Order, the Commission revised its rules regarding Upper 700 MHz licenses. On January 24, 2008, the Commission commenced Auction 73 in which several licenses in the Upper 700 MHz band were available for licensing: 12 Regional Economic Area Grouping licenses in the C Block, and one nationwide license in the D Block. The auction concluded on March 18, 2008, with 3 winning bidders claiming very small business status (those with attributable average annual gross revenues that do not exceed $15 million for the preceding three years) and winning five licenses.
39. 700 MHz Guard Band Licensees. In 2000, in the 700 MHz Guard Band Order, the Commission adopted size standards for “small businesses” and “very small businesses” for purposes of determining their eligibility for special provisions such as bidding credits and installment payments. A small business in this service is an entity that, together with its affiliates and controlling principals, has average gross revenues not exceeding $40 million for the preceding three years. Additionally, a very small business is an entity that, together with its affiliates and controlling principals, has average gross revenues that are not more than $15 million for the preceding three years. SBA approval of these definitions is not required. An auction of 52 Major Economic Area licenses commenced on September 6, 2000, and closed on September 21, 2000. Of the 104 licenses auctioned, 96 licenses were sold to nine bidders. Five of these bidders were small businesses that won a total of 26 licenses. A second auction of 700 MHz Guard Band licenses commenced on February 13, 2001, and closed on February 21, 2001. All eight of the licenses auctioned were sold to three bidders. One of these bidders was a small business that won a total of two licenses.
40. Cellular Radiotelephone Service. Auction 77 was held to resolve one group of mutually exclusive applications for Cellular Radiotelephone Service licenses for unserved areas in New Mexico. Bidding credits for designated entities were not available in Auction 77. In 2008, the Commission completed the closed auction of one unserved service area in the Cellular Radiotelephone Service, designated as Auction 77. Auction 77 concluded with one provisionally winning bid for the unserved area totaling $25,002.
41. Private Land Mobile Radio (“PLMR”). PLMR systems serve an essential role in a range of industrial, business, land transportation, and public safety activities. These radios are used by companies of all sizes operating in all U.S. business categories, and are often used in support of the licensee's primary (non-telecommunications) business operations. For the purpose of determining whether a licensee of a PLMR system is a small business as defined by the SBA, we use the broad census category, Wireless Telecommunications Carriers (except Satellite). This definition provides that a small entity is any such entity employing no more than 1,500 persons. The Commission does not require PLMR licensees to disclose information about number of employees, so the Commission does not have information that could be used to determine how many PLMR licensees constitute small entities under this definition. We note that PLMR licensees generally use the licensed facilities in support of other business activities, and therefore, it would also be helpful to assess PLMR licensees under the standards applied to the particular industry subsector to which the licensee belongs.
42. As of March 2010, there were 424,162 PLMR licensees operating 921,909 transmitters in the PLMR bands below 512 MHz. We note that any entity engaged in a commercial activity is eligible to hold a PLMR license, and that any revised rules in this context could therefore potentially impact small entities covering a great variety of industries.
43. Rural Radiotelephone Service. The Commission has not adopted a size standard for small businesses specific to the Rural Radiotelephone Service. A significant subset of the Rural Radiotelephone Service is the Basic Exchange Telephone Radio System (BETRS). In the present context, we will use the SBA's small business size standard applicable to Wireless Telecommunications Carriers (except Satellite), i.e., an entity employing no more than 1,500 persons. There are approximately 1,000 licensees in the Rural Radiotelephone Service, and the Commission estimates that there are 1,000 or fewer small entity licensees in the Rural Radiotelephone Service that may be affected by the rules and policies proposed herein.
44. Air-Ground Radiotelephone Service. The Commission has previously used the SBA's small business size standard applicable to Wireless Telecommunications Carriers (except Satellite), i.e., an entity employing no more than 1,500 persons. There are approximately 100 licensees in the Air-Ground Radiotelephone Service, and under that definition, we estimate that almost all of them qualify as small entities under the SBA definition. For purposes of assigning Air-Ground Radiotelephone Service licenses through competitive bidding, the Commission has defined “small business” as an entity that, together with controlling interests and affiliates, has average annual gross revenues for the preceding three years not exceeding $40 million. A “very small business” is defined as an entity that, together with controlling interests and affiliates, has average annual gross revenues for the preceding three years not exceeding $15 million. These definitions were approved by the SBA. In May 2006, the Commission completed an auction of nationwide commercial Air-Ground Radiotelephone Service licenses in the 800 MHz band (Auction No. 65). On June 2, 2006, the auction closed with two winning bidders winning two Air-Ground Radiotelephone Services licenses. Neither of the winning bidders claimed small business status.
45. Aviation and Marine Radio Services. Small businesses in the aviation and marine radio services use a very high frequency (VHF) marine or aircraft radio and, as appropriate, an emergency position-indicating radio beacon (and/or radar) or an emergency locator transmitter. The Commission has not developed a small business size standard specifically applicable to these small businesses. For purposes of this analysis, the Commission uses the SBA small business size standard for the category Wireless Telecommunications Carriers (except Satellite), which is 1,500 or fewer employees. Census data for 2007, which supersede data contained in the 2002 Census, show that there were 1,383 firms that operated that year. Of those 1,383, 1,368 had fewer than 100 employees, and 15 firms had more than 100 employees. Most applicants for recreational licenses are individuals. Approximately 581,000 ship station licensees and 131,000 aircraft station licensees operate domestically and are not subject to the radio carriage requirements of any statute or treaty. For purposes of our evaluations in this analysis, we estimate that there are up to approximately 712,000 licensees that are small businesses (or individuals) under the SBA standard. In addition, between December 3, 1998 and December 14, 1998, the Commission held an auction of 42 VHF Public Coast licenses in the 157.1875-157.4500 MHz (ship transmit) and 161.775-162.0125 MHz (coast transmit) bands. For purposes of the auction, the Commission defined a “small” business as an entity that, together with controlling interests and affiliates, has average gross revenues for the preceding three years not to exceed $15 million dollars. In addition, a “very small” business is one that, together with controlling interests and affiliates, has average gross revenues for the preceding three years not to exceed $3 million dollars. There are approximately 10,672 licensees in the Marine Coast Service, and the Commission estimates that almost all of them qualify as “small” businesses under the above special small business size standards and may be affected by rules adopted pursuant to the Order.
46. Advanced Wireless Services (AWS) (1710-1755 MHz and 2110-2155 MHz bands (AWS-1); 1915-1920 MHz, 1995-2000 MHz, 2020-2025 MHz and 2175-2180 MHz bands (AWS-2); 2155-2175 MHz band (AWS-3)). For the AWS-1 bands, the Commission has defined a “small business” as an entity with average annual gross revenues for the preceding three years not exceeding $40 million, and a “very small business” as an entity with average annual gross revenues for the preceding three years not exceeding $15 million. For AWS-2 and AWS-3, although we do not know for certain which entities are likely to apply for these frequencies, we note that the AWS-1 bands are comparable to those used for cellular service and personal communications service. The Commission has not yet adopted size standards for the AWS-2 or AWS-3 bands but proposes to treat both AWS-2 and AWS-3 similarly to broadband PCS service and AWS-1 service due to the comparable capital requirements and other factors, such as issues involved in relocating incumbents and developing markets, technologies, and services.
47. 3650-3700 MHz band. In March 2005, the Commission released a Report and Order and Memorandum Opinion and Order that provides for nationwide, non-exclusive licensing of terrestrial operations, utilizing contention-based technologies, in the 3650 MHz band ( i.e., 3650-3700 MHz). As of April 2010, more than 1270 licenses have been granted and more than 7433 sites have been registered. The Commission has not developed a definition of small entities applicable to 3650-3700 MHz band nationwide, non-exclusive licensees. However, we estimate that the majority of these licensees are Internet Access Service Providers (ISPs) and that most of those licensees are small businesses.
48. Fixed Microwave Services. Microwave services include common carrier, private-operational fixed, and broadcast auxiliary radio services. They also include the Local Multipoint Distribution Service (LMDS), the Digital Electronic Message Service (DEMS), and the 24 GHz Service, where licensees can choose between common carrier and non-common carrier status. At present, there are approximately 36,708 common carrier fixed licensees and 59,291 private operational-fixed licensees and broadcast auxiliary radio licensees in the microwave services. There are approximately 135 LMDS licensees, three DEMS licensees, and three 24 GHz licensees. The Commission has not yet defined a small business with respect to microwave services. For purposes of the FRFA, we will use the SBA's definition applicable to Wireless Telecommunications Carriers (except satellite)— i.e., an entity with no more than 1,500 persons. Under the present and prior categories, the SBA has deemed a wireless business to be small if it has 1,500 or fewer employees. The Commission does not have data specifying the number of these licensees that have more than 1,500 employees, and thus is unable at this time to estimate with greater precision the number of fixed microwave service licensees that would qualify as small business concerns under the SBA's small business size standard. Consequently, the Commission estimates that there are up to 36,708 common carrier fixed licensees and up to 59,291 private operational-fixed licensees and broadcast auxiliary radio licensees in the microwave services that may be small and may be affected by the rules and policies adopted herein. We note, however, that the common carrier microwave fixed licensee category includes some large entities.
49. Offshore Radiotelephone Service. This service operates on several UHF television broadcast channels that are not used for television broadcasting in the coastal areas of states bordering the Gulf of Mexico. There are presently approximately 55 licensees in this service. The Commission is unable to estimate at this time the number of licensees that would qualify as small under the SBA's small business size standard for the category of Wireless Telecommunications Carriers (except Satellite). Under that SBA small business size standard, a business is small if it has 1,500 or fewer employees. Census data for 2007, which supersede data contained in the 2002 Census, show that there were 1,383 firms that operated that year. Of those 1,383, 1,368 had fewer than 100 employees, and 15 firms had more than 100 employees. Thus, under this category and the associated small business size standard, the majority of firms can be considered small.
50. 39 GHz Service. The Commission created a special small business size standard for 39 GHz licenses—an entity that has average gross revenues of $40 million or less in the three previous calendar years. An additional size standard for “very small business” is: An entity that, together with affiliates, has average gross revenues of not more than $15 million for the preceding three calendar years. The SBA has approved these small business size standards. The auction of the 2,173 39 GHz licenses began on April 12, 2000 and closed on May 8, 2000. The 18 bidders who claimed small business status won 849 licenses. Consequently, the Commission estimates that 18 or fewer 39 GHz licensees are small entities that may be affected by rules adopted pursuant to the Order.
51. Broadband Radio Service and Educational Broadband Service. Broadband Radio Service systems, previously referred to as Multipoint Distribution Service (MDS) and Multichannel Multipoint Distribution Service (MMDS) systems, and “wireless cable,” transmit video programming to subscribers and provide two-way high speed data operations using the microwave frequencies of the Broadband Radio Service (BRS) and Educational Broadband Service (EBS) (previously referred to as the Instructional Television Fixed Service (ITFS)). In connection with the 1996 BRS auction, the Commission established a small business size standard as an entity that had annual average gross revenues of no more than $40 million in the previous three calendar years. The BRS auctions resulted in 67 successful bidders obtaining licensing opportunities for 493 Basic Trading Areas (BTAs). Of the 67 auction winners, 61 met the definition of a small business. BRS also includes licensees of stations authorized prior to the auction. At this time, we estimate that of the 61 small business BRS auction winners, 48 remain small business licensees. In addition to the 48 small businesses that hold BTA authorizations, there are approximately 392 incumbent BRS licensees that are considered small entities. After adding the number of small business auction licensees to the number of incumbent licensees not already counted, we find that there are currently approximately 440 BRS licensees that are defined as small businesses under either the SBA or the Commission's rules.
52. In 2009, the Commission conducted Auction 86, the sale of 78 licenses in the BRS areas. The Commission offered three levels of bidding credits: (i) A bidder with attributed average annual gross revenues that exceed $15 million and do not exceed $40 million for the preceding three years (small business) received a 15 percent discount on its winning bid; (ii) a bidder with attributed average annual gross revenues that exceed $3 million and do not exceed $15 million for the preceding three years (very small business) received a 25 percent discount on its winning bid; and (iii) a bidder with attributed average annual gross revenues that do not exceed $3 million for the preceding three years (entrepreneur) received a 35 percent discount on its winning bid. Auction 86 concluded in 2009 with the sale of 61 licenses. Of the ten winning bidders, two bidders that claimed small business status won 4 licenses; one bidder that claimed very small business status won three licenses; and two bidders that claimed entrepreneur status won six licenses.
53. In addition, the SBA's Cable Television Distribution Services small business size standard is applicable to EBS. There are presently 2,436 EBS licensees. All but 100 of these licenses are held by educational institutions. Educational institutions are included in this analysis as small entities. Thus, we estimate that at least 2,336 licensees are small businesses. Since 2007, Cable Television Distribution Services have been defined within the broad economic census category of Wired Telecommunications Carriers; that category is defined as follows: “This industry comprises establishments primarily engaged in operating and/or providing access to transmission facilities and infrastructure that they own and/or lease for the transmission of voice, data, text, sound, and video using wired telecommunications networks. Transmission facilities may be based on a single technology or a combination of technologies.” The SBA has developed a small business size standard for this category, which is: All such firms having 1,500 or fewer employees. To gauge small business prevalence for these cable services we must, however, use the most current census data that are based on the previous category of Cable and Other Program Distribution and its associated size standard; that size standard was: All such firms having $13.5 million or less in annual receipts. According to Census Bureau data for 2007, there were a total of 996 firms in this category that operated for the entire year. Of this total, 948 firms had annual receipts of under $10 million, and 48 firms had receipts of $10 million or more but less than $25 million. Thus, the majority of these firms can be considered small.
54. Narrowband Personal Communications Services. In 1994, the Commission conducted an auction for Narrowband PCS licenses. A second auction was also conducted later in 1994. For purposes of the first two Narrowband PCS auctions, “small businesses” were entities with average gross revenues for the prior three calendar years of $40 million or less. Through these auctions, the Commission awarded a total of 41 licenses, 11 of which were obtained by four small businesses. To ensure meaningful participation by small business entities in future auctions, the Commission adopted a two-tiered small business size standard in the Narrowband PCS Second Report and Order. A “small business” is an entity that, together with affiliates and controlling interests, has average gross revenues for the three preceding years of not more than $40 million. A “very small business” is an entity that, together with affiliates and controlling interests, has average gross revenues for the three preceding years of not more than $15 million. The SBA has approved these small business size standards. A third auction was conducted in 2001. Here, five bidders won 317 (Metropolitan Trading Areas and nationwide) licenses. Three of these claimed status as a small or very small entity and won 311 licenses.
55. Paging (Private and Common Carrier). In the Paging Third Report and Order, we developed a small business size standard for “small businesses” and “very small businesses” for purposes of determining their eligibility for special provisions such as bidding credits and installment payments. A “small business” is an entity that, together with its affiliates and controlling principals, has average gross revenues not exceeding $15 million for the preceding three years. Additionally, a “very small business” is an entity that, together with its affiliates and controlling principals, has average gross revenues that are not more than $3 million for the preceding three years. The SBA has approved these small business size standards. According to Commission data, 291 carriers have reported that they are engaged in Paging or Messaging Service. Of these, an estimated 289 have 1,500 or fewer employees, and two have more than 1,500 employees. Consequently, the Commission estimates that the majority of paging providers are small entities that may be affected by our action. An auction of Metropolitan Economic Area licenses commenced on February 24, 2000, and closed on March 2, 2000. Of the 2,499 licenses auctioned, 985 were sold. Fifty-seven companies claiming small business status won 440 licenses. A subsequent auction of MEA and Economic Area (“EA”) licenses was held in the year 2001. Of the 15,514 licenses auctioned, 5,323 were sold. One hundred thirty-two companies claiming small business status purchased 3,724 licenses. A third auction, consisting of 8,874 licenses in each of 175 EAs and 1,328 licenses in all but three of the 51 MEAs, was held in 2003. Seventy-seven bidders claiming small or very small business status won 2,093 licenses. A fourth auction, consisting of 9,603 lower and upper paging band licenses was held in the year 2010. Twenty-nine bidders claiming small or very small business status won 3,016 licenses.
56. 220 MHz Radio Service—Phase I Licensees. The 220 MHz service has both Phase I and Phase II licenses. Phase I licensing was conducted by lotteries in 1992 and 1993. There are approximately 1,515 such non-nationwide licensees and four nationwide licensees currently authorized to operate in the 220 MHz band. The Commission has not developed a small business size standard for small entities specifically applicable to such incumbent 220 MHz Phase I licensees. To estimate the number of such licensees that are small businesses, we apply the small business size standard under the SBA rules applicable to Wireless Telecommunications Carriers (except Satellite). Under this category, the SBA deems a wireless business to be small if it has 1,500 or fewer employees. The Commission estimates that nearly all such licensees are small businesses under the SBA's small business size standard that may be affected by rules adopted pursuant to the Order.
57. 220 MHz Radio Service—Phase II Licensees. The 220 MHz service has both Phase I and Phase II licenses. The Phase II 220 MHz service is subject to spectrum auctions. In the 220 MHz Third Report and Order, we adopted a small business size standard for “small” and “very small” businesses for purposes of determining their eligibility for special provisions such as bidding credits and installment payments. This small business size standard indicates that a “small business” is an entity that, together with its affiliates and controlling principals, has average gross revenues not exceeding $15 million for the preceding three years. A “very small business” is an entity that, together with its affiliates and controlling principals, has average gross revenues that do not exceed $3 million for the preceding three years. The SBA has approved these small business size standards. Auctions of Phase II licenses commenced on September 15, 1998, and closed on October 22, 1998. In the first auction, 908 licenses were auctioned in three different-sized geographic areas: Three nationwide licenses, 30 Regional Economic Area Group (EAG) Licenses, and 875 Economic Area (EA) Licenses. Of the 908 licenses auctioned, 693 were sold. Thirty-nine small businesses won licenses in the first 220 MHz auction. The second auction included 225 licenses: 216 EA licenses and 9 EAG licenses. Fourteen companies claiming small business status won 158 licenses.

5. Satellite Service Providers
58. Satellite Telecommunications Providers. Two economic census categories address the satellite industry. The first category has a small business size standard of $30 million or less in average annual receipts, under SBA rules. The second has a size standard of $30 million or less in annual receipts.
59. The category of Satellite Telecommunications “comprises establishments primarily engaged in providing telecommunications services to other establishments in the telecommunications and broadcasting industries by forwarding and receiving communications signals via a system of satellites or reselling satellite telecommunications.” For this category, Census Bureau data for 2007 show that there were a total of 570 firms that operated for the entire year. Of this total, 530 firms had annual receipts of under $30 million, and 40 firms had receipts of over $30 million. Consequently, we estimate that the majority of Satellite Telecommunications firms are small entities that might be affected by our action.
60. The second category of Other Telecommunications comprises, inter alia, “establishments primarily engaged in providing specialized telecommunications services, such as satellite tracking, communications telemetry, and radar station operation. This industry also includes establishments primarily engaged in providing satellite terminal stations and associated facilities connected with one or more terrestrial systems and capable of transmitting telecommunications to, and receiving telecommunications from, satellite systems.” For this category, Census Bureau data for 2007 show that there were a total of 1,274 firms that operated for the entire year. Of this total, 1,252 had annual receipts below $25 million per year. Consequently, we estimate that the majority of All Other Telecommunications firms are small entities that might be affected by our action.

6. Cable Service Providers
61. Because section 706 requires us to monitor the deployment of broadband using any technology, we anticipate that some broadband service providers may not provide telephone service. Accordingly, we describe below other types of firms that may provide broadband services, including cable companies, MDS providers, and utilities, among others.
62. Cable and Other Program Distributors. Since 2007, these services have been defined within the broad economic census category of Wired Telecommunications Carriers; that category is defined as follows: “This industry comprises establishments primarily engaged in operating and/or providing access to transmission facilities and infrastructure that they own and/or lease for the transmission of voice, data, text, sound, and video using wired telecommunications networks. Transmission facilities may be based on a single technology or a combination of technologies.” The SBA has developed a small business size standard for this category, which is: All such firms having 1,500 or fewer employees. To gauge small business prevalence for these cable services we must, however, use current census data that are based on the previous category of Cable and Other Program Distribution and its associated size standard; that size standard was: All such firms having $13.5 million or less in annual receipts. According to Census Bureau data for 2007, there were a total of 2,048 firms in this category that operated for the entire year. Of this total, 1,393 firms had annual receipts of under $10 million, and 655 firms had receipts of $10 million or more. Thus, the majority of these firms can be considered small.
63. Cable Companies and Systems. The Commission has also developed its own small business size standards, for the purpose of cable rate regulation. Under the Commission's rules, a “small cable company” is one serving 400,000 or fewer subscribers, nationwide. Industry data that there are currently 4,600 active cable systems in the United States. Of this total, all but nine cable operators are small under the 400,000 subscriber size standard. In addition, under the Commission's rules, a “small system” is a cable system serving 15,000 or fewer subscribers. Current Commission records show 4,945 cable systems nationwide. Of this total, 4,380 cable systems have less than 20,000 subscribers, and 565 systems have 20,000 or more subscribers, based on the same records. Thus, under this standard, we estimate that most cable systems are small entities.
64. Cable System Operators. The Communications Act of 1934, as amended, also contains a size standard for small cable system operators, which is “a cable operator that, directly or through an affiliate, serves in the aggregate fewer than 1 percent of all subscribers in the United States and is not affiliated with any entity or entities whose gross annual revenues in the aggregate exceed $250,000,000.” The Commission has determined that an operator serving fewer than 677,000 subscribers shall be deemed a small operator, if its annual revenues, when combined with the total annual revenues of all its affiliates, do not exceed $250 million in the aggregate. Based on available data, we find that all but ten incumbent cable operators are small entities under this size standard. We note that the Commission neither requests nor collects information on whether cable system operators are affiliated with entities whose gross annual revenues exceed $250 million, and therefore we are unable to estimate more accurately the number of cable system operators that would qualify as small under this size standard.
65. The open video system (OVS) framework was established in 1996, and is one of four statutorily recognized options for the provision of video programming services by local exchange carriers. The OVS framework provides opportunities for the distribution of video programming other than through cable systems. Because OVS operators provide subscription services, OVS falls within the SBA small business size standard covering cable services, which is “Wired Telecommunications Carriers.” The SBA has developed a small business size standard for this category, which is: All such firms having 1,500 or fewer employees. According to Census Bureau data for 2007, there were a total of 955 firms in this previous category that operated for the entire year. Of this total, 939 firms had employment of 999 or fewer employees, and 16 firms had employment of 1,000 employees or more. Thus, under this second size standard, most cable systems are small and may be affected by rules adopted pursuant to the Order. In addition, we note that the Commission has certified some OVS operators, with some now providing service. Broadband service providers (BSPs) are currently the only significant holders of OVS certifications or local OVS franchises. The Commission does not have financial or employment information regarding the entities authorized to provide OVS, some of which may not yet be operational. Thus, again, at least some of the OVS operators may qualify as small entities.

7. Electric Power Generators, Transmitters, and Distributors
66. Electric Power Generators, Transmitters, and Distributors. The Census Bureau defines an industry group comprised of “establishments, primarily engaged in generating, transmitting, and/or distributing electric power. Establishments in this industry group may perform one or more of the following activities: (1) Operate generation facilities that produce electric energy; (2) operate transmission systems that convey the electricity from the generation facility to the distribution system; and (3) operate distribution systems that convey electric power received from the generation facility or the transmission system to the final consumer.” The SBA has developed a small business size standard for firms in this category: “A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours.” Census Bureau data for 2007 show that there were 1,174 firms that operated for the entire year in this category. Of these firms, 50 had 1,000 employees or more, and 1,124 had fewer than 1,000 employees. Based on this data, a majority of these firms can be considered small.

D. Description of Projected Reporting, Recordkeeping, and Other Compliance Requirements for Small Entities
67. The Commission proposes to prohibit the use of non-disclosure agreements that restrict parties to a BDS tariff or commercial agreement from sharing the terms of such agreements with the Commission. In the event of detariffing, the Commission proposes on requiring price cap incumbent LECs to publicly disclose the rates, terms and conditions for services currently subject to tariffing requirements and seeks comment on this proposal.
68. In order to calculate a productivity X-factor, the Commission invites comment on whether we should require price cap LECs to submit their expense matrix data from 2005 to 2015 and, if so, whether should we require that these data be reported using the categories previously required under the Commission's rules and, if not, what categories should we specify, and whether the benefits from these data outweigh the burdens. The Commission asks whether we should require the price cap LECs to submit cost studies to help us determine business data services productivity growth and if so, what methodology should we specify for those costs studies. The Commission asks whether the benefits from relying on company-specific data from these cost studies, as opposed to economy-wide or industry-wide data, outweigh the burdens. Furthermore, the Commission proposes that if it adopts a new X-factor or otherwise requires adjustments to the price cap indices, price cap carriers would implement the associated rate decreases by submitting Tariff Review Plans (TRPs) and special access tariff revisions for all rate elements associated with special access and seeks comment on this proposal.
69. In the FNPRM, the Commission proposes to require providers of BDS subject to anchor pricing or benchmarking to publically disclose generally available terms and conditions. The Commission seeks comment on whether any requirements should be imposed to ensure compliance with our proposed rules and, if so, what form they should take. The Commission seeks comment on whether we should require compliance certification from providers as well as any other requirements we should consider and the costs and benefits.
70. The Commission also proposes a future periodic data collection that will allow the Commission to update periodically its identification of competitive and non-competitive markets. Beginning in 2018 ( i.e., year-end 2017 data), the Commission proposes collecting data every three years from incumbent LEC providers to update the Commission's competitive analysis and monitor the BDS marketplace. The Commission proposes essentially a paired-down version of the 2015 Collection. Specifically, the Commission proposes collecting data on locations with connections, fiber routes, and monthly billing information, revenues, requests for proposals, and wire center locations by regulatory type as well as new categories of information for collection, e.g., churn data, data on managed services, internal documents showing competitive pressure assessments and operational responses. Meanwhile, the Commission proposes omitting purchasers of BDS from the mandatory collection, instead proposing to hire a third-party to voluntarily survey purchaser customer classes.

E. Steps Taken To Minimize the Significant Economic Impact on Small Entities and Significant Alternatives Considered
71. The RFA requires an agency to describe any significant alternatives that it has considered in reaching its proposed approach, which may include (among others) the following four alternatives: (1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification, consolidation, or simplification of compliance or reporting requirements under the rule for small entities; (3) the use of performance, rather than design, standards; and (4) an exemption from coverage of the rule, or any part thereof, for small entities. We expect to consider all of these factors when we have received substantive comment from the public and potentially affected entities.
72. The Commission proposes to apply a Competitive Market Test to determine whether there is sufficient competition to constrain prices for BDS. The Commission proposes two alternatives for applying the Competitive Market Test, favoring one based on bright-line triggers—business density and the number of competitors—which will offer clearer rules and be administratively less burdensome for providers to present the case.
73. The Commission seeks comment on whether data from various sources proposed in a staff study provide a reasonable basis for calculating a productivity-based X factor but seeks comment on alternative sources of data that would more precisely calculate productivity increases in the provision of business data services. The Commission seeks comment on whether the additional precision associated with obtaining those data and using them to calculate a productivity-based X-factor outweigh the associated burdens. In particular, the Commission proposes calculating the X-factor using economy-wide and industry-wide data as opposed to company-specific data from cost studies, but asks whether the added precision from company-wide data outweighs the burdens.
74. For competitive areas, the Commission proposes removing significant regulatory burdens imposed on BDS providers. Specifically, the Commission proposes removing TDM-based BDS determined to be competitive under the Competitive Market Test from price cap regulation and apply a competitive regulatory framework—proposing a path to detariff TDM-based services while maintaining price caps on a detariffed basis. The Commission also seeks comment on a voluntary mechanism that would provide carriers with flexibility to adjust price cap rates for TDM-based services when replacement packet-based services are available.
75. The Commission recognizes that applying heightened regulation to services largely unregulated previously may impose burdens on providers and purchasers. The Commission, therefore, asks commenters whether there should be an implementation period to give providers sufficient time to bring markets into compliance with the applicable regulatory obligations, and seek comment on the length of any implementation period.
76. As noted above, in the FNPRM, the Commission seeks comment on whether we should extend the Tariff Investigation Order's prohibition on all-or-nothing provisions a general prohibition for business data services, including both tariffed offerings and commercial agreements and whether such a prohibition should be imposed in noncompetitive markets or in all markets. The Commission asks what additional management or tracking burdens would this impose on incumbent LECs and how significant would they be, whether such costs or burdens can be quantified, and how such administrative burdens compare with the benefits of added flexibility for customers in the business data services market. The Commission also asks about whether allowing customers to treat their purchases under one Ethernet commercial agreement as separate purchases impose any burdens on providers of business data services and whether the benefits of increase flexibility outweigh any such burdens.
77. In the FNPRM, the Commission proposes to periodically collect data from incumbent LEC providers going forward to update the Commission's analysis and monitor the marketplace for BDS. The Commission took several steps to minimize the economic impact on small providers and proposes exempting purchasers from the collection requirements. The Commission proposes narrowing the scope of the collection to minimize burdens on smaller providers while providing the Commission with the data necessary to periodically update its analysis. The Commission seeks comment on whether it is possible to exclude smaller competitive LECs from the collection without adversely affecting the Commission's analysis of the BDS market. The Commission is considering excluding competitive providers below a set threshold based on either locations with connections, number of customers, or revenues and ask commenters to suggest appropriate thresholds and to quantify the potential impact of any exclusion on the Commission's analysis. The Commission proposes a collection that is significantly less burdensome then the 2015 Collection, largely omitting questions on terms and conditions and narrative responses. The Commission proposes to omit purchasers, largely smaller entities, from the mandatory periodic collection, instead proposing to hire a third party to conduct a voluntary survey of customer classes. Furthermore, the proposed three year periodic collection period, as opposed to annual or quarterly, would minimize the burden on filers.
78. As SBA observed, changes in special access (BDS) prices may have an impact on small carriers including small competitive carriers. In the FNPRM, the Commission proposes modifying the existing regulatory regime applicable to BDS. Any such actions will accrue to the benefit of all carriers, including small competitive carriers, as it will ensure the availability of business data services at just and reasonable rates.

F. Federal Rules That May Duplicate, Overlap, or Conflict With the Proposed Rules
79. None.
Federal Communications Commission.
Marlene H. Dortch,

Secretary.
81
107
Friday, June 3, 2016
Proposed Rules
Part VI
Department of Commerce
National Oceanic and Atmospheric Administration
50 CFR Part 226

Endangered and Threatened Species; Critical Habitat for the Endangered Carolina and South Atlantic Distinct Population Segments of Atlantic Sturgeon; Proposed Rule
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
50 CFR Part 226
[Docket No. 150817733-6237-01]
RIN 0648-BF32
Endangered and Threatened Species; Critical Habitat for the Endangered Carolina and South Atlantic Distinct Population Segments of Atlantic Sturgeon

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

ACTION:
Proposed rule; request for comments.

SUMMARY:
We, the NMFS, propose to designate critical habitat for the endangered Carolina distinct population segment of the Atlantic sturgeon (Carolina DPS of Atlantic sturgeon) and the endangered South Atlantic distinct population segment of the Atlantic sturgeon (South Atlantic DPS of Atlantic sturgeon) pursuant to section 4 of the Endangered Species Act (ESA). Specific occupied areas proposed for designation as critical habitat for the Carolina DPS of Atlantic sturgeon contain approximately 1,997 kilometers (km; 1,241 miles) of aquatic habitat within the following rivers: Roanoke, Tar-Pamlico, Neuse, Cape Fear, Northeast Cape Fear, Waccamaw, Pee Dee, Black, Santee, North Santee, South Santee, and Cooper, and the following other water body: Bull Creek. In addition, we propose to designate unoccupied areas for the Carolina DPS totaling 383 km (238 miles) of aquatic habitat within the Cape Fear, Santee, Wateree, Congaree, and Broad Rivers, and within Lake Marion, Lake Moultrie, rediversion canal, and diversion canal. Specific occupied areas proposed for designation as critical habitat for the South Atlantic DPS of Atlantic sturgeon contain approximately 2,911 km (1,809 miles) of aquatic habitat within the Edisto, Combahee-Salkehatchie, Savannah, Ogeechee, Altamaha, Ocmulgee, Oconee, Satilla, and St. Marys Rivers. In addition, we propose to designate an unoccupied area within the Savannah River for the South Atlantic DPS that contains 33 km (21 miles) of aquatic habitat. We have considered positive and negative economic, national security, and other relevant impacts of the proposed critical habitat. We do not propose to exclude any particular area from the proposed critical habitat.
We are soliciting comments from the public on all aspects of the proposal, including our identification and consideration of impacts of the proposed action.

DATES:
Comments on this proposal must be received by September 1, 2016.
Public hearing meetings: We will hold three public hearings on this proposed rule from 7 to 9 p.m. in the following locations: Brunswick, Georgia on Monday, June 20; Charleston, South Carolina on Tuesday, June 21; and, Morehead City, North Carolina, Thursday, June 23 (see ADDRESSES ).

ADDRESSES:
You may submit comments, identified by the docket number NOAA-NMFS-2015-0157, by any of the following methods:
• Electronic Submissions: Submit all electronic public comments via the Federal eRulemaking Portal. Go to www.regulations.gov/#!docketDetail;D=NOAA-NMFS-2015-0157 click the “Comment Now” icon, complete the required fields, and enter or attach your comments.
• Mail: Assistant Regional Administrator, Protected Resources Division, NMFS, Southeast Regional Office, 263 13th Avenue South, St. Petersburg, FL 33701.
Instructions: You must submit comments by one of the above methods to ensure that we receive, document, and consider them. Comments sent by any other method, to any other address or individual, or received after the end of the comment period, may not be considered. All comments received are a part of the public record and will generally be posted to http://www.regulations.gov without change. All Personal Identifying Information (for example, name, address, etc.) voluntarily submitted by the commenter may be publicly accessible. Do not submit Confidential Business Information or otherwise sensitive or protected information.
NMFS will accept anonymous comments (enter “N/A” in the required fields if you wish to remain anonymous). Attachments to electronic comments will be accepted in Microsoft Word, Excel, WordPerfect, or Adobe PDF file formats only.
Public hearings: The June 20, 2016, public hearing will be held at the Georgia Department of Natural Resources, Coastal Regional Headquarters, 1 Conservation Way, Brunswick, Georgia 31520. The June 21, 2016, public hearing will be held at the South Carolina Department of Natural Resources, Marine Resources Office, 217 Ft. Johnson Road, Charleston, SC 29412. The June 23, 2016, public hearing will be held at the Crystal Coast Civic Center, 2nd Floor, 3505 Arendell St, Morehead City, NC 28557. People needing reasonable accommodations in order to attend and participate or who have questions about the public hearings should contact Andrew Herndon, NMFS, Southeast Regional Office (SERO), as soon as possible (see FOR FURTHER INFORMATION CONTACT ).

FOR FURTHER INFORMATION CONTACT:
Jason Rueter, NMFS, Southeast Regional Office, 727-824-5312, Jason.Rueter@noaa.gov; Andrew Herndon, Southeast Regional Office, 727-824-5312, Andrew.Herndon@noaa.gov; Lisa Manning, NMFS, Office of Protected Resources, 301-427-8466, Lisa.Manning@noaa.gov.

SUPPLEMENTARY INFORMATION:
In accordance with section 4(b)(2) of the ESA and our implementing regulations (50 CFR 424.12), this proposed rule is based on the best scientific information available concerning the range, biology, habitat, threats to the habitat, and conservation objectives for the Carolina and South Atlantic DPSs of Atlantic sturgeon. We have reviewed the information ( e.g., provided in reports, peer-reviewed literature, and technical documents) and have used it to identify physical features essential to the conservation of each DPS, the specific areas within the occupied areas that contain the essential physical features that may require special management considerations or protections, unoccupied areas that are essential to the DPSs' conservation, the federal activities that may impact the essential features or areas, and the potential impacts of designating critical habitat for each DPS. The economic, national security, and other relevant impacts of the proposed critical habitat designations for each DPS are described in the draft document titled, Impact Analysis of Critical Habitat Designation for the Carolina and South Atlantic Distinct Population Segments of Atlantic Sturgeon ( Acipenser oxyrinchus oxyrinchus ). This supporting document is available at http://sero.nmfs.noaa.gov/protected_resources/sturgeon/index.html or upon request (see ADDRESSES ).

Background
In 2012, we listed five DPSs of Atlantic sturgeon under the ESA: four were listed as endangered and one as threatened (77 FR 5880 and 5914; February 6, 2012). Two DPSs of Atlantic sturgeon, both endangered, occur within the southeastern United States (Carolina DPS and the South Atlantic DPS; 77 FR 5914; February 6, 2012); and three DPSs of Atlantic sturgeon (the endangered New York Bight DPS and Chesapeake Bay DPS, and the threatened Gulf of Maine DPS; 77 FR 5880, February 6, 2012) occur in the northeast United States. On March 18, 2014, two non-governmental organizations filed a lawsuit alleging NMFS had violated the ESA by failing to issue proposed and final rules designating critical habitat for Atlantic sturgeon DPSs. Pursuant to a court-ordered settlement agreement, as modified, NMFS agreed to submit proposed rules designating critical habitat for all distinct population segments of Atlantic sturgeon to the Federal Register by May 30, 2016. This rule proposing to designate critical habitat for the Carolina and South Atlantic DPSs of Atlantic sturgeon is complemented by a concurrent rule proposing to designate critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs of Atlantic sturgeon.

Atlantic Sturgeon Natural History and Status
There are two subspecies of Atlantic sturgeon—the Gulf sturgeon ( Acipenser oxyrinchus desotoi ) and the Atlantic sturgeon ( Acipenser oxyrinchus oxyrinchus ). Historically, the Gulf sturgeon occurred from the Mississippi River east to Tampa Bay in Florida. Its present range extends from Lake Pontchartrain and the Pearl River system in Louisiana and Mississippi east to the Suwannee River in Florida. The Gulf sturgeon was listed as threatened under the ESA in 1991. This proposed rule addresses the Atlantic sturgeon ( Acipenser oxyrinchus oxyrinchus ), which is distributed along the eastern coast of North America. Historically, sightings of Atlantic sturgeon have been reported from Hamilton Inlet, Labrador, Canada, south to the St. Johns River, Florida. Reported occurrences south of the St. Johns River, Florida, have been rare but have increased recently with the evolution of acoustic telemetry coupled with increased receiver arrays.
Although there is considerable variability among species, all sturgeon species (order Acipenseriformes ) have some common life history traits. They all: (1) Occur within the Northern Hemisphere; (2) spawn in freshwater over hard bottom substrates; (3) generally do not spawn annually; (4) are benthic foragers; (5) mature relatively late and are relatively long lived; and, (6) are relatively sensitive to low dissolved oxygen levels (Dees, 1961; Sulak and Clugston, 1999; Billard and Lecointre, 2001; Secor and Niklitschek, 2002; Pikitch et al., 2005).
Atlantic sturgeon have all of the above traits. They occur along the eastern coast of North America from Hamilton Inlet, Labrador, Canada to Cape Canaveral, Florida, USA (Bigelow and Welsh, 1924; Dees, 1961; Vladykov and Greeley, 1963; NMFS and USFWS, 2007; T. Savoy, CT DEEP, pers. comm.). Atlantic sturgeon are a long-lived, late-maturing, estuarine-dependent, anadromous species with a maximum lifespan of up to 60 years, although the typical lifespan is probably much shorter (Sulak and Randall, 2002; Balazik et al., 2010). Atlantic sturgeon reach lengths up to 14 feet (ft) (4.27 meters [m]), and weigh over 800 pounds (363 kilograms). Many datasets demonstrate clinal variation in vital parameters of Atlantic sturgeon populations, with faster growth and earlier age at maturation in more southern systems. Atlantic sturgeon mature between the ages of 5 and 19 years in South Carolina (Smith et al., 1982), between 11 and 21 years in the Hudson River (Young et al., 1988), and between 22 and 34 years in the St. Lawrence River (Scott and Crossman, 1973). Atlantic sturgeon likely do not spawn every year. Multiple studies have shown that spawning intervals range from 1 to 5 years for males (Smith, 1985; Collins et al., 2000; Caron et al. 2002) and 2 to 5 years for females (Vladykov and Greeley, 1963; Van Eenennaam et al., 1996; Stevenson and Secor, 1999). Fecundity of Atlantic sturgeon has been correlated with age and body size, with egg production ranging from 400,000 to 8 million eggs per year (Smith et al., 1982; Van Eenennaam and Doroshov, 1998; Dadswell, 2006). The average age at which 50 percent of maximum lifetime egg production is achieved is estimated to be 29 years, approximately 3 to 10 times longer than for other bony fish species examined (Boreman, 1997).
Analysis of stomach contents for adults, subadults ( i.e., sexually immature Atlantic sturgeon that have emigrated from the natal estuary), and juveniles ( i.e., sexually immature Atlantic sturgeon that have not yet emigrated from the natal estuary) confirms that Atlantic sturgeon are benthic foragers (Ryder, 1888; Bigelow and Schroeder, 1953; Johnson et al., 1997; Secor et al., 2000; NMFS and USFWS, 2007; Guilbard et al., 2007; Hatin et al., 2007; Savoy, 2007; Dzaugis, 2013; McLean et al., 2013).
An anadromous species, Atlantic sturgeon spawn in freshwater of rivers that flow into a coastal estuary. Spawning adults migrate upriver in the spring, typically during February and March in southern systems, April and May in mid-Atlantic systems, and May and July in Canadian systems (Murawski and Pacheco, 1977; Smith, 1985; Bain, 1997; Smith and Clugston, 1997; Caron et al., 2002). A fall spawning migration has been hypothesized for many years (Rogers and Weber, 1995; Weber and Jennings, 1996; Moser et al., 1998) and was recently verified in the Roanoke River, North Carolina, and the Altamaha River, Georgia (Smith et. al., 2015; Ingram and Peterson in Post et al., 2014). There is also a growing body of evidence that some Atlantic sturgeon river populations have two spawning seasons comprised of different spawning adults (Darden in Post et al., 2014; Balazik and Musick, 2015).
Spawning typically occurs in flowing water upriver of the salt front of estuaries and below the fall line of large rivers (Borodin, 1925; Leland, 1968; Scott and Crossman, 1973; Crance, 1987; Bain et al., 2000). The fall line is the boundary between an upland region of continental bedrock and an alluvial coastal plain, sometimes characterized by waterfalls or rapids. Spawning sites are well-oxygenated areas with flowing water ranging in temperature from 13 °Celsius (C; 55 °F (F)) to 26 °C (79 °F), and hard bottom substrate such as cobble, coarse sand, hard clay, and bedrock (Ryder, 1888; Dees, 1961; Vladykov and Greeley, 1963; Scott and Crossman, 1973; Gilbert, 1989; Smith and Clugston, 1997; Bain et al. 2000; Collins et al., 2000; Balazik et al. 2012; Hager et al. 2014). Depth at which fish spawn and water depth leading to spawning sites may be highly variable. Atlantic sturgeon in spawning condition have been tracked and captured at depths up to 27m (Borodin 1925; Dees 1961; Hatin et al., 2002; Balazik et al., 2012; Hager et al., 2014).
Within minutes of being fertilized, the eggs become sticky and adhere to the substrate for the relatively short and temperature-dependent period of larval development (Ryder, 1888; Vladykov and Greeley, 1963; Murawski and Pacheco, 1977; Smith et al., 1980; Van den Avyle, 1984; Mohler, 2003). Hatching occurs approximately 94 to 140 hours after egg deposition at temperatures of 68.0 °F to 64.4 °F (20 to 18 °C), respectively. The newly emerged larvae assume a demersal existence (Smith et al., 1980). The yolk sac larval stage is completed in about 8 to 12 days, during which time the larvae move downstream to rearing grounds (Kynard and Horgan, 2002). During the first half of their migration downstream, movement occurs only at night. During the day, larvae use benthic structure ( e.g., gravel matrix) as refuge (Kynard and Horgan, 2002). During the latter half of migration, when larvae are more fully developed, movement to rearing grounds occurs during both the day and night.
Larval Atlantic sturgeon ( i.e., less than 4 weeks old, with total lengths (TL) less than 30 mm; Van Eenennaam et al., 1996) are assumed to inhabit the same areas where they were spawned and live at or near the bottom (Ryder, 1888; Smith et al., 1980; Bain et al., 2000; Kynard and Horgan, 2002; Greene et al., 2009). The best available information for behavior of larval Atlantic sturgeon is described from hatchery studies. Upon hatching, larvae are nourished by the yolk sac, are mostly pelagic ( e.g., exhibit a “swim-up and drift-down” behavior in hatchery tanks; Mohler, 2003), and move away from light ( i.e., negative photo-taxis; Kynard and Horgan, 2002; Mohler, 2003). Within days, larvae exhibit more benthic behavior until the yolk sac is absorbed at about 8 to 10 days post-hatching (Kynard and Horgan, 2002; Mohler, 2003). Post-yolk sac larvae occur in the water column but feed at the bottom of the water column (Mohler, 2003; Richardson et al., 2007).
The next phase of development, referred to as the juvenile stage, lasts months to years in brackish waters of the natal estuary (Holland and Yelverton, 1973; Dovel and Berggen, 1983; Waldman et al., 1996; Shirey et al., 1997; Collins et al., 2000; Secor et al., 2000; Dadswell, 2006; Hatin et al., 2007; NMFS and USFWS, 2007; Calvo et al., 2010; Schueller and Peterson, 2010). Juveniles occur in oligohaline waters (salinity of 0.5 to 5 parts per thousand [ppt]) and mesohaline waters (salinity of 5 to 18 ppt) of the natal estuary during growth and development. They will eventually move into polyhaline waters (salinity of 18-30 ppt) before emigrating to the marine environment. Larger, presumably older, juveniles occur across a broader salinity range than smaller, presumably younger, juveniles (Bain, 1997; Shirey et al., 1997; Haley, 1999; Bain et al., 2000; Collins et al., 2000; Secor et al., 2000; Hatin et al., 2007; McCord et al., 2007; Munro et al., 2007; Sweka et al., 2007; Calvo et al., 2010).
The distribution of Atlantic sturgeon juveniles in the natal estuary is a function of physiological development and habitat selection based on water quality factors of temperature, salinity, and dissolved oxygen (DO), which are inter-related environmental variables. In laboratory studies with salinities of 8 to 15 ppt and temperatures of 12 °C and 20 °C, juveniles less than a year old (also known as young-of-year [YOY]) had reduced growth at 40 percent dissolved oxygen saturation, grew best at 70 percent dissolved oxygen saturation, and selected conditions that supported growth (Niklitschek and Secor, 2009 I; Niklitschek and Secor, 2009 II). Similar results were obtained for age-1 juveniles ( i.e., greater than 1 year old and less than 2 years old), which have been shown to tolerate salinities of 33 ppt ( e.g., a salinity level associated with seawater), but grow faster in lower salinity waters (Niklitschek and Secor, 2009; Allen et al., 2014). The best growth for both age groups occurred at DO concentrations greater than 6.5 milligrams per liter (mg/L). While specific DO concentrations at temperatures considered stressful for Atlantic sturgeon are not available, instantaneous minimum DO concentrations of 4.3 mg/L protect survival of shortnose sturgeon at temperatures greater than 29 °C (EPA, 2003). However, data from Secor and Niklitschek (2001) show that shortnose sturgeon are more tolerant of higher temperatures than Atlantic sturgeon, and the “high temperature” for Atlantic sturgeon is actually considered 26 °C (Secor and Gunderson, 1998).
Once suitably developed, Atlantic sturgeon leave the natal estuary and enter marine waters ( i.e., waters with salinity greater than 30 ppt) which marks the beginning of the subadult life stage. In the marine environment, subadults mix with adults and subadults from other river systems (Bowen and Avise, 1990; Wirgin et al., 2012; Waldman et al., 2013; O'Leary et al., 2014). Atlantic sturgeon travel long distances in marine waters, aggregate in both ocean and estuarine areas at certain times of the year, and exhibit seasonal coastal movements in the spring and fall (Vladykov and Greeley, 1963; Oliver et al., 2013).
The exact spawning locations for Carolina and South Atlantic DPS Atlantic sturgeon are unknown but inferred based on the location of freshwater, hard substrate, water depth, tracking of adults to upriver locations and the behavior of adults at those locations, historical accounts of where the caviar fishery occurred, capture of young-of-year and, in limited cases, capture of larvae and eggs. Spawning sites at multiple locations within the tidal-affected river likely help to ensure successful spawning given annual changes in the location of the salt wedge.

Critical Habitat Identification and Designation
Critical habitat represents the habitat essential for the species' recovery and provides for the conservation of listed species in several ways (78 FR 53058, August 28, 2013). For example, specifying the geographic location of critical habitat facilitates implementation of Section 7(a)(1) of the ESA by identifying areas where Federal agencies can focus their conservation programs and use their authorities to further the purposes of the ESA. Designating critical habitat also provides a significant regulatory protection by ensuring that the Federal Government considers the effects of its actions in accordance with Section 7(a)(2) of the ESA and avoids or modifies those actions that are likely to destroy or adversely modify critical habitat. This requirement is in addition to the Section 7 requirement that Federal agencies ensure that their actions are not likely to jeopardize the continued existence of ESA-listed species. Critical habitat requirements do not apply to citizens engaged in activities on private land that do not involve a Federal agency. However, designating critical habitat can help focus the efforts of other conservation partners ( e.g., State and local governments, individuals and nongovernmental organizations).
Section 3(5)(A) of the ESA defines critical habitat as (i) the specific areas within the geographical area occupied by the species, at the time it is listed in accordance with the provisions of Section 4 of the ESA, on which are found those physical or biological features (I) essential to the conservation of the species and (II) which may require special management considerations or protections; and (ii) specific areas outside the geographical area occupied by the species at the time it is listed in accordance with the provisions of Section 4 of the ESA, upon a determination by the Secretary that such areas are essential for the conservation of the species (16 U.S.C. 1532[5][A]). Conservation is defined in Section 3 of the ESA as “to use and the use of all methods and procedures which are necessary to bring any endangered species or threatened species to the point at which the measures provided pursuant to this chapter are no longer necessary” (16 U.S.C. 1532[3]). Therefore, critical habitat is the habitat essential for the species' recovery. However, Section 3(5)(C) of the ESA clarifies that except in those circumstances determined by the Secretary, critical habitat shall not include the entire geographical area which can be occupied by the threatened or endangered species.
To identify and designate critical habitat, we considered information on the distribution of Atlantic sturgeon, the major life stages, habitat requirements of those life stages, and conservation objectives that can be supported by identifiable physical or biological features (hereafter also referred to as “PBFs” or “essential features”). In the final rule listing the Carolina and South Atlantic DPSs of Atlantic sturgeon (77 FR 5978, February 6, 2012), habitat curtailment and alteration, bycatch in commercial fisheries, and inadequacy of existing regulatory mechanisms were found to be the threats contributing to the endangered status of both DPSs. The Carolina and South Atlantic DPSs were found to be at 3% and 6% of their historical abundances, respectively, due to these threats. Therefore, we evaluated physical and biological features of the marine, estuarine, and riverine habitats of Atlantic sturgeon to determine what features are essential to the conservation of each DPS.
Accordingly, our step-wise approach for identifying potential critical habitat areas for the Carolina and South Atlantic DPSs was to determine: the geographical area occupied by each DPS at the time of listing; the physical or biological features essential to the conservation of the DPSs; whether those features require special management considerations or protection; the specific areas of the occupied geographical area where these features occur; and, whether any unoccupied areas are essential to the conservation of either DPS.

Geographical Area Occupied by the Species
“Geographical area occupied” in the definition of critical habitat is interpreted to mean the entire range of the species at the time it was listed, inclusive of all areas they use and move through seasonally (81 FR 7413; February 11, 2016). The marine ranges of the Carolina and South Atlantic DPSs of Atlantic sturgeon extend from the Hamilton Inlet, Labrador, Canada, to Cape Canaveral, Florida (77 FR 5880, February 6, 2012). We did not consider geographical areas within Canadian jurisdiction ( e.g., Minas Basin, Bay of Fundy), because we cannot designate critical habitat areas outside of U.S. jurisdiction (50 CFR 424.12(g)).
The listing rule identified the known spawning rivers for each of the Atlantic sturgeon DPSs but did not describe the in-river ranges for the DPSs. The river ranges of each DPS consist of all areas downstream of either the fall line or the first obstacle to upstream migration ( e.g., the lowest hydropower dam without fish passage for sturgeon) on each river within the range of the DPS. We identified the Carolina DPS freshwater range as occurring in the watersheds from the Roanoke River southward along North Carolina and South Carolina coastal areas to the Cooper River, South Carolina. The South Atlantic DPS freshwater range occurs from the Ashepoo-Combahee-Edisto (ACE) Basin in South Carolina to the St. Johns River, Florida.

Physical or Biological Features Essential for Conservation That May Require Special Management or Protection
Within the geographical area occupied, critical habitat consists of specific areas on which are found those PBFs essential to the conservation of the species and that may require special management considerations or protection. PBFs are defined as the features that support the life-history needs of the species, including water characteristics, soil type, geological features, sites, prey, vegetation, symbiotic species, or other features. A feature may be a single habitat characteristic, or a more complex combination of habitat characteristics. Features may include habitat characteristics that support ephemeral or dynamic habitat conditions. Features may also be expressed in terms relating to principles of conservation biology, such as patch size, distribution distances, and connectivity. 50 CFR 424.02.
Within the area occupied by Atlantic sturgeon, we considered the various types of habitat utilized by the DPSs for various life functions. Atlantic sturgeon spend the majority of their adult lives in offshore marine waters. They are known to travel extensively up and down the East Coast. As summarized in a number of summary documents including the Atlantic Sturgeon Status Review (NMFS and USFWS, 2007) and the Atlantic States Marine Fisheries Commission's (ASMFC) review of Atlantic coast diadromous fish habitat (Green et al., 2009), Atlantic sturgeon are benthic foragers and prey upon a variety of species in marine and estuarine environments (Bigelow and Schroeder, 1953; Scott and Crossman, 1973; Johnson et al., 1997; Guilbard et al., 2007; Savoy, 2007; Dzaugis, 2013; McLean et al., 2013). In the ocean, Atlantic sturgeon typically occur in waters less than 50 m deep, travel long distances, exhibit seasonal coastal movements, and aggregate in estuarine and ocean waters at certain times of the year (Vladykov and Greeley, 1963; Holland and Yelverton 1973; Dovel and Berggren, 1983; Dadswell et al., 1984; Gilbert, 1989; Johnson et al., 1997; Rochard et al., 1997; Kynard et al., 2000; Savoy and Pacileo, 2003; Eyler et al., 2004; Stein et al., 2004; Dadswell, 2006; Eyler, 2006; Laney et al., 2007; NMFS and USFWS, 2007; Dunton et al., 2010; Erickson et al., 2011; Dunton et al., 2012; Oliver et al., 2013; Wirgin et al., 2015). Several winter congregations of Atlantic sturgeon in the marine environment are known to occur, though the exact location and importance of those areas in the southeast is not known, nor whether Atlantic sturgeon are drawn to particular areas based on physical or biological features of the habitat. While we can identify general movement patterns and behavior in the marine environment ( e.g., aggregating behavior), due to the paucity of data on the DPSs' offshore needs and specific habitat utilization, we could not at this time identify PBFs essential to conservation in the marine environment for the Carolina or South Atlantic DPSs.
Atlantic sturgeon utilize estuarine areas for foraging, growth, and movement. Atlantic sturgeon subadults and adults in non-spawning condition use estuarine waters seasonally, presumably for foraging opportunities, although evidence in the form of stomach content collection and analysis is limited (Savoy and Pacileo, 2007; Dzaugis, 2013). We considered all studies that have collected Atlantic sturgeon stomach contents. All of the prey species identified are indicative of benthic foraging, but different types of prey were consumed and different substrates were identified for the areas where Atlantic sturgeon were foraging (Bigelow and Schroeder, 1953; Johnson et al., 1997; NMFS and USFWS, 2007; Guilbard et al., 2007; Savoy, 2007; Dzaugis, 2013; McLean et al., 2013). Adding to our uncertainty of the essential features that support successful foraging for growth and survival of subadults and adults, Atlantic sturgeon move between estuarine environments in the spring through fall and can occur in estuarine environments during the winter as well (Savoy and Pacileo, 2003; Simpson, 2008; Collins et al., 2000; Balazik et al., 2012). Subadult Atlantic sturgeon spawned in one riverine system may utilize multiple estuaries for foraging and growth, including those not directly connected to their natal river. The benthic invertebrates that comprise the diet of Atlantic sturgeon are found in soft substrates that are common and widespread in most estuaries. Limited data are available to differentiate areas of preferred prey items or higher prey abundance within or across estuaries. Due to the paucity of data on specific habitat or resource utilization, we could not at this time identify any specific PBFs essential for the conservation of the Carolina and South Atlantic DPSs that support adult and subadult foraging in estuarine or marine environments.
Atlantic sturgeon spawning behavior and early life history have been extensively studied and are fairly well understood, though the exact location of spawning sites on many rivers (particularly in the Southeast) is not known, or can change from time to time as water depth and substrate availability changes. However, there is substantial information in the scientific literature indicating the physical characteristics of Atlantic sturgeon spawning and early life history habitat. Therefore, to evaluate potential critical habitat, we focused on identifying the physical or biological features that support Atlantic sturgeon reproduction and survival of early life stages.
The scientific literature indicates that Atlantic sturgeon spawning occurs well upstream, at or near the fall line of rivers, over hard substrate consisting of rock, pebbles, gravel, cobble, limestone, or boulders (Gilbert, 1989; Smith and Clugston, 1997). Hard substrate is required so that highly adhesive Atlantic sturgeon eggs have a surface to adhere to during their initial development and young fry can utilize the interstitial spaces between rocks, pebbles, cobble, etc., to hide from predators during downstream movement and maturation (Gilbert, 1989; Smith and Clugston, 1997).
Very low salinity ( i.e., 0.0-0.5 ppt) is another important feature of Atlantic sturgeon spawning habitat. Exposure to even low levels of salinity can kill Atlantic sturgeon during their first few weeks of life, thus their downstream movement is limited until they can endure brackish waters (Bain et al., 2000). Shortnose sturgeon tend to spawn 200-300 km upriver, preventing the youngest life stages from salt exposure too early in their development (Parker and Kynard, 2005; Kynard, 1997). Parker and Kynard (2005) also noted that long larval/early juvenile downstream movement is common in both shortnose sturgeon from the Savannah River and Gulf sturgeon (a sub-species of Atlantic sturgeon), and that this may be a widespread adaptation of sturgeon inhabiting river systems in the southern United States. Due to their similar life history, Atlantic sturgeon most likely adapted a similar spawning strategy. Therefore, it is essential that the spawning area has low salinity, and that the spawning location is far enough upstream to allow newly-spawned Atlantic sturgeon to develop and mature on their downstream movement before encountering saline water. During their downstream movement, it is important for developing fish to forage in areas of soft substrate and to encounter transitional salinity zones to allow physiological adaptations to higher salinity waters.
Minimum water depths for Atlantic sturgeon spawning are necessary to: (1) Allow adult fish to access spawning substrate, (2) adequately hydrate and aerate newly deposited eggs, and (3) facilitate successful development and downstream movement of newly spawned Atlantic sturgeon. However, water depth at these important spawning areas in the Southeast can be dynamic and portions of rivers may be dry or have little water at times due to natural seasonal river fluctuations, temporary drought conditions, and/or regulation by manmade structures such as dams; thus, these sites require protection to provide consistent services for sturgeon. The scientific literature indicates that Atlantic sturgeon spawn in water depths from 3-27 m (9.8-88.6 ft) (Borodin, 1925; Leland, 1968; Scott and Crossman, 1973; Crance, 1987; Bain et al., 2000). However, much of this information is derived from studies of Atlantic sturgeon in northern United States and Canadian river systems. Atlantic sturgeon in the Southeast are likely spawning in much shallower water depths based on repeated observations by biologists of sturgeon with lacerations on their undersides from moving into extremely shallow water to spawn on hard substrate. In the Southeast, water depths no less than 1.2 m (4 ft) are deep enough to accommodate the body depth and spawning behavior of adult Atlantic sturgeon.
We considered fluid dynamic features as another potential essential feature of Atlantic sturgeon spawning critical habitat. The scientific literature provides information on the importance of appropriate water velocity within Atlantic sturgeon spawning habitat and provides optimal flows for some rivers. Atlantic sturgeon spawn directly on top of gravel in fast flowing sections often containing eddies or other current breaks. Eddies promote position holding between spawning individuals, trap gametes facilitating fertilization, and diminish the probability of egg dislocation by currents—facilitating immediate adhesion of eggs to the gravel substrate (Sulak and Clugston, 1999). However, velocity data are lacking for many rivers, and where data are available, the wide fluctuations in velocity rates on a daily, monthly, seasonal, and annual basis make it difficult to identify a range of water velocity necessary for the conservation of the species. However, we do know that water flow must be continuous.
Adult Atlantic sturgeon must be able to safely and efficiently move from downstream areas into upstream spawning habitats in order to successfully spawn. In addition, larvae and juvenile Atlantic sturgeon must be able to safely and efficiently travel from the upstream spawning areas downstream to nursery and foraging habitat. Therefore, an essential feature for Atlantic sturgeon spawning is unobstructed migratory pathways for safe movement of adults to and from upstream spawning areas as well as providing safe movement for the larvae and juveniles moving downstream. An unobstructed migratory pathway means an unobstructed river or a dammed river that still allows for passage.
Water quality can be a critically limiting factor to Atlantic sturgeon in the shallow, warm, poorly oxygenated rivers of the southeast United States. Conditions in these river systems can change rapidly, particularly in rivers managed for hydropower production, and conditions can quickly become suboptimal or lethal for sturgeon. We considered essential water quality features that support movement and spawning of adults and growth and development of juvenile Atlantic sturgeon. The distribution of Atlantic sturgeon juveniles in the natal estuary is a function of physiological development and habitat selection based on water quality factors of temperature, salinity, and dissolved oxygen, which are inter-related environmental variables. In laboratory studies with salinities of 8 to 15 parts per thousand and temperatures of 12 °C and 20 °C, juveniles less than a year old (YOY) had reduced growth at 40 percent dissolved oxygen saturation, grew best at 70 percent dissolved oxygen saturation, and selected conditions that supported growth (Niklitschek and Secor, 2009 I; Niklitschek and Secor, 2009 II). Results obtained for age-1 juveniles ( i.e., greater than 1 year old and less than 2 years old) indicated that they can tolerate salinities of 33 parts per thousand ( i.e., a salinity level associated with seawater), but grow faster in lower salinity waters (Niklitschek and Secor, 2009; Allen et al., 2014). The best growth for both age groups occurred at dissolved oxygen concentrations greater than 6.5 mg/L. While specific dissolved concentrations at temperatures considered stressful for Atlantic sturgeon are not available, instantaneous minimum concentrations of 4.3 mg/L protect survival of shortnose sturgeon at temperatures greater than 29 °C (EPA, 2003). However, data from Secor and Niklitschek (2001) show that shortnose sturgeon are more tolerant of higher temperatures than Atlantic sturgeon, thus the “stressful temperature” for Atlantic sturgeon is considered 26 °C (Secor and Gunderson, 1998).
In summary, within the area occupied by Atlantic sturgeon, we considered the various types of habitat utilized by the species for various life functions. We determined that Atlantic sturgeon spend the majority of their adult lives in offshore marine waters where they are known to travel extensively up and down the East Coast. However, we could not identify any PBFs in marine waters essential for the conservation of the species. We also determined Atlantic sturgeon utilize estuarine areas for foraging, growth, and movement. The ability of subadults to find and access food is necessary for continued survival, growth, and physiological development to the adult life stage. Likewise, given that Atlantic sturgeon mature late and do not necessarily spawn annually, increased adult survival would improve the chances that adult Atlantic sturgeon spawn more than once. Therefore, we determined a conservation objective for the Carolina and South Atlantic DPSs is to increase the abundance of each DPS by facilitating increased survival of all life stages. After examining the information available on spawning and early life history behavior and habitat, we also concluded that facilitating adult reproduction and juvenile and subadult recruitment into the adult population are other conservation objectives for the Carolina and South Atlantic DPSs of Atlantic sturgeon. We could not identify any specific PBFs essential for the conservation of the species that support adult and subadult foraging in estuarine or marine environments. We determined that protecting spawning areas, juvenile development habitat, the migratory corridors that allow adults to reach the spawning areas and newly spawned sturgeon to make a safe downstream migration, and water quality to support all life stages, will facilitate meeting the conservation objectives discussed above.
Given the biological needs and tolerances, and environmental conditions for Atlantic sturgeon in southeast rivers as summarized above, and the habitat-based conservation objectives, the physical features essential for conservation are:
• Suitable hard bottom substrate ( e.g., rock, cobble, gravel, limestone, boulder, etc.) in low salinity waters ( i.e., 0.0-0.5 ppt range) for settlement of fertilized eggs and refuge, growth, and development of early life stages;
• Transitional salinity zones inclusive of waters with a gradual downstream gradient of 0.5-30 ppt and soft substrate ( e.g., sand, mud) downstream of spawning sites for juvenile foraging and physiological development;
• Water of appropriate depth and absent physical barriers to passage ( e.g., locks, dams, reservoirs, gear, etc.) between the river mouth and spawning sites necessary to support: (1) Unimpeded movement of adults to and from spawning sites; (2) seasonal and physiologically dependent movement of juvenile Atlantic sturgeon to appropriate salinity zones within the river estuary; and (3) staging, resting, or holding of subadults and spawning condition adults. Water depths in main river channels must be deep enough to ensure continuous flow in the main channel at all times when any sturgeon life stage would be in the river. Water depths of at least 1.2 m are generally deep enough to facilitate effective adult migration and spawning behavior.
• Water quality conditions, especially in the bottom meter of the water column, with temperature and oxygen values that support: (1) Spawning; (2) annual and inter-annual adult, subadult, larval, and juvenile survival; and (3) larval, juvenile, and subadult growth, development, and recruitment. Appropriate temperature and oxygen values will vary interdependently, and depending on salinity in a particular habitat. For example, 6.0 mg/L D.O. for juvenile rearing habitat is considered optimal, whereas D.O. less than 5.0 mg/L for longer than 30 days is considered suboptimal when water temperature is greater than 25 °C. In temperatures greater than 26 °C, D.O. greater than 4.3 mg/L is needed to protect survival and growth. Temperatures of 13 °C to 26 °C for spawning habitat are considered optimal.

Need for Special Management Considerations or Protection
We concluded that each of the essential features defined above may require special management considerations or protection. Barriers ( e.g., dams, tidal turbines) to generate power or control water flow in rivers used by Atlantic sturgeon can damage or destroy bottom habitat needed for spawning and rearing of juveniles, restrict movement of adults to and from spawning grounds, prevent juveniles from accessing the full range of salinity exposure in the natal estuary, and alter water quality parameters, including water depth, temperature and dissolved oxygen, to the detriment of sturgeon reproduction, growth, and survival. Water withdrawals can similarly adversely impact water quality for Atlantic sturgeon spawning, recruitment, and development. Land development and commercial and recreational activities on a river can contribute to sediment deposition that affects water quality necessary for successful spawning and recruitment. A build-up of fine sediments may, for example, reduce the suitability of hard spawning substrate for Atlantic sturgeon egg adherence and reduce the interstitial spaces used by larvae for refuge from predators. Dredging to remove sediment build-up, to deepen harbors and facilitate vessel traffic, or to mine construction materials, may remove or alter hard substrate that is necessary for egg adherence and as refuge for larvae or soft substrate needed for juvenile foraging, and may change the water depth resulting in shifts in the salt wedge within the estuary or change other characteristics of the water quality ( e.g., temperature, dissolved oxygen) necessary for the developing eggs, larvae, and juveniles.
The features essential for successful Atlantic sturgeon reproduction and recruitment may also require special management considerations or protection as a result of global climate change. Conditions in Southeast rivers used by sturgeon already threaten the species' survival and recovery due to exceedances of temperature tolerances and the sensitivity of sturgeon to low dissolved oxygen levels; these impacts will worsen as a result of global climate change and predicted warming of the southeast region. Many communities and commercial facilities withdraw water from the rivers containing the features essential to Atlantic sturgeon reproduction. Water withdrawals during drought events can affect flows, depths, and the position of the salt wedge, further impacting the water flow necessary for successful sturgeon reproduction and affect dissolved oxygen levels. Attempts by communities to control water during floods ( e.g., spilling water from dams upriver of Atlantic sturgeon spawning and rearing habitat) can similarly alter flows to the point of dislodging fertilized eggs, washing early life stages downstream into more saline habitat before being developmentally ready, and create barriers ( e.g., from debris) to upstream and downstream passage of adults and juveniles. We therefore conclude that the physical features essential to the conservation of the Carolina and South Atlantic DPSs may require special management considerations or protections.

Specific Areas Containing the Essential Features Within the Geographical Area Occupied by the Species
To identify where the essential features occur within areas occupied by Atlantic sturgeon, we reviewed the best available scientific information, including the 2007 Atlantic sturgeon status review (ASSRT, 2007), the ESA listing rules (77 FR 5914; February 6, 2012), scientific research reports, information and data gathered during the peer-review process, and a database developed by the U.S. Geological Survey for mapping environmental parameters within East Coast Rivers to identify sturgeon habitat. We also considered information on the location of sturgeon spawning activity from scientific reports, as active spawning in an area would indicate that the essential features necessary for spawning are likely present. Information on documented spawning in specific areas in the Southeast is rare, but some does exist. For example, large sections of the Altamaha River have been found to support Atlantic sturgeon spawning activities for many years (Peterson et al., 2006; Peterson et al., 2008). We reviewed reports from a NMFS-funded multi-year, multi-state research project on movement and migration of Atlantic sturgeon (Species Recovery Grant number NA10NMF4720036, Post et al., 2014). In these reports, researchers determined which portions of Southeastern rivers support spawning activities by looking at the upriver extent of sturgeon movements during spawning season.
There are large areas of most rivers where data are still lacking. The available data also represent a snapshot in time, while the exact location of a habitat feature may change over time ( e.g., water depth fluctuates seasonally, as well as annually, and even hard substrate may shift position). For example, some data indicate a change in substrate type with in a given location from year to year ( e.g., from sand to gravel). It is not always clear whether such changes are due to an actual shift in substrate sediments or if the substrate sample was collected in a slightly different location between samplings. Although the habitat features may vary even at the same location, if any of the available data regarding a particular feature fell within the suitable range ( i.e., salinity of 0-0.5 ppt, water depths from 1.2-27 m, or hard substrate [gravel, cobble, etc.]), we considered that the essential feature is present in the area.
When data were not available for certain rivers or portions of occupied rivers, we used our general knowledge of Atlantic sturgeon spawning and applied river-specific information to determine the location of features essential to spawning. We considered salinity tolerance during the earliest life stages to determine appropriate habitat for larvae to develop as they mature. Available telemetry data suggest that most Atlantic sturgeon spawning activity in the Savannah and Altamaha start around river kilometer (RKM) 100 (Post et al., 2014). Similar evidence from the Edisto, Neuse, and Tar-Pamlico rivers indicates spawning activity starts around RKM 80. Peer review comments on the Draft Economic and Biological Information to Inform Atlantic Sturgeon Critical Habitat Designation indicated that Atlantic sturgeon spawn below the fall line, unlike shortnose sturgeon that may spawn well above the fall line.
In order to encompass all areas important for Atlantic sturgeon spawning, reproduction, and recruitment within rivers where spawning is believed to occur or may occur, we identified specific areas of critical habitat from the mouth (RKM 0) of each spawning river to the upstream extent of the spawning habitat. Other than an unexplained report of an Atlantic sturgeon carcass upstream of dams in the Santee Cooper system, we have no evidence that Atlantic sturgeon can pass upstream of dams ( i.e., through turbines or fishways for shad and herring) and thus we are considering those upstream areas as unoccupied for the purpose of this rulemaking. Manmade barriers currently restrict upstream movement of Atlantic sturgeon in the Cape Fear, Santee-Cooper, and Savannah River systems. In other rivers, either the fall line, or for those rivers that do not reach the fall line, an easily identifiable landmark ( e.g., a bridge) near the headwaters is considered the upstream extent of spawning habitat.
To identify specific habitats used by an Atlantic sturgeon DPS in occupied rivers, we considered available information that described: (1) Capture location and/or tracking locations of Atlantic sturgeon identified to its DPS by genetic analysis; (2) capture location and/or tracking locations of adult Atlantic sturgeon identified to its DPS based on the presence of a tag that was applied when the sturgeon was captured as a juvenile in its natal estuary; (3) capture or detection location of adults in spawning condition ( i.e., extruding eggs or milt) or post-spawning condition ( e.g., concave abdomen for females); (4) capture or detection of YOY and other juvenile age classes; and, (5) collection of eggs or larvae.

Large Coastal Rivers that Lack Essential Features
Several large coastal rivers within the geographic area occupied by the Carolina and South Atlantic DPSs of Atlantic sturgeon do not appear to support spawning and juvenile recruitment or to contain suitable habitat features to support spawning. These rivers are the Chowan and New Rivers in North Carolina; the Waccamaw (above its confluence with Bull Creek which links it to the Pee Dee River), Sampit, Ashley, Ashepoo, and Broad-Coosawhatchie Rivers in South Carolina; and the St. Johns River, Florida. We have no information, current or historic, of Atlantic sturgeon using the Chowan and New Rivers in North Carolina. Recent telemetry work by Post et al. (2014) indicates that Atlantic sturgeon do not utilize the Sampit, Ashley, Ashepoo, and Broad-Coosawhatchie Rivers in South Carolina. These rivers are short, coastal plains rivers that most likely do not contain suitable habitat for Atlantic sturgeon. Post et al. (2014) also found Atlantic sturgeon only use the portion of the Waccamaw River downstream of Bull Creek. Due to man-made structures and alterations, spawning areas in the St. Johns River are not accessible and therefore do not support a reproducing population. For these reasons, we are not designating these coastal rivers, or portions of the rivers, as critical habitat. For rivers we are proposing to designate as critical habitat, we have historical or current information that they support spawning and juvenile recruitment as described below.

Roanoke River
The Roanoke River was identified as a spawning river for Atlantic sturgeon based on the capture of juveniles, the collection of eggs, and the tracking location of adults. Further, there was information indicating the historical use of the Roanoke River by Atlantic sturgeon.
Atlantic sturgeon were historically abundant in the Roanoke River and Albemarle Sound, but declined dramatically in response to intense fishing effort in the late 1800's (Armstrong and Hightower, 2002). There is still a population present in the Albemarle Sound and Roanoke River (Armstrong and Hightower, 2002; Smith et al., 2014). DNA analyses of juveniles captured in Albemarle Sound indicate that these fish are genetically distinct from Atlantic sturgeon collected in other systems (Wirgin et al., 2000; King et al., 2001).
Historical records and recent research provide accounts of Atlantic Sturgeon spawning within the fall zone (RKM 204-242) of the Roanoke River (Yarrow, 1874; Worth, 1904; Armstrong and Hightower, 2002; Smith et al., 2014). Atlantic sturgeon remains from archaeological sites on the Roanoke River have been found as far upstream as RKM 261, approximately 19 miles above the upper end of the fall zone (Armstrong and Hightower, 2002; VanDerwarker, 2001); however, that was prior to the construction of dams now located throughout the river. The farthest downstream dam, the Roanoke Rapids Dam, is located near the fall line at RKM 221. No fish passage exists at this dam, so all Atlantic sturgeon are restricted to the lower 17 RKM of fall zone habitat, which extends from the Roanoke Rapids Dam to Weldon, North Carolina at RKM 204 (Armstrong and Hightower, 2002; Smith et al., 2014).
Historic and current data indicate that spawning occurs in the Roanoke River, where both adults and small juveniles have been captured. Since 1990, the North Carolina Division of Marine Fisheries (NCDMF) has conducted the Albemarle Sound Independent Gill Net Survey (IGNS). From 1990 to 2006, 842 sturgeon were captured ranging from 15.3 to 100 centimeters (cm) fork length (FL), averaging 47.2 cm FL. One hundred and thirty-three (16%) of the 842 sturgeon captured were classified as YOY (41 cm TL, 35 cm FL); the others were subadults (ASSRT, 2007). A recent study by Smith et al. (2014), using acoustic telemetry data and egg collection during the fall of 2013, identified a spawning location near Weldon, North Carolina (RKM 204). The location contains the first shoals encountered by Atlantic sturgeon as they move upstream to spawn (Smith et al., 2014). The channel in this area is approximately 100 m wide and the substrate is primarily bedrock, along with fine gravel and coarse sediments in low-flow areas (Smith et al., 2014). During the study, 38 eggs were collected during 21 days that spawning pads were deployed (Smith et al., 2014).
A scientific survey also shows the presence of adult Atlantic sturgeon in the Roanoke River. Using side-scan sonar, Flowers and Hightower (2015) conducted surveys near the freshwater-saltwater interface with repeated surveys performed over 3 days. The surveys detected 4 Atlantic sturgeon greater than 1 m total length. Based on these detections, an abundance estimate for riverine Atlantic sturgeon of 10.9 (95% confidence interval 3-36) fish greater than 1 m was calculated for the Roanoke River. This estimate does not account for fish less than 1 m total length, occurring in riverine reaches not surveyed, or in marine waters.

Tar-Pamlico River
The Tar-Pamlico River was identified as a spawning river for Atlantic sturgeon based on the evidence of spawning and the capture of juveniles. The Tar-Pamlico River, one of two major tributaries to Pamlico Sound, is dammed. However, all riverine habitat is accessible to Atlantic sturgeon in the Tar-Pamlico River, because the lower-most dam, the Rocky Mount Mill Pond Dam (RKM199), is located at the fall line.
Evidence of spawning was reported by Hoff (1980), after the capture of very young juveniles in the Tar River. Two juveniles were observed dead on the bank of Banjo Creek, a tributary to the Pamlico System (ASSRT, 2007). A sampling program similar to the Albemarle Sound IGNS collected 14 Atlantic sturgeon in 2004. These fish ranged in size from 460 to 802 mm FL and averaged 575 mm FL. The NCDMF Observer Program reported the capture of 12 Atlantic sturgeon in the Pamlico Sound from April 2004 to December 2005; these fish averaged 600 mm TL(ASSRT, 2007).

Neuse River
The Neuse River was identified as a spawning river for Atlantic sturgeon based on the evidence of spawning and the capture of juveniles. Evidence of spawning was reported by Hoff (1980), who noted captures of very young juveniles in the Neuse River. An independent gill net survey was initiated in 2001 following the Albemarle Sound IGNS methodology. Collections were low during the periods of 2001-2003, ranging from zero to one fish/year. However, in 2004, this survey collected 14 Atlantic sturgeon ranging from 460 to 802 mm FL, and averaging 575 mm FL. During the same time period (2002-2003), four Atlantic sturgeon (561-992 mm FL) were captured by North Carolina State University personnel sampling in the Neuse River (Oakley, 2003). Similarly, the NCDMF Observer Program documented the capture of 12 Atlantic sturgeon in the Pamlico Sound from April 2004 to December 2005; none of these were YOY or spawning adults, averaging approximately 600 mm TL (ASSRT, 2007).

Cape Fear River System
The Cape Fear and Northeast Cape Fear Rivers were identified as spawning rivers for Atlantic sturgeon based on the capture of juveniles, the capture of adults in spawning condition, and the tracking location of adults, and information indicating the historical use by Atlantic sturgeon. In the late 1800's, the Cape Fear River had the largest landings of sturgeon in the southeastern United States (Moser and Ross, 1995). While species identification ( i.e., shortnose or Atlantic sturgeon) is not possible, these landings suggest large populations of both species. The Cape Fear River is tidally influenced by diurnal tides up to at least RKM 96. The River is also dredged extensively to maintain a depth of 12 m up to RKM 49 and then a depth of 4 m up to Lock and Dam 1. There are numerous deep holes (>10 m) throughout this extent.
A gill net survey for adult shortnose and juvenile Atlantic sturgeon was conducted in the Cape Fear River drainage from 1990 to 1992, and replicated from 1997 to 2005. Each sampling period included two overnight sets. The 1990-1992 survey captured 100 Atlantic sturgeon below Lock and Dam #1 (RKM 95). In 1997, 16 Atlantic sturgeon were captured below Lock and Dam #1, an additional 60 Atlantic sturgeon were caught in the Brunswick (a tributary of the Cape Fear River), and 12 were caught in the Northeast Cape River (Moser et al. 1998). Additionally, Ross et al. (1988 in Moser and Ross, 1995) reported the capture of a gravid female in the Cape Fear River.
Recent telemetry work conducted in the Cape Fear and Northeast Cape Fear River showed that subadult Atlantic sturgeon movement and distribution followed seasonal patterns (Loeffler and Collier in Post et al., 2014). During summer months, Atlantic sturgeon distribution was shifted upriver with limited large-scale movements; during the coldest time of year, subadult fish were absent from the rivers and had migrated to the estuary or ocean (Loeffler and Collier in Post et al., 2014). The high inter-annual return rates of tagged fish to the system demonstrate that Atlantic sturgeon have fidelity to these rivers; this implies that the Cape Fear River system may be the natal system for these fish (Loeffler and Collier in Post et al., 2014).
Further evidence of the importance of this system is demonstrated by the movement patterns of one of five adult Atlantic sturgeon tagged during the study that has shown site fidelity. This individual fish was in ripe and running condition at the time of tagging. This fish subsequently returned to the Cape Fear system each of the following years (2013 and 2014) and has been detected farther upstream in both the Cape Fear (RKM 95) and Northeast Cape Fear (RKM 132) rivers than any tagged subadult fish during this study. This fish did not use the fish passage rock arch ramp at Lock and Dam #1; however, at the time when it was present at the base of the dam, the rock arch ramp structure was only partially complete. In all years of the study this fish had movement patterns that are consistent with spawning behavior and demonstrate that both the Northeast Cape Fear and Cape Fear Rivers may be important spawning areas. While telemetry data have not indicated Atlantic sturgeon presence above Lock and Dam #1, we believe the fish passage present at the dam is successful or that fish pass through the lock. We base this determination on reports of Atlantic sturgeon above Lock and Dam #1 (J. Hightower, NCSU, pers. comm. To J. Rueter, NMFS, July 21, 2015).

Pee Dee River System
The Pee Dee River System was identified as providing spawning habitat used by Atlantic sturgeon based on the capture of juveniles, the capture of adults in spawning condition, and the tracking location of adults. Captures of age-1 juveniles from the Waccamaw River during the early 1980s suggest that a reproducing population of Atlantic sturgeon existed in that river, although the fish could have been from the nearby Pee Dee River (Collins and Smith1997). In 2003 and 2004, nine Atlantic sturgeon (48.4-112.2 cm FL) were captured in the Waccamaw River during the South Carolina Department of Natural Resources annual American shad gill net survey. While these fish were not considered YOY, Collins et al. (1996) note that unlike northern populations, in South Carolina, YOY are considered to be less than 50 cm TL or 42.5 cm FL, because growth rates are greater in the warmer southern waters compared to cooler northern waters. Therefore, the capture of a 48.4 cm FL sturgeon provides some evidence that YOY may be present in the Waccamaw River. Based on telemetry data, these YOY were thought to have been spawned in the Pee Dee River, and then traveled downstream through Bull Creek, and into the Waccamaw River. (B. Post, SCDNR, pers. comm. to J. Rueter, NMFS, July 9, 2015).
Based on preliminary analyses of sturgeon detections during their study, Post et al. (2014) concluded the Pee Dee River system appears to be utilized by Atlantic sturgeon for summer/winter seasonal habitat as well as for spawning. From 2011 to 2014, 41 sturgeon were detected in upstream areas of the Pee Dee River that considered spawning areas. All 10 Atlantic sturgeon that were originally implanted with transmitters in the Pee Dee System were later detected displaying upstream and downstream movement. Distinct movement patterns were evident for these fish as similar patterns were observed each year of the study period. Two of the 10 fish originally tagged in the Pee Dee System and many tagged fish from other systems made spawning runs in the Pee Dee River (Post et al., 2014).

Black River, South Carolina
The Black River was identified as a spawning river for Atlantic sturgeon based on the capture of juveniles and the tracking location of adults. During a telemetry study from 2011 to 2014, Post et al. (2014) detected 10 juveniles and 10 adults utilizing the Black River. An adult male was detected at the last receiver station in the river one year (RKM 70.4) and the next to last receiver station in a subsequent year. While the receiver stations were not at the fall line, they were very far upriver, and it is likely that the only reason this fish traveled so far upriver was to spawn (B. Post, SCDNR, pers. comm. to J. Rueter, NMFS PRD, July 9, 2015). Juveniles were located as far upstream as RKM 42.1, suggesting the Black River is also an important foraging/refuge habitat.

Santee and Cooper Rivers
The Santee-Cooper River system was identified as a spawning river system for Atlantic sturgeon based on the capture of YOY. The Santee River basin is the second largest watershed on the Atlantic Coast of the United States; however with the completion of Wilson Dam in the 1940s, upstream fish migrations were restricted to the lowermost 145 RKMs of the Santee River. Following construction of the Wilson and Pinopolis Dams, the connectivity between the coastal plain and piedmont was lost. In the 1980s, a fish passage facility at the St. Stephen powerhouse, designed to pass American shad and blueback herring, was completed that attempted to restore connectivity throughout the system. (Fish passage and fishway mean any structure on or around artificial barriers to facilitate diadromous fishes' natural migration). The passage facility has not been successful for Atlantic sturgeon (Post et al., 2014). However, in 2007 an Atlantic sturgeon entered the fish passage facility at the fishway to the lift, presumably in an attempt to migrate upstream to spawn, and was subsequently physically removed and then released downstream into the Santee River (A. Crosby, SCDNR, pers. comm.).
Historically, the Cooper River was a small coastal plain river that fed into Charleston Harbor. The completion of the Santee Cooper hydropower project in the 1940s dramatically changed river discharge in the Cooper River. From the 1940s into the 1980s, nearly all river discharge of the Santee River was diverted through the Santee Cooper project, run through the hydroelectric units in Pinopolis Dam, and discharged down the Tailrace Canal and into the Cooper River. In the 1980s, the Rediversion Project redirected part of the system's discharge back to the Santee River; however, a significant discharge of freshwater still flows into the Cooper River. The Cooper River provides the dominant freshwater input for the Charleston Harbor and provides 77 RKM of riverine habitat (Post et al., 2014).
The capture of 151 subadults, including age-1 fish in 1997 indicates a population exists in the Santee River (Collins and Smith, 1997). Four juvenile Atlantic sturgeon, including YOY, were captured in the winter of 2003 in the Santee (N = 1) and Cooper (N = 3) Rivers (McCord, 2004). These data support the existence of a spawning population, but South Carolina Department of Natural Resources biologists working in the Santee-Cooper system believe the smaller fish are pushed into the system from the Pee Dee and/or Waccamaw River during flooding conditions (McCord, 2004). This hypothesis is based on the lack of access to suitable spawning habitat due to the locations of the Wilson Dam and St. Stephen Powerhouse on the Santee River and the Pinopolis Dam on the Cooper River. Nonetheless, the Santee-Cooper River system appears to be important foraging and refuge habitat and could serve as important spawning habitat once access to historical spawning grounds is restored through a fishway prescription under the Federal Power Act (NMFS 2007).
In a recent telemetry study by Post et al. (2014), four Atlantic sturgeon were tagged in the Santee River from 2011 to 2014. Of the four Atlantic sturgeon tagged in the Santee River, one was detected in the river, one was detected at the mouth of the river, and the other two have not been detected in the Santee River system since being tagged. There was no detectable spawning run or pattern of movement for the tagged fish that remained in the Santee River (Post et al., 2014). There were no Atlantic sturgeon captured in the Cooper River during the Post et al., 2014 study. There were seven Atlantic sturgeon detected in the Cooper River that had been tagged in other systems. The Atlantic sturgeon that were detected in the Cooper River were more commonly detected in the saltwater tidal zone, with the exception of one that made a presumed spawning run to Pinopolis Dam in the fall of 2013 (Post et al., 2014).

Edisto River
The Edisto is the largest river in the Ashepoo, Combahee, Edisto (ACE) Basin; begins in the transition zone between piedmont and coastal plain; and is unimpeded for its entire length. It is the longest free flowing blackwater river in South Carolina. During excessive rainy seasons it will inundate lowlands and swamps, and the flow basin increases to a mile wide or more. The Edisto River was identified as a spawning river for Atlantic sturgeon based on the capture of an adult in spawning condition and capture location and tracking of adults.
Spawning adults (39 in 1998) and YOY (1,331 from 1994-2001) have been captured in the ACE basin (Collins and Smith, 1997; ASSRT, 2007). One gravid female was captured in the Edisto River during sampling efforts in 1997 (ASSRT, 2007). Seventy-six Atlantic sturgeon were tagged in the Edisto River during a 2011 to 2014 telemetry study (Post et al., 2014). Fifty-eight of the 76 Atlantic sturgeon tagged were detected in the Edisto River during the study. Distinct movement patterns of Atlantic sturgeon were evident. Fish entered the river between April and June and were detected in the saltwater tidal zone until water temperature decreased below 25° C. They then moved into the freshwater tidal area, and some fish made presumed spawning migrations in the fall around September-October. Spawning migrations were thought to be occurring based on fish movements upstream to the presumed spawning zone between RKM 78 and 210. Fish stayed in these presumed spawning zones for an average of 22 days. The tagged Atlantic sturgeon left the river system by November. A number of tagged individuals were detected making such movements during multiple years of the study. Only those fish that were tagged in the Edisto River were detected upstream near presumed spawning grounds, while fish detected in the Edisto River, but tagged elsewhere, were not detected near the presumed spawning areas. In the winter and spring, Atlantic sturgeon were generally absent from the system except for a few fish that remained in the saltwater tidal zone (Post et al., 2014).

Combahee—Salkehatchie River
The Combahee—Salkehatchie River was identified as a spawning river for Atlantic sturgeon based on capture location and tracking locations of adults and the spawning condition of an adult. Spawning adults (39 in 1998) and YOY (1,331 from 1994-2001) have been captured in the ACE basin (Collins and Smith, 1997; ASSRT, 2007). One running ripe male was captured in the Combahee River during a sampling program in 1997 (ASSRT, 2007). Seven Atlantic sturgeon were captured and five were tagged during a 2010 and 2011 telemetry study (Post et al., 2014). Atlantic sturgeon that were tagged in the Combahee River were absent from the system for the majority of the study period. An Atlantic sturgeon that was tagged in June of 2011 left the system in the fall of 2011, returned in July 2012 and left the system again in the fall of 2012. This fish was detected the farthest upstream of any tagged Atlantic sturgeon in the Combahee River (RKM 56). Another individual was identified as a running ripe male at capture in the Combahee River in March 2011, was relocated exhibiting spawning behavior in the North East Cape Fear River, NC in March, 2012, and in 2014 was detected from February-April in the Pee Dee System.

Savannah River
The Savannah River was identified as a spawning river for Atlantic sturgeon based on capture location and tracking locations of adults and the collection of larvae. Forty three Atlantic sturgeon larvae were collected in upstream locations (RKM 113-283) near presumed spawning locations (Collins and Smith, 1997). Seven Atlantic sturgeon were also tagged from 2011 to 2014 and distinct movement patterns were evident (Post et al., 2014). In 2011, one individual was detected travelling upstream in mid-April and remained at a presumed spawning area (RKM 200 to 301) through mid-September. Two Atlantic sturgeon migrated into the system and upstream to presumed spawning grounds in 2012. The first entered the system in mid-August and returned downriver in mid-September; the other entered the system in mid-September and returned downriver in mid-October. Four Atlantic sturgeon entered the Savannah River and migrated upstream during the late summer and fall months in 2013. Two Atlantic sturgeon previously tagged in the Savannah River made upstream spawning movements; this was the second year (2011) one of these fish was detected making similar upstream movements. These two fish were also detected immediately upstream of the New Savannah Bluff Lock and Dam (RKM 301). It is unknown if they passed through the lock or swam over the dam during high flows. There is a strong possibility that one fish may have been detected by the receiver directly upstream while still remaining downstream of the dam and while flow control gates were in a full open position. Atlantic sturgeon in the Savannah River were documented displaying similar behavior three years in a row—migrating upstream during the fall and then being absent from the system during spring and summer.

Ogeechee River
The Ogeechee River was identified as a spawning river for Atlantic sturgeon based on tracking of adults and YOY. Seventeen Atlantic sturgeon considered to be YOY (less than 30 cm TL) were collected in 2003 by the Army's Environmental and Natural Resources Division (AENRD) at Fort Stewart, Georgia. An additional 137 fish were captured by the AENRD in 2004. Nine of these fish measured less than 41 cm TL and were considered YOY. During a telemetry study from 2011 to 2014, there were no capture or tagging efforts conducted in the Ogeechee River; however, 40 Atlantic sturgeon were detected in the Ogeechee River (Ingram and Peterson in Post et al., 2014).

Altamaha River
The Altamaha River and its major tributaries the Oconee and Ocmulgee Rivers were identified as spawning rivers for Atlantic sturgeon based on capture location and tracking of adults and the capture of adults in spawning condition. The Altamaha River supports one of the healthiest Atlantic sturgeon subpopulations in the Southeast, with over 2,000 subadults captured in trammel nets, 800 of which were nominally age-1 as indicated by size (ASSRT, 2007). A survey targeting Atlantic sturgeon was initiated in 2003 by the University of Georgia. By October 2005, 1,022 Atlantic sturgeon had been captured using trammel and large gill nets. Two hundred and sixty-seven of these fish were collected during the spring spawning run in 2004 (N = 74 adults) and 2005 (N = 139 adults). From these captures, 308 (2004) and 378 (2005) adults were estimated to have participated in the spring spawning run, representing 1.5% of Georgia's historical spawning stock (females) as estimated from U.S. Fish Commission landing records (Schueller and Peterson 2006, Secor 2002).
In a telemetry study by Peterson et al. (2006), most tagged adult Atlantic sturgeon were found between RKM 215 and 420 in October and November when water temperatures were appropriate for spawning. There are swift currents and rocky substrates throughout this stretch of river (Peterson et al., 2006). Two hundred thirteen adults in spawning condition were captured in the Altamaha system in 2004-2005 (Peterson et al., 2006).
Forty-five adult Atlantic sturgeon were captured and tagged from 2011 to 2013 (Ingram and Peterson in Post et al., 2014). Telemetry data from the tagged individuals indicated that the fish were present in the system from April through December. Twenty-six fish made significant (> 160 RKM) migrations upstream with eight fish making the migration in at least two of the years and four making the migration in all three years of the study. No site fidelity was apparent based on these data; however, an upriver site near the confluence of the Ocmulgee (RKM 340-350) was visited by multiple fish in multiple years. Fish migrated upstream into both the Ocmulgee and Oconee Rivers, but the majority entered the Ocmulgee River. The maximum extent of these upriver migrations was RKM 408 in the Ocmulgee River and RKM 356 in the Oconee River (Ingram and Peterson in Post et al., 2014).
Two general migration patterns were observed for fish in this system. Early upriver migrations that began in April—May typically occurred in two steps, with fish remaining at mid-river locations during the summer months before continuing upstream in the fall. The late-year migrations, however, were typically initiated in August or September and were generally non-stop. Regardless of which migration pattern was used during upstream migration, all fish exhibited a one-step pattern of migrating downstream in December and early January (Ingram and Peterson in Post et al., 2014).

Satilla River
The Satilla River was identified as a spawning river for Atlantic sturgeon based on the capture of adults in spawning condition. Ong et al. (1996) captured four reproductively mature Atlantic sturgeon on spawning grounds during the spawning season in the Satilla River.

St. Marys River
The St. Marys River was identified as a spawning river for Atlantic sturgeon based on the capture of YOY Atlantic sturgeon. Atlantic sturgeon were once thought to be extirpated in the St. Marys River. However, nine Atlantic sturgeon were captured in sampling efforts between May 19 and June 9, 2014. Captured fish ranged in size from 293 mm (YOY) to 932 mm (subadult). This is a possible indication of a slow and protracted recovery in the St. Marys (D. Peterson, UGA, pers. comm. to J. Rueter, NMFS PRD, July 8, 2015).

Unoccupied Critical Habitat Areas
ESA section 3(5)(A)(ii) defines critical habitat to include specific areas outside the geographical area occupied if the areas are determined by the Secretary to be essential for the conservation of the species. Our regulations at 50 CFR 424.12(g) also state: “The Secretary will not designate critical habitat within foreign countries or in other areas outside of the jurisdiction of the United States.” At the present time, the geographical area occupied by the Carolina and South Atlantic DPS of Atlantic sturgeon which is within the jurisdiction of the United States is limited to waters off the U.S. east coast from Maine through Florida, seaward to the boundary of the U.S. Exclusive Economic Zone, and upstream in freshwater systems to the fall line or the first impediment to fish passage. We have identified three areas outside the geographical area occupied by these species that are essential for their conservation, and therefore are proposing to designate these unoccupied areas as critical habitat for the Carolina and South Atlantic DPS of Atlantic sturgeon. For the Carolina DPS, we have identified the Cape Fear River from Huske Lock and Dam (Lock and Dam #3) downstream to Lock and Dam #2. We also identified the rivers of the Santee-Cooper basin from the Parr Shoals Dam on the Broad River and the Wateree Dam on the Wateree River downstream to the Wilson Dam and St. Stephen Powerhouse on the Santee River and Pinopolis Dam on the Cooper River. For the South Atlantic DPS we have identified the Savannah River from the Augusta Diversion Dam downstream to the New Savannah Bluff Lock and Dam.
As stated previously, the key habitat-based conservation objectives for these DPSs are facilitating adult reproduction and facilitating recruitment into the adult population by protecting spawning areas, juvenile development habitat, and the migratory corridors that allow adults to reach the spawning areas and newly spawned sturgeon to make a safe downstream movement. To successfully fulfill these conservation objectives, the areas above the dams on these three systems need to be protected until it becomes accessible to the species. Available data suggest that these unoccupied areas did historically, or could, serve as spawning habitat for Atlantic sturgeon should they become accessible in the future.
Telemetry data from the Cape Fear River discussed above (Loeffler and Collier in Post et al., 2014) indicate that Atlantic sturgeon make spawning movements up the Cape Fear River before being stopped at Lock and Dam #1; in one case the fish went downstream and then moved up the Northeast Cape Fear River. However, there have been reports of Atlantic sturgeon above Lock and Dam #1 (J. Hightower, NCSU, pers. comm. To J. Rueter, NMFS, July 21, 2015). It is likely the fish moving up to Lock and Dam #2 are attempting to reach historic upstream spawning areas. Using the fall line as a guide, only 33 percent of the historical habitat is available to Atlantic sturgeon below Lock and Dam #1 (96 km of 292 km). In some years, the salt water interface reaches Lock and Dam #1; so, spawning adults in the Cape Fear River either do not spawn in such years or spawn in the major tributaries of the Cape Fear River ( i.e., Black River or Northeast Cape Fear rivers) that are not obstructed by dams. There may be some exposed outcrops that would provide suitable substrate necessary for spawning between Lock and Dam #2 and Huske Lock and Dam (J. Facendola, NCDMF pers. comm. to J. Rueter, NMFS, July 20, 2015). The primary goal of the Cape Fear River Partnership is restoring access to historic migratory fish habitat. Their 2013 action plan identifies passage at Lock and Dam #2 as a priority and includes Atlantic sturgeon as a target species (Cape Fear River Partnership, 2013). In September 2015, the North Carolina General Assembly approved $250,000 to be used towards the design and engineering of a rock arch weir to help with fish passage at Lock and Dam #2 and matching funds are currently being sought. These efforts indicate to us it is likely a rock arch weir will provide passage at Lock and Dam #2 so that sturgeon can utilize the habitat upstream of Lock and Dam #2 up to the Huske Lock and Dam in the future. We propose to include the area from Huske Lock and Dam (Lock and Dam #3) downstream to Lock and Dam #2 as unoccupied critical habitat on the Cape Fear River because Atlantic sturgeon behavior indicates they are attempting to move upstream to spawning habitat located beyond this barrier, and we consider this historical spawning habitat essential to the conservation of the DPS.
The lowermost dams on the Santee and Cooper Rivers limit, and may eliminate altogether, viable spawning grounds for Atlantic sturgeon. Using the fall line as the upper region of spawning habitat, it is estimated that only 38 percent of the historical habitat is available to Atlantic sturgeon in the Santee-Cooper River system today. There are a number of anecdotal reports of Atlantic sturgeon making spawning runs to the dams and either returning downstream or attempting to spawn at the dams. These dams may not be far enough upstream for eggs and larvae to develop before entering higher salinity waters where they perish. The Santee Cooper Diversion Dam and Canal Project created two reservoirs: the Wilson Dam on the Santee River created Lake Marion, and the Pinopolis Dam on the Cooper River created Lake Moultrie. Currently, relicensing by the Federal Energy Regulatory Commission (FERC) for the South Carolina Public Service Authority (SCPSA) Hydroelectric Project, located in South Carolina is ongoing. Fish passage past these two dams was prescribed as part of the relicensing. Once this passage is constructed, the first dam Atlantic sturgeon will encounter is the abandoned Granby Lock and Dam on the Congaree River. This dam could represent a hindrance, but likely not a complete obstacle, to upstream movements of Atlantic sturgeon because remnant parts of the dam may deter bottom oriented species. Above the Granby Lock and Dam, Atlantic sturgeon will encounter the Columbia Dam on the Broad River. In 2002 we prescribed a fishway to be constructed at the Columbia Dam for American shad, blueback herring, and American eel. Concurrently we reserved authority to prescribe a fishway for sturgeon, because although such a fishway was warranted, a safe and effective passage mechanism was not yet established. The fishway constructed to pass the target species (American shad, blueback herring, and American eel) incorporated “sturgeon friendly” features as sturgeon are potential future target species. Field work conducted during consultation by NMFS Habitat Conservation Division established that excellent spawning and juvenile rearing habitat exists in the 24 miles of large river shoals between the Columbia Dam and the next upstream dam, the Parr Shoals Dam (DOC, 2002). While sturgeon have not been documented as currently passing through the Columbia Dam fishway, our reservation of authority in the 2002 FERC relicensing provides us the expectation the Columbia Dam will be passable in the future so that sturgeon can utilize the upstream 24-miles of shoal habitat for spawning and rearing. Additionally, we have information on a population of shortnose sturgeon that has been stranded above Pinopolis and Wilson Dams for decades, and there is a good deal of data on their spawning activity in the Congaree, Broad, and Wateree Rivers. Shortnose sturgeon spawning habitat requirements are similar to Atlantic sturgeon, thus we believe these unoccupied areas contain suitable spawning habitat for Atlantic sturgeon. We conclude that these unoccupied spawning habitats are essential to the conservation of the DPS, and therefore, we are proposing to designate unoccupied critical habitat from the Wateree Dam on the Wateree River and from the Parr Shoals Dam on the Broad River downstream to the Wilson Dam and St. Stephen Powerhouse on the Santee River and the Pinopolis Dam on the Cooper River.
The Savannah River has some fish passage at New Savannah Bluff Lock and Dam, but successful passage of Atlantic sturgeon is not believed to occur. The historical primary spawning habitat for Atlantic sturgeon (and only shoal habitat on the Savannah River), the Augusta Shoals, is not accessible to Atlantic sturgeon because it lies above the New Savannah Bluff Lock and Dam. Sturgeon are currently frequently seen at the base of the New Savannah Bluff Lock and Dam during spawning season, indicating either crowding below the dam or individual motivation to spawn farther upriver, or both. We conclude this unoccupied area is essential to the conservation of the DPS and therefore, we propose to designate the Savannah River from the Augusta Diversion Dam downstream to the New Savannah Bluff Lock and Dam as critical habitat.

Application of ESA Section 4(a)(3)(B)(i) (Military Lands)
Section 4(a)(3)(B) of the ESA prohibits designating as critical habitat any lands or other geographical areas owned or controlled by the Department of Defense (DOD), or designated for its use, that are subject to an Integrated Natural Resources Management Plan (INRMP) prepared under section 101 of the Sikes Act (16 U.S.C. 670a), if the Secretary determines in writing that such plan provides a benefit to the species for which critical habitat is proposed for designation. The legislative history to this provision explains:
The conferees would expect the [Secretary] to assess an INRMP's potential contribution to species conservation, giving due regard to those habitat protection, maintenance, and improvement projects and other related activities specified in the plan that address the particular conservation and protection needs of the species for which critical habitat would otherwise be proposed. Consistent with current practice, the Secretary would establish criteria that would be used to determine if an INRMP benefits the listed species for which critical habitat would be proposed (Conference Committee report, 149 Cong. Rec. H. 10563 (November 6, 2003)).
In February 2014 and October 2015, we requested information from the DOD to assist in our analysis. Specifically, we asked for a list of facilities that occur within the potential critical habitat areas for the Carolina and South Atlantic DPSs of Atlantic sturgeon and available INRMPs for those facilities. We received information on two INRMPs for DOD facilities on or near the banks of rivers included in the proposed designation—the Naval Submarine Base Kings Bay (GA), on the St. Marys River and Joint Base Charleston (SC), on the Cooper River. At neither base does the Navy own or control, or have designated for its use, lands or geographic areas being proposed as critical habitat. Thus, there are no areas where the INRMP prohibition is applicable. Notably, the Department of Navy response indicated a desire to review and revise applicable INRMPs to provide appropriate and feasible conservation benefits to the species if possible.

Application of ESA Section 4(b)(2)
Section 4(b)(2) of the ESA requires that we consider the economic impact, impact on national security, and any other relevant impact, of designating any particular area as critical habitat. Additionally, the Secretary has the discretion to consider excluding any area from critical habitat if she determines, based upon the best scientific and commercial data available, the benefits of exclusion (that is, avoiding some or all of the impacts that would result from designation) outweigh the benefits of designation. The Secretary may not exclude an area from designation if exclusion will result in the extinction of the species. Because the authority to exclude is discretionary, exclusion is not required for any particular area under any circumstances.
The ESA provides the USFWS and NMFS (the Services) with broad discretion in how to consider impacts. See, H.R. Rep. No. 95-1625, at 17, reprinted in 1978 U.S.C.C.A.N. 9453, 9467 (1978) (“Economics and any other relevant impact shall be considered by the Secretary in setting the limits of critical habitat for such a species. The Secretary is not required to give economics or any other “relevant impact” predominant consideration in his specification of critical habitat . . . The consideration and weight given to any particular impact is completely within the Secretary's discretion.”). Courts have noted the ESA does not contain requirements for any particular methods or approaches. See, e.g., Bldg. Indus. Ass'n of the Bay Area et al. v. U.S. Dep't. of Commerce et al., No. 13-15132, 9th Cir., July 7, 2015 (upholding district court's ruling that the ESA does not require the agency to follow a specific methodology when designating critical habitat under section 4(b)(2). For this proposed rule, we followed the same approach to describing and evaluating impacts as we have for recent critical habitat rulemakings in the NMFS Southeast Region.
The following discussion of impacts summarizes the analysis contained in our Draft Impact Analysis of Critical Habitat Designation for the Carolina and South Atlantic Distinct Population Segments of Atlantic Sturgeon ( Acipenser oxyrinchus oxyrinchus ) (Draft Impacts Analysis), which identifies the economic, national security, and other relevant impacts that we projected would result from including each of the fourteen occupied and three unoccupied specific areas in the proposed critical habitat designation. We considered these impacts when deciding whether to exercise our discretion to propose excluding particular areas from the designation. Both positive and negative impacts were identified and considered (these terms are used interchangeably with benefits and costs, respectively). Impacts were evaluated in quantitative terms where feasible, but qualitative appraisals were used where that is more appropriate to particular impacts. The Draft Impacts Analysis Report is available on NMFS's Southeast Regional Office Web site at http://sero.nmfs.noaa.gov/protected_resources/sturgeon/index.html.
The primary impacts of a critical habitat designation result from the ESA Section 7(a)(2) requirement that Federal agencies ensure their actions are not likely to result in the destruction or adverse modification of critical habitat, and that they consult with NMFS in fulfilling this requirement. Determining these impacts is complicated by the fact that Section 7(a)(2) also requires that Federal agencies ensure their actions are not likely to jeopardize the species' continued existence. One incremental impact of designation is the extent to which Federal agencies modify their proposed actions to ensure they are not likely to destroy or adversely modify the critical habitat beyond any modifications they would make because of listing and the jeopardy requirement. When the same modification would be required due to impacts to both the species and critical habitat, the impact of the designation is coextensive with the ESA listing of the species ( i.e., attributable to both the listing of the species and the designation critical habitat). Relevant, existing regulatory protections are referred to as the “baseline” and are also discussed in the Draft Impacts Analysis. In this case, notable baseline protections include the ESA listings of not only Atlantic sturgeon, but the co-occurring shortnose sturgeon.
The Draft Impacts Analysis Report describes the projected future federal activities that would trigger Section 7 consultation requirements because they may affect the essential features, and consequently may result in economic costs or negative impacts. The report also identifies the potential national security and other relevant impacts that may arise due to the proposed critical habitat designation, such as positive impacts that may arise from conservation of the species and its habitat, state and local protections that may be triggered as a result of designation, and education of the public to the importance of an area for species conservation.

Economic Impacts
Economic impacts of the critical habitat designation result through implementation of Section 7 of the ESA in consultations with Federal agencies to ensure their proposed actions are not likely to destroy or adversely modify critical habitat. These economic impacts may include both administrative and project modification costs; economic impacts that may be associated with the conservation benefits of the designation are described later.
We examined the ESA Section 7 consultation record over the last 10 years, as compiled in our Public Consultation Tracking System (PCTS) database, to identify the types of Federal activities that may adversely affect proposed Atlantic sturgeon critical habitat. We requested that federal action agencies provide us with information on future consultations if we omitted any future actions likely to affect the proposed critical habitat. No new categories of activities were identified through this process. Of the types of past consultations that “may affect” some or all of the essential features in any unit of proposed critical habitat, we determined that no activities would solely affect the essential features. That is, all categories of the activities identified have potential routes of adverse effects to both Atlantic or shortnose sturgeon and the critical habitat.
Fourteen categories of activities implemented by ten different federal entities were identified as likely to recur in the future and have the potential to affect the essential features (total number of projected consultations over 10 years indicated in parentheses):
1. U.S. Army Corps of Engineers (USACE)—Navigation maintenance dredging, harbor expansion (14)
2. USACE—Water Resources Development Act (WRDA) flood control, ecosystem restoration studies (6)
3. USACE—WRDA dam operations, repair, fishway construction (3)
4. USACE—Section 404/Rivers and Harbors Act (RHA) section 10 permitting—dredge, fill, construction (20)
5. Federal Highway Administration (FHWA)—Bridge repair, replacement (67)
6. U.S. Coast Guard (USCG)—Bridge repair, replacement permitting (3)
7. FERC—Hydropower licensing (5)
8. FERC—Liquefied Natural Gas (LNG) facilities, pipelines authorization (5)
9. Nuclear Regulatory Commission (NRC)—Nuclear power plant construction/operation licensing (8)
10. NMFS—ESA research and incidental take permitting (section 10) (46)
11. U.S. Fish and Wildlife Service (USFWS)—Fishery management grants (11)
12. Environmental Protection Agency (EPA)—Nationwide pesticide authorizations (9)
13. Federal Emergency Management Agency (FEMA)—Disaster assistance/preparation grants (5)
14. Department of Energy (DOE)—Nuclear fuel management (3)
We estimate that 205 activities will require consultation over the next 10 years and will require analysis of impacts to Atlantic sturgeon critical habitat. As discussed in more detail in our Draft Impacts Analysis, all the activities identified as having the potential to adversely affect one or more of the proposed essential features, also have the potential to take Atlantic sturgeon. For most, if not all, of the projected future activities, if the effects to critical habitat will be adverse and require formal consultation, those effects would also constitute adverse effects to the species, either directly when they are in the project area, or indirectly due to the effects on their habitat. This is due to the conservation functions that the features are being designated to provide. For example, water quality is being identified as an essential feature to facilitate successful spawning, annual and inter-annual adult, larval, and juvenile survival, and larva, juvenile and subadult growth, development, and recruitment. Effects to the water quality feature that impede that conservation objective could injure or kill individual Atlantic sturgeon, for example by preventing adult reproduction, or rendering reproduction ineffective or resulting in reduced growth or mortality of larvae, juveniles or subadults. In these circumstances, the same project modifications would be required to address effects to both the species and effects to the critical habitat. Thus, projects that adversely affect the proposed essential features are likely to always also adversely affect the species and the project impacts would not be incremental.
For some of the projected activities, it may be feasible to conduct the action when sturgeon are out of the action area. If effects to critical habitat are temporary such that the essential features return to their pre-project condition by the time the sturgeon return and need to use the features, there might not be any adverse effects to either the species or the critical habitat. In these circumstances, consultations would be fully incremental consultations only on critical habitat, and the consultations would be informal ( i.e., impacts to critical habitat would not be permanent and would not be significant). This would likely only apply to actions that affect just spawning habitat in the upper parts of the rivers, as sturgeon of various ages are present year-round in the lower reaches of the rivers and the estuaries. The costs of fully incremental, informal consultations are higher than the marginal costs of adding critical habitat analyses to coextensive, formal consultations. Thus, to be conservative and avoid underestimating incremental impacts of this designation, and based on the activities involved, we assumed that two categories of activities could result in incremental, informal consultations. Those activities, both implemented by the USACE, are section Clean Water Act section 404/Rivers and Harbors Act permitting and WRDA dam operations/repair.
Administrative costs include the cost of time spent in meetings, preparing letters, and in some cases, developing a biological assessment and biological opinion, identifying and designing reasonable and prudent measures (RPMs), and so forth. For this impacts report, we estimated per-project administrative costs based on critical habitat economic analyses by Industrial Economics, Inc. (IEc). (2014a, 2014b). These impacts reports estimate administrative costs for different categories of consultations as follows: (1) New consultations resulting entirely from critical habitat designation; (2) new consultations considering only adverse modification (unoccupied habitat); (3) re-initiation of consultation to address adverse modification; and, (4) additional consultation effort to address adverse modification in a new consultation. Most of the projected future consultations we project to result from this proposed rulemaking will be coextensive formal consultations on new actions that would be evaluating impacts to sturgeon as well as impacts to critical habitat, and the administrative costs for these 182 consultations would be in category 4 above. The remaining 23 actions are projected to involve incremental informal consultation due to impacts to critical habitat alone. Based on IEc (2014a, b), we project that each formal consultation will result in the following additional costs to address critical habitat impacts: $1,400 in NMFS costs; $1,600 in action agency costs; $880 in third party ( e.g., permittee) costs, if applicable; and $1,200 in costs to the action agency or third party to prepare a Biological Assessment (BA). Costs for the incremental informal consultations would be as follows: $1,900 in NMFS' costs; $2,300 in action agency costs; $1,500 in third party ( e.g., permittee) costs, if applicable; and $1,500 in costs to the action agency or third party to prepare a BA. Costs of the 9 EPA nationwide consultations were treated differently. These consultations will involve all listed species and designated critical habitat under NMFS's jurisdiction, and thus costs attributable solely to this proposed rule are expected to be very small. To be conservative, we added 9 consultations to each unit, and 9 to each DPS's total number of consultations. We spread the costs of these consultations ($5,080 each) evenly across all units included in this proposed rule and the companion proposed rule to designate critical habitat for the Gulf of Maine, New York Bight, and Chesapeake Bay DPSs. This resulted in a total cost of $1,474.84 per unit.
In our impacts analysis, we concluded that none of the projected future activities are likely to require project modifications to avoid adverse effects to critical habitat features that would be different from modifications required to avoid adverse effects to sturgeon. In other words, we projected no incremental costs in proposed critical habitat units other than the administrative costs of consultations. While there may be serious adverse impacts to critical habitat from projected future projects that require project modifications to avoid destroying or adversely modifying critical habitat, impacts of these magnitudes to the essential features as defined, would also result in adverse effects to Atlantic sturgeon, either directly when they are in the project area, or indirectly as harm, resulting from impacts to their habitat that result in injury or death to sturgeons. The same project modifications would be required to avoid destroying or adversely modifying critical habitat and avoiding jeopardy or minimizing take of Atlantic sturgeon caused by impacts to its habitat.
Based on our draft impacts analysis, we project that the costs that will result from the proposed designation will total $1,092,793 over the next 10 years. The total incremental cost resulting from the designation for the Carolina DPS is $503,954, and the total incremental cost resulting from the designation for the South Atlantic DPS is $588,839, over 10 years. The per-unit costs vary widely. The annual per-unit costs range from $147 (Unoccupied Cape Fear River unit, Carolina DPS) to $23,051 (Occupied Savannah River unit, South Atlantic DPS).

National Security Impacts
Previous critical habitat designations have recognized that impacts to national security result if a designation would trigger future ESA Section 7 consultations because a proposed military activity “may affect” the physical or biological feature(s) essential to the listed species' conservation. Anticipated interference with mission-essential training or testing or unit readiness, through the additional commitment of resources to an adverse modification analysis and expected requirements to modify the action to prevent adverse modification of critical habitat, has been identified as a negative impact of critical habitat designations. (See, e.g., Proposed Designation of Critical Habitat for Southern Resident Killer Whales; 69 FR 75608, Dec. 17, 2004, at 75633.)
On February 14, 2014, and again in October 7, 2015, NMFS sent letters to DOD and the Department of Homeland Security requesting information on national security impacts of the proposed critical habitat designation, and we received responses from the Navy, Air Force, Army, and USCG. We discuss the information contained within the responses thoroughly in the Draft Impacts Analysis and summarize the information below.
The Navy's first submission provided information on its facilities and operations. However, the Navy was not able to make a full assessment whether there would be any national security impacts. The Navy indicated that as we define our essential features and areas more precisely, they would be able to provide a more detailed response to our requests and would update their INRMPs as necessary for the protection of Atlantic sturgeon and its critical habitat. The Navy's second submission noted that Naval Submarine Base Kings Bay was adjacent to the South Atlantic DPS critical habitat unit in the St. Marys River. The Navy stated it did not own or control any land or waters within the St. Marys channel, but that the TRIDENT-class submarines used 4.9 km of the waterway transiting to and from the Atlantic Ocean. The Navy stated that any operational or dredging restrictions that would impede maintenance of the channel from the Intracoastal Waterway and St. Marys channel intersection, downstream, could pose a national security risk. The USACE is typically the lead action agency with us for dredging actions, and the Navy would be the permit applicant. We determined that dredging has the potential to affect critical habitat, but we also concluded that consultations for effects of dredging on critical habitat will be fully-coextensive with consultations to address impacts to sturgeon. The effects of dredging on essential features would also result in injury or death to individual sturgeon, and thus constitute take. Removal or covering of spawning substrate could prevent effective spawning or result in death of eggs or larvae that are spawned. Changing the salinity regime by deepening harbors and parts of rivers could result in permanent decreases if available foraging and developmental habitat for juveniles. These types of adverse effects are not likely to be temporary and limited to periods of sturgeon absence. Thus, adverse effects of dredging activities are likely to be coextensive formal consultations to address impacts to both the species and the essential features, and thus no new requirements or project modifications are anticipated as a result of the proposed critical habitat designation. Therefore, we find there will be no impact on national security as a consequence of the proposed designation for these actions.
The Navy and Air Force expressed concern that designating the Cooper River, including the area of the river on the west side adjacent to the Joint Base Charleston Naval Weapons Station, could have significant impacts on the Navy's ability to adequately support mission-essential military operations, thereby impacting national security. The Navy and Air Force were concerned designation of critical habitat could affect training facilities and the maintenance of these facilities. Additional concerns were expressed regarding shipping and receiving operations from two waterfront facilities. Because no specifics were given on how designation of critical habitat could affect these activities, and because we determined there are no routes of effects to essential features from these activities based on the information provided, we concluded that designation of critical habitat will have no impact on these activities and thus will not result in impacts to national security
The Army noted that Military Ocean Terminal-Sunny Point, North Carolina, was located on the Cape Fear River and Fort Stewart, Georgia, was located on the Ogeechee River. However, the Army was not able to make a full assessment whether there would be any national security impacts and concluded that technical assessments between the installations and regional levels of NMFS would identify any specific impacts.
The USCG provided information on its facilities and operations. However, the USCG was not able to make a full assessment whether there would be any national security impacts. The USCG indicated that as we define our essential features and areas more precisely, they would be able to provide a more detailed response to our requests. The USCG consulted with us three times on authorizations for bridge repairs or replacements. If conducted in the future, these activities may affect proposed critical habitat features, but the effects would be fully coextensive with effects to listed sturgeon. Based on this information regarding potential future USCG action in proposed Atlantic sturgeon critical habitat, we do not expect any national security impacts as a consequence of the proposed critical habitat designation.
Based on a review of our consultation database, and the information provided by the Navy, Air Force, Army, and USCG on their activities conducted within the specific areas proposed for designation as Atlantic sturgeon critical habitat, we determined that only one military action identified as a potential area of national security impact has routes of potential adverse effects to proposed critical habitat—river channel dredging. As discussed, this activity will require consultation due to potential impacts to listed Atlantic and shortnose sturgeon, and any project modifications needed to address impacts to these species would also address impacts to critical habitat. Thus, no incremental project modification impacts are expected due to this designation. On this basis, we conclude there will be no national security impacts associated with the proposed critical habitat for the Carolina and South Atlantic DPSs of Atlantic sturgeon.

Other Relevant Impacts
Other relevant impacts of critical habitat designations can include conservation benefits to the species and to society, and impacts to governmental and private entities. Our Draft Impacts Analysis discusses conservation benefits of designating the 14 occupied and 3 unoccupied areas, and the benefits of conserving the Carolina and South Atlantic sturgeon DPSs to society, in both ecological and economic metrics.
As discussed in the Draft Impacts Analysis and summarized here, Atlantic sturgeon currently provide a range of benefits to society. Given the positive benefits of protecting the physical features essential to the conservation of these DPSs, this protection will in turn contribute to an increase in the benefits of this species to society in the future as the species recovers. While we cannot quantify nor monetize these benefits, we believe they are not negligible and would be an incremental benefit of this designation. However, although the features are essential to the conservation of Atlantic sturgeon DPSs, critical habitat designation alone will not bring about the recovery of the species. The benefits of conserving Atlantic sturgeon are, and will continue to be, the result of several laws and regulations.
We identified in the Draft Impacts Analysis both consumptive ( e.g., commercial and recreational fishing) and non-consumptive ( e.g., wildlife viewing) activities that occur in the areas proposed as critical habitat. Commercial and recreational fishing are components of the economy related to the ecosystem services provided by the resources within the proposed Atlantic sturgeon critical habitat areas. The essential features provide for abundant fish species diversity.
Education and awareness benefits stem from the critical habitat designation when non-federal government entities or members of the general public responsible for, or interested in, Atlantic sturgeon conservation change their behavior or activities when they become aware of the designation and the importance of the critical habitat areas and features. Designation of critical habitat raises the public's awareness that there are special considerations that may need to be taken within the area. Similarly, state and local governments may be prompted to carry out programs to complement the critical habitat designation and benefit the Carolina and South Atlantic DPSs of Atlantic sturgeon. Those programs would likely result in additional impacts of the designation. However, it is impossible to quantify the beneficial effects of the awareness gained or the secondary impacts from state and local programs resulting from the critical habitat designation.

Discretionary Exclusions Under Section 4(b)(2)
On the basis of our impacts analysis, we are not proposing to exercise our discretion to propose excluding any particular areas from the proposed critical habitat designation.
Our conservative identification of potential incremental economic impacts indicates that any such impacts would be very small—$50,395 annually for the Carolina DPS critical habitat and $58,884 annually for the South Atlantic DPS critical habitat. These costs will result from very few (about 20) Federal ESA section 7 consultations annually. These consultations will be spread over 4 states and over 3,300 river miles (4,900 river kilometers). Incremental economic impacts will consist solely of the administrative costs of consultation; no project modifications are projected to be required to address impacts solely to the proposed critical habitat. Further, the analysis indicates that there is no particular area within the units designated as critical habitat where economic impacts would be particularly high or concentrated. No impacts to national security are expected. Other relevant impacts include conservation benefits of the designation, both to the species and to society. Because the features that form the basis of the critical habitat designation are essential to the conservation of the Carolina and South Atlantic DPSs of Atlantic sturgeon, the protection of critical habitat from destruction or adverse modification may at minimum prevent loss of the benefits currently provided by the species and may contribute to an increase in the benefits of these species to society in the future. While we cannot quantify nor monetize the benefits, we believe they are not negligible and would be an incremental benefit of this designation. Therefore, we have concluded that there is no basis to exclude any particular area from the proposed critical habitat units.

Proposed Critical Habitat Designation
Critical habitat must be defined by specific limits using reference points and lines as found on standard topographic maps of the area, and cannot use ephemeral reference points (50 CFR 424.12(c)). When several habitats, each satisfying the requirements for designation as critical habitat, are located in proximity to one another, an inclusive area may be designated as critical habitat (50 CFR 424.12(d)).
The habitat containing the physical features that are essential to the conservation of the Carolina and South Atlantic DPSs and that may require special management considerations or protection is aquatic habitat of main stem rivers flowing into a coastal estuary. Atlantic sturgeon typically cannot pass dams or natural features such as waterfalls and rapids found at the fall line of rivers. Therefore, we are defining each critical habitat unit by an upriver GPS position or landmark on the main stem river ( e.g., the most downriver dam) and all waters of the main stem downriver of that location to river kilometer zero (RKM 0). Main stem river is the primary segment of a river and any portions thereof that depart from and rejoin the primary segment. Thus, channels and cuts that depart from and rejoin the main channel are included ( e.g., Middle and Front Rivers are part of the Savannah River).
In order to include areas of dynamic water depth containing suitable spawning habitat, we are relying on the ordinary high water mark (OHWM) to delineate the lateral boundaries of the specific critical habitat areas. Federal regulations at 33 CFR 328.3(e) define OHWM as “that line on the shore established by the fluctuations of water and indicated by physical characteristics such as a clear, natural line impressed on the bank, shelving, changes in the character of soil, destruction of terrestrial vegetation, the presence of litter and debris, or other appropriate means that consider the characteristics of the surrounding areas.”

Occupied Critical Habitat Unit Descriptions
Carolina Unit 1, Roanoke Unit. Roanoke River in Bertie, Halifax, Martin, Northampton, and Washington Counties in North Carolina. Carolina Unit 1 includes the Roanoke River main stem from the Roanoke Rapids Dam downstream to RKM 0.
Carolina Unit 2, Tar-Pamlico Unit. Tar-Pamlico River in Beaufort, Edgecombe, Hyde, Nash, Pamlico, and Pitt Counties in North Carolina. Carolina Unit 2 includes the Tar-Pamlico River main stem from the Rocky Mount Millpond Dam downstream to RKM 0.
Carolina Unit 3, Neuse Unit. Neuse River in Carteret, Craven, Duplin, Johnston, Lenoir, Pamlico, Pitt, Wake, and Wayne Counties in North Carolina.
Carolina Unit 3 includes the Neuse River main stem from the Milburnie Dam downstream to RKM 0. The Neuse River, one of two major tributaries to Pamlico Sound, is dammed. It is likely that Atlantic sturgeon historically utilized habitat in the Neuse River up to the falls at RKM 378 where a dam (Falls Dam) is now located, although this site is above the fall line (ASSRT, 2007). Spawning migration may be impeded to historic habitat above the Milburnie Dam (RKM 349).
Carolina Unit 4, Cape Fear Unit. Cape Fear River in Bladen, Brunswick, Columbus, Cumberland, New Hanover, and Pender Counties in North Carolina and the Northeast Cape Fear River in Duplin, New Hanover, Pender, and Wayne Counties in North Carolina. Carolina Unit 4 includes the Cape Fear River main stem from Lock and Dam #2 downstream to RKM 0 and the Northeast Cape Fear River from the upstream side of Rones Chapel Road Bridge downstream to the confluence with the Cape Fear River.
Carolina Unit 5, Pee Dee Unit. Pee Dee River in Anson and Richmond Counties in North Carolina and Chesterfield, Darlington, Dillon, Florence, Georgetown, Horry, Marion, Marlboro, and Williamsburg Counties in South Carolina; Waccamaw River in Georgetown County in South Carolina; and Bull Creek in Georgetown County in South Carolina. Carolina Unit 5 includes the Pee Dee River main stem from Blewett Falls Dam downstream to RKM 0, the Waccamaw River from Bull Creek downstream to RKM 0, and Bull Creek from the Pee Dee River to the confluence with the Waccamaw River.
Carolina Unit 6. Black River Unit. Black River in Clarendon, Georgetown, Lee, Sumter, and Williamsburg Counties in South Carolina. Carolina Unit 6 includes the Black River main stem from Interstate Highway 20 downstream to RKM 0.
Carolina Unit 7, Santee-Cooper Unit. Santee River in Berkeley, Georgetown, and Williamsburg Counties in South Carolina; North Santee River in Georgetown County in South Carolina; South Santee River in Charleston County in South Carolina; and the Cooper River in Berkeley and Charleston Counties in South Carolina. Carolina Unit 7 includes the Santee River main stem from the Wilson and St. Stephen Dams downstream to the fork of the North Santee River and South Santee River distributaries, the Rediversion Canal from the St. Stephen Powerhouse downstream to the confluence with the Santee River, the North Santee River from the fork of the Santee River and South Santee River downstream to RKM 0, the South Santee River from the fork of the Santee River and North Santee River downstream to RKM 0, the Tailrace Canal from Pinopolis Dam downstream to the West Branch Cooper River, the West Branch Cooper River from the Tailrace Canal downstream to the confluence with the East Branch Cooper River, and the Cooper River from confluence of the West Branch Cooper River and East Branch Cooper River tributaries downstream to RKM 0.
South Atlantic Unit 1, Edisto Unit. The North Fork Edisto in Lexington, and Orangeburg Counties in South Carolina; the South Fork Edisto in Aiken, Bamberg, Barnwell, Edgefield, and Orangeburg Counties in South Carolina; the Edisto River in Bamberg, Charleston, Colleton, Dorchester, and Orangeburg Counties in South Carolina; the North Edisto in Charleston and Colleton Counties in South Carolina; and the South Edisto in Charleston and Colleton Counties in South Carolina. South Atlantic Unit 1 includes the North Fork Edisto River from Cones Pond downstream to the confluence with the South Fork Edisto River, the South Fork Edisto River from Highway 121 downstream to the confluence with the North Fork Edisto River, the Edisto River main stem from the confluence of the North Fork Edisto River and South Fork Edisto River tributaries downstream to the fork at the North Edisto River and South Edisto River distributaries, the North Edisto River from the Edisto River downstream to RKM 0, and the South Edisto River from the Edisto River downstream to RKM 0.
South Atlantic Unit 2, Combahee-Salkehatchie Unit. Combahee-Salkehatchie River in Allendale, Bamberg, Barnwell, Beaufort, Colleton, and Hampton Counties in South Carolina. South Atlantic Unit 2 includes the main stem Combahee—Salkehatchie River from the confluence of Buck Creek and Rosemary Creek with the Salkehatchie River downstream to the Combahee River, the Combahee River from the Salkehatchie River downstream to RKM 0.
South Atlantic Unit 3, Savannah Unit. Savannah River in Aiken, Allendale, Barnwell, Edgefield, Hampton, Jasper and McCormick Counties in South Carolina and Burke, Chatham, Columbia, Effingham, Richmond, and Screven Counties in Georgia. South Atlantic Unit 3 includes the main stem Savannah River from the New Savannah Bluff Lock and Dam downstream to RKM 0.
South Atlantic Unit 4, Ogeechee Unit. Ogeechee River in Bryan, Bulloch, Burke, Chatham, Effingham, Emanuel, Glascock, Jefferson, Jenkins, Screven, and Washington Counties in Georgia. South Atlantic Unit 4 includes the main stem Ogeechee River from the confluence of the North Fork and South Fork Ogeechee Rivers downstream to RKM 0.
South Atlantic Unit 5, Altamaha Unit. Altamaha River in Appling, Jeff Davis, Long, McIntosh, Montgomery, Tattnall, Toombs, and Wheeler Counties in Georgia; the Oconee River in Baldwin, Hancock, Johnson, Laurens, Montgomery, Washington, Wheeler, and Wilkinson Counties in Georgia; and the Ocmulgee River in Ben Hill, Bibb, Bleckley, Dodge, Houston, Jasper, Jeff Davis, Jones, Plaski, Telfair, Twiggs, Wheeler, and Wilcox Counties in Georgia. South Atlantic Unit 5 includes the main stem Ocmulgee River from Juliette Dam downstream to the confluence with the Oconee River, the Oconee River from Sinclair Dam downstream to the confluence with the Ocmulgee, and the Altamaha River from the confluence of the Ocmulgee and Oconee downstream to RKM 0.
South Atlantic Unit 6, Satilla Unit. Satilla River in Atkinson, Brantley, Camden, Charlton, Coffee, Glynn, Irwin, Pierce, Ware, and Wayne Counties in Georgia. South Atlantic Unit 6 includes the main stem Satilla River from the confluence of Satilla Creek and Wiggins Creek downstream to RKM 0.
South Atlantic Unit 7, St. Marys Unit. St. Marys River in Camden and Charlton Counties in Georgia and Baker and Nassau Counties in Florida. South Atlantic Unit 7 includes the main stem St. Marys River from the confluence of Middle Prong St. Marys and the St. Marys Rivers downstream to RKM 0.

Unoccupied Critical Habitat Unit Descriptions
Carolina Unoccupied Unit 1. Cape Fear River in Bladen County in North Carolina. Carolina Unoccupied Unit 1 includes the main stem Cape Fear River from Huske Lock and Dam (Lock and Dam #3) downstream to Lock and Dam #2.
Carolina Unoccupied Unit 2. Wateree River in Kershaw, Richland, and Sumter Counties in South Carolina; Broad River in Lexington and Richland Counties in South Carolina; Congaree River in Calhoun and Richland Counties in South Carolina; Santee River in Calhoun and Sumter Counties in South Carolina; Lake Marion in Berkeley, Calhoun, Clarendon, Orangeburg, and Sumter Counties in South Carolina; Diversion Canal in Orangeburg County in South Carolina; and, Lake Moultrie in Berkeley and Orangeburg Counties in South Carolina. Carolina Unoccupied Unit 2 includes the Wateree River from the Wateree Dam downstream to the confluence with the Congaree River, the Broad River from the Parr Shoals Dam downstream to the confluence with the Saluda River, the Congaree River from the confluence of the Saluda and Broad Rivers downstream to the Santee River, the Santee River from the confluence of the Congaree and Wateree Rivers downstream to Lake Marion, Lake Marion from the Santee River downstream to the Diversion Canal, the Diversion Canal from Lake Marion downstream to Lake Moultrie, Lake Moultrie from the Diversion Canal downstream to the Pinopolis Dam and the Rediversion Canal, the Rediversion Canal from Lake Moultrie downstream to the St. Stephen Powerhouse.
South Atlantic Unoccupied Unit 1. Savannah River in Aiken and Edgefield Counties in South Carolina and Columbia and Richmond Counties in Georgia. South Atlantic Unoccupied Unit 1 includes the Savannah River from the Augusta Diversion Dam downstream to the New Savannah Bluff Lock and Dam.

Effects of Critical Habitat Designations
Section 7(a)(2) of the ESA requires Federal agencies, including NMFS, to insure that any action authorized, funded, or carried out by the agency does not jeopardize the continued existence of any threatened or endangered species or destroy or adversely modify designated critical habitat. Federal agencies are also required to confer with NMFS regarding any actions likely to jeopardize a species proposed for listing under the ESA, or likely to destroy or adversely modify proposed critical habitat, pursuant to Section 7(a)(4). A conference involves informal discussions in which NMFS may recommend conservation measures to minimize or avoid adverse effects. The discussions and conservation recommendations are to be documented in a conference report provided to the Federal agency. If requested by the Federal agency, a formal conference report may be issued, including a biological opinion prepared according to 50 CFR 402.14. A formal conference report may be adopted as the biological opinion when the species is listed or critical habitat designated, if no significant new information or changes to the action alter the content of the opinion. When a species is listed or critical habitat is designated, Federal agencies must consult with NMFS on any agency actions to be conducted in an area where the species is present and that may affect the species or its critical habitat. During the consultation, NMFS would evaluate the agency action to determine whether the action may adversely affect listed species or critical habitat and issue its findings in a biological opinion. If NMFS concludes in the biological opinion that the agency action would likely result in the destruction or adverse modification of critical habitat, NMFS would also recommend any reasonable and prudent alternatives to the action. Reasonable and prudent alternatives are defined in 50 CFR 402.02 as alternative actions identified during formal consultation that can be implemented in a manner consistent with the intended purpose of the action, that are consistent with the scope of the Federal agency's legal authority and jurisdiction, that are economically and technologically feasible, and that would avoid the destruction or adverse modification of critical habitat. Regulations at 50 CFR 402.16 require federal agencies that have retained discretionary involvement or control over an action, or where such discretionary involvement or control is authorized by law, to reinitiate consultation on previously reviewed actions in instances where: (1) Critical habitat is subsequently designated; or (2) new information or changes to the action may result in effects to critical habitat not previously considered in the biological opinion. Consequently, some Federal agencies may request reinitiation of consultation or conference with NMFS on actions for which formal consultation has been completed, if those actions may affect designated critical habitat or adversely modify or destroy proposed critical habitat. Activities subject to the ESA Section 7 consultation process include activities on Federal lands and activities on private or state lands requiring a permit from a Federal agency or some other Federal action, including funding. In the marine and aquatic environments, activities subject to the ESA Section 7 consultation process include activities in Federal waters and in state waters that: (1) Have the potential to affect listed species or critical habitat; and (2) are carried out by a Federal agency, need a permit or license from a Federal agency, or receive funding from a Federal agency. ESA Section 7 consultation would not be required for Federal actions that do not affect listed species or critical habitat and for actions that are not Federally funded, authorized, or carried out.

Activities That May be Affected
Section 4(b)(8) of the ESA requires that we describe briefly and evaluate in any proposed or final regulation to designate critical habitat, those activities that may adversely modify such habitat or that may be affected by such designation. As described in our Draft Impacts Analysis, a wide variety of activities may affect critical habitat and, when carried out, funded, or authorized by a Federal agency, will require an ESA Section 7 consultation because they may affect one or more of the essential features of critical habitat. Such activities include in-water construction for a variety of federal actions, dredging for navigation, harbor expansion or sand and gravel mining, flood control projects, bridge repair and replacement, hydropower licensing, natural gas facility and pipeline construction, ESA research and incidental take permits or fishery research grants, and Clean Water Act TMDL program management. Private entities may also be affected by these proposed critical habitat designations if they are a proponent of a project that requires a Federal permit, Federal funding is received, or the entity is involved in or receives benefits from a Federal project. Future activities will need to be evaluated with respect to their potential to destroy or adversely modify critical habitat. For example, activities may adversely modify the substrate essential feature by removing or altering the substrate. The open passage feature may be adversely modified by the placement of structures such as dams and tidal turbines, research nets, or altering the water depth so that fish cannot swim. The salinity feature may be adversely modified by activities that impact fresh water input such as operation of water control structures and water withdrawals, and impacts to water depth such as dredging. The water quality feature may be adversely modified by land development as well as commercial and recreational activities on rivers that contribute to nutrient loading which could result in decreased dissolved oxygen levels and increased water temperature, and increased sediment deposition that reduces Atlantic sturgeon egg adherence on hard spawning substrate and reduces the interstitial spaces used by larvae for refuge from predators. Dredging to remove sediment build-up or to facilitate vessel traffic may remove or alter hard substrate that is necessary for egg adherence and as refuge for larvae, and may change the water depth resulting in shifts in the salt wedge within the estuary or change other characteristics of the water quality ( e.g., temperature, dissolved oxygen) necessary for the developing eggs, larvae, and juveniles. These activities would require ESA Section 7 consultation when they are implemented, funded, or carried out by a federal agency.
Questions regarding whether specific activities will constitute destruction or adverse modification of critical habitat should be directed to us (see ADDRESSES and FOR FURTHER INFORMATION CONTACT ).

Public Comments Solicited
We request that interested persons submit comments, information, and suggestions concerning this proposed rule during the comment period (see DATES ). We are soliciting comments or suggestions from the public, other concerned governments and agencies, the scientific community, industry, or any other interested party concerning this proposed rule, including any foreseeable economic, national security, or other relevant impact resulting from the proposed designations. You may submit your comments and materials concerning this proposal by any one of several methods (see ADDRESSES ). Copies of the proposed rule and supporting documentation can be found on the NMFS Southeast Region Web site at http://sero.nmfs.noaa.gov/. We will consider all comments pertaining to this designation received during the comment period in preparing the final rule. Accordingly, the final designation may differ from this proposal.

Information Quality Act and Peer Review
The data and analyses supporting this proposed action have undergone a pre-dissemination review and have been determined to be in compliance with applicable information quality guidelines implementing the Information Quality Act (Section 515 of Public Law 106-554). On July 1, 1994, a joint USFWS/NMFS policy for peer review was issued stating that the Services would solicit independent peer review to ensure the best biological and commercial data is used in the development of rulemaking actions and draft recovery plans under the ESA (59 FR 34270). In addition, on December 16, 2004, the Office of Management and Budget (OMB) issued its Final Information Quality Bulletin for Peer Review (Bulletin). The Bulletin was published in the Federal Register on January 14, 2005 (70 FR 2664), and went into effect on June 16, 2005. The primary purpose of the Bulletin is to improve the quality and credibility of scientific information disseminated by the Federal government by requiring peer review of `influential scientific information” and “highly influential scientific information” prior to public dissemination. “Influential scientific information” is defined as “information the agency reasonably can determine will have or does have a clear and substantial impact on important public policies or private sector decisions.” The Bulletin provides agencies broad discretion in determining the appropriate process and level of peer review. Stricter standards were established for the peer review of “highly influential scientific assessments,” defined as information whose “dissemination could have a potential impact of more than $500 million in any one year on either the public or private sector or that the dissemination is novel, controversial, or precedent-setting, or has significant interagency interest.”
The information in the Draft Impacts Analysis Report supporting this proposed critical habitat rule is considered influential scientific information and subject to peer review. To satisfy our requirements under the OMB Bulletin, we obtained independent peer review of the information used to draft this document, and incorporated the peer review comments into this draft prior to dissemination of this proposed rulemaking. For this action, compliance with the OMB Peer Review Bulletin satisfies any peer review requirements under the 1994 joint peer review policy. Comments received from peer reviewers are available on our Web site at http://sero.nmfs.noaa.gov/protected_resources/sturgeon/index.html.

Classification

Takings (Executive Order 12630)
Under E.O. 12630, Federal agencies must consider the effects of their actions on constitutionally protected private property rights and avoid unnecessary takings of property. A taking of property includes actions that result in physical invasion or occupancy of private property, and regulations imposed on private property that substantially affect its value or use. In accordance with E.O. 12630, this proposed rule would not have significant takings implications. A takings implication assessment is not required.

Regulatory Planning and Review (Executive Order 12866)
This proposed rule has been determined to be significant for purposes of E.O. 12866 because it may create a serious inconsistency or otherwise interfere with an action taken or planned by another agency. A draft economic impacts report has been prepared to support an impacts analysis under section 4(b)(2) of the ESA.

Federalism (Executive Order 13132)
Pursuant to the Executive Order on Federalism, E.O. 13132, we determined that this proposed rule does not have significant Federalism effects and that a Federalism assessment is not required. However, in keeping with Department of Commerce policies and consistent with ESA regulations at 50 CFR 424.16(c)(1)(ii), we will request information for this proposed rule from state resource agencies in North Carolina, South Carolina, Georgia, and Florida. The proposed designations may have some benefit to state and local resource agencies in that the proposed rule more clearly defines the physical and biological features essential to the conservation of the species and the areas on which those features are found.

Energy Supply, Distribution, and Use (Executive Order 13211)
Executive Order 13211 requires agencies to prepare Statements of Energy Effects when undertaking an action expected to lead to the promulgation of a final rule or regulation that is a significant regulatory action under E.O. 12866 and is likely to have a significant adverse effect on the supply, distribution, or use of energy. OMB Guidance on Implementing E.O. 13211 (July 13, 2001) states that significant adverse effects could include any of the following outcomes compared to a world without the regulatory action under consideration: (1) Reductions in crude oil supply in excess of 10,000 barrels per day; (2) reductions in fuel production in excess of 4,000 barrels per day; (3) reductions in coal production in excess of 5 million tons per year; (4) reductions in natural gas production in excess of 25 million cubic feet per year; (5) reductions in electricity production in excess of 1 billion kilowatt-hours per year or in excess of 500 megawatts of installed capacity; (6) increases in energy use required by the regulatory action that exceed any of the thresholds above; (7) increases in the cost of energy production in excess of one percent; (8) increases in the cost of energy distribution in excess of one percent; or (9) other similarly adverse outcomes. A regulatory action could also have significant adverse effects if it: (1) Adversely affects in a material way the productivity, competition, or prices in the energy sector; (2) adversely affects in a material way productivity, competition or prices within a region; (3) creates a serious inconsistency or otherwise interferes with an action taken or planned by another agency regarding energy; or (4) raises novel legal or policy issues adversely affecting the supply, distribution or use of energy arising out of legal mandates, the President's priorities, or the principles set forth in E.O. 12866 and 13211.
This rule, if finalized, will not have a significant adverse effect on the supply, distribution, or use of energy. Therefore, we have not prepared a Statement of Energy Effects.

Regulatory Flexibility Act (5 U.S.C. 601 et seq. )
We prepared an initial regulatory flexibility analysis (IRFA) pursuant to section 603 of the Regulatory Flexibility Act (RFA) (5 U.S.C. 601, et seq. ). The IRFA analyzes the impacts to those areas where critical habitat is proposed and is included as Appendix A of the Draft Impacts Analysis Report and is available upon request (see ADDRESSES section). The IRFA is summarized below, as required by section 603 of the RFA. The IRFA describes the economic impact this proposed rule, if adopted, would have on small entities.
As discussed previously and in our IRFA, the designation of critical habitat is required under the ESA, and in this particular case, is also required pursuant to a court-ordered settlement agreement. The purpose of the critical habitat designation, as required by the ESA, is to designate, to the maximum extent prudent and determinable, the specific areas that contain the physical or biological features essential to the conservation of the species and that may require special management considerations or protections. The proposed critical habitat rule does not directly apply to any particular entity, small or large. The rule would operate in conjunction with ESA Section 7(a)(2), which requires that federal agencies insure, in consultation with NMFS, that any action they authorize, fund, or carry out is not likely to jeopardize the continued existence of listed species or destroy or adversely modify critical habitat. Consultations may result in economic impacts to federal agencies and proponents of proposed actions ( e.g., permittees, applicants, grantees). Those economic impacts may be in the form of administrative costs of participating in a Section 7 consultation and, if the consultation results in required measures to protect critical habitat, project modification costs.
We evaluated whether predicted future federal actions would affect Atlantic sturgeon, the essential features of the proposed critical habitat, or both, or whether there were other identifiable baseline impacts that might be coextensive with impacts to habitat features, such as impacts to shortnose sturgeon. If a proposed action affects only listed sturgeon or affects both listed sturgeon and essential features, the administrative and project modification costs are not necessarily attributable solely to critical habitat designation. In these circumstances, the added administrative costs associated with addressing critical habitat in a consultation were considered incremental impacts of the proposed designation. There could also be incremental project modification costs for consultations with coextensive impacts, if an action is considered likely to require unique project modifications to specifically address impacts to the features. If a proposed action would only affect the essential features, the administrative and project modification costs would be attributable to the critical habitat designation and thus treated as incremental impacts of the designation.
For most, if not all, of the federal activities predicted to occur in the next 10 years, if the effects to critical habitat will be adverse and require formal consultation, those effects would also constitute adverse effects to Atlantic sturgeon or shortnose sturgeon, either directly when they are in the project area, or indirectly due to the effects on their habitat. Thus, as discussed previously, projects that adversely affect the proposed essential features are likely to always also adversely affect the species and the project impacts would not be incremental. Therefore, the only costs of this class of actions that are attributable to this rule are the administrative costs of adding critical habitat analyses to a consultation that would occur anyway, due to impacts to sturgeon species.
For some of the predicted future federal activities, it may be feasible to conduct the action when sturgeon are out of the action area. If effects to critical habitat are temporary such that the essential features return to their pre-project condition by the time the sturgeon return and need to use the features, there might not be any adverse effects to either the species or the critical habitat. In these circumstances, consultations would be fully incremental consultations only on critical habitat, and the consultations would be informal. This would likely only apply to actions that affect just spawning habitat in the upper parts of the rivers, as sturgeon of various ages are present year-round in the lower reaches of the rivers and the estuaries. Because the costs of fully incremental informal consultations are higher than the marginal costs of adding critical habitat analyses to coextensive formal consultations, we conservatively assumed future actions will be incremental informal consultations, where applicable. Thus, the costs of these future activities that are attributable to the rule would consist of the full costs of informal consultation, to NMFS, to the action agency, and to any third party proponent of the action ( e.g., applicant, permittee).
Ten different federal entities implemented or approved 14 different categories of activities in the areas covered by the proposed critical habitat units that required consultations in the past. All categories of activities implemented by these federal entities were identified as having the potential to affect the essential features. The total number of projected consultations over 10 years is indicated in parentheses below.
1. USACE—Navigation maintenance dredging, harbor expansion (14)
2. USACE—WRDA flood control, ecosystem restoration studies (6)
3. USACE—WRDA dam operations, repair, fishway construction (3)
4. USACE—Section 404/RHA section 10 permitting—dredge, fill, construction (20)
5. FHWA—Bridge repair, replacement (67)
6. USCG—Bridge repair, replacement permitting (3)
7. FERC—Hydropower licensing (5)
8. FERC—LNG facilities, pipelines authorization (5)
9. NRC—Nuclear power plant construction/operation licensing (8)
10. NMFS—ESA research or incidental take permitting (section 10) (46)
11. USFWS—Fishery management grants (11)
12. EPA—Nationwide pesticide authorizations (9)
13. FEMA—Disaster assistance/preparation grants (5)
14. DOE—Nuclear fuel management (3)
We predict that a total of 205 federal actions will require consultation due to impacts to critical habitat over the next 10 years; of these, we project that 179 actions could involve third parties that might be small entities. One hundred fifty-six projected future federal actions that could involve third parties will consist of coextensive formal consultations considering impacts to both sturgeon and critical habitat. The administrative costs of consultation to third parties per consultation from these actions will either be $880 or $2,080, depending upon whether they bear the costs of completing a biological assessment. The 23 projected future actions that would be fully incremental and that could involve third parties would result in either $1,500 or $3,000 in costs to such third parties per consultation, depending upon whether they bear the costs of completing a biological assessment. Given the EPA consultations will be national in scope and involve all of NMFS's listed species and designated critical habitats, costs to third parties involved in the these consultations that are attributable to this rulemaking are conservatively estimated to be $25,072 for all units over 10 years.
Businesses in North American Industry Classification System (NAICS) Subsector 325320, Pesticide and Other Agricultural Chemical Manufacturing, could be involved in the 5 nationwide EPA pesticide authorization consultations. A small business in this Subsector is defined by the SBA as having 1,000 employees ( https://www.sba.gov/sites/default/files/files/Size_Standards_Table.pdf).
Businesses in North American Industry Classification System (NAICS) Sector 22 (Utilities) could be involved in 18 actions projected to occur in federal action categories 7-9. For hydropower power generation and natural gas distribution enterprises, a small business is defined by the SBA as one having a total of 500 employees. For nuclear power generation, a small business is defined by the SBA as one having a total of 750 employees. Businesses in NAICS Sector 54 could be involved as contractors assisting with the ESA consultation in any of the 179 projected future federal actions that could involve third parties. Relevant subsectors could include 541370, Surveying and Mapping, 541620, Environmental Consulting Services, or 541690, Other Scientific and Technical Consulting Services. A small business in any of these subsectors is defined by the SBA as one having average annual receipts of $15 million.
Businesses in NAICS Sector 23, Construction, could be involved in a number of categories of projected future actions, where they could incur administrative costs of construction. Businesses in subsector 237120, Oil and Gas Pipeline and Related Structures Construction, could be involved in the 3 FERC LNG pipeline consultations. A small business in this subsector has average annual receipts of $36.5 million. Businesses in subsector 237310, Highway, Street, and Bridge Construction, could be involved in the 70 FHWA and USCG bridge repair, replacement consultations. A small business in this subsector has average annual receipts of $36.5 million.
Businesses in subsector 238, Other Specialty Trade Contractors, could be involved as construction contractors in the 20 future USACE section 404/RHA permitting actions and the 5 FEMA disaster assistance actions. Small businesses in this subsector have average annual receipts of $15 million.
Cities could be involved in many of the 70 FHWA and USCG bridge repair, replacement projects, and some proportion of the 20 USACE section 404/RHA permitting actions. The SBA defines a small governmental jurisdiction as cities, counties, towns, townships, villages, school districts, or special districts with a population of less than 50,000.
Our consultation database does not track the identity of past third parties involved in consultations, or whether the third parties were small entities; therefore we have no basis to determine the percentage of the 179 third parties that may potentially be involved in future consultations due to impacts to proposed critical habitat that may be small businesses, small nonprofits, or small government jurisdictions.
There is no indication in the data evaluated in the Draft Impacts Analysis Report, which serves as the basis for this IRFA, that the designation would place small entities at a competitive disadvantage compared to large entities. Incremental economic impacts due to the designation proposed for the Carolina and South Atlantic DPSs will be minimal overall. These costs will result from participation in the Section 7 consultation process, and will be spread over 14 river systems totaling over 3,300 river miles in 4 states. Federal agencies will bear the majority of the costs (59% to 83%), which will be limited to administrative costs of consultation for all parties involved. There are no apparent concentrations of costs. Assuming a third party would be involved and incur costs for each of the 179 projects in all of the categories of federal activity that involved third parties in the past, the costs to third parties that could be involved in the projected future consultations, other than the EPA consultations, would be between $880 and $2,080 for each action for coextensive formal consultations, and between $1,500 and $3,000 for each fully incremental informal consultation. The total costs over the next 10 years to all third parties for these 2 classes of actions would be between $30,000 and $60,000 for the incremental informal consultations and between $136,400 and $322,400 for the coextensive consultations. The total costs over the next 10 years to third parties involved in the EPA consultations are conservatively estimated to be $25,072 across all units.
Even though we cannot determine relative numbers of small and large entities that may be affected by the designation of critical habitat, there is no indication that affected project applicants would be limited to, nor disproportionately comprised of, small entities. It is unclear whether small entities would be placed at a competitive disadvantage compared to large entities. However, as described in the Draft Impacts Analysis Report, consultations and project modifications will be required based on the type of permitted action and its associated impacts on the essential critical habitat features.
It is unlikely that the proposed rule will significantly reduce profits or revenue for small businesses, if they are involved in future consultations required by this rulemaking, given costs will be limited to administrative costs of participating in the consultation process and the maximum cost of a single consultation to a third party is projected to be $3,000.
We encourage all small businesses, small nonprofits and small governmental jurisdictions that may be affected by this rule to provide comment on the potential economic impacts of the proposed designation, to improve the above analysis.
There are no record-keeping or reporting requirements associated with the proposed rule. Similarly, there are no other compliance requirements in the rule. There are no professional skills necessary for preparation of any report or record, although consultants are frequently involved on behalf of project proponents, for example in preparing biological assessments of the impacts of a proposed action on listed species and critical habitat. Federal laws and regulations that directly and indirectly protect the Carolina and South Atlantic DPSs of Atlantic sturgeon are listed and discussed in the Draft Impacts Analysis Report. No federal laws or regulations duplicate or conflict with the proposed rule. Existing federal laws and regulations overlap with the proposed rule only to the extent that they provide protection to marine natural resources. However, no existing laws or regulations specifically address negative impacts to, or require the avoidance of the destruction or adverse modification of, the essential features of critical habitat for the Carolina and South Atlantic DPSs of Atlantic sturgeon.
We considered a no action (status quo) alternative to the proposed designation under which NMFS would not propose critical habitat for the Carolina and South Atlantic DPSs of Atlantic sturgeon. Under this alternative, conservation and recovery of the listed species would depend upon the protection provided under the “jeopardy” provisions of Section 7 of the ESA. Compared to the status quo, there would be no increase in the number of ESA consultations or project modifications in the future that would not otherwise be required due to the listing of the Carolina and South Atlantic DPSs of Atlantic sturgeon. However, we have determined that the physical features forming the basis for our proposed critical habitat designation are essential to the conservation of the Carolina and South Atlantic DPSs of Atlantic sturgeon. Thus, the lack of protection of the essential features from adverse modification and/or destruction could result in decline in abundance of the Carolina and South Atlantic DPSs of Atlantic sturgeon, and loss of associated economic and other values this species provides to society. Thus, the no action alternative is not necessarily a “no cost” alternative for small entities.
We also considered an alternative of including all large coastal rivers from the North Carolina/Virginia border southward to the St Johns River, Florida, in the designation. Several large coastal rivers within the geographic area occupied by the Carolina and South Atlantic DPSs of Atlantic sturgeon do not appear to support spawning and juvenile recruitment or to contain suitable habitat features to support spawning. These rivers are the Chowan and New Rivers in North Carolina; the Waccamaw (above its confluence with Bull Creek which links it to the Pee Dee River), Sampit, Ashley, Ashepoo, and Broad-Coosawhatchie Rivers in South Carolina; and the St. Johns River, Florida. We have no information, current or historic, of Atlantic sturgeon utilizing the Chowan and New Rivers in North Carolina. Recent telemetry work by Post et al. (2014) indicates that Atlantic sturgeon do not utilize the Sampit, Ashley, Ashepoo, and Broad-Coosawhatchie Rivers in South Carolina. These rivers are short, coastal plains rivers that most likely do not contain suitable habitat for Atlantic sturgeon. Post et al. (2014) also found Atlantic sturgeon only utilized the portion of the Waccamaw River downstream of Bull Creek. Due to man-made structures and alterations, spawning areas in the St. Johns are not accessible and therefore do not support a reproducing population. For these reasons, we are not designating these coastal rivers, or portions of the rivers, as critical habitat.

Coastal Zone Management Act
We have determined that this action will have no reasonably foreseeable effects on the enforceable policies of approved Coastal Zone Management Programs of North Carolina, South Carolina, Georgia and Florida. Upon publication of this proposed rule, these determinations will be submitted for review by the responsible state agencies under section 307 of the Coastal Zone Management Act.

Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq. )
This proposed rule does not contain any new or revised collection of information. This rule, if adopted, would not impose recordkeeping or reporting requirements on State or local governments, individuals, businesses, or organizations.

Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq. )
This proposed rule will not produce a Federal mandate. The designation of critical habitat does not impose a legally-binding duty on non-Federal government entities or private parties. The only regulatory effect is that Federal agencies must ensure that their actions do not destroy or adversely modify critical habitat under Section 7 of the ESA. Non-Federal entities which receive Federal funding, assistance, permits or otherwise require approval or authorization from a Federal agency for an action may be indirectly impacted by the designation of critical habitat, but the Federal agency has the legally binding duty to avoid destruction or adverse modification of critical habitat.
We do not anticipate that this rule, if finalized, will significantly or uniquely affect small governments. Therefore, a Small Government Action Plan is not required.

Consultation and Coordination With Indian Tribal Governments (Executive Order 13175)
The longstanding and distinctive relationship between the Federal and tribal governments is defined by treaties, statutes, executive orders, judicial decisions, and agreements, which differentiate tribal governments from the other entities that deal with, or are affected by, the Federal Government.
Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, outlines the responsibilities of the Federal Government in matters affecting tribal interests. If NMFS issues a regulation with tribal implications (defined as having a substantial direct effect 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) we must consult with those governments or the Federal Government must provide funds necessary to pay direct compliance costs incurred by tribal governments. The proposed critical habitat designations for the Carolina and South Atlantic DPSs do not have tribal implications.

References Cited
A complete list of all references cited in this rulemaking can be found on our Web site at http://sero.nmfs.noaa.gov/protected_resources/sturgeon/index.html and is available upon request from the NMFS Southeast Region Fisheries Office in St. Petersburg, Florida (see ADDRESSES ).

List of Subjects in 50 CFR part 226
Endangered and threatened species.
Dated: May 24, 2016.
Samuel D Rauch, III

Deputy Assistant Administrator for Regulatory Programs, National Marine Fisheries Service.
For the reasons set out in the preamble, we propose to amend 50 CFR part 226 as follows:

PART 226—DESIGNATED CRITICAL HABITAT
1. The authority citation for part 226 continues to read as follows:

Authority:
16 U.S.C. 1533.
2. Add § 226.226 to read as follows:
§ 226.226
Critical habitat for the Carolina and South Atlantic distinct population Segments of Atlantic sturgeon.
Critical habitat is designated for the Carolina and South Atlantic DPSs of Atlantic sturgeon as described in paragraphs (a) through (b) of this section. The textual descriptions in paragraphs (c) through (d) of this section are the definitive source for determining the critical habitat boundaries.
(a) The physical features essential for the conservation of Atlantic sturgeon belonging to the Carolina and South Atlantic Distinct Population Segments are those habitat components that support successful reproduction and recruitment. These are:
(1) Suitable hard bottom substrate ( e.g., rock, cobble, gravel, limestone, boulder, etc.) in low salinity waters ( i.e., 0.0-0.5 parts per thousand range) for settlement of fertilized eggs and refuge, growth, and development of early life stages;
(2) Transitional salinity zones inclusive of waters with a gradual downstream gradient of 0.5-30 parts per thousand and soft substrate ( e.g., sand, mud) downstream of spawning sites for juvenile foraging and physiological development;
(3) Water of appropriate depth and absent physical barriers to passage ( e.g., locks, dams, reservoirs, gear, etc.) between the river mouth and spawning sites necessary to support:
(i) Unimpeded movement of adults to and from spawning sites;
(ii) Seasonal and physiologically dependent movement of juvenile Atlantic sturgeon to appropriate salinity zones within the river estuary; and
(iii) Staging, resting, or holding of subadults or spawning condition adults. Water depths in main river channels must also be deep enough (at least 1.2 m) to ensure continuous flow in the main channel at all times when any sturgeon life stage would be in the river;
(4) Water quality conditions, especially in the bottom meter of the water column, with temperature and oxygen values that support:
(i) Spawning;
(ii) Annual and inter-annual adult, subadult, larval, and juvenile survival; and
(iii) Larval, juvenile, and subadult growth, development, and recruitment. Appropriate temperature and oxygen values will vary interdependently, and depending on salinity in a particular habitat. For example, 6 mg/L dissolved oxygen (D.O.) for juvenile rearing habitat is considered optimal, whereas D.O. less than 5.0 mg/L for longer than 30 days is considered suboptimal when water temperature is greater than 25°C. In temperatures greater than 26°C, D.O. greater than 4.3 mg/L is needed to protect survival and growth. Temperatures of 13° C to 26° C for spawning habitat are considered optimal
(b) Critical habitat is designated for the following DPSs in the following states and counties:
DPS | State—Counties
Carolina | NC—Anson, Bertie, Beaufort, Bladen, Brunswick, Carteret, Craven, Columbus, Duplin, Edgecombe, Halifax, Hyde, Johnston, Lenoir, Martin, Nash, New Hanover, Northampton, Pamlico, Pender, Pitt, Richmond, Wake, Washington, and Wayne SC—Berkeley, Calhoun, Charleston, Chesterfield, Clarendon, Darlington, Dillon, Fairfield, Florence, Kershaw, Georgetown, Horry, Lee, Lexington, Marion, Marlboro, Newberry, Orangeburg, Richland, Sumter, and Williamsburg
South Atlantic | SC—Aiken, Allendale, Bamberg, Barnwell, Beaufort, Charleston, Colleton, Dorchester, Edgefield, Hampton, Jasper, Lexington, and Orangeburg GA—Appling, Atkinson, Baldwin, Ben Hill, Bibb, Bleckley, Brantley, Bryan, Bulloch, Burke, Camden, Charlton, Chatham, Coffee, Columbia, Dodge, Effingham, Emanuel, Glascock, Glynn, Hancock, Houston, Irwin, Jasper, Jeff Davis, Jefferson, Jenkins, Johnson, Jones, Laurens, Long, McIntosh, Montgomery, Pierce, Plaski, Richmond, Screven, Tattnall, Telfair, Toombs, Twiggs, Ware, Washington, Wayne, Wheeler, and Wilkinson FL—Baker and Nassau
(c) Critical Habitat Boundaries of the Carolina DPS. The lateral extent for all critical habitat units for the Carolina DPS of Atlantic sturgeon is the ordinary high water mark on each bank of the river and shorelines. Critical habitat for the Carolina DPS of Atlantic sturgeon is:
(1) Carolina Unit 1 includes the Roanoke River main stem from the Roanoke Rapids Dam downstream to RKM 0;
(2) Carolina Unit 2 includes the Tar-Pamlico River main stem from the Rocky Mount Millpond Dam downstream to RKM 0;
(3) Carolina Unit 3 includes the Neuse River main stem from the Milburnie Dam downstream to RKM 0;
(4) Carolina Unit 4 includes the Cape Fear River main stem from Lock and Dam #2 downstream to RKM 0 and the Northeast Cape Fear River from the upstream side of Rones Chapel Road Bridge downstream to the confluence with the Cape Fear River;
(5) Carolina Unit 5 includes the Pee Dee River main stem from Blewett Falls Dam downstream to RKM 0, the Waccamaw River from Bull Creek downstream to RKM 0, and Bull Creek from the Pee Dee River to the confluence with the Waccamaw River;
(6) Carolina Unit 6 includes the Black River main stem from Interstate Highway 20 downstream to RKM 0;
(7) Carolina Unit 7 includes the Santee River main stem from the Wilson Dam downstream to the fork of the North Santee River and South Santee River distributaries, the Rediversion Canal from the St. Stephen Powerhouse downstream to the confluence with the Santee River, the North Santee River from the fork of the Santee River and South Santee River downstream to RKM 0, the South Santee River from the fork of the Santee River and North Santee River downstream to RKM 0, the Tailrace Canal from Pinopolis Dam downstream to the West Branch Cooper River, the West Branch Cooper River from the Tailrace Canal downstream to the confluence with the East Branch Cooper River, and the Cooper River from confluence of the West Branch Cooper River and East Branch Cooper River tributaries downstream to RKM 0;
(8) Carolina Unoccupied Unit 1 includes the Cape Fear River from Huske Lock and Dam (Lock and Dam #3) downstream to Lock and Dam #2; and
(9) Carolina Unoccupied Unit 2 includes the Wateree River from the Wateree Dam downstream to the confluence with the Congaree River, the Broad River from the Parr Shoals Dam downstream to the confluence with the Saluda River, the Congaree River from the confluence of the Saluda River and Broad River downstream to the Santee River, the Santee River from the confluence of the Congaree River and Wateree River downstream to Lake Marion, Lake Marion from the Santee River downstream to the Diversion Canal, the Diversion Canal from Lake Marion downstream to Lake Moultrie, Lake Moultrie from the Diversion Canal downstream to the Pinopolis Dam and the Rediversion Canal, the Rediversion Canal from Lake Moultrie downstream to the St. Stephen Powerhouse.
(d) Areas Not Included in Critical Habitat. Pursuant to ESA section 3(5)(A)(i), all areas containing existing (already constructed) federally authorized or permitted man-made structures such as aids-to-navigation (ATONs), artificial reefs, boat ramps, docks, pilings, maintained channels, or marinas.
(e) Maps of The Carolina DPS follow:
(d) Critical Habitat Boundaries of the South Atlantic DPS. The lateral extent for all critical habitat units for the South Atlantic DPS of Atlantic sturgeon is the ordinary high water mark on each bank of the river and shorelines. Critical habitat for the South Atlantic DPS of Atlantic sturgeon is:
(1) South Atlantic Unit 1 includes the North Fork Edisto River from Cones Pond downstream to the confluence with the South Fork Edisto River, the South Fork Edisto River from Highway 121 downstream to the confluence with the North Fork Edisto River, the Edisto River main stem from the confluence of the North Fork Edisto River and South Fork Edisto River tributaries downstream to the fork at the North Edisto River and South Edisto River distributaries, the North Edisto River from the Edisto River downstream to RKM 0, and the South Edisto River from the Edisto River downstream to RKM 0;
(2) South Atlantic Unit 2 includes the main stem Combahee—Salkehatchie River from the confluence of Buck and Rosemary Creeks with the Salkehatchie River downstream to the Combahee River, the Combahee River from the Salkehatchie River downstream to RKM 0;
(3) South Atlantic Unit 3 includes the main stem Savannah River from the New Savannah Bluff Lock and Dam downstream to RKM 0;
(4) South Atlantic Unit 4 includes the main stem Ogeechee River from the confluence of the North Fork Ogeechee River and South Fork Ogeechee River downstream to RKM 0;
(5) South Atlantic Unit 5 includes the main stem Oconee River from Sinclair Dam downstream to the confluence with the Ocmulgee River, the main stem Ocmulgee River from Juliette Dam downstream to the confluence with the Oconee River, and the main stem Altamaha River from the confluence of the Oconee River and Ocmulgee River downstream to RKM 0;
(6) South Atlantic Unit 6 includes the main stem Satilla River from the confluence of Satilla and Wiggins Creeks downstream to RKM 0;
(7) South Atlantic Unit 7 includes the main stem St. Marys River from the confluence of Middle Prong St. Marys and the St. Marys Rivers downstream to RKM 0; and
(8) South Atlantic Unoccupied Unit 1 includes the main stem Savannah River from the Augusta Diversion Dam downstream to the New Savannah Bluff Lock and Dam.
(9) Maps of the South Atlantic DPS follow:
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Presidential Documents
Part VII
Proclamation 9455—African-American Music Appreciation Month, 2016
Proclamation 9456—Great Outdoors Month, 2016
Proclamation 9457—Lesbian, Gay, Bisexual, and Transgender Pride Month, 2016
Proclamation 9458—National Caribbean-American Heritage Month, 2016
Proclamation 9459—National Oceans Month, 2016
Proclamation 9455 of May 31, 2016

African-American Music Appreciation Month, 2016
A Proclamation
A vital part of our Nation's proud heritage, African-American music exemplifies the creative spirit at the heart of American identity and is among the most innovative and powerful art the world has ever known. It accompanies us in our daily lives, and it has rung out at turning points in our history and demonstrated how our achievements as a culture go hand-in-hand with our progress as a Nation. During African-American Music Appreciation Month, we honor the artists who, through this music, bring us together, show us a true reflection of ourselves, and inspire us to reach for the harmony that lies beyond our toughest struggles.
Songs by African-American musicians span the breadth of the human experience and resonate in every corner of our Nation—animating our bodies, stimulating our imaginations, and nourishing our souls. In the ways they transform real stories about real people into art, these artists speak to universal human emotion and the restlessness that stirs within us all. African-American music helps us imagine a better world, and it offers hope that we will get there together.
This month, we celebrate the music that reminds us that our growth as a Nation and as people is reflected in our capacity to create great works of art. Let us recognize the performers behind this incredible music, which has compelled us to stand up—to dance, to express our faith through song, to march against injustice, and to defend our country's enduring promise of freedom and opportunity for all.
NOW, THEREFORE, I, BARACK OBAMA, President of the United States of America, by virtue of the authority vested in me by the Constitution and the laws of the United States, do hereby proclaim June 2016 as African-American Music Appreciation Month. I call upon public officials, educators, and all the people of the United States to observe this month with appropriate activities and programs that raise awareness and foster appreciation of music that is composed, arranged, or performed by African Americans.
IN WITNESS WHEREOF, I have hereunto set my hand this thirty-first day of May, in the year of our Lord two thousand sixteen, and of the Independence of the United States of America the two hundred and fortieth.
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Proclamation 9456 of May 31, 2016

Great Outdoors Month, 2016
A Proclamation
Every day, Americans draw inspiration from the landscapes and outdoor spaces that surround us and connect us with our heritage and with one another. People have lived off of these lands and waters throughout history, and today, they continue to enrich our national experience. In June, we celebrate America's natural and cultural treasures and rich bounty of resources, and we recommit to upholding our responsibility, as those who came before us did, to ensure they are sustained for those who will inherit them.
From dense forests and vast deserts to lakes and rivers teeming with wildlife, our National Parks and other public spaces belong to all of us. That is why I have sought to protect places that are culturally and historically significant and that reflect the story of all our people. My Administration has also worked hard to ensure that everyone has the chance to easily visit and enjoy these spectacular areas. All Americans can explore the parks and monuments we share as our birthright, including through the “Find Your Park” campaign, which my Administration established to help connect people from all walks of life with new outdoor destinations and experiences. We also established the “Every Kid in a Park” initiative, offering free access to our National Parks and other public lands and waters for an entire year to fourth grade students and their families. And by increasing funding for the 21st Century Conservation Service Corps, we are striving to give more Americans hands-on opportunities to restore, enhance, and give back to the outdoor spaces that have given us so much.
Our experiences in nature remind us how fragile our ecosystems can be and of our obligation to protect them. That is why I am proud to have set aside more than 265 million acres of public lands and waters—more than any President in our history—and why my Administration has taken unprecedented action to tackle climate change. The planet and its natural beauty are changing as rising temperatures fuel the melting of glaciers and the increasing intensity of extreme weather events, including longer wildfire seasons and deeper droughts, and as seas rise, coastal communities face greater threats from flooding and eroding shorelines. It is within our power to address the peril of climate change, and we must act before it is too late.
During Great Outdoors Month, let us enjoy our Nation's natural bounty, whether in reflective solitude or in the energizing company of friends and family. As we rediscover the beauty of the outdoors—in our own backyards, along distant trails, or in the shadows of towering mountains—let us rededicate ourselves to preserving nature's splendor for future generations.
NOW, THEREFORE, I, BARACK OBAMA, President of the United States of America, by virtue of the authority vested in me by the Constitution and the laws of the United States, do hereby proclaim June 2016 as Great Outdoors Month. I urge all Americans to explore the great outdoors and to uphold our Nation's legacy of conserving our lands and waters.
IN WITNESS WHEREOF, I have hereunto set my hand this thirty-first day of May, in the year of our Lord two thousand sixteen, and of the Independence of the United States of America the two hundred and fortieth.
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Proclamation 9457 of May 31, 2016

Lesbian, Gay, Bisexual, and Transgender Pride Month, 2016
A Proclamation
Since our founding, America has advanced on an unending path toward becoming a more perfect Union. This journey, led by forward-thinking individuals who have set their sights on reaching for a brighter tomorrow, has never been easy or smooth. The fight for dignity and equality for lesbian, gay, bisexual, and transgender (LGBT) people is reflected in the tireless dedication of advocates and allies who strive to forge a more inclusive society. They have spurred sweeping progress by changing hearts and minds and by demanding equal treatment—under our laws, from our courts, and in our politics. This month, we recognize all they have done to bring us to this point, and we recommit to bending the arc of our Nation toward justice.
Last year's landmark Supreme Court decision guaranteeing marriage equality in all 50 States was a historic victory for LGBT Americans, ensuring dignity for same-sex couples and greater equality across State lines. For every partnership that was not previously recognized under the law and for every American who was denied their basic civil rights, this monumental ruling instilled newfound hope, affirming the belief that we are all more free when we are treated as equals.
LGBT individuals deserve to know their country stands beside them. That is why my Administration is striving to better understand the needs of LGBT adults and to provide affordable, welcoming, and supportive housing to aging LGBT Americans. It is also why we oppose subjecting minors to the harmful practice of conversion therapy, and why we are continuing to promote equality and foster safe and supportive learning environments for all students. We remain committed to addressing health disparities in the LGBT community—gay and bisexual men and transgender women of color are at a particularly high risk for HIV, and we have worked to strengthen our National HIV/AIDS Strategy to reduce new infections, increase access to care, and improve health outcomes for people living with HIV.
Despite the extraordinary progress of the past few years, LGBT Americans still face discrimination simply for being who they are. I signed an Executive Order in 2014 that prohibits discrimination against Federal employees and contractors on the basis of sexual orientation or gender identity. I urge the Congress to enact legislation that builds upon the progress we have made, because no one should live in fear of losing their job simply because of who they are or who they love. And our commitment to combatting discrimination against the LGBT community does not stop at our borders: Advancing the fair treatment of all people has long been a cornerstone of American diplomacy, and we have made defending and promoting the human rights of LGBT individuals a priority in our engagement across the globe. In line with America's commitment to the notion that all people should be treated fairly and with respect, champions of this cause at home and abroad are upholding the simple truth that LGBT rights are human rights.
There remains much work to do to extend the promise of our country to every American, but because of the acts of courage of the millions who came out and spoke out to demand justice and of those who quietly toiled and pushed for progress, our Nation has made great strides in recognizing what these brave individuals long knew to be true in their hearts—that love is love and that no person should be judged by anything but the content of their character. During Lesbian, Gay, Bisexual, and Transgender Pride Month, as Americans wave their flags of pride high and march boldly forward in parades and demonstrations, let us celebrate how far we have come and reaffirm our steadfast belief in the equal dignity of all Americans.
NOW, THEREFORE, I, BARACK OBAMA, President of the United States of America, by virtue of the authority vested in me by the Constitution and the laws of the United States, do hereby proclaim June 2016 as Lesbian, Gay, Bisexual, and Transgender Pride Month. I call upon the people of the United States to eliminate prejudice everywhere it exists, and to celebrate the great diversity of the American people.
IN WITNESS WHEREOF, I have hereunto set my hand this thirty-first day of May, in the year of our Lord two thousand sixteen, and of the Independence of the United States of America the two hundred and fortieth.
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Proclamation 9458 of May 31, 2016

National Caribbean-American Heritage Month, 2016
A Proclamation
The dynamism and diversity of Caribbean Americans have contributed to our Nation's story in extraordinary ways. Millions of people in the United States are connected to our Caribbean neighbors through ties of commerce and family—a relationship reinforced by the values and history we hold in common. During National Caribbean-American Heritage Month, we celebrate the contributions of our Caribbean-American brothers and sisters, and we reflect on how they have bolstered our country and enriched our traditions.
The bonds between the United States and the Caribbean remain strong. Both rooted in similar legacies—of trial and triumph, oppression and liberation—our narratives have advanced on a similar path of progress, driven forward by our shared dedication to fostering opportunity and forging a brighter future. Caribbean Americans excel in our universities, inspire us as athletes and musicians, guide us as community and government leaders, and keep us safe through dedicated service in our Armed Forces.
The United States is committed to working with the nations of the Caribbean to advance security, liberty, and prosperity. That is why we have begun a new chapter in our relationship with Cuba—extending a new hand of friendship to the Cuban people that offers fresh hope for both our futures and will improve the lives of those living in both our countries. My Administration also introduced the 100,000 Strong in the Americas initiative to provide higher education exchanges to students across the Western Hemisphere, and we launched the Young Leaders of the Americas Initiative to address persistent opportunity gaps in the Americas and to give emerging entrepreneurs and civil society leaders the resources they need to reach their full potential. In harnessing the spirit and boldness of young people in the Caribbean and throughout the Americas, and in channeling their creativity and innovation, we can continue to build on the progress we have made. And by carrying out Jamaican-American poet Claude McKay's call to “strive on to gain the height although it may not be in sight,” we can enable more young people, here at home and throughout the Caribbean, to reach for the change that is within their grasp.
The legacy of Caribbean Americans is one of tenacity and drive; it reminds us that in America, with faith and determination, anything is possible. This month, let us honor the resilient heritage and rich history of Caribbean Americans, and let us reflect upon the diversity of experiences that unites us as a people.
NOW, THEREFORE, I, BARACK OBAMA, President of the United States of America, by virtue of the authority vested in me by the Constitution and the laws of the United States, do hereby proclaim June 2016 as National Caribbean-American Heritage Month. I encourage all Americans to celebrate the history and culture of Caribbean Americans with appropriate ceremonies and activities.
IN WITNESS WHEREOF, I have hereunto set my hand this thirty-first day of May, in the year of our Lord two thousand sixteen, and of the Independence of the United States of America the two hundred and fortieth.
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Proclamation 9459 of May 31, 2016

National Oceans Month, 2016
A Proclamation
Covering more than 70 percent of the earth's surface, oceans have a profound impact on our way of life. Home to a great diversity of plant and animal species, their precious ecosystems provide food and energy that are integral to our survival. In bringing tourism and recreation to coastal areas, oceans are important to America's economy, and they help facilitate trade and transportation, give mobility to our Armed Forces, and preserve our Nation's maritime heritage. In observation of National Oceans Month, we recommit to good ocean stewardship and redouble our efforts to preserve the health and resilience of our vast oceans, coasts, and Great Lakes.
Jeopardizing marine populations and degrading oceanic habitats, pollution poses a significant risk to all of our interconnected oceans. Oceans and their nearby regions are also highly vulnerable to the effects of a changing climate—a once-distant threat that is now very present and is affecting ecosystems and shoreline communities on every coast. Rising sea levels, coastal storms, and a growing risk of erosion and flooding are looming realities faced by seaside towns. It is critical that we take measures to safeguard our blue planet and heed the urgency to defend against these mounting threats, particularly in the Arctic where the effects of a changing climate are already swiftly accelerating.
In collaboration with stakeholders; scientists; businesses; and State, tribal, and local partners, my Administration is continuing to implement the National Ocean Policy, a coordinated effort to support local communities, strengthen our ocean economy, and improve the health of our oceans. We are concentrating on key areas outlined in our 2016 Annual Work Plan, including combatting illegal, unregulated, and unreported fishing and monitoring significant changes in the acidity of our oceans. We are also focused on reducing the toxic effects of harmful algal blooms, which occur when algae grow too rapidly and threaten the safety of our food, drinking water, and air quality. Using the science-based roadmap laid out in the National Ocean Policy, we are dedicated to enhancing the economic and ecological sustainability of our oceans and advancing our knowledge of how they influence and are influenced by human activity.
This month, let us continue the work of ensuring the well-being of these grand bodies of water and the communities that depend on them. As we celebrate the immense beauty and power of our oceans, we are reminded of our shared responsibility to protect them—now and for generations to come.
NOW, THEREFORE, I, BARACK OBAMA, President of the United States of America, by virtue of the authority vested in me by the Constitution and the laws of the United States, do hereby proclaim June 2016 as National Oceans Month. I call upon Americans to take action to protect, conserve, and restore our oceans, coasts, and Great Lakes.
IN WITNESS WHEREOF, I have hereunto set my hand this thirty-first day of May, in the year of our Lord two thousand sixteen, and of the Independence of the United States of America the two hundred and fortieth.